Did residential electricity rates fall after retail competition? A dynamic panel analysis

A key selling point for the restructuring of electricity markets was the promise of lower prices. There is not much consensus in earlier studies on the effects of electricity deregulation in the U.S., particularly for residential customers. Part of the reason for not finding a consistent link with deregulation and lower prices was that the removal of transitional price caps led to higher prices. In addition, the timing of the removal of price caps coincided with rising fuel prices, which were passed on to consumers in a competitive market. Using a dynamic panel model, we analyze the effect of participation rates, fuel costs, market size, a rate cap and switch to competition for 16 states and the District of Columbia. We find that an increase in participation rates, price controls, a larger market, and high shares of hydro in electricity generation lower retail prices, while increases in natural gas and coal prices increase rates. We also find that retail competition makes the market more efficient by lowering the markup of retail prices over wholesale costs. The effects of a competitive retail electricity market are mixed across states, but generally appear to lower prices in states with high participation rates.     

Energy price forecasting - problems and proposals for such predictions

This paper discusses the value of price forecasting in the electricity market during bidding or hedging against volatility. When bidding in a pool system, the market participants are requested to express their bids in terms of prices and quantities. Since the bids are accepted in order of increasing price until the total demand is met, a company that is able to forecast the pool price can adjust its own price/production schedule depending on hourly pool prices and its own production costs. This paper also discusses the challenges of price forecasting and describes some of the proposed methods for meeting these challenges.     

Optimal generation and reserve dispatch in a multi-area competitive market using a hybrid direct search method

With restructuring of the power industry, competitive bidding for energy and ancillary services are increasingly recognized as an important part of electricity markets. It is desirable to optimize not only the generator’s bid prices for energy and for providing minimized ancillary services but also the transmission congestion costs. In this paper, a hybrid approach of combining sequential dispatch with a direct search method is developed to deal with the multi-product and multi-area electricity market dispatch problem. The hybrid direct search method (HDSM) incorporates sequential dispatch into the direct search method to facilitate economic sharing of generation and reserve across areas and to minimize the total market cost in a multi-area competitive electricity market. The effects of tie line congestion and area spinning reserve requirement are also consistently reflected in the marginal price in each area. Numerical experiments are included to understand the various constraints in the market cost analysis and to provide valuable information for market participants in a pool oriented electricity market.     

On the efficient market diffusion of intermittent renewable energies

Capacity costs of renewable energies have been decreasing dramatically and are expected to fall further, making them more competitive with fossils. Building on an analytically tractable peak-load pricing model, we analyze how intermittency of renewable energies affects the market diffusion that results from these lower costs. In particular, once renewables have become competitive by attaining the same levelized cost of electricity (LCOE) as fossils, the marginal increase in efficient capacities due to a further cost reduction varies substantially. Initially it is small, then it rises, but it falls again once renewable capacities are large enough to satisfy the whole electricity demand at times of high availability. If external costs of fossils are internalized by a Pigouvian tax, then perfect competition leads to efficient investments in renewable and fossil capacities; even though we assume that only a subgroup of consumers can adapt their demand to price fluctuations that are caused by the intermittency of renewables. Moreover, fossils receive a capacity payment through the market for their reliability in serving demand of non-reactive consumers. Maximum electricity prices rise with the share of renewables. If regulators impose a price cap, this initially raises investments in renewables, but the effect may reverse if the share of renewables is large.     

The impact of the North Atlantic Oscillation on electricity markets: A case study on Ireland

The North Atlantic Oscillation (NAO) is a large-scale atmospheric circulation pattern driving climate variability in north-western Europe. As the deployment of wind-powered generation expands on electricity networks across Europe, the impacts of the NAO on the electricity system will be amplified. This study assesses the impact of the NAO, via wind-power generation, on the electricity market considering thermal generation costs, wholesale electricity prices and wind generation subsidies. A Monte Carlo approach is used to model NAO phases and generate hourly wind speed time-series data, electricity demand and fuel input data. A least-cost unit commitment and economic dispatch model is used to simulate an island electricity system, modelled on the all-island Irish electricity system. The impact of the NAO obviously depends on the level of wind capacity within an electricity system. Our results indicate that on average a switch from negative to positive NAO phase can reduce thermal generation costs by up to 8%, reduce wholesale electricity prices by as much as €1.5/MWh, and increase wind power generators' revenue by 12%.     

Economic modelling of price support mechanisms for renewable energy: Case study on Ireland

The Irish Government is considering its future targets, policy and programmes for renewable energy for the period beyond 2005. This follows a review in 2003 of policy options that identified a number of different measures to stimulate increased deployment of renewable energy generation capacity. This paper expands this review with an economic analysis of renewable energy price support mechanisms in the Irish electricity generation sector. The focus is on three primary price support mechanisms quota obligations, feed in tariffs and competitive tender schemes. The Green-X computer model is utilised to characterise the RES-E potential and costs in Ireland up until, and including, 2020. The results from this dynamic software tool are used to compare the different support mechanisms in terms of total costs to society and the average premium costs relative to the market price for electricity. The results indicate that in achieving a 20% RES-E proportion of gross electricity consumption by 2020, a tender scheme provides the least costs to society over the period 2006–2020 but only in case there is limited or no strategic bidding. Considering, however, strategic bidding, a feed-in tariff can be the more efficient solution. Between the other two support mechanisms, the total costs to society are highest for feed-in-tariffs (FIT) until 2013, at which point the costs for the quota system begin to rise rapidly and overtake FIT in 2014–2020. The paper also provides a sensitivity analysis of the support mechanism calculations by varying default parameters such as the interim (2010) target, the assumed investment risk levels and the amount of biomass co-firing. This analysis shows that a 2010 target of 15% rather than 13.2% generates lower costs for society over the whole period 2006–2020, but higher costs for the RES-E strategy over the period 2006–2010.     

High penetration wind generation impacts on spot prices in the Australian national electricity market

This paper explores wind power integration issues for the South Australian (SA) region of the Australian National Electricity Market (NEM) by assessing the interaction of regional wind generation, electricity demand and spot prices over 2 recent years of market operation. SA's wind energy penetration has recently surpassed 20% and it has only a limited interconnection with other regions of the NEM. As such, it represents an interesting example of high wind penetration in a gross wholesale pool market electricity industry. Our findings suggest that while electricity demand continues to have the greatest influence on spot prices in SA, wind generation levels have become a significant secondary influence, and there is an inverse relationship between wind generation and price. No clear relationship between wind generation and demand has been identified although some periods of extremely high demand may coincide with lower wind generation. Periods of high wind output are associated with generally lower market prices, and also appear to contribute to extreme negative price events. The results highlight the importance of electricity market and renewable policy design in facilitating economically efficient high wind penetrations.     

Effects of regulatory reforms in the electricity supply industry on electricity prices in developing countries

Electric power sector reforms in the electricity supply industry have had an impact on industrial and household prices in developing countries in Latin America, the former Soviet Union, and Eastern Europe. Using original panel data for 83 countries during the period from 1985 to 2002, we examine how each policy instrument of the reform measures influenced electricity prices for countries in the above regions. We found that variables such as entry of independent power producers (IPP), unbundling of generation and transmission, establishment of a regulatory agency, and the introduction of a wholesale spot market have had a variety of impacts on electricity prices, some of which were not always consistent with expected results. The research findings suggest that neither unbundling nor introduction of a wholesale pool market on their own necessarily reduces the electric power price. In fact, contrary to expectations, there was a tendency for the price to rise. However, coexistent with an independent regulator, unbundling may work to reduce electricity prices. Privatization and the introduction of foreign IPP and retail competition lower electricity prices in some regions, but not all.     

Has electric utility restructuring led to lower electricity prices for residential consumers in Texas?

This paper analyzes the determination of residential electricity prices in the competitive Electric Reliability Council of Texas (ERCOT) market. This analysis suggests that electricity restructuring in Texas has not yet resulted in lower prices for the majority of residential energy consumers in areas open to competition. Contrary to common expectations, residential electricity costs for consumers at a typical (1000 kWh per month) consumption level have increased at a greater rate in the areas of Texas offering retail choice than in the areas of the State where retail competition has not been introduced.     

Estimating the electricity prices,generation costs and CO2 emissions of large scale wind energy exports from Ireland to Great Britain

The share of wind generation in the Irish and British electricity markets is set to increase by 2020 due to renewable energy (RE) targets. The United Kingdom (UK) and Ireland have set ambitious targets which require 30% and 40% of electricity demand to come from RE, mainly wind, by 2020, respectively. Ireland has sufficient indigenous onshore wind energy resources to exceed the RE target, while the UK faces uncertainty in achieving its target. A possible solution for the UK is to import RE directly from large scale onshore and offshore wind energy projects in Ireland; this possibility has recently been explored by both governments but is currently on hold. Thus, the aim of this paper is to estimate the effects of large scale wind energy in the Irish and British electricity markets in terms of wholesale system marginal prices, total generation costs and CO₂ emissions. The results indicate when the large scale Irish-based wind energy projects are connected directly to the UK there is a decrease of 0.6% and 2% in the Irish and British wholesale system marginal prices under the UK National Grid slow progression scenario, respectively.     

Stockholm CHP potential—An opportunity for CO2 reductions?

The potential for combined heat and power (CHP) generation in Stockholm is large and a total heat demand of about 10 TWh/year can be met in a renewed large district heating system. This model of the Stockholm district heating system shows that CHP generation can increase from 8% in 2004 to 15.5% of the total electricity generation in Sweden. Increased electricity costs in recent years have awakened an interest to invest in new electricity generation. Since renewable alternatives are favoured by green certificates, bio-fuelled CHP is most profitable at low electricity prices. Since heat demand in the district heating network sets the limit for possible electricity generation, a CHP alternative with a high electricity to heat ratio will be more profitable at when electricity prices are high. The efficient energy use in CHP has the potential to contribute to reductions in carbon dioxide emissions in Europe, when they are required and the European electricity market is working perfectly. The potential in Stockholm exceeds Sweden's undertakings under the Kyoto protocol and national reduction goals.     

Hedging local volume risk using forward markets: Nordic case

With focus on the Nordic electricity market, this paper develops hedging strategies for an electricity distributor who manages price and volume risk from fixed price agreements on stochastic electricity load. Whereas the distributor trades in the spot market at area prices, the financial contracts used for hedging are settled against the system price. Area and system prices are correlated with electricity load, as are price differences. In practice, however, this is often disregarded. Here, we develop a joint model for the area price, the system price and the load, accounting for correlations, and we suggest various strategies for hedging in the presence of local volume risk. We benchmark against a strategy that ignores correlation and hedges at expected load, as is common practice in the industry. Using data from 2013 and 2014 for two Danish bidding areas, we show that our best hedging strategy reduces gross loss by 5.8% and 13.6% and increases gross profit by 3.8% and 9.5%, respectively. Although this is partly due to the inclusion of correlation, we show that performance improvement is mainly driven by the choice of risk measure.     

Do producers apply a capacity cutting strategy to increase prices? The case of the England and Wales electricity market

Promoting competition among electricity producers is primarily targeted at ensuring fair electricity prices for consumers. Producers could, however, withhold part of production facilities (i.e., apply a capacity cutting strategy) and thereby push more expensive production facilities to satisfy demand for electricity. This behavior could lead to a higher price determined through a uniform price auction. Using the case of the England and Wales wholesale electricity market we empirically analyze whether producers indeed did apply a capacity cutting strategy. For this purpose we examine the bidding behavior of producers during high- and low-demand trading periods within a trading day. We find statistical evidence for the presence of capacity cutting by several producers, which is consistent with the regulatory authority's reports.     

Electricity procurement for large consumers based on Information Gap Decision Theory

In the competitive electricity market, consumers seek strategies to meet their electricity needs at minimum cost and risk. This paper provides a technique based on Information Gap Decision Theory (IGDT) to assess different procurement strategies for large consumers. Supply sources include bilateral contracts, a limited self-generating facility, and the pool. It is considered that the pool price is uncertain and its volatility around the estimated value is modeled using an IGDT model. The proposed method does not minimize the procurement cost but assesses the risk aversion or risk-taking nature of some procurement strategies with regard to the minimum cost. Using this method, the robustness of experiencing costs higher than the expected one is optimized and the related strategy is determined. The proposed method deals with optimizing the opportunities to take advantage of low procurement costs or low pool prices. A case study is used to illustrate the proposed technique.     

计入峰谷分时上网电价的天然气发电竞争力分析

针对当前天然气发电燃料成本高、天然气供应不足而导致上网电价水平偏高,难以与煤电竞价的问题,提出考虑在发电侧实施峰谷分时上网电价机制,鼓励燃气电厂提高峰时段的上网电量,同时制定计入峰谷分时电价补贴标准来提高天然气发电的市场竞争力。算例结果表明,该措施明显提高了天然气发电的经济优势、气价的承受能力、与煤电平等竞价上网的竟争力。     

Area price and demand response in a market with 25% wind power

Denmark, east and west of the Great Belt are bidding areas with separate hourly area prices for the Nord Pool power exchange, covering four Nordic countries and parts of Germany. The share of wind power has now increased to 25% on an annual basis in western Denmark. This has a significant impact not only on the electricity wholesale prices, but also on the development of the market. Hourly market data are available from the website of Danish TSO from 1999. In this paper these data are analysed for the period 2004–2010. Electricity generators and customers may respond to hourly price variations, which can improve market efficiency, and a welfare gain is obtained. An important limitation for demand response is events of several consecutive hours with extreme values. The analysis in this paper is a summary and update of some of the issues covered by the EU RESPOND project. It shows that extreme events were few, and the current infrastructure and market organisation have been able to handle the amount of wind power installed so far. This recommends that geographical bidding area for the wholesale electricity market reflects external transmission constraints caused by wind power.     

Market structure and the stability and volatility of electricity prices

By using a novel approach in this paper, (λ,σ²)-analysis, we have found that electricity prices most of the time have increased in stability and decreased in volatility when the Nordic power market has expanded and the degree of competition has increased. That electricity prices at Nord Pool have been generated by a stochastic dynamic system that most often has become more stable during the step-wise integration of the Nordic power market means that this market is less sensitive to shocks after the integration process than it was before this process. This is good news.     

Elecxit: The cost of bilaterally uncoupling British-EU electricity trade

The UK's withdrawal from the European Union could mean that it leaves the EU's Internal Energy Market for electricity (Elecxit). This paper develops methods to study the longer-term consequences of this electricity market disintegration, especially the end of market coupling. Before European electricity markets were coupled, different market closing times forced traders to commit to cross-border trading volumes based on anticipated market prices. Interconnector capacity was often under-used, and power sometimes flowed from high- to low-price areas. A model of these market frictions is developed, empirically verified on 2009 data (before French and British market coupling) and applied to estimate the costs of market uncoupling in 2030. A less efficient market and the abandonment of some planned interconnectors would raise generation costs by €700 m a year (2%) compared to remaining in the Internal Energy Market. This result is sensitive to how the British and French electricity systems develop over the coming decades. Economic losses are four times greater (€2700 m a year) if France retains substantial nuclear capacity due to its low marginal costs. Conversely, losses are reduced by two-thirds if UK weakens its decarbonisation ambitions, as lower carbon prices subsidise British fossil fuel generation, allowing electricity prices to converge with those in France. A Hard Elecxit would make British prices rise and French prices fall in three of our four scenarios, with the opposite movements in the fourth scenario.     

Short-term electricity price forecast based on the improved hybrid model

Half-hourly electricity price in power system are volatile, electricity price forecast is significant information which can help market managers and participants involved in electricity market to prepare their corresponding bidding strategies to maximize their benefits and utilities. However, the fluctuation of electricity price depends on the common effect of many factors and there is a very complicated random in its evolution process. Therefore, it is difficult to forecast half-hourly prices with traditional only one model for different behaviors of half-hourly prices. This paper proposes the improved forecasting model that detaches high volatility and daily seasonality for electricity price of New South Wales in Australia based on Empirical Mode Decomposition, Seasonal Adjustment and Autoregressive Integrated Moving Average. The prediction errors are analyzed and compared with the ones obtained from the traditional Seasonal Autoregressive Integrated Moving Average model. The comparisons demonstrate that the proposed model can improve the prediction accuracy noticeably.     

Generators' bidding behavior in the NYISO day-ahead wholesale electricity market

This paper proposes a statistical and econometric model to analyze the generators' bidding behavior in the NYISO day-ahead wholesale electricity market. The generator level bidding data show very strong persistence in generators' grouping choices over time. Using dynamic random effect ordered probit model, we find that persistence is characterized by positive state dependence and unobserved heterogeneity and state dependence is more important than unobserved heterogeneity. The finding of true state dependence suggests a scope for economic policy intervention. If NYISO can implement an effective policy to switch generators from higher price groups to lower price groups, the effect is likely to be lasting. As a result, the market price can be lowered in the long-run. Generators' offered capacity is estimated by a two-stage sample selection model. The estimated results show that generators in higher-priced groups tend to withhold their capacity strategically to push up market prices. It further confirms the importance of an effective policy to turn generators into lower price groups in order to mitigate unexpected price spikes. The simulated market prices based on our estimated aggregate supply curve can replicate most volatility of actual DA market prices. Applying our models to different demand assumptions, we find that demand conditions can affect market prices significantly. It validates the importance of introducing demand side management during the restructure of electricity industry.