It is important to highlight the fact that the proposed technique to compute \nodal" marginalprices assumes that all the costs of redispatching are fully distributed among the market participants, as is the case of the current NewEnglandelectricity markets . Hence, since a \zero sum" approach is used in this case, there are no \leftovers" to be used by the ISO for possible upgrades of the transmission system. Furthermore, costs associated with losses and re- active power dispatch, as well as reserves for frequency con- trol, are assumed to be resolved in other independent auc- tion markets or by other market mechanisms, which may in turn yield system operating conditions that could have a signicant eect on the marginal costs generated by each one of the dierent markets. Although the latter might be resolved by using other iterative processes, somewhat simi- lar to the one proposed here for the integration of the ATC into the auction system, this is certainly a disadvantage of these types of markets.
Transmission Operator (RTO). In this role, it is the system operator for the six-state region of NewEngland. In the subsequent two years of its founding, ISONE completed the design and implementation of the region’s first wholesale electricitymarket. Since its inception, renewed investments have allowed more than 1.3 GW of new generational capacity to be installed in the region, as well as a 2% increase in generator reliability. This market design allows generators to respond to economic incentives when demand is highest , e.g., during hot summer days. A centralized approach to managing power flow allows for scheduling required plant maintenance without concern of insufficient peak period generation. To improve system reliability and to mitigate price-volatility, ISONE administers Day-Ahead (DA) and Forward Capacity markets (FCM) as a means to efficiently schedule future supply and demand requirements. On the supply side, ISONE can call upon generating units that range from small ‘peak-load’ units, to medium-sized units used in the presence of a quick increase in demand, to large base-load units that are online nearly continuously. In total,
In theory, electricity capacity auctions work in tandem with electricity spot and forward markets to ensure that energy companies invest in suf- …cient capacity to meet consumer demand for reliability. But economists disagree about whether electricity markets – unlike the markets for breakfast cereals or new cars – require special institutions like government-organized capacity markets to achieve e¢cient long-run investments. Those in favour point to “market failures” such as the lack of demand-side participation in many electricity markets which makes market clearing problematic in times of scarcity, or to “missing money” due to regulatory caps on peak-period prices, to justify the need for intervention. Excessive price volatility and coordination failures are further factors which have been adduced in support of introducing capacity markets. 2
A controversial area of energy policy has been the use of electric rate payer funds to finance natural gas infrastructure. Independent of the merits of new pipeline additions, private capital is a viable alternative financing option. This would serve to eliminate one of the more divisive aspects of the pipeline by not exposing rate payers to risks of over paying for additional natural gas capacity and stranded costs. On August 17, 2016, the Massachusetts Supreme Court and on October 6, 2016 the NH PUC determined that rate payer funds should not be used to support natural gas pipeline capacity contracts. Furthermore, on October 25, 2016, the Connecticut Department of Energy & Environmental Protection cancelled a request for proposal (RFP) it has issued for natural gas related capacity despite acknowledging that “ . . . the NewEngland region is facing volatile electricity prices and significant risks to electric reliability due to limitations in our restructured electricitymarket that have driven investment in new natural gas-fired power plants, but not in the natural gas delivery infrastructure needed to ensure that those plants can run reliably all year round.” 236
Wolfram (1999) showed that generators exercised less market power from 1992 to 1994 than predicted by Green and Newbery (1992). She also found that market power was less sensitive to large changes in the level of contract cover than one would expect in a static oligopoly model with contracts, but that it was sensitive to actions taken by the regulator. A number of recent papers, several of them citing an earlier version of the current paper (Sweeting (2001)) have examined Pool data from the late-1990s. Evans and Green (2003) find that the Lerner index fell significantly just after the end of my data period and they suggest that tacit collusion may have broken down once it was known that the Pool would be replaced by the NewElectricity Trading Arrangements (NETA) in March 2001. Macatangay (2002) identifies patterns in NP and PG’s bidding which he suggests are consistent with tacit collusion. Bower (2002) and Newbery (2003) suggest that the incumbent generators may have exercised more market power from 1998 to 2000 because of a government moratorium on approving the construction of new combined cycle gas turbine (CCGT) capacity which may have reduced the need for entry deterrence. Newbery (2003) also suggests that NP and PG may have raised prices in 1999 and 2000 to increase the resale value of power stations which they were trying to sell. This paper provides direct evidence that the generators were exercising more market power in the late-1990s and that NP and PG were restricting output to raise prices by more than would have been expected in a static oligopoly model with contracts.
ENERGY EFFICIENCY IN THE CAPACITY MARKET The NewEnglandelectricity grid is run by the ISO-NE (see Chapter 3); and the ISO does regional planning to ensure the region’s future energy needs will be satisfied with the Forward Capacity Market (FCM) (see Chapter 6). Energy efficiency resources participate in the Forward Capacity Auctions, and are able to compete on a level playing field with supply resources (such as fossil-fuel generators) to meet the region’s power needs. Efficiency resources can and do bid into the FCM, just as generation sources can. Efficiency resources are then paid for their ability to reduce the need for electricity and reduce the capacity that would otherwise require a generating plant to be available. Since efficiency resources can meet capacity needs at a much lower cost than generation resources, the par- ticipation of efficiency in the FCM lowers costs for all NewEngland customers. About 80% of all energy effi- ciency programs in NewEngland clear in the Forward Capacity Market. The revenue streams that result from these auctions are a significant source of funds for advancing energy efficiency in NewEngland (but there are also other significant sources of revenue for effi- ciency programs, including the state-mandated SBCs). The most recent FCM auction (FCA-9, in February 2015; see Chapter 6) drew 367 MW of new energy efficiency resources (that reduce overall demand for electricity).
Our results support those found by other authors that switching costs are likely to reach high values. The cost of switching regional incumbents is consistent for example with that obtained for Swedish customers. We found the following interesting result in the prepayment market that it is possible for new entrants to retain customers. This suggests that the entrant’s customers would perceive a gross cost of switching too high relative to the value they attach to the incumbent. That value may be low given that both the incumbents and the entrant charge close and high prices relative to those offered to non2prepayment customers. In the latter, the costs to switch the entrant are negative thus supporting that many customers may be inclined to switch back to their default provider or to other reputed and well established incumbents. We measured those costs by using an extension of Shy (2002)’s model that, we hope will reinforce its appeal to policy analysts. Under more rigorous conditions on the values of switching costs and market shares, this extension allowed us for example to predict a new equilibrium where the larger firm charges a higher price.
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the time it would take to reach the long-run demand response. The long-run supply curve indicates that the cost of generating electricity using the most up- to-date technology available is the determining influence on market price. The long-run supply curve embodies the notion that long-run expansions in industry output will be accomplished by building new generating units using the most economically efficient methods possible. The expected long-run price of electricity will be determined by the intersection of long-run supply and demand, as is shown in Figure 2. The estimated long-run equilibrium price of electric power is three cents per kilowatthour. Again, this is an estimated average price across all utilities and customer classes in the region over the course of an entire year. This long- run equilibrium is reached because at the same time that demand is increasing, the upward sloping portion of the industry supply curve will be decreasing (or shifting to the left). That will happen because each year some existing generating units become uneconomical to operate and are retired. How long it takes for long-run demand to intersect with long-run supply in the horizontal portion of the long-run supply curve thus depends on the decisions that utilities will make about renovating or retiring existing generating units in a deregulated environment.
The promotion of renewables is a key feature of current Scottish Government policy, as indeed it has been of successive Scottish administrations. This reflects the scale of the resource in Scotland and the perceived opportunities for economic development (considered in Section 4 below). The Scottish Government has used a variety of instruments to encourage this. An example is the streamlining of the planning process and investments in port infrastructure to facilitate offshore developments so as to create a perception of a renewables- investor-friendly location. However, currently the main policy instrument used to directly induce this is ROCs. While the Scottish Government has influenced the policy, as reflected in the banding that favours new marine technologies, the costs are currently borne by UK consumers as a whole. However, not surprisingly some doubt has been expressed about the likelihood of this arrangement continuing after independence, and if it is not, and the Scottish Government continues to pursue its objective of generating the equivalent of Scottish consumption of electricity, prices to Scottish consumers would have to rise significantly above those charged in RUK (Citigroup, 2011) .
The Nordic electricitymarket is increasingly connected to the continental markets. Through the implementation of the third inner market package, which will be in force by March 2011, the development towards an inner European market for electricity is strengthened. Important projects with relevance for the Nordic electricitymarket are going on in cooperation between the EU Commission, and the organisations of the national energy regulators (ERGEG) and from March 2011 ACER, and system operators (ENTSO-E). The top priority in this work is to develop day ahead market coupling across Europe. In November 2010, a market coupling solution will be launched connecting the Nordic market to the French, Belgian, Dutch and German markets, with the NorNED cable coming into the market coupling in mid December. This is an interim solution which will be further developed into a single price coupling model. In order to reach this goal, market design will need to adapt in all affected countries.
The first five-year ALTENER programme ended on 31.12.97. In May 1998 the Council adopted its successor ‘ALTENER II’ 44 which ran two years from 1998 to 1999. The stated overall aim of ALTENER II is to make an essential contribution to the White Paper Strategy and Action Plan, including the Campaign for Take-Off. It continues the approach of the earlier ALTENER programme focussing on non-technical barriers (RES legislation, market opportunities, environment benefits, employment, standards, training structures, planning, monitoring, etc.) but in addition stresses targeted actions in order to reduce the gap between innovative projects and large scale applications. Around 200 projects providing direct support for the Action Plan including the Campaign for Take-Off were selected and approved under the 1998/1999 project round.
3.2. In the case of generation the Directive provides that Member States may choose between an authorisation and/or a tendering procedure for the construction of new generating capacity. Authorisation and tendering must be conducted in accordance with objective, transparent and non-discriminatory criteria. 11 The Directive specifies a number of requirements for the operation of both authorisation and tendering procedures. 12 In addition it sets down the rules for the operation of the transmission and distribution systems. These provide inter alia that Member States shall designate or require undertakings which own transmission systems to designate for a period of time a system operator to be responsible for operating, ensuring the maintenance of, and, if necessary, developing the transmission system in a given area and its interconnection with other systems, in order to guarantee security of supply. 13 The system operator may not discriminate between system users and, unless the transmission system is already independent of generation and distribution activities, the system operator must be independent, at least in management terms, from the other activities not relating to the transmission system. 14 Similar provisions apply to distribution. 15 Integrated electricity undertakings are required to keep separate accounts for their generation, transmission and distribution activities with a view to avoiding discrimination, cross subsidisation and distortion of competition. 16 The Directive provides that Member States may choose between allowing third party access to the electricity system or establish a Single Buyer regime. 17 The Single Buyer regime, where adopted, must comply with certain criteria including, inter alia, that:
It is unclear that CCGTs (the most efficient form of gas generation and with the lowest emissions) will be able to respond within the required 4-hour period unless CCGTs are kept warm and ready to run, which is inefficient. Query whether this will lead to the less efficient OCGT technology (with its higher emissions, lower construction costs and higher operating costs) becoming the default new build option used within the capacity market? This is likely to depend (at least to some extent) on whether stress events tend to appear “out of the blue” or can be reasonably anticipated in advance – perhaps because of movements in the balancing market (although the SO may choose to issue a Capacity Market Warning first, as the cheaper option in the case of the general system (i.e. non-locational) system stress) or because there is not enough gas generation available to support intermittent wind generation during high pressure weather systems. Given the penalties are calculated in relation to each half-hour settlement period, generators may be more relaxed about this requirement if they are able to respond shortly after 4 hours and believe that Capacity Market Warnings will be rare. Although, given Ofgem’s estimates in its Electricity Capacity Assessment Report 2013 of the increased probability of a large shortfall requiring the controlled disconnection of customers, generators are perhaps unlikely to take this view.
Argentina, Carlos Bastos, Secretary of Energy 1991-96, led the privatisation of the electricity sector, within the general policy framework of the Minister of Economy. Bastos was formerly an electrical engineer, researcher and a consultant on electricity issues for the Inter-American Development Bank and the Harvard Institute for International Economic Development. He brought the conceptual vision and insistence on a reformed, privately owned and competitive sector. He gave general direction and control to the privatisation of the energy sector, and took on the political battles, including with parties from the existing industry. The reform was along similar lines to the UK, and even went further with respect to restructuring (Littlechild and Skerk, 2004). Similarly, UK has been successful in market reform because it managed to find a set of quite able, fair-minded regulators. Professor Stephen C. Littlechild was Director General of Electricity Supply (DGES), in charge of the Office of Electricity Regulation (OFFER), from its foundation in September 1989 to 1998. Littlechild, one of the architects of the successful UK electricity reform, has been a true believer in competition in electricity markets. Before the appointment, he was Professor of Commerce and Head of Department of Industrial Economics and Business Studies at the University of Birmingham from 1975-89, and a member of the Monopolies and Mergers Commission from 1983-89. In response to the apparent problems of the cost-recovery methods, in 1983, Professor Stephen C. Littlechild proposed a “high - powered” incentive scheme, popularly known as RPI -X or price cap, in which the regulator caps the allowable price or revenue for each firm for a pre-determined period. Thus far, in terms of economic efficiency, RPI-X has been a clear success. In the United Kingdom, the RPI-X regulatory approach has induced cost reductions well beyond expectations. Electricity companies have been able to greatly reduce operating costs in large part through substantial work force reductions. In short, the educational and professional backgrounds of energy minister and regulator played an important role in the reform progress in Argentina and the UK, respectively. Therefore our first hypothesis is as follows:
Thereby, in 1992, Malaysia Electricity Supply Industry (MESI) had move forward to restricting by encourage private investors in producing electrical energy. Tenaga Nasional Berhad (TNB) monopoly the whole electricitymarket, but it’s come to end when Malaysia government introduced Independent Power Producers (IPP). IPP aim’s to assist Tenaga Nasional Berhad (TNB) to overcome the electricity issue and enlarge electrical energy generation sector. Other than that, IPP will create competition among other generation . This electricitymarket model applied in Malaysia known as single buyer model. Nowadays, there are 14 IPP in the Peninsular Malaysia that serve electricity and sold to TNB to purchase by the consumers. IPP and TNB have an agreement that last for 21 years based on the power purchase agreement (PPA).
Member States that have already adopted the predominant bilateral contracts market design will be in a position to implement the Target Model without extensive reforms. In contrast, the SEM (which is an ex-post mandatory gross pool with centralised dispatch) requires substantial modifications in order to implement and comply with the Target Model. The SEM also features no forecast risk for renewables such as wind and there is no concept of balance responsibility for generators (i.e. financial responsibility for the deviation in market schedules between DA and real-time). In the SEM the cost of deviations between the market schedule in DA and real- time due to network and energy actions are socialised, therefore in effect generators have no balance responsibility exposure. For wind generation, where output is always variable and difficult to forecast beyond 4-6 hours ahead, this element of the SEM currently provides investment certainty.
This section discusses the derivation of half- hourly electricity “ total demand” for the 50 regional nodes shown in Wild et al. (2015 figs. 2-6). We derived this load data for Queensland and New South Wales using regional load traces supplied by Powerlink and Transgrid. This data was then re-based to the state load totals published by AEMO (2014) for the ‘QLD1’ and ‘NSW1’ markets. For the other three States, the regional shares were determined from terminal station load forecasts associated with summer peak demand (and winter peak demand, if available) contained in the annual planning reports published by the transmission companies Transend (Tasmania), Vencorp (Victoria) and ElectraNet (South Australia). These regional load shares were then interpolated to a monthly based time series using a cubic spline technique and these time series of monthly shares were then multiplied by the ‘TAS1’, ‘VIC1’ and ‘SA1’ State load time series published by AEMO (2014) in order to derive the regional load profiles for Tasmania, Victoria and South Australia.
Since income level affects purchasing decision, we use income distribution data generated from surveys taken between 2005 and 2009 in Texas by the United States Census Bureau to assign income to individual households in the model. In the absence of state-specific data on correlations between electricity usage and income, it is as- sumed that average data for households in the United States is the same for the Texas households. As a result, we use the 2005 EIA Residential Energy Consumption Surveys (RECs) data to delineate the relationship be- tween electricity consumption and household income. Our model also analyze the willingness of a consumer to switch to purchasing renewable energy even if the cost is greater than that of fossil fuel-based electricity. In 2008, the National Renewable Energy Laboratory published the Green Power Marketing Report in which they summarize consumer participation rates in utility green pricing tables . Accordingly, this model utilizes the trend established in the NREL document to characterize the “Green Conscious” population as shown in Figure 1. Since green consumers are defined simply as those willing to pay more for electricity obtained from renewa- ble sources, our analysis assumes that a green consumer is willing to pay up to 15% more for certified renewable energy than for fossil fuels.