© Corbis

Recognizing the technical adva- nces in electricity storage and power electronics technologies coupled with the changes of the application opportunities and challenges for the electric utilities, the Electric Power Research Institute (EPRI) and the United States Department of Energy (DOE) cosponsored the preparation of the Handbook of Energy Storage for Transmission and Distribution Applications in 2003. A supplement for wind applications was prepared in 2004 (see "For Further Reading"), and plans call for an integrated update and expansion by the end of 2006.

The Handbook of Energy Storage for Transmission and Distribution Applications identifies the overall markets and benefits of DES systems and provides a technology-neutral framework for comparative benefit-cost assessments for representative utility use of DES systems. This article draws upon the handbook and supplement as bases for the DES business case from the utility perspective. We address the applications and value streams of DES with the intent of being technology neutral and then describe the status of some commercial technologies.

DES Benefits in a Nutshell

Such DES systems may also be adapted for load-shifting applications, through which low-cost, off-peak energy may be stored for use to offset on-peak, high-cost energy, thereby reducing the cost of service. Furthermore, such DES systems located close to loads may allow utilities to reduce the cost per megawatt served by deferring or even avoiding much bigger upgrades or expansions in their GT&D infrastructure.

Finally, DES is well suited to stabilize and optimize intermittent renewable resources, particularly wind generation, including short term (seconds) for fluctuation stabilization or long term (hours) for curtailment mitigation plus firming and shaping for forecast hedging or the time shift of generation.

For DES to be broadly deployed and achieve such potential, three key and interrelated conditions must be met: 1) quantified DES benefits must justify deployment, 2) utilities must have regulatory support to achieve remuneration for these DES systems, and 3) utility power engineers must have the tools needed to evaluate the technical and financial merits of DES systems.

Even if all these conditions are met, the DES community (suppliers and users) must ensure that their capabilities, technical characteristics, and benefits are understood by regulators, utility planners and power engineers, regional transmission organizations (RTOs), independent system operators (ISOs), and ratepayers and related advocacy groups.

Leading DES Applications

• DPQ: Short-duration power quality (SPQ) provides a high power discharge to mitigate voltage sags on the distribution system. The reference duty cycle is on standby for infrequent events characterized by 2 s of full power discharge (FPD), one event per hour, five events per day, and 100 events per year. Such applications are valued at the cost of the alternative solution.
• DPQ: Long-duration power quality (LPQ) provides SPQ protection and has the capability to provide several hours of reserve power. The reference duty cycle is on standby for infrequent events characterized by SPQ plus standby for 4 h FPD and one event per year. Such applications are valued at the cost of alternative solutions.
• GS: Grid frequency excursion suppression (GFS) provides a "prompt" spinning reserve for bridging to nonspinning reserve generation in the event of a loss-generating unit or transmission line. It requires electricity storage to discharge real power for durations of up to 30 min. The reference duty cycle is on standby for infrequent events characterized by 15 min FPD, one event per day, and ten events per year. Such applications are valued at the cost of the alternative solution.
• GOS: Regulation control (RC) gjves grid frequency regulation control support, both up and down. The reference duty cycle is characterized by continuous cycles equivalent to 7.5-min FPD and charge cycle (triangular waveform), 2 c/h deployed with 10 min of advance notice. Such applications are valued at the market rates for RC.
• DLS: Three-hour load shifting (LS3) shifts 3 h of stored energy from periods of low value to periods of high value. The reference duty cycle for analysis is a scheduled 3-h FPD, 1 event per day, 60 events per year. Such applications are valued at market rates of peak versus off-peak electricity and demand plus the value of the avoided grid upgrade.
• DLS: Ten-hour load shifting (LS10) is the shifting of 10 h of stored electricity from off-peak periods of low value to on-peak periods of high value. The reference duty cycle is a scheduled
  10-h FPD, one event per day, and 250 events per year. Such applications are valued at market rates of peak versus off-peak energy and demand plus the value of the avoided grid upgrade.
• WGS: Time-shifting (TS) firms and shapes a wind generation profile by storing wind generation during the off-peak interval (6 p.m. to 6 a.m.), supplemented by power purchased from the grid when wind generation is inadequate, and discharged during the on-peak interval (6 a.m. to 6 p.m.). Such applications are valued at the market rates for the time-shifted and shaped energy plus the capacity credit.

Although such combined benefits are readily accrued by an integrated GT&D utility, the restructuring of the utility industry typically precludes the full attribution of value for such benefits and consequently poses an institutional challenge for such DES deployment.

Leading DES Technologies

Application Assessment and Business Case

Attractive matchups of the DES system with the leading single and combined applications, based on the benefit-to-cost ratio being greater than one, are noted in Table 2 with a . In addition, marginal matchups are noted with an M for a benefit-to-cost ratio of less than but near one and considered to have economic potential within the range of market conditions. Such results provide the utility a screening tool to evaluate the technical and economic fundamentals of a business case for DES deployment for a range of the leading single and combined applications.

However, such analyses are based on representative economic groundrules and assumptions as described in the Handbook of Energy Storage for Transmission and Distribution Applications. The parameters used therein should be reviewed in light of utility- and project-specific applications, alternative solutions, electric rates, and financial parameters. Any project deployment considerations deserve detailed interactions with the respective vendors able to optimize their systems to the site-specific application(s). From that, the full DES business case can be developed with detailed functional specifications for the application(s); vendor prices, warranties, terms, and capabilities; overall costs, risks, and a benefits assessment of the DES candidate system(s); and the comparison of all the above against the competing alternative solution(s). As multiple applications can be served and related values accrued to the stakeholders, the business case for DES will improve, becoming worthy or even compelling. The utilities with the ability to achieve this will lead DES deployment into the future.

For Further Reading

EPRI-DOE Handbook Supplement of Energy Storage for Grid Connected Wind Generation Applications, EPRI, Palo Alto, CA and US DOE, Washington, DC, 1008703, 2004.

Biographies

Joe Iannucci is with Distributed Utility Associates in Livermore, California.

Jim Eyer is with Distributed Utility Associates in Livermore, California.

Steve Eckroad is the program manager for the Electric Power Research Institute (EPRI) in Charlotte, North Carolina.

These issues and the pressures from international financial organizations and donor agencies such as the International Monetary Fund (IMF) and World Bank have been the principal driving forces behind the electricity power industry (EPI) reforms in many of these countries. In more developed countries, however, the aim of electricity reform has been cited as improving the performance of relatively efficient power systems. Ever-increasing customer expectations on power quality and reliability, local and federal governments' willingness to deregulate the industry by reducing their monitoring role, further EPI investment mandates by government sectors, and governments' commitments to spend existing resources in other sectors and on more urgent social projects were among the more direct motives for EPI restructuring in those countries.

Actual reform programs exhibit a variety of designs, particularly in terms of market structure, degree of private involvement, and sequencing of reform stages. No one model fits all participating countries, and no matter which model is initially chosen, electricity restructuring is an ongoing and evolving activity. Therefore, the design of reform programs in individual countries should reflect the particular socioeconomic circumstances of a country and its electricity sector. Many power sector reform programs in developing countries, particularly in those where the power industry is organized as monopolies under public ownership (as it is in Turkey), are focused on moving from a monopoly to either a single buyer model (SBM) or directly to a wholesale competition model.

The SBM allows a state-owned single buyer or purchasing agency to encourage competition among generators by choosing its supply of electricity from a number of competitive electricity producers. Each utility in such an arrangement is still vertically integrated (although an unbundled case is also possible) and enters power purchase agreements (PPAs) with independent power producers (IPPs) through a competitive process. SBM has been adopted in many countries as a transition stage to wholesale competition, allowing additional time for generation and distribution sectors to reorganize and regroup sufficiently for participation in a competitive wholesale electricity market. Such SBM arrangements allow distribution companies (and eligible customers) to purchase electricity directly from generators of their choice, transmit electricity under an open-access transmission system to their service areas, and deliver it to their customers using local grids. Using an SBM, power sectors could undergo the unbundling of generation, transmission, and distribution and eventually establish a regulatory authority to set up a multibuyer, multiseller competitive power market in which competition could take place at the wholesale level through bilateral contracts and spot market pricing.

The popularity of the modest SBM is due to several economic, technical, and institutional factors, including the ease of network operation and control and simplicity of tariff regulation. However, the main risks involved with the implementation of this model include the ability of governments to impose inefficient regulatory practices on the market for manipulating the single buyer, the possibility of existing monopolies imposing market power, a lack of initial financial resources to implement SBM, a lack of social desire by customers to make changes in electricity utilization to empower restructuring, and the lack of government commitment to full reform in order to avoid politically controversial consequences of introducing privatization and competition.

Under the SBM, IPPs could benefit from long-term PPAs backed by government guarantees for raising long-term financial requirements. One of the major disadvantages of the SBM is that PPAs between the single buyer and private generator companies (or IPPs) could create a contingent liability for the government. When government guarantees are attractive to investors, there may be an upward bias in the generation capacity procurement, and government officials may find it difficult to resist powerful interest groups pushing for treasury-guaranteed capacity expansion. Accordingly, decisions to add generating capacity could be influenced by government officials who will not have to directly bear the financial consequences of their actions. This was experienced in Turkey during the 1990s.

Electricity Restructuring in Turkey

The Electricity Market Law (EML), enacted in 2001, aimed to put an end to those types of PPAs. EML envisioned a wholesale electricity market based on bilateral contracts allowing generation companies and wholesale trade companies, distribution companies, independent retail companies, and eligible customers (consuming more than 7.8 GWh per year) to buy electricity from their regional distributor or retailer, a wholesaler, a new independent retailer, or an independent generator. Captive customers, on the other hand, had no choice but to buy their electricity from a regional distributor or retailer. EML covers generation, transmission, distribution, wholesale, retail, and respective electricity services (including its import and export), the rights and responsibilities of individuals connected with those services, the establishment of a regulatory body, and its running procedures and principals as well as actions to be followed for the privatization of generation and distribution assets.

After the enactment of EML, an energy market regulatory authority (EMRA) was established, and generation, transmission, and trading parts of the state monopoly, Turkish Electricity Generation Transmission Co. (TEAS), were unbundled. The generation company is named Turkish Electricity Generation Co. (EUAS), the transmission company Turkish Electricity Transmission Co. (TEIAS), and the wholesale trade company Turkish Electricity Trading and Contracting Co. (TETAS). The distribution company, Turkish Electricity Distribution Co. (TEDAS), which had already been separated from the monopoly (TEK) in 1993 with an attempt to prepare it for privatization, continues to be in charge of distribution with its regional affiliate companies. Under the new structure, state-owned EUAS will take over and operate the state's existing power plants that have not transferred to the private sector. TEIAS is responsible for transmission assets, system operation and maintenance, planning new transmission investments, and building new transmission facilities. TETAS was created to carry out wholesale electricity trading; it will take over all existing energy sale and purchase agreements from TEAS and TEDAS. Indeed, dealing with the long-term treasury-guaranteed PPAs and the associated stranded costs is a primary reason for the creation of TETAS, which will be regulated because it will be the dominant buyer and seller in the market for the foreseeable future.

Market Design Issues

The privatization of state-owned distribution companies by the Turkish government through transferring their operational rights (not the ownership) is expected to solve the financial difficulties of the distribution sector, improve collections, enforce the punitive actions against nonpaying customers, and improve the reliability and quality of the supplied electricity. It may be argued that privatization can achieve these targets. However, these issues are highly political and sensitive in nature, and the punitive disconnection of nonpaying customers could ultimately need political approval. Therefore, privatization will not remove the government's responsibility and role. It is also arguable that if the government is not able to initiate these measures, private (and often foreign) ownership alone could at best only partially achieve the restructuring targets. Moreover, privatization could result in higher electricity prices in order for private investors to guarantee their service obligations. Current subsidies for residential electricity prices could make the privatization process more difficult; the removal of subsidies and ensuring a higher quality of service are major challenges, which could create social and political headaches for authorities.

Subsidies on Electricity Prices

In order to soften the public outcry against relaxing the subsidies after establishing the electricity market, all organizations involved in the electricity power sector should get involved in more aggressive public relations campaigns. The government and electricity authorities especially should do much more in explaining the core of the reform and its long-term consequences and benefits. It should be taken into account that certain relatively low-income population sectors in Turkey may not be able to bear any substantial increases to their cost of living. Therefore, it is essential to introduce incremental steps for initial energy price increases before competitions among suppliers can stabilize market prices.

A Possible Strategy for Relaxing Subsidies

The question is: If the reliability of the electricity supplied to farmers is improved, would they be able to pay their electricity bills through their increased productivity? If the farmers are able to utilize the technology efficiently, the answer certainly will be "yes." Indeed, many farmers working in similar situations in different countries confirm that they would probably not need as large a subsidy on electricity prices if they had a more reliable supply of electricity. The reliability of supplied electricity, however, can be improved mainly from the increased capital-intensive investment in rural electrification. How can farmers be convinced to pay more while the subsidy on their electricity prices is being relaxed? Service providers and farmers could negotiate based on different models to implement such plan.

In one possible model, the electricity prices could be increased in steps as the duration of the supply interruption is gradually decreased (Figure 1). Assume that the total interruption of the supply is D/month. If this duration is decreased by some amount (D), then the farmers could be convinced to pay proportionally more (P). The key point is that the total increase in the electricity price accepted by the farmers should be sufficient to recover the required investments and to relax the subsidy.

A similar method can also be applied to relax subsidies on household electricity prices in big cities where consumers complain frequently about supply interruption and agree to pay more for a more reliable electricity supply.

Competition at the Generation Segment

An ongoing electricity project the Turkish authorities are very keen to achieve is the link to the European Union (EU) electricity network, that is, the Union of Coordination of Transmission of Electricity (UCTE). Turkey eventually plans to interconnect its electrical system with the UCTE grid via the Greek and Bulgarian grid and take advantage of cross-border electricity trading with the UCTE member countries. Preliminary works for this interconnection have been carried out according to UCTE regulations. The importance of this project has increased recently, especially after Turkey attained its candidacy for the EU membership in 2004. The actual interconnection is expected to be realized within a few years. However, recent directives issued by the European Commission (EC) underscore the importance of the full opening of energy markets to improve Europe's competitiveness. The SBM is not permitted in EU membership countries because it delays the development of cross-border electricity trade by leaving it to the state-owned single buyer without a strong profit motive. The development of a retail market is proposed, which allows all electricity customers the freedom to choose suppliers.

The development of the EU electricity market with the provision of an interconnection with the Turkish electricity network seems to provide new electricity trading opportunities for companies in EU membership countries. If the market is freed up completely and subsidies on electricity prices are relaxed to a competitive level, foreign companies will be able to trade with noncaptive customers through interconnected transmission lines without the need for making new investments in Turkey.

Concluding Remarks

Opening the market to eligible ratepayers, which include subsidized residential and other electrical customers, may threaten the success of the proposed transition phase. The eligible customers will no longer be a source of cross-subsidies if they have the opportunity to buy from a cheaper supplier. For example, the interconnection of the system in Turkey with the UCTE grid could provide new electricity trading opportunities for generation companies in EU membership countries in the near future. This could lead to a substantial and immediate increase in retail tariffs for captive electricity customers, rather than a series of incremental increases over a longer period of time.

Finally, the simplicity of the tariff regulation process makes an SBM more favorable during the transition phase, provided that the additional generation capacity required during the transition phase is supplied by IPPs through a competitive process.

For Further Reading

D.M. Newbery, "Issues and options for restructuring electricity supply industries," Dept. Applied Econ., Univ. Cambridge, Cambridge, MA, DAE Working Paper WP 0210, 2002.

T. Jamasb, "Reform and regulation of the electricity sectors in developing countries," Dept. Applied Econ., Univ. Cambridge, Cambridge, MA, DAE Working Paper WP 0226, Aug. 2002.

R.W. Bacon and J.B. Jones, "Global electric power reform, privatization and liberalization of the electric power industry in developing countries," in "Annual Rev. Energy Environ. 2001," World Bank, Washington, DC, 2001, vol. 26.

L. Lovei, "The single buyer model—A dangerous path toward competitive electricity markets," in "Private Sector and Infrastructure Network," Worldbank Group, Washington, DC, Note 225, Dec. 2000.

I. Atiyas and M. Dutz, "Competition and regulatory reform in the Turkish electricity industry," Conference on EU Accession, Ankara, Turkey, May 2003.

Biography