Around the globe, the electric industry is undergoing sweeping restructuring. The trend started in the 1980s in the U.K. and some Latin American countries, and has gained momentum in the 1990s. The main motivation and driving forces for restructuring of the electric industry in different countries are not necessarily the same. In some countries, such as the U.K. and the Latin American countries, privatization of the electric industry has provided a means of attracting funds from the private sector to relieve the burden of heavy government subsidies. In the countries formerly under centralized control (central and eastern Europe), the process follows the general trend away from centralized government control and towards increased privatization and decentralization. It also provides a vehicle to attract foreign capital needed in these countries. In the United States and several other countries where the electric industry has for the most part been owned by the private sector, the trend is toward increased competition and reduced regulation.
This article presents an overview of the evolving structural models and the main structural components of the emerging deregulated electricity industry. An analysis of the central structural components, namely the independent system operator (ISO) and the power exchange (PX), is provided and used as a basis for structural classification with a view to the supporting computer application needs.
Restructuring Framework
A variety of restructuring models are being proposed, considered, and experimented with in different countries. The unbundling of generation from transmission and distribution as separate businesses is prevalent among different models. The transmission sector is re- garded as a natural monopoly, and in general remains regulated in order to permit a competitive environment for generation and retail services.
In many structural models, vertical unbundling involves only a functional separation. This is the case in the United States, where Order 888, issued on 24 April 1996 by the Federal Energy Regulatory Commission (FERC), mandates functional unbundling of generation and transmission services, but does not require corporate restructuring. Transmission open access (TOA) is mandated in order to facilitate competition in wholesale generation.
The transmission sector and its products and services may be further unbundled, allowing their provision and/or trading as separate commodities if the transmission users so desire. The most usual unbundling of transmission services includes separation of basic network transport services from transmission support services (ancillary services), as described later.
Figure 1 shows the main structural components of the new electricity market. Each component of this model represents a segment of the emerging electricity market. These include generating companies (G), power marketers (PM), power exchanges (PX), transmission owners (TO), the independent system operator (ISO), ancillary service providers (AS), scheduling coordinators (SC), retail service providers (R), and distribution service providers (D). In this model, generating companies and power marketers represent the primary and secondary generation sectors respectively. The distribution sector is represented by the retail service providers and the distribution service providers. The transmission sector includes the transmission owners, transmission service providers (generically designated by the ISO), the ancillary service providers, and the transmission users (represented by the PX and the SCs). The transmission sector is central in the emerging energy market and is the focus of this article.
Structural Components of the Transmission Sector
Since the transmission sector is of particular interest in this article, the market segments that comprise the transmission sector are explored further. The main functions of each market segment are described briefly. These functions determine the computer applications needed to support each market segment. Since the ISO is a central component of the emerging transmission business, the main functions of the ISOs are described more thoroughly in a subsequent section.
Transmission Owners
The basic premise of transmission open access is that the transmission owners/providers treat all transmission users on a nondiscriminatory and comparable basis regarding access to and use of the transmission system and services. This requirement could be difficult to ensure if the transmission owners have any financial interests in energy generation or supply. A general trend is, therefore, to designate an ISO to operate the transmission system and facilitate provision of transmission services. Maintenance of the transmission system generally remains the responsibility of the transmission owners.
The computer applications pertinent to transmission owner functions include mainly the classical transmission planning tools, possibly augmented and supplemented by new tools to account for market signals. The latter include tools to account for transmission congestion revenues, primary and secondary markets for financial transmission rights, and use of transmission infrastructure for other markets such as communications.
Independent System Operator
The ISO operates the transmission grid and provides transmission services to all transmission customers. The basic requirement of an ISO is lack of financial interest in generation resources and load markets. In most cases, the word "independent" is interpreted to also convey the requirement for lack of interest in and ownership of transmission facilities. However, there is no universal requirement in the context of transmission open access to separate transmission ownership and operation. For example, in the U.K., NGC is both the owner and operator of the transmission system. The extent of authority and responsibility of the ISO varies widely in different existing and emerging structures. This issue will be scrutinized further later in this article, along with a discussion of the computer applications needed for different types of ISO functions.
Power Exchange
The primary function of a power exchange is to provide a forum to match electric energy supply and demand in the forward energy markets. The market horizon may range from an hour to a few months. The most usual situation is a day-ahead market to facilitate energy trading 1 day before each operating day. Depending on the market design, the day-ahead market may be preceded by a longer term market and supplemented by hour-ahead markets. An hour-ahead market provides energy trading opportunities up to 1 or 2 hours before the operating hour.
In its simplest form, a power exchange may provide a bulletin board type of an environment for energy suppliers and energy customers to engage into bilateral forward contracts. However, the more usual function of the power exchange is to act as a pool for energy supply and demand bids, and establish a market clearing price (MCP). The market clearing price is then the basis for the settlement of the forward market commitments. Regardless of their asking prices, all selected bidders are paid the MCP. This approach is adopted to encourage the bidders in a competitive market to price energy close to their marginal cost.
Depending on the market design and activity rules, the energy bids may include several price components (multipart bid) or a single price component (single-part bid). A multipart bid may include separate prices for unit startup, no-load operation, and energy. A single-part bid would offer an energy price inclusive of other fixed or variable costs. In either case, the energy bid may include several energy price segments ($/MWh) depending on the amount of energy (e.g., a separate $/MWh price for each block of energy from the same unit or portfolio of units).
The PX market design, bidding protocols, and bid selection (scheduling) process will have a direct impact on the computer applications needed to support the PX. In the case where the market design is based on single-part bids, a simple market clearing process based on the intersection of supply and demand bid curves may be sufficient to determine the winning bids and schedules for each hour. However, if the market design is based on multipart bids, a unit commitment software, possibly with enhancements to take into account security constraints (security constrained unit commitment, SCUC) may be needed.
The complexity of the bidding infrastructure and system is also dictated by the market design and protocols. If the PX market allows iterative bidding, as is common with single-part bids, the bidding infrastructure and system may have stringent performance requirements. Since multipart bid systems do not require bidding iterations with the market participants, the bidding system performance requirements for multipart bid markets may be less stringent than those for markets with single-part bids.
Ancillary Service Providers
Ancillary service providers supply the transmission network support services that are needed for reliable operation of the power system. The majority of ancillary services (A/S) are, in fact, real or reactive power/energy resources needed to operate the transmission system in a secure and reliable manner.
Depending on the organizational structure adopted, ancillary services may be traded in the power exchange, the ISO market, or both. In either case, the ancillary services may be provided in a bundled manner or as an unbundled menu. In some cases, e.g., in the U.K., the transmission system operator procures these services and charges the users of the transmission system at a bundled rate, through the so-called "uplift."
In the United States, FERC Order 888 requires the ISO (transmission provider) to offer some of the ancillary services in an unbundled manner, giving the transmission users the choice to either self-provide or request the ISO to provide them. Four of these services may be self-provided by the user of the transmission system:
- Regulating reserve
- Spinning reserve
- Supplemental operating reserve (nonspinning reserve)
- Energy imbalance.
In case the transmission user does not provide them (directly or through third-party arrangements), the user must purchase them from the ISO. The ISO must offer these services, and will usually procure them through a competitive auction in the forward market and charge the users according to their ancillary service responsibility not self-provided. Two other ancillary services are procured and provided by the ISO, and the users must purchase them from the ISO:
- Reactive power/voltage support
- System control/redispatch.
In fact, these are the six ancillary services that FERC Order 888 requires the ISOs to offer.
Some other transmission support services, such as loss compensation or backup support, may or may not be offered by the ISO. For example, the transmission user agents (scheduling coordinators) may be required to submit balanced schedules, i.e., include transmission losses in their schedules based on transmission loss factors published by the California ISO. This is the situation in California.
The term interconnected operations services (IOS) is sometimes used to include all ancillary services including, but not limited to, those mandated by FERC. Table 1 lists the IOS and its FERC subset of ancillary services. In the case of California, black start is included among ancillary services to be provided by the California ISO, and a special ancillary service (replacement reserve) is defined to cover the discrepancies between the ISO load forecast and the forecast (preferred schedule) by market participants (PX and other SCs).
The bidding and scheduling protocols adopted for the provision and procurement of ancillary services will dictate the complexity of the computer applications needed. Optimal procurement of ancillary services may entail simultaneous processing of energy and ancillary service bids, if allowed by the market protocols. This would require complex optimization software, particularly if simultaneous optimization of both bilateral and pool-wide provision of energy and ancillary services is targeted. Some market structures, such as the Californa market, disallow such simultaneous optimization, and require separate market clearing mechanisms for enegy and ancillary services. This simplifies the software. Further software simplification may be realized if the processing is carried out sequentialy for each of the ancillary services. This may, however, result in nonoptimal procurement, i.e., higher cost of ancillary services to the transmission users and the end-use customers. This is the approach originally adopted in California, but currently under revision for a more rational buyer approach to ancillary service procurement.
Scheduling Coordinators
Scheduling Coordinators (SCs) are entities that put together supply and demand energy schedules without necessarily abiding by the rules of a Power Exchange. The Power Exchange may thus be viewed as a regulated SC. Some structures restrict forward schedule coordination to a central pool and do not permit other SCs to operate. The U.K. is an example. In some other structures no central pool or regulated Power Exchange exists; schedule coordination is done in a decentralized manner often by the existing control areas. This is the situation in ERCOT and the Mid-West ISO, and the structure contemplated by IndeGO. In many new and emerging structures SCs are integral components of the market. California and New York Power Pool are examples.
Scheduling Coordinators generally need a combination of classical energy scheduling computer applications such as Unit Commitment, as well as a mix of new tools for market analysis, strategic bidding, and contract optimization. They would generally also need metering, accounting, settlement, and billing systems to settle with their clients and with the ISO.
Classification of Transmission Sector Structures
The structural components mentioned in the previous section may or may not be present in a specific restructuring model. In some cases one or more of the segments are missing. In other cases, two or more of these structural components are merged and delegated to a single entity. Examples of some existing transmission structures are given in Figure 2. The segments with joint boundaries represent a single entity.
The existing and emerging structures may be broadly classified as follows:
- Structures with no power exchange (examples: ERCOT, IndeGO, and Mid-West ISO)
- Structures with no scheduling coordinators (examples: NGC and Alberta)
- Structures with merged ISO/PX (examples: PJM and Victoria PX)
- Structures with merged ISO/PX/TO (example: NGC)
- Structures with separate ISO and PX (examples: California, Norway, and Alberta).
The structure adopted in each case is to a large extent influenced by the scope of responsibility and authority delegated to the entity responsible for the day-to-day operation of the transmission system, i.e., the ISO. In the next section, we provide a classification of the ISO functions with a view to the supporting computer applications and systems needed in each case.
Classification of ISO Functional Structures
The responsibilities and scope of activities of the different ISOs existing or emerging in the U.S. and other countries around the world, vary widely. To facilitate classification of the ISO structures and the relevant computer applications, it is helpful to consider the ISO's role and responsibilities in each of the following areas:
- Operations planning/scheduling
- Dispatching
- Control and monitoring
- Online network security analysis
- Market administration
- Transmission planning/ownership.
Possible ISO responsibilities in each of these areas are discussed briefly, as follows. The ISO responsibilities as classified here form a basis for classification of functional requirements of the ISO computer applications and systems.
Operations Planning/Scheduling
The responsibilities of the ISO in this area could include scheduling of generation resources, ancillary services, and transmission facilities.
Generation scheduling may or may not be included among ISO responsibilities. It may be limited to scheduling of ancillary services. In case the organizational structure does not provide for an energy market, the ISO's role in scheduling will be limited to ensuring that the submitted schedules do not cause transmission congestion. This is the situation in ERCOT and the Mid-West ISO.
The same situation applies if an energy market exists, but another entity is responsible for its operation. The California ISO is an example, where the California Power Exchange (PX) is handling the energy market. In fact, in the case of California, the separation between the ISO and the PX is quite strict. The ISO is expected to treat the PX as any other Scheduling Coordinator.
In cases where the ISO is also responsible for the energy market, generation scheduling falls within the ISO's area of responsibility. This is the situation in PJM and the New England ISO (NE ISO).
In cases where generation scheduling is included among ISO's responsibilities, the ISO may or may not be responsible for Unit Commitment. If bidding protocols for generation resources allow for multipart bids, (i.e., separate prices per MWh generation, start-up and no-load operation), the ISO scheduling process must take into account Unit Commitment type data including start-up price, no-load price, minimum up and down times, ramp rates, etc.
Management of transmission congestion is an ISO responsibility in almost all restructuring models. It may be included among the ISO's scheduling functions, dispatching functions or both. Congestion management may be carried out based on a nodal or zonal pricing framework. For example, PJM and New York ISO have adopted the nodal pricing model, whereas California has chosen the zonal approach to congestion management and pricing.
Optimal power flow (OPF) is often the core application used for congestion management and pricing in conjunction with generation and ancillary service scheduling applications.
Dispatching
The responsibilities of the ISO in this area could include dispatching of generation resources, ancillary services, and transmission facilities.
Depending on the restructuring model adopted, the ISO may have the authority to redispatch generation in case of transmission congestion. Congestion management may involve changes in generation or load (through demand-side management) based on incremental and decremental prices quoted by the users of the transmission system. This is the case for the California ISO. Congestion management may also involve curtailment of bilateral transactions, based on established priorities. This is how MAPP handles congestion management (line loading relief procedure) at present, and contemplates to continue the process in its emerging ISO.
Depending on the market rules and protocols, the ISO dispatch and real-time control functions may be combined in a single application package, along the lines of the classical automatic generation control and economic dispatch (AGC/ED), or may be separated in two different systems. For example, in the case of the California ISO, a balancing energy and ex-post pricing (BEEP) software is used to perform the economic dispatch and load following functions separately from (but with an interface to) the AGC function.
Control and Monitoring
The ISO may or may not have the authority and the means for supervisory control and/or real-time control of generation. The ISO's role in real-time control of generation may be limited to the coordination and monitoring of the operation of control areas under its jurisdiction. In that case, each control area will perform its own automatic generation control (AGC). This is the situation in ERCOT. In California, the ISO is responsible for AGC.
Network Security Analysis
The ISO is generally responsible to ensure security of system operation against occurrence of credible contingencies. The ISO may perform this task by using operating nomograms, estimated operating data, and an offline power flow or contingency analysis program. In many emerging ISOs, however, the ISO will generally need to perform online contingency analysis.
Market Administration
The ISO may or may not be responsible for administration of an energy market. In either case, the ISO may administer a market for ancillary services.
The ISO's involvement in the settlement process depends on the scope of its responsibilities and interaction with the market players. The ISO usually settles with the users of the transmission system for the costs it incurs to perform congestion management and to procure ancillary services, as well as its administrative costs. Depending on the market rules and number of markets (day-ahead, hour-ahead, etc.) multiple settlements may take place with the same participant for a given period. For example, in California, a three-settlement system prevails, namely, day-ahead, hour-ahead, and real-time. The day-ahead settlement is based on day-ahead schedules, the hour-ahead settlement pertains to changes from the day-ahead commitments, and the real-time settlement is based on deviations from the last committed schedules (day-ahead or hour-ahead, as the case may be). The California ISO performs the settlement function for all ISO market commodities (ancillary services, congestion, and real-time balancing energy) with its clients (PX and SCs) and the TOs.
The computer applications needed to support the ISO's market administration functions may include the settlement, billing and credit, and participant registration software. Metering and meter data reconciliation may also be included among the market administration functions of the ISO. The ISO may elect to outsource some of these services, such as participant credit check or meter data reconciliation.
Market surveillance and compliance monitoring are among other market administration functions of the ISO. These may require dedicated software.
Ownership/Planning of Transmission Assets
The ISO may or may not own transmission assets. In general, however, it is responsible for coordinated planning of the transmission facilities. If the initial transmission providers or other parties do not invest to build the needed facilities, the ISO will often have to have it built and recover the costs from the transmission users following approved procedures. In case several candidates offer to build the facilities, the ISO will conduct an auction. The computer applications needed for this ISO function include the conventional transmission planning computer programs with possible enhancements to accommodate long-term market signals.
Classification of ISOs
The six areas of responsibility discussed above may be used as differentiating elements to detect similarities and differences among various existing and emerging ISOs and the supporting computer applications and systems they need to perform their functions.
A brief survey of the existing and emerging ISOs reveals that at a minimum the responsibilities of an ISO include coordination of operations planning within the ISO's area of jurisdiction. Such a minimalist ISO intervenes in operations planning/scheduling only in case the schedules developed by the participants (control areas, scheduling coordinators, etc.) is likely to result in transmission congestion. It will also coordinate measures to alleviate transmission congestion. A minimalist ISO does not perform real-time control. It may, however, monitor the operation of the power system to ensure adequacy of available reserves and other pertinent ancillary services. Examples of minimalist ISOs are ERCOT and MAPP.
At the other end of the scale, some existing or emerging ISOs have a wide range of responsibilities and authority. The so-called maximalist ISO would perform generation scheduling (possibly including unit commitment) and scheduling of ancillary services. It would dispatch generation for energy imbalance and ancillary services, as well as congestion management. It would perform real-time control of generation, transmission, and ancillary resources. It would facilitate an energy market either directly, or in coordination with a Power Exchange. It would plan and execute transmission system expansion (although it may or may not own the transmission assets). The PJM ISO is an example of maximalist ISO. NGC in the U.K. is another example, where the ISO assumes ownership of transmission assets.
Figure 3 schematically shows the six areas of responsibility defined previously as vertices of a hexagon. This is used in Figure 4 to illustrate where various ISOs fit in this scheme. The scope of responsibility and authority in each area is shown by the distance from the center of the hexagon. The fill area represents the relative scope of responsibility and authority of the ISO in each case. A maximalist ISO would have a large fill area; the fill area for a minimalist ISO would be small. ISOs with similarly shaped fill areas are generally expected to have similarities between the support systems (applications) and infrastructure that they need.
ISO Computer Applications and Systems
The ISO responsibilities and functions determine the scope and complexity of the computer applications and systems needed for different ISOs. Despite differences in scope and complexity, various computer application functions may be further grouped into the following broad categories:
Scheduling (or bidding) infrastructure system provides the computer and communication hardware, software, databases, and user interface allowing interaction of the outside world (market participants) with the ISO. It supports the bidding protocols, and facilitates publication of market information, often using the Web technology to the maximum extent possible along with necessary data security measures.
Scheduling applications system supports the operations planning (scheduling) functions. It may also include the security assessment functions. The application functions included in this category are time critical for proper operation of the competitive market but may not be time critical for power system operation.
Real-time control system includes the power system control and monitoring applications. These functions are time critical for power system operation. Their execution periodicity and response times are often too fast to permit market interaction.
Business system includes settlement and billing functions, along with participant registration and credit check applications. The ISO may outsource some of these services rather than implementing the functions.
Metering system includes metering and meter data correction and reconciliation equipment and functions. The ISO may outsource this activity to a so-called metering agent rather than implementing the system. The metering agent will then provide settlement-ready data for use by the ISO business system.
The real-time control system has an extremely high availability requirement. The availability requirements of the scheduling infrastructure and scheduling applications systems are high, but less stringent than the real-time control system. The business system has lower availability requirements.
