Learning the trade
California has been down the road of deregulation, retail competition and subsequent implementation of a trading system. With EU countries being forced to open up their markets to competition, a look at the Californian experience could be useful to those countries looking at setting up trading systems of their own.
Dr Farrokh Albuyeh,
ABB Energy Information Systems,
Santa Clara, California, USA
With a few exceptions, most states in the US have started the deregulation process. A key to whether these states will successfully operate a fully deregulated market depends on how well the necessary electricity trading markets are implemented and operated. In the US, California has led the way in setting up a competitive market. Both the California Independent System Operator (ISO) and the Power Exchange (PX) started operation in March of 1998, three months behind the originally mandated schedule. And although implementation of the ISO and the PX in such a short schedule was a monumental task, both systems have been operating successfully for over a year now.
So far, much of the focus of deregulation has been on the creation of grid operators. The market operators (see box) such as PXs seem to have taken a back seat. In a number of regions, the functions of the PX is performed by the grid operator. Two such examples are the New York ISO and Pennsylvania-Jersey-Maryland (PJM).
Currently there are only four ISOs in various stages of operation in the US. These are: California Independent System Operator (CAISO); Pennsylvania-Jersey-Maryland Interconnections LLC (PJM); ISO New England, Inc. (ISO NE); and the New York ISO (NY ISO).
Of these, CAISO is in the forefront. CAISO started operation in March 1998 as a system operator and a market operator for ancillary services. It is one of only two fully functional ISOs operational in the US today. The structure of the CAISO was developed from scratch with the first employees hired in May 1997.
Pennsylvania-Jersey-Maryland Interconnections LLC (PJM) is the other fully functional ISO in the US. It started life as a pool operator in the 1970s. PJM began independent operations in April of 1997.
ISO New England, Inc. (ISO NE) is yet to operate any real markets. Energy and Ancillary Services markets are scheduled to start operation in the first quarter of 1999.
The New York ISO (NY ISO) is being implemented in phases. The Federal Energy Regulatory Commission (FERC) issued the order conditionally authorizing the establishment of the NYISO on June 30, 1998.
Deregulation of the electric power industry in the state of California started in December 1995. Prior to deregulation, the electric power industry in the state of California was characterized by three large investor-owned, and vertically integrated utilities, Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric; and a number of municipalities, and independent power producers (IPPs).
The transmission owners were obligated to purchase the output of the IPPs at their own replacement costs. The energy consumers were served by the utilities that serviced their respective geographic areas. The generation facilities include a mix of resources. However, the transmission facilities presented several transmission bottlenecks.
Figure 2 shows an overview of the new electricity market structure. In the California market the PX and the Scheduling Coordinators (SC) create the spot market for electric energy. All energy supply and demand in the system must be bid through the PX or the SCs. There is a requirement that, for the first five years of operation, the generation owned by the existing three investor-owned utilities (Pacific gas & Electric, Southern California Edison, and San Diego Gas & Electric) can only be bid through the Power Exchange. The PX and the SCs must submit balanced portfolios for energy to the ISO.
A balanced portfolio for energy includes schedules for generation, load, imports, exports, and trades of energy with other SCs. Losses are accounted for in the generation schedules. The SCs and the PX determine the amount of losses using the so-called `generator meter multipliers` (GMM) that are similar to traditional generator penalty factors and are calculated and published ahead of time by the ISO.
The ISO market participants (MP) may choose to self-provide for the ancillary services that are required to support their energy schedules. They may also opt for the ISO to procure the required ancillary services on their behalf.
The ISO creates a market for ancillary services. It first determines the requirements for additional ancillary services beyond those already provided by the PX and the SCs as self provision, and it then selects and prices the most economical services from the bids submitted by the SCs.
Initially, three separate physical markets were defined. These were:
1. The day-ahead;
2. Hour-ahead; and
3. Balancing (real-time) markets.
The day-ahead market is composed of 24-hourly markets for energy and ancillary services. The hour ahead market includes markets for energy, ancillary services and balancing energy. The Balancing market, as the name implies, is for balancing energy.
The commodities traded in these markets include energy, ancillary services, and supplemental energy. The energy commodity includes load, generation, imports, exports, and trades of energy among SCs. The ancillary services handled by the California market include spinning reserve, non-spinning reserve (dispatchable load and generation), replacement reserve (dispatchable load and generation), regulation, reactive power and voltage control, and black start capability. The markets for the last two ancillary services, reactive power and black start, are handled manually.
Currently, the California ISO is in the process of upgrading the system to create a long term (yearly) and short term (day-ahead and hour ahead) market for transmission capacity or the Firm Transmission Rights.
Efforts are also underway, to extend the inter-SC trades to include trades of ancillary services among SCs.
The California ISO
The California ISO system is composed of five major components: the metering data acquisition system (MDAS); scheduling infrastructure (SI); scheduling applications (SA); balance of business systems (BBS); and the power management system (PMS).
$#8226; The metering data acquisition system (MDAS): The function of the metering system is collect the revenue metering data related to all resources that are scheduled through the system by the PX and by the SCs. These include all loads, generations, imports, and exports.
$#8226; The Scheduling Infrastructure (SI): The primary interface between the ISO and the market participants (PX and the SCs) is through a private intranet called Wenet. Some public market information is also posted on the public Internet.
The market participants (MPs) interface to the system using standard browsers such as the Netscape navigator or the Microsoft Explorer using ISO-supplied templates and web pages.
All schedules and bids are received, validated, and processed by the SI. If errors are found, they are reported back to the market participants. When schedules are adjusted as a result of the congestion management process, the adjusted schedules are communicated back to the MPs, who will in turn, submit their revised schedules. The design objectives for the SI are security, performance, and reliability.
The SI provides the database platform to maintain and to process the schedules and the facilities to provide the interface with the MPs.
$#8226; Scheduling Applications (SA): The scheduling applications constitute the decision support system of the ISO. The main modules of the SA are: ancillary service scheduling and pricing; congestion management and pricing; over-generation mitigation; balancing energy and ex-post pricing; and transmission assessment
$#8226; Balance of Business Systems (BBS): The `balance of business systems` handle the financial and administrative tasks of the ISO. The main modules of the BBS are:
$#8226; Settlements: The ISO is required to settle to zero. That is, all income must be equal to the payouts. The settlements module analyzes data obtained from the metering subsystem and uses the final committed schedules and prices to calculate the settlement reports. The mathematics of the settlements subsystem are very straight forward: billable quantities are multiplied by the appropriate prices to calculate the amount to be billed or to be paid out. The main difficulty is keeping track of all the details that are involved.
$#8226; Billing & credit: This module is responsible for keeping track of the MP`s credit information and providing the mechanism to generate bills and billing statements.
$#8226; Administrative systems: These include general office automation packages such as word processing, spreadsheets, project planning, human resources packages etc.
$#8226; Power Management System (PMS): The `power management system` is a conventional SCADA/EMS. The main modules of the PMS are the system dispatch functions, and the network security functions. The dispatch functions include `automatic generation control`, `resource scheduler`, and `merit order dispatch`. Network security functions include `network topology processor`, `state estimation`, `security and stability validation`, `optimal power flow`, `dispatcher power flow`, and `network sensitivity calculations`.
The PMS is connected to the existing area control centres through ICCP links. In the initial phase of the operation, a hierarchical automatic generation control scheme was used where the ISO dispatched generation on a system-wide basis and sent the area requirements to the area control centres that, in turn, performed load frequency control and sent dispatch signals to the generating units. Subsequently, in the second phase of the operation a centralized generation control is being used. The ISO performs all the automatic generation control functions on a system-wide basis and dispatch instructions are sent to the generating units via the area control centres.
Another salient feature of the centralized AGC process is the interface with the `scheduling applications` and the method by which the `balancing energy and ex-post pricing` function calculates the supplementary energy bids and ancillary services in support of the AGC function.
The restructuring and the deregulation of the electric power industry in California was implemented in record time and against all odds. In contrast to other states, the structure and the systems supporting it, for the most part, had to be designed and built from the ground up.
Nevertheless, the California ISO and PX systems have performed, as expected and passed fire tests during all-time high peak load conditions in the summer of 1998. From an operational viewpoint, the control performance of the electric power system in California has improved significantly. This is primarily due to the fact that the system is now being controlled as a single control area instead of as three separate control areas as in the past. As far as the market performance and the costs to end use customers, the jury is still out.
The regulatory process was very slow and took the lion`s share of the time. However, once the decision to deregulate was made, a very short schedule for the implementation of the plan was mandated. It was then left up to the designers and implementers to solve the technical issues in the given time frame.
Many of the technical solutions had never before been implemented or tried. Some of the other issues that had to be dealt with included:
$#8226; The implementation schedule, although short, was mandated by law and there were severe penalties associated with any slippage
$#8226; There were a number of external systems such as the area control centres, regional dispatch centres, etc, that had to be interfaced with
$#8226; There were no detailed functional or design documents that were prepared ahead of time. The implementers had to adopt a “go as you build” strategy to meet the schedule
$#8226; Market processes were not defined in detail
$#8226; The infrastructures of the PX and the ISO did not exist half way through the project. The customers for the systems being built were unknown
$#8226; The market protocols, the resulting technical requirements, and the regulatory mandates, continued to change during the course of implementation. Many systems and subsystems had to be redesigned and rebuilt to accommodate the changes
$#8226; Because of the financial implications, testing of the systems had to be very thorough
$#8226; The market participants and system operators had to have had sufficient training by day one of the market operation
$#8226; The initial systems were designed by committees and reflected many contradictory viewpoints and requirements
$#8226; The market participants had to become involved in the design and implementation process.
These and many other issues, made the restructuring and implementation of the system supporting it a true challenge. Many of the complexities that existed in California are present now in mainland Europe.
Many organizations are sceptical that deregulated markets can be introduced within the timeframes mandated by the European Commission. The experience in California, however, has shown that given the will and the resources, almost any technical and schedule challenge can be overcome.
Structure of the California deregulated electricity market
The main elements of the California electric market are the Independent System Operator (ISO), the Power Exchange (PX), and the Scheduling Coordinators (SC).
(1) The Independent System Operator: The primary responsibilities of the ISO are:
$#8226; Ensure grid reliability
$#8226; Provide non-discriminatory and open access to the grid
$#8226; Schedule all power through the grid, and balance the grid operation
$#8226; Manage transmission congestion and constraints
$#8226; Competitively procure and operate ancillary services
$#8226; Provide information to market participants
$#8226; Settle the real-time energy and ancillary services markets.
Additionally, the ISO is in the process of setting up a market for transmission capacity. As a part of this new service, the ISO will auction transmission capacity on interfaces between the major congestion zones and interfaces with external systems. The transmission capacity rights, referred to as the Firm Transmission Rights (FTR), will be used as a hedge against congestion on specified paths, and will entitle the FTR owner to priority scheduling rights and a share of the transmission-use revenues.
With a peak demand of over 45 000 MW, the California ISO is the second largest control area in the United States and the fifth largest in the world.
(2) The Power Exchange: The main responsibilities of the PX are:
$#8226; Provide a competitive spot market for energy
$#8226; Determine day-ahead and hour-ahead market clearing price for energy based on a least-cost balanced schedule
$#8226; Procure adequate ancillary services on a least cost basis
$#8226; Act as scheduling coordinator for PX participants
$#8226; Perform settlements process for the market.
(3) The Scheduling Coordinator: To qualify as an SC, certain financial and technical requirements must be met. In addition, the SC must have access to and commitment from the resources, both supply and demand, that it is representing. The responsibilities of the SCs are very similar to those of the PX.
Figure 1. Generation mix in California 1996
Figure 2. California electricity market overview
Figure 3. California ISO overview