I



Implementation of the California

Independent System Operator

Farrokh Albuyeh, Senior Member, IEEE Ziad Alaywan, Member, IEEE

ABB Energy Information Systems California ISO

Santa Clara, CA. 95050 USA Folsom, CA. 95630 USA

Abstract: The Assembly Bill 1890, signed in September 1996, opening the California Electricity Industry to open competition, required the creation of an Independent System Operator and a Power Exchange. The first contract for the implementation of the California ISO was signed in December of 1996, and subsequent contracts were signed on March 31, 1997. The California ISO started commercial operation on March 31, 1998 and in its first few months of operation has proven its viability. This paper provides an overview of the California ISO.

Keywords: Electric Industry Restructuring, Open Transmission Access, Independent System Operator, Power Exchange, Electric Energy Trading, Ancillary Services.

INTRODUCTION

The de-regulation of the electric power industry in the state of California began with the ruling by the California Public Utilities Commission (CPUC) in April of 1994. Subsequently, the passage of Assembly Bill (AB) 1890 in September of 1996 required the establishment of an Independent System Operator (ISO) to coordinate safe and reliable delivery of power and to provide open access to the providers and consumers of electric energy. AB 1890 also required the creation of an Independent Power Exchange to create a spot market for energy. The first contract for the implementation of a Power Management System (PMS) as a part of the ISO was awarded in December of 1996. The contracts for the remaining parts of the ISO, including the Scheduling Infrastructure (SI), Scheduling Applications (SA) and the Balance of Business Systems (BBS) were awarded by the end of March 1997. It was also required that the ISO commence operation on January 1, 1998; allowing less than 9 months for the development, integration, testing, and training of the market participants in using the system.

The implementation of the California ISO was a “from-the-ground-up” effort. It included (a) the formation of the project management teams, (b) the implementation of the hardware/software systems for the ISO, the communications systems, and the metering system, and (c) the basic ISO infrastructure. It also included the hiring of the ISO staff, and the selection and outfitting of the primary and backup sites in, respectively, Folsom and Alhambra, California.

The following sections describe the structure and functions of the ISO. More information can be obtained from [1].

THE CALIFORNIA MARKET STRUCTURE

The main elements of the California electric market are the ISO, the Power Exchange (PX), and the Scheduling Coordinators (SC). The responsibilities of each entity are defined next.

1 The Independent System Operator

The primary responsibilities of the ISO are:

• Ensure grid reliability

• Provide non-discriminatory and open access to the grid

• Schedule all power through the grid, and balance the grid operation

• Manage transmission congestion and constraints

• Competitively procure and operate ancillary services

• Provide information to market participants

• 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.

2 The Power Exchange

The main responsibilities of the PX are:

• Provide a competitive spot market for energy

• Determine day-ahead and hour-ahead market clearing price for energy based on a least-cost balanced schedule

• Procure adequate ancillary services on a least cost basis

• Act as Scheduling Coordinator for PX Participants

• 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.

4 The Markets and Market Commodities

Initially, three separate physical markets were defined. These included the Day-Ahead, Hour-Ahead, and 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.

As was mentioned before, 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.

5 Market Overview

Figure 1 shows an overview of the California electric market structure.

In the California market the Power Exchange (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.

THE CALIFORNIA ISO OVERVIEW

The basic structure of the California ISO is shown in Figure 2.

The California ISO system is composed of five major components including the Metering System, Scheduling Infrastructure (SI), Scheduling Applications (SA), Balance of Business Systems (BBS), and the Power Management System (PMS). These components are described in the following sections.

1 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.

2 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 interface to the system using standard browsers such 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. The main modules of the SI are described below:

Bidding & Schedule Management: This module analyzes the incoming schedules, performs two phases of validation, and informs the MPs of any errors that are found. In the first validation phase, schedules are checked for syntax. In the second phase, they are checked for inter-related data such as consistency, balance, etc. Once schedules are evaluated, the MPs are informed of the acceptance of the schedules. In cases where the initial schedules are adjusted by the ISO, the MPs are informed of such adjustments. The module, through the use of Java Applets, will also inform the MPs of various market events such as the opening and closing of markets and approaching deadliness.

Market Information Publishing: This module publishes the market information to the market participants. Information such as forecasted loads, generator meter multipliers, forecasted congestion conditions, forecasted loop flows are made available to the market participants.

3 Scheduling Applications (SA)

The Scheduling Applications constitute the decision support system of the ISO. The main modules of the SA are:

Ancillary Service Scheduling & Pricing: This module analyses the submitted schedules and forecasted conditions and determines the required levels of ancillary services of each type. The module will then select the most economical set of ancillary services from the submitted A/S bids to satisfy the requirements. In cases where there are congestion, the module will treat each congestion zone separately. Currently the system is being modified to allow the trade of A/S among the SCs.

Congestion Management & Pricing: The ISO service area is currently divided into four major congestion zones. External parts of the system are also identified as congestion zones. In all, there are 23 congestion zones defined in the California ISO service area. A two step process is used to mitigate congestion. Inter-Zone congestion management process is concerned with congestion between major congestion zones. A DC Optimal Power Flow-based method is used to adjust the submitted schedules to remove flow limit violations on the interfaces connecting the congestion zones. The function calculates the incremental prices for each bus of each zone and then calculates the average of the bus prices in each zone to arrive at the zonal marginal prices. The difference between marginal prices of two connecting zones is the transmission usage charge for transferring energy on the connecting path.

Intra-Zone congestion management, on the other hand, is concerned with congestion within each zone. An AC Optimal Power Flow-based solution method is used to adjust schedules to ensure that branch flow limits and bus voltage limits are respected. During the Intra-zonal congestion management process, the terminal conditions at the boundaries of the congestion zone are fixed at the values calculated by the Inter-zonal congestion management process.

In both Inter and Intra-zonal congestion management, a set of so-called “market separation constraints” are enforced. The market separation constraints ensure that the balance of the SC’s portfolios is maintained during the schedule adjustment process [2,3].

Over-Generation Mitigation: In the initial design of the SA, a process to deal with situations where there existed excess generation in the system was envisioned. The function of the Over-generation Mitigation function was to back down generation in a pre-defined priority order, in order to provide balance between load and generation. However, this provision was eliminated by the FERC from the filing that was approved in October of 1997 and the function was disabled in the ISO.

Balancing Energy & Ex-Post Pricing: The objective of this module is to schedule resources to meet real-time imbalances between actual and scheduled load and generation. The resources include spinning, non-spinning, and replacement reserves arranged in the day-ahead and hour-ahead markets and supplemental energy bids. The module orders and selects resources according to prices to meet energy imbalances. This module interfaces with the on-line Automatic Generation Control function to communicate the real-time dispatch instructions to generating units that have provided spinning, non-spinning, and replacement reserves as well as supplemental energy bids.

Transmission Assessment: The transmission assessment functions in the Scheduling Applications include:

• Available Transfer Capability- to calculate the simultaneous power transfer capability on major interfaces in the system;

• Voltage Collapse Analysis- to analyze the voltage profile of the system and to determine margins to voltage collapse in selected parts of the system;

• Transient Stability Analysis- to analyze stability of the system;

• Contingency Analysis- to analyze the security of the system against a large set of possible outages;

• Transmission Loss Rate Calculation- to calculated the sensitivity of system losses to changes in generation, import, and export patterns and to calculate the Generator Meter Multipliers.

• Other supporting functions such as load forecasting, outage scheduling, network topology processing, power flow calculation, bus load scheduling, and interchange scheduling.

4 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:

Settlements: The ISO is required to settle to zero. That is, all income must 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 to keep track of all the details that are involved,

Billing & Credit: This module is responsible to keep track of the MP’s credit information and to provide the mechanism to generate bills and billing statements.

Administrative Systems: These include general office automation packages such as word-processing, spreadsheets, project planning, human resources packages etc.

Master File: The master file contains up-to date information regarding the current market place. Information such as who are the current scheduling coordinators, what resources they are responsible for scheduling, and where these resources are located are maintained in the master file. The master file is updated every day at midnight and is then propagated to the Metering System and the Scheduling Infrastructure.

5 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 & Stability Validation, Optimal Power Flow, Dispatcher Power Flow, and Network Sensitivity calculations.

The PMS is connected to the existing Area Control Centers 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 centers 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 centers.

Another salient feature of the centralized AGC process is the interface with the Scheduling Applications and the method by which the Balancing Energy & Ex-Post Pricing function calculates the supplementary energy bids and ancillary services in support of the AGC function.

HARDWARE ARCHITECTURE

The primary site for the ISO is situated in the Folsom area near Sacramento and the backup facility is situated in Alhambra near Los Angeles. The backup facility is fully manned, round the clock, and is kept in synchronism with the primary site. To ensure integrity of the database, a centralized, and fully redundant, hardware architecture was adopted. Figure 3. shows the overview of the hardware structure and Figure 4. shows the detail of the hardware structure for the Scheduling Applications.

The hardware structure for the Scheduling Infrastructure, Balance of Business Systems and the PMS are very similar to the structure for the Scheduling Applications shown in Figure 4.

FUTURE

The California ISO hardware and software was designed with ample space for expansion and for new functions in the future.

The California ISO is currently evolving to meet the new requirements for the market. As an example, new structures and facilities are being put in place to support the creation and operation of the market for transmission capacity. Existing functionality is also being refined as more experience is gained with the electricity market.

CONCLUSIONS

The California ISO was implemented in record time and against all odds. A major part of the system had to be designed from the ground up. The system started commercial operation on March 31, 1998, three months behind the original schedule. There were a number of reasons for this delay as outlined below:

Interface With the Power Exchange: In order to avoid the appearance of any special treatment of the Power Exchange as compared with other SCs, it was mandated that there be little or no contact between ISO and the PX. This lack of communication resulted in a number of inconsistencies in the interfaces between the two entities that were subsequently corrected.

FERC Filing Approval and Changes: The final filing to FERC was approved at the end of October, 1998; several days before the scheduled start of the operational dry runs. FERC’s approval mandated a number of changes to the system that required modifications to the software.

Additional Training & Testing: The fact that the ISO deals with large sums of money required a perfect operation on day one. Also, the Market Participants needed additional training to be able to use the system. Time and effort was spent to perform more detailed tests and to provide the additional training that was required.

In the few months since the start of its operation, the California ISO has proven itself beyond all expectations. Current information can be obtained from CAISO’s web site at [4].

REFERENCES

1] FERC Electric Tariff, "California Independent System Operator Corporation", Volume 1, Issued June 1, 1998.

2] Harry Singh, Shangyou Hao, Alex Papalexopoulos, " Transmission Congestion Management in Competitive Electricity Markets", IEEE PES Conference paper, Winter 1997.

3] Paul R. Gribik, George A. Angelidis, Ross R. Kovacs, "Transmission Access and Pricing with Multiple Separate Energy Forward Markets", IEEE PES Conference paper, Winter 1998.

4] ISO Web Site is pubinfo

BIOGRAPHY

Farrokh Albuyeh (SM) received the B.S, M.S. and Ph.D. degrees in Electrical Engineering from the University of Wisconsin-Madison. He is currently the Director of Product Management and Marketing at ABB Energy Information Systems in Santa Clara, California. Prior to joining ABB in 1985, he worked as a Senior Consultant with Energy & Control Consultants, Inc. in San Jose, California and as the Manager of Power Systems Development at Control Data Corporation in Minneapolis, Minnesota.

Ziad Alaywan (M) received his B.S. and M.S. degrees in Electrical Engineering from Montana State University. He joined Pacific Gas & Electric Company where he held various positions in System Operations, Power Plant Operations and Planning.

During 1996 he lead the effort in designing the "Blue-Print" of the California ISO “Market Rules and Protocols” and was responsible for implementing the bidding, scheduling and settlement systems. Currently, he is Director, Market Operations at the California ISO.

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Fig. 1. Overview of the California Market Structure

Fig. 2. Overview of the California ISO

Fig. 3. Overall Hardware Struicture

Fig. 4. Scheduling Applications Hardware Structure

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