Real-Time IT in Electric Markets by Chris Trayhorn, Publisher of mThink Blue Book, April 1, 2003 Energy companies transact close to a million dollars a day for physical delivery in markets run by independent systems operators. The settlement of those transactions may not occur until months after the power flows. Assuming a conservative error rate of 2 percent in invoice calculations, a large market participant could be exposed to losses of tens of thousands of dollars per day without even knowing it. Companies will continue to face financial exposure as ISOs evolve to a nationwide system of regional transmission organizations and/or independent transmission providers (ITPs). The United States Supreme Court reinforced the Federal Energy Regulatory Commission’s decision to move quickly toward transmission and energy markets overseen by RTOs. Markets will come online quickly, and energy companies need to be ready to do business the minute they do. Just to keep the lights on around the clock, companies need to schedule the flow. Companies that invest the time and effort now to understand market dynamics and the systems needed to support them will be better prepared than those companies that wait to see how the RTOs will shake out. Bidding and scheduling are mission-critical; systems will need to be in place quickly once the new RTOs are defined. FERC is on the fast track toward standard market design, having crisscrossed the country to garner acceptance. AMR Research expects that many of the market design issues will be settled and physical markets will be ready to go by early 2005. Energy companies cannot participate in the markets without a bidding and scheduling system. Such a system is no small order. For the ISO, RTO, or ITP, the technology is the market mechanism. ISOs have spent $100 million to $350 million to put together information technology infrastructure, with IT operating expenses comprising 15 to 26 percent of ISO revenue. Energy companies must make their own IT investments to meet the data-communication requirements of ISOs. No matter how flexible the system is to changes in market rules, companies will need to configure applications to fit their business requirements. For example, one generation company found that it could achieve scheduling efficiencies by looking at its net position while scheduling delivery. A deal for 100 megawatts of power might require 50 megawatts from one injection point and 50 megawatts from another, requiring the debooking of the trade deal and rebooking two 50-megawatt deals, creating opportunities for error. Instead, this company reworked its business processes and invested in an application platform to give schedulers the ability to access and translate day-type trading deals to real-time schedules. Evidence from AMR Research interviews with energy companies suggests it will take at least one year to create the business processes and assemble the supporting architecture for a truly profitable operation. Market Exposure In the best of markets, it takes months for daily power transactions to be completely settled. Initial settlement — the reconciliation between scheduled and actual delivery and subsequent assignment of charges for maintaining system balance — comes at three days, final settlement at 45 to 90 days, true-up in six months, and over a year to resolve disputes over charges. A company that does not have access to the right data can find itself unaware of its position. Companies may face penalties when they under- or over-schedule. One generation and wholesale company that also has a commercial and industrial load was hit with unanticipated invoices, ranging in the millions of dollars, because the load scheduled was not meeting what was being consumed through the load-serving entities (LSEs). The company was not only penalized for under-scheduling, but it had to pay interest on past penalties accrued, even though true-up was more than six months later than under-scheduling incidents. Without timely delivery of meter data, generators and power marketers must depend on profiling and forecasting to calculate expected settlement. Meter data is the basis for invoicing determinants, but often it isn’t delivered until the day after or later. One energy company came closer to forecasting exposure by taking day-ahead forecasts and rerunning these using day-of weather feeds. Spreadsheets and back-of-the-envelope calculations are not sufficient to validate settlements in the new markets. An invoice can hold as many as 1,000 line items. Energy companies need to deconstruct the ISO invoice so that they can use forecasts to re-create the invoice they can expect to receive. However, invoicing rules are a moving target, requiring technology that offers flexibility in changing business rules. To understand financial exposure, companies need a fully functional scheduling and settlement system. In the most advanced ISOs, generators use Web or extensible markup language (XML) transactions to communicate bids and schedules to the market, based on their supply forecasts. Figure 1 shows the optimal flow of interactions for the RTO. The savvy market participant will create a feedback loop to adjust future bids and schedules. Companies need to reproduce the ISO’s complex transmission and energy market calculations in order to understand their final obligations and exposure. To get it right, energy companies need to do all of the following: • Closely forecast, profile, and/or estimate load (profile and forecast). • Bid into day-ahead or hour-ahead markets (bidding). • Schedule and adjust schedules to avoid penalties, reduce transmission costs, and optimize plant operation (schedule delivery). • Understand capacity obligations established in their contracts (contract management). • Interface with the ISO/RTO and/or load-serving entities (ISO interface). • Calculate potential ISO/RTO exposure (shadow settlement). • Perform settlement and invoice reconciliation as a basis for disputes (settlement and invoice reconciliation). Figure 1: Keeping the lights on requires around-the-clock robust systems with messaging. © AMR Research, Inc. Robust Systems Bidding and scheduling systems must be robust enough to handle hour-ahead markets. They must operate at all hours with deadlines for flows and submittals for every hour in the day and notifications requiring response receipts. Although existing companies rework legacy systems connected to systems by ABB, Siemens, or Alstom ESCA for mandatory plant dispatch, legacy bidding and scheduling systems do not work for the new markets. Systems are not built for generators, power marketers, or distribution companies that have divested of generation. Also, the new RTO markets go beyond day-ahead bidding and will allow for hour-ahead adjustments to day-ahead bids. The volume and complexity of transactions is high. In the Italian market, for example, a national player will have 5,000 transactions a day and 200 supply points to inject or take out power. Similarly, a large regional U.S. player conducts 3,000 transactions a day. Flexible System A technology platform that allows changes in business rules provides the most flexibility. No two ISOs are the same, and RTOs by their nature will also be different. RTOs will not develop for all regions on the same timetable. Each region is also likely to have its own demand-side bidding programs or uplift charges, and existing ISO infrastructure will be incorporated into the new RTOs. A business process outsourcing (BPO) model works for energy companies dabbling in more than one market. Using a BPO, an energy company can avoid the investment and risk for entering new markets. APX, which does not take a position in the market, provides scheduling and settlement for cents per megawatt hour. APX has strict security protocols, but companies are reluctant to have proprietary data hosted outside the four walls. To handle variation in market rules requires a flexible architecture. Using XML and open standards, Excelergy’s Energy Trading is an application layer that sits on top of an integration platform. It is now being used to deliver a trading, scheduling, and settlement application to American Electric Power. Vendors like the Structure Group, while not providing the software for volume bidding and scheduling, offer market connectors for scheduling and settlement applications. If the promise of SMD is realized and there is greater standardization of communications, there will be fewer connectors required to operate across markets. The Price Tag Expect to pay between $1.5 million and $3.5 million for a complete forecasting, scheduling, and settlement system. No one vendor can provide a complete scheduling and settlement system. Different vendors provide analytic and transactional applications (see Figure 2). Energy companies will need to assemble a set of applications to achieve visibility to exposure in the physical markets. The potential of companies serving this market has been proven by acquisitions in 2002: Henwood Energy Services by Global Energy Decisions, NewEnergy Associates by Siemens Westinghouse, and RER by Itron. Load profiling ranges from $300,000 to $500,000 and requires three to six months to implement, with maintenance at 20 percent and an industry standard of one-to-one license to implementation. With a longstanding history and deep market penetration for load profiling and settlement, Lodestar has been able to use this experience to meet the requirements of the new markets with its Lodestar Profile & Settlement System. Lodestar’s ground-up, account-level estimation is supplemented by RER neural network capabilities in the Texas market. Load-profiling vendors, such as ICF Consulting and Lodestar with BillExpert, also offer shadow settlement. In addition, the Structure Group offers shadow settlement for ISO-New England, Electric Reliability Council of Texas (ERCOT), and New York ISO, among other markets. Licensing for scheduling and settlement generally runs from $500,000 to $750,000, although it can go as low as $150,000. For market-specific connectors, add $100,000 to $750,000 more in license fees, depending on the number of markets. Henwood Energy Services and NewEnergy Associates offer forecasting in addition to scheduling and settlement. Henwood is known for forecasting and settlement analysis capabilities, while NewEnergy’s EnergyOffice supports both LSEs and retailers in scheduling and settlement, as well as transmission congestion forecasting. A niche player, OATI has a lion’s share of the market for the NERC, tagging as an application service provider (ASP); OATI also offers transaction management tools for generators. More advanced scheduling and settlement systems link pre- and post-trade, connecting risk management with scheduling and settlement. KWI offers scheduling and settlement as an adjunct to KW3000 for companies that do not already have the necessary tools. Caminus, meanwhile, identifies scheduling and settlement as a market for its seasoned ACES product. It also has an integration platform for its popular trading, risk, and power-management suites, including Nucleus and Altra Power. Integrators with experience in this area are SAIC; Cap Gemini Ernst & Young; AMS (now owned by Wipro); Sapient; IBM Business Consulting Services with its acquisition of PwC Consulting; and Accenture. Experienced integration platforms include TIBCO, SeeBeyond, and IBM Websphere. Recommendations Energy companies participating in ISO markets do not need to wait for the RTOs; rather, smart companies will start planning now. In approaching scheduling and settlement, they should do the following: • Expect that the market rules will continue to change dynamically, and negotiate software agreements accordingly. Closely examine maintenance and upgrade policy and inherent configurability of the application; you cannot afford an expensive upgrade every time the market rules change. • Require vendors to use historical data to recreate financial exposure for a past period. Because of the complexity of charges in different markets, you need to be assured that the vendor’s packaged applications can accurately predict your exposure. • Do not underestimate the importance of program scheduling. Submitting bids and schedules via a Web site can be labor-intensive. For a small player, this is not an issue, but for larger market participants, automation is a must. • Consider the ease of integration of applications before making your final selection. Rather than separate applications for scheduling and tagging, consider an application that offers both. However, if your existing tagging application can integrate easily, you may not need to purchase tagging as part of your settlement option. • If and when the market rules resolve and true-up times shorten, you will still need a means to verify RTO invoice calculations. According to one ISO staffer, “Although we have fully tested our systems, given the complexity of the invoicing system, there are opportunities for error.” n Filed under: White Papers Tagged under: Utilities About the Author Chris Trayhorn, Publisher of mThink Blue Book Chris Trayhorn is the Chairman of the Performance Marketing Industry Blue Ribbon Panel and the CEO of mThink.com, a leading online and content marketing agency. He has founded four successful marketing companies in London and San Francisco in the last 15 years, and is currently the founder and publisher of Revenue+Performance magazine, the magazine of the performance marketing industry since 2002.