Real-Time IT in Electric Markets

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

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
• 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
© 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.


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