Fortnightly Supplement
Trading Systems: More Human Than Machines?
December 30, 1999
Richard Stavros
It takes more than just technology to manage the risks of electric commodity trading, say experts.
As electric deregulation exposes more energy companies to the rapid-fire volatility of electric commodity price risk, which experts say is manageable only with sophisticated trading technology, energy executives are learning that success rests not with the systems themselves but in the delicate balance between human and machine.
Buying the top-of-the-line trading technology does not make a utility a major trading power, says Eldon Klaassen, president of Allegro Development, a trading and risk-management software and systems developer. The way people use the technology is as important as the system itself. Klaassen compares trading technology to a piano.
"An out-of-tune piano cannot sound good no matter who is playing. At the same time, a well-tuned grand piano will sound very different in the hands of a master than an inexperienced novice." Klaassen concludes, "Two organizations using the same trading tools may get vastly different results."
Daniel A. Valenti, vice president and chief information officer at PG&E Energy Trading, agrees. The assessment and modeling of a transaction's risk and profitability often is proprietary, he says.
"We may do deals that someone else may walk away from because they cannot assess the risk as capably as we can. That [process] is not likely to become generic." Market vendors offer pretty good products, says Valenti, but they won't allow a company to leapfrog the competition.
"You will beat them by how you implement your systems and how you capitalize on the information that the systems make available to you. That is really the driver behind your competitive advantage," he says. PG&E prefers to keep vendor trading and software systems intact, rather than reconfiguring them, adds Valenti.
"We tend to do most of our [software] development outside the system. Most of our development efforts are focused on the proprietary end," he says. "We develop strategies, create models around those strategies and create the infrastructure that allows us to know how well those strategies are doing."
For example, Valenti explains that every time PG&E Energy Trading tries a new transaction, the company needs to know how to account for that transaction. Trading and risk-management personnel must determine the value-at-risk (VAR) and project a daily profit and loss statement. A portfolio's VAR is the worst loss expected to be suffered during a period of time with a given probability.
"There is a new product process that we go through so that everyone understands what the new product is, how we are going to track it and to what extent systems have to be changed to track the product in a controlled way," he says. A new product can be a new kind of electricity, natural gas or weather derivative trade identified or invented in a particular market.
Moreover, Valenti says, energy companies engaged in commodities trading tend to have nearly a third of their costs tied up in technology.
"This is a very technology-intensive business. If you were to look at this business as compared to a utility, I think you would find a very large difference in terms of percentage of revenue and percentage of cost that are involved in technology [dollar] spent," he says.
Valenti is one of a new class of energy technology executive that is more active in running the trading business.
"In my experience, it is very unusual for an IT guy to be sitting [in] on the commercial decision-making process," he says. "[But] PG&E Energy Trading views IT as such an enabler of our ability to make money that I participate in strategy sessions with management."
* System Design: Single Vendor vs. Integrated Approach *
Perhaps because electricity remains partially regulated, debate continues among technology executives concerning the kind of system to buy and how it should be assembled. Should an energy company implement the same vendor's system for all trading and risk-management functions or should it integrate best-of-breed software packages?
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Dave Christensen, manager of information technology at Aquila, says when you talk about front-to-back-office trading systems, one piece of software is sufficient.
"Today we have an integrated package that we developed in-house called the RiskWorks suite, which has financial risk-management, as well as the physical scheduling of power and gas, all integrated into a single database," Christensen says.
The software assets of RiskWorks developed by Aquila Energy, a unit of Kansas City-based UtiliCorp United were sold to SunGard Energy Systems Group in July. Under the sale agreement, SunGard Energy Systems and Aquila Energy will continue joint development of RiskWorks. "Aquila will get to keep what it develops," says Christensen.
"There are a lot of people that talk about capabilities to bring in data from a number of different sources or to combine that data. We haven't taken that approach," says Christensen. "We have one single database that is totally integrated across all of our physical and financial systems. What that allows us to do is value our entire portfolio either by strategic business unit or in total without a lot of interfaces," he says.
Christensen adds that when he came to Aquila four years ago, the company's system had 15 points of entry. That number has been reduced to one through software applications. One database to house all the company's information means reliability, he says.
One way a company might construct a single database is through use of "middleware," says Christensen. Middleware is software that links disparate applications. For example, merging companies often use middleware to consolidate incompatible software systems.
Says Christensen, "I am not saying that is a bad thing, but it is just messy. If you have many different systems managing coal, power, gas, you are always changing the middleware."
While PG&E Energy Trading's Valenti disagrees with Christensen on the use of multiple vendors, he agrees that a trading system must have one database for all transactions.
"There is a clear advantage to being able to deal with a single vendor. [However], our view as an organization is that there is not a single vendor that provides the front-to-back-office [trading] solution," he says.
PG&E Energy Trading purchased the RiskWorks suite in April 1997, but later switched to other systems. In late October, the trading group implemented Zai*Net, a part of Caminus LLC. PG&E expanded the trading technology used in its power trading business over to its gas trading operation.
"The thing about power vs. gas is really almost a coincidence that we are going in that direction. We could have gone in the other direction, depending on the vendor," says Valenti.
"We kind of view ourselves in a mode where we selectively pick the best-of-breed opportunities," says Valenti. "We will have one vendor that does power scheduling, another that does gas scheduling and another that does fuels trading," he says. PG&E then takes these disparate systems and feeds them into a single risk system.
"Effectively, we will have a single repository for all our transactions, even though the trading part of the systems and the logistical parts can be quite separate. We want all our risks to be housed in a single location because there are cross-commodity risks that you can't capture if you keep them in silos," he says.
For example, Valenti explains, it is difficult to know that you have a power position that you can hedge with a gas trade if your gas transactions are recorded in a separate system than your power trades.
Increasingly, speed is another necessity of trading systems. As Klaassen explains, one of the biggest changes in the industry has been a reduction in the decision cycle time.
"People don't make monthly decisions any more," he says. "They make minute-by-minute decisions."
* Internet: More Than a Trading Vehicle *
Technology experts say that beyond faster computers, the most dramatic change on the trading floor is the emergence of the Internet as a trading vehicle and source of market information.
Says Christensen, "We used to have to deal with 80 pipelines and have 80 different programs. We had to enter those transactions several times, but because of the Internet we have been able to consolidate that." For this reason, he says, the use of Internet represents valuable cost-savings to UtiliCorp.
PG&E's Valenti predicts that future trading systems will rely on the Internet to a much greater degree.
Trading systems are relatively similar in terms of technology, except perhaps for the tools used to build the user interface. For the most part, they are windows-based applications. They tend to be one-, two- or three-tier systems, a fairly common type of architecture. A personal computer unattached to a network is a stand-alone, or single-tier, system. Several personal computers attached to a larger machine or server that processes data is a two-tier system. A three-tier system adds one or more servers for specialized processing.
"What you will see going forward is more Web-centric," Valenti predicts.
"The dream of almost everyone that is serious about developing applications is to build an architecture that is, on the front end anyway, based inside a browser," Valenti says. "For obvious reasons, there is virtually no software distribution cost associated with it. It means that anyone can access the system from almost anywhere, relatively simply.
"We have traders in Bethesda, Md., Houston and Calgary. If all of these people were on a Web-based system, it would probably be much easier for them to use that single system," he says.
Valenti says that his review of risk systems reveals that many trading and risk-management software companies are moving along this path.
"Altra [Energy Technologies] has a pretty impressive suite of Web-based applications. Certainly Zai*Net [is] looking at those things....I think everybody is headed in that direction," he says.
Furthermore, Valenti explains that how the commodity is traded has no impact on risk-management.
"The trading activity itself could occur on the Internet or via the usual broker phone networks. That does not play a major role with how we get into the risk system. Our risk system just needs to be able to capture those trades however they are actually executed and be able to be a single repository of all those transactions," he says.
In fact, maybe because the line between online trading and broker phone networks is beginning to blur, Altra Energy Technologies, a trading software and systems developer, and energy brokers Amerex Power and Prebon Energy, have joined forces in an attempt to provide the best of both worlds. They recently launched Altrade Power, a real-time online trading exchange technology that interfaces with the traditional broker market.
Altrade Power went live on Oct. 14, achieving liquidity in the first two days of trading, according to an Altra press release. In addition, more than 210 installed users, out of 450 traders who have already requested the system, logged on to complete more than $24 million in wholesale power trades.
Frank Getman, president and chief executive officer at HoustonStreet.com, another online trading exchange, says his company does not compete with companies such as Altra.
"We would like to work with those folks. We would like to have Houston Street integrate with those systems not for them to be competitors," he says.
"Most of these trading companies have spent millions on developing sophisticated middle- and back-office systems. We are not trying to sell our customers software. We are about providing a platform that allows them to trade more efficiently," he says.
Getman says he wants to see other electronic trading platforms succeed because ultimately, all trading will be done through an electronic platform. He says his Internet-based exchange distinguishes itself from others in the flexibility that it offers traders with physical generation.
"We offer them the flexibility to trade whatever product, whatever lot at whatever deliver point they want. We are the only trading platform that provides that. The other electronic trading platforms are just for hub trading," he says.
Getman adds that the Internet allows the addition of new markets, products and features to his system virtually overnight.
"That is the beauty of a Web-based application. You can continually make changes and improvements and [all traders benefit]," Getman says.
For example, traders asked for a cancel-all button to allow them to put all bids and offers on hold in the event of market volatility.
"It was a legitimate issue that added functionality. The next morning every trader had a cancel-all button," Getman says.
Getman plans to launch a trading floor specifically for financial markets. The new trading platform will be for trading big blocks of standard product as a trader's revenue and profit center, rather than in order to maximize output from a particular plant or portfolio, he says.
* FAS 133 Compliance: The Next Y2K? *
Can an obscure accounting rule set to go into effect next year revolutionize the technology utilities use to manage commodity risk?
Financial experts predict that Financial Accounting Standard 133 (FAS 133), which specifically defines what is a derivative and the accounting treatment for hedging transactions, will sensitize utilities to commodities risks. (See sidebar, "FAS 133: What Does It Mean For Energy Companies?"). Further, the standard is expected to drive the use of sophisticated trading technology.
Of course, the process of becoming FAS 133-compliant could be compared to the headache utilities went through to become Y2K-complaint.
In fact, it is precisely because most companies have been busy readying their systems for the millennial turnover that the Financial Accounting Standards Board delayed the original 1999 deadline for FAS 133 compliance. Instead, companies must be FAS-133 compliant beginning with fiscal years that start after June 15, 2000. In delaying the implementation deadline, FASB in press materials cited concerns about companies' abilities to modify their information systems and educate managers in time to apply the standard.
Meanwhile, trading system vendors are racing to make their systems FAS 133-compliant in hopes of getting in on a purchasing boom that they hope will model Y2K-spurred system demands.
"FAS 133 could be a minor element or a major change," says Allegro Development's Klaassen. "Companies that were on a mark-to-market reporting basis prior to the requirement will see no change." To mark-to-market is to adjust the valuation of a security or portfolio to reflect its current market value.
But Klaassen says that traditional utilities and some large producers of crude gas and power that have used accrual-based accounting for gas really have no concept of marking their derivatives forward to market. Furthermore, he says, vertically integrated utilities, which may believe their businesses have nothing to do with derivatives, should think again.
"Physical assets might, in fact, be viewed as derivatives. A generation plant may be nothing more than a generation plant," Klaassen explains. "[Yet] another may take the point that the power generation plant is really a big call option, which has a strike at the operating cost of operating the plant. [That organization] may want to sink the asset."
Nevertheless, Klaassen says not all is cut-and-dried with FAS 133. Several compliance issues still must be resolved. The forward curve, a predictor of price during a given four-year period, for example, is easier to calculate in some markets than others.
"Certain organizations have very liquid market places that lend themselves to identifying the forward curve. If, for example, I am selling power at Cinergy, I can look to New York Mercantile Exchange's Cinergy contract and get a pretty good idea of where the market is in four years," Klaasen explains.
"Conversely, [in an] illiquid market such as [the Electric Reliability Council of Texas], I don't really have a good forward measurement to use. We may construct something based on certain knowledge about volatility and historical market prices."
Says Klaasen, "The second major hurdle is deciding what the future market is, what forward curves are we going to use."
The third compliance issue concerns technology. In a changing environment where 200 spot trades per day are executed, how can you re-measure that minute-by-minute and comply with reporting at all times?
Klaassen sees his company's role as providing the technology to meet not only the FAS 133 needs, but also the resources needed for quick decision making.
But the paradigm shift from vertically integrated utility to trading organization will require more than just advanced technology, say risk managers. Good trading groups, they agree, first need "a realization that the old days are gone." [End of article; sidebar article follows.]
** FAS 133: What Does It Mean For Energy Companies? **
PricewaterhouseCoopers' Fred Cohen, partner for energy risk management, and Lou LeGuyader, principal consultant, explain the challenges energy companies face in becoming compliant with Financial Accounting Standard 133, Accounting for Derivative Instruments and Hedging Activities.
What is the application of FAS 133?
Cohen: All SEC registrant companies are required to implement FAS 133 effective for fiscal years beginning after June 15, 2000. Utility companies need to go through a very comprehensive assessment of all their business activities to determine whether those activities (including traditional purchase and sales contracts) would be characterized as derivatives under the criteria that is specified in FAS 133.
LeGuyader: This is the first accounting standard that provides definitions that must be used to determine if certain contracts are derivative instruments from the FAS 133 point of view. This means that some contracts that do not seem to be a derivative will be considered a derivative for FAS 133 accounting. It also means that some contracts that appear to be derivatives will not necessarily be a "FAS 133 derivative."
How does FAS 133 define a derivative?
Cohen: FAS 133 has very specific criteria that define a derivative and those criteria are not limited to financial instruments, but also include certain purchase and sales contracts that have derivative characteristics embedded in the contract. All three of the following characteristics need to be met for an instrument or a contract to be considered a derivative:
1. The value of the contract is by direct reference linked to an underlying measure or index, i.e., a gas price or an electricity price, and that there is a specified notional amount, for example, kilowatts or megawatts. If a utility has a contract that is linked to the COB price [California-Oregon Border] for so many megawatts, they may meet that first requirement.
2. There is no initial or a small investment for a particular contract. The term "small investment" may, for example, include the premium on an option.
3. If the contract has a net settlement provision, or if by delivery of an asset it is readily convertible to cash, it could be considered a derivative.
These criteria are difficult to apply in practice and their detailed implementation has changed with the FASB's continued review of FAS 133.
LeGuyader: What is insidious about this is that a lot of the operating contracts that utilities would have used to buy or sell capacity might have derivative attributes in them that this statement clearly carves out.
How often must derivative positions be reported?
Cohen: FAS 133 requires the quarterly measurement, valuation and reporting of derivative fair values at a minimum. We think that most large users of derivatives will, for internal purposes, want to measure their positions on a more frequent basis.
What is the process?
Cohen: The first question you must ask: Is any transaction, instrument or contract a derivative under the FAS 133 standard? Then a utility must ask to what extent do they want some form of special accounting, which was previously called hedge accounting. They then have to go through another set of criteria to determine whether they can obtain that special accounting for that particular instrument or contract. In that case, there are very specific rules about evaluating the effectiveness of that particular derivative to the underlying exposure. The effectiveness rules further impact the type of special accounting that may be attainable.
Using a gas example, to the extent that a utility is located in the Northwestern U.S. and has entered into a gas supply contract where the index is the Henry Hub, they could have a significant basis risk. When they do the effectiveness test, they may find that they cannot get hedge accounting for that derivative transaction because the gas index used in the derivative contract is not highly correlated to the actual exposure to the gas delivered to their plant in the Northwest. Even if they prove that the initial transaction meets the effectiveness criteria, the utility still must report in its income statement any ineffectiveness that occurs over the life of the contract.
LeGuyader: If you can't properly link the derivatives and the exposure, you may not qualify for special accounting under FAS 133. In this instance, you would still have to show changes in fair value of the derivative, both on the balance sheet and in current earnings. The less specific you are in creating hedges that are identical to the underlying exposure, the greater the likelihood that contracts will be subject to mark-to-market accounting. The basis risk identified above may be too great to qualify for special accounting. [To mark-to-market is to adjust the valuation of a security or portfolio to reflect its current market value.]
Will compliance be easier for a vertically integrated, regional utility than for a power marketer?
Cohen: The regional utility, in many ways, has the same and potentially more complexity than the power marketer. The power marketer may potentially deal with all their transactions on a mark-to-market basis. By contrast, the regional integrated utility may want to retain some of the elements of its current hedge accounting.
To make the problem even more complex for your vertically integrated utility, they could have a non-regulated side of the business, which is independent of the marketing business. As a result, they could have one part of their business doing mark-to-market accounting while another part of their business is in a hedge accounting mode, meeting the special accounting requirements of FAS 133. This complex reporting situation will need to be reconciled both internally, to management, and externally, to readers of the financial statements.
How long does it take to assess and implement FAS 133?
Cohen: We are seeing that companies require from six to 12 months to implement the changes created by FAS 133. This goes beyond just systems. There are training issues. There is a significant documentation requirement. They have to reassess all their policies and procedures in the context of the standard.
For the energy utility industry, to the extent that there are complex option type of derivative contracts, you obviously need fairly sophisticated and robust models. Primarily accounting and valuation methodologies need to be embedded into the systems technology. They don't necessarily have to buy a new trading floor system.[End.]
Richard Stavros is Senior Editor for Public Utilities Fortnightly.
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