Interviews with software middlemen.

Lawrence Oliva
Partner, Utility Practice Group
Andersen

Q: What sort of work have you been doing with RTOs [regional transmission organizations]?
Oliva: We've been working in four basic areas: [1] Business strategy, [2] market design and monitoring, [3] budgeting and program management, and [4] outsourcing of various financial back-office and settlement functions.

Q: What do you think about a forced marriage of RTOs in the Northeast and Southeast? Can they still meet the December deadline imposed by the FERC [Federal Energy Regulatory Commission] for RTO start-up?
Oliva: I seriously doubt that it [agreement on RTO structure] can be done now in 45 or 60 or even 90 days. I don't see why the FERC cannot extend the deadline. In fact, I think we may have lost ground in the short run, by forcing New England to halt its work on its proposed standard market design [SMD] and agree to mediation on the PJM version. There is clearly some backtracking that will occur now.

Q: How will this "backtracking" affect software development?
Oliva: To answer that, I've got to explain to you that there's certain process involved for the RTO in hiring vendors and building software. First of all, you need regulatory approval. How many RTOs are there that really have specific approval from the FERC over a market design? In the Northeast, for instance, the problem is identifying who the party is who will engage the vendors. Let's assume that this new Northeast RTO forms and takes on the basic market design and structure of PJM. But if there is to be some designation of PJM as the spearhead party for software contracting, when does that designation actually occur?

Q: At the "seams" conference on regional coordination at the FERC back in June, we heard talk that new deadlines could upset contracts with software vendors. How do you see it?
Oliva: If I'm a software vendor working in New England-even if I've got a contract-I would be concerned now whether I can even continue work or else recover damages for projects that don't proceed to completion.

Q. Even if the industry consolidates into just four RTO's-as the FERC wants-the regions likely will adopt different rules. Will that stifle a true nationwide electricity market?
Oliva. No, and here's why. Think about the gas industry. The gas pipelines are better off today than they were before Order 636, because they now have unbundled gas transmission from the commodity business and have focused on creating value in an entirely new business-the pipes-only business. This process will also take place in the electric industry, and should yield similar benefits.

Q. In the upper Midwest and the Great Plains, they've talked of forming a "Crescent Moon" RTO to protect them from higher costs in case they're forced to join a larger RTO. How will they fare?
Oliva: When you have areas of high-cost transmission that must span long distances to serve small loads, yes, you could have some negative effects in terms of cost shifting. But, remember that transmission represents only a small part of the total cost picture. For a region like you describe, that has been somewhat leery of joining a larger RTO, I think what it boils down to is that some regions might not reap the same degree benefits that others might.

Q: Let's get back to market design. Some regions favor physical flowgates to allocate transmission rights and manage congestion. Others rely on financial rights. How does that affect power marketers operating nationwide?
Oliva: It is true that we have different models across the country for transmission rights and congestion management. New York and PJM both follow a financial model based on LMP (locational marginal pricing), though New York is not as granular as PJM in terms of the number of pricing nodes. By contrast, GridSouth, RTO West and DesertStar envision a physical rights model. Alliance, MISO and the Southwest Power Pool have proposed a hybrid model that would marry aspects of the physical and financial models. "Can we come up with a forward market for transmission rights?" That's the thinking behind a physical model. It allows you to set up a forward market for transmission rights, ahead of the trading day. And from there you can trade these physical rights in a financial way. But will these multiple models prove to be an impediment to trading? I don't think so. The marketers have just not said that, from what I can see.

Larry Winter
Accenture

Q: Can you describe your practice with RTOs?
Winter: We have been focusing on back-office systems and processes, including billing and settlements.

Q: If RTOs consolidate-as the FERC wants-how will that affect software vendors and power marketers?
Winter: We have been working with PJM West and GridSouth toward a Dec. 15 implementation date. But first, before that happens, and after the participants receive the finished software, they will want to construct a mock market to test the software. So the FERC orders have probably slowed things up. You see, it's not really the software. It's the changes in the market rules that the vendors have to deal with.

Q: Is the situation in the Southeast any different from the Northeast, where the different regions already have been working on coordination?
Winter: In the Northeast, PJM is viewed as the model. New England already has said that they're working toward the PJM model. They're already close to a meeting of the minds. And I've talked with Enron-they like PJM's LMP model. I think they would prefer to have just the one set of market rules. And remember, many of the big traders build their own shadow software-for things like settlements and dispute resolution. In the Southeast, however, it's not that easy. GridSouth and Entergy and the Southwest Power Pool each have been writing software.

Q: And Grid Florida? Is that RTO dead now?
Winter: No, I don't thinks so. Grid Florida is in a deep freeze now, but I think eventually they will settle their differences with the Florida Public Service Commission.

Q: What do you hear about National Grid becoming the manager of a future Alliance Transco? Is that deal over if RTOs consolidate in the Northeast and Midwest, putting National Grid's New England assets is closer proximity to Alliance?
Winter: You've got to consider other scenarios, too. National Grid also has been talking with other regions about a manager role. And you could see other outside players coming in. Look at Alberta. The power pool runs the markets and the enterprise management software, but they've outsourced the transmission side-OASIS and scheduling-to the Electricity Supply Board of Ireland. In the Midwest, Alliance could adopt a similar idea. National Grid might get away with running OASIS and scheduling in Alliance, even if they don't become the overall RTO manager. Or you could see a company like National Grid running the regional control center with another of the big RTOs.

Q: If RTOs consolidate, will that help utilities develop transcos [stand-alone transmission companies] since they won't have to work so hard on RTO rules?
Winter: Well, so far there's only one working ITC [independent transmission company] where the assets have been transferred, and that's American Transmission, in Wisconsin. So transco formation has not moved ahead very far, and FERC's new orders could slow things down even further. What the FERC decision will do is put transco proponents and opponents in the same room together. It may prove more difficult now for them to reach agreement.

Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.