By Marija Ilic and Leonard Hyman

 

Why a standard design in each ISO is no guarantee of regional coordination.

How do you complete an efficient transaction that requires the cooperation of two or more markets when each is operated independently of the other?

That is the "seams" issue that so concerns the Federal Energy Regulatory Commission (FERC), and the participants in the electric utility industry. This problem-conducting power transactions between geographic areas under well-defined rules and transmission tariffs-marks one of the main obstacles to the growth of electricity trading across the U.S.

In response, the FERC issued Order 2000,¹ with an implied assumption that the formation of regional transmission organizations (RTOs) would lead to the necessary upgrades of the transmission network. These RTOs would serve as improved, second-generation versions of independent systems operators (ISOs) which have already formed in a handful of regions around the country to manage the local transmission grid.

In June, the FERC took two major steps regarding the ISOs already in place in the Northeast U.S. that should give reason to pause to an interested observer. Earlier, these three northeastern ISOs (New York, New England and PJM) had proposed vague plans to add RTOs to their regional structures, without a clear vision of how the RTOs and ISOs would interact, or how the new setup would encourage improvements in the transmission networks. The ISOs had developed a memorandum of understanding (MOU)² which would lead to a solution of the seams problem.

In the first of these two steps, the FERC singled out the operating platform and software of the PJM region and declared it to be the industry standard.³ That gave the three northeastern ISOs their marching orders. In the second step, the FERC ordered the three ISOs, plus the new PJM West, to enter into 45 days of negotiations that should lead to the formation of a single RTO.⁴ The commission proposed this shotgun marriage because: "[I]n order to successfully address seams issues...and to establish efficient markets in the Northeast, it is necessary that all four entities combine to form a single RTO."⁵

By now, however, we should have learned that public policy decisions can produce unintended consequences.⁶ The California fiasco, alone, should cause warning lights to go off whenever a public agency decides to impose not only market structures but also software solutions.

So, for the sake of argument, we will assert that this rush to enforce consolidation, with the rules of operation set out by the FERC, will not solve the seams problem in a timely and efficient manner, but instead will lock in the Northeast electricity market to nothing more than a jazzy variation on the old utility paradigm.

What is wrong with the standard market design envisioned for the Northeast?

Actually, there is nothing standard about the design, other than the desire to make it the sole operating/software platform by implementing it everywhere.

In many ways, the standard market design (SMD) is a makeshift solution for the selection of suppliers, without clear signals or incentives to those demanding the electricity (the loads) or those owning the transmission lines. It uses a rigid unit commitment method, which originated in the regulated industry. Moreover, a closer look into the actual software shows that this computationally complex software is not useful for near real time decision making that turns units on or off. It does not optimize use of the transmission system during the commitment of generating units. Because it bundles together the ancillary services and reserve markets with the energy market and is too computationally complex to use in real time, the current platform (called MAPS) cannot differentiate value-offered-day-ahead from value-offered-in-near-real-time.

Furthermore, MAPS works with rigid reserve requirements, a relic of the old utility days. MAPS, moreover, does not capture the value of peaking technologies or of faster ramping rates. Nor does it offer quantifiable ways to value the willingness of customers to allow interruption of service or to shave peak demand. Any makeshift moves in this direction must end with the recognition that the amount of total reserve capacity is not related to what end users are willing to do when supply is short. This lack of sensitivity to the needs and desires of the ultimate customer could put an end to the development of a viable energy service provider industry.

Now let's move on to transmission constraints. The supposed model platform deals with them by a process of sub optimal unit commitment based on knowing the specifics of each given transmission system. In addition, the platform offers firm transmission rights (FTRs) as the means of hedging against volatile market conditions. The near-real-time Congestion Management System (CMS) has no protocols in place by which long-term FTRs would not be implemented in order to make way for more valuable spot market requests for transmission; this failure has a large impact on the revenue of the transmission provided, and also on the optimal use of overall transmission capacity available. The FTRs are rarely denied access except in case of emergencies. The transmission owner, of course, sees no income from the FTR.

Sweating the Deadline: What Consolidation Means for Traders and Vendors

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.

In sum, the platform does not differentiate the value of various technologies (for generation, demand and delivery). As such, the SMD, in its current form, may stifle, if not throttle, the possibilities for a truly efficient, competitive power market. The design looks like an attempt to repackage old tools for dispatching power under the regulated paradigm, with an FTR mechanism grafted on. The FTR concept currently in place at PJM and destined for everyone else in the Northeast, seems to lack a link between the valuation and the management of the FTR and the investment process. One gets the feeling that the FTR design is biased in favor of FTR holders, while their risks are covered by everyone else.

Of course, the FTR concept is supposed to give someone the incentive to add to the transmission network when economically justifiable. The lack of concrete proposals to build on an unregulated basis in the Northeast may indicate that the region does not really need new lines or, possibly, that the FTR mechanism does not send the right signals. Incidentally, if the FTR mechanism works as advertised, perhaps the FERC could dispense with all the rate of return incentives that it proposes for new transmission investment. Do we need both?

How does the forced mediation order solve the seams problem?

We wonder whether the order, as presently proposed, might not create other problems in place of seams. Handled in the wrong way-using the current SMD platform without improvements-the order could lead to market failure, certainly not an unusual outcome these days.

Will the northeastern ISOs merge or just adopt the same platform under the jurisdiction of a northeastern RTO? The ISOs, probably, would prefer the latter course, as a means of survival as institutional entities. Would that motive impel them to adopt the SMD, based on the thinking that doing so solves the seam problem in an optimal manner, and keeps them in business as well? That approach could lead to problems involving differences of operating and planning practices at individual state and control areas. Furthermore, think of the transmission related cost shifts among transmission owners and the new RTO, which should create a major new source of income for regulatory lawyers.

On the technical side, the new setup could lead to highly conservative use of the system, with each ISO computing Available Transfer Capability (ATC) in a conservative manner, without incentive to relax its reserve margins. Duplication of the SMD in each ISO and exchange of data need not produce the coordination needed for near real time adjustments to produce regional reliability in the most efficient manner. For that matter, which entity of the many envisioned would have responsibility for overall reliability? Finally, we doubt that the new entity would have in place the right incentives to induce transmission investment.

We favor an inter-regional group, founded on profit.

You may wonder why we are asking so many questions. Don't we want to see progress?

Yes, of course, progress would be nice, but consider what can go wrong. So far, the restructuring process has featured a plethora of well-meaning, governmentally imposed, detailed solutions hammered out for the benefit of stakeholders, which, at best, have barely moved us in the direction of efficient, competitive markets, and, at worst, have led to economic and operational catastrophe. Now, could we come up with something better, a solution that utilizes market forces and considers technological limitations as well?

What we should do is encourage consumer choice, new technologies and timely progress. Now that may sound like apple pie, but it is not the current direction in which the industry is moving. To reverse the current trend, we propose that entrepreneurs form inter-regional transmission organizations (IRTOs). Does the country really need still another alphabet soup organization in the business? Judge for yourself.

The IRTO, as we envision it, would be a profit-making organization responsible for reliability within the entire region. It would act as a one-stop shop for those seeking to consummate transactions that require the user of more than one ISO or control area. The IRTO would serve as a market maker for implementing inter-regional transactions. The suppliers of the inter-regional delivery are the entities within the IRTO, and the users of the IRTO's services are those proposing the transactions, which would be implemented according to a well-defined contractual arrangement.

Technically, the IRTO would provide direct tie-line flow control between control areas in order to implement regional transactions. The IRTO arrangement would fully preserve the autonomy of the entities within its purview, giving those entities a choice of how much power to transfer and at what value. Some of the profit from transactions would go to transmission owners, who could upgrade their systems. Technically, we are proposing a minimal, information exchange-based market for facilitating delivery of inter-market transactions, with a hierarchical structure, with ISOs, transmission owners and control areas as fully identifiable members of the IRTO.^7,8,9,10

What makes this idea different from a big RTO, as envisioned in the northeast consolidation? Basically, the IRTO would not rely on uniform SMDs and/or committee work to manage inter-regional transmission. Coordination would come about largely through value-based signals between the IRTO and its immediate lower level (ISOs, control areas, transmission owners) and between the IRTO and its customers for inter-regional transmission. Each individual ISO or control area or transmission owner could decide how much transmission capacity to make available to the inter-regional users (at the expense of its own reliability margin) and at what price. Keep in mind, though, that the IRTO will have an economic reason to want to facilitate inter-regional transactions. It will make more money if it does so. Keep in mind, too, that sooner or later, somebody will have to set up an IRTO, at least until North America manages to put together a continental grid.

Isn't the IRTO just one more idea that we don't need?

It's no more untried than anything else on the table, and we think that setting up the IRTO would be a more manageable task, computationally, than the MOU/SMD proposal.¹¹

To be fair about it, the FERC may have gotten one thing right-that a lot of small, uncoordinated ISOs will not succeed in forming viable competitive markets. The question on the table, however, is this: Will a hastily arranged marriage encouraged by FERC, with FERC prescribing the details of the market, produce a vigorous, efficient market, either?

That sounds like the opening of one of those old radio soap operas doesn't it? Unfortunately, it is not.

1. Regional Trans. Organizations, , modified on rehearing, ¶.
2. , signed Aug. 10, 1999. See www.isomou.com.
3. See Massey, Commissioner, concurring in, "I am also heartened that today's orders addressing the Northeast clearly set PJM as the platform upon which the Northeast RTO will be built. The PJM market design, which is based onlocational marginal pricing, has proven itself again and again."
   See also, , Order on RTO Compliance Filing [New York], ; Order Granting, In Part, and Denying, In Part, Petition for Declaratory Order [New England], .
4. Order Initiating Mediation, Docket No. RT01-99-000, July 12, 2001, 96 FERC ¶61,065
5. Id., mimeo at pp. 1
6. See, e.g., Marija Ilic and Leonard Hyman, "Getting It Right the First Time: The Value of Transmission and High Technologies", Vol. 9, No. 9, Nov. 1996.
7. Ilic, M., "A Eulogy for RTOs - Interregional is Better", , Oct. 15, 2000.
8. Yoon, Y., Ilic, M. and Collison, K., "Efficient Implementation of Inter-regional Transactions", Proceedings of the IEEE PES Summer meeting, Vancouver, CA, July 2001.
9. Ilic, M. and Liu, S., Hierarchical Power Systems Control: Its Value in a Changing Power Industry, Springer-Verlag London Limited Series, Advances in Industrial Control, March 1996.
10. Intelligent Energy Systems, Inc.; rms@hutch.com, www.intelligentenergysystems.com.
11. Ilic, M., and Y. Yoon. "Inter-regional Transmission Organization: Designs, Functions and Tariffs", U. S. Patent Filing (MIT case 9062), October, 14, 2000.

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