Views from the top: CEOs share insights about ERCOT and merchant plants

Pam Boschee
Managing Editor

EL&P invited several CEOs to share their views of the industry and to offer their ideas about future directions. In this first installment of a two-part series, Tom Noel, CEO of the Electric Reliability Council of Texas (ERCOT) and Clarence Ray, president of Duke Energy Generation Services, a new company established to provide operations and maintenance (O&M) services for Duke Energy’s fleet of wholesale merchant power plants in North America, provide EL&P readers a unique opportunity to learn more about these leaders’ perspectives.

Texas debut

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As its June 1 pilot program launch approaches, Texas becomes the next debutante in deregulation. Noel shares his optimism, highlighting unique aspects of the Texas market that may prove to be advantageous.

“I am very hopeful that Texas will become a case study, a laboratory that can be used by others to try concepts and to make things work because we have so few variables.”

-Thomas E. Noel
Chief Executive Officer
Electric Reliability Council of Texas (ERCOT)

EL&P: Texas is being watched closely since it’s the next big state to open its market to competition on Jan. 1, 2002. The pilot program begins in June. What backlash, if any, was experienced when the California situation became regular nightly news? Was there backlash from utilities or customers?

Noel: No, there really wasn’t and I attribute that to a number of factors, perhaps most important of which is that the state legislature has held some hearings, the PUC has held hearings. Market participants, of course are actively involved and they’ve all concluded that given the fact that we’ve carefully and thoroughly prepared for this, the California situation is so different from our own that it really is not applicable. I think it’s a vote of confidence among the groups I just mentioned, but it’s also a realistic estimate based on active participation by an awful lot of people.

EL&P: According to at least one report (ICF Consulting), more than 10 GW of new generation capacity is scheduled to come on line in Texas by 2004. This may represent a capacity surplus. In contrast to California, generation will most likely be adequate. However, Texas faces transmission constraints, especially in the northern half of the state.

Noel: Yes, we do, but only in the context of new generation. The transmission generally follows the generation, so somebody’s got to build a plant and then you have a new need for transmission. We think we’ve got a pretty good model for that. We have at least two approaches that have been followed with some success, one of which is the traditional one and that is where someone like TXU has traditionally built its own transmission and operated it to support its own plants. They will complete in May a very significant 345 kV line from the south to the north that substantially reduces congestion from south to north. They invested their money and got a return on it and built it.

There’s a second model, though, that’s also likely to occur and that has to do with AEP, which has taken a strategic direction, and said we don’t need to own transmission or any new transmission; we’re going to invest our money in other things. LCRA (Lower Colorado River Authority) is actually going to borrow money at municipal rates and build and operate a line on behalf of someone else [AEP]. These aren’t proprietary lines, but LCRA is willing to build a line to someone else’s benefit in exchange for which they’re going to get a return on their investment allowed by the PUC. That’s a different model and I’ve been at several conferences recently where people are touting the value of establishing RTOs and various for-profit corporations. My opinion is that at least here, the wires companies can be for-profit, but they don’t have to be separate companies-they may be adjuncts or affiliates of others.The key to that is what rate of return the PUC is willing to allow. They understand that and I’ve had several conversations with Pat Wood, among others, about that and we don’t know exactly what it’s going to take to make that attractive, but we’re pretty confident that what we’re doing right now is attractive.

EL&P: As it stands now, what rate of return is the PUC allowing on these projects?

Noel: I don’t know the answer, but I do know the commission believes that it may take as much as 10 to 12 percent return to be attractive. I’m told that in other parts of the country where it has been tried, that may be just a tad high. You certainly would be safe [to estimate] in the 9 to 12 range, maybe even the 9 to 11 range. We believe that people will invest money because at the end of the day, it acts like a traditional utility stock. Once the line is built, it’s as close as you come to utility-type [investment] stability.

EL&P: An issue sometimes identified as a challenge for Texas is that the state has its own self-contained grid. Interconnections are limited. Do you see that changing as more generating capacity comes online?

Noel: We are not technically interconnected. Our only connections outside the state boundaries are to dc lines, which do not qualify as interconnections, therefore we’re not under FERC regulation. Those lines are relatively small; the smallest of the three [30 plus MW] is the one that goes to CFE in Mexico at Eagle Pass, Texas. In fact, I don’t think it’s even in full commercial operation, but it would permit power to move across that connection into Mexico or from Mexico to the U.S.

The other lines go up to SPP [Southwest Power Pool], but those do not qualify, and that’s why we’re not an interconnection. We truly are our own grid.

In June of this year, we should have 70,000 MW of power available to us, and our peak day last year, August 31, was 57,731. You look at that and you say we have a 20 percent reserve, but that’s all a relative issue when you recognize that we have fifty-year-old plants, forty-year-old plants, thirty-year-old plants, some of which are coal, some of which are combined gas oil plants. When you get newer, cleaner, more efficient plants, you take your less efficient ones off[line]. Right now, we don’t have all our plants running.

The value of markets is that markets make the adjustments needed to correct any imbalances that occur. I’m not much worried that we’re going to have too much capacity and, therefore, be anxious to sell it across the borders. I think that what happens is that market rules apply and the most efficient plants are kept in operation and those that are less efficient back out. Honestly, it’s a nice problem to have, and I would also share with you that I think we work on roughly three-year projections here. One time recently, for the legislature, they wanted to know what things look like at the five-year and the 10-year. I didn’t offer them a forecast because I know we can build plants in this state in about three years. In California, it takes about 10 [years]. Their planning horizon has to be 10, but ours has to be three because we know that where we have temporary imbalances, we can come up.

There are also other dynamics in the market that are also very important, one of which is obviously fuel cost and which fuel you use. When gas is at $10, I hesitate to say the word, but nuclear plants start looking interesting; certainly coal is interesting, it’s something in the $5 to $6 range. In other words, you can build high-quality coal plants with emission characteristics not too different from gas, and they are competitive when gas is at $6. This is a very dynamic situation, and I’m just very pleased that we’re set up as we are to take advantage of these shifts in emphasis. There’s a lot of concern right now in this state and others that most plants that have been built over the last 10 years have been built to burn gas. Some people think the highest and best use of gas is to make petrochemicals, not to fuel fireplaces and power plants.

EL&P: Do you think having the unique status of a state with a self-contained grid may be an advantage in terms of monitoring and being able to control what is happening?

Noel: Yes. We have many, many fewer moving parts than any other system. We don’t have FERC, we don’t have multi-state PUCs to deal with, we don’t have multi-legislatures to deal with.

I am very hopeful that Texas will become a case study, a laboratory that can be used by others to try concepts and to make things work because we have so few variables. Because we have so few moving parts, we could try something and do it in a way that is truly replicable because we’re not encumbered by all these other things going on that tend to skew a market.

I find my counterparts both in Canada and the rest of the U.S. are looking at us with great interest. We can set up a market that built on the mistakes of others, and we’re not going to make the mistakes that California or PJM made or others made. They’ve been very straightforward with us in helping us understand what works and what doesn’t and I think we’re going to build a system here that if you started with a clean sheet of paper, is what you would build elsewhere. We’ll make some [mistakes] of our own that will be new ones. Because of our unique situation, we can try things out and demonstrate what works, and if not, why it didn’t work and it’s not because one of five states in our group refused to adopt a rule or refused to do something the way we hoped they might.

EL&P: There have been concerns that Texas may have too much reliance on natural gas for its generation. Given the recent high prices of natural gas, might the touted advantage of competition (i.e., lower prices for end users) disappear?

Noel: No, I don’t think so, because the price of gas lifts all boats the same amount so the price to beat-which provides the headspace or the competitive advantage against which a new supplier is bidding-that relative difference stays the same. What we’ve got today is our investor-owned utilities are going to be precluded for five years, or until they give up 40 percent of their market, from dropping their price, so a new competitor knows what price it is he has to beat. Presumably, the [fuel] cost is going up equally for both sides of that equation.

Now, you could be aggressive and go the other way and take someone who wants to be really aggressive and say okay I’m going to assume the gas prices will stay high and I’m going to buy this old coal plant and take the chance that gas prices will stay high because if gas prices drop, then obviously the price to beat is going to drop. So your headspace is going to diminish some. But let’s say the price of gas goes up-you’ve made a good bet.

Nobody is going out there naked; they’re all going to have short-term supply, medium-term supply and long-term supply to sell into the market. They’re going to cover their risk by putting together a portfolio, not only of different fuel sources, but of different lengths of term of contract, hoping they’re going to be more right than they’re wrong. I think that’s why markets are so exciting.

EL&P: Market abuses have been alleged in California with lawsuits pending, demanding refunds from accused suppliers. How will Texas monitor its market for potential abuse?

Noel: The short answer for that is: the PUC monitors for abuses and we do not. We provide the raw data and the commission’s been over here to look at our databases and understand what our archives look like. We’re settling four times an hour, or will be. Voluminous data will be available.

The people I’ve talked to in the industry who participate in the California market and in whom I have a good bit of confidence tell me that look, first of all, nobody wants to go to jail and second of all, most of those plants out there have been running without maintenance for extended periods of time and they are literally living on borrowed time. They do not want a plant to crash and be ruined and then they’re off[line] big time. There have been a good number of allegations, but the people I know and, again, have some confidence in, tell me that they just simply haven’t done that; if anything, they’re offended by it because they’ve run their plants at substantial risk to the loss of the plant for extended periods of time. Admittedly, they made money doing it in some cases, although many of them haven’t been paid for it. They are very much offended by the allegation and do not believe it to be true. FERC has looked into it, others have looked into it, and frankly, I will be very surprised if they find that somebody took something offline just to manage a market.

We’ve operated this wholesale market since ’96 and in fairness, you need to understand these guys out here [generators]. We’re [ERCOT] not in competition with any of them and that’s why we’re an independent body, but they are all in aggressive competition with each other and one of the things that I think has worked very well in Texas is that these guys get together in a room and they go at it hammer and tong. I must say it’s been a very collegiate kind of thing. Every one of our market rules and every one of the things we do that has to do with those market participants has been a negotiated settlement among the participants. We don’t go out there and say we think you need to do this or this; as a matter of fact, I assiduously avoid letting my staff get involved in setting these market rules because we have no skin in that game. Our job is to be totally independent and to make sure that whatever the rules are, we follow them meticulously. We collect data that make it possible for the PUC to monitor the effective of those rules and whether or not people are in compliance with the rules. It stretches credibility for me to suggest that somebody who’s out there in such strong competition would let somebody abuse the rules and the word wouldn’t get out. That’s the strength of this system; these folks are all out there. They can go to us, they can go to the commission, they can go to the legislature and suggest that something isn’t being done right and I’m pretty sure that these guys watching themselves is going to be a whole lot more effective than anything we might do. That’s the benefit again of competition.

You’ve got these competitive folks that came out of gas businesses-that is not a genteel game, and they would cut off the ear of their competitor on a whim. So, you’ve got them out there, and they’re all watching each other and, despite the fact that there’s this creative tension among competitors, they work through this thing in a very collegial way.

We had our advisory committee meeting yesterday. These folks haggle over every point. The advisory committee and our board are both representative of the entire market population. These guys must get a vote and it’s a two-thirds plus one; in other words, it’s always rounded up. They vote and vote until finally they reach agreement and it goes through. That’s all [documented in minutes] and we follow it meticulously.

EL&P: During the Midwest price spikes in 1999, it was suggested that transmission capacity was manipulated (i.e., capacity was allegedly reserved, but ultimately not used by the entity that reserved it, resulting in unavailability of that capacity for others’ use). Concerns arose that more stringent transmission loading relief (TLR) protocols or improved transmission tagging procedures might be needed. Has that been a problem in Texas or do you see it as a possible problem?

Noel: No, it has not and I don’t see it likely to be a problem here because we will be running a single control area for all of Texas. Every one has to submit a balanced schedule the day before.

I think, if anything, there’s a fear it will go the other way, where people submit a schedule that’s actually less than they anticipated with the idea that they may get a break on the ancillary services.

I see the opposite problem, where people are underreporting what they need with the idea that some of that risk will be spread. Of course, if they get that wrong on any given day and the ancillary services go for a much higher price, it costs them money. That may be a risk some of them are willing to take.

Operating a single control area as we do here I honestly don’t think that is likely to occur.

EL&P: Senator Murkowski introduced a bill in February, and in March Senators Bingaman and Daschle introduced another, which contained reliability language. How likely is it that reliability organizations, such as ERCOT, will ultimately have the authority and jurisdiction to enforce mandatory reliability standards?

Noel: I have very little doubt that that will be the norm. Speaking first of Texas, the [ERCOT] staff and I have the total support of our board and our market participants. If somebody is potentially affecting reliability, all bets are off-you’ve got to get it right.

I think at the NERC level, there is the same very high confidence and very high dedication to that principle. My sense is that NERC potentially is somewhat less committed to open access, competition and that sort of thing. I think that’s evolving there, but I have not run across anybody in the industry that doesn’t feel extremely strongly about reliability. That’s something you don’t tamper with.

Duke’s merchant fleet O&M

At press time, Clarence Ray, newly named president of Duke Energy Generation Services, was a very busy man. Until a replacement was found, he would also remain in his position as president and CEO of Duke/Fluor Daniel.

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The new company, Duke Energy Generation Services, falls under the organizational umbrella of Duke’s Energy Services, the unregulated side of Duke’s business. According to Ray, there may be restructuring of the company over time depending upon deregulation.

“Enhancements are driven by trading and marketing; [we see] asset managers as our client, and as their needs change, so will the merchant enhancements.”

-Clarence Ray
President, Duke Energy
Generation Services

EL&P: What are your plans for upgrades and power enhancements in your merchant fleet? Will Duke Energy Generation Services make these decisions or will they be directed by Duke?

Ray: We will be the ones that know how to and what the options will be for upgrades and power enhancements to the fleet. Those decisions will really be driven by the market. The way you dispatch plants and the way you want the plants to perform can change with time. As we sense there are changes, for example design a plant for primarily peaking and run it more hours, that may mean there need to be upgrades or modifications to it. You can be in an area where you didn’t anticipate high peaks but then you get into a situation where that changes, and the traders say that if they had some short-term peaking, they could make more money, that’s what we’re in the business for.

Enhancements are driven by trading and marketing; [we see] asset managers as our client, and as their needs change, so will the merchant enhancements.

A large portion of our merchant fleet are new cogeneration and combined cycle. In California, we bought existing facilities, primarily gas-fired boilers. We are at Moss Landing [in Monterey County] more than doubling the MW of that facility and are adding a 1,000 MW cogeneration facility on the same site, and we propose to do that at Morro Bay [in San Luis Obispo County] and South Bay [in San Diego County] also. We’re in the permitting process for that. Those are upgrades of the facilities, adding to the existing sites. We’ve also added, when dealing with the older units, pollution control to meet state and federal standards that are increasing.

All of those upgrades and power enhancements will be handled by Duke Energy Generation Services, but the driver to do those will come from the entity that actually markets the power and has ownership of the asset.

EL&P: Do you prescribe to the idea of long-term service agreements (LSAs)with gas turbine manufacturers, or will Duke Energy Generation Services do the maintenance itself?

Ray: We evaluate the advantages and disadvantages of LSAs versus doing it ourselves. With a very large fleet, in all but one plant, everything we are doing and projecting to do involves GE-7FA combined cycle turbines and GE-7EA simple turbines. Duke has set up standard plants and uses those for expansion for several years. Duke uses a series of standard plants because as technology and markets change, it will make adjustments. We’ll do a group of plants-for example, four that are exactly alike-and then we’ll learn from those, and maybe we’ll change it a little bit and then the next four will be a little different.We do take advantage of standardization.

In doing this we’ve found two issues: parts availability and the maintenance itself. Duke has acquired LSAs for all of the 7FA turbines, but has not done that for the 7EA turbines. The 7EA is a much smaller turbine and less high-tech than the 7F, and the LSA didn’t bring as much advantage as it did with the 7F turbines. The primary advantage of LSAs is assurance of access to parts. With the volume of equipment that’s going into service, that’s going to be a strong consideration. We’ve got to keep these units running; they have to be available or you lose a lot of money if you’re not available in these peak times. You don’t want them sitting out waiting for parts, and LSAs bring with them strong commitments for parts supply and incentive to the manufacturer to keep the units online. There are incentive-type contracts where they [manufacturers] are rewarded for the performance of the plants. The parts are very expensive. When you weigh in the costs of the parts under an LSA versus buying them separately, sometimes you see some savings there.

EL&P: OEMs of gas turbines recommend operating limits, maintenance intervals, etc. Many operators, however, go outside of these recommendations and establish their own working parameters. What is Duke Energy Generation Services’ approach to this?

Ray: We have the technical capability to evaluate what the machines are doing over time. In the initial years of the equipment, we don’t want to violate the warranty conditions and so for anything we do outside parameters, we’d get approval from the manufacturer. We pretty well stick within their limits, or get their approval, probably with more focus during the warranty period. We look at this as a long-term business, and there are things you can do that would maybe give you some short-term return but cause you problems in the long term. There are limits that you can exceed without affecting the reliability of the machines. Because we have experience, as well as having a very good working relationship with our equipment manufacturers, those decisions are usually made together. At the same time, I wouldn’t say that we agree every time; we may step out and stretch some of their limits if we evaluate it to be in our best interests.

I have seen some independent operators that don’t have our background and history that have run equipment of various types well beyond design parameters because they’re really after a good three or four years, and not looking at the long term. That’s not our approach to doing business. On the other hand, we probably have more technical expertise; we can get some of the same results without doing damage to the equipment because of our knowledge.

EL&P: In terms of O&M staffing, do you plant to use local labor, or do you plan to outsource?

Ray: We will self-perform maintenance; we have a hands-on approach. It has served us well over the 80-year history of the company. Staffing will be a strong emphasis of Duke Energy Generation Services. With all the plants that are coming online, and projected to come online over the years, it’s going to spread the trained resources fairly thin.

On the other hand, we believe there’s time with a very well-planned effort to leverage the resources that we have to train others due to the extensive amount of generation we already operate. When you staff a plant, you generally need a few key people that have the experience to give the leadership for the plant staff; you can generally then hire in the local area the balance of your staff. We do provide extensive training as the plants are brought online. We have to spread the management and experienced operator resources across the plant and train additional people as we go. We’ll seed in people into the plant that are targeted to move on to another plant as they gain experience. We’ll leverage and spread out our existing experience base.

EL&P: Merchant plants are springing up around the country in spite of high natural gas prices. There are concerns that in the year 2005 or beyond, there could be a near-term oversupply. Duke has more than 13,500 MW under development at this time. Given Duke’s experience in portfolio management and wholesale energy sales, what is your view of future merchant growth opportunities?

Ray: There are various drivers in the industry that led to the situation we’re in. Ten or 11 years ago we formed Duke Fluor Daniel because we thought that this market for building new generation was going to start 10 years ago based on our evaluation of the needs across the country and that we hadn’t put any significant generation online in the previous 10 years. And that market didn’t materialize. There were a lot of reasons for that-some good and some have proven out to be not so good. Over that 10-year period, reserve margins have been decreasing and I think that’s been a good thing to an extent in that power used to be traded over very restricted boundaries and now power is traded over much broader boundaries; that gives more options and gives more opportunity to lower reserve margins. On the other hand, pending deregulation created an uncertainty in the market in terms of how, if you were a builder of plants, how you would recover your investment. If you were a regulated utility, how would you recover that or would it get stranded. The opportunity then opened up for merchant power.

Merchant power came in as strong as it did because we went another 10 years, so it’s been 20 years since any significant capacity has been put on. Reserve margins came down to a point where we’re seeing brownouts and blackouts and so forth in areas like California, and I think we’re going to see it in other areas of the country because we can’t build the plants fast enough. We should have started building these plants at a more controlled rate 10 years ago or certainly five years ago instead of trying to build them all at once. It has put the ability to build the plants, to build equipment and to design and construct the plants under significant stress of growth.

That’s good-except when you take anything to an extreme it can be bad. We are limited in how fast we can build plants by the availability of equipment and availability of engineering and construction resources to do that. That moderates the market to some extent.

The volume that’s being built is on the extreme. I think we’ll continue this volume until plants that go into service-probably through at least 2004-drop off; it won’t be a cliff that drops off to nothing, it will drop off to about half of this current market. However, half of this current market is a huge market for building power plants. We’re putting in so much power just to catch up and close the gap of where we brought the reserves down too low. I’m pretty sure that last year all of the plants that went in service didn’t even meet the growth for that year, so the gap was not closed at all. Maybe the gap’s getting closed a little bit this year, but most of it’s going to meet [continued] growth. There’s a 2 to 2.5 percent growth, which is a lot of power. It’s going to take several years to catch up but then when it catches up, continuing that growth, we’ll still have a pretty substantial market. It won’t go to zero.

There may be pockets of overbuilding. That is typical of when you open up a market, but it doesn’t last very long. When building stops, the market grows and drives down prices-that’s what you’re looking for. Overall, you want the competitive nature of the market to optimize that.

I see the pace of building increasing at least through 2004. Plants going in service this year will be more than last year, the 2002 plants will be more than this year, and I see it about level for 2003, 2004 and maybe 2005. And then we may see a dropping off, but not a major cliff. n

Noel may be contacted at 512-343-7289; Ray may be contacted at 704-426-2770. For more information about deregulation in Texas, see the State of Deregulation on page 10.

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