Asset optimization is a favored utility strategy in an economic downturn.
Generation plant construction has gone down with the economy. "Our project finance pipeline is as dry as I have seen it," says energy analyst Jerry Pfeffer of Skadden, Arps, Slate, Meagher & Flom, speaking at a recent energy conference in New Orleans. He predicts it will take at least a year or two until new construction starts up again in any significant manner.
That downturn can be attributed to any number of factors, from the cyclical nature of business, to the fallout from Enron, to accounting practices. So instead of building new generating plants, companies are turning toward asset optimization to squeeze dollars and megawatts from already existing power plants.
Taking aim at this trend, Fortnightly turned to some top experts to find out how to get the most from power plants.
According to Christopher Grier, a director at Navigant Consulting, the best way now to improve the bottom line is to increase capacity and energy from existing plants. "It's just so much less expensive than building a new plant, plus you don't have all the issues surrounding siting and permitting," Grier says.
He has worked on coal plants in the Northeast and Midwest and found the same drivers of value kept showing up over and over again. Those drivers are somewhat basic-minimization of fuel costs, heat rates, and forced outage rates.
Philip Q. Hanser, an economist and statistician with the Brattle Group, points out that while asset optimization has been talked about by utilities for years, it has a lot more relevance now than it used to. Especially for pure-play generators, he believes getting as much profitability as possible from assets is important. He compares plant optimization to the airline industry, where it was called "yield management"-which meant that if not fully loaded, the asset (the airplane) was not getting as much yield as it could have. That led to the hub-and-spoke routing system and to the crazy-quilt system of varied fares among passengers. But all those systems were aimed at increasing profitability.
Terry Maxey, vice president and PassPort production manager with Indus International, believes the answer to asset optimization lies in software. Maxey explains that the PassPort is enterprise management software that is used at power plants for work management, supply chain procurement, and safety compliance. And while the software is used at a variety of places, it is in use at over 80 percent of the nuclear plants in North America. But Maxey cautions that "we don't think you buy a piece of software, put it in a PC, and things are great."
Instead he likes to think of the software as a catalyst to the key drivers at a plant such as management and regulatory performance. He says a direct benefit of using PassPort is reduced outage time. A 50- to 60-day nuclear plant outage used to be common, but now 20 days is more the norm. Also, if there is an unplanned outage, PassPort helps end it sooner.
Meanwhile, Hanser says the drop in liquidity in wholesale energy markets is having a direct impact on how plant operators manage their assets.
He says the trading market, with players such as Enron and others, allowed trading of various contracts, which forever changed the liquidity of the market and changed the economics of power plants. Now, the loss of liquidity in these markets will hurt plant operators, he says.
Moreover, in terms of the customer demand-side and price responsiveness, Hanser says, "What you build and how much you build in terms of generation is also a function of how much real price-responsive demand there is." So a market with no price-responsive demand requires a different type of generation mix and a different level of generation than a market where customers have the ability to respond to different prices. That also will create substantial differences concerning the kind of generation that needs to be built, and how much needs to be built throughout the country.
The Big Squeeze
Asset optimization strategies vary and can depend on the type of plant, management methods and more.
Navigant's Grier gives an example of what he calls the "ah-ha" moment, to demonstrate a real difference between nuclear and fossil plants. He explains that now that the nuclear fleet generally is operating so well, everything that can be done in a nuclear plant to improve capacity factor is very important, because marginal costs of production are going to be very low-around $4/MWh. So any extra megawatts created can be sold, since it is so much cheaper than buying from fossil plants. But on the fossil side, the driver is the organization's ability to market energy, i.e., increasing the opportunity to sell MWhs. That nuance drives capital asset allocation, as well as the need to work closely with marketing people. "For fossil plants the key is a very close relationship with who is marketing your energy," Grier says.
Grier uses Sony as an example. He says the whole Sony design team looks at the total cost of what a widget can be sold for in the market, and they find a way to meet that price. But with fossil plants, the marketing people have to go to the operations people and say, "Look, we can sell this many megawatt-hours if you can get the price to this point, and sell even more megawatt-hours if you can get the price to an even better point." That gives guidance to the engineering, operations, and fuel employees then to ask what is the optimal strategy for that asset. For example, if heat-rate efficiency is improved by three percent, it translates into a value that can be sold in MWhs.
Grier explains that such a strategy differs from what was done in the past, which was much more an engineering approach. That approach was to spend money on plant performance improvement, but without the knowledge of whether such action affects the product profitability. Such action was taken more under cost-of-service regulation, since the company knew it could get the cost of service adjusted. But the market approach requires that if the market only will pay $26/MWh and a plant is selling at $28/MWh, there will be no interest in buying. Grier emphasized the importance of marketers, fuels management, and operations groups working closely together at fossil baseload plants. He believes that as markets move toward standard market design and locational marginal pricing, marketing departments will become even more important, providing the "headlights" to see down the path and squeeze as much as possible out of plants.
In retrospect, Hanser believes some merchant combined-cycle unit operators may need to re-think how such plants are operated.
For example, in some jurisdictions, certain combined cycle units have avoided putting on certain pollution controls (catalytic converters) because with low NOx burners one can avoid putting on a selective catalytic reduction (SCR) if the plant operates at above a 70 percent capacity factor. But if the plant drops below that capacity factor, some stage burners do not operate properly and start to produce NOx-and at that point, an SCR is required. So plant operators without the pollution control device have no flexibility to operate at below certain levels. Hanser believes those operators will re-think that decision over time, because they will want the plant flexibility.
Another example Hanser gave was a generating plant that was retrofitted in such a way that it had the capability to ramp more quickly at a lower cost. That resulted in the plant having a load-following capability that it didn't have before, and the plant began selling that service into one of the power pools. The plant operators found it was more profitable to take advantage of the new-found capability to follow load up and down, rather than to operate at maximum limits. The yield was maximized for that asset by taking advantage of a new technology, driven by allowing the plant operator to have a new product to sell.
In terms of what software can do to save money at a plant, Maxey says programs using complex algorithms can tell plant operators what spare parts to store in a warehouse, so that expensive parts are not sitting unused, while others needed to prevent outages are unavailable. Furthermore, Maxey notes that the algorithms allow managers to know when to purchase parts, stressing that there is a high carrying cost to holding nuclear plant parts. He recalls one utility warehouse that was able to cut costs by 20 percent using this type of software.
Moreover, Grier points to a shift in asset optimization-understanding not only the immediate impact of postponing a large maintenance activity (outage), but also the downside of changing the timetable. That then changes the probability of additional forced outages, or a de-rate of the plant or even some sort of catastrophic failure of the plant. It creates a tension between the immediacy of saving money in the plant, and the realization that it does impact the probability of a de-rate, a catastrophic event, or the forced outage, Grier explains. The result is that Navigant has moved toward looking at things from a probabilistic viewpoint, as opposed to just a single value. For example, postponing a turbine overhaul may save millions of dollars, but increases the likelihood of turbine problems, which causes de-rate and can cost a lot more than the overhaul would have.
As a case study, Grier points to a plant that needed three different pumps to operate. Typically one pump would stop working in the hottest part of the summer, when the plant was most "in the money." The question his company worked on was whether or not a fourth pump should be purchased as a backup. He explains that because it could take two days to replace a pump that went out in the summer, it was worth so much more to purchase the fourth pump, despite the cost. "Asset optimization may also mean identifying the real critical systems and the impact on the cost if one of those systems does go out," Grier says. He adds that in essence, "you can be penny-wise and pound-foolish" and that plant management needs to take into account the likelihood of a "big, bad event."
For example, Potomac Electric Power recently experienced manhole covers blowing up into the air above streets in Washington, and while the event itself may not have been so bad, there is a resulting, traumatic effect on public perception. That in turn can impact the amount of dollars to be spent to regain the public confidence. "We see that in nuclear plants all the time," he says. For example, two nuclear plants in Nebraska-Fort Calhoun and Cooper-were operated by two different entities, the Omaha Public Power District and the Nebraska Public Power District (NPPD), respectively. Fort Calhoun was very well run, but the Cooper plant was struggling from an operations capacity factor and cost standpoint. It resulted in an all-around lack of public confidence, Grier says. So NPPD hired an outside firm to run the Cooper plant. "If you get in a situation where you lose control, you will spend millions of dollars to regain the confidence of the public, and will probably make investments that don't add much value," Grier concluded.
Staffing levels also greatly affect asset optimization. Cutting employees, while it does impact the bottom line, is not what drives value in power plants, Grier explains. The only real place to save the way to success, he says, is with fuel. "If you look at all the things that drive the value of the plant, 95-plus percent is locked up in five or six things," Grier adds. So if you can manage those five or six key levers of your business, it creates value, and it helps people understand how the work they do creates or destroys value.
In another example, Grier worked with a utility company that operated in multiple jurisdictions. One of the key cost drivers was the timing of adding a transformer in a substation. The policies were different in each jurisdiction-each MVA or KVA of capacity would be added when one jurisdiction got a 40 percent margin on that capacity. But another company would add capacity when the margin reached 25 percent. That decision was made at a low level, and turned out to be a key driver of the cost of that business, he says. So the leadership team needs to discover what drives the value of the business. On the distribution system, Grier says, you need to ask what drives economic value, what drives risks to the system, and what drives customer satisfaction?
Grier points out that better reliability does not guarantee a better rate of return from a regulator. But a catastrophic event and bad reliability does have a strong correlation with the amount disallowed in the next rate case. The leadership team needs to have a handle on what is the risk profile of the system to catastrophic events, he says. Going forward, leadership of utilities must recognize that they need to shift from a cost-of-service mentality to understanding they have an obligation to deliver a product at a high level of quality at a very low cost. They need to say, "I have to become the Home Depot or Wal-Mart of the world," Grier argues, because those companies have learned to get as much out of their assets as possible. Grier believes the only difference between Wal-Mart and Kmart was that Wal-Mart understood how to optimize assets and Kmart didn't.
Several years ago the main issue was flexibility of the plant, Hanser says. For example, a large baseload coal plant would be more profitable if it was more flexible. "What may be efficient from an engineering standpoint may not be efficient from an economic standpoint," Hanser adds. "For example, on the trading side, it means you need to think carefully about the kinds of contracts you set up with the kind of plant characteristics that you have." You may need to modify the plant to better fit the market characteristics, Hanser explains. In some sense that is what deregulation is all about. "One of the long-run primary goals of deregulating the electricity market was to get to a better mix of generation, in terms of the kind of generation that was out there and how it was operated," Hanser points out. "If the market is doing that in the form of asset optimization, that is a plus in some sense for the deregulation of the electricity market," he adds.
Hanser does believe the generation asset mix has gotten more diverse, in the sense that in the old days utilities often faced cost overruns by building behemoth plants that cost two to three times more than the original expected cost of the plant. The big plants lacked flexibility and adaptability to the market. But Hanser explained that from the standard system planning perspective that utilities used to have, these were ideal plants to be building. That is where asset optimization comes in. "To some degree, if the market now says those assets built years ago are not necessarily the best assets and need to be operated differently, then I think the market is doing the right thing in terms of helping folks get to a better mix," Hanser says.
Hanser notes that optimization occurs more on the unregulated side, because of incentives. Hanser points to an example of a utility operating under an incentive rate for having a high capacity factor for its plant. But the plant was operated at an incredibly high capacity factor, and was operating even when it wasn't economical to do so (i.e., the marginal cost of purchasing the power was below the cost of generating power for that plant). But with a high capacity factor under the incentive regulation scheme, the plant would continue to operate. And so the utility found it more profitable to run the plant at a high capacity factor than to turn the plant off and buy the power on the open market. Hanser concluded that in such a case, regulation tends to create sometimes "perverse incentives" as to how to operate a plant.
Take for example a recent case where Duke/Fluor Daniel turned generating plants from a utility operating environment to a merchant plant-operating environment. In California, Ted Rosiak, senior vice president of operating plant services at Duke/Fluor Daniel, explained that they had a client purchase a number of generating plants from a utility, but that the employees came with the mind-set from having worked in a regulated-utility environment. Rosiak says the Duke team worked with the employees to introduce them to the merchant plant mind-set, which included how to make a profit, not just make megawatts. "Actually it was pretty easy once you got focused on what the goals were," he says. The team worked with staff to teach them how to operate in the open market so they could realize the impact their decisions had on the bottom line. The result was the staff says they were "energized" and "enthusiastic" and felt more in control of their own destinies. "The transition from a utility mind-set-which is not bad, it's just different-to a merchant mind-set set actually occurred by laying out a real business plan and putting goals and objectives forth, while the profit motive was the driver," Rosiak says.
Glenn Burney, a plant manager at a facility operated by Duke/Fluor Daniel, pointed out that all individuals at the newly minted merchant plants then receive employee performance incentives as a certain percentage of base pay. So the incentive plan helps get employees interested in learning the business plan, plus added training helps them achieve the new goals. According to Dean Blaha, also a plant manager at Duke/Fluor Daniel, the utility versus merchant-plant mind-set for maintenance often comes down to a replace versus repair mind-set. He noted that a regulated utility often simply would replace a piece of equipment because it gets built right into the rate base, while at a merchant plant, the repair versus replace decision is based much more on economics.
In the Trenches
Five plant managers who run very different types of generating plants for Duke/Fluor Daniel's Operating Plant Services talked to the Fortnightly about situations they have dealt with involving asset optimization. Ted Rosiak, senior vice president of Duke/Fluor Daniel's Operating Plant Services explained that they operate merchant and cogeneration plants, as well as provide support for utility plants.
Rosiak pointed to a cogeneration facility, which Duke/Fluor Daniel built in 1992 and operated to supply steam to an industrial plant, with electricity made as a side product. But when the steam host closed its plant, the cogeneration facility owners, with assistance from Duke/Fluor Daniel, worked quickly to modify the power purchase agreement so the plant could continue to operate under that agreement. "The issue is how do you change the business structure of the facility. Doing that changes the way the plant is dispatched, which means maintenance practices have to change," Rosiak says.
Maintenance isn't the only thing that has to change-managing fuel and having the right employees count, too. So the transition to a new business approach had to be dealt with.
Glenn Burney, the project manager for that plant, explains that while the cogeneration plant can operate from a range of 18 MW to 132 MW, that it in fact operates under a long-term contract for 132 MW. That means that the challenge is that while no more MWs can be squeezed from the plant, he needs to make sure no MWs are lost, for example, as the plant experiences wear and tear. Under the contract, reliability is the key for that plant. "If it's not extremely reliable," Burney says, "we can suffer liquidated damages and lawsuits under the agreement." So the plant operates under a very predictive and intensive maintenance program.
Dean Blaha manages two municipal plants in Delaware, which consist of two natural gas-fired and oil-fired generating stations. He explained that prior to 1996, the plants were owned and operated by the city. When the city contracted with Duke/Fluor Daniel for operations and maintenance services, they operated as baseload units, with fairly small fuel oil storage capacity on-site. But Duke/Fluor Daniel saw there could be more profitability with those units functioning as peaking units, in order to take advantage of economics in the summer and winter, when it was more justified to run the plants, and then purchase power in the off seasons. Also the small fuel oil tank size made the plant very vulnerable to the fluctuations in fuel oil costs. So Duke/Fluor Daniel at no cost to the city purchased and installed a much larger fuel oil tank on-site, in order to buy fuel when the price was low and store it. Blaha says the combination of the two optimizations helped keep the cost of power low for the city. "So it's not necessarily a megawatt squeeze, but an economic squeeze," he concludes.
Rick Roberts runs operations and maintenance at a 480-MW coal-fired generating station in Texas, equipped with a General Electric turbine/generator and a Combustion Engineering boiler providing 2,400-psig steam. He presently is involved in working with the client concerning the single source of fuel supply and single method of transportation for getting that fuel to the plant. The single-unit plant obtains its fuel from a coal mine in Wyoming, and only one railroad is available for transport. "We feel very vulnerable to this single source of fuel," Roberts says. "One of the things we're doing for that client is a risk evaluation of that process, determining what can go wrong, what the duration is, what the probability of those occurrences would be-and using that to guide our fuel inventory to minimize our risk exposure to those different occurrences." He says they just finished the probability analysis and now are working on the business case evaluation. What that will lead to, Roberts says, is minimizing the plant's risk and exposure to ensure its long-term health.
At the same plant, Duke/Fluor Daniel just finished a joint project with the customer to install an over-fired air process for NOx reduction and low NOx burners that have reduced NOx emissions dramatically and increased boiler efficiency. Roberts says they are still involved in fine-tuning, so while he does not have the final numbers, "it looks very, very promising." He added that they know they are saving money just from a fuel efficiency perspective.
Roberts says his company also modified a lot of the chemical processes at the plant, which improved reliability dramatically. That increase in availability and corresponding ability to make money was extremely important at that plant because it is captive to four cities who must pay for the cost of the plant, regardless of whether it generates one megawatt or a million. That plant was built in 1982 and in the last two years has had the best productivity in its history. Last year, Roberts added, the plant had 100 percent availability.
Rick Toney is the manager of a complete power system in West Papua, Indonesia, consisting of 45 diesel-fired units, and three 65-MW coal-fired stations. Duke/Fluor Daniel also manages the entire distribution system of the island for its one customer engaged in milling. Recently, Toney was involved in a project involving optimizing the amount of coal generation and reducing the amount of diesel generation, while still keeping reliability and stability high. "We've done that over the past couple of years, and we're still working on that today," Toney says. He noted that diesel fuel costs much more than coal, partly because the coal comes from Indonesia, which is much closer than the diesel sources. Also, Toney is involved in plant system modeling-plugging in different scenarios and being told what will happen in a particular situation. And since Toney runs the only system on the island, high reliability is essential, since if the lights go out, there is no backup.
Jim Schaddel is a plant manager who runs a system unique in the United States-16 waste-heat boilers and production of up to 928,000 lbs./hour of high-pressure steam by capturing waste heat from 268 coke ovens, in which coke is used as a fuel to make iron in blast furnaces. The high-pressure steam is converted into electricity and process steam in this first-of-a-kind plant located in Indiana. Since Duke/Fluor Daniel inaugurated the plant's commercial operation in 1998, Schaddel says boiler performance has increased, there have been fewer turbine trips, and Duke has met or exceeded some of the goals the client had regarding steam production and generation. Not only that, but the plant has won some environmental awards from the state. "We're very proud of the fact that not only are we able to operate an efficient plant, but we are able to clean up the environment quite a bit," Rosiak says. He adds that it garners a lot of goodwill from the community.
Rosiak points out that when trying to squeeze megawatts out of a plant, it also is important to be able to keep the plant running under new environmental regulations. When trying to squeeze megawatts, he cautions that sometimes you might not be able to go too far because of environmental or other issues. "So it's not just simply squeezing megawatts, you have to deal with all the regulatory issues that come from the output of the unit," Rosiak concludes.
The How and Why by Region
Although the generation plant construction industry is experiencing a downturn, there are regional variations in the boom-and-bust cycle. Henwood, a consulting firm, recently released its six-month updates on power market fundamentals for the following regions:
In the Midwest: Henwood says the turbulence and price spikes of 1998 and 1999 are in the past. Today's power market in the Midwest is defined by capacity overbuild. New construction by merchant plant developers and by some electric utilities has resulted in systemic overbuild for the region. But that supply is not evenly distributed. So while sufficient capacity is completed or under construction to meet demand growth for the rest of the decade, in other markets new capacity will be needed in a few years. Wholesale electric prices are expected to stay low for several years because there is too much supply relative to demand. But wholesale prices are expected to increase rapidly in the mid-term as markets move toward all-in pricing in the 2007 to 2012 time frame.
In the West: Henwood finds that while drought, capacity shortages, and high electricity prices of 2000 to 2001 are indeed in the past, the West does face challenges. For example, the liquidity crisis facing many merchant developers has resulted in many project cancellations and postponements. But Henwood notes that a large number of new generating plants are coming online, and others are under construction, while loads have not returned to their pre-crises levels. Henwood believes there may be an overreaction by forecasters to the precipitous load drop, and that some entities predict a more rapid return to the old forecast level, which is consistent with Henwood's view. But for the first time, Henwood forecasts that some aluminum smelter load in the Pacific Northwest never will return. Generation appears adequate from an overall margin reserve viewpoint. And while some load-serving entities (LSEs) need to secure their energy requirements, some generators still have not sold their output. So both the "short" LSEs and the "long" generators are exposed to volatility and need to find a way to enter mutually beneficial bilateral contracts. Finally, Henwood does predict the potential for price spikes in September 2003, and finds some outage potential in Northern California, as well. But overall wholesale prices presently are low and are expected to remain moderate over the forecast period (through 2012), despite some regional and localized differences.
In the Southeast: New construction by merchant plant developers in the Southeast, as well as by some electric utilities, has resulted in a systemic capacity overbuild for the region, according to Henwood. But it cautions that the supply is not evenly distributed. So in some markets there is sufficient capacity completed or under construction to meet the expected growth in demand for the balance of the decade, while in others there is a need for new capacity in just a few years. Most areas in the Southeast have adequate margins through 2010, but some areas may need added peaking capacity as early as 2004. Overall the wholesale price of electricity in the Southeast is low compared to historical levels and is expected to stay that way for several years. Henwood expects prices to rise rapidly in the Southeast after 2006 as markets move toward equilibrium pricing, but not to reach levels to support merchant generation solely from the spot energy markets until well after 2010. However, prices could rise earlier if loads increase moderately such as from a prolonged weather event, old coal or nuclear capacity retirements, or more rapid market evolution.
In the Northeast: While the Northeast is marked by capacity overbuild, the supply is not evenly distributed. So in most areas within the Northeast, with the possible exception of Quebec, there is sufficient capacity completed or under construction to meet the expected growth in demand for the balance of the decade. But in other markets, such as New York and New England, there is a need for added peaking capacity as early as 2004. Henwood says that overall, the Northeast markets reflect high reserve margins that will keep wholesale power prices low. Low prices also are in large part due to an overbuild in generation that is highly efficient and heavily dominated by nuclear in a region that is a mix of multi-fueled units. Henwood expects wholesale prices to rise rapidly after 2006 as markets move toward equilibrium pricing, but not to reach levels to support merchant generation solely from the spot energy markets until well after 2010.
In Texas: The forecast had not yet been released at press time, but Gary L. Hunt, vice president of consulting services at Henwood, says preliminary results show that Henwood's prediction of two years ago-that ERCOT faced a threat of displacement-has come true. In fact, about 7,000 MW of older, mostly coal-fired generation has been mothballed. "The newer, efficient units are driving out the older ones," Hunt says. "That is accelerated in part by the regulatory quirk that ERCOT is the last market where you can get something equivalent to stranded costs recovery," he explains. "So some of the older units are coming off now because the PUC says 'Get this junk out of here and clean up the air and we'll give you some stranded cost recovery.'" He adds that there is still a large capacity overbuild in that market, but in the past ERCOT had a fast growth rate to absorb it. But while that growth rate was anemic in 2001, Henwood predicts it will return to its historic levels, which are high by North American standards-about 2.7 percent. So ERCOT will come back into balance in about five years, but there is an ugly period in the short-term that it has to go through, Hunt predicted -L.A.B.
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