Duke Energy’s Jim Turner and other utility executives weigh the odds on billion-dollar bets.
Richard Stavros is executive editor of Public Utilities Fortnightly.
It could be described as the world’s highest stakes betting game—power generation development. Not even the recent James Bond movie, Casino Royale, where audiences were riveted by a climactic $100 million poker game, can touch the sums (and risks) that utility executives must face.
According to the Edison Electric Institute (EEI), investor-owned utilities spent $46.5 billion in 2005 and more than $60 billion in 2006 to develop new power infrastructure. U.S. utilities added 5,507 MW and announced 33,998 MW of new capacity additions in 2006. In fact, last year alone, environmental capital expenditures doubled from $3.2 billion to $6.4 billion, said EEI.
Looking at the forecasts for 30 years, the heavy investment required for new generation technologies clearly is a global phenomenon. According to the World Energy Investment Outlook 2006, power-sector companies will spend about $11 trillion dollars by 2030. “That’s for the overall power sector that includes power generation, transmission, and distribution assets,” says Andy Webster, a consultant at Accenture, adding that power generation alone will account for $5 trillion.
Without question, those amounts would impress even the most exclusive casino owner in Monte Carlo, especially as the odds of winning the development game are quickly changing.
Global resource competition is making power-plant development more expensive, and may even limit the number that any one utility in any one country can develop.
Duke Energy recently disclosed a cost of roughly $1.9 billion (including Accumulated Funds Used During Construction [AFUDC]) for its proposed 800-MW Cliffside coal unit in North Carolina, which translates to a price tag of $2,375/kW. In a research report, Wachovia analyst Samuel Brothwell said the price reinforces the trend of escalating costs for new-build construction materials, equipment, and labor contracts. The $1.93 billion for the one unit was almost the original cost estimate for the two plants Duke had proposed to build. Also, in late 2006, Duke Energy had to revise its price estimates for the nuclear power plant it may build in Cherokee County, S.C.
“We have said that the cost of constructing two AP1000 Westinghouse units could be between $4 billion and $6 billion,” said Jim Turner, president and COO, U.S. Franchised Electric & Gas, at Duke Energy.
Turner says the utility is taking a proactive approach in trying to convey the higher costs to regulators and the public. “We are going to let everybody know, ‘Look it’s more expensive today than it was not long ago. Prices have gone up everywhere. It is a hot market for both base-load coal and for base-load nuclear and that’s the world in which we find ourselves,” he says.
“We’ll make it clear in the beginning that the costs estimates are higher than we expected, and then we are going to work like crazy to bring the plants in at the estimates that we put out there,” Turner explains.
Indeed, some nuclear experts believe that world-resource competition may put limitations on the number of nuclear plants that actually can be built in the U.S. This is the belief of Jack Bailey, vice president, nuclear generation, Tennessee Valley Authority (see sidebar, “Battle of the Big Nukes,” on what nuclear designs are favored). An example is the recent spike in uranium prices, which have soared to $95 per pound, from less than $20 three years ago, as a result of supply disruptions and dwindling inventories. The Nuclear Energy Institute, which represents nuclear operators and uranium suppliers, has said if the fuel prices don’t moderate, nuclear power will be somewhat less profitable.
Of course, anyone that has been watching TV or reading the newspaper lately will know that far greater considerations than just input commodity prices are driving power-generation technology decisions.
The Supreme Court recently ruled that the Environmental Protection Agency has the authority to regulate the emission of “greenhouse gases” linked to global warming. In the meantime, talks of national carbon-emissions legislation have all but changed the economic calculus of choosing non-carbon emitting nuclear versus other technologies.
“Electricity demand and other factors such as global warming concerns continue to drive major investments in power-plant development,” says Accenture’s Webster. “We’re seeing an increasingly challenging environment for utilities to deliver successful plant construction projects that meet their cost, schedule, and operability objectives.”
That may explain TXU’s decision as part of its acceptance of a leveraged buyout offer from private equity firm Kohlberg Kravis Roberts & Co. and Texas Pacific Group, to scrap plans to build a large fleet of coal-fired power plants in Texas. The coal plants were highly controversial and drew much public criticism. It also had been widely debated in the industry whether TXU would have been able to build the 11 new coal-fired power plants in Texas at an original cost estimate of nearly $1 billion a piece.
“As I talk with investors and others in the industry over the last year, we never totally got what TXU was doing anyway. I’m not sure I ever totally believed the cost estimates associated with their build. So, maybe I’m alone in this, but I don’t think I was very shocked that they canceled those units,” said Duke Energy’s Turner.
Meanwhile, perhaps because of the growing expectation of climate-change regulation, TXU in early April announced its shift to nuclear power, joining an ever growing list of utilities.
Currently, three other organizations—NRG Energy Inc., Exelon Corp., and Amarillo Power—have said they, too, may build nuclear plants in Texas.
Given climate change, it is no coincidence that utilities are placing ever greater bets on nuclear, but experts warn that the technology is not a panacea for meeting future demand.
John G. Rice, vice chairman, General Electric (GE), speaking at CERAweek 2007, advised against utilities looking for a silver bullet, no matter how tempting.
“There is not one technology. If I listen to the discussions that take place in Houston, or in Washington, or in Beijing, or in Brussels, or anyplace else where this is the subject of discussion, the one fallacy that you [hear] is that people tend to be hoping that there is going to be one solution to all of this,” Rice said.
Rice, who also holds the title of president and CEO of GE Infrastructure, said he has met many in the industry who are either all for nuclear, all for wind, or all for coal. “The fact of the matter is it isn’t going to be all of any one thing. It is going to be a portfolio of options,” he said. He stressed that coal, nuclear, natural gas, wind, and other renewables would all be part of the solution.
Efficiency: The Safe Bet
The Art of War, penned in the 6th century B.C. by Chinese general Sun Tzu, states that “every battle is won before it is fought.” Given the escalating costs of power-plant development, many executives are trying to find ways to win more capacity without having to build. What can you achieve on demand-side management and efficiency?
“I’m not sure we have ever thought about energy efficiency in the way we are all about to think about it—not just the technology, but the rate-making treatment associated with that,” says Duke Energy’s Turner. This may be an oversimplification, but the idea is that utilities could book base-load energy-efficiency investments at something slightly below the avoided cost of generation, he says.
“Isn’t that a good thing for customers because it’s saving the need for new generation, and lets the utilities essentially earn on rate-basing energy efficiency and demand-management investment the same way that they would in building a power plant?” asks Turner. He proposes that energy efficiency be part of the integrated resource plan so such programs do not fall by the wayside after power-plant development is complete.
“We’re not waiting like last time, where we build generation and then got into an oversupply situation, and then tried to look at energy efficiency and demand-side management. It is going to be awfully hard to make any of those investments look cost-effective when you have an excess generation build,” he says.
That’s why he believes that investment in energy efficiency and demand management should be done in concert with evaluations of new generation resources so only those plants that are needed get built.
Turner proposes that utilities should “economically be indifferent as to whether they build generation or invest in energy efficiency.” And he has considered the possibility that utilities could become too reliant on energy efficiency and renewable alternatives.
“You might see companies look to expand their reserve margins so that you can count on these resources. It may well be that utilities look at increasing that 17-percent reserve margin to 20 percent,” he says.
In the near term, Turner says Duke Energy has been encouraging its commercial and residential customers to adopt compact fluorescent light bulbs and more efficient appliances in homes.
In the longer term, he says the utility is looking at installing new metering technology and is installing controls in appliances that customers “actually have in their homes, so that we have the ability to cycle on and off their appliances at particular times of the day and use new metering infrastructure as a way to facilitate that happening.” Turner would not hazard a guess as to how many power plants would not have to be built as a result of such efficiency measures.
But Dan Merilatt, manager of the demand-response program at Cannon Technologies/Cooper Power Systems, has worked on many of these programs and has a strong view of what can be achieved. He says many programs have garnered up to 30 percent of customers with central air conditioning, which represents a significant amount of dispatchable load control. “If you looked at that in the market nationally, that would allow maybe 10 percent of the summer-time peak demand that could be met through demand response alone or through these load-control programs,” he says. “It can be met at a cost that is about half what a greenfield combustion turbine would cost.”
Merilatt wouldn’t suggest that these replace combustion turbines, but as part of the supply mix, he says it is an economical way of meeting peak demand in the summer.
“I think these programs are full-cost in marketing and incorporating customer incentives, keeping customers engaged, and buying and installing the devices and servicing them. If you roll that up, the present value of a whole program is pretty close to half of what a combustion turbine would cost you over its life cycle as well,” Merilatt says.
He believes these programs bring “good value” for electric utilities because they do not discomfort customers. “Maybe less than 1 percent of customers are even aware that these cycling or control events are occurring. And those that do can probably call a customer-service center and have themselves removed from the event as the devices that are deployed are all individually addressable.”
The Long Odds on Coal
Even while some utility executives might be reluctant to bet on coal given impending climate-change legislation, many experts say it’s a bet they will have to make. “Carbon regulation does not mean the end of coal. I think the country would be foolhardy to think that. I think our commission in North Carolina got that very clearly,” Turner says. “To me [the TXU decision to not build coal plants] was not earth-shattering news that said, ‘Uh oh, coal plants are now off limits.’
“You are always going to have coal in the mix, even with TXU’s decision, even if Congress mandates carbon regulation. The country should want to have coal in the mix from an energy-security standpoint and a competitive standpoint,” he says.
Turner says Duke Energy has taken a novel approach to making coal a more reasonable alternative given emissions considerations. The utility gave several concessions, for lack of better word, that made coal more politically and socially acceptable, in exchange for building new coal units.
“We said we were going to spend up to 1 percent of our Carolinas revenues on energy efficiency investments. The number that was used in the case was about $50 million per year. We were putting our money where our mouth was on energy efficiency and demand management,” Turner said.
Second, Duke Energy promised to retire Cliffside units 1-4 as part of the negotiation, which would take 200 MW of significantly older, less efficient units out of operation.
And third, Duke Energy said it would be “prepared to retire on a megawatt-for-megawatt basis older, less-efficient coal for every megawatt of demand-side reduction that [the utility] gains from new [demand-side] programs,” according to Turner.
While a verification system would need to be put in place, Duke Energy has promised to retire older, dirtier units (up to the full 800 MW of Cliffside) as the utility obtains and verifies new demand-side reductions. “I think that is indicative of some of the creativity you can get to meet carbon regulation,” he says.
In fact, many utility executives have been exploring using biomass to refuel their existing coal-burning plants to potentially mitigate CO2 effects, according to Jim Rossi, vice president, Power Generation & Sustainables, at KEMA.
“It’s a very viable alternative as far as a partial replacement of the fuel. It’s not a complete replacement. But you can replace up to 15 percent of the fuel on an energy basis with biomass. That’s actually quite substantial. And the capital costs associated with that are generally not that large,” he says. Biomass is organic fuel such as wood, switch grass, peanut shells, or any replenishable fuel source.
Rossi explains that the costs of biomass for existing coal plants are nowhere near what it would cost to build a standalone 30-MW, 40-MW, or 50-MW biomass facility, which he says, “is very expensive and is just about cost prohibitive in most cases. You really couldn’t build one and generate electricity competitively.”
But fueling coal-fired plants with biomass, he says, is inexpensive since most of the equipment is already in operation. “You are adding very little new equipment, some storage silos, or pulverizing equipment.”
Whether it’s a viable option really comes down to your location.
“It is the location of the individual projects. Where they are located and how close they are to some good low-cost biomass resource,” he says.
Rolling the Dice on Commodities
Even as the industry decides how much they will bet on any power-generation technology, the containment of construction costs is first and foremost on the minds of utility executives. Many power-plant developers are not providing a fixed fee to utilities in their engineering, procurement, and construction costs due to the escalation in commodity input costs, experts say.
“There may be opportunities to do multi-prime type of arrangements where maybe you don’t completely rely on an EPC to do everything for you in the project. But you internally take on some of that risk and that management as well,” Duke Energy’s Turner says. He says what is important in such an environment is to keep regulators and ratepayers informed of what costs are fixed and which are not on particular commodities, or for particular services, or for particular labor costs.
“The commission already has asked that we update them basically every year on cost, but has invited us to update them as often as every month on cost,” he says. In fact, Turner believes it may help in working with suppliers to let them know that the utility has to go back to the regulators every month to reexamine the cost. “It may have a salutary effect on helping keeping some of the prices down,” he says.
Richard Ward, senior director at Cambridge Energy Research Associates (CERA), says his firm is developing an index of commodity costs associated with power-plant development as a way to bring greater transparency to the process.
“What we are doing actually is leveraging our experience in a methodology we developed a year ago in the oil and gas sector,” Ward says.
About 18 months ago, CERA noticed that costs were starting to go up in the building of oil and gas projects. “What we found is when we asked executives about it, they couldn’t summarize it. They would jump straight down to the details about the price of steel or an engineering quote that they got,” Ward says. In response, CERA developed something like a consumer price index for oil and gas projects.
“So, it’s a portfolio of 28 projects from around the world, and every six months we go out and re-price, almost like an Ebay buy-it-now price for this entire basket of projects, and then we roll up the cost of all those things and index it back to the year-2000 cost.”
The IHS/CERA Upstream Capital Costs Index (UCCI), as it is called, which tracks nine key cost areas for offshore and land-based projects, climbed 13 percent during the six months ending Oct. 31, 2006, compared with an increase of more than 17 percent in the previous six months, according to press materials. The index could provide a high-level barometer to utility executives and regulators to look at what has happened in the cost situation in the last 24 months, he says.
Ward says he recently got the green light from internal management as well as some external power companies to start building the index with the same methodology, but for generation construction costs in North America. He predicts that the first results from the completed index will be available by late summer.
When asked about the benefits of using an index, one utility executive overseeing several construction projects said, on the condition of anonymity, that it could be helpful when dealing with the state-regulatory process. “It’s probably best to be as specific as you can with the costs related to your own project,” the executive said. It’s fine to show an index related to commodity prices, but you have to be prepared to show regulators what that specifically means with regard to the project they are looking at, he said. “As long as you can explain how such an index could impact a particular project and the cost of this particular project, I think that has a positive effect.”
And if utility executives do manage to contain the costs and build the right plants and manage the stress, the big bets and high stakes will have been worth it.