By David Wagman, Chief Editor
Prospects for new coal-fired generation appear to be limited until issues related to carbon are resolved at the federal level, either through congressional action or through rulemaking by the Environmental Protection Agency. New natural gas-fired development may fare better in part because of the fuel’s more favorable environmental footprint and in part because the development of unconventional natural gas resources may ease price volatility.
The overarching concern, however, centers on how quickly the economy can recover. Even then demand for new generation may be suppressed by energy efficiency initiatives, demand-side management programs and smart grid development all of which are aimed at suppressing load curves and demand forecasts. New fossil-fired power plants also are likely to be affected by renewable portfolio standards (adopted in around two-thirds of the states) and a variety of programs at the federal level to encourage renewable project development.
Under the current political, regulatory and economic climate there is no push for significant big baseload aside from “a few marquee” projects in nuclear, said Jeff Schroeter, a principal with Genova Power Partners, which develops natural gas-fired combined cycle power plants. “If you take large baseload out of the equation for environmental or societal reasons, you can’t keep the lights on without gas to take up the slack.” As recently as 2005 there was talk about building as many as 100 new coal-fired power plants. Rising capital costs and uncertainty over carbon regulation ended most of those projects.
Schroeter said that within the last 90 days his company has been approached by four different entities to develop projects. Figuring on two years for the permitting process and two years to build, those potential new gas-fired projects could come online in 2014. Demand in the western and southern U.S. could recover first. More heavily industrialized parts of the country could lag.
Near the end of 2009 the California Energy Commission approved construction of a 600 MW combined cycle, natural gas-fired plant. Work on the Avenal Energy Project is slated to begin in 2010 and the plant is expected to be in service by 2012.
And Progress Energy filed with North Carolina regulators to build a 600 MW natural gas-fired plant at its Sutton Plant. The move follows Progress Energy’s decision earlier in the year to close 11 coal-fired units, including Sutton. The company estimates the new plant will cost around $600 million. Three coal-fired units at Sutton are expected to be shut down in 2014 about the same time the natural gas units are scheduled for completion.
A potential growth area is for quick start natural gas plants to smooth the peaks and valleys of so-called “as available” energy sources, which includes wind and solar. “The technical solution is that if you have volatile as-available generation you need to offset with natural gas,” he said. However, not all market pricing structures offer a price signal to justify installing firming capacity. Without a price signal it’s difficult for energy providers to justify the capital investment required for a unit that sees infrequent use. The default approach is to either run other units harder or off their design specifications, Schroeter said.
Other factors that may favor natural gas are the development of unconventional natural gas resources and additional storage capacity. Both tend to dampen price volatility, which has been a negative factor in the past. “We won’t see $14 gas any time soon,” Schroeter said.
Renewable Energy 2010: Utilities Emerge
By David Wagman, Chief Editor
Renewable energy consultant Nadav Enbar may have offered the understatement of the year when he described 2009 as “pretty messy.”
Messy, indeed. Projects were scaled back, postponed or cancelled altogether; sources of finance dried up almost overnight; demand for electricity fell; and natural gas prices remained low through much of the year playing havoc with project development economic forecasts.
“Development was slow going, particularly for large projects that required upfront capital,” said Enbar, Boulder, Colo.-based research manager for IDC Energy Insight.
Despite the mess—or perhaps because of it—two trends emerged that seem likely to drive renewable energy markets well into 2010.
First was the steadily growing utility role in the renewable energy sector. Their emergence is driven by ongoing access to capital, growing comfort in renewable technologies, an array of financial incentives and—in the case of solar photovoltaics—a drop in price that makes PV an attractive investment.
The price decline spurred at least seven utilities across the country to begin developing PV facilities for their own rate base, said Lisa Frantzis, managing director for renewable and distributed energy with Navigant Consulting. Those utilities include Southern California Edison, Pacific Gas & Electric, Public Service Electric and Gas and Duke Energy, among others. “I have never seen so much interest,” she said.
A related development is the growing use by utilities of investor equity, tax equity or pools of tax equity capital to develop projects.
“Utilities have tax burdens that are roughly six to seven times higher than what has historically been the pool for tax equity finance,” said Chris O’Brien, who heads market development efforts for thin-film silicon maker Oerlikon Solar. “Now utilities can use the credits themselves, increasing the opportunity for them to invest directly in projects,” either to include in their rate base or as a non-regulated investment.
Investor-owned utilities seem to have weathered the economic downturn better than other sectors. “The important thing was we (investor-owned utilities) were able to continue to borrow on a long-term basis” during the financial crisis, said Mark Agnew, director of financial analysis for the Edison Electric Institute, which represents many investor-owned utilities.
At the height of the financial crisis, a number of utilities cut their capital budgets by an average of 10 percent. As the year progressed, however, many of those cuts were reversed. “We’re back on track for capex in 2009-2010 in the mid-$80 billion range,” Agnew said.
Another trend is that for the first time more than half the utilities polled by the Electric Power Research Institute said they considered themselves renewable energy project owner-operators. That factor is likely to put more downward pressure on costs as utilities work to cut costs further, said Bryan Hannegan, vice president of environment and generation at EPRI. “The days of freewheeling, ‘I’ll buy it at whatever cost’ are ending,” he said.
A second major trend likely to influence the sector during 2010 is the federal government’s financial market intervention, which included some $67 billion of stimulus money, loan guarantees and grant programs for the renewables industry. Intervention actually began in the autumn of 2008 when Congress extended an already existing series of tax incentives and then took the step of making utilities eligible for the credits for the first time. In February 2009 Congress passed the American Recovery and Reinvestment Act (the “stimulus bill”). Included were a variety of loan guarantee and grant programs offered through the departments of Treasury and Energy and intended to keep money flowing for project development and new manufacturing initiatives.
“The government stimulus made up for the shortfall in private sector finance,” said Hannegan. The money helped the renewable energy industry maintain momentum it otherwise would have lost.
Federal financial aid has allowed virtually every developer to opt between receiving a production tax credit or an investment tax credit, said Energy’s Insight’s Enbar. And it also allowed developers to receive up-front grants, “which is, in some ways, the best way to get financing.”
One question for 2010 is whether or not the federal stimulus money is sustainable over time. Barry Worthington, executive director of the U.S. Energy Association, offered the reminder that “what the federal government giveth, the federal government can taketh away.” He wondered whether pressures to balance the federal budget may lead Congress to pull back some of the financial programs that benefit the renewable industry. Tighter fiscal policy, he said, could trump interest both in climate change and the push for national renewable energy standards.
A related question is the extent to which the private financial sector reenters the renewables market. Loan conditions tightened and lenders showed little appetite for billion-dollar-plus projects during 2009. Instead, lenders favored projects in the range of $300 to $400 million earlier in the year, then as markets recovered, expanded that range to $700 million to $800 million.
Because of this and other examples, Ed Feo wonders whether the federal loan guarantee program may eventually form the basis for the still nascent “green bank” concept. “Does it become the vehicle for federal support for renewables,?” asks the Los-Angeles-based partner in the law firm Milbank, Tweed, Hadley & McCloy LLP and co-chair of the firm’s project finance and energy practice. If yes, then perhaps the federal government could end up as the principal source of finance.
A third trend relates to project scale and scope. Ongoing frustrations with siting, permitting and transmission access have some developers seeking the path of least resistance. That favors small, distributed projects.
Just such a strategy is being pursued by Southern California Edison, among others, as it deploys 250 MW of rooftop-mounted solar PV across its service territory. Rather than site all that capacity in a single project, the utility is adding it in 1 and 2 MW increments. The approach aims to achieve several things.First, it spreads capacity across the local grid, distributing benefits and drawbacks inherent in the solar resource. Second, building on rooftops eases many of the siting and permitting headaches that accompany greenfield development. Local building codes and permits still must be followed, however.
The development focus in the solar energy sector likely will shift from “enormous solar farms in the desert to 1 to 20 MW projects co-located with substations,” said O’Brien. The approach allows for new capacity without the need for additional transmission, a third benefit to the distributed energy approach.
Most sources expressed cautious optimism that the worst of the recession is over and that 2010 will see growth resume. They point to the infusion of federal stimulus dollars and renewable portfolio mandates in most states that compel adopting renewable energy technology. At the same time, however, sources noted conflicting trends that make it too early to tell whether or not sustainable recovery is likely in the next 12 to 18 months.
It’s a tough time to predict the future, said Jeff Dennis, a regulatory specialist with the Edison Electric Institute. On the one hand, demand for electricity is down, but state renewable portfolio standards and federal policies continue to push renewable energy deployment. “There are so many competing drivers that are 180 degrees from each other,” Dennis said.
One uncertainty is the prospect for a federal renewable energy standard. Work on legislation to create such a standard stalled during the autumn as lawmakers argued over health care reform. Several sources suggested the outcome of the health care debate and proposals for financial sector reform may actually determine whether or not a comprehensive energy bill is possible.
If Congress fails to pass any sort of a bill before mid-2010, the prospects of getting climate legislation done next year will begin to fade. That leaves Congress with little more than a six-month window to complete its work.
“The government has taken some good steps to incentivize renewables,” said Martin Gross, power systems president for ABB. But he believes those steps fall short of enabling the country to reach a goal of even 15 percent renewable energy in the U.S. generation mix by 2020.
“Fifteen percent at an availability of 30 percent would require 500 GW of installed capacity nationwide,” he said. “How does that happen?” For one thing, investors need a predictable 10-year return on their investment. For another, firm in-service dates for new transmission need to be set. “If you don’t see that it will be a continuation of 2009 with delays, delays, delays, delays,” Gross said.
Transmission and permitting will be perennial issues for renewable energy projects for the foreseeable future, said EPRI’s Bryan Hannegan. Opposition continues to large-scale developments, even those that promise low-carbon renewable energy. “We may have misled ourselves,” Hannegan said. “Folks still won’t want those in their backyards.”
Nuclear 2010: Clear and Murky
By Nancy Spring, Senior Editor
The forecast for nuclear power in 2010 is a simple one: Maintain the old plants, start building the next generation of plants and formulate a new nuclear waste policy.
Simple but not easy, at least when it comes to building or developing a new waste policy.
For existing plants, the game plan is clear. The oldest reactors still operating in the U.S. were licensed in 1969, but half of the reactors in the country are less than 24 years old. Between uprates and upgrades and advancements in service and repair technology, operators can expect to get more power out of them for years to come—and judging by investments made by key industry players, plenty of work for the companies ready to serve this market.
Building new plants is another story entirely. Even with government loan guarantees and strong political support, the future of the U.S. nuclear renaissance is ambiguous. Throw in uncertainty about Yucca Mountain and the outlook becomes murkier.
The Maintenance Market
There are 104 nuclear reactors operating in the U.S. and 20 in Canada, most of which were put into service in the 1980s. As of June 2009, the NRC had extended licenses for 54 reactors and has license renewal applications under consideration for another 16 units, so these units have to operate smoothly for another 20 or even 40 years.
“One of our key focuses is to keep them running,” said Richard Reimels, president, nuclear power generation group, Babcock & Wilcox (B&W). “Like an old car or an old house, they need a lot of repairs and maintenance.”
It’s a hot market and B&W’s Mount Vernon, Ind., facility, is growing to keep up with the pace. “We got our nuclear N-stamp back there a little over three years ago and so we’re doing some replacement reactor heads there, for Diablo Canyon for example,” he said.
Since September 2007, there have been 30 new N-stamps and the Nuclear Energy Institute has held a number of workshops to bring production capability back to the market.
Major component replacement is one of the principle maintenance projects at the older reactors. SGT replaced a total of eight steam generators at PG&E’s Diablo Canyon plant in 2008 and 2009, for example. B&W is building the steam generator replacements for Davis-Besse and recently shipped two units to the Crystal River plant, but most of the older plants have now completed that job, said Reimels. “On the Canadian side, for the Bruce Station we’re building the replacement steam generators there and then I think that’s probably it for steam generator replacements north of the border as well.”
Utilities also continue to uprate existing plants, modifying the plant to eke out more power. The Nuclear Regulatory Commission (NRC) anticipates 12 uprates in 2010, 17 in 2011 and seven in 2012 (combining projects across all three of the NRC’s uprate categories). According to the NRC, uprates to the U.S. nuclear fleet have added generating capacity to existing plants that is equivalent to more than five new reactors.
“We’re in negotiations with three or four utilities to replace and upgrade condensers and heaters and that type of thing,” said Reimels.
Equipment upgrades at Exelon’s Quad Cities nuclear plant in Illinois increased the plant’s output by 38 MW. Last fall, Areva completed installation and commissioning of two Siemens variable frequency drive (VFD) systems for reactor recirculation pump speed control at Quad Cities Unit 1. The new drives are designed to improve plant performance while reducing house load.
“Our nuclear units, which had an average capacity factor of about 47 percent in 1997, consistently achieve a capacity factor of 93 percent or more today,” said John Rowe, Exelon’s CEO, in an interview with Electric Light & Power magazine. “We invested to add more than 900 MW of capacity from existing plants in the past 10 years and solidified Exelon’s position as the least carbon-intensive large power generator in the U.S.”
According to Areva, the NRC projects that more than 2,600 MW of capacity at existing nuclear power plants will have been added through efficiency gains alone by 2013.
Another upgrade trend Reimels is seeing is the move from analog to digital controls. “And there is a lot of work being done to improve operator training and security,” he said.
Photo courtesy Babcock & Wilcox
Older plant operators have to vigilantly monitor balance-of-plant (BOP) systems, from welds, piping and seals to concrete floors. Nuclear power plants are quite literally springing a leak almost every day and companies with an eye on this market are expanding their capabilities.
Areva recently teamed up with Day & Zimmermann to offer engineering, construction and maintenance services to U.S. nuclear utilities and opened a new $6.5 million research facility to analyse corrosion issues at U.S. nuclear power plants.
During lifecycle extensions and upgrades, there may be parts such as valves that are no longer supported by N-stamp manufacturers. Tyco Flow Control is one company that is working to provide nuclear grade products for these applications.
“There is a wide variety of ways to define the whole after-market service and maintenance piece required in this industry,” said Patrick Decker, Tyco Flow Control president. “We see tremendous growth opportunty.”
Burying Yucca Mountain
The Obama administration made it clear last year that it does not support the Yucca Mountain repository. After pulling most of the project’s funding, President Barack Obama called for a “blue ribbon panel” to recommend options for spent nuclear fuel.
Nuclear waste is currently being stored safely at reactor sites around the U.S. The problem is, since passage of the Nuclear Waste Policy Act of 1982, when the U.S. DOE promised to remove spent fuel from nuclear plant sites starting in 1998 and ship it to a centralized repository, utilities have been paying quarterly fees to the DOE’s Nuclear Waste Fund—a total of about $25 billion at this point.
“We would support completing the license activities associated with the geological repository at Yucca Mountain,” said Bryan Dolan, vice president of nuclear plant development, Duke Energy. “The entire industry has invested a significant effort down this path, the site was chosen as the selected site and is a very good geological repository.”
More than 70 utilities have filed suit against DOE, although little in the way of damages has been paid and DOE has rejected the idea of suspending fee collection.
“Yucca Mountain is the best place for a long-term permanent repository for spent nuclear fuel,” said Jim Miller, president and CEO, Southern Nuclear Operating Co. “Yucca Mountain is currently the subject of a lot of challenges but they haven’t changed the Nuclear Waste Policy Act and the DOE still has the legal obligation to accept spent nuclear fuel and they’ll just have to take their blue ribbon panel and the other studies they will do and devise a plan on a going-forward basis.”
Some good ideas have surfaced to resolve the spent fuel policy dilemma. The federal government’s role could be modified, with the states becoming more active; monies from the Nuclear Waste Fund could be transferred to an escrow fund that a new government corporation would administer.
“We think a public corporation should assume responsibility for used fuel management, something that can operate effectively outside the politics of an organization like the DOE,” said Dolan.
In the meantime, dry cask storage is the best option when used fuel pools are full.
“We have a solution—interim storage onsite or even in a centralized location, that’s perfectly safe and can be fairly long-term,” said Michael Kansler, president and chief nuclear officer, Entergy Nuclear (recently retired). “If you’re talking 100 years, 150 years, dry cask storage is fine and that gives you plenty of time to look at the science of storage and figure out what’s the best option.”
The general consensus is it’s politics holding us up, not technology.
“It is not a technological issue, it’s not a safety issue,” said George Vanderheyden, president and CEO, UniStar Nuclear Energy. “All over the world people know how to store used nuclear fuel and there are many places in the world where they know how to reprocess used fuel, because 95 percent of it is recyclable. Our country just hasn’t made that decision.”
For the time being, a national policy on nuclear waste management remains elusive, but that’s not a deal breaker for the next generation of nuclear power plants.
“Some time in the next 120 to 130 years the DOE and Congress have to decide how they want to handle ultimate waste storage,” said Steve Winn, CEO, Nuclear Innovation North America LLC (NINA), a partnership between NRG and Toshiba. “It’s not something that factors into the decision on whether to build the plant or not.”
Unfortunately, when we do come to a decision, it will still take decades to put the plan into place.
To Build or Not to Build
Despite strong government support for new nuclear power plants, progress for the expected nuclear new build has stalled. Cost is the chief reason the U.S. is not yet taking part in the global nuclear renaissance.
Most industry analysts think that new nuclear plants will be needed to meet carbon-free energy goals, but Exelon CEO John Rowe is not convinced that building new plants is the best choice for his company. Exelon operates the largest fleet of commercial nuclear reactors in the U.S. and the third largest in the world.
“Exelon plans to add 1,300 to 1,500 MW of zero-emission nuclear power through uprates over the next eight years,” said Rowe. “Not only will this build long-term value for the company, but it will displace up to 8 million metric tons of carbon emissions. Exelon 2020 indicates that these investments offer far better returns than building a new nuclear plant.” Exelon 2020 is the company’s program to reduce greenhouse gases.
Because financing a multi-billion dollar nuclear project is next to impossible, DOE loan guarantees were designed to give the first wave of new plants a push-start.
“It’s my firm belief that without a federal loan guarantee there literally would not be any new nuclear being pursued in this country,” said UniStar’s Vanderheyden.“It’s become very clear to us given what’s going on in the greater economy...that private equity has no interest in investing in this project right now and the financial markets are not able to support a nuclear energy facility at this stage.”
Energy Secretary Steven Chu would like to double the loan guarantees but the current program is already “… entangled in bureaucratic disputes and bickering in Congress,” said former New Mexico Senator Pete Domenici in December. “I fully support Secretary Chu’s recommendation to double the size of the loan guarantee program, and I believe we could go even further, but such a pronouncement won’t have much impact if we can’t even execute the present loan guarantee program in a timely fashion.”
Sticker shock for first-wave nuclear projects continues to threaten new build projects. Price escalation issues cost several senior-level people at CPS Energy their jobs last November—including the general manager and deputy general counsel. CPS Energy, San Antonio’s municipal utility, is a 50-50 partner in the South Texas Project expansion plan with NINA/NRG. Toshiba raised cost estimates for the project to $13 billion.
Securing skilled manpower to build these mammoth projects is another concern.
“Finding the right expertise in the craft and the engineering and the construction management is going to be a chore because those guys are few and far between,” said Entergy’s Kansler.
UniStar secured a project labor agreement with the building and construction trades in the AFL/CIO in April 2009, all the major unions necessary to build the Calvert Cliffs project.
“The unions have made commitments to us that they will build this plant in the most efficient way possible … and are guaranteeing us that they will bring the skills and workers from anywhere in the country necessary to build this project,” said Vanderheyden.
New construction timelines range from post-2020, when Kansler said Entergy might be starting construction, to UniStar’s plans to begin onsite preparation in 2010, with full-blown construction anticipated for 2012. NINA/NRG’s Winn said they are hoping to pour safety concrete by early 2012. Southern Nuclear’s Miller said construction has already begun on Vogtle 3 and 4.
New nuclear would certainly pump a lot of money into the economy.
“In round numbers, it will be about a $14 billion capital investment in Georgia, with 3,000 construction jobs and about 800 permanent workers when we’re done, so if you are looking for a stimulus package, all you’ve got to do is look at Vogtle 3 and 4,” said Miller. Interestingly, Miller said the project is not dependent on getting a loan guarantee to go forward.
Major nuclear companies are investing in America. The Areva Northrup Grumman facility in Newport News, Va., will create about 550 new jobs; Shaw and Westinghouse are building a facility in Louisiana; and Alstom has invested $200 million in its Chattanooga, Tenn., facility, creating about 350 new jobs.
Winn calculated that assuming a 40-year license life plus a 20-year life extension, the last of the existing nuclear fleet will be offline in 2053. With today’s larger units, he said 70 new units would be needed just to replace the old. Unfortunately, at some point it may be too late for us to start building.
“The U.S. could be left in a place where it cannot pursue nuclear energy because the rest of the world has taken all the resources,” said Vanderheyden. “I worry about that a lot because the debate keeps on going and the timelines keep on moving out and this is something we must do and we must do quickly.”