When people in Northern Minnesota talk about Excelsior Energy’s planned coal-gasification power project, many speak in the past tense.
“There would have been a huge economic impact, with the influx of construction workers for a number of years,” said Peter McDermott, an economic development official in Grand Rapids, speaking to a Minnesota Public Radio reporter.
The 1,200-MW project encountered a major barrier in April 2007. An administrative law judge recommended the Minnesota Public Utilities Commission (PUC) deny Excelsior Energy’s proposed power-purchase agreement (PPA) with Xcel Energy, saying it would pose “an unreasonable cost to Xcel and its ratepayers.”
For its part, Excelsior continues working toward a 2010 startup date, in hopes the PUC either will disregard the recommendation or suggest acceptable changes to the PPA. In the meantime, Excelsior’s opponents are planning the project’s funeral.
“It’s dead, dead, dead,” says Carol Overland, a regulatory lawyer in Red Wing, Minn. “The ALJ’s opinion pulled the plug, and we are waiting for the inevitable.”
Meanwhile, at a foundry in Hokkaido, Japan, steelworkers have completed the first forgings for a new reactor vessel to be installed at a proposed nuclear power plant on Maryland’s Chesapeake Bay.
Groundbreaking remains a long way into the future, but partners in the UniStar project are optimistic. They expect to apply late this year for a construction and operating license (COL) for a new 1,600-MW reactor at the site of the existing Calvert Cliffs nuclear plant. If all goes well, the project could begin construction as soon as 2011.
“Constellation Energy is moving aggressively,” says Tom Christopher, CEO of AREVA NP Inc., which is designing the new Calvert Cliffs project. “This will probably be the first new reactor built in the United States.”
The Excelsior and UniStar projects represent only two views on a complex picture. Other nuclear projects are faltering, and some integrated gasification combined-cycle (IGCC) plants are surging ahead.
But these two projects also illustrate the relative positions of nuclear and climate-friendly coal development in America. In short, both approaches to building new base-load power capacity are struggling out of the starting gate. Both face complex challenges in terms of technology deployment, regulatory treatment and construction cost factors. Both depend on strong public support to overcome siting and permitting hurdles, and they depend on public funding to make them financially viable.
However, some important differences distinguish nuclear plants from any type of coal plant—most notably the fact that any new nuclear plant will take at least eight years to complete, if everything goes absolutely right. Coal plants can be delivered in much less time, generally three to five years.
Yet in the race to build the next fleet of base-load power plants, nuclear seems to be gaining ground on coal. The reasons are complex, but they come down to this: Coal is no longer cheap.
“The economics have changed dramatically,” Christopher says. “Coal prices and rail costs have risen. That’s the number-one driver for new nuclear power in the United States.”
Environmental factors also are impeding coal’s progress. Virtually every major pulverized-coal fired power project faces public opposition on environmental grounds, and these concerns have driven some project sponsors—including FPL, TXU, Duke, and Sempra—to scale back or cancel plans to build new pulverized-coal plants. Further, uncertainties about future carbon regulation have increased risks and costs for new coal-fired projects.
“With the last 18 months of discussions around global warming, coal has become more of a challenge,” says Jim Suciu, president of global sales for GE Energy. “A lot of people are having difficulty permitting coal plants, and coal will see more carbon pressure. Nuclear doesn’t have that element.”
Technology companies are working to develop back-end carbon-capture systems for pulverized-coal boilers, but the process of research, development, and commercialization has only just begun. IGCC offers well-proven options for extracting carbon-dioxide from gasified coal before it is burned, and geologic sequestering appears to be a feasible option in some locations.
“Being as rational as possible about carbon removal, we found there is a huge cost advantage for pre-combustion technology,” says Lee Davis, a vice president with NRG Energy, which is developing a 680-MW IGCC project in Western New York that will include carbon-capture and sequestration systems. “Post-combustion technology has a role to play, but from an efficiency and cost point of view, IGCC and pre-combustion technology wins, hands down.”
Specifically, a recent National Energy Technology Laboratory study estimates IGCC+CCS (carbon capture and sequestration) facilities will cost about 13 percent less to build than PC+CCS, and will generate electricity 9 percent cheaper.1 (Without CCS in the equation, most analysts expect IGCC will be about 15 to 20 percent more costly to build than supercritical PC plants.)
The idea of sequestering carbon on an industrial scale, however, still is being studied, leaving coal burners with waste-disposal uncertainties that vaguely resemble the nuclear industry’s spent-fuel management problem.
“In many respects, the challenges of building climate-friendly coal plants and nuclear plants today are pretty similar,” Suciu says. “They both have regulatory risks and cost uncertainties, and they will both need a regulatory environment where cost-recovery is allowed during construction.”
In the long run, neither technology may prove to be more successful than the other at overcoming those challenges and reaching the finish line. In the meantime, power companies planning the next generation of base-load power capacity are facing the full spectrum of challenges, one project proposal at a time.
Gasification is alive and well. It’s just not living around here.
That’s not exactly true, of course. Several utilities and independent power companies are developing IGCC power projects in the United States, with interesting announcements recently from Southern California Edison and TXU’s private-equity suitors. The biggest drivers for new gasifiers, however, are not found in electric-power markets, but in industrial-chemicals and fuels markets.
“Molecules are worth more than electrons,” says Phil Amick, director of commercialization for ConocoPhillips’ E-Gas technology. “Electric-power generation will be the big market at the end of the day. But for right now, considering the generation mix in the United States, industrial gasification projects will be more widespread.”
Examples include Rentech’s plans to convert a natural-gas fed ammonia/fertilizer plant in East Dubuque, Ill., to use Illinois coal from a Peabody mine. Using the ConocoPhillips’ E-Gas technology, the facility would produce both fertilizer and transportation fuels, as well as 76 MW of electric power. Other industrial gasification projects will use coal or other solid fuels, such as petroleum coke, to produce hydrogen for use by oil refineries, and CO2 for enhanced oil recovery.
“These industrial poly-generation projects are a much better approach than central power plants,” says Dale Simbeck, vice president of technology at SFA Pacific in Mountain View, Calif. “There is tremendous potential for industrial poly-generation in Texas, California, and Alberta.”
By comparison, IGCC is moving slower than industrial gasification because base-load power supplies are not yet constrained enough in most markets, and regulators are reluctant to push IGCC plants any faster. The long-term picture for IGCC appears brighter—particularly if CCS options prove workable. But in the short term such projects face tough challenges.
Namely, IGCC proposals today must stand up against well-established base-load heavyweights already in the market: nuclear, gas-fired combined cycle, and pulverized-coal (PC) plants. Even the advent of carbon regulation wouldn’t change the economic equation for IGCC significantly for at least a few years after the regulation took effect. Existing PC plants will be able to remain competitive in the market if they offset their carbon emissions with cheap carbon credits, probably costing about $10 a ton at the outset.
“You can’t beat 300 GW of old coal units to death with a carbon-tax stick,” Simbeck says.
Thus, until the existing fleet of coal-fired plants is retired, and CCS is demonstrated to be cost-effective on an industrial scale, IGCC plants will have difficulty getting a foothold in the market. But then again, any new power plant will have a disadvantage against any fully depreciated plant. The more valid question compares IGCC+CCS with other large-scale options for climate-friendly power generation.
Comparing nuclear with any other power technology is a hazardous thing to do. No new nuclear plant has been ordered in the United States for more than 30 years, and since then the industry has gone through a painful series of setbacks – massive cost overruns, public protests and the Three Mile Island accident. And the risks of terrorism and nuclear proliferation have exacerbated security fears involving nuclear facilities.
Recent developments, however, have changed the outlook for new nuclear plants. Utilities and independent power companies are pursuing about 30 reactor projects. About a dozen are expected to file COL applications by the end of 2008, and six new plants seem likely to seek financing in the near-term future.
“We expect early site preparation will start by the late 2008 and 2009 time frame,” says Adrian Heymer, senior director of new plant deployment at the Nuclear Energy Institute. “Once the first companies get their licenses, probably in late 2010 or early 2011, they will start pouring concrete for safety structures and beginning to move components into place.”
Which companies will actually seek to break ground on a new nuclear plant in the first wave is somewhat difficult to predict. No companies have made firm commitments to build new nuclear plants. But in addition to the aforementioned Constellation, several other utilities, including Ameren, Dominion, Duke, Entergy and Southern Co., seem likely to be among the first group to move toward construction. NRG Energy also is proposing a merchant nuclear project with plans to file a COL application in 2008.
This apparent reversal of fortune for nuclear power is being driven by federal-level policy changes. Namely, the 2005 Energy Policy Act included promises of federal tax credits, schedule insurance and loan guarantees for the first new nuclear plants. And the Nuclear Regulatory Commission (NRC) is implementing a new licensing process that promises to eliminate the most deadly regulatory risks.
Specifically, the NRC has trimmed the hydra-headed monster of nuclear permitting down to a single COL application. The NRC seems eager to approve the first new reactor licenses, and standardized and certified plant designs give applicants a much better chance of cruising through the safety-review process than was conceivable in the 1970s.
However, no company has yet submitted a COL application to the NRC, and the public-review process has not begun in earnest for any of the planned reactors. Although some environmental groups have started supporting nuclear energy as a climate-friendly power source, only time will tell whether public and political sentiment about nuclear power really has improved. Given the long lead time for licensing and construction, and high capital costs, nuclear plants present unpredictable development risks.
“We’re believers in nuclear power, and we think the problems are solvable,” says Ray Spitzley, a managing director with Morgan Stanley. “But every year or two you add to a project fundamentally changes the risk/reward equation. In the seven or eight years it will take to license and build one of these things, a lot will happen that could change the viability of a project. Only the federal government can cover that risk.”
And the loan guarantees promised in EPACT have yet to materialize in a way that project sponsors can take to the bank. In May 2007 the DOE revised its draft guidelines for the Title XVII loan-guarantee program, but restrictive terms disappointed prospective borrowers. Specifically, the initial guidelines would limit the federal government’s exposure to 90 percent of the project debt and 80 percent of total project cost, leaving remaining costs to be financed at market rates. It also would require any syndicated or secondary-market debt to be subordinated to DOE’s lien – increasing the costs for commercial debt financing.
These terms are considered problematic for financing, and stakeholders are watching closely to see how the final program will be structured.
“It will have an enormous effect on the economics of new nuclear projects,” Christopher says. “With loan guarantees, the first units may be able to get 5 to 6 percent interest-rate financing, but without loan guarantees they’ll be paying 10 to 15 percent. The difference on a $3 [billion] or $4 billion loan translates into $20/MWh in production costs. It’s a big number.”
On a pure economic basis, both nuclear and IGCC plants are difficult to justify. No company today is developing either type of plant without significant public-policy support. Sponsors of nuclear projects are counting on federal lawmakers to deliver incentives promised by the Energy Policy Act, and IGCC projects rely on a portfolio of federal, state, and even local incentives (see sidebar “Funding IGCC”).
“Where utility commissions are looking hard at gasification, they are looking a little beyond the initial cost of electricity,” Amick says. “They are looking at the cost of carbon capture in later years, and trying to put together a path that considers the environmental good of the investment as well as the cost of electricity.”
The same could be said of nuclear plants, but none have gone far enough in the development process to become part of a rate case. Some IGCC proposals have come before state utility commissions, and a few are getting a warm reception on Wall Street. “IGCC had a good three- or four-year head start on nuclear,” says Caren Byrd, executive director with Morgan Stanely. While no IGCC projects have yet been financed, several are assembling a strong package of incentives and rate support.
“For IGCC projects to get built, everyone has to feel a stake in the solution,” Spitzley says. “The vendors must provide some degree of wrap, and the off-taker must bear some early-stage scheduling and performance risk.”
In this respect, IGCC has come a long way in the last couple of years, with multiple equipment vendors—Siemens, Mitsubishi, and GE Energy—offering standardized plant designs, equipment warranties, and operational support.
“We created our relationship with Bechtel and developed a standard 60-Hz IGCC product so we could get as comfortable with the technology as possible,” Suciu says. “That allowed us to guarantee the performance, the schedule and as much of the cost as possible.”
The costs of IGCC+CCS versus new nuclear plants, however, are somewhat difficult to compare, because of major uncertainties about nuclear licensing, permitting, construction, waste-management, and capital costs. Uncertainties about IGCC+CCS are significant, but they relate mostly to operating costs. Performance data for commercial-scale IGCC plants are relatively scanty, and no one knows for sure what long-term carbon sequestering will cost. Capital costs, on the other hand, are relatively well understood for IGCC and carbon-capture technology.
“IGCC projects are at the whim of commodity pricing, but it’s the normal world of construction risks,” Amick says. “It’s not like the nuclear world, where everything you do might have to be redone to satisfy changes in law at very detailed levels.”
Indeed, actual costs for nuclear power plants have proved to be notoriously unpredictable. But as sponsors of all types of construction projects have learned, prices for labor, materials and equipment have skyrocketed in recent years and likely will continue rising in the coming decade (see sidebar “Return to Cost-Plus”). In short, all cost estimates for either nuclear or IGCC+CCS plants today are speculative, and almost certainly will increase significantly over time.
“To nail down the cost you have to complete the design, do detailed construction planning and understand commodity rates and equipment prices better than you do today,” says Brew Barron, Duke Energy’s chief nuclear officer. “As you begin actually expensing these projects, you’ll have inflation on the dollars spent.”
Notwithstanding uncertainties in estimating costs, the economics of new nuclear and IGCC+CCS plants appear comparable, with nuclear power gaining the edge in operating costs.
Discussions with sources for this story suggest new nuclear plants will cost somewhere between $1,800 and $2,800 a kilowatt to build. IGCC+CCS might cost between $1,860 and $2,500/kW—roughly on par with capital costs for new nuclear plants. But on the basis of operating costs, IGCC suffers compared to nuclear power. Estimates for new nuclear generation costs range widely, between $45 and $70/MWh3 —or more, depending on the cost of financing—while generation from IGCC+CCS plants will cost about $67 to $78/MWh,4,5 and significantly higher for some projects.
None of these prices can be considered economical compared with electricity generated by today’s installed base-load fleet, which produces power for less than $50/MWh in most places. But the costs for new nuclear and IGCC+CCS compare favorably with recent gas-fired generation proposals at more than $80/MWh,6 and wind-power generation delivered to market at $70 to $100/MWh.7 Of course, gas-fired and wind-power plants don’t pose the same development risks as next-generation coal and nuclear projects, and they can be built lightning-fast by comparison.
At the end of the day, climate-friendly coal and nuclear technologies both have a role to play in the future of America’s power-generation industry. How big their respective roles turn out to be, however, will depend on power companies’ ability to manage the uncertainties of building capital-intensive, cutting-edge projects—and lawmakers’ willingness to make it worth their while by providing public funding.
Neither factor seems likely to be a fait accompli for either nuclear or coal anytime soon, leaving the next-generation power fleet effectively up for grabs.
“It’s not really a question of nuclear versus IGCC,” Suciu says. “We need to invest in a broad portfolio of technologies, including efficiency, renewables and gas turbines, and both climate-friendly coal and nuclear have to be part of the U.S. power-generation mix in the long-term. In the near to medium term, most people expect it to be a gas and wind world.”
1. “Cost and Performance Baseline for Fossil Energy Power Plants, Vol. 1: Bituminous Coal and Natural Gas to Electricity,” National Energy Technology Laboratory, May 2007.
2. Ciferno, Jared P., “CO2 Capture: Comparison of Cost & Performance of Gasification and Combustion-based Plants,” National Energy Technology Laboratory, Workshop on Gasification Technologies, Denver, Colorado, March 14, 2007.
3. “The Future of Nuclear Power: An Interdisciplinary MIT Study,” Massachusetts Institute of Technology, July 2003; http://web.mit.edu/nuclearpower/.
4. “Integrated Combined Cycle Gasification Draft Report,” Wisconsin Department of Natural Resources and Public Service Commission of Wisconsin, Docket 9300-GF-176
5. Ciferno, Jared P., ibid.
6. “PSC Staff Review and Recommendations on Generation Bid Proposals,” Delaware Public Service Commission, Docket No. 06-241.
7. “Biennial Review of the Cost of Windpower,” Northwest Power & Conservation Council, July 2006.