By Brian Schimmoller, Contributing Editor
Buoyed by stronger balance sheets, and facing emerging concerns such as dwindling reserve margins and climate change, the power industry is stepping back into the sunlight from its self-imposed hibernation. Leading the charge are TXU and NRG Energy. Both companies have announced ambitious growth programs, featuring large capacity buildout campaigns and heightened attention to operating performance. On the surface, the initiatives are similar, but dig a litter deeper and significant differences emerge.
TXU’s efforts are primarily tied to the challenges it faces in Texas, where strong demand growth could drive estimated reserve margins from almost 15 percent in 2007 to 5 percent in 2011 without additional capacity. Because Texas is dependent on natural gas-fired generation for more than 70 percent of capacity, diversity is a key element. While development over the next five years is dominated by coal, plans for 5 to 15 years out include wind and nuclear as well. TXU’s 9 GW near-term coal plant buildout is based entirely on coal, with nine of the 11 units relying on supercritical steam technology, a decision that has ruffled some feathers because it overlooks the potential environmental advantages associated with integrated gasification combined-cycle (IGCC) technology.
TXU capably defends its decision to defer a commitment to IGCC until 2011 or beyond, citing its unproven capabilities on Texas lignites and Powder River Basin coals; higher projected electricity production costs; and longer constructions times. A fourth point – whether IGCC technology provides a better “carbon alternative” – highlights a leading difference between TXU and NRG. While NRG’s 10 GW “Repowering” program is heavily weighted toward coal and solid fuels as well – 4,050 MW of solid-fuel capacity (2,250 MW of which will be IGCC), 2,800 MW of gas, 2,700 MW of nuclear and 450 MW of wind – it reflects a higher level of confidence in IGCC technology.
NRG also espouses a corporate conviction that carbon constraints are on the way. “While some forward-thinking executives have taken a stand, the broader utility view, as expressed by its lobbying organization, can best be described as ‘See no carbon, hear no carbon, speak no carbon,’” NRG President and CEO David Crane said in remarks to the Merrill Lynch Global Power & Gas Leaders Conference in New York in September.
It’s tempting to boil down the differences between NRG and TXU to the following statement: NRG believes public opposition to coal-fired generation will coalesce, compelling generators to install carbon capture and sequestration equipment, while TXU believes near-term power demand – in Texas at least – will trump opposition and enable capacity growth without carbon capture.
Such simplification, however, ignores the regional dynamic at play. While NRG is pushing gasification technology, and has already proposed an IGCC plant in response to a resource request from the New York Power Authority, the one solid fuel plant NRG has planned for Texas will be a supercritical pulverized coal unit. And while TXU has consistently acknowledged the future likelihood of CO2 regulations, is it mere coincidence that its strongest statements on CO2 were issued in association with its Phase 2 expansion plans outside Texas? [In November, when TXU announced development plans for 7 to 14 GW of capacity outside Texas, it committed to making its supercritical reference plants carbon capture ready and to investing up to $50 million in an energy venture fund that will develop the next generation of clean power generation technologies.]
This is not a criticism of either company. Regional dynamics play a vital role in business decisions, and can quickly tip the project scales from viable to unnecessarily risky. NRG has apparently determined that IGCC is more viable in New England and New York than in Texas and Louisiana. Interestingly, NRG attributes a higher success probability to IGCC (67 percent) than to other solid fuel (50 percent) technologies in its repowering matrix, a position diametrically opposed to that of TXU, at least over the near term.
The time horizon represents another critical difference. TXU’s coal plants in Texas are slated to enter commercial operation by 2010 to meet electricity demand, imposing significant pressure on major equipment delivery and construction schedules. The first of NRG’s IGCC plants is not due on-line until 2011 or 2012, providing a larger cushion for this less-mature technology.
Further, based on enormous disparities in cited capital costs for supercritical and IGCC technology between TXU and NRG, one party may be badly out of the market. TXU is basing its reference supercritical coal plants on capital costs of $1,100/kW, with expectations that $850-900/kW may be possible through aggressive offshore sourcing. NRG, on the other hand, is projecting capital costs for supercritical technology at about $1,600/kW (and IGCC at about $2,000/kW). In light of Duke Energy’s late November announcement that expected capital costs for the Cliffside Station had increased 50 percent, to $1,875/kW, which end of the spectrum is more likely? That question is open to debate. Financial institutions may view NRG’s estimates as the more credible, but if carbon dioxide regulations come into force and TXU can deliver capture-ready supercritical plants within its cost projections, NRG’s plants may be tremendously overpriced.
In the end, then, while TXU and NRG’s growth initiatives differ, both reflect characteristics increasingly common in the power industry: greater utilization of renewables, but with an explicit recognition that renewables will not be enough; renewed commitment to coal as a stable, low-cost component of the generation mix; optimism for nuclear power, to provide baseload electricity and reduce the industry’s emission footprint in a carbon-constrained world; and, last but not least, despite the fungibility and ubiquity of electricity, the recognition that the power industry remains a regional business. Billions of dollars in investment hinge, in part, on regional differences in technology preference, support of brownfield development, attitudes toward global climate change, and capital cost projections.
Such differences may lead to dramatically different results. Depending on the direction taken by the power generation market and CO2 regulations, one developer may encounter “the best of times,” while the other may endure “the worst of times.”