IGCC … The Struggles with New Technology Adoption

By Tim McClive, Director, Power Markets & Forecasting, Pace

THE DEVELOPMENT OF INTEGRATED Gasification Combined Cycle ("IGCC") technology as a promising new generating source has been debated for several years, and the reason why is obvious. Continued use of coal addresses energy-independence and national security concerns, and the potential for IGCC plants to incorporate carbon capture and sequestration ("CCS") is an advantage to conventional coal plants with regard to reducing CO₂ emission levels that are contributing to global warming concerns. However, the prospect for the technology to become a real factor in meeting generation growth over the next decade is very speculative, at best. The problem is that cost uncertainty has made financing of IGCC projects difficult, if not impossible. This is frustrating developers and putting this promising technology at significant risk.

Technology and Background

IGCC offers numerous potential technology advantages. Using a controlled chemical reaction, coal is combined with water and oxygen to produce a synthetic gas, and the by-products (acid gases, particulates and other pollutants) are removed prior to combustion for disposal or for use in construction and industrial processes. The syngas is combusted in an efficient combined cycle power plant to produce electricity, and as much as 90% of the carbon dioxide (CO₂) produced can potentially be captured and sequestered, either for commercial purposes such as injecting it into old oilfields to increase oil output (tertiary oil recovery) or by pumping it to storage deep underground or undersea.

With the benefit of more than ten years operating experience, a new fleet of IGCC is poised to start construction in the U.S. and Europe. As of early 2007, nearly three dozen IGCC projects with a combined capacity of nearly 20 GWs were in or past the proposal stage in twenty-five states in the U.S. Of these, eight with a combined capacity of 4 GWs, were already permitted or conducting feasibility studies and seven with a combined capacity of 5 GWs, had applications pending. However, none are under construction and the additional fifteen projects, with combined capacity of 11 GWs, have been postponed or cancelled.

Cost Estimates Have Risen

Project proposals as recently as 5 years ago were estimated to cost as little as $1100-$1300 per kW for engineering, procurement, and construction ("EPC") without CCS. Owners' costs (land, engineering services, insurance, facilities, fuel inventory, spare parts and others) would add about 10%-20% to the cost. But capital cost projections have risen dramatically in recent years, with recent estimates for total costs ranging from $1700 to $3550 per kW, depending on technical and fuel specifications and without carbon capture or sequestration. The low end of the range is from a study by the Department of Energy's National Energy Technology Laboratory ("NETL"), while other estimates based on actual proposed projects are typically above $2,500/kW. The increase in IGCC construction costs is no surprise, U.S. prices for various construction and industrial materials have risen rapidly from 2001 to 2006 (iron and steel up 78%, cement and concrete up 29%, heat exchangers and steam condensers up 36%) due in large part to rapid economic expansion and construction activities in China and India. These underlying increases in input costs affect the entire industry, but appear to have a strong impact on IGCC. The unknown factor is whether these price increases are cyclical or permanent. Clearly, power plants to be built within the next few years will be markedly more expensive than expected when first proposed, and the cost of IGCC, even without CCS, is not competitive at this time with pulverized coal-based technologies. But it is uncertain whether plants to be built 10 to 20 years from now will face continued escalation or whether these growth rates in costs will abate.

Perhaps more significant is that the early public excitement about IGCC was often missing an important element … the additional cost of CCS. Notwithstanding questions about where the CO₂ would be pumped and whether that form of storage would be "permanent," CCS raises the overall capital cost of a power project. Further, its associated internal demand for energy decreases the generating plant's overall fuel efficiency by significant amounts, whether the CCS is added to a coal IGCC, a pulverized coal plant, or a natural gas combined cycle plant. For example, reports that were recently released by EPRI ¹ and by the NETL ² estimate that CCS will increase the installed costs of IGCC by about 32% to 50%, depending on the technology selection and type of coal burned. Also, the fuel utilization efficiency will decline by about 15% to 30%. Non-fuel O&M costs are also higher when capture and sequestration are added. In short, capture and sequestration inflate both the fixed costs and the short-run marginal cost.

Regulatory Approvals and Financing Have Emerged as Major Hurdles

Utilities and independent power developers face significant hurdles obtaining project financing. First, the traditional process for justifying and securing regulatory approvals for cost recovery has been disrupted in many regions by market and regulatory developments over the past couple of decades, making it difficult for utilities to obtain cost-recovery guarantees.

*Utility divestitures and departures from the generation sector in restructured markets in New York, New England, and elsewhere have broken the link between generation supply and the regulated company.

*FERC's Edgar ³ standards for reviewing purchase power agreements between utilities and affiliates and its authority to grant or deny market-based rate authority have had the unintended consequence (or intended, as some contend) of discouraging utilities from building their own capacity.

*Multi-party planning or integrated resource planning (IRP) is re-emerging in some jurisdictions, with its concomitant "analysis paralysis" that can delay investment decisions for years.

*Regulators have shown reluctance, or political inability, during the past few years to put their approval on anything that may increase prices in future years.

Further, Wall Street is bearish on IGCC projects for numerous reasons, and without that support it may be very difficult to build this fleet of new plants.

*IGCC is regarded as an unproven technology. Less than a handful of plants currently operate in the U.S. and Europe, and second generation demonstration projects will need to be built and successfully operated to justify the removal of the technology risk premium.

*There is little likelihood that EPC contractors will provide viable turnkey contracts with performance guarantees.

*Capital cost expectations are very expensive on a $/kW basis and the implied capacity payment required to support a traditional project financing is significant. Currently, market pricing does not support an IGCC build case.

*Regulatory uncertainty about cost recovery and lingering operational performance, start up, and maintenance issues translate into cash flow concernsespecially if utilities are unable to secure long term regulatory assurances for cost recovery and/or developers are unable to secure long term power purchase agreements with distribution utilities.

*Government guaranty and tax incentives to support IGCC development are unclear.

*Rating agencies have not been fully supportive of IGCC.

So, with rising costs and dwindling financing, will IGCC be too expensive to be developed as a significant technology in meeting new demand? Considering the normal inclinations of regulators to look for the lowest cost option and of the finance community to minimize risk, that prognosis may get even stronger. But that is probably the wrong question. Control of CO₂ emissions and EPC cost escalation have and will continue to increase the costs of virtually every technology. On a relative basis, higher cost for IGCC will result in raised rates but it is not clear that this will kill its long term development. We should consider whether the nation can realistically meet its electric power needs without coal, and if it can figure out how to get past the current roadblocks to IGCC.

New Generation Capacity will be Needed and Coal will be Necessary

The demand for new generation in the U.S. continues to grow. Pace currently projects long term growth to average about 1.5%-2.0% per year in the U.S., a rate that will require the addition of 200-300 GWs of net new generation capacity over the next 20 years. What can meet that demand?

*Natural gas will likely have a role. It is attractive as a fuel source for power because of the relatively low capital costs for peakers and natural gas combined cycle plants, its status as a proven technology, a carbon footprint that is only about half that of coal and oil, and its relative ease of permitting. But it has issues fueled by its high and volatile commodity prices and it is unlikely that it can replicate the heady growth experienced during the past decade, when it comprised 90% of new capacity added in the U.S. The run-up in gas prices since 2002, coupled with the fact that natural gas was on the margin in most on-peak hours in many regions, contributed largely to high and volatile power prices. This created a highly charged and politicized atmosphere that often verged on the edge of national and/or local proposals for regulatory or legislative actions to reduce our reliance on gas for power. The lesson learned from over-reliance on one fuel will probably not be forgotten for several years. In addition, the U.S. has shifted from being a net producer to a net importer of natural gas, a development that may feed policy debates about reducing reliance on natural gas.

*Oil will likely not have a role. Oil-fired generation has not been added in any appreciable amounts since the 1970s, and its value as a transportation fuel and the nation's quasi-effort to wean ourselves of imports will not allow oil to be used for electric power.

*Nuclear may have a role but critical questions remain about the disposal of spent fuel and whether the U.S. has an appetite for a major building program that hasn't occurred since the 1970s. Despite robust growth overseasthe Nuclear Energy Institute reports 31 plants under construction, two-thirds of which are located in China, India, Russia, and Ukrainethere has not been a single new operating license issued in the U.S. in decades. And, while a handful of nuclear operators have begun the process of applying for site licenses, the prospects for new nuclear are far in the future. Pace currently expects that the first new nuclear generator will not come online until 2015 at the earliest, by which point close to 100 GWs of new non-nuclear generation will have already been built. Furthermore, the perception that nuclear power has low operating costs may come under more scrutiny. There has been little expansion in the uranium mining sector for several years, and this tightening supply picture has become evident as spot prices for nuclear fuel have climbed to $140/pound in the past two years, after staying in a range of $10-$20/pound for more than a decade. This supply picture may also have a long-term edge to it, as industry watchers start to talk about the possibility of uranium mining hitting a "Hubbert" style peak in the near future and experiencing declining finds and yields. Potential shortages of uranium would drive a shift to breeder reactors and fuel reprocessing to optimize fuel and waste in the cycle, which in turn would open another protracted national debate with no clear conclusion.

*Hydroelectric and non-hydroelectric renewables, such as wind, solar, tidal, and geothermal, have an intrinsic value of not involving a fuel cycle once they are up and running and can operate on a carbon-free basis. But the era of large hydroelectric projects ended decades ago and existing hydroelectric sites are occasionally shut down and dismantled to accommodate watershed and fishery concerns. Wind, solar, geothermal, tidal, and numerous other renewable sources have heretofore made but a small contribution to the power supply and concerns over the technologies' costs versus market prices for electricity continue. Further, the reliability of supply issue continues to linger, despite improvements in unit capital costs and capacity factors. In the absence of continued production tax credits, many renewable projects would never be completed.

With these limitations to generation technology options, there may be no alternative but to build coal-fired generation capacity.

IGCC Should be Included in the Nation's Plans for the Future

Environmental goals, economic goals, and national security goals seem to be proceeding on a collision course in the national debate over energy, and this is manifested in the debate about IGCC where each goal can lead to different conclusions about investment in IGCC. But power plants have a long usable lifetime, typically much longer than the lifetime of most regulatory or legislative initiatives, so decisions need to be made with a long view. In fact, the history of the power sector is replete with regulatory policies, legislative mandates, and investment trends that seem to be immensely imprudent under some circumstances and the epitome of sound planning under other circumstances.

Growing concerns about a greenhouse gas buildup, increasingly believed to be directly linked to global warming, and a steady drumbeat of political and media messages, have put supporters of fossil-based power generation on the defensive. In particular, due to a conventional coal-fired power plant's significantly higher CO₂ emissions over gas-fired plants, many regulators and investors have concluded that it would be imprudent to build new coal. At the same time, industry analysts, regulators, utility companies, and customers have repeatedly acknowledged that demand for electric power will continue to grow directly with our economy, and new power plant construction will be needed.

Resistance by regulators and investors is based on short-term concerns, but the deliberations and decisions to be made in the next few years will need to include recognition that today's high costs of building new plants may be temporary, if market prices for steel, concrete, and industrial equipment abate, and that technology roll-outs typically follow an adoption curve that results in greater product performance and lower fixed costs over time. The IGCC plants that are currently operating are basically test units, and IGCC will face more years in this demonstration phase. However, the long-term case for IGCC remains strong. Economic viability will come as the technology matures and as capital costs stabilize. The social benefits of reduced CO₂ emissions and the strategic benefits of using the nation's abundant coal reserves are compelling.

Until IGCC technologies are proven on a commercial basis, a viable public policy solution may be to encourage partnerships to include municipal or public power agency financing, government guarantees, long term power purchase agreements from the utility, early recovery of construction costs, and other methods that have been proven over time to facilitate the construction of large projects. The large risk that is faced now is that the short-term concerns of regulators and investors will defer action for so long that the next decade's opportunities to address our economic, environmental, and national security objectives will be lost.

¹ Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site. EPRI, Palo Alto, CA: 2006. 1014510

² Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, Bituminous Coal and Natural Gas to Electricity, Final Report, May 2007, DOE/NETL-2007/1282

³ See Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 at 62,167 (1991) (Edgar). Edgar establishes criteria to ensure that no affiliate should receive undue preference during any stage of an RFP for the purchase of wholesale power: the competitive solicitation process should be open and fair, the product or products sought through the competitive solicitation should be precisely defined, evaluation criteria should be standardized and applied equally to all bids and bidders, and an independent third party should design the solicitation, administer bidding, and evaluate bids prior to the company's selection.

Gasification is not a new technology. Gas was manufactured from coal as early as the late 18th century. Gasification and liquefaction of coal were extensively developed and employed around the world in the 20th century for production of transportation fuels, fertilizers, chemicals, and CO₂. By some estimates there are well over one hundred gasification plants in operation that are used primarily for gasifying coal, petroleum coke, natural gas, and refinery wastes.

Coal-based IGCC is a more recent development. Five plants in the U.S. and Europe, with an average capacity of 270 MWs, brought online between 1994 and 2000 by Tampa Electric, PSI Energy, Premcor, ELCOGAS, and Nuon, are in operation. In addition, three test plants, with average capacity of 130 MWs were brought online between 1984 and 1997 by Sierra Pacific, Dow Chemical, and Texaco. These latter three test plants have since been decommissioned. While these plants have not reached an 85% availability design goal, most were able to achieve an availability of 75%-80% within about five years of operation.