Which power technologies will dominate?
David Walls is a director, John Higgins is a director and Steven Tobias is a managing consultant in Navigant Consulting Inc.’s Energy Practice. Contact Walls at firstname.lastname@example.org.
U.S. power-plant construction tends to follow fads. In the 1960s and early 1970s, the fad was large, sub-critical coal plants. In the late 1970s and early 1980s, it was nuclear plants, although no one could agree on a standard design. In the 1980s, the trend was to not build any plants but instead enter into long-term PURPA-based contracts. In the 1990s, the industry turned to gas turbine combined-cycle (GTCC) plants, and the “dash to gas” began (see Figure 1).
Identifying these trends is easier than determining the primary drivers and issues that contributed to them. Was market growth the primary driver? Fuel price and availability? Policy and regulatory issues (e.g., the Clean Air Act, investment tax incentives)? Lowest installed cost? Lowest levelized cost of electricity? Or, was the utility industry guilty of a group-think mentality driven by common planning processes, selection criteria and assumptions?
Understanding how these drivers affect power-planning decisions can help utilities predict generation-construction trends in the future and avoid getting caught in a group-think trap.
In recent years, natural-gas additions have declined from their peak in 2002, when regions experienced excess power-generation capacity and natural-gas prices began to rise. The price of natural gas for electric-power generation increased from $2.38 per MMBtu in 1998 to $4.44/MMBtu in 2001 (the point at which orders for GTCC plants began to decline) and peaked at $8.21 per MMBtu in 2005.1
As natural-gas prices increased, utilities and investors began searching for alternative generating technologies. Low-cost coal appeared promising and orders for coal-fired power plants started to rise. Orders for steam turbines for new coal power plants increased from below 1,000 MW/year from 1994 through 2002 to nearly 6,000 MW in 2006 (see Figure 2). Once again, coal appeared destined to be king.
As of May 2007, utilities and other power producers had announced plans to build more than 150 new coal plants.2 However, as plans for growth in coal progress, the industry is seeing an increasing number of cancellations, and development of new projects has slowed to a crawl. Coal-fired power plants are facing increased opposition on a number of fronts. Environmental advocates concerned with criteria pollutants, looming greenhouse-gas (GHG) regulation, and increasing material and construction costs have significantly limited the number of actual coal projects moving toward construction.
This trend is evinced by the recent cancellation of several key coal-fired power projects, including Florida Power and Light’s 1,960-MW Glades plant, one of the 800-MW twin units for Duke Energy’s Cliffside plant, eight of TXU’s 11 planned units, and similar announcements by power producers in Kansas and Oklahoma.3
While the future of conventional coal power plants does not look as promising as it did just a short time ago—due primarily to environmental concerns, higher than expected coal prices, public opposition and rising construction costs (see “Sticker Shock,” p. 56)—project sponsors increasingly are interested in clean-coal technologies. As the cost of these technologies becomes more competitive, the industry likely will see a trend toward integrated gasification combined-cycle (IGCC) and other advanced coal technologies. However, without demonstrated commercial successes and more specific plans for CO2 sequestration, new coal-fired power plants of any type likely won’t comprise a significant share of power-plant orders.
The last two U.S. nuclear power plant additions were Comanche Peak 2 (Texas, 1993) and Watts Bar 1 (Tennessee, 1996). No commercial nuclear reactors are under construction in the United States. However, nuclear-industry advocates have been discussing its re-emergence for years, and several factors would suggest the next energy trend may in fact be nuclear power plants. New nuclear plants would increase energy diversity with no air pollutants or greenhouse-gas emissions, which could make it the favored technology under various carbon regulation frameworks. Furthermore, the Energy Policy Act of 2005 (EPAct) provides an eight year Production Tax Credit of 1.8 cents per kWh for up to 6 GW of new nuclear capacity built before 2021, and the EPAct Title XVII loan-guarantee program might help the industry obtain affordable financing for nuclear plants (see “Hot Potato Policy”).
As a result, utilities and independent power producers once again are considering new nuclear plants, with more than 30 applications for combined construction-and-operation licenses expected between 2007 and 2009.4 Project-cost estimates vary widely for these plants. For example, the South Texas Project’s costs, initially estimated at $2,037 per kilowatt, may reach as much as $4,000/kW based on increasing material and construction expenses, possibly jeopardizing the proposed project.5
Some experts estimate even higher per-kilowatt costs for new nuclear power plants. Additionally, the issue of long-term storage of spent fuel and nuclear waste likely will require resolution before any substantial investment in new nuclear projects.
A report issued by Moody’s on Oct. 10, 2007, highlights risks associated with cost, permit requirements and politics, and forecasts only one or two new nuclear plants will be brought into the power generation capacity mix by 2015.6
Fallback Options: Gas and Renewables
Traditionally, gas-fired power capacity has the lowest total installed cost compared with other generating technologies, but has higher operating and maintenance costs—deferring any cost risk and passing it to the market. Although higher natural-gas prices have led to a decline in the number of recent GTCC projects, natural-gas projects are filling the gaps left by recently delayed coal projects.7
To supply new GTCC projects, additional natural-gas import capacity will be required. More than 40 LNG terminals are in various stages of development across the United States.8 If just one-quarter of these projects are completed, the increased import capability into the United States will enable supplies of natural gas for power generation at more competitive prices.
Although the order volume placed for GTCC power plants between 1997 and 2001 most likely won’t occur again in the next 15 years, GTCC will continue to be one of the key options for new power-generation capacity.
Also, after spending many years on the horizon, renewable energy now is cost-competitive with conventional power generation technologies. At the state and national levels, renewable energy is benefiting from discussions about energy diversity, reduced pollution, and, in particular, GHG emissions offsets.
In recent years, renewable energy has become the fastest growing source of new power-generation capacity in the United States. The windpower market in particular has shown tremendous growth, increasing at an average 24 percent annual rate between 1997 and 2006, with total generation capacity at 9,149 MW in 2005 and 11,603 MW in 2006.9
Several factors are driving this growth, including declining wind-turbine installation costs, available financial incentives (e.g., federal production tax credits), the high cost of competing fuel sources, and significant interest from private investors looking to provide equity and debt financing for renewable energy projects.
Satisfying the renewable portfolio standards (RPS) already established in 28 states could require more than 110 GW of installed capacity by 2030 (see Figure 3). Additionally, a national RPS requirement would build upon state targets, although continuing policy debates make predicting the outcome impossible.
Meeting future RPS requirements will spur development primarily of wind, solar and biomass facilities. But similar to conventional generation technologies, renewable energy options each face their own challenges. Solar technologies are intermittent and limited by high capital cost. More significant quantities of wind, also intermittent, will require new transmission lines to bring power generated in remote locations to load centers. Biomass is limited by the availability of low cost and reliable fuel sources (see “Biomass Fuel Foibles”), while many of the best hydro opportunities already have been exploited. Also, hydro power is often complicated by environmental challenges, making any significant new hydro plant additions unlikely.
Based on the myriad issues facing the electric utility industry, GTCC plants likely will continue to be the dominant form of new capacity over the next 15 years, supplying more than 50 percent of new capacity. This amount probably will be limited by natural-gas cost and availability over the coming years. Renewable energy capacity will continue to grow in importance and could account for 21 percent of new capacity additions or more, based on a national RPS or regulations limiting GHG emissions. Coal will supply a smaller portion (20 percent) of additions relative to recent expectations, with GHG regulations likely paring this percentage even further.
Nuclear capacity could comprise up to 5 percent of new capacity additions, but that will depend significantly on federal loan guarantees or other subsidies to offset the current risk premium.
Given the scenarios outlined above, the future U.S. power industry may find itself heavily reliant on natural gas and renewable energy. Under most scenarios, these technologies offer the lowest risk and are likely to face the least opposition (see Figure 4).
On the other hand, developments in public policy and generating technologies are difficult to predict. Coal might return as a dominant form of new power-generation capacity, and a nuclear surge might result from budding climate-change policies and growing energy-security concerns. While neither appears likely in the next 10 to 15 years, stranger things have happened.
1. The increase in the price of natural gas in 2005 was due in large part to the active Atlantic Basin hurricane season in the third quarter of 2005.
2. Shuster, Eric, “Tracking New Coal-Fired Power Plants: Coal’s Resurgence in Electric Power Generation,” National Energy Technology Laboratory. May 1, 2007.
3. Cassell, Barry, “Tampa IGCC becomes fourth Florida coal project to bite the dust,” SNL Interactive, Oct. 04, 2007.
4. “Expected New Nuclear Power Plant Applications,” Nuclear Regulatory Commission, Updated Oct. 01, 2007.
5. Lindsay, Mark, “MarketWeek: Analysts wonder how much NRG's proposed nuclear project will cost,” SNL Interactive, Sept. 28, 2007.
6. Barber, Wayne, “Moody’s sees high risk in building new nuclear generation capacity,” SNL Interactive, Oct. 10, 2007.
7. Example: Cassell, Barry, “Florida PSC unanimously rejects FPL application for coal-fired Glades project,” SNL Interactive. June 05, 2007.
8. “FERC: Liquefied Natural Gas (LNG) in the US.,” Federal Energy Regulatory Commission, accessed Oct. 9, 2007.
9. “AWEA Wind Power Projects Database,” American Wind Energy Association, Accessed Oct. 9, 2007.