The USA power market is hungry for investment in both generation and grid infrastructure. In a special PEi report, Peter Howard Wertheim finds out just how important fuel choices will be in driving many of these investments.
Declining reserve margins, the need to connect the next wave of power plants, and distribution system weakness exposed during the heat waves point to the investment need in the US power industry, says a survey by Cambridge Energy Research Associates (CERA), an IHS Company and leading US advisory firm.
“With the time for large capital commitments rapidly approaching the power industry, and with fuel supply concerns, technological change and energy policy still evolving, the investment landscape remains uncertain and the survey results indicate a strong belief that investment will shift back toward the regulated side of the business with a concentration on controlling fuel risks and leveraging new technology,” said Lawrence J. Makovich, managing director of CERA’s Global Power Group. Substantial power price differentials, the need to connect remote renewable resources to grid, the need to connect the next wave of baseload generation, and to make up past underinvestment, all point to substantial increase in investment on transmission in the US for the next decade or two, Jone-Lin Wang, CERA’s senior director and head of research told PEi.
Since the electric power business is very capital intensive, this will require substantial capital for all segments: generation, transmission, distribution, and environmental retrofits, Wang added.
The industry will need at least 200 GW of new capacity by 2020, most likely a lot more depending on retirements and demand growth. It will cost $250 billion to $300 billion to build 200 GW, she estimated.
For CERA, the next wave of new power plants will be more capital intensive – coal (mostly online after 2010) plus nuclear (online after 2015) and some gas, instead of predominantly gas as was the case over the past 15 years.
The transmission segment has been picking up fast just recently. “Although investment has been stagnant for more than a decade and many obstacles remain for siting and building lines and some of the proposed projects may not get built, it is safe to say that transmission investment for the next 15 years will likely exceed $120 billion,” Wang affirms.
The heat waves last summer exposed many weak links in distribution networks, resulting in local outages. CERA’s recent survey of power executives showed that most ranked distribution as number one for future investment. Total distribution investment from now to 2020 will likely exceed $300 billion – over $20 billion a year.
Survey respondents also identified environmental compliance as an area where they will invest capital in the next five years. However, power executives are strongly pessimistic about prospects for achieving supply-demand balance in regional power markets through the next build cycle.
The lowest-ranking investment items were competitive retail assets and wholesale trading.
CERA’s survey concludes that executives are convinced that the power business will remain a hybrid mix of regulation and competition over the next ten years, and that most new capacity will be added on the regulated side of the business. Only companies pursuing competitive strategies rate merchant generation as their number-one priority, and most of them indicated plans to build natural gas generation.
Those executives with a higher proportion of regulated businesses in their portfolios predict increased regulation in the next five years, with the wholesale power segment becoming more competitive and the retail segment becoming more regulated as a result of regulators’ response to increasing fuel and environmental costs. However, power executives believe the industry will become more market driven in the long run.
Figure 1. Annual US electricity sales by sector
Fuel price influence Another survey, the Annual Energy Outlook 2006 with projections to 2030, forecasts total electricity sales to increase to 5341 TWh (See Figure 1) with the largest increase in the commercial sector, as service industries continue to drive economic growth. To meet demand, investments should create 347 GW of new capacity by 2030.
According to the outlook, coal fired and natural gas fired plants account for about 50 per cent and 40 per cent, respectively, of the capacity additions being forecasted up to 2030 (Figure 2).
Figure 2. US electricity capacity additions by fuel type, including CHP
The study highlights the fact that capacity decisions depend on the costs and operating efficiencies of different options, fuel prices, and the availability of federal tax credits for investments in some technologies.
“Natural gas plants are generally the least expensive capacity to build but are characterized by comparatively high fuel costs. Coal, nuclear, and renewable plants are typically expensive to build but have relatively low operating costs and, in addition, receive tax credits under Energy Policy Act 2005.”
Eric Markell, Puget’s senior vice president of energy resources, recently told The Bellingham Herald in Washington that in the years ahead, the nation will need to import large quantities of liquefied natural gas to keep the lights on. “The power markets in the West are being driven by the supply and cost of natural gas,” Markell said. “It’s a phenomenally costly fuel. That’s the box the West Coast is in. That’s the box the country is in.”
Nationwide, some new natural gas fired plants are built to maintain a diverse capacity mix or to serve as reserve capacity. Most are located in the Midwest and South. The Midwest has a surplus of coal fired generating capacity and does not need to add many new coal fired plants. In the South, natural gas prices are lower than the national average, and natural gas fired plants are more economical than in other regions.
As per Outlook 2006 forecasts, the largest amounts of new capacity are expected in the Southeast and the West. In the Southeast, electricity demand represents a relatively large share of total US electricity sales, and its need for new capacity is greater than in other regions.
Figure 3. US electricity power generation from nuclear sources
However, Frank Giacalone the president of Houston-based Navasota Energy warns: “The cost of fuel drives the cost of power. Better than 50 per cent of our cost is the cost of the fuel.”
Quail Run, one of two 550 MW power plants Navasota is currently building in Texas, will be fuelled by natural gas. It could be fuelled by coal at some later time if, for example, coal was being transported through Odessa on the way to a coal fired facility such as FutureGen.
In Arkansas, about 2800 forested acres (11.3 km2) north of Fulton are the proposed site for a coal fired plant that could supply up to 600 MW of electricity to Southwestern Electric Power Co. customers by 2011.
The $1.3 billion facility, announced at a recent news conference in Texarkana, is one of three plants that SWEPCO, a subsidiary of American Electric Power, plans to build to meet growing demand over the next five years, spokesman Mike Young told the Arkansas Democrat Gazette.
In the Energy Outlook 2006-2030 reference case, fuel costs account for about two-thirds of the generating costs for new natural gas fired plants, less than one-third for new coal fired units, and less than one-tenth for new nuclear power plants in 2030.
New nuclear outlook
Due to high prices for natural gas and uncertainty about how emissions from coal plants will be regulated in the future, a debate within the utility industry over nuclear power is gaining momentum. The debate has added importance because, unlike plants that burn coal and other fossil fuels, reactors do not produce gases that contribute to global warming.
The prospect is that perhaps a handful of plants will be ordered in the next few years and the Nuclear Regulatory Commission counts 27 potential reactors under consideration.
However, nuclear plants cannot replace all of the fossil fuel used in power generation because current nuclear designs cannot quickly react to changing power output requirements. Plants running on natural gas and coal, by contrast, can adjust their output over the course of a day to match demand.
In the Energy Outlook 2006 forecast, nuclear capacity increases to 108.8 GW by 2030, still maintaining its current 20 per cent share of total generation. The Energy Policy Act 2005 provides an eight-year production tax credit of 1.8 cents per kilowatt-hour for up to 6 GW of capacity built before 2021.
Figure 4. Fuel prices to US electricity generators (2004 dollars per million Btu)
Most of the sites being considered for the next generation of nuclear plants are in the south, where hot weather is pushing up power demand and the political climate is more favourable to nuclear power. Among the 15 sites where utilities are preparing preliminary plans for new nuclear units, 13 are in the southern states.
Because of the decade or more it takes to plan, design and build a nuclear plant, many utilities are pursuing preliminary plans to get more nuclear generation by 2015 to 2025.
Adrian Heymer, senior director for new plant deployment at the Nuclear Energy Institute, an industry-backed trade group in Washington D.C., said he expects a half dozen nuclear reactors to be added by 2015 and at least 20 more units to be online by 2020.
In the next 15 years electricity demand is projected to grow by 30 per cent in the Southeast, according to the North American Electric Reliability Council.
Overall, about eight per cent of the expected capacity expansion consists of renewable generating units. Of the 26.4 GW of new renewable generating capacity expected by the organization, more than 93 per cent of the capacity additions stimulated by State programmes are wind plants.