World Oil Prices in IEO2006 

Figure Data

In previous IEOs, the world crude oil price was defined on the basis of the average imported refiner acquisition cost of crude oil to the United States (IRAC), which represented the weighted average of all imported crude oil. Historically, the IRAC price has tended to be a few dollars less than the widely cited prices of premium crudes, such as West Texas Intermediate (WTI) and Brent, which refiners generally prefer for their low viscosity and sulfur content. In the past 2 years, the price difference between premium crudes and IRAC has widened—in particular, the price spread between premium crudes and heavier, high-sulfur crudes. In an effort to provide a crude oil price that is more consistent with those generally reported in the media, IEO2006 uses the average price of imported low-sulfur, light crude oil to U.S. refiners. 

Liquefied Natural Gas: Market Developments in China 

Pressed by shortages of peak-load capacity and growing concern about pollution from coal burning, China has begun to turn to cleaner burning fuels—in particular, LNG—for electricity generation. There is great potential for development of LNG within China, and a number of regasification facilities are currently under construction or planned, especially in the eastern part  of the country, where access to coal resources is limited (see map below). In large part, however, the growth of China’s LNG market may be limited by competition with coal. 

Rapid growth in China’s manufacturing output increased its electric power demand by about 15 percent in 2004.^a In summer 2004, China saw a 30-gigawatt nationwide power deficit, with 24 provincial grids forced to restrict power supplies,^b prompting a sharp increase in demand for fuel oil (estimated at 170,000 barrels per day) to generate electricity, in addition to the existing 300,000 barrels per day used for electric power generation annually.^c The power shortage is expected to continue through 2006, but demand for fuel oil in the power sector is expected to fall in the second half of 2006, when new LNG projects come online. China’s LNG imports are expected to increase from 1 million metric tons in 2006 to between 20.9 and 25.9 million metric tons in 2015.^d 

Several LNG projects are underway in China. Construction of the country’s first LNG regasification terminal, in Guangdong Province, has been completed, and the facility is scheduled to receive its first cargo in June 2006 from North West Shelf Australian LNG. A second LNG terminal, in the city of Xiuyu in Fujian Province, is scheduled for completion by 2008. At present, the Chinese government is reviewing more than 10 additional LNG proposals up and down China’s coastline (see table). 

Plans to build LNG terminals on China’s northeast coast developed quickly in 2004, accelerating when negotiations between China and Russia over a major proposed natural gas pipeline project that would bring natural gas from Irkutsk, Russia, to northern China were stalled. Lack of progress in the negotiation resulted mainly from China’s insistence that the price of natural gas from Russia be indexed to domestic coal prices in China. LNG pricing in Asian contracts traditionally has been linked to the price of oil, not coal, but China has been attempting to index LNG and pipeline natural gas imports to the price of domestic coal. 

The three LNG projects most likely to be built after the Guangdong and Fujian projects are in Shanghai, Ningbao (Zhejian Province), and Qingdao (Shandong Province). Economic growth and industrial output in the two provinces are the highest in China, making it possible for their regional governments to purchase relatively expensive imported natural gas. Shanghai is both China’s largest city and its largest port, and it is one of the most prosperous cities in China. The municipal government of Shanghai is planning to phase out use of coal in the city over the course of the next 10 years. At present, Shanghai consumes more than 46 million short tons of coal per year, providing 70 percent of its energy needs.^e Shandong is rich in coal, but the provincial power companies still have coal production and deliverability problems, and there is a serious lack of available peaking capacity.^f 

Most of the areas in China targeted for LNG developments have large coal-fired power plants, and the government is carefully considering the issue of natural gas and coal prices charged to the power plants. In 2004, the cost of coal from northern China was around $1.92 per million Btu, and the average cost of natural gas from China’s west-to-east pipeline was $4.22 per million Btu. On average, coal-fired electricity generation in China costs $34 per megawatthour and natural-gas-fired generation $44 per megawatthour.^g Potential users of natural gas in the electric power sector estimate that prices for natural gas must be in the range of $3.30 to $3.60 per million Btu to compete economically with coal.^h The expected price of natural gas from the Guangdong LNG terminal is $2.80 per million Btu, including freight, plus $0.40 per million Btu for regasification.ⁱ

All the Chinese provinces have some coal resources; however, those in the east and southeast, which account for one-half of China’s total GDP, contain only 17 percent of its coal resources.^j As a result, more than 60 percent of the coal produced in China is transported by rail over an average distance of about 340 miles, under a coal pricing scheme that used to be determined by the central government.^k The Chinese government has gradually relaxed its pricing control on coal since 1992, and coal prices for power generation have become negotiable. Currently, coal prices are determined by a mix of negotiated contracts between  state-run producers and large end users, and the price of coal imports. Domestic coal prices are typically $5 to $7 per short ton higher than the international market price of high-quality steam coal, which makes imports more attractive.^l 

Concerns about pollution from electricity generation in China have also led to higher coal prices, as the government has incorporated a number of environmental controls to limit pollution from power generation. In October 2003, the State Environmental Protection Administration (SEPA) raised the fee assessed to generators for sulfur dioxide emissions by a factor of ten and applied the same fee for the first time to nitrogen oxide emissions, in addition to banning the construction or expansion of coal-fired plants in many large cities. 

China’s attempts to index its import contracts for LNG and pipeline natural gas to the price of domestically produced coal may or may not succeed. If they do, China will certainly be able to accommodate more imports of natural gas.

China’s Proposed LNG Imports, 2005-2015  (Million Metric Tons per Year)  Printer friendly version Year  Haikou LNG (Hainan)  Shenzhen LNG (Guangdong)  Xiuyu LNG (Fujian)  Ningbao LNG (Zhejian)  Shanghai LNG  Rudong LNG (Jiangsu)  Qingdao LNG (Shandong)  Hebei/ Tianjin LNG  Dalian LNG (Liaoning)  Beihai LNG (Guangxi)  2005  —     —  —     —     —  —  —  —  —  —  2006  —    3.9  —     —     —  —  —  —  —  —  2008  —    3.9  2.6     —     —  —  3.0  —  —  —  2010  1.0    9.9  2.6    4.0    4.0  3.0  5.0  —  —  —  2012  2.0  12.9  2.6    4.0    4.0  3.0  5.0  2.0  3.0  —  2015  3.0  12.9  5.0  10.0  10.0  5.0  5.0  3.0  6.0  3.0

^aCambridge Energy Research Associates, “China Market Commentary, Spring 2005: After the Peak” (April 15, 2005), web site www. cera.com. 
^bWorld Market Research Centre, “China: Urban Centers in China To Face Power Crunch” (April 7, 2005), web site www. worldmarketsanalysis.com.
^cPersonal correspondence with Fatih Birol, Chief Economist, International Energy Agency (April 26, 2005), web site www.iea.org. 
^dK. Wu, L. Wang, and F. Fesharaki, “China’s LNG Imports: Delayed Terminal Projects and a Less Bullish Demand Outlook,” FACTS Gas Insights, No. 4 (January 2006), web site www.factsinc.net. 
^eC. Bergersen, “Country Profile: China Electric Power Overview” (February 16, 2005), web site www.platts.com/coal/resources. 
^fA.J. Minchener, “Coal in China” (July 2004), web site www.iea-coal.org.uk.
^gD. Hurd, “Global LNG: Key Themes and Choices” (April 21, 2005), web site www.db.com. 
^hK. Wu and F. Fesharaki, “Natural Gas Pipelines and LNG Terminals in China: An Update,” FACTS Gas Insights, No. 46 (March 2005), web site www.factsinc.net. 
ⁱPetroleum Intelligence Weekly, No. 5 (July 2004), web site www.EnergyIntel.com. 
^jFACTS Inc., Gas Databook I (Honolulu, HI, 2005). 
^kChina National Bureau of Statistics. 
^lA.J. Minchener, “Coal in China” (July 2004), web site www.iea-coal.org.uk.

Current Developments in Gas-to-Liquids 

The relatively high world oil prices of the past several years have made gas-to-liquids (GTL) a more attractive option for monetizing stranded natural gas reserves. Currently, only South Africa and Malaysia have commercial GTL operations; but new projects have been proposed for Algeria, Australia, Egypt, Iran, Nigeria, and Qatar. Proposed plant sizes range from 20 to 160 thousand barrels per day of liquids output. In addition, Russia has significant potential for GTL production because of its plentiful and often remote natural gas reserves. 

Natural gas use as a feedstock for GTL operations is reflected in the IEO2006 projections for industrial natural gas consumption. In regions where natural gas markets are less developed, GTL may represent a significant share of industrial or even total natural gas use. For example, in 2003, natural gas for the Bintulu GTL plant in Malaysia, with an original design capacity of only 12.5 thousand barrels per day, accounted for almost 2 percent of industrial sector natural gas use and 1 percent of total natural gas consumption in non-OECD Asia excluding China and India (”Other Non-OECD Asia”). In Africa, natural gas use for GTL operations in 2003 represented some 6 percent of industrial and 3 percent of total natural gas consumption. 

Figure Data

In IEO2006, significant quantities of GTL production by 2030 are projected only for Russia, Africa, the Middle East, and Other Non-OECD Asia. For all but Russia, which already consumes large amounts of natural gas in its industrial sector, natural gas use for GTL has potentially significant effects on industrial and total natural gas consumption. The addition of a single 140 thousand barrel per day GTL plant, consuming  0.5 trillion cubic feet of natural gas per year, would represent an increase in total natural gas consumption over 2003 levels: 3 percent in Russia, 6 percent in the Middle East, 9 percent in non-OECD Asia, and 18 percent in Africa. In all but Russia, projected GTL operations in large part drive industrial sector natural gas demand in the reference case. The projected growth rates for industrial natural gas use in the Middle East, non-OECD Asia, and Africa are among the highest in IEO2006 (see figure).

Technology Choices for New U.S. Generating Capacity: Levelized Cost Calculations

When decisionmakers are faced with the need for new capacity, several technology types can be considered. One of the tools used by decisionmakers is a levelized cost calculation, which incorporates all the expenses and revenues associated with a project over its lifetime. The costs include investment in plant construction, interest charges on funds borrowed to finance the construction, capital outlays after the plant has started operating, taxes, operations and maintenance costs, and fuel costs. The levelized cost calculation balances those expenses against estimates of revenues over the life of the plant, including proceeds from power sales and a desired rate of return on the investment. The streams of expenses and revenues are expressed as a real annuity, where the payments are assumed to be for the same dollar amount in every year of the plant’s life.

Levelized Cost Comparison for New Generating Capacity in the United States (2004 Dollars per Megawatthour) Printer friendly version Cost Element Technology Coal Natural Gas Wind Nuclear Capital 30.4 11.4 40.7 42.7 O&M   4.7   1.4   8.3   7.8 Fuel 14.5 36.9   0.0   6.6   Totala 53.1 52.5 55.8 59.3

Levelized cost comparisons give investors one basis for choosing a technology. In addition, other factors are considered, such as the operating characteristics of different technologies. For example, intermittent technologies like wind and solar produce less power over time than do coal, nuclear, or combined-cycle natural gas plants. There may also be tradeoffs between capital costs and fuel costs. Nuclear generators are expensive to build, but their fuel and operating costs are low; combined-cycle plants are far less expensive to build, but their fuel and operating costs are much higher.

An illustration of levelized cost calculations for a typical coal plant, an advanced combined-cycle natural gas plant, a wind plant, and a nuclear plant to be built in the United States is shown in the table below. The cost estimates are based on assumptions used in EIA’s Annual Energy Outlook 2006, expressed in 2004 dollars per megawatthour. For U.S. plants that would begin operation in 2015, the combined-cycle plant is the least-cost option and the nuclear plant the most expensive.