Natural gas markets in North America had a tumultuous year in 2008. This contrasted with the relative stability of 2007. In early 2008, the market tightened and prices moved up. In the summer, supply area spot prices went much higher than in the past, then decreased through the rest of the year to end lower than at the start of the year. This report examines current conditions and trends in the U.S. natural gas markets. Key market elements examined include prices, consumption, production, imports, and infrastructure. Expectations about the future, as reflected in recent official forecasts, are also incorporated here. Natural gas remains an important and environmentally attractive energy source for the United States and supplied approximately 24% of total U.S. energy in 2008. Domestic supply has recently increased significantly. New developments in Alaska increase the likelihood that a pipeline from the North Slope will proceed, although uncertainty remains regarding this undertaking. The natural gas industry continues to attract capital for new pipeline and storage infrastructure to link shifting loads and supply sources. In 2008, liquefied natural gas (LNG) imports decreased 54% from the record levels of 2007, decreasing already low utilization factors at import facilities. The Federal Energy Regulatory Commission (FERC) approved two more major import terminals in 2008. Given the generally adequate functioning of natural gas markets, congressional attention may address development of new supply sources (such as deep shale gas), unexpected price volatility or behavior, or import and other supply issues. In the longer term, industry pressure for increased access to public lands for exploration and production may continue as a policy concern. This report reviews key factors likely to affect market outcomes. These factors include weather, the economy, oil prices, and infrastructure development. Table A -1 to Table A -6 (in Appendix A ) present selected highlight statistics that illustrate current market status. Briefly, important developments in natural gas markets during 2008 include the following: Domestic natural gas production increased to 20.5 trillion cubic feet, the most since 1974. Hurricanes Gustav and Ike reduced Gulf of Mexico production but did not affect market prices significantly. There was an unusual price pattern in the first half of 2008, with citygate (delivered) prices lower than Henry Hub spot prices. Citygate prices have seldom exceeded Henry Hub prices. The natural gas spot price at Henry Hub peaked on July 3, 2008, at $13.32 per million Btu and declined to under $6 by end of year. During the 2007-2008 heating season (October to March), average wellhead prices increased more than 30%, according to the U.S. Energy Information Administration (EIA) estimates. Natural gas for power has reduced seasonal variation in use because gas-for-power peaks in summer, versus the total natural gas use peak in winter. The power generation sector used more natural gas than any other sector in 2008 and 2007. Storage levels towards the end of the 2007-2008 heating season dropped below five year averages. In the first storage report after the 2007-2008 heating season, working gas storage was at 1,234 billion cubic feet (Bcf) – the lowest level since April 30, 2004. However, as of December 2008, working gas storage was at 2,840 Bcf. LNG imports in 2008 dropped 54% from the 2007 record level of 77.1 billion cubic feet. The future outlook is uncertain. FERC approved 2 import facilities in 2008, with an import capacity increase of 2 billion cubic feet per day. Natural gas infrastructure development continued to advance, with more pipeline and storage projects successfully completed in 2007 and more underway in 2008. Industrial gas use had some growth in 2008, continuing increases since 2006. Unlike the global oil market, natural gas markets remain generally regional, with global trade in LNG growing. For the most part, North America has a continent-wide market that is integrated through a pipeline network that connects the lower-48 states, the most populous provinces of Canada, and parts of Mexico. Prices throughout this integrated market are influenced by demand (which may be influenced by weather, economic conditions, alternative fuel prices, and other factors), supply, and the capacity available to link supply sources and demand loads (transmission and distribution systems). The U.S. natural gas market is the major component of the North American natural gas market. It accounts for about 81% of North American consumption and about 70% of North American supply. The key price point in North America is Henry Hub. Henry Hub is a major pipeline hub near Erath, Louisiana, that is used as the designated pricing and delivery point for the New York Mercantile Exchange (NYMEX) gas futures contracts and other transactions. The price difference between other locations and Henry Hub is called the "basis differential." When there is spare capacity available to move natural gas from Henry Hub, or the Gulf of Mexico region in general, to the relevant price point area, the basis differential tends to be low, approximating the costs of fuel used to move the gas to the location. When capacity availability is tight, basis differentials can grow because the driving force can become the value of the natural gas at the delivery point, rather than the cost of getting the natural gas to that point. Natural gas prices also incorporate costs for distributing the gas from the wholesale marketplace to retail customers. These rates are generally determined by state regulators and involve both (1) the approval of costs and rates of return and (2) the allocation of costs among customer classes (e.g., residential, commercial, industrial firm, industrial interruptible). Although the North American natural gas market remains a distinct regional market, it is connecting to a global gas marketplace through international LNG trade. Oil prices still affect U.S. natural gas prices and this evolving relationship is discussed later in this report. The key elements of the market are prices, consumption, and supply. This section provides highlights from recent market developments relating to these factors. The price stability of 2006 and 2007 ended in 2008. Early 2008 prices increased at a faster pace than in 2007. According to EIA figures, spot prices at Henry Hub increased about 70% from January 1 to July 3, 2008, peaking at $13.31 per million Btu (MMBtu). The price then decreased to $5.83 per MMBtu by the end of December 2008, ending the year about 28% below the start-of-year price. (See Figure 1 for price graph.) The U.S. Energy Information Administration reports producer price data for its wellhead price series. During the 2007-2008 heating season (October to March), EIA estimates the average wellhead price increased more than 30%, to $8.06 per MMBtu. The highest monthly value was $10.52 per MMBtu in June. The EIA citygate price series reflects the unit prices delivered to consuming areas. The average U.S. citygate price increased $1.03 to $9.15 per thousand cubic feet (mcf) from 2007 to 2008. From 2006 to 2007, LNG import prices continued to decrease, from $7.19 per mcf to $7.07. (EIA full year 2008 LNG price data are not yet available.) At the retail level, average U.S. residential natural gas prices were $13.52 per MMBtu in 2008, with a high of $19.74 in July. This average was about 5% increase from 2007. The average commercial price was $11.76 per MMBtu, an increase of about 6% from 2007. Industrial prices increased about 25% to $9.61 per MMBtu. Yearly totals are not yet available for natural gas sold for electric power; as of September 2008, prices had increased 25% versus September 2007 however. (See Figure 2 for price chart.) The spot price of natural gas is a key indicator of the price that producers or LNG importers are receiving for spot sales in the major producing area of the Gulf of Mexico. From there, the gas generally moves to markets to the north (e.g. Chicago), to the east (e.g. New York), or around the Gulf (e.g. Florida). This transmission to market generally leads to a transport cost add-on and a higher price at the delivery point. Since the Henry Hub spot price was first reported in 1993 until 2008, this price has exceeded the EIA citygate (delivered price) in only eleven months (see Figure A -1 in Appendix A ). In the first half of 2008, the Henry Hub spot price exceeded the EIA reported citygate price in three consecutive months (April, May, and June). The spot price at Henry Hub appears to have increased quickly in the first half of 2008, and this price at Henry Hub (a supply area price benchmark) actually exceeded the EIA estimated average citygate (the "delivery points" in consumption areas) price. CRS has found no discussion of this price anomaly in market monitoring documents from that period. One possible explanation for this anomaly is that the citygate price includes multi-month contracted-for supplies that would include natural gas from earlier months when prices were lower than the current spot price. Greater production from shale areas near markets or storage gas withdrawal could be other explanations. Total U.S. consumption of natural gas grew almost 1% from 2007 to 2008, according to EIA. Power sector use of natural gas decreased about 2.8% in 2008. Commercial and residential sectors grew more than 3% each and industrial use (without lease and plant use) increased 0.3%. The power sector led end-use consumption for the first time in 2007 and maintained its position as the sector using the most gas in 2008. Power and industrial use were essentially equal for 2008. ( Table 1 shows the consumption data.) U.S. natural gas supply comes from domestic production, pipeline imports, imported LNG, and net withdrawals from storage.