Natural gas markets in North America remained relatively stable compared to oil markets in 2007. The situation has tightened and prices have regained some upward momentum in 2008. 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. Its share of the power generation market has grown. Domestic supply has remained stable and even increased in recent months. New developments in Alaska increase the likelihood that a pipeline from the North Slope will proceed. The natural gas industry continues to attract capital for new pipeline and storage infrastructure. Liquefied natural gas (LNG) imports hit a record level in 2007, even as import facilities continue to have low utilization rates. Weather and the economy remain important factors in natural gas prices, as well. Given the generally adequate functioning of natural gas markets, congressional interest in the near term is likely to focus on unexpected price volatility or importation (or other supply) issues. In the longer term, industry pressure for increased access to public lands for exploration and production is expected to continue receiving congressional attention. This report reviews key factors likely to affect market outcomes. These factors include weather, the economy, oil prices, and infrastructure development. Tables A1 to A4 (in the Appendix) present selected highlight statistics that illustrate current market status. Briefly, important developments in natural gas markets include the following: The growth in natural gas for power generation has contributed to increased consumption and reduced seasonal variation in use because gas-for-power peaks in summer, versus the total natural gas use winter peak. In 2007, for the first time, the power generation sector used more natural gas than any other sector. The first quarter 2008 average spot price at Henry Hub increased 20% from the first quarter 2007 to $8.92 per thousand cubic feet (mcf), versus a 6% year-to-year increase from 2006 to 2007. During the 2007-2008 heating season (October to March), average wellhead prices increased more than 30%, according to EIA estimates. Storage levels towards the end of the 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—the lowest level since April 30, 2004. This may indicate that slack in the supply side is decreasing. The United States had record LNG imports in 2007, and increased LNG imports appear likely. Natural gas infrastructure development continued to advance, with many pipeline and storage projects successfully completed in 2007 and more underway in 2008 (including LNG import facilities). Industrial natural gas use had a small rebound in 2007. 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 69% of North American supply. The key price point in North America is Henry Hub. Henry Hub is a major pipeline hub in Erath, Louisiana, that is used as the designated pricing and delivery point for the New York Mercantile Exchange (NYMEX) gas futures contract 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). Although the North American natural gas market remains a distinct regional market, it is increasingly connecting to a global gas marketplace through international LNG trade. Oil prices still affect U.S. natural gas prices and this relationship is changing. The key elements of the market are prices, consumption, and supply. This section provides highlights from recent market developments relating to these factors. Prices remained fairly stable between 2006 and 2007. Early 2008 prices have increased at a faster pace than in 2007. According to EIA figures, average spot prices at Henry Hub increased about 6% between 2006 and 2007. (See Table 1 for price data.) The U.S. Energy Information Administration (EIA) reports producer price data for its wellhead price series. This price remained stable from 2006 to 2007, decreasing by $0.01 to $6.39 per mcf in 2007 (average). During the 2007-2008 heating season (October to March), EIA estimates the average wellhead price increased more than 30%, to $8.29 per mcf. The EIA citygate price series reflects the unit prices delivered to consuming areas. The U.S. average citygate price decreased $0.49 to $8.11 per mcf from 2006 to 2007. Complete import price data for 2007 are not yet available from EIA. From 2005 to 2006, LNG import prices decreased 11.6% to $7.14 per mcf. At the retail level, average U.S. residential natural gas prices were $13.01 per mcf in 2007, with a high of $16.65 in July. This average was a 5.4% decrease from 2006. The average commercial price was $11.31 per mcf, a decrease of 5.7% from 2006. Industrial prices decreased 4.6% on average to $7.58 per mcf. Natural gas sold for electric power use increased prices 2.8% to average $7.30 per mcf. See Table 2 for these data. Power sector use of natural gas increased most rapidly in 2007, followed by the weather-sensitive residential and commercial sectors. Total U.S. consumption of natural gas grew 6.5% from 2006 to 2007, according to EIA. Gas-for-power led the sectoral growth, increasing 10.5%. Residential consumption increased about 8.2%, primarily due to colder weather than 2006. The commercial and industrial (without lease and plant use) sectors also had modest increases in consumption, reversing drops in use in these sectors for 2005 to 2006. The power sector led end-use consumption for the first time in 2007. Table 3 shows these consumption data. U.S. natural gas supply comes from domestic production, pipeline imports, imported LNG, and net withdrawals from storage. Both domestic and imported supplies increased between 2006 and 2007. Dry gas production increased by 4.3% from 2006 to 2007, to 19,278 billion cubic feet (Bcf). This reflects the increase in drilling activity in response to price increases, as indicated in the natural gas rig count. The U.S. natural gas rig count has trended upward since 2002. In 2002, the average monthly rig count was about 600. Recent data show the count at approximately 1,500. The U.S. natural gas reserve base increased recently. EIA reserves and production data indicate the latest reserves-to-production ratio (2006) is 11.4, an increase from the prior year's ratio of 11.1 and 2000's ratio of 9.2. In 2007, U.S. consumers received most of their supply, 84%, from domestic production. The domestic supply has shifted from shallow Gulf of Mexico to deep Gulf of Mexico and unconventional sources, in the Rocky Mountains and elsewhere. As these new resources grow in importance, industry pressure for increased gas leasing of on- and offshore federal lands is likely to be a continuing issue. Net imports (pipeline and LNG) increased almost 10%, to 3,793 Bcf. Imports via pipeline from Canada increased 5%. LNG imports increased more than 32%, growing from 584 Bcf in 2006 to 771 Bcf in 2007. Table 4 show these data. In 2007, the available spot LNG supplies were sometimes bid away to European terminals for higher prices. Nevertheless, new U.S. LNG infrastructure went into service in early 2008 and still more received approvals from the Federal Energy Regulatory Commission (FERC). To compete effectively for supply in the global LNG market, natural gas prices at the delivery points may have to increase further to attract LNG deliveries. Location of import facilities is an important factor in the value of landed LNG. EIA forecasts U.S. imports of 1,080 Bcf LNG for 2008, including regasified LNG from Mexico's Costa Azul terminal in Baja California. In addition, an LNG import facility in eastern Canada largely focused on exporting to the United States is expected to enter service in 2008. There are several trends under way in natural gas markets of interest to policy makers. They include: a decrease in seasonal demand swings a growth in gas-for-power use a small rebound in industrial use of natural gas a growing international trade in LNG continuing progress in natural gas infrastructure development.