The Energy Information Administration (EIA), in its October 2006 Short-Term Energy and Winter Fuels Outlook (STEWFO), provided encouraging news for residential natural gas consumers. Their 2006-2007 winter heating bills were projected to decline by an average of about $119 per household, or 13%, from 2005-2006 levels. This anticipated decline in consumer costs is related to market conditions in 2006 that have been quite different from those observed a year ago. This report analyzes the key factors affecting prices in the U.S. natural gas market, including consumption, production, reserves, and storage levels. The current environment of declining prices is compared to last year, as well as near-term future projections that continue to show a tight market and high prices. The U.S. natural gas market is a regional market, drawing supplies from domestic sources as well as imports, via pipeline, from Canada. In addition, a small part of domestic supply is imported in the form of liquefied natural gas (LNG) which is part of a small, but growing, world market. As a result of the regional nature of natural gas markets around the world, prices may differ across the various regions. Within the U.S. market, different groups of consumers pay different prices for natural gas. Residential, commercial, industrial, and electric power consumers are the largest groupings, with transportation uses the newest category. Cost of distribution, as well as scale of quantity purchased, determine price paid, although in some cases state regulatory commissions can determine some prices. In general, residential consumers constitute the largest customer base (over 62 million in 2004), purchase the smallest quantities per customer, and pay the highest prices. Electric power generators consume large quantities, and pay the lowest per unit price. Historically, industrial consumers were the largest consumers of natural gas, although their aggregate consumption has declined in recent years. On the supply side, in 2005, domestic production provided about 83% of consumption, imports via pipeline from Canada accounted for approximately 16%, and LNG, mostly from Trinidad, accounted for about 2%. Production represents a draw from the reserve base. In the U.S., the reserve base, measured by the reserve to production ratio, has been growing, increasing from 8.8 years in 1997 to 10.4 years in 2004. Storage is an important component of natural gas supply because while production tends to be relatively constant throughout the year, consumption tends to peak during the winter heating season (November through March) as home heating use rises and tends to moderate in the other seasons. For this reason, the industry injects gas into storage facilities to prepare for winter heating season demand peaks. In recent years, the industry has established a target of over 3 trillion cubic feet (tcf) of gas in storage for this purpose. While price is an important determinant of consumption and production in the market at the aggregate level, the weather is perhaps even more important in consumption decisions by residential consumers. The primary use of natural gas by residential consumers, home heating, tends to be quite price inelastic; consequently, the onset of cold temperatures causes demand peaks largely independent of the level of prices. Aggregate consumption of natural gas in the United States for the first seven months of 2006 was 4.1%, or 551 billion cubic feet (bcf), lower than the comparable period in 2005. Table 1 shows how this decrease in consumption, for comparable time periods, was divided between the consuming market segments. Residential consumption declined by the largest amount in both percentage and volume terms. Commercial demand also decreased by more than the average for the market. Industrial demand decreased by more than the average for the market, but this decline may be part of a long term fall in industrial demand of approximately 19% over the period 2000 to 2005. Consumption by electric power generators is a derived demand in the sense that their demand for natural gas is dependent on, and derived from, consumers' demand for electric power, which has been growing. The use of natural gas in transportation vehicles is a very small, but growing portion of the total market. The key factors in explaining the observed reductions in natural gas consumption over the past year are price and the weather. Although these two factors affect all market segments, their relative effects vary across the market segments. Average U.S. residential natural gas prices were $14.64 per thousand cubic feet, (mcf) in the winter of 2005-2006, a peak price for the decade, 57% above the average residential price for the period 2000-2005, and an increase of 32% over the previous winter heating season. Probably more important, the winter heating season in 2005-2006 was also warmer than normal for the United States as a whole, as measured by population weighted heating degree days. These two factors, warm weather, coupled with high prices, likely accounted for a large portion of the reduced demand observed in the residential sector. Commercial demand is, like residential demand, largely used for space heating. As a result, this sector's consumption is also likely to be relatively insensitive to changes in price, and quite sensitive to weather variations. Industrial consumption of natural gas is likely to be more sensitive to price variations, and less sensitive to weather variations than residential or commercial consumption. Natural gas is used in production processes both as a raw material, for example, in the nitrogenous fertilizer industry, and as a source of process heat, as in the steel industry. Many of the domestic industries that use large quantities of natural gas cannot easily pass cost increases on to final consumers because they face competition from overseas producers who have access to cheaper sources of natural gas. As a result of this inability to remain competitive in the face of increased natural gas prices in the United States, some firms have either ceased domestic production, or moved their facilities overseas, accounting for the decrease in U.S. industrial natural gas consumption. The electric power sector's consumption of natural gas depends on the demand for electricity, which itself is dependent on the price of electricity and the weather in the short term. Consumption is also affected by the primary fuel choice for the mix of power generators in the supply base, fuel switching capability, and how production is divided between baseload and peak power generation. The use of natural gas in transportation vehicles is largely for commercial purposes, for example, city bus fleets. As such, this sector's consumption might be expected to be relatively insensitive to the price of natural gas as well as weather conditions. Aggregate dry natural gas production in the United States for the first seven months of 2006 was 2.8%, or 307 bcf, lower than in the comparable period in 2005. Production data for the first seven months does not, however, provide a complete picture of the 2005-2006 winter fuels market from the producer's side, because the effects of hurricanes Katrina and Rita were felt largely in the fourth quarter of 2005, and into 2006. The hurricanes disrupted natural gas production and deliveries from the Gulf Coast region by about 6.7 bcf per day, or about 11% of average daily U.S. consumption. The effect of the hurricanes on natural gas production continued to be important during the first quarter of 2006 and persisted through the summer of 2006. Imports of natural gas come mainly from Canada through pipelines. Comparing the period January to July 2006 and 2005, imports from Canada declined by about 3.5%, a smaller decline than that of U.S. consumption of natural gas. LNG imports into the United States come mainly from Trinidad, which supplied almost 70% of U.S. consumption, as well as Nigeria, Algeria, and other nations. However, the quantities are small in the aggregate. LNG supplied only 2.8% of total U.S. natural gas consumption in 2005. Over the first seven months of 2006, imports of LNG have declined by 2.7%. Consumption of natural gas is governed by two weather related cycles; one somewhat predictable, the other less so. The first cycle is yearly; average consumption rises during the winter heating season (November to March), and is lower in the spring and fall seasons. The second pattern, less predictable as to timing, is that extremely cold weather conditions yield sharp increases in consumption. Taken together with a relatively constant rate of production, these patterns create the need for natural gas storage capacity. The typical yearly pattern is that stored gas is withdrawn during the winter heating season, and replenished with storage injections during the following spring, summer, and fall seasons. A relatively new development in this process is that summer storage injections can be interrupted by periods of extremely hot weather. As peak electric power generating capacity has become fired by natural gas to a greater extent, the summer gas injection season can become disrupted by peak electricity demand conditions. The industry ideally plans to carry an average natural gas storage inventory of approximately 3.3 to 3.5 tcf at the start of the winter heating season. The estimated maximum storage capacity in the United States is 3.6 tcf. On December 1, 2006 the amount of natural gas in storage was 3.406 tcf, which was 232 bcf more than at the comparable time in 2005, and 282 bcf above the five year average quantity in storage at the end of November 2006. The EIA estimates that stored natural gas will amount to 1.69 tcf by the end of the 2006-2007 winter heating season. This level of stored gas is above the five year average. The high levels of stored gas attained as the winter 2006-2007 heating season begins suggests that the market is well supplied, unlikely to experience physical shortages, and is likely to experience moderate price levels. A number of prices are monitored by analysts of the natural gas industry. There is a spot market price set at the Henry Hub in Louisiana, and a futures market price set at the New York Mercantile Exchange (NYMEX) in New York City.