The natural gas market is composed of three major components on the supply side; producers,pipelines, and local distribution companies. The price of natural gas paid by consumers is layered,in the sense that the wellhead price paid to producers forms a baseline. Pipeline transportation costsare then added, which yields the city gate price. Finally, local distribution companies add additionalcharges to yield the prices actually paid by consumers. Consumer markets themselves are dividedinto segments, each of which tends to pay a different, in many cases a significantly different, price. Residential consumers pay the highest prices, followed by commercial, industrial, and electricityusers. Table 1 shows the relationship between these prices in recent months. The residential prices presented in Table 1 represent an increase of 7% over residential pricesfor a comparable period in 2003. The most recent EIA natural gas price data available at the timeof this report was August 2004. On the New York Mercantile Exchange (NYMEX), natural gas fordelivery in December 2004 was trading at $6.80 per mcf and January and February 2005 natural gaswas trading at over $7.50 per mcf. (1) Table 1. Natural Gas Prices Source : EIA Natural Gas Price Data, measured as dollars per mcf. Natural Gas Monthly, October,2004, Table 4, p.8. In addition to multiple prices faced by consumers, other prices are key variables for supply and policy decisions. The wellhead price of natural gas, as noted in this report, is competitivelydetermined by market forces. This was not always the case. The process of natural gas pricederegulation began in 1978 when the Natural Gas Policy Act ( P.L. 95-621 ) became law. Under theNatural Gas Policy Act, nearly all price controls were phased out by the end of 1984. (2) The spot price of natural gas is recorded at a transportation hub, the largest in the United Statesbeing Henry Hub in Louisiana, and is generally somewhat higher than the wellhead price becauseit includes some processing and transportation costs. Natural gas futures contract trading on theNYMEX establishes forward prices for natural gas, and allows market participants to hedge shortand medium term price risk. The NYMEX future price is determined by the interaction of traderswho have business interests in the real, physical natural gas market, and financial traders whospeculate on the market. Natural gas is also traded by numerous brokers and other entities forphysical delivery at a number of local markets. Interstate pipeline rates are not directly regulated and their pricing structure largely reflects open access for shippers and market pricing. The Federal Energy Regulatory Commission (FERC)monitors pipeline tariffs to assure "just and reasonable" pricing, and has intervened in a number oftariff situations. The city gate price includes the addition of these pipeline transportation charges. Residential and small commercial consumers buy gas from a local distribution company, which delivers gas from a long-haul pipeline to the customer's premises. Local distribution companies areregulated by state public service commissions, who set distribution charges. The price data in Table1 indicates that residential prices have recently been almost double city gate prices in 2004. Theprice premium paid by residential and commercial consumers reflects the high fixed cost associatedwith distribution of their supply, as well as the added cost of small volume purchases. The EIA defines effective productive capacity as the maximum production available fromnatural gas wells, allowing for limitations in the production, gathering, and transportation systems. (3) The effective capacity utilization rate (ECUR) is the ratio of actual production to effective productivecapacity. Surplus capacity is the difference between effective productive capacity and actualproduction. Figure 1 shows, for monthly data over the period 1987 to 2001, that the average wellheadpricehas stayed below $3.00 per mcf whenever the ECUR was below 90%. The data also show howupwardly volatile natural gas prices can be as the ECUR rises above 90%. The correlation betweenhigh values of the ECUR and high prices suggests that when the ECUR is above 90%, conditionsare in place that are consistent with high, volatile natural gas prices. Figure 2 shows the history of the ECUR, capacity and production since 1985. Several trendsare noticeable in the data. Productive capacity has declined since the late 1980s, but appears to haveremained stable since 1993. Actual production has trended up from 1985 to 1995 and has beenrelatively stable since then. These two trends, taken together, drove the ECUR to 90% or higherlevels for almost all of the past eight years. An ECUR in excess of 90% indicates that available natural gas output is nearly fully allocated to meeting demand. Any further increase in demand, or disruption of supply, can only be metthrough extraordinary draws on existing gas wells, increased draws from storage, or increasedimports. All of these alternatives suggest that prices for the consumer are likely to rise. If thesesources are unavailable for expansion the price could rise dramatically, and supply disruption mightoccur. As part of the market adjustment to higher prices, increased development drilling could take place, but exploration and development does not immediately result in gas on the market. The EIAestimates that there is a lag of between 6 and 18 months between an increase in natural gas pricesand an increase in developmental drilling and ultimately higher production. (4) The decliningproductivity of U.S. fields is also a factor. According to one industry observer, "it takesapproximately 2.5 times more active rig capacity to produce the same amount of gas as just eightyears ago." (5) Alternatively, when the ECUR is below90%, any requirement for additional supply canbe quickly brought to the market by increasing production from existing wells. Source : U.S. Energy Information Administration, derived from data available at http://tonto.eia.doe.gov/dnav/ng/hist/n9190us3A.htm . Figure 3 shows the history of the wellhead price of natural gas from 1973 through 2003. Again, several trends are noticeable. The first run up in prices, from 1973 to the mid 1980s was theresult of price deregulation in a market where supply was not abundant, demand-after years ofregulated prices-was strong, and oil prices were high, as a result of the Arab oil embargo of theUnited States in 1973-74, and the Iranian political upheaval of the late 1970s. Prices declined after1985-as did demand-and the United States entered a decade long period of relatively low, stableprices. During this period, use of natural gas as an abundant, cheap, clean fuel was promoted. Increasing demand, in conjunction with the supply trends shown in Figure 2 ,has resulted in theECUR remaining at, or above, 90% since 1995. These conditions set the stage for the gas priceincreases and price volatility experienced since 2000. An interesting break in the pattern of the Figure 2 data is associated with the sharp price increases of the winter of 2000-01. As can be seen in Figure 2 , the ECUR achieved very highvaluesduring this period. When coupled with the low temperatures of that winter, the result was highprices that set off a boom in exploration and drilling. While only 496 rotary drilling rigs, on average,were drilling for natural gas in 1999, that number increased to 720 in 2000 and rose to 939 for 2001. As the resulting production entered the market in 2002 (6 to 18 months later) the ECUR fell below90% in 2002 and the price of natural gas fell. (6) Thelower price, however, resulted in lowerdevelopmental drilling and set the stage for sharp price increases in the winter of 2002-03. As pricesdeclined in 2002, as seen in Figure 3 , the drilling rig count also declined, to 691. The ECUR,reflecting the lower anticipated increments to production from reduced exploratory drilling, againrose above 90%, and price increases beginning during the winter of 2002-03 followed. Drilling activity may be responding to 2003's higher prices. The EIA reported that the average monthly drill rig count for 2003 was 872, with the count running over 900 per month from June toDecember. The nine month average drilling rig count for 2004 is 1009, and has been on a path ofsteady monthly increases since January 2004. (7) Whether the recent increase in drilling activity resultsin large enough supply increases to allow the price of natural gas to fall depends on the explorationsuccess rate, the size of the fields found, and the degree to which existing producing wells showoutput declines. Any factor that increases demand or decreases supply will increase the ECUR. When theECUR is below 90% extra pressure on the market is likely to result in higher production. Once theECUR rises to 90% or above, timely increases in production are less available and pressure on themarket manifests itself as higher prices. Higher prices create incentives that eventually could causeprice increases to moderate, although new sources may require higher prices to satisfy investmentcriteria. The demand for natural gas exhibits a seasonal pattern even when the weather is normal. Figure 4 shows the typical pattern, which is characterized by seasonal demand peaks. Sinceseasonal patterns are repetitive, suppliers, attempting to accommodate consumers, accumulatequantities of gas in storage facilities in the traditional off-peak season for release during the heatingseason. Source : U.S. Energy Information Administration available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/presentations/2004/searuc/searuc_files/frame.htm If the seasonal demand pattern is accentuated by extreme weather conditions, the stored quantities of natural gas might not be sufficient, setting the stage for price increases if the ECUR ishigh. For example, as we approached the heating season of 2002-03, stored gas was at a normallevel of approximately 3 trillion cubic feet (tcf). Below average temperatures early in the winterquickly drove stored quantities down to low levels, which set the stage for the price increases thatfollowed. If the ECUR remains high, as is likely, and a cold winter weather pattern repeats, the limited amount of stored gas, as well as the unresponsiveness of both supply and demand to real time pricevariations at the consumer level, could well bring about another price spike in the winter of 2004-05. The seasonal pattern of natural gas demand is being altered by its growing use by electric power generators. Power generators expanded their demand for natural gas by 36% over the period1997-2002. The EIA expects that over the long term forecast period, 80% of new electricitygeneration will be fueled by natural gas, continuing the strong growth of the last several years. Notonly is electricity demand adding to total natural gas demand, but the pattern of peak demand mightinterfere with traditional gas demand cycles. The demand for natural gas for electricity generationpeaks in the months June through October when space heating demand from residential andcommercial customers is low, but when storage facilities replenish their stocks. As a result, it mightbe the case that the ECUR is pushed to higher levels, year round. Competition for summer suppliescould cause short falls in storage quantities, create price pressures that squeeze out price sensitiveindustrial customers, or force higher electricity rates or even shortages to the system. (8) As discussed earlier in this report, when the ECUR is 90% or above, the ability of the industry to respond to increased demand with expanded supply from existing wells is limited, causing priceto increase quickly. However, the higher prices do provide an incentive to begin the process ofdrilling new wells and exploring for new supplies. The resulting supply increase will tend to causeprice to fall as productive capacity is enhanced, reducing the ECUR. The nature of this relationship in the natural gas industry can, under some circumstances, lead to a cycle of unstable boom and bust feared by those investing in gas production. Taken to itsextreme, this could lead to chronic under-investment in gas production and stagnant supply. Higher prices for natural gas justify investment in exploratory drilling by increasing the value of the expected cash flow derived from the new production. In an efficiently operating market, asustained, marginal increase in price is supposed to elicit a marginal increase in production. Innatural gas, when the price rises, hundreds of extra rigs drill thousands of additional wells. Historical averages suggest that about 80% of these efforts will be successful and yield some newproduction. Once a well is brought into production, there is little economic rationale for notproducing at full capacity. As a result, the market moves to a condition of excess supply as newproduction begins, causing a fall in the price. The reduced price brings a disincentive to invest inexploratory drilling, which leads to a period of stable supply setting the stage for a rising ECUR atightening market balance and rising prices. A key factor in the ability of the rate of investment in exploration to affect the ECUR is the degree to which existing wells deplete, or yield declining output levels. For example, the EIAexpected that in 2003 the estimated effective productive capacity of the U.S. natural gas industrywould be approximately 57 billion cubic feet per day (bcf/d). For 2003, production was expectedto be approximately 51.4 bcf/d, leaving a surplus of 5.6 bcf/d, or about 10%. To demonstrate howthis balance depends on new drilling and expansion of capacity, the EIA estimated that 25% ofeffective productive capacity comes from wells one year old or less. The two largest suppliers ofU.S. natural gas, Texas and the Gulf of Mexico, derive 30% of their production from wells one yearold or less. If drilling were to stop in the U.S., all surplus capacity would disappear in less than oneyear. In 2001, the incentive of high prices led to 22,800 well completions that resulted in increased productive capacity. Only 17,800 wells were completed in 2002 and productive capacity declined. If, as this recent data suggests, the potential for a boom/bust investment cycle may be developing inthe natural gas industry, the result will be brief periods of low prices and plentiful supply followedby periods of high prices and potential physical shortages. (9) The measures analyzed in the EIA study of effective productive capacity only refer to resources in the lower 48 states. As the U.S. natural gas market develops, this restriction will become lessappropriate. The U.S. natural gas market is well integrated with the Canadian market. Imports ofCanadian natural gas have long been an important supply source when U.S. consumption exceededU.S. production and available stock draw down. Imports of natural gas from Canada, all viapipeline, reached over 3.7 tcf per year in 2001 and 2002, but declined to less than 3.5 tcf in 2003. Canadian gas fields, like those in the United States, may be unable to easily expand output withoutthe development of new fields. An additional source of imports might be liquefied natural gas (LNG). (10) The U.S. has fouroperational (or near operational) LNG receiving facilities with an annual operational send-outcapacity of 1.4 tcf per year after all planned expansions are completed. (11) The critical issueconcerning LNG is cost. Although the cost of a complete LNG facility has fallen substantially(30%) due to economies of scale and enhanced technology over the last decade, LNG cost is greaterthan most conventional gas from wells in the lower 48 states. (12) As a result, dependence on LNG maysafeguard the nation from physical shortage by building a new, higher, baseline price into the market. The volume of gas held in storage is a critical element in evaluating the possibility of price volatility. If storage volumes are below normal as the winter heating season begins, and the ECURis above 90%, the potential for elevated prices must be considered to be high. Notes: A weekly record for March 8, 2002, was linearly interpolated between the derived weeklyestimates that end March 1 and the initial estimate from the EIA-912 on March 15. The shaded areaindicates the range between the historical minimum and maximum values for the weekly series from1999 through 2003. Source: Weekly storage values from March 15, 2002, to the present are from Form EIA-912, "Weekly Underground Natural Gas Storage Report." Values for earlier weeks are from theHistorical Weekly Storage Estimates Database, with the exception of March 8, 2002. Figure 5 shows the variability of storage volumes of working gas. Stored volumes totaled 2.7tcf at the end of the 2000 refill season. The severe temperatures during the heating season of2000-01 drew this down to a low of 742 billion cubic feet (bcf) in March of 2001. In contrast, at theend of the 2001 refill season, the stored volume was 3.1 tcf, but the heating season was characterizedby more moderate temperatures and the stored volume did not fall below 1.5 tcf, double the As shown in Figure 5 , in November 2004 working gas storage levels were above their five yearaverage, suggesting that adequate supplies were available. The EIA reported that by November 26,2004 stocks in the lower 48 states totaled about 3.3 tcf, about 0.2 tcf more than at the same time in2003. (13) Given this storage report, it would seemunlikely that the current high futures pricesobserved on the NYMEX could be supported by uncertainties related to available stocks. The potential effects of high, volatile natural gas prices on both the national economy as wellas individual consumers is not insignificant. High, sustained levels of natural gas prices can act asa drag on economic growth. As with oil price shocks in the past, high natural gas prices canconstitute a classic supply side shock which reduces output and productivity growth. If severeenough, a shock of this type can increase unemployment and cause inflation in the short term. On the level of individual consuming sectors, high natural gas prices negatively affect specific industrial users who make heavy use of natural gas in their production process, which makes themuncompetitive. Residential users might have difficulty paying their winter heating bills, forcing themto choose between adequate home heating and other necessities. In the very near term little can be done to affect natural gas prices, except through market intervention in the form of price controls, mandatory conservation, and prioritized rationing. Theconditions that will determine market balance for 2004 and 2005 are largely in place, with the majorexception of the weather. To help mitigate the effects of possible price spikes this winter, aid to lowincome gas consumers through the Low Income Home Energy Assistance Program (LIHEAP) couldbe increased. (14) Much can be done to alter the demand and supply characteristics of the natural gas market in the long term. Conservation, expansion of LNG use, access to areas not currently available forexploration, and new pipeline construction, among others can be debated. Any of these options willtake significant time to implement and must be considered in a long term context. None of themare likely to have significant influence on prices over the next six months to one year.

Summary:
Intermittently high, volatile natural gas prices since 2000 have raised concern among all types of consumers. Residential customers have seen gas bills increase dramatically during the heatingseason. Industrial consumers have seen costs increase, which reduces their competitiveness. Because the price of natural gas at the consumer level is a mixture of market forces and regulation,explaining the behavior of price can be difficult. Debate in the 108th Congress concerning the energy bill ( H.R. 6 ), considered provisions which are intended to improve long term natural gas supplies in the United States. Otherissues are likely to be brought before the 109th Congress for consideration. This paper analyzes theshort term forces which influence the natural gas market. The Energy Information Administration has developed a metric called the effective capacity utilization rate as a framework for analyzing the economics of the natural gas market. This measurehas been shown to be correlated with the price of natural gas. When as the effective capacityutilization rate attains high levels (90% and above) it becomes increasingly likely that tight marketconditions will yield high prices. As a result of the Natural Gas Policy Act of 1978 ( P.L. 95-621 ) and subsequent legislation in 1989 and 1992 ( P.L. 101-60 and P.L. 102-486 ) the wellhead price of natural gas is marketdetermined. Pipeline rates are federally monitored and distribution charges are regulated at the statelevel. Price variability centers on the wellhead price as well as the price determined in futuresmarkets. Price spikes have occurred in two of the past three heating seasons. Whether severe weather causes price increases depends on the tightness of the market as measured by the effective capacityutilization rate. The same level of demand could lead to very different price results if the effectivecapacity utilization rate is high or low. A variety of factors can affect the effective capacity utilization rate. Since short run supply adjusts to meet demand, the weather will be an important determinant. The relationship betweennatural gas prices and investment in exploration, development and production is an important factorin determining productive capacity. The availability of stored gas and imported gas become vitalto price stability as the effective productive capacity exceeds 90%. In the very short term there appears to be little that can be done from a policy perspective to alter the fundamental economics of the natural gas market. In the longer term, policies that slowdemand growth and/or encourage the growth of supply, either from domestic or foreign sourcescould be effective. This report will be updated as events warrant.