Executive Summary

Recent Trends in Natural Gas Markets

Natural gas prices rose dramatically in 2000 and remained high through much of the first half of 2001. The sustained runup of prices was unprecedented in U.S. natural gas markets. Contributing to the price increases in 2000 were increased utilization of expanded natural gas consumption capacity, and a decline in natural gas productive capacity that limited production responses. Rising prices at the beginning of the natural gas storage refill season in April 2000 resulted in lower levels of injections than normal and unusually low levels of natural gas in storage at the start of the 2000-2001 winter. Exceptionally cold weather along with unusually low storage levels in November and December 2000 caused spot prices to spike higher, exceeding $10 per million British thermal units (Btu) on a few days in late December and early January 2001. These conditions have since abated with spot prices falling below $2 per million Btu on some days from late September to late November 2001.

As prices rose during 2000, the number of rotary rigs drilling for natural gas rose substantially, reaching 879 by year end, more than double the most recent low of 362 gas rigs in April 1999. The increase in drilling raised domestic production to 19.0 trillion cubic feet in 2000— an increase of almost 0.2 trillion cubic feet from 1999. At the same time, however, market demand expanded by more than 0.9 trillion cubic feet in 2000, absorbing all additional production and causing prices to rise.

The domestic natural gas production industry continued its expansion during 2001, with the number of active gas drilling rigs rising to 1,068 in mid-July 2001 and subsequently declining to 785 on November 30, 2001. Gas well completions in 2001 are expected to be more than 20,000 wells.,sup>1 The large number of gas well completions increased effective productive capacity and resulted in a 6-percent increase in proved natural gas reserves between 1999 and 2000, by far the largest increase since the Energy Information Administration (EIA) began collecting these data in the late 1970s.²

Natural gas prices have declined substantially since early 2001, and supplies have been sufficient to allow record volumes to be added to storage—after ending the 2000-2001 heating season at 742 billion cubic feet, 16 billion cubic feet below the previous record end-of-season low. Net additions to working gas in storage during the 2001 refill season have occurred at a record pace. By November 1, working gas stocks are estimated to have reached more than 3,100 billion cubic feet. Even though the 2001 storage fill rate represents almost 4 billion cubic feet per day of incremental natural gas demand over refill rates in 2000, prices have fallen during this period—a clear indication that the supply situation has improved since last year. Increased productive capacity and slower growth in natural gas demand because of mild weather and a slowing economy have combined to reduce natural gas prices dramatically, despite an aggressive storage refill effort.

Canadian imports grew during 2000 primarily because of increased utilization of the Portland Pipeline and two new cross-border pipelines, the Maritimes & Northeast Pipeline (Maritimes) and the Alliance Pipeline. Maritimes became operational in January 2000, providing approximately 400 million cubic feet per day of capacity into eastern Massachusetts. The Alliance Pipeline, with a capacity of 1.3 billion cubic feet per day into the Chicago market, began operations in December 2000.

Natural gas imports from Canada have increased during 2001, and the new Alliance Pipeline has transported some of that increase. In April 2001, the Federal Energy Regulatory Commission (FERC) gave preliminary approval to Maritimes to extend its transportation capacity in 2002 by 350 million cubic feet per day.

Liquefied natural gas (LNG) imports grew during 2000, reaching 226 billion cubic feet, a 38-percent increase over the previous year. The imports came primarily from Algeria, Qatar, and Trinidad and Tobago.

California natural gas prices remained high through May 2001, as the local natural gas utilities and others injected as much gas into storage as possible. By the end of August, California had 187 billion cubic feet of working gas in storage, 33 percent more than at the same time in 2000.³ By November 30, 2001, with storage facilities full, California natural gas prices had declined to $2.19 per million Btu at the southern California border interconnect and $2.44 per million Btu at Pacific Gas and Electric’s citygate.

Near-Term Outlook for Natural Gas Markets

The price reductions and record storage additions during 2001 indicate that the U.S. natural gas market contains the self-correcting mechanisms that are associated with well-functioning markets. This bodes well for the market outlook, as domestic resources are expected to be substantial and the potential exists for both Canadian and LNG supplies to expand, given favorable economics.

Natural gas prices are expected to continue to decline through next year.⁴ Average monthly wellhead natural gas prices are expected to be $3.98 per million Btu in 2001, although prices have been decidedly lower in the latter part of the year than in the early months. Wellhead prices are projected to decline to $1.91 per million Btu in 2002, a 52-percent drop.

The lower price forecast for 2002 is based on current record-high storage volumes and the potential for record high additions to productive capacity. High storage levels are expected to moderate any upward price pressure, even if the 2001-2002 winter is colder than normal. If the winter weather is either normal or warmer than normal, there could be a significant surplus of natural gas storage supplies in the spring of 2002.

High natural gas prices during the second half of 2000 and the beginning of 2001 motivated a boom in gas well drilling that is expected to result in a significant increase in wellhead productive capacity. Although wellhead prices peaked in January 2001, the inherent delay between price changes and drilling increases meant that the gas drilling rig count did not peak until July 13, 2001, at 1,068 rigs. Depending on how quickly the gas rig count declines during the remainder of 2001, the annual average count could range between 910 and 924 rigs for 2001, which, in turn, could result in 2001 gas discoveries in the range of 22 to 24 trillion cubic feet. With new wellhead gas discoveries in 2000 replacing 99 percent of that year’s natural gas production,⁵ and with the prospect for even higher reserve discoveries in 2001, the large additions to wellhead natural gas supply during 2000 and 2001 create the potential for a further decline in wellhead natural gas prices. The potential for low natural gas prices during 2002 will be further enhanced if the domestic economy remains in recession, dampening natural gas demand from both industrial consumers and electricity generators, which together accounted for 60 percent of total natural gas consumption in 2000.

Although there were some regional pipeline capacity constraints, such as in California, during the winter of 2000-2001, overall pipeline capacity was adequate and appears to be so for the foreseeable future. The growth in demand for natural gas pipeline capacity appears to have peaked in some fast-growing market areas such as California, Florida, and New York, and the capacity constraints in these regions appear to be short-term in nature and readily resolved. In the first 9 months of 2001, 3.8 billion cubic feet per day of new capacity and 1,660 miles of pipeline were completed. If all remaining projects scheduled for completion during 2001 are actually finished, an additional 6.5 billion cubic feet per day of capacity will be added to the network.

Mid-Term Prospects for Natural Gas Supply

In light of the recent high natural gas prices, EIA conducted a mid-term model analysis, using the National Energy Modeling System (NEMS), of two natural gas supply options that could make more supplies available: removing access restrictions on Federal lands and the Outer Continental Shelf (OCS), and adding new LNG terminals. The reference case for the analysis was EIA’s Annual Energy Outlook 2002 (AEO2002) reference case.⁶ In addition, a carbon dioxide emissions limit case was used to provide a baseline for comparisons in an environment of higher demand for natural gas.

The AEO2002 reference case is a policy-neutral case developed by EIA under the assumption that all laws, including Federal access restrictions, remain in force as currently enacted. In the reference case, total dry natural gas production is projected to increase by 2.0 percent per year, from 19.1 trillion cubic feet in 2000 to 28.5 trillion cubic feet in 2020. The natural gas wellhead price is projected to reach $3.26 per thousand cubic feet in 2020.

The carbon dioxide emissions limit case includes all the assumptions of the reference case, as well as a cap on carbon dioxide emissions from the electricity generation sector that results in higher demand for natural gas. Relative to the reference case, the carbon dioxide emissions limit case projects higher natural gas production in the lower 48 States from 2005 through 2015, which is later supplanted by natural gas supplies flowing from new LNG terminals and an Alaskan natural gas pipeline. By 2020, much of the incremental natural gas supply required in the carbon dioxide emissions limit case is projected to be met by Alaskan natural gas shipments to the lower 48 States (1.6 trillion cubic feet) and by higher net imports of LNG (almost 1.4 trillion cubic feet). Total dry natural gas production in 2020 is projected to be 30.2 trillion cubic feet. The lower 48 average wellhead natural gas price is projected to be $3.72 per thousand cubic feet in 2020 in the carbon dioxide emissions limit case.

Analysis of Access Restrictions on Federal Lands

Federal access restrictions substantially affect the Rocky Mountain region, where considerable natural gas resources are either off limits (legally or de facto⁷) to exploration and development or subject to Federal lease stipulations.⁸ Federal access limitations also affect offshore natural gas resources in the Pacific, Atlantic, and Eastern Gulf of Mexico OCS. Except for a relatively small tract in the Eastern Gulf of Mexico, these areas are legally off limits to exploration and development under existing Federal moratoria.

Reducing Federal access restrictions in the Rocky Mountains and OCS is expected to increase the available resource base by 87 trillion cubic feet, which would expand the available lower 48 resource base from 1,190 to 1,277 trillion cubic feet, a 7-percent increase. Reducing Federal access restrictions does not imply that all land restrictions would be removed. An estimated 62.5 trillion cubic feet of natural gas resources would remain unavailable for development, for example, in National Parks, National Monuments, and wilderness and roadless areas, as well as areas currently precluded by the effect of statutes and regulations. Although the available resource base expands by 7 percent with increased Federal access, lower 48 production during the forecast increases only slightly, because production is driven by demand for natural gas. The primary impact of greater Federal access is to reduce natural gas prices slightly as a result of the availability of lower cost resources that were otherwise unavailable to the gas market. The slightly lower prices are projected to result in slightly higher demand for natural gas and, accordingly, slightly higher levels of natural gas production.

The Rocky Mountain region contains approximately 35 percent (293 trillion cubic feet) of the remaining unproved technically recoverable natural gas resources in the lower 48 onshore United States.⁹,¹⁰ Most of the Rocky Mountain resources (81 percent) are “unconventional”—65 percent in low permeability sandstones (tight sands), 16 percent in coal formations (coalbed methane), and a negligible amount in low permeability shales (gas shales).

The 293.3 trillion cubic feet of unproved Rocky Mountain natural gas resources are subject to a variety of access restrictions. Of that amount, 33.6 trillion cubic feet is officially off limits to either drilling or surface occupancy. An additional 57.7 trillion cubic feet of the resources are judged to be currently de facto off limits because of the prohibitive effect of compliance with environmental and pipeline regulations. Of the 202 trillion cubic feet of resources that are accessible, 50.8 trillion cubic feet are located in areas where Federal lease stipulations are estimated to increase development costs by 6 percent and to add 2 years to their development schedule. The remaining 151.2 trillion cubic feet of unproved Rocky Mountain natural gas resources are located either on Federal land without lease stipulations or on private land and are fully accessible subject to standard lease terms (without lease stipulations).

Estimated total undiscovered,¹¹ technically recoverable natural gas resource as of January 1, 2000, in the entire lower 48 OCS is 233.7 trillion cubic feet. The currently inaccessible portion of the total amounts to 58.2 trillion cubic feet, with 18.9 trillion cubic feet in the Pacific, 28.0 trillion cubic feet in the Atlantic, and 11.3 trillion cubic feet in the Eastern Gulf of Mexico. The remaining 175.5 trillion cubic feet of fully accessible lower 48 OCS resources are located almost entirely in the Western and Central Gulf of Mexico, with 1 trillion cubic feet in the Eastern Gulf of Mexico.

EIA’s analysis assumed that increased access to Federal lands would increase the exploitable resource base in the Rocky Mountains by 28.8 trillion cubic feet and would reduce development costs by 6 percent and development times by 2 years for an additional 50.8 trillion cubic feet of Rocky Mountain resources. In the OCS region, increased access was assumed to expand exploitable offshore resources by the full 58.2 trillion cubic feet that is currently inaccessible. It was also assumed that leases for currently restricted OCS areas would be included in a 2007-2012 lease sale. For both the Rocky Mountains and the OCS, resource development costs were assumed to be the same as those in unrestricted areas.

The impact of lifting Federal access restrictions was examined in four analysis cases:

• Rocky Mountain access case: Includes all the assumptions of the reference case, but reduces Federal access restrictions in the Rocky Mountain region.

• OCS access case: Includes all the assumptions of the reference case, but removes Federal access restrictions in currently inaccessible areas of the OCS.

• Rocky Mountain and OCS access case: Includes all the assumptions of the reference case, but reduces Federal access restrictions in the Rocky Mountain region and opens currently inaccessible areas of the OCS.

• Rocky Mountain and OCS access case with carbon dioxide emissions limit: Includes all the assumptions of the carbon dioxide emissions limit case, but reduces Federal access restrictions in the Rocky Mountain region and opens currently inaccessible areas of the OCS.

The projections for natural gas production and prices in 2020 are shown in Table ES1.

As shown in Table ES1, increasing access to restricted areas in either the Rocky Mountains or the OCS areas results in about the same magnitude of incremental production relative to the reference case, amounting to just under 250 billion cubic feet per year. Simultaneously increasing access to both the Rocky Mountain and OCS restricted areas provides slightly more incremental production than the sum of the two increments in the single access cases, amounting to about 580 billion cubic feet per year.

The Rocky Mountain and OCS access case with a carbon dioxide emissions limit indicates that the impact of increased Federal access would be more significant in an environment of high demand and high natural gas prices. This is because a substantial share of the newly accessible resource base, particularly in the offshore, requires higher prices to be profitable. In comparison with the carbon dioxide emissions limit case without increased access, projected natural gas production in 2020 is just over 1 trillion cubic feet per year higher. Collectively, the results suggest that the benefits of increased Federal access would be proportional to future demand for natural gas supplies, which in turn depends on other factors, such as economic growth and the availability and costs of other energy sources (coal, nuclear, and renewable energy).

Analysis of LNG Imports

LNG imports are expected to become a larger source of natural gas supply in the mid-term. The AEO2002 reference case projects growth in net LNG imports from 0.2 trillion cubic feet in 2000 to 0.8 trillion cubic feet in 2010, leveling off at that amount through 2020. The reference case projection is based on the expectation that the four existing U.S. LNG terminals—Cove Point, Maryland; Elba Island, Georgia; Everett, Massachusetts; and Lake Charles, Louisiana—will operate at full capacity (80 percent of design capacity) by 2010.

LNG has become a more viable source of future natural gas supply because of the extent of world natural gas resources and the significant decline in LNG costs in all segments of the supply chain. As of January 1, 2001, 10 countries held 77 percent of the world’s natural gas reserves (4,043 trillion cubic feet out of 5,278 trillion cubic feet), with Russia, Iran, and Qatar accounting for more than 55 percent (2,906 trillion cubic feet).¹² Given this concentration of resources and the need for countries to monetize resources, an increase in the quantity of natural gas traded across international borders is all but inevitable.

If sufficient domestic LNG processing capacity existed, LNG imports could play a potentially important role in the U.S. natural gas market by dampening natural gas price extremes. Increasing spot cargos of LNG during periods of high prices would moderate price increases, and reducing spot cargos during periods of low prices would moderate price declines.

Projected LNG costs in the reference case fall within the range of the recent high natural gas prices. Liquefaction costs between 1996 and 2000 averaged $230 per ton compared with $560 per ton between 1986 and 1990. Between 1996 and 2000 the cost of a new tanker dropped by approximately 30 percent.¹³ The construction costs for regasification terminals have seen similar decreases. Because of the capital-intensive nature of LNG trade, more than 70 percent of the cost of regasified, delivered natural gas is made up of processing and transportation costs.

There is considerable uncertainty about the costs of constructing new LNG terminals, because the capital costs for any particular project are site-specific and can vary considerably, depending on the harbor’s characteristics, land costs, access to interstate transmission systems, and the degree of local opposition to the project. Moreover, the future delivered cost of LNG to a terminal depends on the world LNG market, and there is a potential for the few large LNG producers to create a cartel similar to the Organization of Petroleum Exporting Countries (OPEC). Given this price uncertainty, EIA’s analysis examined the impact of both high and low cost assumptions.

LNG already plays an expanding role in meeting natural gas demand in the reference case projections, with imports projected to grow from 160 billion cubic feet per year in 2000 to 830 billion cubic feet per year in 2020. The growth in imports is expected to come from increased utilization of existing domestic terminals, plus some expansion at existing sites. In the carbon dioxide emissions limit case (described above), with higher projected demand for natural gas in the lower 48 States, LNG imports increase even more, to 1,350 billion cubic feet.

To examine the effects of a range of LNG costs, cost assumptions were varied—within the context of the carbon emissions limit case—in two analysis cases:

• High LNG cost case: Includes all the assumptions of the carbon dioxide emissions limit case, but assumes higher LNG production costs and higher returns on investments in LNG tankers and liquefaction plants.

• Low LNG cost case: Includes all the assumptions of the carbon dioxide emissions limit case, but assumes lower LNG production costs and lower returns on investments in LNG tankers and liquefaction plants.

Table ES2 summarizes the projections for net LNG imports and natural gas wellhead prices in 2020.

Like increased Federal access, the potential contribution of increased LNG imports to future natural gas supplies depends in part on the level of demand for natural gas, as shown by the projections in the reference and carbon dioxide emissions limit cases, both of which are based on current LNG cost estimates. In addition, however, the future costs of LNG production and processing facilities are projected to affect its role in natural gas supply. In the high LNG cost case, which assumes higher costs (such as those that might result from an LNG producer cartel or from costly site permitting), net LNG imports in 2020 are projected to be lower than in the carbon dioxide emissions limit case, and natural gas wellhead prices are projected to be 7 cents per thousand cubic feet higher. In contrast, in the low LNG cost case, net LNG imports in 2020 increase to 1.74 trillion cubic feet per year, and the average wellhead natural gas price is 9 cents per thousand cubic feet lower.

Mid-Term Trends in Natural Gas Supply and Prices: Potential for Cyclic Price and Investment Behavior

The natural gas production industry possesses the causal attributes necessary for business cycle behavior:

• Relatively inelastic supply and demand in the short term, which can cause large fluctuations in price during periods of relative scarcity or abundance of supply

• Large fluctuations in producer cash flows, investments, and wellhead gas supplies, as a result of large price fluctuations

• Significant delays (approximately 6 to 18 months) between changes in price and changes in wellhead gas supply, which encourage overinvestment when prices are high and underinvestment when prices are low, relative to gas demand

• Rapid declines in production from new natural gas wells, which could rapidly turn a supply surplus into a deficit during a period of low producer investment.

Short-Term Inelasticity of Natural Gas Supply and Demand

From early 2000 through mid-2001, a scarcity of available natural gas supplies led to sustained high wellhead prices for natural gas for the first time since the early 1980s. These sustained, high natural gas prices reflected the relative inflexibility of short-term natural gas production, in that natural gas drilling—and ultimately natural gas production—could not respond immediately to the high prices. Natural gas supply is also inelastic, because the U.S. natural gas market is relatively isolated from overseas natural gas supplies due to a limited LNG import infrastructure and the limited extent of LNG international trade.

Natural gas consumption is also relatively inelastic to prices in the short term, because natural gas consumption equipment typically has lifetimes in excess of 15 years. The short-term inelasticity of natural gas demand increases the probability that natural gas supplies could be either comparatively abundant or scarce relative to prevailing natural gas consumption requirements. Short-term supply and demand inelasticity could lead to wide swings in future natural gas prices.

Dependence of New Productive Capacity on Producer Cash Flows and Prices

The development of new wellhead natural gas supplies is dependent on natural gas prices. When prices are high, producer cash flows are also high, inducing investment and drilling (Figure ES1). Natural gas drilling activity, in turn, is directly related to the development of new productive capacity, with higher gas rig levels generally resulting in a higher level of natural gas discoveries (Figure ES2).¹⁴ As a rule, high natural gas prices result in high levels of new natural gas productive capacity, and low natural gas prices result in low levels of new natural gas productive capacity.

Delays Between Price Changes and Drilling Investments

New wellhead natural gas supplies will increase or decrease as wellhead prices increase or decrease, but the response is not immediate. The delay between a price increase and a natural gas production increase may range between 6 and 18 months. In addition, there is a delay between the onset of a decline in natural gas prices and a reduction in drilling activity by producers, which appears to be about 7 months (Figure ES3). The delay between changes in price and changes in new wellhead supplies increases the propensity of natural gas producers to overinvest in new productive capacity during periods of high wellhead prices and to underinvest in new productive capacity during periods of low wellhead prices.

More Rapid Declines in Production From New Natural Gas Wells

In recent years, production from new natural gas wells has been declining more rapidly than in the past (Figure ES4).¹⁵ Although there is some year-to-year variation in the trend, lower 48 gas well half-lives have declined from 40 months in 1990 to 24 months in 1999. The more rapid decline in natural gas well production rates increases the requirement for investment in new wells in the next year and the year beyond. If natural gas well drilling were to stop completely, productive capacity in the lower 48 States would decline by between 14 and 22 percent after 1 year and between 26 and 39 percent after 2 years.¹⁶

Low wellhead natural gas prices over any sustained period of time will reduce producer cash flow and could cause natural gas drilling to decline sufficiently to cause productive capacity to be less than the potential natural gas demand within a period as short as 1 year. Thus, low prices, low cash flows, and low investment levels increase the probability that natural gas supplies will fall quickly and cause a deficit in wellhead productive capacity relative to natural gas demand.

In summary, because neither productive capacity nor consumption is highly elastic with respect to price in the short term, a relative scarcity in wellhead productive capacity could be expected to cause very high natural gas prices, and a relative surplus could be expected to cause very low prices. When supply is scarce and prices are high, the delay associated with new natural gas supply investment would tend to cause natural gas prices to overshoot the long-run market-clearing wellhead price, contributing to the tendency for natural gas productive capacity to overshoot demand. As a result, the production “boom” would be followed by an extended period of low prices, insufficient investment, and rapidly declining natural gas productive capacity. Eventually, natural gas prices would begin to rise again as supply scarcity increased; however, the delay in new supply investments would cause prices to overshoot the long-run marginal cost and cause an over-investment in new productive capacity. Consequently, the natural gas industry embodies a set of dynamics that could cause periodic cycles in investment, drilling, supply, and prices. In the future, U.S. natural gas markets probably will exhibit a tendency toward cyclic supply behavior, which may be either exacerbated or moderated by random external events, resulting in rather large and unpredictable price swings.

Implications of Large, Unpredictable Price Fluctuations

Large, unpredictable price fluctuations impose substantial risk on large, capital-intensive supply projects that require long lead times, such as LNG terminals and the Alaskan gas pipeline to the lower 48 States. In contrast, onshore, conventional drilling investments carry considerably less price risk, because they can be deployed more quickly and are shorter lived and therefore can take advantage of the immediate price environment. As a result, a price environment with large and unpredictable price swings would shift the mix of natural gas supply investments away from LNG terminals and the Alaskan pipeline toward conventional, onshore wellhead natural gas supplies. Ironically, LNG facilities might be precluded even though they could potentially moderate natural gas price extremes in the future by providing more natural gas during periods of high prices and less natural gas during periods of low prices.

Unpredictable prices also have deleterious consequences for natural gas consumers by increasing the risk associated with the operating costs of long-lived natural gas consumption facilities. For example, they obscure the value of appliances with higher energy efficiency ratings and can affect the financial viability of large industrial projects, such as electricity generation plants and fertilizer plants, where natural gas supply is the largest component of operating costs. Coal-fired projects might become more financially attractive than natural-gas-fired projects, simply because coal prices are expected to be more predictable and less likely to exhibit extreme fluctuations.

The deleterious effects of cyclical prices on suppliers and consumers can be mitigated through fixed-price contracts, price hedging and constant payment programs offered to residential consumers by local natural gas distributors. Although they are generally limited in duration, such financial instruments can mitigate the near-term financial impacts of unpredictable price behavior.

The Need for Improved Data on Natural Gas

The accuracy, timeliness, and detail of data series and products are important in providing adequate information for market analyses and policy decisions. Restructuring and growth in the industry, which began during the mid-1980s, expanded the number of market participants and changed business practices, requiring the design of new data collection instruments, increased efforts to identify industry participants, and greater effort by EIA and industry to assure data quality. In addition, greater data timeliness is desirable, which means that reliance on voluntary surveys and outside data sources such as those used for production data, wellhead price data, and imports data must be reviewed. Some data elements that have only been collected annually may need to be collected more often.

Consumption and Price Data

The collection of natural gas consumption data has been affected by the continuing restructuring of the natural gas and electricity generation industries, which started in the mid-1980s and mid-1990s, respectively. Industry changes have increased the difficulty of measuring total gas use accurately and assigning it to the appropriate sector—residential, commercial, industrial, transportation, or electricity generation, because firms providing natural gas delivery do not know the intended use for delivered natural gas.

Changes in the natural gas industry have had significant effects on data quality. The industry has grown and restructured in recent years as it moved away from its prior, more regulated structure. The types of information previously created for regulatory requirements and thus easily available for reporting to EIA are no longer available. There have also been large numbers of new firms, business sales, reorganizations, and mergers during this period.

For price data, as for volume data, the fact that pipeline and local distribution companies no longer know the purchasers and purchase terms for large volumes of natural gas sold means that data collected from them is less representative for measuring the average price of all final deliveries. For example, EIA’s industrial end-use price data currently capture less than 20 percent of the total market. Because these prices primarily represent small industrial customers, it is likely that the reported sector prices are higher than the actual average industrial price.

Supply Data

Due to the large cost of collecting and processing data from many thousands of natural gas producers, the annual and monthly measurement of marketed natural gas production is based on voluntary annual and monthly reports by producing States and by the Minerals Management Service (MMS) of the U.S. Department of Interior. The States and MMS process the information for revenue purposes, but the resulting reported sales volumes do not necessarily represent the same production definitions requested by EIA. This frequently means that the elements used to calculate marketed production must be estimated by EIA.

While EIA requests information on the volume and value of marketed natural gas production, the States and MMS do not always use this point in the supply chain for their valuation. Given these differences regarding the value of natural gas for tax and royalty purposes, as well as the treatment of monetary elements such as taxes and other fees, EIA makes adjustments to reach a common definition across States. In addition, because data are not provided for most States until months after the requested report date, EIA uses an estimation procedure for U.S. average wellhead prices until complete data reports are received from the States.

Data on natural gas in underground storage are collected each month on a storage field and reservoir basis. Storage levels are then published on a State basis. These monthly data are subsequently adjusted to correspond to annual data. Weekly storage data are most useful for monitoring the potential for price volatility. In October 2001, Secretary of Energy Spencer Abraham directed EIA to begin a weekly gas storage survey in May 2002 after the American Gas Association announced its intent to discontinue its weekly survey of natural gas storage, which it has conducted since 1994.

As part of the triennial review of EIA’s natural gas data collection authority, which must be conducted in 2002, EIA will invite suggestions and comment on many of the data issues discussed in this report. During the spring of 2002, EIA will release a Federal Register notice outlining a number of proposals developed as the result of interviews with data respondents and users and other reviews of the program. Following public comment, EIA will propose changes to the Office of Management and Budget. Authorized changes will be implemented during 2003.

Notes