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U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply |
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2. Mid-Term Natural Gas Supply: Analysis of Federal Access Restrictions Introduction A substantial amount of the Nation’s natural gas resources underlie Federal lands and/or environmentally sensitive areas where access is limited by Federal statutes, rules, and regulations. Most of the onshore natural gas resources subject to Federal access limitations are located in the Rocky Mountain region. Significant portions of the Rocky Mountain resources are either off limits to exploration and development or subject to Federal lease stipulations52 when production is allowed. Offshore natural gas resources in the Pacific, Atlantic, and Eastern Gulf of Mexico Outer Continental Shelf (OCS)53 are also subject to Federal access limitations. 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.
Onshore Resources Of the natural gas resources yet to be developed in the onshore United States, those subject to Federal access restrictions are located primarily in the Rocky Mountain region.54 The Rocky Mountain region contains approximately 37 percent (293 trillion cubic feet) of the remaining unproved technically recoverable natural gas resources in the lower 48 onshore United States (Figure 10).55,56 In the onshore, only the Gulf Coast Region at 24 percent approaches in magnitude this region’s endowment. Most of the Rocky Mountain resources, however, need to be subjected to a significant degree of stimulation (e.g., hydraulic fracturing) or other “unconventional” production techniques in order to attain sufficiently economic levels of production. These unconventional natural gas resources consist of three basic types: gas in low permeability sandstones (tight sands), gas in low permeability shales (gas shales), and gas in coal formations (coalbed methane). Tight sands account for 65 percent of the unproved natural gas resources in the Rocky Mountains. The rest of the Rocky Mountain unconventional resources, 16 percent of the region’s total resources, are mostly coalbed methane and a small amount of gas shales. The remaining 19 percent of total unproved resources in the Rocky Mountain Region are conventional natural gas resources, primarily in higher permeability sandstone or carbonate reservoirs. The 293.3 trillion cubic feet of unproved Rocky Mountain natural gas resources are subject to a variety of access restrictions (Table 4). Of that amount, 33.6 trillion cubic feet is officially off limits to either drilling or surface occupancy (No Access - Legal). Included in this category are those areas where drilling is precluded by statute (e.g., national parks and wilderness areas) and by administrative decree (e.g., “wilderness re-inventoried areas” and “roadless areas”). Also included are those areas of a lease where surface occupancy is prohibited by stipulation to protect identified resources such as the habitats of endangered species of plants and animals. An additional 57.7 trillion cubic feet of the resources are judged to be currently de facto off limits57 because of the prohibitive effect of compliance with environmental and pipeline regulations created under such laws as the National Historic Preservation Act, the National Environmental Policy Act, the Endangered Species Act, the Air Quality Act, and the Clean Water Act58 (No Access - De Facto). Of the 202 trillion cubic feet of resources that are accessible, 50.8 trillion cubic feet are located in areas where Federal lease stipulations affect the costs and timing of development (Access - Lease Stipulated). The lease stipulations are set by either the U.S. Bureau of Land Management or the U.S. Forest Service. 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 with no lease stipulations (Access - Standard Lease Terms). These 151.2 trillion cubic feet of resources are currently available for development.
Offshore Resources The offshore natural gas resources most affected by Federal access restrictions are located in certain areas of the lower 48 OCS. The lower 48 OCS is estimated to contain substantial resources of natural gas, including both gas in gas fields (nonassociated) and gas in oil fields (associated-dissolved). Based on the 2000 assessment by the Minerals Management Service (MMS) of the U.S. Department of Interior, the mean estimate of undiscovered, technically recoverable natural gas resource as of January 1, 2000, in the lower 48 OCS is 233.7 trillion cubic feet59 (Figure 11), including resources in areas that are currently inaccessible. The Gulf of Mexico area contains 80 percent of the U.S. OCS undiscovered natural gas resources. Of the estimated 186.8 trillion cubic feet of remaining undiscovered natural gas in the Gulf of Mexico, approximately 70 percent can be found in water depths greater than 200 meters. Associated-dissolved gas accounts for 9 percent of the undiscovered resources in shallow waters (less than 200 meters) and almost 32 percent of the resources in deep waters. The vast majority (93 percent) of the undiscovered resources in the Gulf of Mexico are in the Western and Central planning areas. Access to offshore natural gas resources is restricted primarily by Federal moratoria on leasing. The MMS is responsible for overseeing the development of resources in the OCS as directed in the Outer Continental Lands Act of 1953 (OCLA). The MMS announces which leases will be available for sale under a 5-year leasing schedule in order to manage the resources in the OCS in an orderly manner; however, not all areas are open for leasing. The planning areas in the Pacific, Atlantic, and most of the Eastern Gulf of Mexico are withdrawn under Section 12 of the OCLA through June 30, 2012. As a result of this legislation, 58.2 trillion cubic feet of the undiscovered, technically recoverable natural gas resources in the OCS are currently unavailable: 18.9 trillion cubic feet in the Pacific, 28 trillion cubic feet in the Atlantic, and 11.3 trillion cubic feet in the Eastern Gulf of Mexico. The MMS sale 181 area, which contains 1 trillion cubic feet of technically recoverable resources, is the only part of the Eastern planning area that is not excluded under Section 12. 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. Even if the Federal moratoria were lifted and offshore leasing activity resumed in Federal waters, States and nongovernmental entities in opposition to offshore oil and gas development could use other legal means to preclude or at least limit the extent of Federal offshore oil and gas exploration and production. Although the States and local governments can not directly prohibit the physical development of offshore oil and gas resources in Federal waters, it would be possible to make their development considerably more expensive. A primary method for accomplishing this would be to preclude or limit the development of oil and gas infrastructure within the jurisdiction of the State and local governments by use of restrictive zoning. The oil and gas infrastructure necessary to develop Federal offshore energy resources include many elements, such as harbor facilities, onshore separation and treatment plants, oil refineries, and pipelines for transporting the crude oil and natural gas onshore. For the purposes of this analysis it is assumed that local infrastructure issues and other potential non-Federal impediments would be overcome if Federal access restrictions were lifted, and that oil and gas development would proceed at rates similar to those seen in the early development of currently accessible areas. Analysis of Access Restrictions Representation in the National Energy Modeling System As requested by the Secretory of Energy, the Energy Information Administration (EIA) has conducted an analysis of the impact of removing Federal restrictions on access to natural gas resources, using mid-term forecasts from the National Energy Modeling System (NEMS). The reference case for the analysis is the reference case from EIA’s Annual Energy Outlook 2002 (AEO2002),60 which assumes that the current Federal restrictions on access to natural gas resources will remain in place throughout the forecast period (2001-2020). Federal access limitations in the Rocky Mountain region are represented in the NEMS Oil and Gas Supply Module (OGSM) by removing inaccessible resources from the module’s resource base and by assuming cost increases and timing delays for developing resources in areas where Federal lease stipulations are routinely imposed. Access limits on the restricted portions of the OCS are represented in the OGSM by not allowing any exploration or development in those areas throughout the forecast period. Access Restrictions in the Rocky Mountain Region The treatment of access restrictions in the Rocky Mountain region in the reference case varies by access status. Resources located on land that is legally inaccessible are removed from the model’s operative resource base. Resources located in areas that are de facto inaccessible because of environmental and pipeline regulations are initially removed from the model’s resource base but are made available gradually over the forecast period to reflect the tendency of technological progress to enhance industry’s ability to overcome difficulties in complying with the restrictions. Resources that are accessible but located in areas that are subject to lease stipulated access limitations are accounted for by two adjustments: (1) exploration and development costs are increased by 6 percent61 to reflect the increased costs that access restrictions generally add to a project; and (2) 2 years are added to the assumed schedules for projects in restricted areas to simulate the delay usually incurred as a result of efforts to comply with the access restrictions. The following assumptions were used in developing analysis cases to evaluate the potential effect of increased access to natural gas resources in the Rocky Mountains on the mid-term outlook for U.S. natural gas supply:
With these assumptions, 230.8 trillion cubic feet, instead of the current 202 trillion cubic feet, of unproved natural gas resources in the Rocky Mountain Region would be immediately accessible, and 50.8 trillion cubic feet of that 230.8 trillion cubic feet would be less expensive and take less time to find and develop than in the reference case. Access Restrictions in the Outer Continental Shelf Although existing moratoria on leasing in the OCS are scheduled to expire in 2012, the AEO2002 reference case assumes that the moratoria will again be reinstated, as they have been in the past. Current rules as to access are therefore assumed to prevail for the remainder of the forecast period, and no exploration or development is allowed in areas currently closed to leasing under Federal moratoria. The following assumptions were used in developing analysis cases to assess the potential impact of opening access to areas currently under leasing moratoria in the lower 48 OCS:
With these assumptions, 58.2 trillion cubic feet is added to the amount of accessible undiscovered, technically recoverable natural gas resources in the lower 48 OCS, raising the total to 233.7 trillion cubic feet from the current level of 175.5 trillion cubic feet. Higher Demand for Natural Gas If natural gas consumption were higher in the future than projected in the reference case, the higher level of demand would likely stimulate more rapid development and production of natural gas resources, including the additional resources assumed to be made available in the Rocky Mountain and OCS areas in the analysis cases that reduce Federal access restrictions. A carbon dioxide emissions limit case was used in this analysis to examine the effects of higher demand for natural gas. Because the carbon content of coal is the highest among the fossil fuels, electricity generators are expected to reduce their coal use to meet a cap on carbon dioxide emissions, and natural gas consumption is expected to increase as a result. The carbon dioxide emissions limit case includes all the assumptions of the AEO2002 reference case and, in addition, assumes that carbon dioxide emissions from electricity generators will be capped at 7 percent below their 1990 levels beginning in 2007. The cap is phased in over a 5-year period, beginning in 2002, reaching 440 million metric tons carbon equivalent (the 1990-7% level) in 2007. In this case, carbon dioxide emissions from the electricity generation sector are projected to be lower than in the reference case by an average of 229 million metric tons carbon equivalent per year from 2002 through 2020, and total U.S. natural gas consumption in 2020 is projected to be 2.9 trillion cubic feet higher than in the reference case. Analysis Cases To examine the sensitivity of natural gas supply and prices to the lifting of Federal access restrictions, four analysis cases were employed. In three access cases, Federal access restrictions were assumed to be lifted for either the OCS or the Rocky Mountains, or for both regions, with all other assumptions the same as those in the reference case. In the fourth access case, Federal access restrictions were assumed to be lifted for both the OCS and the Rocky Mountains in an environment of higher natural gas demand resulting from the imposition of a carbon dioxide emissions limit. In total, six cases were used, as summarized below:
Table 5 shows the assumed levels of accessible unproved, technically recoverable natural gas resources that would be available for development in the Rocky Mountain and OCS areas in each of the six cases. Results In the analysis cases for this study, the lifting of Federal access restrictions makes more resources available for conversion into producing reserves and enables less costly, more timely production of resources in areas that are currently open to development. All other things being equal, this should tend to increase the potential supply of natural gas and put downward pressure on average wellhead prices. The model results, summarized in Table 6, reflect those expectations. Reference Case In the reference case, natural gas consumption is projected to grow by an average of 2.1 percent per year, from 22.5 trillion cubic feet in 2000 to 33.8 trillion cubic feet in 2020. The highest projected growth is in the electricity generation sector, from 4.2 trillion cubic feet in 2000 to 10.3 trillion cubic feet in 2020. By 2020, electricity generation becomes the largest consumer of natural gas. In comparison, the largest current gas consumer, the industrial sector, is expected to increase from 8.4 trillion cubic feet in 2000 to 10.1 trillion cubic feet in 2020. To meet the growth in natural gas consumption, both domestic production and imports are projected to increase. Dry gas production increases by 2.0 percent per year in the reference case from 19.0 trillion cubic feet in 2000 to 28.5 trillion cubic feet in 2020. Most of the increase is from lower 48 onshore production, which is projected to increase from 13.3 trillion cubic feet in 2000 to 21.1 trillion cubic feet in 2020. Lower 48 offshore production is projected to increase from 5.3 trillion cubic feet in 2000 to 6.8 trillion cubic feet in 2020. Alaskan gas production is projected to increase only slightly, from 0.4 trillion cubic feet in 2000 to 0.6 trillion cubic feet in 2020. Projected increases in gas imports are expected to come primarily from Canada and from overseas in the form of liquefied natural gas (LNG). Net Canadian gas imports are projected to increase from 3.5 trillion cubic feet in 2000 to 5.1 trillion cubic feet in 2020, and net LNG imports are projected to increase from 0.2 trillion cubic feet in 2000 to 0.8 trillion cubic feet in 2020. The LNG projection is based on the expectation that the four existing LNG terminals—Cove Point, Maryland; Elba Island, Georgia; Everett, Massachusetts; and Lake Charles, Louisiana—will be operating at full capacity (80 percent of design capacity) by 2010. From 1995 to 2000, the natural gas wellhead price averaged $2.38 per thousand cubic feet (2000 dollars). Relative to that average, the natural gas wellhead price is projected to increase at an average rate of 1.6 percent per year in the reference case, to $3.26 per thousand cubic feet in 2020. Increasing prices reflect the rising demand for natural gas and the progression of the discovery process to smaller, deeper conventional fields and to unconventional natural gas fields, all of which are more costly to develop on a per unit of production basis. Carbon Dioxide Emissions Limit Case A carbon dioxide emissions limit favors less carbon-intensive fuels. By 2020, coal consumption in the carbon dioxide emissions limit case is 50 percent lower than projected in the reference case, and natural gas consumption rises to 36.7 trillion cubic feet, as compared with 33.8 trillion cubic feet in the reference case. Natural gas consumption in the electricity generation and industrial sectors is projected to increase to 11.9 and 10.4 trillion cubic feet, respectively, in 2020, compared with 10.3 and 10.1 trillion cubic feet in the reference case. The impact of the carbon dioxide emissions limit on the projected mix of natural gas supplies depends on the time frame. In 2010, higher natural gas demand in the carbon dioxide emissions limit case results primarily in greater production from lower 48, onshore wells (17.7 trillion cubic feet, compared with 16.5 trillion cubic feet in the reference case). Conventional and unconventional lower 48 natural gas production levels are also higher than projected in the reference case in 2010 at 8.5 and 7.7 trillion cubic feet, respectively. After 2010, new LNG terminals and an Alaskan gas pipeline to the lower 48 States are expected come into operation. By 2020, much of the incremental gas supply required in the carbon dioxide emissions limit case is projected to be met by shipments of Alaskan gas to the lower 48 States (1.6 trillion cubic feet62) and by higher net LNG imports (almost 1.4 trillion cubic feet63). As LNG and Alaskan gas become increasingly available, they displace the need for lower 48 production. Consequently, lower 48 production in the carbon dioxide emissions limit case in 2020 is projected to be only 60 billion cubic feet more than in the reference case, at 27.9 trillion cubic feet. A cyclic price trend is apparent in the carbon dioxide emissions limit case after 2005 (see Figure 13), primarily due to the initial surge in natural gas demand that results from the imposition of a carbon dioxide emissions limit (see Chapter 4 for analysis of potential cyclic price behavior in the U.S. natural gas market). Between 2005 and 2007, natural gas consumption is projected to increase by more than 1 trillion cubic feet per year. At that rate of increase in natural gas consumption there would be a relative scarcity of supply and reserves, causing natural gas prices to increase to relatively high levels. Because of the delay between price increases and the availability of new natural gas supplies, natural gas prices would have to remain at a high enough level for a long enough period of time to bring forth sufficient supplies to satisfy the higher projected level of demand. After 2010, the initial surge in natural gas demand is projected to taper off, and the growth in demand returns to a rate that is closer to that projected in the reference case. At this point, natural gas prices are expected to begin declining, both because of the more moderate growth in demand and because of a relative surplus of supply. The relative supply surplus would be created by the delay between changes in price and changes in wellhead supply. Essentially, high levels of gas drilling activity would continue even after natural gas prices have fallen, causing prices to fall even further. Eventually, however, lower drilling activity would cause natural gas reserves to be depleted, and as a result, prices are projected to begin increasing again after 2015 as natural gas supplies become relatively more scarce. Wellhead natural gas prices in 2020 are higher in the carbon dioxide emissions limit case than in the reference case, because the higher production levels earlier in the forecast move the industry further along the depletion curve for conventional gas (making it more costly), and because onshore, high-cost unconventional gas production makes up a larger portion of lower 48 production. By 2020, the lower 48 average wellhead price for natural gas in the carbon dioxide emissions limit case is $3.72 per thousand cubic feet, $0.46 per thousand cubic feet higher than projected in the reference case. Rocky Mountain Access Case Of the 57.7 trillion cubic feet of Rocky Mountain natural gas resources assumed to be de facto inaccessible in the reference case, 28.8 trillion cubic feet is assumed to be accessible in the Rocky Mountain access case as a result of increased flexibility in the administration of Federal environmental and pipeline regulations. In addition, with the removal of Federal lease stipulations, 50.8 trillion cubic feet of the Rocky Mountain natural gas resources is no longer assumed to incur higher development costs and deferred income due to drilling delays. The larger, more profitable resource base results in increased reserve additions, which enlarge the reserve base and increase productive capacity relative to the reference case projection. With more natural gas available at lower prices, projected lower 48 natural gas production in 2020 is 245 billion cubic feet higher than in the reference case, at an average wellhead price that is 6 cents per thousand cubic feet lower. OCS Access Case In the OCS access case, access is allowed to the currently inaccessible areas of the Atlantic, Pacific, and Eastern Gulf of Mexico OCS, adding 58.2 trillion cubic feet to the approachable, technically recoverable U.S. natural gas resource base. As a result, cumulative lower 48 natural gas reserve additions are projected to be 8 trillion cubic feet greater by 2020 than projected in the reference case. From the higher reserve level in the OCS access case, 236 billion cubic feet more production is projected in 2020 than in the reference case, at an average wellhead price that is 4 cents per thousand cubic feet lower. Rocky Mountain and OCS Access Case The Rocky Mountain and OCS access case combines increased access to the Rocky Mountains with the opening up of the OCS. As a result, 87 trillion cubic feet of currently inaccessible natural gas resources become available for exploration and development, and 50.8 trillion cubic feet of resources become less costly to develop with a shorter lead time. With the larger, less costly resource base, cumulative lower 48 reserve additions throughout the forecast are projected to be 15 trillion cubic feet higher than in the reference case. Consequently, the remaining lower 48 natural gas reserves in 2020 are projected to be 11 trillion cubic feet higher than in the reference case. With this improved reserve position, natural gas production in 2020 is projected to be 578 billion cubic feet higher than in the reference case, and the average wellhead price is projected to be 11 cents per thousand cubic feet lower.
Rocky Mountain and OCS Access Case with Carbon Dioxide Emissions Limit This analysis case uses the same access assumptions as the Rocky Mountain and OCS access case, with the higher natural gas demand projected in the carbon dioxide emissions limit case. The higher demand requirements exert upward pressure on the wellhead price to the extent that some of the fields that are expected to be accessible but not profitable in the Rocky Mountain and OCS access case become profitable. Because the newly profitable fields contain some of the larger resource deposits in the previously inaccessible areas, the differences in results between this case and the carbon dioxide emissions limit case tend to be greater than the differences between the Rocky Mountain and OCS access case and the reference case. Lower 48 cumulative reserve additions are projected to be 17 trillion cubic feet greater in 2020 in the Rocky Mountain and OCS access case with carbon dioxide emissions limit than in the carbon dioxide emissions limit case. Natural gas production is projected to be 1.1 trillion cubic feet higher in 2020, and the average wellhead price is projected to be 15 cents per thousand cubic feet lower than in the carbon dioxide emissions limit case. With the higher levels of demand (and higher production) in both cases, end-of-year reserves in 2020 are projected to be 8 trillion cubic feet greater in the Rocky Mountain and OCS access case with carbon dioxide emissions limit than in the carbon dioxide emissions limit case—3 trillion cubic feet smaller than the projected difference in 2020 end-of-year reserves (11 trillion cubic feet) between the Rocky Mountain and OCS access case and the reference case. Comparison of production projections (Figure 12) shows the effect of increased access to be greater in a higher demand environment. The higher demand for natural gas that results from an assumed cap on carbon dioxide emissions from the electricity generation sector causes upward pressure on prices. At higher price levels, substantially more of the newly accessible deposits become profitable to develop. Over the last 10 years of the forecast, a period during which increased access to the OCS is fully implemented, the cumulative difference in production between the Rocky Mountain and OCS access case with carbon dioxide emissions limit and the carbon dioxide emissions limit case is projected to reach 7 trillion cubic feet, as compared with a projected differential of 3 trillion cubic feet between the Rocky Mountain and OCS access case and the reference case over the same period. The projections for wellhead natural gas prices show a similar trend among the cases with different demand levels (Figure 13). In the two cases with a cap on carbon dioxide emissions, the price increases sharply from 2004 to 2007, then begins to decline as drilling increases induced by the higher prices enhance productive capacity through additions to the reserve base. In addition, higher projected prices in the two cases with higher natural gas demand result in the opening of a pipeline to provide natural gas supplies from the north slope of Alaska, as well as increases in imports of liquefied natural gas (LNG)—from new and existing LNG import terminals—both of which put downward pressure on prices in the later years of the forecast. Under these conditions, increased access to Rocky Mountains and OCS natural gas resources is projected to put further downward pressure on prices. In the latter half of the forecast (2011 to 2020), the average lower 48 wellhead price is projected to average 14 cents lower in the Rocky Mountain and OCS access case with carbon dioxide emissions limit than in the carbon dioxide emissions limit case. In comparison, the average lower 48 wellhead price in the Rocky Mountain and OCS access case is projected to average 8 cents lower than in the reference case over the same period. Conclusion The lifting of Federal access restrictions is projected to have an impact on U.S. natural gas supply and prices in the mid-term, and the projected impact is even greater in the high price environment of the carbon dioxide emissions limit case. When Federal access restrictions are assumed to be lifted to varying degrees in the reference case environment, the average wellhead price of natural gas in 2020 is projected to be lower by 4 to 11 cents per thousand cubic feet, and domestic natural gas production in 2020 is projected to be higher by 236 to 578 billion cubic feet, than projected in the reference case (which assumes the continuation of current access restrictions). By comparison, in the Rocky Mountain and OCS access case with carbon dioxide emissions limit, the average wellhead price of natural gas in 2020 is projected to be lower by 15 cents per thousand cubic feet, and domestic natural gas production in 2020 is projected to be higher by 1,078 billion cubic feet, than projected in the carbon dioxide emissions limit case (which also assumes the continuation of current access restrictions). Further, the cumulative impact in the Rocky Mountain and OCS access case with carbon dioxide emissions limit is even more dramatic: wellhead natural gas prices from 2010 to 2020 are projected to average 14 cents per thousand cubic feet lower than projected in the carbon dioxide emissions limit case, and cumulative production is projected to be 7 trillion cubic feet greater over the 10-year period.
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