Oil and Gas Exploration and Development on Public Lands
Released: 2004-03-26T00:00:00

Introduction

Significant amounts of technically recoverable oil and gas resources are projected to be onfederal public lands (see Table 7 ). However, energy development on some of these lands has beenrestricted because they are considered environmentally sensitive or unique. These restricted areasmay contain sizable amounts of oil and natural gas, according to the U.S. Geological Survey (USGS)and the Energy Information Administration (EIA).

The conflict between environmental concerns and the need for increased domestic energyproduction from public lands is a major policy issue. For example, the conference report on theomnibus energy bill ( H.R. 6 ) and the Senate substitute, S. 2095 hasprovisions that would examine restrictions and impediments to oil and gas development on publiclands, including an evaluation of the current permitting process. Reportedly, reflecting its EnergyTask Force recommendations, the Bush Administration has its own initiative to expedite the oil andgas permitting process on federal lands.

Oil and gas development practices have generated considerable debate in Congress since theearly years of the industry. Originally, oil and gas resources on public lands could be transferred toprivate ownership (patented) under the Mining Law of 1872 -- essentially, lands containing oil weresold at a fixed price per acre to the first claimant. (1) Conservationists contended that there was widespread abuse of theMining Law that led to wasteful use of public lands. In 1909 President Taft withdrew 3 million acresof lands prospective for oil in Wyoming and California from availability under the Mining Law of1872. Taft requested congressional approval for his action, leading to the Pickett Act of 1910 (43U.S.C. 141-143), which explicitly recognized executive branch authority to make such public landswithdrawals. (2)

Congress eventually decided that defense-related minerals -- including oil and gas -- shouldremain under federal ownership. As a result, the Mineral Lands Leasing Act of 1920 (30 U.S.C. 181,et. seq.) removed oil and gas from the patenting process and placed it under a leasing system. Underthe leasing system, the federal government has raised billions of dollars in revenues from royalties,rents and bonus bids. (3)

Minerals owned by the federal government under lands held privately (patented) creates a"split-estate." There are other split-estate situations as well: surface and mineral rights held bydifferent private interests, or state owned mineral rights and privately held surface rights. Threemajor federal statutes (4) allowed the federal government to issue patents to land but reserve the right to the minerals. Underthese statutes the mineral estate became the dominant estate and the surface use servient. There arespecific policies and procedures that must be followed by the mineral estate holder in order todevelop minerals. Generally, for oil and gas, a federal lessee must meet one of the followingconditions: a surface agreement; written consent or a waiver from the private surface owner foraccess to the leased lands; payment for loss or damages; or the execution of a bond not less than$1,000. (5) About 11% ofthe public lands are under the split-estate category. However, in Wyoming 50% of the lands aresplit-estate and in Montana about 57%. (6)

Environmentalists have supported public land withdrawals and other restrictions because ofconcern that the Mining Law of 1872 and then the Mineral Leasing Act of 1920 provided inadequateenvironmental protection. Recently, ranchers and other groups have expressed similar concernsspecifically about the impact of development on water and land. Conversely, development supporterscontend that numerous environmental laws are now in place to regulate oil and gas development onpublic lands. They note that the federal government must comply with the National EnvironmentalPolicy Act (NEPA) in leasing oil and gas and that the oil and gas industry must comply withapplicable requirements of the Clean Water and Clean Air Acts, Safe Drinking Water Act, theResource Conservation and Recovery Act, and state and federal reclamation standards, among otherlaws. The industry complains that environmental and other reviews often create long delays indrilling exploratory and production wells on leased lands.

The proposed conference report on a comprehensive energy bill ( H.R. 6 ) and S. 2095 addresses some of the industry and Bush Administration concerns overincreasing domestic oil and natural gas supplies. Title III of H.R. 6 and S. 2095 , if enacted, would establish a White House Office of Federal Project Coordination to helpexpedite permitting on public lands and identify restrictions and impediments to resourcedevelopment on public lands. Environmentalists and other public land users argue that theseprovisions would cause harm to the environment and prevent the land from being used in otherproductive ways. The conference report has been approved by the House but not in the Senate as aresult of a cloture motion on November 21, 2003 that did not get the required 60 votes, (57- 40). TheSenate's scaled-back substitute bill, S. 2095 is awaiting action.

This report provides a general overview of the oil and gas leasing system on U.S. publiclands, including information on permitting, production, and reserves. The report describes thecontribution of onshore oil and gas towards meeting U.S. energy demand and discusses currentestimates of reserves in restricted areas. An Appendix provides some historical background on landswithdrawn from mineral development, the role of the Bureau of Land Management (BLM), andapplication of the Federal Land Policy and Management Act (FLPMA) in the context of oil and gasdevelopment.

For information on U.S. offshore oil and gas development, see CRS Report RL31521, OuterContinental Shelf Oil and Gas: Energy Security and Other Major Issues , by [author name scrubbed].

Oil and Gas Leasing on Public Lands

Leasing of onshore federal public lands for oil and gas development is based on multiple-use/sustained yield Resource Management Plans (RMPs) developed by the Bureau of Land Management in the Department of the Interior. In accordance with those land-use plans, tracts of public land withoil and gas potential are offered for competitive leasing each quarter. After a lease is awarded, adrilling permit is required for each exploratory or production well. Industry has long complainedthat this process is too lengthy.

In FY2002, the federal government issued 1,765 new oil and gas leases on public landstotaling about 1.4 million acres. Through the end of FY2002, about 18.6 million acres of publiclands had been leased for oil and gas development.

Land Use Planning

Under the Federal Land Policy and Management Act (FLPMA), Resource Management Plansor Land Use Plans (43 USC 1712) are required for tracts or areas of public lands prior todevelopment. The Bureau of Land Management (BLM) must consider environmental impacts duringland-use planning when RMPs are developed and implemented. RMPs can cover large areas, oftenhundreds of thousands of acres across multiple counties.

FLPMA requires that RMPs reflect diverse uses -- such as timber, grazing, wildlifeconservation, recreation, and energy -- and consider the needs of present and future generations. (7) Impacts of various uses areidentified early in the process so that they can be weighed equitably against one another. The plansare also intended to weigh the various benefits associated with public lands to best serve thecommunity. RMPs must be consistent with environmental regulations and allow meaningful publicparticipation. Through the land-use planning process, the BLM determines which lands with oil andgas potential will be made available for leasing.

The Mineral Leasing Act of 1920, as amended, requires that all public lands available forlease be offered initially to the highest responsible qualified bidder by oral competitive bidding.These auctions are held quarterly by the BLM. The objective of the competitive bid is to provide a"fair market value" return to the federal government for its resources. If no bids are received or thehighest bid is less than the $2/acre national minimum acceptable bid, oil and gas leases on theselands are offered on a noncompetitive basis within 30 days. The tracts remain available on anoncompetitive basis for two years.

Tracts available for noncompetitive leasing may be obtained by the first qualified applicantupon payment of a nonrefundable application fee of at least $75. Simultaneous (SIMO)noncompetitive lease applications filed on the day following the competitive lease sale are prioritizedthrough a lottery system. Lease applicants filing on subsequent days are given priority according tothe time of filing. (For more details on leasing terms, see Appendix A.)

Geophysical exploration permits on unleased public lands may be issued by BLM. Suchexploration does not include drilling for core samples or drilling for oil and gas. The permittee mustfile a notice of intent with the BLM and must comply with specific practices and procedures spelledout by the surface managing agency (SMA). (8) Once a lease is obtained, the lessee is given exclusive rights tofurther explore, develop, and produce on that land.

Drilling Permits

After a lease has been obtained, either competitively or noncompetitively, an Application fora Permit to Drill (APD) must be approved for each oil and gas well. (9) As noted in the MineralLeasing Act, section 226 (g), "no permit to drill on an oil and gas lease issued under this chapter maybe granted without the analysis and approval by the Secretary concerned of a plan of operationscovering proposed surface-disturbing activities within the lease area."

The application form (APD form 3160-3) must include a drilling plan, a surface use plan,and evidence of bond/surety coverage. The surface use plan should contain information on drillpadlocation, pad construction, the method for containment and waste disposal, and plans for surfacereclamation.

The APD is posted for review for 30 days. Within 5 working days after the 30-day period,the BLM consults with the surface managing agency, whose consent is also required, then notifiesthe applicant of the results. BLM is required to process the application within the 35-day period. Theapplication may be approved, approved with stipulations, rejected, or delayed for additional analysisor information. The applicant is informed when final action is expected.

Despite the 35-day review requirement, a recent study by a trade association, the IndependentPetroleum Association of Mountain States (IPAMS), found that in its region it took an average of137 days to approve an APD in 2002, up from an average of 84 days in 2001. (10)

Delays in the Permitting Process

One of the major reasons for delays in the issuance of drilling permits cited by both BLM andIPAMS is the need to rewrite outdated RMPs because the surface disturbance anticipated underapproved activities may exceed the limits in the old plan because increased natural gas leasing anddevelopment is taking place. In these cases, oil and gas leases may have been awarded under an oldRMP that must be revised before a drilling permit can be issued. According to the BLM, there areseveral such plans currently being revised.

Under FLPMA, section 1712, regarding Land Use Plans: "the Secretary [of the Interior] shallwith public involvement and consistent with the terms and conditions of this Act, develop, maintainand, when appropriate, revise land use plans which provide by tracts or areas for the use of the publiclands." Current planning regulations require preparation of an environmental impact statement (EIS)under the National Environmental Policy Act (43 C.F.R. 1601.06).

After a draft EIS is issued for public comment, an RMP can be approved by the BLM StateDirector and published with an EIS and record of decision and filed with the EnvironmentalProtection Agency (EPA).

In testimony before the House Committee on Resources, IPAMS asserted that rewritingRMPs can take as long as three years, when less than a decade ago the average time was less thanone year. The Association contends that the usefulness of an RMP is now seven years, when in thepast they may have been in place for as long as 20 years. (11) The rapid pace of coalbed methane (CBM) development, inparticular, has generated new land use concerns that some argue have not been previouslyincorporated in the RMPs. Environmentalists contend that 20-year-old plans are not a good basisfor land management decisions. The need for a revised/amended RMP would necessarily delay anysite-specific analysis conducted in the drilling permit process by the BLM and the surface managingagency. Thus, even when an application for a permit to drill (APD) is in process, the BLM oftenwaits until the new RMP and EIS are complete before proceeding to any site-specific analysis neededto grant the permit.

In April 2003, BLM announced new strategies to expedite the APD process. These includeprocessing and conducting environmental analyses on multiple permit applications with similarcharacteristics, implementing geographic area development planning for an oil or gas field or an areawithin a field, establishing a standard operating practice agreement that identifies surface and drillingpractices by oil and gas operators, allowing for a block survey of cultural resources, promotingconsistent procedures, and revising relevant BLM manuals. (12)

Leasing Restrictions on Oil and Gas Resources

The availability of public lands for oil and gas leasing can be divided into three categories:lands open under standard lease terms, open to leasing with restrictions, and closed to leasing. Areasare closed to leasing pursuant to land withdrawals or other mechanisms. Much of this withdrawnland consists of wilderness areas, national parks and monuments, and other unique andenvironmentally sensitive areas that are unlikely to ever be reopened to oil and gas leasing. (13) Some lands are closed toleasing pending land use planning or NEPA compliance, while other areas are closed because offederal land management decisions on endangered species habitat or historical sites. Some of thoserestricted areas may be opened by future administrative decisions.

A BLM study (14) determined that of the approximately 700 million acres of federal subsurface minerals under theagency's jurisdiction in 2000, approximately 165 million acres have been withdrawn from mineralentry, leasing, and sale, subject to valid existing subsurface mineral rights. (15) Lands in the National ParkSystem (except National Recreation Areas), Wilderness Preservation System, and the Arctic NationalWildlife Refuge (ANWR) are among those that are statutorily withdrawn. Also of the 700 millionacres, mineral development on another 182 million acres was subject to the approval of the surfacemanagement agency, and must not be in conflict with land designations and plans, according to theBLM. Wildlife refuges (except ANWR), wilderness study areas, and roadless areas are examples oflands in this category, although many other wildlife refuges also are withdrawn from leasing.

Public lands that are open to leasing may be subject to a variety of restrictions imposed bythe Department of the Interior. Such restrictions include leasing with no surface occupancy, areasgenerally off-limits with the exception of directional drilling; leasing with timing limitations, whichprotect wildlife during certain times of the year; and leasing with controlled surface use, whichrequires a mitigation plan for specific areas under the lease. Industry sources claim some of theselease stipulations are so stringent that they constitute "de facto" closures to oil and gas development. However, development has proceeded under some of these stipulations.

Energy and mineral industry representatives maintain that federal withdrawals inhibitexploration and limit the reserve base even when conditions are favorable for production. Theindustry argues that substantial amounts of public land have been unnecessarily withdrawn throughadministrative actions to pursue preservation goals. However, environmental groups and othersgenerally contend the withdrawals are the most effective protection for the non-mineral values ofpublic lands.

Rocky Mountain Region

The Rocky Mountain region accounts for 37% of the natural gas and 17% of the crude oilprojections of the technically recoverable resource base on public lands in the lower 48 states. (16) According to the EPCAstudy noted below, 60% of the undiscovered resource base in the five basins studied in the RockyMountain region is on public lands and about 40% of that amount is not accessible or is subject tolease stipulations and restrictions. (17) Because of increased interest in access to natural gas, theprotection of public lands and Bush Administration policies, the Rocky Mountain region has becomea focal point for U.S. oil and gas policy.

Three recent reports have studied restrictions on natural gas in the Rocky Mountain region:

Natural Gas, Volume 1 Summary Report by the National Petroleum Council(NPC); 1999.

Energy Policy and Conservation Act Amendments (EPCA) study, 2003; (18)

U.S. Natural Gas Markets: Mid-term Prospects for Natural Gas Supply, 2001, by the EIA.

While the EIA and NPC studies include data for total domestic natural gas supplies, theEPCA Report more narrowly confines itself to five major geologic basins within the RockyMountain region. (19) Themost direct comparison of data on the Rocky Mountain region would be between the EIA and NPCstudies because they define the region as essentially the same. (20)

Even though the resource base was different in each of the three studies, the relative amountsof natural gas on federal lands found to be either closed, restricted, or open to development wasabout the same.

Data from the 1999 NPC study indicate the natural gas resource base in the Rocky Mountainregion is 335 trillion cubic feet (tcf). More recent data from EIA estimates technicallyrecoverable (21) naturalgas resources, excluding reserves, to be 293.6 tcf. (22) The EPCA study found 138.5 tcf in the five major geologicbasins in the region.

Although oil and gas reserves are not included in the EIA report, the relative amounts ofnatural gas closed and restricted is similar to the amounts found in the other studies. For example,the NPC reports that 9% of the region's natural gas resource base is closed and 32% restricted, whilethe EIA data shows that 11.5% is closed and 37% restricted (see Table 1 ). The NPC and EIAstudies report a more significant difference between the amount of natural gas open to leasing: 60%and 51.5% respectively, also shown in Table 1. This difference is probably because a larger portionof the proven reserves (excluded from the EIA report) are available for leasing. For instance, theEPCA study found that about 26 tcf of proven reserves are on federal lands out of 43 tcf total in thefive major geologic basins. Of this total, 63% is open under standard lease terms. If the RockyMountain reserves were included in the EIA report, then the percentage of natural gas open understandard lease terms would likely increase, and the percentage of natural gas characterized as underrestrictions would likely decline.

Oil resources in the Rocky Mountains that were examined in the EPCA study have somewhatless significance relative to U.S. oil supply. The study concludes that about 600 million barrels ofoil resources (about 30 days of total U.S. consumption) fall under the "no access" category. Another3.2 billion barrels would be available for leasing, of which one-third have restrictions. About 2.5billion barrels of oil are estimated to be available on non-federal lands in the basins studied. Thetotal oil resource included in the EPCA study represents about 7% of all technically recoverable oilin the United States.

As mentioned earlier, the numbers in the EPCA study are based on a much more selectivearea of the Rockies that included the five major geologic basins, and thus the numbers were smaller.However, as shown in Table 1, the relative rate with no access was similar to the other reports(11.6%), the amount of restricted gas was less (26%), and the amount of natural gas under standardlease terms was slightly higher (62.4%).

Both the NPC and EIA studies conclude that development of natural gas in the restricted landuse category would be -- at a minimum -- likely to face costly delays. The EIA also concludes thatif there were greater flexibility in some of the federal regulations, about 29 tcf could becomeimmediately available from this restricted category. Additionally, if certain lease stipulations wereremoved, about 51 tcf would be less costly to develop, thus freeing up a total of 80 tcf, according tothe EIA report. Environmental groups argue that there is an ecological basis for most of theserestrictions and that environmental assessments or impact statements are incomplete. From thisperspective, to relax these development restrictions would put the environment at greater risk.

Table 1. Rocky Mountain Natural GasResources

a The NPC study estimates that 41% (137 tcf) of the total amount of gas resources in the RockyMountain region is either closed (29 tcf) or restricted (108 tcf). Thus, 335 tcf would be the estimatedtotal amount of natural gas resources in the region as of 1999.

Significance of Access Restrictions

Substantial oil and gas reserves are located on public lands, but there are major policydisagreements about the potential importance of those reserves in meeting U.S. energy needs. TheRocky Mountain region represents an estimated 37% (293 tcf/788 tcf) of the unproved technicallyrecoverable natural gas resource base in the United States, onshore lower 48. (24) If the estimated 108 tcfof natural gas in the Rocky Mountain region currently restricted were produced, it could last between20-30 years, assuming a production rate of about 4 tcf to 5 tcf per year, according to the EIA; thiswould meet about 15% of projected annual U.S. demand. Currently, U.S. natural gas demand isbeing met with supplies from the outer continental shelf (OCS) (25%), imports (15%), the RockyMountain region (15%) and other onshore (45%). (25)

Testimony by The Wilderness Society (TWS) before the House Subcommittee on Energy andMineral Resources, March 15, 2001, based on the NPC report, asserted that the United States hassufficient natural gas supply to meet domestic needs for the next 40 years. (26) This conclusion was basedon annual demand growing from 22 tcf in 2001 to 31 tcf in 2015. Also, based on the NPC figure of1,466 trillion cubic feet as "technically recoverable resources in the U.S.," (27) of which 115 tcf isclassified as off-limits (39 tcf onshore, 76 tcf offshore), TWS concludes that 1,351 tcf of natural gascould be available for development in the future. In other words, from this perspective ample supplyis available now and possibly in the future without disturbing the resources in restricted or no-accessareas. The NPC report estimated that about 16% of the 1,351 tcf cited by TWS is subject torestrictions that may prevent development. (28)

The NPC argues that 70 tcf of Rocky Mountain natural gas is under restriction or leasestipulations and otherwise could be brought into production in the near term. The NPC contends thatthere are a number of impediments that could be resolved to ensure access to this gas in a timelyfashion, and proposes relaxing certain land-use constraints that would allow for more drilling onfederal lands in the intermountain west. Among these constraints include the use of "no surfaceoccupancy"designations that make resources "effectively" off-limits, use of stipulations to protectenvironmental resources that it believes are too restrictive, and old access restrictions that do notconsider new technology that could minimize damage to the environment. (29)

The RAND Corporation produced an Issue Paper in 2002 (30) asserting that the debateneeds to be more focused on the reserve category of the resource base. RAND's view is that accessrestrictions should be considered only for the resource category that is most viable -- or most likelyto be produced. Under this view, the amount of the resource considered to be restricted becomesmuch less. However, the analysis would be complicated by the rate at which oil and gas resourceswere assumed to be converted to reserves during the next 15-20 years.

Oil and Gas Resources and Production on Public Lands

Federal Onshore Oil and Gas Production

Total U.S. oil production was nearly 1.9 billion barrels in 2002, down from 2.5 billion barrelsin 1991. Oil production is forecast to fall by 0.4% annually, from 5.8 million barrels per day (mbd)in 2002 to 5.3 mbd in 2025. And oil imports are estimated to account for nearly 65% of total U.S.supply in 2025. Total production of natural gas was 19.4 tcf in 2002, up from 17.8 tcf in 1993. (31)

In 2002, oil production from federal onshore leases was estimated at 5.4% of all U.S. oilproduction (see Table 2 ). (32) Federal onshore oil production is concentrated in three stateswhich produce 79% of onshore federal oil: Wyoming (33%), New Mexico (29%), and California(17%). Oil production from onshore federal leases has fluctuated over the years but has generallybeen in decline over the past 10 years, falling from 133.5 million barrels in 1992 to about 100million barrels in 2002.

According to the EIA, U.S. production of natural gas varied between 18-20 tcf annuallybetween the years 1993-2002. Various projections show U.S. natural gas production reachingbetween 20 tcf - 24.3 tcf by 2025. (33) Imports from Canada are forecast to rise to 3.7 tcf in 2010, thenfall to 2.6 tcf in 2025. Higher EIA forecasts of Canadian natural gas for the year 2025 were adjusteddownward because of Canadian reports of declining gas production, less certain offshore suppliesand greater use domestically in the production of oil sands, expected to triple by 2025. Imports ofliquefied natural gas (LNG) were projected to rise from 170,000 bcf in 2002 to 4.8 tcf in 2025,according to the EIA. (34)

Table 2. U.S. Oil Production, 2002

Source : EIA, 2002, p. 22.

* Based on an Minerals Management Service (MMS) estimate for FY2003.

Gas production on public lands has increased to 2.2 tcf in 2002 from 1.7 tcf in 1993 andaccounts for 11.5% of all U.S. production (see Table 3 ). Of the 2.2 tcf total, New Mexico accountsfor 50% and Wyoming 35%; these rank as the top two states in natural gas production on publiclands, accounting for 85% (1.87 tcf) of the total. The federal onshore share of total U.S. domesticoil and gas production is not expected to change significantly in the near term. (35)

Table 3. U.S. Natural Gas Production,2002

* Based on MMS FY2003 estimate from Mineral Revenues Report..

Source : EIA Annual, 2002, p. 30.

U.S. Oil and Gas Reserves and Resources

Proved U.S. oil reserves (36) were 22.7 billion barrels of oil (BBO) as of December 31, 2002;natural gas liquids were estimated at 8 billion barrels and natural gas (dry) reserves are 187 tcf (37) according to EIA (see Table 4 ). Texas leads the United States in both oil and natural gas reserves (see Table 5 ). U.S. oilreserves have declined by 1.2 billion barrels over the past 10 years, while U.S. production declinedby 500 million barrels.

The 2.5 billion barrels of recoverable oil discovered in 2001 was three times greater than theaverage annual discovery since 1976 (890 million barrels). (38) In 2002, the discoverieswere about 950 million barrels or 6% over the annual discovery average since 1976. There are stillsubstantial amounts of oil available and likely to be produced from existing fields and fromundiscovered reserves in the United States, but the rate of production will likely continue decliningover the long term. As indicated by EIA, technically recoverable onshore and state offshore oilresources are estimated at 92 billion barrels, not all of which is likely to be recoverable. (39)

Table 4. U.S. Proved Oil and Gas Reserves and Production,1993-2002

Source : EIA, U.S. Crude Oil and Natural Gas, Annual Report, 2002.

Table 5. U.S. Proved Oil and Gas Reserves, by State,2002

Source : EIA, U.S. Crude Oil and Natural Gas and NGL Reserves 2002, Annual Report.

The natural gas story may be different, as the United States has seen its gas reserves increaseby 16.5 tcf (10%) since 1991; production has also risen. At the same time, U.S. gas imports haverisen to 17% from about 9% in 1991. (42) Annual discoveries were up 70% above the average since 1976(i.e., 22.8 tcf compared to12.7 tcf). Technically recoverable gas resources onshore and state offshoreare estimated by the EIA to be about 1,000 tcf, over five times the amount of current provedreserves. Over two-thirds of the total amount of onshore natural gas (proven and undiscovered) ison nonfederal land and may be available for exploration and development.

The 2002 oil and gas resource assessment records an estimated 1.9 billion barrels of oil, 183tcf of natural gas and 3.1 billion barrels of natural gas liquids as undiscovered resources locatedwithin five priority basins in the Rocky Mountain West. Over 90% of the undiscovered gas isclassified as unconventional; 25% (42 tcf) is coalbed methane. Of the proven reserves in five majorbasins in the Rocky Mountain region, oil and natural gas liquids (43) on public lands accountedfor 53.6%, while 60.1% of natural gas was on public lands (see Table 6 ).

Table 6. Rocky Mountain Proved Reserves (Five major basins)

Source : EPCA Study, p. A6-18, January 2003.

Recent estimates by the EIA indicate that federal onshore oil is 12.5% of all technicallyrecoverable oil. Natural gas on public lands is estimated to account for 22.3% of all technicallyrecoverable gas. EIA estimates undiscovered conventional oil to be 30.1 billion barrels andundiscovered conventional natural gas resources at 319.7 trillion cubic feet. The estimate forundiscovered unconventional natural gas is even greater at 358.7 tcf (see Table 7 ).

Table 7. Total Onshore Technically Recoverable Resources,2002

Source : EIA, Annual Report, 2002.

Growing Role of Coalbed Methane

Coalbed methane gas is natural gas dissolved in water and trapped in a coalbed. There areseveral important variables that determine the quantity of methane gas, including the depth of coal,pressure, temperature, thickness, and composition.

To extract coalbed methane (CBM), water must be removed from the coal by pumping,which drops the water pressure that traps the gas and allows the gas to flow. Some operators fracturecoal formations and allow water and gas to move out of the coal. Concerns have arisen concerninggroundwater contamination. The USGS reports that the water pumped out of coal beds can vary inquality. Some water can be discharged near the surface for reuse if "sufficiently fresh," or if the waterdoes not meet reuse standards, it can be disposed of by subsurface injection or surface discharge intowetlands, streams, or impoundments. (44) Water quality and water disposal have become central concernsin the production of CBM.

A 1980 tax credit (section 29) for unconventional fuel production provided a major incentivefor CBM development. Significant production of CBM began in 1987. Production has increasedfour-fold since 1991, and coalbed gas accounted for about 8% (1.6 tcf) of the 18.8 tcf of natural gasproduced in 2002 in the United States. (45) In 2002 there were 10,000 CBM wells also producing 1.65million barrels of water (46) per day. The leading producers are in New Mexico, Colorado,and Wyoming. Production rates vary widely because of the heterogenous geology of coalbeds. DOEestimates that out of the 39,000 new wells anticipated by 2010, 23,900 will be on federal lands. (47)

CBM reserves are still largely undeveloped. Of the estimated 700 tcf of coalbed methane inthe United States, only about 100 tcf are classified as economically recoverable. The previouslydiscussed EIA study of U.S. oil and gas resources found that of the 293 tcf of unproved technicallyrecoverable unconventional fuels in the Rocky Mountain region, about 46 tcf are coalbed methane,of which about 20% would fall under the "no access" category. Coalbed methane proved reserveswere 18.5 tcf in 2001, which was 10% of U.S. dry gas reserves. CBM reserves have more thandoubled since 1991. Two states, Colorado and New Mexico, account for more than half of U.S.CBM reserves. Wyoming, Utah, and Alabama also have significant reserves. The San JuanBasin (48) is the mostproductive. It contains 65% of known reserves and 80% of production. The Warrior Basin inAlabama is the second most productive, claiming 9% of U.S. production and 8% of reserves. (49) USGS estimates CBMresources in the Powder River Basin (PRB) at 39 tcf. (50)

The federal government owns over half the mineral rights in the PRB, while the majority ofthe surface rights are held privately, resulting in spilt-estates. However, most of the currentproduction of CBM is taking place on private lands. Over 80% of the land overlying of CBM wellsis privately or state held in Wyoming, and some surface owners oppose development and otherscontend they are not compensated fairly for surface use. (51) A number of concerns has come up regarding surface useagreements between the surface owner and the mineral lessee or mineral owner. The central concernfor the surface owner is receiving adequate compensation for damages from CBM or productionfrom other extractive industries. In Wyoming, stakeholders such as the Petroleum Association,ranchers and the Farm Bureau Federation established the Wyoming Split-Estate Initiative in 2002.They have created a new framework to help resolve conflicts between surface owners and mineralowners or lessees. (52)

CBM Environmental Issues

Environmental concerns about CBM production focus primarily on land disturbance andwater -- both surface and ground water issues. Production of CBM can involve not only wells butalso access roads, power lines, compressor stations, and waste water impoundments. Major issuesinclude surface infrastructure, the net amount of water removed, effects on the water table, and thesalinity levels and disposal of the water removed, which may affect wildlife, land and surface waterresources.

The process of hydraulic fracturing (53) for CBM production has come under closer scrutiny because ofconcerns over the possible impact of the injected fluids (such as diesel fuel) used in the process onunderground drinking water. A draft EPA report (54) concluded that there is no evidence of contamination of drinkingwater wells from CBM hydraulic fracturing. However, the EPA did express concern over the use ofdiesel fuel as an injection fluid because it contains many of the EPA's "constituents of concern",(chemicals). Thus, the EPA and the major companies using diesel fuel entered into anMemorandum of Agreement (MOA) in December 2003, to end the use of diesel fuel as an injectingfluid. Proposed energy legislation ( H.R. 6 and S. 2095 ) include provisionsthat would prohibit EPA from regulating underground injection of fluids for hydraulic fracturingpurposes under the Safe Drinking Water Act. (See CRS Report RS21673.)

Dennis Hemmer of the Wyoming Department of Environmental Quality explained in anenergy newsletter that most water from CBM production does not flow to surface supplies but ratherseeps into underground aquifers and formations. (55) As a result, wells being used for drinking water may becomepolluted with sodium-tainted water.

CBM production resulted in water discharges of 602 million barrels annually or 1.65 millionbarrels per day in 2002, typically into surface waters or holding ponds. Water is also reinjectedunderground. Environmentalists contend that holding ponds are like wastewater treatment pondsthat are unlined and leak into groundwater. There is concern about the lowering of the water tableand the effects on wells and water sources used by wildlife. The Wildlife Management Institute ofWashington D.C. argues that CBM production and the disposal of high volumes of water may leadto, among others things, the depletion of underground aquifers, the loss of natural vegetation, andaquatic life within waterways that receive CBM water. Further, the infrastructure required by CBMproduction may threaten wildlife habitats. (56)

In response to concerns over the impact of CBM on groundwater quality and quantity, BLMhas required CBM producers to drill two monitoring wells per township with CBM leases since1992. The cost of drilling each well is about $50,000, plus an additional $5,000 for monitoringequipment. After BLM review, it was established that one set of wells (one shallow and one deep)is required per four townships with CBM leases. The wells monitor both the water quality and waterlevels from CBM production. On private lands, monitoring wells are not required (57) .

The Interior Board of Land Appeals (IBLA) invalidated three leases in April 2002 becauseenvironmental issues related to CBM production, as discussed above, were not evaluatedsufficiently. Supplemental environmental assessments (EA) were prepared for the Powder RiverBasin to help determine where to develop CBM in areas already approved for leasing. (58) Generally, the results haveallowed more CBM drilling to occur; however, there have been new conditions imposed upon someproducers.

An environmental group, the Wyoming Outdoor Council (WOC), sued BLM to withdrawadditional leases -- four parcels totaling 3,800 acres -- from a June 2002 sale in Wyoming becauseit violated an April 26, 2002, IBLA ruling that directed the BLM to update a 1985 resourcemanagement plan (RMP) before offering CBM leases in the Powder River Basin. After the suit,BLM did not proceed with any lease sales on public lands with high CBM content, including the fourparcels that prompted the suit, while the IBLA ruling was being interpreted by Bureau attorneys. TheIBLA dismissed the case December 18, 2003. The Wyoming BLM office finalized a new EA andRMP and reportedly is anticipating approving 39,000 permits for new wells over a 10- year period.A decision to begin issuing permits was made by the DOI in July 2003. (59)

Outlook for Oil and Gas Development on Public Lands

Demand for oil is forecast to rise 1.6% annually to 28 mbd by 2025 in the EIA reference case.Because consumption would rise faster than domestic production, imports are projected to reachnearly 65%. U.S. demand for natural gas is forecast to rise 1.4% annually, reaching 31.4 tcf by 2025.

The outlook is mixed for increased oil and natural gas production from leases on U.S. publiclands or areas where the United States holds mineral rights. While domestic natural gas productionand natural gas imports are expected to rise, it is unclear how much of the domestic supply will comefrom public lands that are currently restricted or off-limits. The Bush Administration has initiatedactions to ease restrictions in instances where this can be done administratively. How muchopposition these initiatives will generate is unclear. The media has reported challenges based onalleged violations of BLM's multiple-use mandate. Areas statutorily removed would requirecongressional action to change their status. On available lands, production of conventional naturalgas is expected to remain steady, even though significantly more wells and higher-cost deeper wellswill be drilled. Onshore unconventional natural gas (over 70% located in the Rocky Mountainregion) is forecast to increase its share from 32% in 2002 to 43% of production in the lower 48 by2025. The central concern for industry is to have greater access to federal lands believed to possessoil and gas potential and to expedite the permitting process. Environmental groups and some surfaceowners are concerned that drilling and production would damage sensitive lands, wildlife habitat andsurface water and groundwater quality and quantity.

Meeting U.S. energy demand will likely occur by using a mix of increased domestic outputplus higher imports. The Rocky Mountain region might account for as much as 40% of U.S. naturalgas production in 2025, up from about 25% in 2002. (60) The United States will likely rely more on natural gas imports,primarily LNG from stable countries, as well as increased production from the deepwater OCS. A proposed Alaskan natural gas pipeline, if built, could provide 2.71 tcf by 2025.

Oil and gas firms continue worldwide exploration and development seeking the bestreturn for their investment; a significant resource base, political stability, and financing arefactors considered when making investment decisions. The United States scores well for politicalstability and its resource endowment is still attractive, but other concerns such as the impact onthe environment, on residents and society must be weighed in making public land use decisions.

Appendix A. Terms of an Oil and Gas Lease

The terms for a competitive lease are:

Maximum acreage -- 2,500 acres, except Alaska -- 5,760acres

$2/acre minimum bonus bid five-year term

Bond requirement -- $10,000

For noncompetitive leases, the terms are:

Maximum acreage -- 10,240 acres in all states

No minimum bonus bid

10-year term

$75 application filing fee

Bond requirement -- $10,000

Rents and royalties on competitive and noncompetitive leases are:

Rentals -- not less than $1.50/acre for 1-5 years

Rentals -- not less than $2/acre each year thereafter

Royalty -- not less than 12.5% in amount or value of the productionremoved or sold from the lease

Table 8. Oil and Natural Gas Production in U.S. OnshoreFederal Lands, 1991-2000

Source: MMS, Mineral Reserves, 2000, p.80.

The onshore leasing program brings in significant annual revenues to the U.S. Treasury.Revenues include bonus bids, rents and royalties (see Table 8 ). The revenues are collected by theMinerals Management Service (MMS, an agency within the Interior Department) and distributed tostates, the General Fund of the U.S. Treasury, and other designated programs. All states exceptAlaska receive 50% of the revenues collected from public land oil and gas leases within theirboundaries. Alaska receives 90% of all revenues collected. Revenues from federal leases varywidely over the years because of price fluctuations; for example, revenues increased significantlyin 2000 over 1999 because of higher oil and gas prices. The number of federal oil and gas leasesstood at 23,000 and encompassed over 17 million acres of federal public lands in 2001.

Appendix B. History of Public Land Withdrawals

The first public lands withdrawal took place in 1872 to establish Yellowstone National Park,and since that time Congress has created other national parks at regular intervals. (61) The National Park System(NPS) was created in 1916 to "conserve the scenery and the natural and historic objects and the wildlife [in national parks] and to provide for the enjoyment of the same in such a manner and by suchmeans to leave them unimpaired for the enjoyment of future generations" (16 U.S.C. 1). (62) In the early days of theNPS, its philosophy was not synchronized with the Forest Service (FS). The FS philosophy was that"all the resources of the forest reserves are for use and where conflicting interests exist the issue willbe resolved based on the greatest good for the greatest number of people in the long run." Earlytension arose between "conservationists" promoting National Parks and "utilitarians" promotingNational Forests. (63)

Sources of Withdrawal Authority

During the early 1900s the focus of the public lands withdrawal debate was on whether theCommander-in-Chief had authority to make the withdrawal order based on national security. Withdrawals were defined as an administration action/order that changed the designation of aspecific parcel of land from available to unavailable for activities ranging from homesteading toresource exploitation. The President acted as chief custodian of the public lands and with tacitapproval of Congress withdrew public land from entry or location by the private sector. TheConstitution vests authority over public lands in Congress rather than with the Executive, butPresidents have repeatedly exercised "an inherent power to withdraw" or reserve some lands. Aprime example is the establishment of military reservations out of public lands.

Withdrawals also occurred under the Antiquities Act of 1906 (16 U.S.C.A. 88, 433-431), theTaylor Grazing Act of 1934 (43 U.S.C. 315 et. seq.), the Organic Act of 1897 (16 U.S.C.A. 473),the Alaska Native Claims Settlement Act of 1971 (43 U.S.C.A. 1601 et. seq.) and the WildernessAct of 1964 (16 U.S.C.A. 1131-36). National monuments can be created by the executive branchthrough statutory delegation under the Antiquities Act. The President can reserve the "smallest areacompatible with the proper care and management" of the protected sites on federal lands that containhistoric landmarks, prehistoric structures, and other objects of scientific interest. Under the TaylorGrazing Act, 140 million acres were withdrawn from homesteading laws. The Organic Act was usedto regulate and designate recreation and "primitive areas." Under FLPMA, withdrawals can be madeby the executive branch or the Congress.

Congressional designations as "wilderness" were later considered essential by many becausean administrative wilderness designation could be revoked administratively any time. The AlaskaNative Claims Settlement Act withdrew large areas of Alaska from availability for resource use ordevelopment pending congressional disposition. The Wilderness Act required that the Forest Servicestudy 5.4 million acres of designated primitive areas and report on wilderness suitability. Wildernessis generally defined as an area "off limits to development to avoid destruction of pristinecharacteristics of nature." (64) The Wilderness Act states that "no federal lands shall bedesignated as wilderness areas except as provided for in the Wilderness Act or by an Act ofCongress" (16 U.S.C. 1131 (a)).

Currently, there are four types of withdrawal: First, there are instances where Congress hasthe sole authority to withdraw or reserve public lands. For example, creating National Parks andwilderness areas and in some cases national wildlife refuges can only be done by an act of Congress. Second, the executive branch has used power delegated to it by Congress under the previouslymentioned Antiquities Act of 1906 and the Pickett Act of 1910. Third, Congress may withdrawspecific resources such as when oil, gas, coal, and like minerals were removed from the GeneralMining Law of 1872. Lastly, there is the "general congressional" withdrawal, (65) which allows lands to beremoved from potential development pending "final disposition." (66)

Withdrawals Under FLPMA

Modern executive withdrawals are governed by FLPMA. (67) FLPMA (68) established a federal landuse management policy that includes land use planning based on a multiple-use approach that allowsfor significant public and congressional input. Sections of FLPMA detail procedures (see 43 U.S.C.1714 (d)) for the sales and acquisition of public lands, withdrawals, and exchanges of public lands.Under FLPMA, withdrawals can be made by the executive or the Congress. The withdrawal can betemporary or permanent.

FLPMA replaced the implied authority of the executive branch to withdraw public lands withspecifically defined procedures. Withdrawals of parcels exceeding 5,000 acres requirecongressional approval. The land can be withdrawn for 20 years subject to renewal. Proposedwithdrawals must be submitted to Congress with a report explaining the reasons for the withdrawalin detail, effects on the economy and environment, alternatives to withdrawal, how BLM isconsulting with other agencies and groups, and the geological and mineral potential of the areasproposed. The Secretary of the Interior, however, can make emergency withdrawals of any size forup to three years. A report must be available three months following a withdrawal.

FLPMA mandated a review of public land withdrawals in 11 Western states to determinewhether, and for how long, existing withdrawals should be continued (43 U.S.C. 1714(l)). Therewere millions of acres withdrawn prior to FLPMA. Under the law, the Secretary of the Interior candetermine whether and for how long the continuation of existing withdrawals are consistent withstatutory objectives of the programs under which lands were dedicated in the first place.

BLM continues to review approximately 70 million withdrawn acres, giving priority to about26 million acres that are expected to be returned by another agency to BLM, or, in the case of BLMwithdrawals, become available for one or more uses. As of November 2000, BLM had completedreviewing approximately 7 million withdrawn acres, mostly BLM and Bureau of Reclamation land;the withdrawals on more than 6 million of these acres have been revoked. According to the BLM Manual, retention of a withdrawal requires a compelling show of need, and an agency manager"recommending that lands not be opened to multiple use, particularly mining and mineral leasing.That manager must convince the BLM Director, the Secretary, and watchful segments of the public,that there is no reasonable alternative to continued withdrawal or classification." The review processis continuous over the next several years, in part because the withdrawals must be considered inBLM's planning process and be supported by documentation under the National EnvironmentalPolicy Act (NEPA).

Some lands, through revocation and terminations, could be developed for oil and gasresources. Other areas deemed not suitable for mineral development, will likely remained closed orrestricted.