Contents

• Introduction
• U.S. Crude Oil Production: Federal and Nonfederal Areas
• Federal Onshore Oil Production Data for Selected States
U.S. Natural Gas Production: Federal and Nonfederal Areas
• Federal Onshore Natural Gas Production Data for Selected States
EIA Projections
• Oil and Natural Gas Lease Data for Federal Lands
• Leased and Producing Acres
• Applications for Permits to Drill (APDs)
• Concerns over Nonproducing Leases
• Streamline Pilot
Issues for Congress
• Withdrawals and Access to Federal Land and Water
• Onshore Federal Land
• The Outer Continental Shelf
• Streamlining the Application for Permits to Drill
• Streamline Pilot
• The Trump Administration Initiative
• Congressional Activity
• Background
• State Management of Federal Energy Leases
• Congressional Activity
• State Authority
• Leased and Producing Acres

Summary

A number of legislative proposals and executive branch initiatives designed to increase domestic energy supply, enhance energy security, and/or amend the requirements of environmental statutes that apply to energy development are before the 114^115th Congress. Proposals range from leasing primarily in the Gulf of Mexico Outer Continental Shelf (OCS) via the Proposed Five-Year Program (PP) for FY2017-FY2022 or to implement the Proposed Draft for FY2010-FY2015 (a plan prepared by the Bush Administration), to a proposal to prohibit new fossil fuel leases on federal land. Several proposals include new revenue sharing provisions for coastal states.

A key question There are legislative proposals that include new revenue-sharing provisions for coastal states that would allow states the authority to manage federal energy leases within their state. The Trump Administration's theme of "energy dominance" has translated into several administration initiatives and executive orders, including the opening of the Arctic National Wildlife Refuge (ANWR) under the 2017 tax revision (P.L. 115-97), modifying monument designations, streamlining the permitting process for energy projects on federal land, and authorizing more leasing in the Outer Continental Shelf (OCS) under a new Draft Proposed Program (DPP) for 2019-2024. The new DPP would supersede the current five-year leasing program (2017-2022). Conversely, there are congressional proposals that oppose this Administration's policy direction. A key question addressed in this discussion is how much oil and gas is produced in the United States each year and how much of that comes from federal versus nonfederal areas. Oil production has fluctuated on federal landsrisen in federal areas (onshore and offshore) over the past 10 fiscal years but has increased dramaticallyat a faster rate on nonfederal lands. Nonfederal crude oil production has rapidly increased in the past few years, partlyprimarily due to betterimproved extraction technology, favorable geology, and the ease of leasing, more than doubling daily production between FY2006 and FY2015 (although because of recent low oil prices, production has dropped somewhat since a peak in mid-2015)FY2008 and FY2017. The federal share of total U.S. crude oil production fell from its peak at nearly 36% in FY2010 to 21% in FY2015.

2009 to less than 24% in 2017 at the same time overall production increased. Natural gas production in the United States overall dramatically increased each year since 2006, inhas steadily increased since 2008. In contrast, production on federal lands declined each year from FY2007 through FY2014. There was a small increase of 3.5% in FY2015 over FY20142009 through 2017. Much of the decline can be attributed to offshore production falling by over 50%. Onshore production declines were less dramatic. Federal natural gas production fluctuated around 30% of total U.S. production for much of the 1980s through the early 2000s, after which there began a steady decline through 2015. This picture of natural gas production is much different than that of federal crude oil in that federal natural gas had accounted for a much larger portion of total U.S. natural gas over the past few decades.

Another major issue that Congress may address is streamlining the processing of applications for permits to drill (APDs). Some Members contend that this would be one way to help boost energy production on federal lands. After a lease has been obtained, either competitively or noncompetitively, an application for a permit to drill must be approved for each oil and gas well. It took an average of 307 days for the Bureau of Land Management (BLM) to process (approve or deny) an onshore APD in FY2011, but that has declined to an average of 220 days in FY2015 (up from 194 days in FY2013). The BLM stated in its annual budget justifications (FY2012 and FY2016) that overall processing times per APD rose to such high levels in FY2011 and other years because of the complexity of the process, but they expect shorter time frames in the future.

The Energy Policy Act of 2005 (EPACT '05, P.L. 109-58) included a provision to initiate and fund a pilot program at seven Bureau of Land Management (BLM) field offices in an effort to streamline the permitting process for oil and gas leases on federal lands. Funding for the pilot program was made permanent under the FY2015 National Defense Authorization Act P.L. 113-291.

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Introduction¹

In 2015, the price of oil averaged about $49 per barrel (average composite price), down from $92 per barrel in 2014. Prices started dropping in June 2014, but dropped dramatically in December 2014, and by February 2016 crude oil prices were under around $30 per barrel. The Energy Information Administration (EIA) projects crude oil prices to average about $43 per barrel through 2016, but rising to about $52 per barrel in 2017.² Current prices have risen to about $50 per barrel. Prices are lower because of high global supply and a softening of demand. This lower price, if sustained, may impact long-term oil development and lower production volumes.

A number of legislative proposals designed to increase domestic energy supply, enhance security, and/or amend the requirements of environmental statutes that apply to energy development are before the 114^th Congress. Proposals range from authoring more leasing primarily in the Gulf of Mexico Outer Continental Shelf (OCS) via the Proposed Five-Year Program (PP)³ for FY2017-FY2022 or to implement the Proposed Draft for FY2010-FY2015 (a plan prepared by the Bush Administration), to a proposal to prohibit new fossil fuel leases on federal land. Several proposals include new revenue sharing provisions for coastal states.

A key question addressed in this discussion is how much oil and gas is produced in the United States each year and how much of that comes from federal versus nonfederal areas. Oil production has fluctuated on federal lands over the past 10 fiscal years but has increased dramatically on nonfederal lands. Nonfederal crude oil production rapidly increased in the past few years, primarily due to improved extraction technology, favorable geology, and the ease of leasing, more than doubling daily production between FY2006 and FY2015. The federal share of total U.S. crude oil production fell from its peak at nearly 36% in FY2010 to 21% in FY2015.

Natural gas prices, on the other hand, have remained low for the past several years, as the shale gas boom has resulted in rising supplies of natural gas. This has allowed gas to become much more competitive with coal for power generation. Overall, annual U.S. natural gas production rose by about 10 trillion cubic feet (tcf) since FY2006, while annual production on federal lands (onshore and offshore) fell by about 1.6 tcf (or nearly 26%) over the same time period. Natural gas production on nonfederal lands nearly doubled over the same time period (see Table 2). The big shale gas plays have been primarily on nonfederal lands and have attracted a significant portion of investment for natural gas development. The federal share of natural gas production fell from 32.8% in FY2006 to 16% in FY2015.

This report examines U.S. oil and natural gas production data for federal and nonfederal areas with an emphasis on the past five fiscal years of production.⁴55%. Onshore production declines were less steep.

Based on the federal government's 2008 inter-agency Phase III report, 113 million acres of onshore federal lands were open and accessible for oil and gas development and about 166 million acres were off-limits or inaccessible. The Bureau of Land Management (BLM—a land and mineral managing agency within the Department of the Interior) says it is addressing public concerns (including legal challenges) prior to a lease sale at a higher rate than in the past.

Congressional debate has been ongoing for decades over how much federal land should be available for energy development or other uses and how much should be set aside (e.g., off limits or restricted) for conservation and environmental concerns. There has been recent controversy over revoking or modifying previously withdrawn areas.

Another issue that Congress is addressing (for onshore federal lands) is streamlining the processing of applications for permits to drill (APDs). Some Members contend that this would be one way to help boost energy production on federal lands and would be consistent with the Trump Administration's energy policy.

Critics, including other Members of Congress and environmental groups, argue that the streamlining proposals would limit public input into land use decisions and possibly overlook important environmental impacts.

Introduction

In 2016, the price of oil averaged about $41 per barrel (average composite price), down from $92 per barrel in 2014. Oil prices have been on the rise since 2016, when the Organization of Petroleum Exporting Countries (OPEC) announced production cuts. The Energy Information Administration (EIA) projects crude oil prices to average about $65 per barrel through 2018, falling slightly to $63 per barrel in 2019.¹ In mid-October 2018, prices are fluctuating between $75-$80 per barrel.

A number of legislative proposals and executive branch initiatives designed to increase domestic energy supply, enhance energy security, or amend the requirements of environmental statutes that apply to energy development are before the 115^th Congress. There are legislative proposals that include new revenue-sharing provisions for coastal states (H.R. 4239) that would allow states the authority to manage federal energy leases within their state. The Trump Administration's theme of "energy dominance" has translated into several administration initiatives and executive orders, including the opening of ANWR under the 2017 tax revision (P.L. 115-97), modifying monument designations, streamlining the permitting process for energy projects on federal land, and authorizing more leasing in the Outer Continental Shelf (OCS) under a new Draft Proposed Program (DPP) for 2019-2024. The new DPP would supersede the current five-year leasing program (2017-2022). Conversely, there are congressional proposals that oppose this Administration's policy direction. For example, S. 750/H.R. 2242 would, among other things, prohibit the Bureau of Land Management (BLM) or the Bureau of Ocean Energy Management (BOEM) from renewing or extending any nonproducing fossil fuel lease on federal land or water, and H.R. 4426 seeks to promote renewable energy development and reform fossil fuel leasing and development on federal land.²

A key question addressed in this discussion is how much oil and gas is produced in the United States each year and how much of that comes from federal versus nonfederal areas. Oil production has risen in federal areas (onshore and offshore) over the past 10 years but has increased at a faster rate on nonfederal lands. Nonfederal crude oil production rapidly increased in the past few years, primarily due to improved extraction technology, favorable geology, and the ease of leasing, more than doubling daily production between FY2008 and FY2017 (see Table 1 and Figure 1). The federal share of total U.S. crude oil production fell from its peak at nearly 36% in 2009 to less than 24% in 2017.

U.S. natural gas prices, on the other hand, have remained low for the past several years, as the shale gas boom has resulted in rising supplies of natural gas. This has allowed gas to become more competitive with coal for power generation. Overall, annual U.S. natural gas production rose by about 7.5 trillion cubic feet (tcf) since 2008,³ while annual production on federal lands (onshore and offshore) fell by about 2.0 tcf (or nearly 32%) over the same time period. Natural gas production on nonfederal lands rose by 50% over the same time period.⁴ The big shale gas plays have been primarily on nonfederal lands and have attracted a significant portion of investment for natural gas development. The federal share of natural gas production fell from nearly 25% in 2008 to 13% in 2017.

This report presents issues that Congress may consider as it examines U.S. oil and natural gas production data for federal and nonfederal areas with an emphasis on the past 10 years of production.⁵

U.S. Crude Oil Production: Federal and Nonfederal Areas

Historically, according to Department of the Interior (DOI) data, crude oil production on federal lands (onshore and offshore) was consistently under 20% of total U.S. production until the late 1990s. Annual production then surged on federal lands (primarily offshore), rising to over 30% in the early 2000s and reaching a high point of nearly 36% in FY2010 (see Table 1).⁵ As a result of recent production increases on nonfederal lands, the question is raised whether nonfederal lands might regain a more dominant position of roughly 80%-85% of total U.S. crude oil production. The fact remains, however, that there2009.⁶ There are an estimated 5.3 billion barrels of proved oil reserves located on federal acreage onshore⁶,⁷ and another 4.33.9 billion barrels of proved reserves offshore (nearly all in the Gulf of Mexico).⁷8 Taken together, U.S. federal oil reserves equal about 2426% of all U.S. crude oil (and condensate) reserves, which are estimated at 39.935.2 billion barrels, according to the EIA.⁸9 Proved oil reserves are amounts accessible under current policy, prices, and technology. Higher prices often translate into higher reserve estimates.

Crude oil production on federal lands, particularly offshore, is likely to continue to make a significant contribution to the U.S energy supply picture and could remain consistently higher than previous decades depending on the level of total U.S. crude oil production. There is continued interest among some in Congress to open more federal lands for oil and gas development (e.g., the Arctic National Wildlife Refuge [ANWR] and areas offshore) and increase the speed of the permitting process. But having more lands accessible may not translate into higher levels of production on federal lands, as industry seeks out the most promising prospects and higher returns, which in recent years have come on more accessible nonfederal lands. Others in Congress would like to discontinue the leasing of fossil fuels altogether on federal lands or account for climate change impacts and other environmental impacts in its evaluation of energy leasing projects on federal land.

Figure 1. U.S. Crude Oil Production: Federal and Nonfederal Areas FY2006-FY2015 2008-2017 (million barrels per day)

Source: Federal data obtained from ONRR Production Data, http://www.onrr.gov. Nonfederal from EIA. Figure created by CRS. Note: This figure represents the data in Table 1 graphically.

Federal Onshore Oil Production Data for Selected States Crude oil production trends for selected states in Table 2 show significant increases in New Mexico and North Dakota and moderate increases in Colorado and Wyoming. California and Utah declined in production over the past few years. The six states below account for 96% of onshore oil production on federal land. Table 2. Crude Oil Production for Selected States on U.S. Federal Land

(thousand barrels/day)

Year	California	Colorado	New Mexico	North Dakota	Utah	Wyoming
2017	25.4	14.3	244.0	95.8	24.9	107.1
2016	30.2	12.0	211.0	73.6	25.6	104.6
2015	36.7	13.8	219.5	74.1	31.6	122.0
2014	40.2	14.9	181.0	57.6	63.7	107.5
2013	41.9	12.0	143.5	49.9	33.1	94.4
2012	41.6	12.2	121.5	44.4	30.7	89.9
2011	40.9	11.3	97.3	34.1	29.2	88.7
2010	38.2	10.4	86.1	26.7	29.7	88.9
2009	38.5	10.8	77.9	20.6	30.1	87.6
2008	36.9	11.4	70.5	20.2	27.8	89.4

Source: Office of Natural Resources Revenue (ONRR) http://www.onrr.gov (see Data and Statistics).

U.S. Natural Gas Production: Federal and Nonfederal Areas Natural gas production in the United States overall has steadily increased since 2008U.S. Natural Gas Production: Federal and Nonfederal Areas

Natural gas production in the United States overall has dramatically increased each year since 2006, while production on federal lands has declined each year from FY2007 to FY20152009 to 2017 (see Table 3 and Figure 2). Much of the decline can be attributed to offshore production falling by over 5055%. Onshore production declines, beginning in FY2010, were less dramatic. Federal natural gas production fluctuated around 30% of total U.S. production for much of the 1980s through the early 2000s, after which there began a steady decline (as a percent of U.S. total production) through FY20152017. For example, federal natural gas production declined from about 3325% of total U.S. production in FY2006 to 16gross withdrawals¹⁰ in 2008 to 13% of U.S. production in FY20152017; however, as noted below, this mostly reflects the dramaticsignificant growth in non-federalnonfederal production rather than the decline in total federal production. This picture of natural gas production is much different than that of federal crude oil in that federal natural gas had accounted for a much larger portion of total U.S. natural gas over the previous few decades.

Any increase in production of natural gas on federal lands is likely to be easily outpaced by increases on nonfederal lands, particularly because shale plays are primarily situated on nonfederal lands and are located where most of the growth in production has occurred in recent years and where future growth is projected to occur.

U.S. drynatural gas proved reserves are estimated at about 388.8341.1 trillion cubic feet (tcf) by the EIA,⁹11 of which the federal share is about 22% (69 tcf onshore, 166.6 tcf offshore).¹² Nearly all of the offshore proved reserves are located in the Central and Western Gulf of Mexico (GOM).

Figure 2. U.S. Natural Gas Production: Federal and Nonfederal Areas FY2006-FY2015 2008-2017

Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using salescalendar year data). Figure created by CRS. Note: This figure represents the data in Table 23 graphically. Federal Onshore Natural Gas Production Data for Selected States Production data below show that the leading natural gas producing states of Wyoming, New Mexico, and Colorado accounted for 88% of total onshore gas produced on federal land in 2017. Even though there were significant declines in Wyoming and New Mexico, they remain the top two states producing natural gas on federal leases. Table 4. Natural Gas Production for Selected States on U.S. Federal Land (billion cubic feet) Year Colorado New Mexico North Dakota Texas Utah Wyoming 2017 652.9 801.4 65.4 34.3 189.7 1,372.0 2016 636.8 789.0 48.2 38.3 227.4 1,440.7 2015 664.7 803.2 42.4 33.5 264.7 1548.0 2014 742.1 785.7 27.1 38.8 280.8 1,537.0 2013 725.2 782.7 22.2 45.9 293.3 1,586.0 2012 734.9 806.2 18.1 57.1 328.3 1,730.0 2011 726.4 820.1 13.9 34.4 301.2 1,836.0 2010 686.3 841.2 11.1 21.7 288.9 1,938.0 2009 669.6 895.5 10.0 23.4 305.0 1,939.0 2008 622.7 927.1 10.9 25.1 296.8 1,857.0 Source: ONRR. graphically.

EIA Projections

In the short term, the EIA estimates show oil production increasing in federal offshore areas (lower 48), from nearly 1.51.71 million barrels per day (mbd) in FY20152017 to 1.995 mbd in 2017,¹⁰2019, while EIA's longer-term estimates show a decrease in federal offshore (GOM) oil production overall, declining to 1.6 mbd during the 2030-2040 period.¹¹45 mbd in 2040.¹³ Overall, the EIA projects in the short term U.S. oil production reaching 8.211.70 mbd in 2019.¹⁴ Long mbd in 2017,¹² but long-term estimates show U.S. oil production rising to 11.3as high as 11.90 mbd by 2040.¹³15 According to these estimates, federal lower 48 offshore production in 2040 could account for about 1412% of total U.S. crude oil production. (See Table 35.)

Offshore dry natural gas production wasis projected to peak in 2019 at 1.36 tcf,¹⁶ projected to reverse a years-long decline in 2015 (Table 2 shows a slight increase in production), with annual production rising to 2.0 tcf in 2040. Even though these projections are presented in calendar years, 2.0 tcf of natural gas would be about 33% higher than current offshore production (provided in fiscal years in the earlier sections of this report) and would only account for about a 4.6% share of total U.S. natural gas production in 2040. (See Table 4.)

Oil and Natural Gas Lease Data for Federal Lands

Based on the federal government's 2008 inter-agency Phase III report, 113 million acres of onshore federal lands arewere open and accessible for oil and gas development and about 166 million acres arewere off-limits or inaccessible.¹⁴17 The BLM says it is addressing public concerns (including legal challenges) prior to a lease sale at a higher rate than in the past.

In 2015, 462017, 38% of onshore federal leases and 8171% of offshore leases were not in production (see Table 5). Offshore, most of the 1.7 billion acres of federal water are no longer under leasing and development moratoria. The current (FY2012-FY2017) five-year leasing program has lease sales scheduled in Western and Central Gulf of Mexico and parts of Alaska.¹⁵ In the offshore areas, 85% of the acreage that is leased is not in production, but may have an approved exploration or development plan.

Through FY2014, according to the BLM and the Bureau of Ocean Energy Management (BOEM), there were approximately 67 million acres of oil and gas leases in federal areas (onshore and offshore). About 34.6 million acres were located onshore and an additional 32.2 million acres were offshore. Approximately 12.7 million federal acres onshore and about 4.8 million federal acres offshore were in production. (See Table 5.)

Leased and Producing Acres

The number of federal producing acres may or may not be a function of how many acres are leased, and the number of acres leased may or may not correlate to production levels, and it is beyond the scope of this report to examine that issue thoroughly. (Table 6 provides data on the amount of federal acreage leased annually for onshore and offshore oil and gas development.) In recent years, some Members of Congress have proposed a $4/acre lease fee for nonproducing leases. This proposal grew out of efforts to promote more oil and gas drilling and development on public land and water (offshore) when gasoline prices spiked in 2006-2008. Some in Congress noted that there were many leases they believed were not being developed in a timely manner, while at the same time, others in Congress were advocating greater access to areas off-limits (such as ANWR and areas under leasing moratoria offshore). Higher rents for offshore leases were imposed by the Secretary of the Interior in 2009 to discourage holding unused leases and to move more leases into production, if possible.¹⁶ Rents escalate over time. The escalation in annual rents is significant, as they rise from $7/acre to $28/acre (in year-8 forward) in water depths less than 200 meters, and increase from $11/acre to $44/acre (in year-8 forward) in water depths between 200 and 400 meters. However, Congress has not established a similar escalation for onshore leases, as they remain $1.50/acre for years 1-5, and then rise to $2/acre thereafter.¹⁷

A nonproducing fee or an escalation of rents may not increase production but may increase the ratio of producing leases to active leases if some leaseholders relinquish their leases rather than paying the fee. Thus, there might be fewer "idle" leases and acreage not in production or exploration. The BLM can re-lease acreage that has been relinquished or passed over at a future lease sale.

Applications for Permits to Drill (APDs)

Another major issue that Congress may address (for onshore federal lands) is streamlining the processing of applications for permits to drill (APDs). Some Members contend that this would be one way to help boost energy production on federal lands. After a lease has been obtained, either competitively or noncompetitively, an application for a permit to drill must be approved for each oil and gas well.¹⁸ As stated in the Mineral Leasing Act, Section 226 (g) (for onshore federal lands), "no permit to drill on an oil and gas lease issued under this chapter may be granted without the analysis and approval by the Secretary concerned of a plan of operations covering proposed surface-disturbing activities within the lease area." The application form (APD form 3160-3) must include, among other things, a drilling plan, a surface use plan, and evidence of bond/surety coverage. The surface use plan should contain information on drillpad location, pad construction, the method for containment and waste disposal, and plans for surface reclamation.¹⁹

Prior to the Energy Policy Act of 2005 (P.L. 109-58, EPAct '05)24 This issue was addressed in the Energy Policy Act of 2005 (EPAct '05) (P.L. 109-58), providing new timelines and the introduction of a pilot program to streamline the permitting process. Streamline Pilot

EPAct '05 included a provision to initiate and fund a pilot program at seven BLM field offices in an effort to streamline the permitting process for oil and gas leases on federal lands. Initial results from the pilot project were published according to the timetable required by EPAct '05 (within three years after enactment). The conclusion was that the pilot made a difference in reducing the processing times for APDs at the pilot offices overall and increased the number of environmental inspections.

BLM noted that the National Environmental Policy Act (NEPA) processing time for APDs and rights of way (ROW) applications fell from 81 to 61 days or roughly 25% due to "colocation" of agency staff. BLM reported that the number of environmental inspections went up by 78% from FY2006 to FY2007.²⁵ BLM reported mixed results at the specific field offices. While some of the offices processed more permits in 2007 than they did in 2005, all the pilot sites reported more completed environmental inspections.²⁶ Funding for the pilot program was made permanent under the FY2015 National Defense Authorization Act (P.L. 113-291).

The Trump Administration Initiative

The Trump Administration introduced an initiative in Secretarial Order 3354 to seek ways to improve the oil and gas leasing system and ensure that the regulatory process serves its intended purpose. More specifically, the initiative seeks to clear up the backlog of applications for permits to drill and hold quarterly lease sales held by the BLM state field offices. An Instruction Memorandum (IM 2018-034) was published on February 1, 2018, that presents BLM policy with the intent to streamline (expedite) the oil and gas leasing process by "alleviating unnecessary impediments and burdens and to ensure quarterly lease sales are held as required in the MLA."

Congressional Activity

Congressional action includes several bills that would also seek to shorten the timelines for approving the permitting process for energy development. H.R. 6106 would clarify the categorical exclusions (CE) authorized under EPAct '05 and the use of additional CEs to expedite oil and gas permitting. There are provisions that would allow more flexibility in skipping the environmental review (ER) or an environmental impact statement (EIS) if action has only minimum impact on the human environment (not defined in the bills). S. 2151, a bill to streamline the oil and gas permitting process, would remove drilling permit requirements under the Federal Oil and Gas Royalty Management Act (FOGRMA) of 1982 for an action occurring within an oil and gas drilling or spacing unit under certain circumstances. H.R. 6088 would allow for a notification of permit to drill (NPD) to be submitted to the Secretary of the Interior in lieu of an application for permit to drill (APD) for developed fields, existing wells, and an approved land use plan and an environmental review that was prepared within the last 10 years under NEPA.

Critics, including some Members of Congress and environmental groups, argue that the proposals to shorten the review timelines would limit public input into land use decisions and overlook important environmental impacts.

Background Prior to the Energy Policy Act of 2005, a major concern that prompted the permit streamlining debate was the lengthy timetable to process an APD. The BLM attributed the longer timelines to the rewriting of outdated Resource Management Plans (RMPs). BLM revised several RMPs over the pastpreceding decade. Leading up to the provisions in EPAct '05 that attempted to streamline the permitting process, the BLM announced, in April 2003, new strategies to expedite the APD process. The new strategies included processing and conducting environmental analyses on multiple permit applications with similar characteristics, implementing geographic area development planning for an oil or gas field or an area within a field, establishing a standard operating practice agreement that identifies surface and drilling practices for oil and gas operators, allowing for a block survey of cultural resources, promoting consistent procedures across BLM offices, and revising relevant BLM manuals.²⁰27 EPAct '05 Section 366 (Deadline for Consideration of Application for Permits) provided a new timeline for BLM to process APDs.²¹28

Addressing a backlog, the previous and current Administrationscurrent Administration processed more APDs than itthey received from 2009 to 2013. It2017, with the exception of 2014 (See Table 8). They received far fewer applications over that period than had been received annually from 2006 to 2008. Even though the number of pending applications fell steadily from 2008 to 2013, the ratio of APDs pending to APDs processed was higher than during the period 2006-2008. The BLM expects to process about 4,500 APDs in each of the fiscal years 2016 and 2017300 APDs in 2018. In addition, as of the beginning of 2016 there were 7,000 approved APDs not in the exploration or production stages (approved but not drilled).²²

29

It took an average of 307 days for the BLM to process (approve or deny) an APD in FY2011, but that declined to an average of 220257 days in FY2015FY2016 (up from 194 days in FY2013).²³30 The BLM has stated in its annual budget justifications for FY2012 and FY2016 that overall processing times per APD rose to such high levels in FY2011 and other years because of the complexity of the process, but they expect shorter time frames in the future.

Some critics of this lengthy time frame highlight the relatively speedyfaster process for permit processing on private and state lands. However, crude oil and gas development on federal lands takes place in a wholly different regulatory framework than that of development on private lands.²⁴31 State agencies permit drilling activity on private lands within their states, with some approving permits within 10 business days of submission. This faster approval rate does not necessarily diminish the additional work required by the state to address other state requirements. But often, some surface management issues are negotiated between the producer and the individual land/mineral owner. A private land versus federal land permitting regime does not lend itself to an "apples-to-apples" comparison.

Concerns over Nonproducing Leases

A number of concerns may arise in the oil and gas leasing process that could delay or prevent oil and gas development from taking place, or might account for the relatively large number of leases held in nonproducing status. It should be noted that many leases expire without exploration or production ever occurring.

Below is a list of issues and practices which, individually or in combination, are often cited by various stakeholders to explain why more leases are not producing.

• Rig or equipment availability, particularly offshore;
• Oil and natural gas prices;
• High capital costs and available capital;
• Skilled labor shortages;
• Leases in the development cycle (e.g., conducting environmental reviews, permitting, or exploring) but not producing;
• Legal challenges that might delay or prevent development;
• No commercial discovery on a lease tract;
• Holding leases (because of the lack of capital or as "speculators") to sell or "farm out" at a later date;
• Ability to secure extensions on nonproducing leases;
• Ability to secure and being able to hold large number of lease tracts, often contiguous, to maximize return on investment; and
• The potential for inadequate coordination between the Department of the Interior's lease management and regulatory agencies (Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement) and other federal agencies to ensure protection of federal areas encompassing coastal and marine sanctuaries.

Streamline Pilot

EPAct '05 also included a provision to initiate and fund a pilot program at seven BLM field offices in an effort to streamline the permitting process for oil and gas leases on federal lands. Initial results from the pilot project were published according to the timetable required by EPAct '05 (within three years after enactment). The conclusion was that the pilot made a difference in improving the processing times for APDs at the pilot offices overall and increased the number of environmental inspections. The BLM noted that the National Environmental Policy Act (NEPA) processing time for APDs and rights of way (ROW) applications fell from 81 to 61 days or roughly 25% due to "colocation" of agency staff. BLM reported that the number of environmental inspections went up by 78% from FY2006 to FY2007.²⁵ The BLM reported mixed results at the specific field offices. While some of the offices processed more permits in 2007 than they did in 2005, all the pilot sites reported more completed environmental inspections.²⁶ Funding for the pilot program was made permanent under the FY2015 National Defense Authorization Act (P.L. 113-291).

Footnotes

1.	For a broader analysis of offshore oil and gas leasing and resources, see CRS Report R40645, U.S. Offshore Oil and Gas Resources: Prospects and Processes, by [author name scrubbed] and [author name scrubbed].
2.	Energy Information Administration (EIA), Short Term Energy Outlook, http://www.eia.gov/forecasts/steo, June 2016.
3.	The PP includes 13 lease sales (10 in the Gulf of Mexico and 3 offshore Alaska) over the five-year period.
4.	For more information on U.S. oil development, see CRS Report R43148, An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions, by [author name scrubbed] and [author name scrubbed], and CRS Report R43429, Federal Lands and Natural Resources: Overview and Selected Issues for the 114th Congress, coordinated by [author name scrubbed].
5.	The early data (1980 and 1990s) were taken from annual Mineral Revenue reports. The data used at that time were accounting data which are considered by the Office of Natural Resources Revenue (ONRR) as not very reliable. ONRR currently provides more useful fiscal year production volume data.
6.	U.S. Depts. of the Interior, Agriculture, and Energy, Inventory of Onshore Federal Oil and Natural Gas Resources and Restrictions to Their Development (Phase III), May 2008, available on the BLM website at http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/EPCA_III.html.
7State Management of Federal Energy Leases Congressional Activity Several legislative proposals introduced in the 115th Congress would amend the Mineral Leasing Act (MLA) to authorize states to manage either federal oil and gas leases, or all energy leases, on federal land.32 The intent of these bills is to expedite the energy leasing and permitting process, which is consistent with the Administration's strategy of U.S. "energy dominance." Most of the bills are similar in that the Secretary of the Interior could delegate (transfer) the responsibility of managing oil and gas or all energy leases once a state program has been established and an application showing the state's capacity and capability has been submitted. Thus, the question arises, do states have the capacity and capability to manage federal leases? The bills would further propose that, generally, any action by a state would not be subject to or considered a federal action, and would not require a federal permit or a federal license. Among other things, such state actions would not be subject to the Endangered Species Act (ESA) or NEPA. The bills would require that there be no effect on royalties or other federal revenues. There is language in three of the bills (H.R. 4239, S. 316, and S. 2319) that would prohibit the Secretary of the Interior from enforcing any federal regulation guidance or permit requirement for hydraulic fracturing for oil, gas or geothermal energy on any land in a state that has its own regulations for hydraulic fracturing. Supporters argue that under a state process, energy development on federal lands would occur more efficiently and expediously. Critics argue that without the NEPA process, public input and a more rigorous environmental review would be lost. State Authority BLM regulations authorize cooperative agreements between federal and state agencies for joint administration and enforcement of oil and gas leases on federal land. The state may require mineral developers to obtain certain permits from state agencies. Federal land managing agencies often delegate environmental regulatory roles to the state when they are as strict or stricter than federal policy. The MLA gives BLM discretionary power to attach conditions to mineral leases for protection of the interests of the United States, but provides that such provisions shall not be in conflict with the laws of the state. The MLA also includes a broad disclaimer against affecting "the rights of the state or other local authority to exercise any rights which they may have.…"33 FLPMA requires BLM's land use plans to provide for compliance with "applicable pollution control laws," but also to be as consistent as possible with state and local land use plans.34 In the offshore areas, states have significant input regarding energy development off their coastlines under both the Outer Continental Shelf Lands Act (43 U.S.C. Sec. 1331 et seq.) and the Coastal Zone Management Act of 1972 (P.L. 92-583, 16 U.S.C. Ch. 33). Leased and Producing Acres The number of federal producing acres may or may not be a function of how many acres are leased, and the number of acres leased may or may not correlate to production levels, and it is beyond the scope of this report to examine that issue thoroughly. (Table 9 provides data on the amount of federal acreage leased annually for onshore and offshore oil and gas development.) In recent years, some Members of Congress have proposed a $4/acre lease fee for nonproducing leases. This proposal grew out of efforts to promote more oil and gas drilling and development on public land and water (offshore) when gasoline prices spiked in 2006-2008. Some in Congress noted that there were many leases they believed were not being developed in a timely manner, while at the same time, others in Congress were advocating greater access to areas off-limits (such areas under leasing moratoria offshore). Higher rents for offshore leases were imposed by the Secretary of the Interior in 2009 to discourage holding unused leases and to move more leases into production, if possible.35 Rents escalate over time. The escalation in annual rents is significant, as they rise from $7/acre to $28/acre (in year-8 forward) in water depths less than 200 meters, and increase from $11/acre to $44/acre (in year-8 forward) in water depths between 200 and 400 meters. However, Congress has not established a similar escalation for onshore leases, as they remain $1.50/acre for years 1-5, and then rise to $2/acre thereafter.36 A nonproducing fee or an escalation of rents may not increase production but may increase the ratio of producing leases to active leases if some leaseholders relinquish their leases rather than pay the fee. Thus, there might be fewer "idle" leases and acreage not in production or exploration. The BLM can re-lease acreage that has been relinquished or passed over at a future lease sale. Table 9. Federal Onshore and Offshore Oil and Gas Leased Acreage Annually (2000-2017)
Year	Onshore Acres Leased	Offshore Acres Leased
2017

1,114,218

1,288,432

2016

577,317

771,238

2015

810,068

1,069,991

2014

1,197,852

2,090,265

2013

1,172,808

1,950,432

2012

1,752,060

2,988,168

2011

2,016,176

1,036,205

2010

1,353,663

2,369,101

2009

1,913,602

2,668,409

2008

2,615,259

7,996,920

2007

4,634,736

5,760,793

2006

4,385,378

4,122,703

2005

4,314,207

4,635,967

2004

4,157,121

4,689,702

2003

2,064,289

4,848,116

2002

2,812,606

4,192,904

2001

3,997,271

5,004,472

2000

2,650,493

2,919,920

Source: Onshore data obtained from BLM: Oil and Gas Statistics, accessed August 21, 2018. Offshore data obtained from BOEM, Oil and Gas Leasing, August 1, 2018 (https://www.boem.gov/Outer-Continental-Shelf-Lease-Sale-Statistics/).

Author Contact Information

Acknowledgments

Special thanks to Research Assistant Danielle Arostegui.

Footnotes

1.

Energy Information Administration (EIA), Short Term Energy Outlook, http://www.eia.gov/forecasts/steo, August 2018.

2.

The BLM is the land and mineral managing agency within the Department of the Interior. BOEM, also within the Department of the Interior, manages energy leasing in the OCS.

3.

Natural gas production is reported as gross withdrawals throughout this report, except where otherwise noted. Gross withdrawals is defined as the full volume of gas extracted from a well, including natural gas plant liquids and nonhydrocarbon gases, but excluding lease condensates.

4.

Federal data obtained from ONRR Production Data, http://www.onrr.gov (as of August 20, 2018). Total U.S. natural gas production data obtained from EIA, Natural Gas, Natural Gas Gross Withdrawals and Production, July 31, 2018, http://www/eia/gov.

5.

For more information on U.S. oil development, see CRS Report R43148, An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions, by [author name scrubbed] and [author name scrubbed], and CRS Report R43429, Federal Lands and Related Resources: Overview and Selected Issues for the 115th Congress, coordinated by [author name scrubbed].

6.

The early data (1980 and 1990s) were taken from annual Mineral Revenue reports. The data used at that time were accounting data which are considered by the Office of Natural Resources Revenue (ONRR) as not very reliable. ONRR currently provides more useful calendar-year production volume data.

2009 data was taken from the Office of Natural Resources Revenue (ONRR) Production Data, as of August 20, 2018, http://www.onrr.gov.

7.

U.S. Depts. of the Interior, Agriculture, and Energy, Inventory of Onshore Federal Oil and Natural Gas Resources and Restrictions to Their Development (Phase III), May 2008, available on the BLM website at http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/EPCA_III.html.

8.

BOEM, Estimated Oil and Gas Reserves, Gulf of Mexico, Pacific OCS Regions, as of December 20142016.

89.

EIA, U.S. Crude Oil and Natural Gas Proved Reserves, 2014, November 23, 2015Year-End 2016, February 13, 2018, http://www.eia.gov.

910.

EIA, U.S. Crude Oil and Natural Gas Proved Reserves, 2014, November 23, 2015, http://www.eia.gov. Dry gas is marketed production less extraction losses.

10.

EIA, Short Term Energy Outlook, http://www.eia.gov/forecasts/steo, June 2016.

11.

EIA, Early Release: Annual Energy Outlook, 2016, Annotated Summary of 2 Cases, May 17, 2016, p. 44.

12The Energy Information Administration defines gross withdrawals as "full well stream volume, including all natural gas plant liquids and all nonhydrocarbon gases but excluding lease condensate. Also includes amounts delivered as royalty payments or consumed infield operations." 11. Proved reserves are reported for natural gas wet, after lease separation. This is defined as a volume of natural gas remaining after lease condensates and nonhydrocarbon gases are removed. 12.

EIA, Natural Gas Proved Reserves, Wet after Lease Separation, 2016, February 13, 2018, https://www.eia.gov/dnav/ng/ng_enr_wals_a_EPG0_R21_Bcf_a.htm.

13.

EIA, Annual Energy Outlook, 2018, "Table: Oil and Gas Supply," February 8, 2018, https://www.eia.gov/outlooks/aeo/tables_ref.php.

14.

EIA, Short Term Energy Outlook, http://www.eia.gov/forecasts/steo, June 2016, p. 1August 2018, p. 31.

1315.

EIA, Annual Energy Outlook, February 8, 2018. 16.

The EIA does not estimate future natural gas gross withdrawals. Instead, estimates of future natural gas production are reported for dry production only. Dry production is marketed production less extraction losses.

Early Release, May 17, 2016, p. 44.

1417.

U.S. Depts.Departments of the Interior, Agriculture, and Energy, Inventory of Onshore Federal Oil and Natural Gas Resources and Restrictions to Their Development (Phase III), May 2008, available on the BLM website at http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/EPCA_III.html.

The agencies have not issued a similar analysis in the past 10 years.

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. Areas are closed to leasing pursuant to land withdrawals or other mechanisms. Much of this withdrawn land consists of wilderness areas, military bases, national parks and monuments, and other unique and environmentally sensitive areas that are unlikely to be reopened to oil and gas leasing given their current status. Some lands are closed to leasing pending land use planning or NEPA compliance, while other areas are closed because of federal land management decisions on endangered species habitat or historical sites. Some of those restricted areas may be opened by future administrative decisions.

1518.

For more information on the current five-year program, see CRS Report R44504, The Bureau of Ocean Energy Management's Five-Year Program for Offshore Oil and Gas Leasing: History and Final Program for 2017-2022, by [author name scrubbed], [author name scrubbed], and [author name scrubbed].

19.

Nearly all of the Eastern GOM is under a leasing moratorium until 2022 under the Gulf of Mexico Energy Security Act (P.L. 109-432). theThe North Aleutian Basin of Alaska was withdrawn from leasing under an executive order by the Obama Administration. Separately, President Obama withdrew selected parts of the Chukchi and Beaufort Seas of Alaska indefinitely in January 2015.

In December 2016, President Obama made further withdrawals in the Alaskan region, including the entire Chukchi Sea, almost all of the Beaufort Sea planning area, some planning areas in the North Bering Sea, as well as portions of the Atlantic Ocean region associated with major canyons. In April 2017, President Trump revoked all withdrawals except for those pertaining to National Marine Sanctuaries under executive order. 20 16.

The Secretary of the Interior has authority to establish rental rates under the Outer Continental Shelf Lands Act 43 U.S.C. §1337For more information on the proposed FY2019-2024 five-year plan, see CRS Report R44692, Five-Year Program for Federal Offshore Oil and Gas Leasing: Status and Issues in Brief, by [author name scrubbed].

1721.

DOI, Oil and Gas Lease Utilization, Onshore and Offshore, Updated Report to the President, May 2012, p. 18. (Authority is under 30 U.S.C. §226.)

18.

For more details on oil and gas leasing on federal lands, see CRS Report R40806, Energy Projects on Federal Lands: Leasing and Authorization, by [author name scrubbed].

19According to the Bureau of Ocean Energy Management, the Interior Department agency responsible for the management of offshore energy and mineral resources, undiscovered technically recoverable resources are "oil and gas that may be produced as a consequence of natural pressure, artificial lift, pressure maintenance, or other secondary recovery methods, but without any consideration of economic viability. They are primarily located outside of known fields." 22.

54 U.S.C. 320301(b).

23.

Under 43 U.S.C.A.§1702(j), FLPMA defines a withdrawal as "withholding an area of Federal land from settlement, sale, location or entry under some or all of the general land laws for the purpose of limiting activities under those laws in order to maintain other public values in the area or reserving the area for a particular public purpose or program; or transferring jurisdiction over an area of federal land from one department, bureau or agency to another department, bureau or agency."

24.

U.S. Department of the Interior, Bureau of Land Management (BLM), Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development, The Gold Book, Fourth Edition-Revised 2007, p. 8.

2025.

Bureau of Land Management, BLM Year Two Report, Section 365 of the Energy Policy Act of 2005 Pilot Project to Improve Federal Permit Coordination, February 2008.

26.

Ibid.

27.

DOI/BLM Instruction Memorandum No. 2003-152, Application for Permit to Drill Process Improvement#1-Comprehensive Strategies, April 14, 2003.

2128.

Within 10 days of receiving the application from the operator, BLM shall notify the operator as to whether the application is complete and also schedule a site visit. If the application is not complete, the operator then has 45 days to submit additional information to BLM to complete the application or the application is returned to the operator. Within 30 days of receiving a completed application the BLM will approve or defer the application. If deferred, the operator has up to two years to take specified actions to complete the application or face the possibility of being denied a permit.

2229.

U.S Department of the Interior, BLM Budget Justifications, Fiscal Year 2017, p. VII-109.

2330.

Bureau of Land Management, "Average Application for Permit to Drill (APD) Approval Timeframes: FY2005-FY2015," http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/statistics/apd_chart.html.

Oil and Gas Statistics, "Table 12: Time to Complete an APD," accessed August 21, 2018, https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/oil-and-gas-statistics. 2431.

Under the Federal Land Policy and Management Act (FLPMA), Resource Management Plans or Land Use Plans (43 U.S.C. 1712) are required for tracts or areas of public lands prior to development. The Bureau of Land Management (BLM) must consider environmental impacts during land-use planning when RMPs are developed and implemented. RMPs can cover large areas, often hundreds of thousands of acres across multiple counties. Through the land-use planning process, the BLM determines which lands with oil and gas potential will be made available for leasing.

2532.

Bureau of Land Management, BLM Year Two Report, Section 365 of the Energy Policy Act of 2005 Pilot Project to Improve Federal Permit Coordination, February 2008.

26.

Ibid.

See H.R. 3565, H.R. 4239, S. 2319, S. 335, and S. 316. 33.

30 U.S.C. Sec. 189.

34.

43 CFR part 1600, section 1610.3-2(a) and (b).

35.

The Secretary of the Interior has authority to establish rental rates under the Outer Continental Shelf Lands Act 43 U.S.C. §1337.

36.

DOI, Oil and Gas Lease Utilization, Onshore and Offshore, Updated Report to the President, May 2012, p. 18. (Authority is under 30 U.S.C. §226.)