U.S. Crude Oil and Natural Gas Production in
Federal and Non-Federal Areas
Marc Humphries
Specialist in Energy Policy
April 3, 2015
Congressional Research Service
7-5700
www.crs.gov
R42432
U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Summary
A number of proposals designed to increase domestic energy supply, enhance security, and/or
amend the requirements of environmental statutes that apply to energy development were before
the 113th Congress and are likely to be reintroduced in the 114th Congress. A key question 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 non-federal areas. Oil production has fluctuated on federal lands
over the past five fiscal years but has increased dramatically on non-federal lands. Non-federal
crude oil production has been rapidly increasing in the past few years, partly due to favorable
geology and the ease of leasing, rising by 3.0 million barrels per day (mbd) between FY2010 and
FY2014, causing the federal share of total U.S. crude oil production to fall from 36.4% to 21.4%.
Crude oil production on federal lands, particularly offshore, however, is likely to continue to
make a significant contribution to the U.S energy supply picture and could remain consistently
higher than previous decades, but still fall as a percent of total U.S. production, if production on
non-federal lands continues to rise at a faster rate.
The shale gas boom has resulted in rising supplies of natural gas. Overall, annual U.S. natural gas
production rose by about 4.7 trillion cubic feet (tcf) (or 21%) since FY2010, while production on
federal lands (onshore and offshore) fell by about 1.6 tcf, (or 31%) over the same time period.
Natural gas production on non-federal lands grew by 37% over the same time period. The big
shale gas plays have been primarily on non-federal lands and have attracted a significant portion
of investment for natural gas development.
There is however, 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 on more accessible non-federal lands.
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 all parties to process (approve or deny) an APD in FY2011, but
that has declined to an average of 227 days in FY2014 (up from 194 days in FY2013). The
Bureau of Land Management (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 timeframes in the future.
The Energy Policy Act of 2005 (EPACT ’05) included a provision to initiate and fund (funding
authorized through FY2015) 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.
There were legislative proposals in the 113th Congress that would have established the
streamlining pilot program as a permanent program. This topic may be revisited in the 114th
Congress.
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Contents
Introduction ...................................................................................................................................... 1
U.S. Crude Oil Production: Federal and Non-Federal Areas (Fiscal Year) ..................................... 1
U.S. Natural Gas Production: Federal and Non-Federal Areas (Fiscal Year) .................................. 3
EIA Projections .......................................................................................................................... 4
Oil and Natural Gas Lease Data for Federal Lands ................................................................... 5
Producing Acres......................................................................................................................... 6
Applications for Permits to Drill (APDs) .................................................................................. 7
Streamline Pilot ................................................................................................................... 9
Concerns over Non-Producing Leases ...................................................................................... 9
Figures
Figure 1. U.S. Crude Oil Production: Federal and Non-Federal Areas, FY2010-2014 ................... 3
Figure 2. U.S. Natural Gas Production: Federal and Non-Federal Areas FY2010-FY2014 ........... 4
Tables
Table 1. U.S. Crude Oil Production: Federal and Non-Federal Areas FY2010-FY2014 ................. 2
Table 2. U.S. Natural Gas Production: Federal and Non-Federal Areas FY2010-FY2014 ............ 4
Table 3. EIA Oil Production Projections .......................................................................................... 5
Table 4. EIA Natural Gas Production Projections ........................................................................... 5
Table 5. Oil and Gas Lease Data for Federal Lands, 2014 .............................................................. 6
Table 6. Onshore Oil and Gas Drilling Permits (FY2006-FY2014) ................................................ 8
Contacts
Author Contact Information........................................................................................................... 10
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Introduction1
In 2014, the price of oil averaged $92 per barrel (average composite price), down from $98 per
barrel in 2013. Prices dropped dramatically in December 2014, and by January 2015 crude oil
prices were under $50 per barrel. The Energy Information Administration (EIA) projects crude oil
prices to average in the lower to upper $50 per barrel range through 2015. This lower price, if
sustained, may impact long term oil development and lower production volumes.
A number of proposals designed to increase domestic energy supply, enhance security, and/or
amend the requirements of environmental statutes that apply to energy development were before
the 113th Congress and are likely to be reintroduced in the 114th Congress. A key question 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 non-federal areas. Oil production has fluctuated on federal lands
over the past five fiscal years but has increased dramatically on non-federal lands. Non-federal
crude oil production has been rapidly increasing in the past few years, partly due to favorable
geology and the ease of leasing, rising by 3.0 million barrels per day (mbd) between FY2010 and
FY2014, causing the federal share of total U.S. crude oil production to fall from 36.4% to 21.4%.
Natural gas prices, on the other hand, have remained low for the past several years, allowing gas
to become much more competitive with coal for power generation. The shale gas boom has
resulted in rising supplies of natural gas. Overall, annual U.S. natural gas production rose by
about 4.7 trillion cubic feet (tcf) (or 21%) since FY2010, while production on federal lands
(onshore and offshore) fell by about 1.6 tcf (or 31%) over the same time period. Natural gas
production on non-federal lands grew by 37% over the same time period (see Table 2). The big
shale gas plays have been primarily on non-federal lands and have attracted a significant portion
of investment for natural gas development.
This report examines U.S. oil and natural gas production data for federal and non-federal areas
with an emphasis on the past five fiscal years of production.2
U.S. Crude Oil Production: Federal and Non-Federal
Areas (Fiscal Year)
Historically, according to Department of the Interior (DOI) data, crude oil production on federal
lands 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 about 36% in FY2010.3 As a result of recent production increases on
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 Marc Humphries and Robert Pirog.
2 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 Michael Ratner and Mary Tiemann, and CRS Report R43429,
Federal Lands and Natural Resources: Overview and Selected Issues for the 114th Congress, coordinated by Katie
Hoover.
3 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 as not very reliable. The more useful
production volume data provided by ONRR now are based on fiscal year sales data.
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non-federal lands, the question is raised whether non-federal lands might regain a more dominant
position of roughly 80%-85% of total U.S. crude oil production. The fact remains, however, that
there are an estimated 5.3 billion barrels of proved oil reserves located on federal acreage onshore
and another 4.3 billion barrels of proved reserves offshore (nearly all in the Gulf of Mexico).
Taken together, U.S. federal oil reserves equal about 26% of all U.S. crude oil reserves, which are
estimated at 36.5 billion barrels, according to the EIA.4 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, but it could still fall as a percent of total U.S. production, if production on
non-federal lands continues to rise at a faster rate.
There is, however, 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 on more accessible non-federal lands.
Table 1. U.S. Crude Oil Production: Federal and Non-Federal Areas FY2010-FY2014
(Barrels per day)
Total Federal
Federal
Federal
Fiscal Year
U.S. Total
Non-Federal
(% of U.S. Total)
Offshore
Onshore
2014
8,324,000
6,545,000
1,779,000 (21.4)
1,372,400
406,200
2013
7,261,200
5,583,300
1,677,900 (23)
1,303,300
374,600
2012 6,249,000
4,603,500
1,645,500
(26.3)
1,302,800 342,700
2011
5,550,200
3,775,700
1,774,400 (32)
1,454,300
320,100
2010 5,446,500
3,466,300
1,980,200
(36.4)
1,685,200 295,000
Source: Federal data obtained from the Office of Natural Resources Revenue (ONRR) Statistics, as of January 5,
2015, http://www.onrr.gov (using sales year data), March 2015.
Notes: U.S. Fiscal Year Total data derived from EIA monthly production data contained in its publication
Petroleum and Other Liquids, U.S. Field Production of U.S. Crude Oil, March 30, 2015, http://www.eia.gov. Data
includes lease condensate, defined by EIA as a liquid hydrocarbon recovered from lease separators or field
facilities at associated and non-associated natural gas wells.
4 EIA, U.S. Crude Oil and Natural Gas Proved Reserves, 2013, December 2014, http://www.eia.gov.
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Figure 1. U.S. Crude Oil Production:
Federal and Non-Federal Areas, FY2010-2014
Million barrels per day (Mb/d)
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data). Non-federal
from EIA. Figure created by CRS.
U.S. Natural Gas Production: Federal and
Non-Federal Areas (Fiscal Year)
Natural gas production in the United States overall has dramatically increased each year since
2010, while production on federal lands has declined each year over the same period. Much of the
decline can be attributed to offshore production falling by about 50%. Onshore production
declines were less dramatic. Federal natural gas production fluctuated from around 30% of total
U.S. production for much of the 1980s through the early 2000s (34% of U.S. total in 2003), after
which there began a steady decline through 2014.5 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 that past few decades.
Any increase in production of natural gas on federal lands is likely to be easily outpaced by
increases on non-federal lands, particularly because shale plays are primarily situated on non-
federal lands and are where most of the growth in production is projected to occur.
U.S. dry gas proved reserves are estimated at about 354 tcf by the EIA,6 of which the federal
share is about 24% (69 tcf onshore, 16 tcf offshore). Nearly all of the offshore proved reserves are
located in the Central and Western Gulf of Mexico.
5 U.S. natural gas production on federal lands fell from about 7 trillion cubic feet in FY2003 to about 3.5 trillion cubic
feet in FY2014.
6 EIA, U.S. Crude Oil and Natural Gas Proved Reserves, 2013, December 2014, http://www.eia.gov. Dry gas is
marketed production less extraction losses.
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Table 2. U.S. Natural Gas Production:
Federal and Non-Federal Areas FY2010-FY2014
(billion cubic feet)
Total Federal
Federal
Federal
Fiscal Year
U.S. Total
Non-Federal
(% of U.S. Total)
Offshore
Onshore
2014
26,679
23,158
3,521 (13)
1,060
2,461
2013
25,551
21,733
3,818 (15)
1,189
2,629
2012 25,190
20,944
4,246
(16.9)
1,365 2,881
2011 23,510
18,934
4,576
(19.5)
1,682 2,894
2010
21,924
16,850
5,074 (23)
2,070
3,004
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data as of January 5,
2015), March 2015.
Notes: U.S. Fiscal Year Total data derived from EIA monthly production data in its publication “Natural Gas,
U.S. Natural Gas Marketed Production,” March 30, 2015, http://www.eia.gov.
Figure 2. U.S. Natural Gas Production:
Federal and Non-Federal Areas FY2010-FY2014
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data). Figure created
by CRS.
EIA Projections
While in the short-term, EIA estimates show oil production continuing to decline in federal
offshore areas, EIA’s longer-term estimates show a slight increase in federal offshore oil
production overall, from its nearly 1.4 mbd in FY2014 to 1.6-2.0 mbd in 2040.7 Overall, the EIA
7 EIA, Annual Energy Outlook 2014, December 2013. The release of the Annual Energy Outlook, 2015 is due later in
(continued...)
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projects in the short term, oil production reaching 9.5 mbd in 2016,8 but long-term estimates show
U.S. oil production falling to about 7.5 mbd by 2040 (essentially equal to 2013 production levels)
and at 9.0 mbd in 2025.9 According to these estimates, offshore production in 2040 could range
from 21% to 27% of total U.S. crude oil production. (See Table 3.)
Offshore natural gas production is projected to reverse a years-long decline in 2015, with annual
production rising as high as 2.9 tcf in 2040. Even though these projections are in calendar years,
2.9 tcf of natural gas is nearly triple the current offshore production (provided in fiscal years in
the earlier sections of this report) but would only account for about a 7.7% share of total U.S.
production in 2040. (See Table 4.)
Table 3. EIA Oil Production Projections
(million barrels per day)
Year
U.S. Offshore
U.S. Total
2025 1.6-2.0 9.0
2040
1.6-2.0
> 7.5
Source: EIA, Early Release Overview, 2014, Annual Energy Outlook, December 2013.
Table 4. EIA Natural Gas Production Projections
(trillion cubic feet per year)
Year
U.S. Offshore
U.S. Total
2025 1.7-2.9
31.93
2040 1.7-2.9
37.61
Source: EIA, Early Release Overview, 2014 Annual Energy Outlook, December 2013.
Oil and Natural Gas Lease Data for Federal Lands
Based on the federal government’s inter-agency’s Phase III report, there are 113 million acres of
onshore federal lands open and accessible for oil and gas development and about 166 million
acres off-limits or inaccessible.10 The Bureau of Land Management (BLM) is seeking to lease in
(...continued)
April 2015.
8 EIA, Short Term Energy Outlook, http://www.eia.gov/forecasts/steo, March 10, 2015.
9 Ibid.
10 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.
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, national parks and
monuments, and other unique and environmentally sensitive areas that are unlikely to ever be reopened to oil and gas
leasing. 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
(continued...)
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areas where it anticipates fewer legal challenges. The BLM also says it is addressing public
concerns prior to a lease sale at a higher rate than in the past. In 2014, 49% of onshore federal
leases and 37% of onshore federal acreage were not in production. Offshore, most of the 1.7
billion acres of federal water are no longer under leasing and development moratoria. The current
five-year leasing program has lease sales scheduled in Western and Central Gulf of Mexico
(GOM) and parts of Alaska.11 In the offshore areas, 85% of the acreage that is leased is not in
production, but may have an approved exploration or development plan.
According to the BLM and the Bureau of Ocean Energy Management (BOEM), there are
approximately 67 million acres of oil and gas leases in federal areas (onshore and offshore).
About 34.6 million acres are located onshore and an additional 32 million acres are offshore.
Approximately 12.7 million federal acres onshore and about 4.8 million federal acres offshore are
producing commercial volumes. (See Table 5.)
Table 5. Oil and Gas Lease Data for Federal Lands, 2014
Onshore Offshore
Acreage under lease
34.6 million acres
32 million acres
Leased acres producing
12.7 million acres
4.8 million acres
Leased acres not in production or exploration
21.9 million acres
27.3 million acres
Number of Leases
46,193
5,938
Producing Leases (or with approved DOCD)a 23,657 970
Percentage of producing leases
51
16
Source: Offshore data: DOI/BOEM, Combined Leasing Status Report, March 2015 (www.boem.gov). Onshore
data: DOI/BLM, Oil and Gas Statistics (www.blm.gov/wo/st/en)
a. A DOCD is a Development Operations Coordination Document that must be submitted for approval to
BOEM before development activities begin.
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, but it is
beyond the scope of this report to examine that issue thoroughly. In recent years, some members
of Congress have proposed a $4/acre lease fee for non-producing leases. This proposal grew out
of the efforts to open more public land and water (offshore) for oil and gas drilling and
development 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
(...continued)
restricted areas may be opened by future administrative decisions.
11 Nearly all of the Eastern GOM is under a leasing moratorium until 2022 under the Gulf of Mexico Energy Security
Act, and the 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.
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production, if possible. The escalation in annual rents is significant over time, 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,
there was no similar escalation for onshore leases, as they remain $1.50/acre for years 1-5, then
rise to $2/acre thereafter.12 Legislative options to increase the rents and royalties on federal oil
and gas leases have been debated in Congress. A non-producing fee or an escalation of rents may
not increase production but may increase the ratio of producing leases to active leases. 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 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.
As noted in the Mineral Leasing Act, Section 226 (g), “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.13
Prior to the Energy Policy Act of 2005 (P.L. 109-58, EPACT ’05), a major concern that prompted
the streamlining of permits debate was the lengthy timetable to process an APD. The BLM
attributed the longer timelines to the rewriting of outdated Resource Management Plans (RMPs).
There were several RMPs revised over the past 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 by oil and
gas operators, allowing for a block survey of cultural resources, promoting consistent procedures,
and revising relevant BLM manuals.14 EPACT ’05 Section 366 (Deadline for Consideration of
Application for Permits) provided a new timeline for BLM to process APDs.15
12 DOI, Oil and Gas Lease Utilization, Onshore and Offshore, Updated Report to the President, May 2012, p.18.
13 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.
14 DOI/BLM Instruction Memorandum No. 2003-152, Application for Permit to Drill Process Improvement#1-
Comprehensive Strategies, April 14, 2003.
15 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.
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While the current Administration processed more APDs than it received from 2009-2013, it
received far fewer applications over that period than had been received annually from 2006-2008.
Even though the number of pending applications has fallen steadily from 2008-2013, the ratio of
APDs pending to APDs processed was higher than during the period 2006-2008. In addition,
there are 6,000 approved APDs that are not in the exploration or production stages (approved but
not drilled).16 The BLM expected to process over 5,000 APDs in each of the fiscal years 2015 and
2016.
Table 6. Onshore Oil and Gas Drilling Permits (FY2006-FY2014)
APDs Pending at Year-
Fiscal Year
New APDs Received
Total APDs Processed
End
2014 5,316 4,924 4,121
2013 4,757 4,892 3,546
2012 5,240 5,861 3,683
2011 4,728 5,200 4,108
2010 4,251 5,237 4,603
2009 5,257 5,306 5,589
2008 7,884 7,846 5,638
2007 8,370 8,964 5,600
2006 10,492 8,854 6,194
Source: DOI/ BLM, FY2016 Budget Justification for years FY2011-FY2016. For earlier years, see DOI, Oil and Gas
Utilization, Onshore and Offshore, May 2012.
It took an average of 307 days for all parties to process (approve or deny) an APD in FY2011, but
that has declined to an average of 227 days in FY2014 (up from 194 days in FY2013).17 In
FY2006, it took the BLM an average of 127 days to process an APD, while in FY2014 it took
BLM 133 days (up from 95 days in FY2013). In FY2006, the industry took an average of 91 days
to complete an APD, but in 2014, the industry took 133 days (up from 99 days in FY2013). The
BLM 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 timeframes in the future.
Some critics of this lengthy timeframe highlight the relatively speedy process for permit
processing on private 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.18 State
16 U.S Department of the Interior, Oil and Gas Lease Utilization, Onshore and Offshore, Updated Report to the
President, May 2012, p. 14.
17 Bureau of Land Management, “Average Application for Permit to Drill (APD) Approval Timeframes: FY2005-
FY2014,” http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/statistics/apd_chart.html.
18 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.
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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 versus federal permitting regime does not lend itself to an “apples-to-apples” comparison.
Streamline Pilot
EPACT ’05 also included a provision to initiate and fund (funding authorized through FY2015) 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
FY2007.19 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.20 There were legislative proposals in the 113th Congress that would
have established the streamlining pilot program as a permanent program. This topic may be
revisited in the 114th Congress.
Concerns over Non-Producing 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 non-producing status. It should be noted that many leases expire without exploration or
production ever occurring.
Below is a list of often-cited issues which, individually or in combination, are 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;
19 Bureau of Land Management, BLM Year Two Report, Section 365 of EPACT 2005 Pilot Project to Improve Federal
Permit Coordination, February 2008.
20 Ibid.
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
• 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 non-producing leases;
• Securing and being able to hold large number of lease tracts, often contiguous, to
maximize return on their 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.
Author Contact Information
Marc Humphries
Specialist in Energy Policy
mhumphries@crs.loc.gov, 7-7264
Congressional Research Service
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