U.S. Crude Oil and Natural Gas Production in
Federal and Non-Federal Areas
Marc Humphries
Specialist in Energy Policy
March 7, 2013April 10, 2014
Congressional Research Service
7-5700
www.crs.gov
R42432
CRS Report for Congress
Prepared for Members and Committees of Congress
U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Summary
In 2012, oil prices ranged from $80 to $1102013, the price of oil averaged $98 per barrel (West Texas Intermediate spot price) and
remain high in early 2013. Congress is faced with, up from
$94 per barrel in 2012. Prices remain high in early 2014 (near $100 per barrel) and are projected
by the Energy Information Administration (EIA) to average in the mid-$90 per barrel range
through 2014. A number of proposals designed to increase domestic energy
supply, enhance
security, and/or amend the requirements of environmental statutes. A key
are before the 113th Congress.
A key question in this discussion is how much oil and gas is produced each in the United States each
year and how much of that
comes from federal and non-federal areas. On non-federal lands, there were modest fluctuations
in oil production from fiscal years (FY) 2008-2010, then a significant increase from FY2010 to
FY2012 increasing total U.S. oil production by about 1.1 million barrels per day over FY2007
production levels. All of the increase from FY2007 to FY2012 took place on non-federal lands,
and the federal share of total U.S. crude oil production fell by about seven percentage pointsversus non-federal areas. Oil production has
fluctuated on federal lands over the past five fiscal years but has increased dramatically on nonfederal lands. Non-federal crude oil production has been rapidly increasing in the past few years
partly due to favorable geology and the relative ease of leasing from private parties, rising by 2.1
million barrels per day (mbd) between FY2009-FY2013, causing the federal share of total U.S.
crude oil production to fall by nearly 11%.
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 four trillion
cubic feet (tcf) or 2019% since 2007FY2009, while production on federal lands
(onshore and offshore) fell
by about 23% and28%. Natural gas production on non-federal lands grew by 40%
33% over the same time period. The big shale gas plays are
primarily on non-federal lands and
are attracting a significant portion of investment for natural
gas development.
The number of producing acres may or may not be a function of how many acres are leased, and
the amountnumber of acres leased may or may not correlate to the amount of production, but 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 fashion, while at
the same time, others in Congress were pushing for greater access to areas off-limits (such as the
Arctic National Wildlife Refuge (ANWR) and areas under a 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.
Another major issue that the 113th Congress may seek to 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 non-competitively, an application for a permit to drill (APD)APD must be approved
for each oil and gas well. Despite
the new timeline for review (under the Energy Policy Act of
2005, P.L. 109-58), it took an
average of 307 days for all parties to process (approve or deny) an
APD in 2011, up from an
average of 218 days in 2006. The difference, however, is that in 2006 it
took the BLMBureau of Land
Management (BLM) an average of 127 days to process an APD, while in 2011 it took BLM 71
days. In
2006, the industry took an average of 91 days to complete an APD, but in 2011, industry
took 236
days. The BLM stated in its FY2012 and FY2013 budget justifications that overall processing
processing times per APD have increased because of the complexity of the process.
Congressional Research Service
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.......................................................................................................................... 5
Oil and Natural Gas Lease Data for Federal Lands ................................................................... 5
Producing Acres ......................................................................................................................... 6
Applications for Permits to Drill (APDs) .................................................................................. 7
Streamline Pilot ................................................................................................................... 9
Concerns .............................................................................................................................. 9
Conclusions .............over Non-Producing Leases .......................................................................................................... 10 9
Figures
Figure 1. U.S. Oil and Lease CondensateCrude Oil Production: Federal and Non-Federal Areas,
FY2007-2012 ................................................................................................................................ FY2009-2013 ................... 3
Figure 2. U.S. Natural Gas Production: Federal and Non-Federal Areas FY2007-FY2012FY2009-FY2013 ........... 4
Tables
Table 1. U.S. Crude Oil Production: Federal and Non-Federal Areas FY2007-FY2012FY2009-FY2013................. 2
Table 2. U.S. Natural Gas Production: Federal and Non-Federal Areas FY2007-FY2012FY2009-FY2013 ............ 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, 2012 .............................................................. 6
Table 6. Onshore Drilling Permits (FY2006-FY2011) .................................................................... 8
Contacts
Author Contact Information........................................................................................................... 10
Congressional Research Service
U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Introduction1
In 2012, oil prices ranged from $80 to $1102013, the price of oil averaged $98 per barrel (West Texas Intermediate spot price) and
remain high (above $90/barrel) in early 2013, up from
$94 per barrel in 2012. Prices remain high in early 2014 (near $100 per barrel) and are projected
by the Energy Information Administration (EIA) to average in the mid-$90 per barrel range
through 2014. A number of proposals designed to increase
domestic energy supply, enhance
security, and/or amend the requirements of environmental
statutes are before the 113th 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 nonfederalnon-federal areas. Oil production has
fluctuated on both federal and non-federal lands over the past
five fiscal years. On non-federal lands, there were modest fluctuations in oil production from
fiscal years (FY) 2008-2010, then a larger increase from FY2010 to FY2012, increasing total U.S.
oil production by about 1.1 million barrels per day over FY2007 production levels. All of the
increased production from FY2007 to FY2012 took place on non-federal lands, causing the
five fiscal years but has increased dramatically on nonfederal 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 2.1 million barrels per day
(mbd) between FY2009 and FY2013, causing the federal share of total U.S. crude oil production to fall by about seven percentage points (see Table
1)
to fall by nearly 11%.
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 four trillion
cubic feet (tcf) or 2019% since 2007FY2009, while production on federal lands
(onshore and offshore) fell
by about 33% and28%. Natural gas production on non-federal lands grew by 40%
33% over the same time period (see Table 2). The big shale gas
plays are primarily on non-federalnonfederal lands and are attracting 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 sixfive years of production.2
U.S. Crude Oil Production: Federal and Non-Federal
Areas (Fiscal Year)
Oil production has fluctuated widely between FY2007 and FY2012, yielding different results
when comparing various years. For example, when comparing fiscal year 2010 with 2007, growth
in the federal share of production was about 82% of the total. On federal lands, there was an
increase in production from FY2008-FY2009 and another increase in FY2010, but then declines
in FY2011 and FY2012, which brought production below FY2007 production levels. Historically,
according to the 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 when annual production
surged on federal lands (primarily offshore) rising to over 30% in the early 2000s and reaching a
high point of about 37% in FY2010.3 As a result of recent production increases on non-federal
1
For a broader analysis of offshore oil and gas leasing and resources, please see CRS Report R40645, U.S. Offshore
Oil and 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
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 5.3 billion barrels of proved oil reserves located on federal acreage onshore and another
5.6 billion barrels of proved reserves offshore (nearly all in the Gulf of Mexico). Taken together,
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 R40872, U.S. Fossil Fuel Resources: Terminology,
Reporting, and Summary, by Carl E. Behrens, Michael Ratner, and Carol GloverR43148, An Overview of Unconventional Oil and
Natural Gas: Resources and Federal Actions, by Michael Ratner and Mary Tiemann; CRS Report R41132, Outer
Continental Shelf Moratoria on Oil and Gas Development, by Curry L. Hagerty; and CRS Report R40237, Federal
Lands Managed by the Bureau of Land Management (BLM) and the Forest Service (FS): Issues in the 111th Congress,
coordinated by Ross W. Gorte and Carol Hardy Vincent.
3
The early data 1980 and 1990s was taken from annual Mineral Revenue reports. The data used at that time were
(continued...)
Congressional Research Service
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
lands, a question is raised as to whether non-federal lands will regain a more dominant position of
roughly 80%-85% of total U.S. crude oil production. The fact remains, however, that there are 5.3
billion barrels of proved oil reserves located on federal acreage onshore and another 5.6 billion
barrels of proved reserves offshore (nearly all in the Gulf of Mexico). Taken together, U.S. federal
R43429, Federal
Lands and Natural Resources: Overview and Selected Issues for the 113th 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.
Congressional Research Service
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
U.S. federal oil reserves equal about 43% of all U.S. crude oil reserves, which are estimated at 25.2 billion
29
billion barrels, according to the Energy Information Administration (EIA).EIA.4 Proved oil reserves are
amounts accessible under current
policy, prices, and technology.
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 highest returnshigher returns on more accessible non-federal lands.
Table 1. U.S. Crude Oil Production: Federal and Non-Federal Areas FY2007-FY2012FY2009-FY2013
(Barrels per day)
Total Federal
(% of U.S. Total)
Federal
Offshore
Federal
Onshore
4,580,800
1,627,400
(26)
1,295,900
331,500
5,565,000
3,850,000
1,715,000
(31)
1,408,200
306,800
2010
5,442,600
3,453,600
1,989,000
(36.5)
1,693,200
295,800
2009
5,219,300
3,487,800
1,731,500
(33)
1,443,800
287,700
2008
5,001,100
3,450,400
1,550,700
(31)
1,265,800
284,900
2007
5,083,400
3,387,500
1,695,900
(33)
1,408,200
287,700
Fiscal Year
U.S. Total
Non-Federal
2012
6,208,200
2011
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data).
Notes: U.S. Fiscal Year Total data derived from EIA production data as a percent of total U.S. fiscal year
production in Appendix A of EIA publication Sales of Fossil Fuels Produced from Federal and Indian Lands
FY2003-FY2011, March 2012. The federal production data is consistent with BLM and BOEM statements about
onshore and offshore federal production levels as percent of total U.S. crude oil production. 2012 U.S. Total
data obtained from EIA Monthly Energy Review, February 2013.
(...continued)
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 data5,576,700
1,658,300
(23)
1,294,000
364,465
6,241,000
4,598,000
1,643,000
(26.3)
1,303,300
339,700
2011
5,552,000
3,826,500
1,725,500
(31)
1,415,600
309,900
2010
5,438,800
3,463,700
1,975,100
(36.3)
1,680,300
294,800
2009
5,233,000
3,464,400
1,768,600
(33.8)
1,482,900
285,700
Fiscal Year
U.S. Total
Non-Federal
2013
7,235,000
2012
Source: Federal data obtained from the Office of Natural Resources Revenue (ONRR) Statistics, as of February
2014, http://www.onrr.gov (using sales year data), March 2014.
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 28, 2014, 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, 2011, August 2013, http://www.eia.gov.
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Figure 1. U.S. Oil and Lease CondensateCrude Oil Production:
Federal and Non-Federal Areas, FY2007-2012FY2009-2013
Million barrels per day (Mb/d)
Million barrels per day
8
US Total
6
Non-Federal
4
2
Federal Offshore
Federal Onshore
0
2009
2010
2011
2012
2013
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data). Figure created
by CRS.
U.S. Natural Gas Production: Federal and NonFederal Areas (Fiscal Year)
Natural gas production in the United States overall has dramatically increased each year since 2007
2009, while
production on federal lands has remained static or declined each year over the same period. Much
of the
decline can be attributed to offshore production falling by overabout 50%. Onshore production
declines were less dramatic. Federal natural gas production has 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 2012.42013.5 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 nonfederal lands and isare where most of the growth in production is projected to occur.
DryU.S. dry gas proved reserves wereare estimated at about 305334 tcf by the EIA,6 of which the federal
share is
about 2825% (69 tcf onshore;, 16 tcf offshore). Nearly all of the offshore proved reserves are located
located in the Central and Western Gulf of Mexico.
4
5
U.S. natural gas production on federal lands fell from about 7 trillion cubic feet in FY2003 to about 4.3 trillion cubic
feet in FY2012.FY2013.
6
EIA, U.S. Crude Oil and Natural Gas Proved Reserves, 2011, August 2013, http://www.eia.gov. Dry gas is marketed
(continued...)
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Table 2. U.S. Natural Gas Production:
Federal and Non-Federal Areas FY2007-FY2012FY2009-FY2013
(billion cubic feet)
U.S. Total
Non-Federal
Total Federal
(% of U.S. Total)
Federal
Offshore
Federal
Onshore
2012
24,493
20,242
4,251 (17.7)
1,330
2,921
2011
23,587
18,978
4,609 (19.5)
1,654
2,955
2010
22,012
16,846
5,166 (23.5)
2,098
3,068
2009
21,609
16,233
5,376 (24.9)
2,206
3,170
2008
21,007
15,460
5,547 (26.4)
2,496
3,051
2007
19,959
14,415
5,544 (27.8)
2,709
2,8352013
25,470
21,592
3,878 (15.2)
1,172
2,706
2012
25,208
20,938
4270 (16.9)
1,351
2,919
2011
23,539
18,953
4,586 (19.5)
1,668
2,918
2010
21,924
16,849
5,076 (23.2)
2,056
3,020
2009
21,612
16,241
5,372 (24.9)
2,205
3,167
Fiscal Year
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data), March 2014.
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 31, 2014, http://www.eia.gov.
Figure 2. U.S. Natural Gas Production:
Federal and Non-Federal Areas FY2009-FY2013
Billion cubic feet
30,000
US Total
25,000
Non-Federal
20,000
15,000
10,000
5,000
Federal Onshore
Federal Offshore
0
2009
2010
2011
2012
2013production data as a percent of total U.S. fiscal year
production in Appendix A of EIA publication Sales of Fossil Fuels Produced from Federal and Indian Lands
FY2003-FY2011, March 2012. The federal production data is consistent with BLM and BOEM statements about
onshore and offshore federal production levels as percent of total U.S. crude oil production. 2012 U.S. Total
data obtained from EIA Monthly Energy Review, February 2013.
Figure 2. U.S. Natural Gas Production:
Federal and Non-Federal Areas FY2007-FY2012
Source: Federal data obtained from ONRR Statistics, http://www.onrr.gov (using sales year data). Figure created
by CRS.
(...continued)
production less extraction losses.
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
EIA Projections
While in the short-term, EIA estimates show oil production continuing to decline in federal offshore
areas, their
offshore areas, EIA’s longer-term estimates show a slight increase in federal offshore oil
production overall,
from 1.3 mb/d in 2012 to 1.4-1.8 mb/d in 2040.51 mbd in 2013 to 1.6-2.0 mbd in 2040.7 Overall, the EIA projects U.S.
oil production to
rise from 5.59 mb/d in 2011 to about 6.13 mb/d by 2040 after reaching 6.7 mb/d in 2025.6
7.4 mbd in 2013 to about 7.5 mbd by 2040 (essentially equal to 2013
production levels) after reaching 9.0 mbd in 2025.8 According to these estimates, offshore
production in 2040 could range from 2321% to 2927% of total
U.S. crude oil production. (See Table
3.)
Offshore natural gas production is projected to reverse a years-long decline in 2015, rising to 2.8
tcf annual productionwith annual
production rising as high as 2.9 tcf in 2040. Even though these projections are in calendar years 2.8 tcf is still
very likely,
2.9 tcf of natural gas is still likely more than a doubling of current offshore production (provided
in fiscal years in the earlier
sections of this report) but would only account for an 8.4about 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
n/a
6.709.0
2040
1.4-1.8
6.136-2.0
7.48
Source: EIA 2013, Early Release projectionsOverview, 2014, Annual Energy Outlook, FebruaryDecember 2013.
Table 4. EIA Natural Gas Production Projections
(trillion cubic feet per year)
Year
U.S. Offshore
U.S. Total
2025
n/a
28.65
2040
2.8
33.2131.93
2040
1.7-2.9
37.61
Source: EIA 2013, Early Release Overview, 2014 Annual Energy Outlook, February 2013December 2013.
Oil and Natural Gas Lease Data for Federal LandsLands9
Currently, 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.710 The Bureau of Land
57
EIA, Early Release Overview, 2014, Annual Energy Outlook, FebruaryDecember 2013.
Ibid.
79
2013 data from BLM was not available at the time of this writing.
10
U.S. Depts. of the Interior, of Agriculture, and of Energy, Inventory of Onshore Federal Oil and Natural Gas
Resources 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
(continued...)
6(continued...)
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Management (BLM) is seeking to lease in areas where they anticipateit anticipates fewer legal challenges and
according to the BLM, they are; BLM
also says it is addressing public concerns prior to a lease sale at a higher rate
than in the past. In
2012, 56% of the onshore acreage under federal lease and 45% of federal
onshore leases 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.811 In the
offshore areas, 72% of
the acreage is leased and 75% of the leases are not in production.
According to the Bureau of Land Management (BLM)BLM and the Bureau of Ocean Energy
Management (BOEM), there are
approximately 72.8 million acres of oil and gas leases in federal
areas (onshore and offshore).
About 37.0 million acres are located onshore and an additional 35.8
million acres are located offshore.
Approximately 11.1 million federal acres onshore and about
6.6 million federal acres offshore are
producing commercial volumes. (See Table 5.)
Table 5. Oil and Gas Lease Data for Federal Lands, 2012
Onshore
Offshore
Acreage under lease
37.0 million acres
35.8 million acres
Acreage with approved exploration or development plan
(i.e., acreage in production or exploration)
16.3 million acres
10.1 million acres
Leased acres producing
11.1 million acres
6.6 million acres
Leased acres not in production or exploration
20.8 million acres
25.7 million acres
Number of Leases
49,213
6,621
Producing Leases (or with approved DOCD)a
27,300
1,611
Source: DOI, Oil and Gas Utilization—Onshore and Offshore, Report to the President, May 2012.
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 amount the number of acres leased may or may not correlate to the amount of productionproduction levels, but it is beyond
beyond the scope of this report to examine that issue thoroughly. In recent years, some members of
of Congress have proposed a $4/acre lease fee for non-producing leases. This proposal grew out of
of the efforts to open more public land and water (offshore) for oil and gas drilling and development
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 production if
(...continued)
(...continued)
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
restricted areas may be opened by future administrative decisions.
811
The Eastern GOM is under a leasing moratoria 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 current Administration.
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal 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. The escalation in rents ispossible. The escalation in rents are 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.912 A non-producing fee or an escalation of rents may not increase production but may
may reduce the ratio of producing leases to active leases. Thus, there might be fewer “idle” leases and
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 the 113th 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, sectionSection 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.1013
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 would attemptattempted to streamline the permitting process, the BLM announced, in April 2003,
new new
strategies to expedite the APD process. The new strategies included processing and
conducting conducting
environmental analyses on multiple permit applications with similar characteristics,
implementing 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.1114 EPACT ’05 Section 366 (Deadline
for Consideration of
Application for Permits) provided a new timeline for BLM to process
APDs.12
915
12
DOI, Oil and Gas Lease Utilization, Onshore and Offshore, Updated Report to the President, May 2012, p.18.
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.
1114
DOI/BLM Instruction Memorandum No. 2003-152, Application for Permit to Drill Process Improvement#1Comprehensive Strategies, April 14, 2003.
1215
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.
1013
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While the current Administration processed more APDs than it received from 2009-2011, it
received far fewer applications over that period than the previous Administration had received
from 2006-2008. AsEven though the number of pending applications has fallen steadily since 2008,
the ratio
of APDs pending to APDs processed was higher than during the period 2006-2008. In
addition,
there are 7,000 approved APDs that are not in the exploration or production stages
(approved but
not drilled).1316 The BLM expected to process more than 5,000 APDs in each of the
fiscal years
2012 and 2013.
Table 6. Onshore Drilling Permits (FY2006-FY2011)
Fiscal Year
APDs Received
APDs Processed
APDs Pending
2011
4,278
5,200
4,309
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: U.S. Department of the Interior, Oil and Gas Utilization, Onshore and Offshore, May 2012
Despite the new timeline for review, it.
It took an average of 307 days for all parties to process
(approve or deny) an APD in 2011, up frombut
that has declined to an average of 218 days in 2006.14 The difference
however, is that in 2006194 days in 2013.17 In 2006, it took the BLM an average of 127
days to process an APD, while in
2011 2013 it took BLM 7195 days. In 2006, the industry took an
average of 91 days to complete an APD,
but in 2011, the industry took 236 days. Thus, since 2006, it took the BLM 56 fewer days to
process APDs, while it took the industry145 days longer to submit a completed application.15 The
BLM stated 2013, the industry took 99 days. The BLM stated
in its FY2012 and FY2013 budget justifications that overall processing times per
APD have increased APD rose to
such high levels in 2011 because of the complexity of the process; now the permit process is
improving, resulting in shorter timeframes.
Some critics of this lengthy timeframe highlight the relatively speedy process for permit
processing on private lands. However, crude oil development on federal lands takes place in a
wholly different regulatory framework than that of oil development on private lands.1618 State
agencies permit drilling activity on private lands within their statestates, with some approving permits
within ten10 business days of submission. This faster approval rate does not necessarily diminish
the the
additional work required by the state to address other state requirements. But oftentimes,
often, some surface
management issues are negotiated between the oil producer and the individual
13 land/mineral
owner. A private versus federal permitting regime does not lend itself to an “apples-to-apples”
comparison.
16
U.S Department of the Interior, Oil and Gas Lease Utilization, Onshore and Offshore, Updated Report to the
President, May 2012, p. 14.
1417
Bureau of Land Management, “Average Application for Permit to Drill (APD) Approval Timeframes: FY2005FY2012,” http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/statistics/apd_chart.html.
15
Ibid.
1618
Under the Federal Land Policy and Management Act (FLPMA), Resource Management Plans or Land Use Plans (43
USCU.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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land/mineral owner. A private versus federal permitting regime does not lend itself to an “applesto-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. 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
FY2007.17 However, the19 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 completed
environmental inspections.18
Concerns20
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 used to explain
why more leases are not producing.
•
Rig or equipment availability, particularly offshore;
•
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 non-producing leases; and
•
Securing and being able to hold large number of lease tracts, often contiguous, to
maximize return on their investment;
17
Bureau of Land Management, BLM Year Two Report, Section 365 of EPACT 2005 Pilot Project to Improve Federal
Permit Coordination, February 2008.
18
Ibid.
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•
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.
Conclusions
There are substantial oil and natural gas reserves and resource potential in federal areas, many of
which are already accessible. Production from these areas will likely continue to make a
significant contribution to the U.S. energy supply picture, but any rise in production, as projected
by the EIA, will be outpaced by faster rising production in non-federal areas. A more efficient
permitting process may be an added incentive for the industry to invest in developing federal
resources, which may allow for some oil and gas to come onstream sooner, but in general, the
regulatory framework for developing resources on federal lands will likely remain more involved
and time-consuming than that on private land.
Author Contact Information
Marc Humphries
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
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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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
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