U.S. Offshore Oil and Gas Resources: Prospects and Processes
Congressional research reportFeb 10, 2012
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U.S. Offshore Oil and Gas Resources:
Prospects and Processes
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Specialist in Energy Policy
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Specialist in Energy Economics
February 10, 2012
Congressional Research Service
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R40645
CRS Report for Congress
Prepared for Members and Committees of Congress
U.S. Offshore Oil and Gas Resources: Prospects and Processes
Summary
Access to potential oil and gas resources under the U.S. Outer Continental Shelf (OCS) continues
to be controversial. Moratoria on leasing and development in certain areas were largely
eliminated in 2008 and 2009, although a few areas remain legislatively off limits to leasing. The
112th Congress may be unlikely to reinstate broad leasing moratoria, but some Members have
expressed interest in protecting areas (e.g., the Georges Bank or Northern California) or
establishing protective coastal buffers. Pressure to expand oil and gas supplies and protect coastal
environments and communities will likely lead Congress and the Administration to consider
carefully which areas to keep open to leasing and which to protect from development.
The oil spill that occurred on April 20, 2010, in the Gulf of Mexico brought increased attention to
offshore drilling risks. Consideration of offshore development for any purpose has raised
concerns over the protection of the marine and coastal environment.
On December 1, 2010, the Obama Administration announced its Revised Program (RP) for the
remainder of the 2007-2012 OCS Leasing Program. Among other components, the RP eliminates
five Alaskan lease sales (sales 209, 212, 214, 217, and 221) that had been contemplated in the
current lease program. Lease sale 219 in the Cook Inlet (scheduled to be held in 2011) was
cancelled because of a lack of industry interest. Further, the Obama Administration, under
executive authority, withdrew the North Aleutian Basin Planning Area from oil and gas leasing
activity until June 30, 2017. Public hearings began in 2010 on the scope of the 2012-2017 OCS
oil and gas leasing program, but three planning areas in Alaska (Cook Inlet, Chukchi, and
Beaufort Sea) are being scoped as well. On November 8, 2011, the Administration announced its
second draft proposed oil and gas leasing program for 2012-2017, which excludes all three
Atlantic and all four Pacific Coast planning areas at least through 2017. On December 14, 2011,
the Obama Administration held lease sale 218 in the Western Gulf of Mexico, the first sale since
the oil spill. A combined lease sale in the Central Gulf of Mexico (sale 216 and 222) is scheduled
for June 20, 2012, the final sale of the 2007-2012 leasing program.
Three bills that were passed in the House in May 2011 would address permitting efficiencies
(H.R. 1229), enforce certain lease sales in the current five-year planning period (H.R. 1230) and
require lease sales in the “most promising” OCS Planning Areas during the 2012-2017 Lease
Program (H.R. 1231). Most recently, legislation introduced in the House—the Energy Security
and Transportation Jobs Act (H.R. 3410) on November 14, 2011—combines some of the
language from bills passed earlier by the House (H.R. 1230 and H.R. 1231, discussed below) and
incorporates this proposal into H.R. 7, the American Energy and Infrastructure Jobs Act of 2012,
as Title XVII – Subtitle B.
Exploration and production proceed in stages during which increasing data provide increasing
certainty about volumes of oil and gas present. The Bureau of Ocean Energy Management
(BOEM) conducts assessments of undiscovered technically recoverable resources (UTRR) on the
U.S. OCS. The statistical certainty of these assessment estimates varies by region because the
availability of geologic data varies widely by region. One characteristic of the U.S. oil market, as
well as of world oil markets, is that the access to supply tends to be sequential. Normally, the first
source of oil used by a nation is domestic production, if available. The ultimate impact of oil and
gas development in offshore areas will depend on oil and gas prices, volumes of resources
actually discovered, infrastructure development, and restrictions placed on development, all of
which currently carry significant uncertainties.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Contents
Introduction and Background .......................................................................................................... 1
Legislative Issues ............................................................................................................................. 3
U.S. Oil and Gas Supply and Demand............................................................................................. 5
U.S. Oil Markets ........................................................................................................................ 5
U.S. Natural Gas Markets .......................................................................................................... 7
Economic Effects: Oil Market ................................................................................................. 10
Economic Effects: Natural Gas Market ................................................................................... 11
Greater OCS Access and Supply ............................................................................................. 12
Oil and Gas Reserves and Resources in the OCS .......................................................................... 13
Resource Estimation and Technological Change .............................................................. 13
OCS Resource Estimates ......................................................................................................... 15
Resource Estimates by Planning Area ..................................................................................... 16
Resource Estimates by Water Depth........................................................................................ 18
The OCS Leasing Process and Program ........................................................................................ 18
OCS Revenues ............................................................................................................................... 21
Revenue Sharing or Not?......................................................................................................... 21
Royalty Revenue Estimates ............................................................................................... 22
Environmental Concerns Associated with Offshore Exploration and Development ..................... 23
Offshore Areas Currently Protected......................................................................................... 23
General Environmental Regulations and Requirements for Offshore Exploration and
Production ............................................................................................................................ 25
Environmental Impact Statements ........................................................................................... 26
Oil Spills and Leaks................................................................................................................. 27
Seismic Surveys and Industrial Noise ..................................................................................... 29
Figures
Figure 1. OCS Natural Gas Resource Estimates ............................................................................ 15
Figure 2. Estimated Undiscovered, Economically Recoverable Resources .................................. 18
Tables
Table 1. U.S. Petroleum Consumption, 2004-2010 ......................................................................... 5
Table 2. U.S. Petroleum Supply, 2005-2010 .................................................................................... 6
Table 3. U.S. Offshore Crude Oil Production, 2004-2010 ............................................................... 7
Table 4. U.S. Proved Crude Oil Reserves, 2004-2009 ..................................................................... 7
Table 5. U.S. Natural Gas Consumption, 2004-2010....................................................................... 8
Table 6. U.S. Natural Gas Supply, 2004-2010 ................................................................................. 9
Table 7. U.S. Natural Gas Proved Reserves, 2004-2009 ............................................................... 10
Table 8. BOEM Assessment of UTRR in the OCS by Planning Areas ......................................... 16
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Table 9. Lease Expirations and Relinquishments, 2001-2007 ....................................................... 20
Table 10. Number of Spill Incidents Between 1996 and 2008 ...................................................... 28
Appendixes
Appendix. Definition of Terms ...................................................................................................... 30
Contacts
Author Contact Information........................................................................................................... 31
Acknowledgments ......................................................................................................................... 31
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Introduction and Background
In the wake of the Deepwater Horizon explosion and oil spill in the Gulf of Mexico on April 20,
2010, Congress continues to debate how much of the outer continental shelf (OCS) should be
available for oil and gas development. Having all of the OCS available is seen by some as a way
to increase domestic supply and improve U.S. energy security; others contend that OCS
development has risks for the coastal environment and coastal communities, and that other
options are available for energy security. The issue remains contentious, as industry would prefer
that the entire OCS remain available without any area exclusions such as buffer zones (e.g., 25 or
50 miles from the coastline) or withdrawals. Industry might be reluctant to invest in any new
resource assessments unless they are confident that the OCS will remain open for long-term
leasing and development. Environmental groups have argued to retain the OCS moratoria as
previously specified and that industry already has access to areas in the Gulf of Mexico with large
oil and gas reserves as well as several thousand leases not yet developed.
Following the Deepwater Horizon oil spill the Obama Administration saw an immediate need to
review and upgrade drilling and safety rules for offshore oil and gas development. The 2010 oil
spill changed the landscape for offshore oil and gas development. It has led to the reorganization
of the Minerals Management Service (MMS) (discussed below), rewriting safety rules for drilling
offshore, a suspension of permitting and drilling operations for some, review of the role of the
National Environmental Policy Act (NEPA) and use of categorical exclusions, and a revised
leasing program (announced December 1, 2010). Many in the oil and gas industry asserted that
the six-month suspension that was announced on May 28, 2010 (called a “de-facto” moratoria)
caused significant disruption of development activities and will lead to a reduction of oil and gas
production and other economic losses at least in the short term. However, according to the EIA
reference case, crude oil production from the lower 48 offshore region is estimated to increase
from 1.71 million barrels per day (mb/d) in 2009 to 1.81 mb/d in 2015.1 New deepwater drilling
permits were not issued until February 28, 2011.
The Former MMS2
On May 11, 2010, Secretary of the Interior Ken Salazar announced a plan to separate the safety
and environmental functions of the Minerals Management Service (MMS) from its leasing and
revenue collection function. The goal was to improve the efficiency and effectiveness of the
agency. Subsequently, on May 19, 2010, a decision was made by the Secretary to establish the
following three new entities to perform the functions of the MMS: Bureau of Ocean Energy
Management (BOEM), Bureau of Safety and Environmental Enforcement (BSEE), and the Office
of Natural Resources Revenue (ONRR).3 The transition to the new framework was completed on
October 1, 2011. Each of the three new entities has a director under the supervision of an assistant
secretary.4
1
Annual Energy Outlook, 2011, US. Energy Information Administration, April 2011.
This report may refer to the MMS in various references or elsewhere when unavoidable.
3
Additional information on the reassignment of MMS’s responsibilities is contained in Secretarial Order No. 3299, on
the DOI website at http://www.doi.gov/deepwaterhorizon/loader.cfm?csModule=security/getfile&PageID=32475.
4
Additional information on the reassignment of MMS’s responsibilities is contained in Secretarial Order No. 3299, on
the DOI website at http://www.doi.gov/deepwaterhorizon/loader.cfm?csModule=security/getfile&PageID=32475, and
in a September 30, 2011, DOI news release on the DOI website, at http://www.doi.gov/news/pressreleases/Interior(continued...)
2
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BOEM manages development of the nation’s offshore resources, including administering offshore
leasing, conducting environmental and economic analyses, and preparing resource evaluations.
BSEE enforces safety and environmental regulations. Functions include offshore regulatory
programs, research, and oil spill response. Field operations include permitting, inspections, and
environmental compliance. ONRR was established under the Office of the Department of the
Interior (DOI) Secretary to collect, account for, analyze, audit, and disburse revenues from energy
and mineral leases on the outer continental shelf, federal onshore, and American Indian lands.
Prior to the establishment of BOEM and BSEE, the Bureau of Ocean Energy Management,
Regulation, and Enforcement (BOEMRE) temporarily handled the activities now being
performed by BOEM and BSEE.
OCS Moratorium5
Oil and gas development moratoria in the OCS along the Atlantic and Pacific coasts, parts of
Alaska, and the Gulf of Mexico had been in place since 1982, as a result of public laws and
executive orders of the President. On July 14, 2008, President Bush lifted the executive
moratoria, which included planning areas along the Atlantic and Pacific coasts. On September 30,
2008, moratoria provisions in annual appropriations laws expired, allowing these areas to
potentially open for oil and gas leasing activity. The eastern Gulf of Mexico and a portion of the
central Gulf of Mexico, however, continue under a moratorium established by separate statute.
The Gulf of Mexico Energy Security Act of 2006 (GOMESA, P.L. 109-432), placed nearly all of
the eastern Gulf of Mexico under a leasing and drilling moratorium until 2022 but allowed
leasing in designated portions of the eastern Gulf. Thus, most of the eastern Gulf of Mexico
remains off limits to development because it was not part of the executive OCS ban that was
lifted by President Bush, nor part of the annual congressional ban that was not continued.
On December 1, 2010, the Obama Administration announced its Revised Program (RP) for the
remainder of the 2007-2012 OCS Leasing Program. Among other components, the RP eliminates
five Alaskan lease sales (sales 209, 212, 214, 217, and 221) that had been contemplated in the
current lease program. Lease sale 219 in the Cook Inlet (scheduled to be held in 2011) was
cancelled because of a lack of industry interest. Further, the Obama Administration, under
executive authority, withdrew the North Aleutian Basin Planning Area from oil and gas leasing
activity until June 30, 2017. The RP excludes all three Atlantic and all four Pacific Coast planning
areas at least through 2017.
Public hearings began in 2010 on the scope of the 2012-2017 OCS oil and gas leasing program,
but three planning areas in Alaska (Cook Inlet, Chukchi, and Beaufort Sea) are being scoped as
well. On November 8, 2011, the Administration announced its second draft proposed oil and gas
leasing program for 2012-2017, which excludes all three Atlantic and all four Pacific Coast
planning areas at least through 2017.
After the Deepwater Horizon oil spill, President Obama cancelled the August 2010 lease sale
(215) and the 2011 Mid-Atlantic lease sale (220). On December 14, 2011, the Obama
Administration held lease sale 218 in the Western Gulf of Mexico, the first sale since the oil spill.
(...continued)
Department-Completes-Reorganization-of-the-Former-MMS.cfm.
5
For a comprehensive review of the OCS moratorium see CRS Report R41132, Outer Continental Shelf Moratoria on
Oil and Gas Development, by (name redacted).
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A combined lease sale in the Central Gulf of Mexico (sale 216 and 222) is scheduled for June 20,
2012, the final sale of the 2007-2012 leasing program.
Recent high oil and gasoline prices have led to some renewed calls by some Members of
Congress for increased domestic oil development, a push to include more of the OCS in the next
five-year leasing program, and an assurance of already scheduled lease sales to go forward in the
current five-year program. These legislation proposals are discussed below.
This report examines questions around lifting the moratoria on OCS exploration and production
and the significance of the change on U.S. oil and natural gas supplies and markets. The report
presents the current U.S. oil and gas supply and demand picture and provides a discussion of
legislative issues, resource assessments, the leasing system, and environmental and social issues
associated with offshore oil and gas development.
Legislative Issues
Although reinstatement of a blanket moratorium on the OCS is unlikely in the 112th Congress,
some Members of Congress have argued for open but restricted access. The President has the
administrative authority to place areas of the OCS under a leasing and development moratoria,6
whereas legislated moratoria must be signed by the President. To open the Eastern Gulf of
Mexico, GOMESA would need to be amended or repealed. Congress and the Administration are
likely to give careful consideration to which parts of the OCS to keep open and which to protect
through leasing moratoria.
The Revised Program confirms plans to conduct a programmatic environmental impact statement
to determine if seismic studies should be conducted in the Mid and South Atlantic Planning
Areas. Would this additional information on the OCS prior to lease sales generate more interest in
those areas and possibly generate more revenue in higher bonus bids and high royalty rates
(16.7% or 18.75%) as part of the lease terms? A related controversial legislative issue is whether
coastal producing states should receive a greater share of those revenues. Revenue sharing is
discussed in more detail below.
Generally, proponents and opponents alike would argue that some sense of certainty is desirable.
Industry proponents, for example, want to know, if the industry invests in exploration and
development and finds oil and natural gas, whether it could then move forward with production.
And conversely, if certain areas are placed off limits or restricted, would those limitations remain
in place for the long term? The balance of this report provides information to inform this debate.
There are numerous House and Senate bills that would restructure the way the OCS is managed,
improve safety standards, make permitting more efficient, prevent or enforce lease sales, and
address oil spill and deepwater production issues.
Most recently, legislation introduced in the House—the Energy Security and Transportation Jobs
Act (H.R. 3410) on November 14, 2011—combines some of the language from bills passed
earlier by the House (H.R. 1230 and H.R. 1231, discussed below) and incorporates this proposal
into H.R. 7, the American Energy and Infrastructure Jobs Act of 2012, as Title XVII – Subtitle B.
6
OCSLA Section 12(a).
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Subtitle B of this act would require BOEM to offer lease sales in the most prospective areas in
each of the OCS Planning Areas for the 2012-2017 5-Year Leasing Program specifically, areas
that contain more than 2.5 billion barrels of oil or more than 7.5 trillion cubic feet of natural gas.
Increased production goals would be established at 3 million barrels per day (mb/d) of oil and 10
billion cubic feet (bcf) of natural gas per day by 2027. The bill would also require BOEM to offer
lease sales 216, 220, and 222 all within a year of enactment.
The bill would require a lease sale in southern California under Section 8 of Outer Continental
Shelf Lands Act (OCSLA), using onshore-based drilling technology by July 2014 and a lease sale
in the North Aleutian Basin (lease sale 214, which was cancelled by the Obama Administration).
There is a provision that would amend Section 18 of OCSLA allowing the Secretary of the
Interior to hold lease sales in areas identified by the Secretary to have the greatest potential for oil
and gas. The current moratorium in the Eastern Gulf of Mexico (EGoM) would be repealed, the
boundaries in the EGoM shifted, extending the moratorium until 2025, but allowing limited
leasing in years 2013, 2014, and 2015 in certain areas that would be considered exempt and with
the most oil and gas potential.
Provisions for revenue sharing with the coastal states would be phased in for new leasing revenue
(12.5% in the first leasing program 2012-2017 and 25% in the second leasing program) defined in
the bill, following enactment. The application of OCSLA would apply the U.S. Territories.
Title XV of H.R. 7 (also H.R. 3864) would appropriate the net increase in federal revenues from
offshore and onshore energy revenue from leasing and production based on enactment of Title
XVII of H.R. 7 (Subtitle B explained above) to the Highway Trust Fund.
Other earlier legislation (H.R. 1230—Restarting American Offshore Leasing Now Act) before
Congress would require the Secretary of the Interior to conduct four lease sales (lease sales 216,
218, 220, and 222) within about a year of the bill’s enactment. The Administration’s Revised
Program is scheduled to hold three more lease sales (sales 216, 218, and 222) in the Central or
Western Gulf of Mexico as part of the 2007-2012 Leasing Program. H.R. 1230, which would
reinstate lease sale 220, passed the House on May 5, 2011, by a vote of 266-149.
Another bill (H.R. 1229—Putting the Gulf of Mexico Back to Work Act), would provide a new
safety review and seek to expedite the drill permitting process by providing a new timeline for the
Secretary to make a final decision on the permit application. The bill includes language on
judicial reviews that would provide timelines, an exclusive venue for civil actions, and limits on
relief and attorney fees. The House passed H.R. 1229 on May 11, 2011, by a vote of 263-163. A
third bill (H.R. 1231—Reversing Presidents Obama’s Offshore Moratorium Act), which passed
the House on May 12, 2011 (243-179), would require BOEM to offer lease sales in the most
prospective areas in each of the OCS Planning Areas for the 2012-2017 5-Year Leasing Program,
specifically, areas that contain more than 2.5 billion barrels of oil or more than 7.5 trillion cubic
feet of natural gas. Increased production goals would be established at 3 million barrels per day
(mb/d) of oil and 10 billion cubic feet (bcf) of natural gas per day by 2027.
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U.S. Oil and Gas Supply and Demand
U.S. Oil Markets
Consumption of petroleum products in the United States has averaged more than 20 million
barrels per day (mbd) over the last seven years.
Table 1. U.S. Petroleum Consumption, 2004-2010
(millions of barrels per day)
Gasoline
All Petroleum
Products
2004
9.10
20.73
2005
9.16
20.80
2006
9.25
20.69
2007
9.29
20.68
2008
8.97
19.50
2009
8.98
18.77
2010
9.03
19.15
Source: Energy Information Administration, April 28, 2011, http://www.eia.doe.gov/petroleum/
data.cfm#consumption.
Table 1 shows that almost half of petroleum consumption has been in the form of motor gasoline
used in automobiles and light trucks. The data for 2008 through 2010, which show declines in
both gasoline and total petroleum product consumption, reflect two economic conditions. In the
second and third quarters of 2008, the price of oil increased to record-high levels, reaching over
$145 per barrel in July 2008. The high price of oil caused the price of gasoline to rise to over $4
per gallon in June and July 2008. High prices reduced consumer demand. In addition, the
recession and associated financial market problems that affected the U.S. economy in 2008 also
contributed to the decline in petroleum product demand by reducing consumer income and
wealth. The recession, which continued through 2009, resulted in negative demand growth.
Uncertainty surrounding supply disruptions resulting from political turmoil in the Middle East
and North Africa has again driven oil and gasoline prices up in 2011.
To meet the demand for oil to fuel the U.S. economy, the oil industry draws on two primary
sources: domestic production of crude oil, and imports. Other sources include natural gas
condensates and refinery expansion. The data in Table 2 show that domestic production of crude
oil declined through 2008, which is likely part of a sectoral decline in crude oil production that
has occurred since the mid-1970s when U.S. production peaked. Production increases in the Gulf
of Mexico and in the Bakken Formation in North Dakota have increased domestic production
over the last two years.
A characteristic of the U.S. oil market, as well as the world oil market, is that the access to supply
tends to be sequential. Normally, the first source of oil used by a nation is domestic production, if
available. Typically, the next source of U.S. supply is imports from countries that are not party to
the Organization of the Petroleum Exporting Countries (OPEC). Finally, residual demand is met
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
by OPEC.7 This behavior implies that, if the United States were to increase domestic production
of crude oil and natural gas condensates, the result is likely to be an equal decrease in imports (all
else being equal).
Table 2. U.S. Petroleum Supply, 2005-2010
(millions of barrels per day)
Crude Oil
Production
Net Imports
2005
5.18
12.55
2006
5.10
12.39
2007
5.06
12.04
2008
4.95
11.11
2009
5.36
9.68
2010
5.51
9.44
Source: Energy Information Administration, April 28, 2011, available at http://www.eia.doe.gov/dnav/pet/
pet_crd_crpdn_adc_mbblpd_a.htm and http://www.eia.doe.gov/dnav/pet/
pet_move_neti_a_ep00_IMN_mbblpd_a.htm.
Notes: Net imports includes both crude oil and petroleum products, net of U.S. exports.
The data in Table 2 suggest that even the price spike of 2008 was not sufficient to cause U.S.
crude oil production to increase, or even stop its decline. The reduction in consumption that
resulted from high prices and declining incomes in 2008 did contribute to the decline in imports
observed in 2008 and 2009, and increased domestic production contributed to further decline in
imports into 2011.
Offshore production of crude oil accounted for approximately 31% of total U.S. production of
crude oil in 2010, down from 35% in 2004. Offshore production, as shown in Table 3, is divided
between production in federal and state waters.8 Within the federal waters category, 96% of crude
oil production is from the Gulf of Mexico, and 3% is from waters off the coast of California. The
state offshore production is largely raised from the waters off Alaska, where 51% of the state
offshore total of crude oil was produced in 2010.
7
This viewpoint is substantiated by Energy Information Administration data which shows that excess supply in the
world tends to reside in OPEC.
8
State jurisdiction is typically limited to three nautical miles seaward of the baseline from which the breadth of the
territorial sea is measured. However, the state jurisdiction off the Gulf Coast of Florida and Texas extends nine nautical
miles and for Louisiana, three imperial nautical miles. Federal jurisdiction extends, typically, 200 nautical miles
seaward of the baseline from which the breadth of the territorial sea is measured.
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Table 3. U.S. Offshore Crude Oil Production, 2004-2010
(millions of barrels per day)
Federal Offshore
State Offshore
2004
1.528
0.356
2005
1.355
0.358
2006
1.371
0.331
2007
1.344
0.312
2008
1.218
0.280
2009
1.584
0.119
2010
1.695
0.118
Source: Energy Information Administration, available at http://www.eia.doe.gov/dnav/pet/
pet_crd_crpdn_adc_mbblpd_a.htm.
Production of crude oil depends on the existence of a proved reserve base. The data in Table 4
show that, while the total of U.S. proved reserves has varied over a narrow range, total reserves
were about 8% lower in 2009 than 2004. The reserve base in the federal offshore areas declined
by approximately 17% in the five-year period 2004-2009. The decline in the proved reserve base
occurred during a period of high crude oil prices, suggesting that the economic incentive existed
to explore and develop new reserves, but other constraints might have prevented this activity in
federal OCS areas until recently.
Table 4. U.S. Proved Crude Oil Reserves, 2004-2009
(billions of barrels)
Federal Offshore
Total Reserves
2004
4.691
21.371
2005
4.483
21.757
2006
4.096
20.972
2007
3.905
21.317
2008
3.903
19.121
2009
4.129
20.682
Source: Energy Information Administration, available at http://www.eia.doe.gov/dnav/pet/
pet_crd_pres_dcu_RUSF_a.htm.
As the reserve base in any field declines, and natural pressures within the reserve deposit weaken,
the result is declining output of crude oil. This decline in production from the declining reserve
base can be mitigated through the use of enhanced recovery methods, but the result is higher
production costs.
U.S. Natural Gas Markets
Consumption of natural gas in the United States has averaged more than 22 trillion cubic feet (tcf)
over the last six years.
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Table 5. U.S. Natural Gas Consumption, 2004-2010
(trillion cubic feet)
Delivered to
Consumers
Total
Consumption
2004
20.725
22.388
2005
20.315
22.010
2006
19.958
21.685
2007
21.249
23.097
2008
21.400
23.268
2009
20.965
22.839
2010
22.168
24.132
Source: Energy Information Administration, available at http://www.eia.doe.gov/dnav/ng/
ng_cons_sum_dcu_nus_a.htm.
Notes: The difference between total consumption and quantities delivered to consumers is gas used in the
production and distribution of natural gas.
Of the total natural gas delivered to consumers in 2010, approximately 22% was used by
residential customers, 14% was used by commercial customers, 30% was used by industrial
customers, and 33% was used in electric power generation. Over the six-year period 2004-2009,
residential consumption was relatively constant, with variations attributable to weather conditions
and the price. Commercial consumption was also relatively constant, while industrial
consumption declined by about 15% but rebounded in 2010. The use of natural gas for electric
power generation increased by approximately 26% over the period 2005-2010.
The 2004-2010 consumption patterns in the United States reflect the different reactions to price
variations within the various sectors. Derived demand (indirect demand) from residential,
commercial, and electric power generation sources are not very price sensitive, because the
primary, ultimate uses of natural gas in these sectors are considered necessities: space heating,
lighting, and appliances. Industrial consumption tends to be more price sensitive because when
natural gas is used as a production input, as, for example, in the fertilizer industry, the produced
goods are subject to international competition, and as a result passing on cost increases to
consumers is difficult.
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Table 6. U.S. Natural Gas Supply, 2004-2010
(trillion cubic feet)
Domestic
Production
Imports
2004
18.59
4.26
2005
18.05
4.34
2006
18.50
4.19
2007
19.27
4.60
2008
20.16
3.98
2009
20.58
3.75
2010
21.58
3.74
Source: Energy Information Administration, available at http://www.eia.doe.gov/dnav/ng/
ng_move_impc_s1_a.htm.
In 2010, the United States produced about 85% of the natural gas it consumed (see Table 6), with
90% of the imported volumes arriving from Canada via pipeline. Liquefied Natural Gas (LNG)
accounted for about 10% of imports, or about 1.3% of total U.S. consumption. LNG imports
largely come from Trinidad, although Egypt, Norway, and Yemen also exported to the United
States in 2010.
U.S. production of natural gas has increased since 2005 as production from unconventional
sources such as shale gas has increased. As a result of increased domestic production, and the
effects of the economic recession, imports decreased in 2008 through 2011. LNG, which some
had forecast to become a major source of natural gas for the U.S. economy, has remained a minor
component in natural gas supply, at about 1%-2%.
U.S. proved natural gas reserves have increased over the period 2004-2009 by approximately
42% (see Table 7), even though the nation has relied heavily on domestic supplies for
consumption over the period. This result can be attributed to the development of new, nonconventional deposits of natural gas, such as shale gas. Offshore reserves have declined by about
35% over the period.
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Table 7. U.S. Natural Gas Proved Reserves, 2004-2009
(trillion cubic feet)
Offshore
State
Offshore
Federal
Total
Reserves
2004
0.79
19.3
192.5
2005
0.77
17.8
204.4
2006
0.82
15.4
211.0
2007
0.72
14.3
237.7
2008
1.17
13.5
244.6
2009
0.99
12.6
272.5
Source: Energy Information Administration, available at http://www.eia.doe.gov/dnav/ng/
ng_enr_dry_dcu_NUS_a.htm.
Notes: Reserves are proved, dry gas.
Economic Effects: Oil Market
The oil market is global in scope. Changes in demand and/or supply that take place anywhere in
the world are likely to affect virtually all consumers. The key measure of price, in many cases,
has responded with high upward volatility to increases in demand. This price behavior is the
result of the short-run inelasticity of demand for oil and petroleum products. In the short run,
inelastic demand implies that an increase in price will have a relatively smaller effect on the
quantity demanded. This conclusion starts with a price change and traces through how the change
affects quantities. The reverse logic is also true: that small changes in quantity can lead to
relatively larger changes in price. During the period of high oil prices from 2004 through 2008,
the actual quantity of oil demanded was exceeding forecast demand due to higher-than-expected
world growth rates of gross domestic product. High growth in demand reduced excess capacity to
minimal levels and resulted in substantial oil price increases. The economic recession moderated
world growth of gross domestic product and led to stabilized demand for petroleum, but demand
is rising again as the global economy emerges from the recession.
Another factor that increased in importance over the 2004 through 2010 period was the
emergence of oil contracts as financial assets through commodity market investment. The extent
to which this factor has contributed to the volatility of oil prices is still being debated, but the
emergence of “financial oil” has introduced the role of expectations more directly into oil prices.
Both the short-run inelasticity of demand and the increased sensitivity of the oil market to
expectations are likely to play a role in determining the degree to which opening offshore areas
with potential resource deposits affects the price of oil.
Analyses of the effect on oil markets of opening offshore restricted areas to exploration, and
ultimately, production, are complicated by the uncertainties inherent in existing reserve estimates.
Since no exploration, or assessment of reserves, has taken place using modern technology, the
available estimates are likely to be speculative (see detailed discussion below). Time is also a
factor. Even if exploration of the tracts began this year, it would likely be 5 to 10 years before
significant production reached the market. For these reasons, rigorous quantitative estimates on
the effect on the price of oil of opening these offshore areas are not possible.
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Qualitative observations are possible. If the oil markets are slack when the key decision points
(leasing, exploration, production, etc.) are reached, meaning significant excess capacity exists,
and oil exporting nations are restricting production, the effect on oil prices will likely be minimal.
If the markets are tight, the effects could be noticeable, and contribute to lower prices. The
inelasticity of demand plays a role here, as a relatively small increase in expected reserves and
production could have a disproportionate effect on price.
However, a lower price of oil will generally also encourage consumption. Increased consumption
of cheaper oil could lead to increased carbon emissions. As long as the increased consumption
due to lower price was met through the use of new domestic supplies, energy dependence would
not increase. The development of the offshore areas would be unlikely to eliminate U.S.
dependence on foreign energy sources, and may not even reduce it. Other, older fields are likely
to have experienced further declines in production by the time the new offshore sources go into
production, meaning that it is likely that these new sources of production might only replace other
lost output, thereby reducing the rate of increase of foreign dependence.
The cost of developing these resources also depends on the state of the oil market at the key
decision points. Construction and development costs for petroleum investment projects have
escalated sharply in recent years, reflecting the high market prices for oil. Delays and rapidly
increasing costs reduced the economic viability of many projects. Although a low oil price
environment might reduce the tightness in construction and development markets, reducing costs,
it may also reduce the likelihood that the oil companies would find development of these
resources to be economically viable.
Economic Effects: Natural Gas Market
Natural gas markets differ from the oil market in that they are not global, but regional. As shown
in Table 6, above, virtually all U.S. natural gas consumption comes from U.S. or Canadian
sources. The only link between regional natural gas markets is through LNG, but the rapidly
growing market for LNG predicted earlier in this decade has failed to materialize. LNG is still
largely characterized by long-term, two-party supply and purchase agreements. In the North
American market, LNG plays the role of making up marginal short-falls in the demand and
supply balance. As production from domestic onshore shale gas deposits increases, the role of
LNG in the U.S. market will likely be small.
In this regional market structure, the development of new, offshore U.S. supplies could have a
significant impact on the domestic price of natural gas, as well as contributing to U.S. energy
independence of this fuel. Although the price of natural gas has not shown the same degree of
volatility as oil, the United States has been among the highest-priced regions in the world. High
prices have caused residential consumers to allocate a greater portion of their budgets to home
heating expenses. Industrial users either lose sales to overseas competitors, or cease U.S.
production when domestic natural gas prices rise too much beyond those observed in other
regions of the world.
The development of offshore natural gas resources is likely to further retard the development of a
growing LNG system in the United States. Terminals for the re-gasification of LNG have proven
to be difficult to site and permit, and expensive to build. If domestic natural gas resources, close
to existing collection and distribution systems, at least in the Gulf of Mexico, could be developed,
the LNG terminals might prove to be redundant, depending on the volumes of natural gas that
ultimately might be recovered. Offshore natural gas development, though commonly associated
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with offshore oil production, will likely be less competitive in a market environment dominated
by onshore shale gas development.
Greater OCS Access and Supply
The Energy Information Administration (EIA) of the Department of Energy projects that U.S. oil
production would increase from today’s 5.3 million barrels per day (mbd) to 6.0 mbd by 2035
with complete OCS access.9 Because of its significant reserves and resource potential, most of the
projected increase in production would reportedly come from the OCS. The EIA projected that
offshore crude oil production would increase from about 1.7 mbd to 1.9 mbd by 2035 when
including complete access to the OCS. The EIA projected that production from the Atlantic and
Pacific planning areas after 2014 and from the Eastern Gulf of Mexico after 2025 would add
500,000 barrels of oil per day to U.S. supply. Offshore natural gas production in the lower 48
states is expected to remain roughly stable out to 2035. The EIA estimates are uncertain as to how
much of the increased natural gas production would come from the formerly restricted areas.10
Based on mean resource estimates by the Bureau of Ocean Energy Management (BOEM), a
report prepared for the American Petroleum Institute by ICF International estimates an increase in
OCS production from areas formerly off limits of 286,000 barrels per day in 2030.11 When ICF
assumed a much larger resource base for the OCS (and without the leasing moratoria), oil
production from those areas formerly off limits were estimated to increase 900,000 barrels per
day in 2030.
A National Petroleum Council (NPC) study estimated that 1 million barrels of oil and 3.8 billion
cubic feet of natural gas per day could be added to U.S. oil and gas supply by 2025 from areas
formerly off limits if the OCS remains open along with a cumulative investment of as much as
$98 billion in exploration and development projects.12
Prior to lifting the OCS moratoria, the BOEM projected a rise in U.S. domestic production on
federal lands coming primarily from deepwater offshore areas in the Gulf of Mexico. According
to the BOEM, deepwater oil already accounts for more than 70% of offshore production and
18.5% of total U.S. crude oil production. The number of shallow water lease sales dropped from
418 in 2002 to 264 in 2008, while the number of deepwater lease sales rose from 281 to 633
during that same period. Deepwater (1,000 feet or 305 meters) lease sales spiked in 1997 at 1,110,
following the Deepwater Royalty Relief Act of 1995. Further, it is notable that there has been
increasing exploration activity and an increase in reported finds in the Gulf of Mexico in ultradeep (5,000 feet or more) waters since 2003.
However, new production realized from newly opened areas would depend on many factors, such
as oil and gas prices; investment in exploration, discoveries, and infrastructure; and regulatory
requirements. Is the development scenario likely to change much if the OCS remains open?
9
U.S. DOE/EIA, Annual Energy Outlook, 2011.
Testimony of Dr. Howard Gruenspecht, Acting Administrator, EIA, U.S. Department of Energy, before the
Subcommittee on Energy and Minerals, Committee on Natural Resources, U.S. House of Representatives, March 5,
2009.
11
ICF International, Strengthening Our Economy: The Untapped U.S. Oil and Gas Resources, prepared for American
Petroleum Institute, December 5, 2008.
12
National Petroleum Council, Facing the Hard Truths About Energy, p.168, July 2007.
10
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Development of deepwater leases is much more expensive than shallow water leases, but the
reserve potential and payoff are likely to be much greater in the deeper water. The Gulf oil spill of
April 2010 and the associated changes in regulation of deepwater development has slowed
offshore development in the short term, but the long-term impacts on offshore oil and gas
development are uncertain.
Oil and Gas Reserves and Resources in the OCS
Meaningful projections or forecasts of the impact of offshore oil and gas production from areas
previously under moratorium must rely on technical estimates of the oil and gas resources in
those areas. The quality of those assessments depends on the methodology used and the data
available. This section provides an overview of the quality of current assessments of the
unexplored offshore areas and the uncertainties associated with those estimates.
Resource Estimation and Technological Change
Estimation Techniques in the OCS
Exploration and production proceed in stages during which increasing data provide increasing
certainty about volumes of oil and gas present. Prior to discovery by drilling wells, the estimated
volumes of oil and gas are termed undiscovered resources. When oil and/or gas has been
discovered, the volumes of oil and gas are measured within pools or fields via well penetration or
other technology, and are called reserves. Measured reserves are reported to the Securities and
Exchange Commission by the owners of the wells.13 Reserves have been reported for U.S. OCS
areas that have been developed, such as the central and western Gulf of Mexico and some parts of
the California coast, but no reserves of oil or gas have been reported along the Atlantic OCS,
because there have been no discoveries, and only modest oil reserves have been reported on the
Alaska OCS (30 million barrels of oil and no gas as of 2006).
In frontier areas or in undeveloped areas around existing production where little or no
geophysical exploration or drilling has occurred, volumes of undiscovered oil and gas resources
may be estimated based on the geological characteristics of the area. The quality of those
estimates (or assessments) depends largely on the abundance and quality of geologic data
available to the geologists making the estimates. The geologic characteristics of a remote area, to
the extent they are known, can be compared to the oil and gas production history in a geologically
similar or analogous area. The number and size of oil and gas fields vary with geologic
environment, so an appropriate geologic model must be applied to the remote area. Again, more
geologic information allows a more reliable assessment of undiscovered resources, whereas less
geologic information results in greater uncertainty in the estimates. Secretary of the Interior Ken
Salazar instructed departmental scientists from the BOEM and U.S. Geological Survey (USGS) to
produce an updated estimate on conventional and renewable offshore energy resources. The
report, published in early April, drew primarily from previous BOEM and Department of Energy
13
For a full glossary and explanation of oil and gas reporting terms, see Securities and Exchange Commission: 17 CFR
Parts 210, 229, and 249 [Release Nos. 33-8935; 34-58030; File No. S7-15-08] RIN 3235-AK00, Modernization of the
Oil and Gas Reporting Requirements.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
studies. The report concluded that there are a number of significant gaps related to environmental
and energy resource data in the OCS.14
Because undiscovered resources of oil and gas in new areas are estimated using historical
production in known areas, and because production in known areas is based on current
exploration and production technology, these estimated volumes are called “technically
recoverable” and are therefore referred to as undiscovered technically recoverable resources
(UTRR). UTRR are estimates of the volumes of oil or natural gas likely to be recovered using
currently available technologies without considering price. UTRR changes as available
technology changes, but not as prices change. If an economic analysis is conducted to determine
the volumes of oil and gas that could be profitably recovered under current economic conditions,
those volumes are referred to as undiscovered economically recoverable resources (UERR).
Estimates of UERR vary with the price of oil or gas.
Because these numbers are estimates and have been derived using probabilistic methods, three
values for UTRR are normally reported: the volume of oil or gas that is 95% likely to be present,
the volume that is 5% likely to be present, and a mean value. The 95% probability is the smallest
number because it has the greatest certainty, and the 5% probability is the largest volume but
carries great uncertainty. Many users of these assessments rely on the mean value for volumes of
oil or gas present, but it is important to examine all three values to judge the uncertainty with
which the volumes of oil or gas are likely to be present.
Analysis of Estimates
The assessments of UTRR on the U.S. OCS by the BOEM provide estimates whose statistical
certainty varies by region, because the availability of geologic data varies widely by region.15 For
example, the extensive exploration and production histories of the central and western Gulf of
Mexico and Southern California provide a comparatively greater amount of geologic data to use
for assessments. In contrast, much of the remainder of the U.S. OCS has seen little exploration
and production of oil and gas. Therefore, estimates of UTRR along the Atlantic Coast, much of
the Pacific Coast, and coastal Alaska carry significant uncertainties. BOEM attempts to acquire
geophysical exploration data (primarily seismic data) along these coasts, and purchases data to
the degree they are available and if possible within their budget, but good data are difficult to
acquire and much of the existing data are old.16 Typically, initial estimates of UTRR change,
sometimes dramatically, as the quantity and quality of data improve as exploration progresses.
See Figure 1. Furthermore, no estimate of UERR has been attempted for U.S. OCS outside the
currently producing areas. Therefore, caution must be exercised when attempting to forecast
future production and resulting revenues from the OCS.
14
U.S. Department of the Interior, Survey of Available Data on OCS Resources and Identification of Data Gaps,
Report to the Secretary, OCS Report MMS 2009-015. http://www.doi.gov/ocs/report.pdf.
15
U.S. Department of the Interior, Minerals Management Service, Fact Sheet RED-2006-01b, Assessment of
Undiscovered Technically Recoverable Oil and Gas Resources of the Nation’s Outer Continental Shelf, 2006.
16
U.S. Department of the Interior, Minerals Management Service, OCS Report MMS 2007-049, Geological &
Geophysical Data Acquisition, Outer Continental Shelf Through 2004-2005, 2007.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Figure 1. OCS Natural Gas Resource Estimates
Source: Figure 1. American Petroleum Institute, 2009.
Notes: Changes in estimates for undiscovered technically recoverable resources of natural gas in the Atlantic
and Pacific regions (under moratorium) and the Gulf of Mexico (developed) between 1974 and 2006. Natural gas
production from the Gulf of Mexico between 1974 and 2008 is shown in green.
OCS Resource Estimates
For offshore oil, under the Known Resources category (proved reserves, unproved reserves, and
reserve appreciation), the BOEM estimated proved and unproved oil reserves in the OCS to be
8.55 billion barrels (3.9 Bbbl proved and 4.65 Bbbl unproved). The BOEM categorized 6.88 Bbbl
of oil as reserve appreciation. Offshore proved (14.3 tcf) and unproved (14.96 tcf) natural gas
reserves are estimated to be 29.26 tcf, plus 30.91 tcf in reserve appreciation.
In the UTRR category, the BOEM estimated oil resources to be nearly 86 billion barrels. Of this,
about 41 Bbbl oil would potentially come from the central and western Gulf of Mexico and about
25.3 Bbbl of oil would come from Alaska. With that total, roughly 66.4 billion possible barrels
out of 84.24 billion possible barrels are available (about 79%) for leasing in the current BOEM
five-year leasing program.
BOEM estimates the amount newly available (with the moratoria ended) at around 13.9 Bbbl.17
For natural gas, the BOEM estimates a total of 420 tcf of which about 55 tcf is newly available
since the lifting of the moratoria. All of the newly available areas could be included in the next
BOEM five–year leasing program under current law. About 3.88 Bbbl of oil and 21.51 tcf in the
eastern Gulf of Mexico would remain off limits.
17
Statement of C. Stephen Allred, U.S. Department of the Interior, before the Senate Committee on Energy and Natural
Resources, Resource Estimate Table, January 25, 2007.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Of the total 1.7 billion acres of the OCS, there are about 131 million acres available for leasing in
the current five-year leasing program.18 About 76% of the total acreage, but only 21% of the
UTRR, was unavailable under the OCS moratoria, according to BOEM estimates. There are
1,600 leases in production (10.5 million acres) out of 8,124 leases (on 43 million acres)
administered by the BOEM in the OCS.
In the near term, additional offshore reserves are likely to come from deepwater fields in the Gulf
of Mexico, an area where the vast majority of leases are held and where the largest resource
potential exists. Deepwater discoveries are typically much larger than those found in shallow
water fields. Annual volume additions to unproved reserves, resources, and industry-announced
discoveries in deepwater reached an all-time high in 2006. When it becomes apparent that a field
will go into production, those unproved reserves then become proved reserves. Since 2006, there
has been a 44% increase in proved deepwater discoveries in the Gulf of Mexico. But at the same
time, there are vast numbers of deepwater leases going undrilled. Of the nearly 1,900 ultradeepwater (depths of 5,000 feet or greater) leases, only 272 were drilled between 1996-2007. If
the oil and gas industry continues to commit significant capital for OCS exploration and
development, and deepwater discoveries are made, then the decline in offshore reserves could be
slowed or reversed.
Resource Estimates by Planning Area
The BOEM has divided the OCS into 26 planning areas within four regions (Atlantic, Gulf of
Mexico, Pacific, and Alaska). Table 2 below lists resource assessments by Planning Area.
According to the BOEM assessments, the areas of greatest resource potential are located in the
central and western Gulf of Mexico. Taken together, these two planning areas account for about
48% of the UTRR oil and 50% of the UTRR natural gas in the OCS. Alaska accounts for about
31% of the estimated oil and natural gas potential in the OCS.
Table 8. BOEM Assessment of UTRR in the OCS by Planning Areas
Oil (Bbbl)
Natural Gas
(Tcf)
North Atlantic
1.91
17.99
Mid Atlantic
1.50
15.13
South Atlantic
0.41
3.86
3.82
36.99
Eastern
3.88
21.51
Central
30.32
144.77
Western
10.70
66.25
Straits of Florida
0.02
0.02
Planning Area
Atlantic
Total Atlantic
Gulf of Mexico
18
The amount of acreage available in the OCS under the 2007-2012 leasing plan was listed at 181 million acres in the
U.S. DOI, MMS, Budget Justifications, FY2010, p. 9, but the April 2, 2010 announcement to eliminate five Alaskan
sales reduced the available acreage by about 50 million acres.
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Oil (Bbbl)
Natural Gas
(Tcf)
44.92
232.54
Washington/Oregon
0.40
2.28
Northern California
2.08
3.58
Central California
2.31
2.41
Planning Area
Total Gulf of Mexico
Pacific
Southern California
5.74
5.74
10.53
18.29
Beaufort Sea
8.22
27.64
Cook Inlet
1.01
1.20
Gulf of Alaska
0.63
4.65
Kodiak
0.05
1.84
Total Pacific
Alaska
North Aleutian Basin
0.75
8.62
Shumagin
0.01
0.49
St. Georges Basin
0.21
2.80
Navarin Basin
0.13
1.22
Norton Basin
0.06
3.06
Hope Basin
0.15
3.77
Chukchi Basin
15.38
76.77
Aleutian Arc
na
na
Bowers Basin
na
na
Aleutian Basin
na
na
St. Matthew-Hall
na
na
Total Alaska
26.61
132.06
Total U.S. OCS
85.88
419.88
Source: Statement of Stephen C. Allred, DOI/MMS, January 25, 2007.
In addition, the economically recoverable resources of oil and natural gas, based on an oil price of
$80 per barrel, are provided on the map in Figure 2 for the planning areas proposed for EIS
scoping under President Obama’s recent directive.
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Figure 2. Estimated Undiscovered, Economically Recoverable Resources
(Resources at $80/bbl)
Source: BOEM, http://www.BOEM.gov/revaldiv/PDFs/NA2006BrochurePlanningAreaInsert.pdf.
Note: No price for natural gas was specified for economically recoverable natural gas resources.
Resource Estimates by Water Depth
BOEM Planning Areas differ considerably based on both water depth and distance from shore.
(See BOEM website 2006 Resource Assessment Maps at http://www.mms.gov/revaldiv/
NatAssessmentMap.htm.) For example, in the North Atlantic, over half of the potential oil and
gas might be located in water depths of 200 meters or less, whereas in the South Atlantic, over
70% of the oil and gas is located between 200-800 meters of water and, based on BOEM maps,
appears to be more than 50 miles from the coast. Because of the narrow shelf off the California
coast, most of the potential oil and gas resources would likely be found within 50 miles of the
coast and in water depths between 0-800 meters. The eastern Gulf of Mexico is vastly different
than both coasts in that the vast majority of the potential oil (84%) and gas (68%) resources are
beyond 2,400 meters of water depth and beyond 100 miles from the coast. Estimates show about
15% of the potential oil and 22% of the potential natural gas might be found in less than 200
meters of water (which could also be beyond 100 miles from the coast).
The OCS Leasing Process and Program
The Outer Continental Shelf Lands Act of 1953 (OCSLA), as amended, provides for the leasing
of OCS lands in a manner that protects the environment and returns revenues to the federal
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government. Revenues come in three ways: bonus bids, rents, and royalties. Lease sales are
conducted through a competitive, sealed, bidding process, and leases are awarded to the highest
bidder. A minimum bid is determined for each tract offered. Successful bidders make an up-front
cash payment, called a bonus bid, to secure a lease.
During the past 17 years, annual bonus revenues have ranged from $85 million in 1992 to $1.4
billion in 1997. Bidding on deepwater tracts in the mid-1990s led to a surge in annual bonus
revenue.19 Offshore bonus bids totaled $374 million in FY2007. But as a result of high oil and
natural gas prices and the significant possible resources in the Central Gulf of Mexico, recordsetting bonus bids of $3.7 billion were accepted by BOEM/ONRR at a lease sale in March 2008.
In addition to the cash bonus bid, a royalty rate of 12.5% or 16.7% is imposed on the value of
production, depending on location factors, which can be cash or “in-kind.”20 The rate could be
higher than 16.7% depending on the lease sale. For instance, lease sales 224 (March 2008) and
213 (March 2010) will require a royalty rate of 18.75% in all water depths. According to BOEM
Congressional Affairs representatives, this higher rate (18.75%) is likely to remain in place for
future lease sales. The Secretary of the Interior may reduce or eliminate the royalty established by
the lease to promote increased recovery.
Annual rents are $5-$9.50 per acre (depending on water depth), with lease sizes generally ranging
from 2,500-5,760 acres.21 However, annual rental rates for the March 2009 sale in the Central
Gulf of Mexico began at $11 per acre for leases in water depths over 200 meters. Bonding
requirements are $50,000 per lease and as much as $3 million for an entire area.
OCSLA requires the Secretary of the Interior to submit five-year leasing programs that specify
the time, location, and size of the areas to be offered. Each five-year leasing program entails a
lengthy multistep process that includes an environmental impact statement. After a public
comment period, a final proposed program is submitted to the President and Congress, which may
be approved by the Secretary after 60 days if there is no objection by Congress.
Under current law, the primary offshore lease terms are 5, 8, or 10 years depending on water
depth.22 However, new lease terms, for blocks between 400 meters and 1,599 meters water depth,
were imposed beginning with the March 2010 sale.23 Leases continue as long as commercial
quantities of hydrocarbons are being produced. If the lease is not producing oil or gas in
commercial quantities by the end of its primary term, the lease reverts to the government for a
possible future lease sale—unless the lessee is granted an extension. Extensions can be granted
for offshore leases under 30 CFR 250.180. The regulation for offshore extensions does not
19
U.S. Department of the Interior, FY2002 Budget Justifications, p. 63.
A royalty-in-kind payment would be in the form of barrels of oil or cubic feet of natural gas.
21
The annual rental rate prior to 2009 was usually $5-$6.25 per acre in water depths less than 200 meters and $7-$9.50
per acre in water depths of 200 meters or more. After 2009, the rental rates begin at $7/acre and escalate to $28/acre in
year 8 and beyond for water depths less than 200 meters. In water depths between 200-400 meters, rental rates escalate
from $11 per acre in year one to $44/acre in year 8 and beyond. For deep water over 400 meters, rates begin at $11/acre
and escalate to $16/acre in year 8 and beyond.
22
The primary term is 5 years for shallow water (<400 meters deep), 8 years for leases in water 400-799 meters deep,
and 10 years for deepwater leases 800 meters and beyond.
23
Initial lease terms for blocks between 400 meters to 799 meters water depth would be for five years which could be
extended to eight years with a spudded well. Blocks between 800 meters to 1,599 meters water depth would receive a
seven-year initial lease which could be extended to 10 years with a spudded well.
20
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specify the length of the extension nor the conditions or requirements for an extension. Also, it is
not clear how often the BOEM grant extensions.
Many leases expire before exploration or production occurs. Data from BOEM on the
development status for existing leases has not been made available; thus, it is difficult to classify
the amount of acreage that has had no activity, is in the permitting stage, or is under exploration
but not producing.
Table 9. Lease Expirations and Relinquishments, 2001-2007
Year
Expired
Relinquished
Total
2001
496
248
744
2002
432
224
656
2003
208
352
560
2004
155
252
407
2005
352
303
655
2006
711
280
991
2007
938
241
1,179
Source: DOI/BOEM.
Nineteen lease sales were scheduled for the 2007-2012 leasing program.24 Nine lease sales have
occurred to date. Two lease sales were held in 2007 (sales 204 and 205), lease sale 193 in
February 2008, and lease sales 206 and 224 in March 2008. Lease sale 207 was held in August
2008, lease sale 208 occurred in March 2009 and lease sale 210 in August 2009. The most recent
sale (lease sale 213 ) took place in March 2010. The August 2011 lease sale 215 was cancelled.
There are three lease sales remaining in the Revised Program.
Revenues from lease sale 224 will be shared with coastal states (Mississippi, Alabama, Texas, and
Louisiana) as required by the Gulf of Mexico Energy Security Act (GOMESA). Thirteen of the
348 tracts (leases) bid on in lease sale 207 (located in sale area “181 South”) also fall under the
revenue sharing agreement in GOMESA (see revenue-sharing section of this report).
The Obama Administration had generally expressed support for BOEM efforts to facilitate
development of deepwater and ultra deepwater oil and gas in the Gulf of Mexico and in the
Alaskan OCS. With the moratoria lifted, leasing can occur in the newly opened areas. If the OCS
remains open, it could be as much as five years or longer for lease sales to be held in the newly
opened areas. Production might begin 5-10 years from the lease sale if commercial quantities are
found. New infrastructure requirements (e.g., pipelines, roads, and onshore facilities) are likely to
be needed, particularly along the East Coast where there has been no leasing activity in decades.
Generally, a number of concerns arise in the oil and gas leasing process that delay or prevent oil
and gas development from taking place, or might account for the large number of leases held in
non-producing status. There could be a lack of drilling rigs or other equipment availability, and
financing and/or skilled labor shortages. Legal challenges might delay or prevent development.
24
Since 1983, a typical OCS lease sale would consist of thousands of leases/tracts being offered (as high as 8,800 tracts
offered in a 1984 lease sale), but only as many as several hundred receiving bids.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
There are typically also many leases in the development cycle (e.g., conducting environmental
reviews, permitting, or exploring) but not producing commercial quantities.
OCS Revenues
Revenue Sharing or Not?
Federal revenues from offshore leases were estimated at $6.5 billion in FY2011 by the Office of
Natural Resources Revenue (ONRR). During the previous 10 fiscal years (2001-2010), revenues
from federal OCS leases ranged from a low of $4.1 billion in FY2002 to a high of $18 billion in
FY2008. Of the $18 billion offshore revenue in FY2008, $8.3 billion was from royalties and $9.5
billion came from bonus bids. Changing prices for oil and gas are the most significant factors in
the revenue swings.
Overall, revenues from federal energy and mineral leases were estimated at $11.2 billion in
FY2011 by the Office of Natural Resources Revenue (ONRR). Offshore receipts have accounted
for between 55% and 75% of the total mineral and energy leasing revenues received by the
federal government during the past 10 fiscal years.
OCS leasing revenues are split among various government accounts. Revenues from the offshore
leases are statutorily allocated among the coastal states, the Land and Water Conservation Fund,25
the National Historic Preservation Fund,26 and the U.S. Treasury. States receive 27% of all OCS
receipts closest to state offshore lands under Section 8(g)27of the OCSLA amendments of 1985
(P.L. 99-272). A dispute over what was meant by a “fair and equitable” division of the 8(g)
receipts was settled by the 1985 OCSLA amendments.28 In FY2011, this share was about $42.0
million out of about $2 billion in total state on-shore and offshore disbursements. States have
argued for a greater share of the OCS revenues based on the significant impacts on infrastructure
and the environment. According to the coastal producing states, the revenues are needed to
mitigate environmental impacts and to maintain the necessary support structure for the offshore
oil and gas industry. Revenue sharing provisions in the Gulf of Mexico Energy Security Act of
2006 (GOMESA) allow for Gulf producing states (defined as Alabama, Mississippi, Louisiana,
and Texas) to receive 37.5% of revenues generated from certain leases beginning FY2007.
Beginning in FY2017 and thereafter, the Gulf producing states would also receive 37.5% of the
revenues generated from leases awarded within the 2002-2007 planning area, including historical
25
For details on the Land and Water Conservation Fund, see CRS Report RL33531, Land and Water Conservation
Fund: Overview, Funding History, and Issues, by (name redacted).
26
Under the National Historic Preservation Act (16 U.S.C. 470 et. seq.), the National Historic Preservation Fund is
authorized to receive $150 million annually from OCS receipts. Authorization for this act expired at the end of
FY2005, thus no funds were disbursed from OCS receipts in FY2006. After reauthorization in December 2006, funding
from OCS receipts resumed in FY2007.
27
The 8(g) revenue stream is the result of a 1978 OCSLA amendment that provides for a “fair and equitable” sharing
of revenues from Section 8(g) common pool lands. These lands are defined in the amendments as submerged acreage
lying outside the standard three-nautical-mile state-federal demarcation line, typically extending to a total of six
nautical miles offshore (or three miles beyond the state’s boundary) but that include a pool of oil common to both
federal and state jurisdiction. The states’ share of the revenue (27%) was established by the OCSLA amendments of
1985 (P.L. 99-272) and is paid directly to the states. Payments to the states previously had been placed in escrow,
which were then paid out between 1986 and 2001.
28
U.S. Department of the Interior, Minerals Management Service, Mineral Revenues 2000, p. 95.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
leases (described in the statute). The Land and Water Conservation Fund (currently funded from
OCS revenues) would receive 12.5% of the qualified revenues for state programs and the federal
General Treasury would receive 50% of those revenues. BOEM/ONRR estimated that the states’
share would total $3.1 billion through 2022 and increase to a total of $59.6 billion through 2067.
Revenues derived from lease sale 224, held in March 2008, and 13 OCS tracts in lease sale 208,
held in March 2009, have been split with the four coastal states under GOMESA. Coastal Impact
Assistance Program (CIAP) revenue, derived from OCS leasing revenues, is shared with coastal
producing states. Based on the formula and authority in the Energy Policy Act of 2005 (Section
384, P.L. 109-58), $250 million of OCS revenues is shared annually for a four-year period ($1
billion from 2007-2010). Revenues from both GOMESA and CIAP are authorized for specific
purposes (identified in the statutes) such as for the conservation, protection, and restoration of
coastal areas; mitigation of damage to fisheries; and the implementation of a federally approved
marine, coastal, or comprehensive conservation management plans.
For onshore public domain leases, states generally receive 50% of rents, bonuses, and royalties
collected. Alaska, however, receives 90% of all revenues collected on public domain leases.
There was language in the proposed draft five-year lease program (2010-2015) to encourage
Congress to pass legislation that would expand revenue sharing agreements with states from
future lease sales.
Royalty Revenue Estimates
The ICF International report29 estimated that opening the OCS to production would increase
federal revenues by $360 billion to $1.4 trillion (including royalties and bonuses of about $180
billion). This increase represents an increase over projected revenues (given the OCS moratoria)
of 15% to 60% over the area that was classified as accessible, and assumes development of the
entire economic resource base over a 30-year period.30
The Draft Proposed Leasing Program (DPP), 2010-2015, projected leasing revenues of $368
million based on the 30 lease sales (which includes 10 sales in areas formerly off limits) in the
DPP. An additional $1.1 billion would be generated from taxes. The DPP was not implemented.
These estimates should be viewed with caution, as there are major uncertainties involved. First,
the amount of recoverable resource is an estimate based on assumptions and probabilities; they
are in fact educated guesses. Second, projecting the price of oil for a few years is difficult and
complex; projecting prices for decades is highly uncertain. Lastly, possible future legislation and
its terms are not known at this time, and could significantly alter revenue arrangements.
29
30
Strengthening Our Economy: The Untapped U.S. Oil and Gas Resources, December 5, 2008.
Ibid, p. 9.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Environmental Concerns Associated with Offshore
Exploration and Development
The environmental risks of offshore oil and gas development are being vividly displayed in the
Gulf of Mexico as a result of the recent and ongoing oil spell there. In addition, historical events
associated with offshore oil production, such as the large oil spill off the coast of Santa Barbara,
CA, in 1969, cause both opponents and proponents of offshore development to consider the risks
and to weigh those risks against the economic and social benefits of the development. Despite the
use of more sophisticated drilling and monitoring tools by oil companies, the recent offshore oil
spill resulting from the explosion and subsequent sinking of the Deepwater Horizon mobile
drilling rig has demonstrated that catastrophic accidents may still occur, particularly associated
with the more complex process of drilling in deep water. (For a full description of that event and
related issues, see CRS Report R41262, Deepwater Horizon Oil Spill: Selected Issues for
Congress, coordinated by (name redacted) and (name redacted); CRS Report R41407,
Deepwater Horizon Oil Spill: Highlighted Actions and Issues, by (name redacted) and (name red
acted); CRS Report R41684,
Oil Spill Legislation in the 112th Congress, by (name redact
ed); CRS Report RL33705,
Oil Spills in U.S. Coastal Waters: Background and Governance,
by (name redacted); and CRS Report R41311,
The Deepwater Horizon Oil Spill: Coastal
Wetland and Wildlife Impacts and Response, by (name redacted) and (name redacted).)
This section describes some of the general environmental risks associated with offshore oil and
gas development, and considers how those risks have changed over time. A more detailed
discussion of offshore environmental issues is included in OCS Report MMS 2009-015 (see
footnote 11), which describes potential impact of offshore oil and gas development on seafloor
habitats, coastal habitats, marine fish resources, marine mammals, sea turtles, and marine and
coastal birds.
Offshore Areas Currently Protected
In addition to limited areas in shipping lanes and military reserves, certain portions of offshore
U.S. waters remain off limits to development even when moratoria are lifted. The National
Marine Sanctuaries System, administered by the National Oceanic and Atmospheric
Administration, was originally created under the Marine Protection, Research, and Sanctuaries
Act of 1972 (MPRSA) and later amended most significantly as the National Marine Sanctuaries
Act of 1992.31 This legislation provides authority for the Secretary of Commerce, under certain
conditions, to:
designate as marine sanctuaries those areas of the oceans, coastal, and other waters, as far
seaward as the outer edge of the Continental Shelf ... which he determines necessary for the
purpose of preserving or restoring such areas for their conservation, recreational, ecological,
or esthetic values.
The National Marine Sanctuary System comprises of 14 sanctuaries ranging in size from less than
one square mile to 137,792 square miles. Of the 14 sanctuaries, 10 are currently or potentially
31
Listed in order of creation. For more information, see Legislative History of the National Marine Sanctuaries Act at
http://sanctuaries.noaa.gov/about/legislation/leg_history.html.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
located within areas that might be attractive for oil and gas exploration. See box below. Oil and
natural gas exploration and development are not permitted within the boundaries of the National
Marine Sanctuaries, but such activities may be allowed nearby depending on specific provisions
of the BOEM leasing programs.
Because of ongoing concerns about the effects of nearby oil and gas development on the health of
the National Marine Sanctuary habitat, the BOEM has monitored the effects of oil and gas
activities on a coral reef area of the Flower Garden Banks National Marine Sanctuary in the Gulf
of Mexico for over 25 years. This effort is ongoing and conducted in partnership with the
National Oceanic and Atmospheric Administration (NOAA), who administers the sanctuary.
Although a buffer zone of three miles is maintained, oil and gas activities have increased in the
surrounding area with no observable effects to the corals. BOEM requires that the nearby industry
shunt wastes (dispose of through a pipe to near the seafloor) away from the banks. This
mitigation was developed based on oceanographic research that indicated this would prevent
these materials from coming in contact with the coral reefs.
National Marine Sanctuaries Located in Continental U.S. Coastal Waters32
Monitor National Marine Sanctuary protects the wreck of the famed Civil War ironclad USS Monitor off Cape
Hatteras, NC. Established Jan. 30, 1975.
Channel Islands National Marine Sanctuary encompasses the waters surrounding San Miguel, Santa Rosa, Santa
Cruz, Anacapa, and Santa Barbara Islands off the coast of California. Established Sept. 22, 1980.
Gray’s Reef National Marine Sanctuary is 23 square miles just off the coast of Georgia. Established Jan. 16, 1981.
Gulf of the Farallones National Marine Sanctuary covers more than 1,200 square miles of coastal and ocean
wilderness west of San Francisco. Established Jan. 16, 1981.
Cordell Bank National Marine Sanctuary gets its name from the underwater mountain that rises to within 120
feet of the ocean’s surface off Point Reyes, CA, 526 square-miles. Established May 24, 1989.
Florida Keys National Marine Sanctuary is 3,700 square miles surrounding the Florida Keys. Established Nov.
16, 1990.
Flower Garden Banks National Marine Sanctuary is 50 square miles, 100 miles off the Texas-Louisiana coast.
Established Jan. 17, 1992.
Monterey Bay National Marine Sanctuary is the nation’s largest marine sanctuary, spanning more than 6,000
square miles of coastal waters off central California. Established Sept. 18, 1992.
Gerry E. Studds Stellwagen Bank National Marine Sanctuary sits at the mouth of Massachusetts Bay, just 25
miles from Boston. 824 square miles. Established Nov. 4, 1992.
Olympic Coast National Marine Sanctuary spans 3,310 square miles of marine waters off the Olympic
Peninsula. Established July 16, 1994.
32
http://sanctuaries.noaa.gov/welcome.html.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
General Environmental Regulations and Requirements for
Offshore Exploration and Production
All environmental aspects of offshore exploration, development, drilling, production,
transportation, and decommissioning are subject to regulation. In addition to the general legal and
regulatory framework that includes the OCLSA,33 several environmental laws and executive
orders have been enacted or amended since the first congressional moratorium for offshore areas
in 1982, including:
•
The 1990 Clean Air Act Amendments (P.L. 101-549) transferred jurisdiction over
air quality from BOEM to EPA for all OCS areas outside the Central and Western
Gulf of Mexico, and require BOEM to coordinate air pollution control activities
with EPA. The regulations are the same as onshore leasing requirements. EPA
also is setting emission limits on diesel engines and marine vessels to decrease
emissions.
•
The Oil Pollution Act of 1990 (P.L. 101-380), in part, revised Section 311 of the
Clean Water Act to expand federal spill-response authority; increase penalties for
spills; establish U.S. Coast Guard pre-positioned oil-spill response equipment
sites; require vessel and facility response plans; and provide for interagency
contingency plans.
•
On February 11, 1994, President Clinton issued Executive Order 12898, entitled
Federal Actions to Address Environmental Justice in Minority Populations and
Low-Income Populations, which directs federal agencies, including BOEM, to
assess whether their actions have disproportionate environmental effects on
people of ethnic or racial minorities or with low incomes.
•
National Fishing Enhancement Act of 1984 (P.L. 98-623), also known as the
Artificial Reef Act, establishes artificial reef development standards and a
national policy to encourage the development of artificial reefs that will enhance
fishery resources and commercial and recreational fishing. BOEM adopted a
national Rigs-to-Reefs policy that supports and encourages the reuse of oil and
gas structures for offshore artificial reef developments, which provide valuable
habitat for species of fish in areas devoid of natural hard bottom. It is anticipated
that approximately 10% of OCS platforms installed would become a rigs-to-reef
after decommissioning.
•
President Clinton issued Executive Order 13089 on Coral Reef Protection on
June 11, 1998. BOEM carries out the mission of E.O. 13089 by supporting coral
reef research and developing mitigation measures to protect these fragile and
biologically rich ecosystems.
•
Other acts, such as the Shore Protection Act of 1988 (P.L. 100-688) and Marine
Plastic Pollution Research and Control Act of 1987 (P.L. 100-220), require
containment of trash and debris, and restrict its disposal offshore. As a result of
these acts, BOEM has issued Notice to Lessees on awareness and elimination of
33
For more information on the legal aspects of offshore oil and gas development, see CRS Report RL33404, Offshore
Oil and Gas Development: Legal Framework, by (name redacted).
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
marine trash and debris, which pose a threat to fish, marine mammals, sea turtles,
and other marine animals.
•
The 1996 amendments to the Magnuson-Stevens Fishery Conservation and
Management Act (P.L. 94-265, as amended) emphasized the need to protect
fisheries habitat for long-term conservation of fisheries. Under its authority,
Fishery Management Plans designate essential fish habitat (EFH) for managed
species. The act requires that federal agencies consult with NOAA (National
Marine Fisheries Service) about actions that could damage EFH. This process
ensures consultation on fisheries of concern in a given project area.
•
The National Environmental Policy Act of 1969 (NEPA, P.L. 91-190, as
amended) requires that all federal agencies use a systematic, interdisciplinary
approach to assess the impacts of proposed actions on the human environment;
this approach is intended to ensure the integrated use of the natural and social
sciences in any planning and decision-making that may have an impact upon the
environment. Since its enactment, thousands of environmental assessments and
environmental impact statements have evaluated the potential impacts of OCS oil
and gas exploration and development on environmental and socioeconomic
resources.
Environmental Impact Statements
As with many development activities, offshore oil and gas exploration and development requires
environmental impact statements (EIS). The EIS provides the public with an opportunity to
comment on the estimated environmental impacts of development alternatives. The OCS Report
MMS 2009-01534 summarizes the EIS process:
As required in Section 20 of the Outer Continental Shelf Lands Act (OCSLA), the MMS has
established a tiered process that evaluates the potential environmental consequences for each
successive management decision starting with the proposed program, then individual lease
sales, and finally project-specific plans. The 5-Year Programmatic Environmental Impact
Statement (EIS) analyzes the proposed leasing schedule, focusing on the size, timing, and
location of proposed lease sales for the 5-year period identified in the proposed program
document. The Programmatic EIS takes a broad overview of the environmental effects from
the potential activities.
Once the 5-year lease sale schedule is approved, a more detailed environmental analysis is
conducted for each proposed lease sale in a given area. These lease sale EISs are more
detailed, including analyzing scenarios of potential activities that could result, should a lease
sale occur. At this point, MMS identifies lease stipulations, which are protective of the
environment, to be included in the leases granted to industry. In some cases, an EIS is
prepared for multiple lease sales in a program area. This Multisale EIS is the only
environmental review conducted for the first sale held in a program area. An additional
environmental review, in the form of an Environmental Assessment (EA) or supplemental
EIS, is conducted for each subsequent proposed lease sale to address any new relevant
information. Along with the preparation of a lease sale EIS or EA, the MMS carries out
informal and formal consultations with other Federal Agencies, the affected States, and the
public. This includes the ESA Section 7 consultations with the National Oceanic and
34
Op. cit.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Atmospheric Administration (NOAA) and the U.S. Fish and Wildlife Service (FWS), an
Essential Fish Habitat (EFH) consultation with NOAA, government to government
consultations with tribes, and preparation of a consistency determination for each affected
coastal State, as required in the CZMA.
After leases are issued, the MMS conducts environmental reviews for every exploratory and
development plan to ensure that the proper environmental protective measures (mitigations)
are employed. The MMS identifies site-specific mitigation measures in the form of
conditions of approval. The mitigations may include avoidance of sensitive biological
communities and archaeological resources, or inclusion of specialized discharge
requirements.
Oil Spills and Leaks
Perhaps the greatest environmental concern associated with offshore oil production is oil spills or
“blowouts.” A blowout is the potentially catastrophic loss of control of the fluids in a well during
drilling that releases drilling fluids, oil, and natural gas into the water, such as the Deepwater
Horizon blowout and oil spill that occurred on April 20, 2010. With the drilling of oil wells and
the production and transport of oil offshore, there is always some risk of oil leakage or spillage,
and the serious damage that crude oil has on wildlife and on wildlife habitat is extensively
documented in a number of environments. Prior to the Deepwater Horizon oil spill in the Gulf of
Mexico, the industry had demonstrated some progress in reducing the risk of oil spills, as
described in BOEM’s Draft Proposed Outer Continental Shelf (OCS) Oil and Gas Leasing
Program, 2010-2015:35
Since the Santa Barbara Channel OCS oil spill in 1969, measures have been underway
continuously to improve the technology of offshore operations, and the Federal government
has developed more stringent regulations governing OCS operations. Each OCS facility is
subject to an announced inspection for compliance with environmental and safety regulations
at least once a year and MMS also conducts periodic unscheduled inspections. The result of
all of these efforts is an excellent record that has been documented in detail in previous 5year program analyses and in several MMS publications. In the fifteen year period between
1993 and 2007, Federal OCS operators produced 7.49 billion barrels of oil (crude oil and
condensate). During that same period, the amount of oil spilled totaled about 47,800 barrels
(crude & refined petroleum spills of 1 barrel or greater) (0.0006% of that produced) or about
1 barrel of petroleum spilled for every 156,000 barrels produced.
Despite improvements in the offshore technologies such as improved blowout protectors and
subsurface safety shutoff valves (SSSV)36 and the accompanying reduction in the risk, equipment
may fail, drilling procedures may be not be followed, and oil spills may still occur. In addition to
spills that occur during general drilling operations such as the recent spill, the number of spills
generally increases during hurricanes in the Gulf of Mexico, as reflected in the high number of
spills in 2004 (Hurricane Ivan) and 2005 (Hurricanes Katrina and Rita). See Table 10. Of course,
35
Department of the Interior, Minerals Management Service, Draft Proposed Outer Continental Shelf (OCS) Oil and
Gas Leasing Program 2010-2015, January, 2009: http://www.mms.gov/5-year/PDFs/2010-2015/
DPP%20FINAL%20(HQPrint%20with%20landscape%20maps,%20map%2010).pdf.
36
MMS published in December of 2000 the final rule (Section 30, Code of Federal Regulations, Part 250) which
included the international standard that specifies the minimum acceptable requirements for subsurface safety valve
equipment. The SSSV will shut off flow of hydrocarbons in the event of an emergency and is considered the last line of
defense in securing a well and/or preventing pollution.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
the number of spills per year does not fully communicate the impact of individual spills such as
the Deepwater Horizon incident.
Table 10. Number of Spill Incidents Between 1996 and 2008
(more than 50 gallons per incident)
Year
OCS Spill Incidents
1996
4
1997
3
1998
9
1999
5
2000
7
2001
9
2002
12
2003
12
2004
22
2005
49
2006
14
2007
4
2008
5
2009
11
2010
6
Source: U.S. Department of the Interior, Bureau of Ocean Energy, Regulation and Enforcement, Spills - Statistics
and Summaries 1996-2008, http://www.BOEM.gov/incidents/IncidentStatisticsSummaries.htm.
Notes: Data are for the oil and gas producing regions of the Gulf of Mexico and Southern California OCS.
Hurricane Ivan entered the Gulf of Mexico in 2004, and most of the 2005 spills were associated with Hurricanes
Katrina and Rita in the Gulf of Mexico.
The BOEM regulations require that the producers be prepared for oil spills:
The MMS requires that all drilling or production operations on the OCS have an approved
oil spill contingency plan that describes where the nearest equipment is located, where the
trained personnel are, and how everyone is notified. Additional site-specific information as
to response capabilities specific to a worst case spill will be required. During drilling
operations, a company can be required to have equipment staged on a dedicated vessel
located at the rig, which can immediately contain and clean up a spill. There is also oil spill
equipment available at onshore bases. The MMS conducts frequent inspections of all OCS
activity—both at the drilling stage and at production. It also requires the use of subsurface
safety valves that shut-in the flow of oil in emergencies such as loss of the entire rig or
platform.37
Of course, the effectiveness of such measures depends upon compliance and enforcement of the
regulations.
37
Ibid.
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Seismic Surveys and Industrial Noise
Virtually every oil and gas exploration program involves the gathering of two-dimensional or
three-dimensional reflective seismic data. Seismic data are collected by generating intense sound
waves using percussive air guns towed by ships. The sound waves are propagated through
seawater into the underlying sediment and rocks, and reflected sound waves are detected using an
array of hydrophones towed behind the ship. These data provide images of subsurface rock strata
and structures and guide exploration and development.
The impact of seismic surveys on fish and marine mammals is mixed. One study indicates that
there is a local and temporary reduction in the catch of cod by fishermen after seismic data
collection,38 whereas other studies suggest little or no effect on other fish species.39 In neither case
is permanent damage to individual fish or to fish populations ascribed to seismic surveys. The
effects of seismic surveys on whales and other marine mammals have been more carefully studied
and have received more public attention. The rigorous study by Jochens et al. of whales and other
cetaceans found no unusual effects of experimentally controlled exposure to seismic exploration
on the swimming and diving behavior by sperm whales in the Gulf of Mexico.40 A more complete
discussion of environmental issues associated with offshore oil and gas exploration and
development can be found in Section III of OCS Report MMS 2009-015.
38
A. Engas, et al., “Effects of seismic shooting on local abundance and catch rates of cod (Gadus morhua) and haddock
(Melanogrammus aeglefinus),” Canadian Journal of Fisheries and Aquatic Sciences, vol. 53, no.10, 1996, pp. 22382249.
39
J. Dalen and G.M. Knutsen, “Scaring effects in fish and harmful effects on eggs, larvae and fry by offshore seismic
explorations.” In: H.M Merklinger (ed.), Progress in Underwater Acoustics, Plenum Press, NY, 1986.
40
A. D. Jochens et al., Sperm whale seismic study in the Gulf of Mexico: Synthesis report. U.S. Dept. of the Interior,
Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA., OCS Study MMS 2008-006, 2008,
341 pp.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Appendix. Definition of Terms41
Proved reserves. The quantities of hydrocarbons estimated with reasonable certainty to be
commercially recoverable from known accumulations under current economic conditions,
operating methods, and government regulations. Current economic conditions include prices and
costs prevailing at the time of the estimate. Estimates of proved reserves do not include reserves
appreciation.
Reserves. The quantities of hydrocarbon resources anticipated to be recovered from known
accumulations from a given date forward. All reserve estimates involve some degree of
uncertainty.
Reserves appreciation. The observed incremental increase through time in the estimates of
reserves (proved and unproved) of an oil and/or natural gas field as a consequence of extension,
revision, improved recovery, and the additions of new reservoirs.
Resources. Concentrations in the earth’s crust of naturally occurring liquid or gaseous
hydrocarbons that can conceivably be discovered and recovered.
Undiscovered resources. Resources postulated, on the basis of the geologic knowledge and
theory, to exist outside of known fields or accumulations.
Undiscovered technically recoverable resources (UTRR). 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.
Undiscovered economically recoverable resources (UERR). The portion of the undiscovered
technically recoverable resources that is economically recoverable under imposed economic and
technologic conditions.
Unproved reserves. Quantities of hydrocarbon resources that are assessed based on geologic and
engineering information similar to that used in developing estimates of proved reserves, but
technical, contractual, economic, or regulatory uncertainty precludes such reserves from being
classified as proved.
41
Definitions of terms taken from Report to the Secretary, op. cit., MMS 2009-015, Appendix A, List of Terms Used.
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U.S. Offshore Oil and Gas Resources: Prospects and Processes
Author Contact Information
(name redacted)
Specialist in Energy Policy
[redacted]@crs.loc.gov, 7-....
(name redacted)
Specialist in Energy Economics
[redacted]@crs.loc.gov, 7-....
Acknowledgments
(name redacted), one of the original authors of this report, is no longer with CRS.
Congressional Research Service
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