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U.S. Offshore Oil and Gas Resources:
Prospects and Processes
Marc Humphries
Analyst in Energy Policy
Robert Pirog
Specialist in Energy Economics
Gene Whitney
Section Research Manager
June 12, 2009
Congressional Research Service
7-5700
www.crs.gov
R40645
CRS Report for Congress
P
repared for Members and Committees of Congress

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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 established by
Congress (beginning in 1981) and by the President (beginning in 1990). These moratoria were
largely eliminated in 2008 and 2009, although a few areas remain legislatively off limits to
leasing. The 111th 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.
Consideration of offshore development for any purpose may raise concerns over the protection of
the marine and coastal environment. 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. However, both technology and regulatory
oversight have improved since that event.
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. The Minerals Management Service
(MMS) 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. For example, the extensive exploration and
production histories of 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.
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. Typically, the next source of supply is imports from countries not party to
the Organization of the Petroleum Exporting Countries (OPEC). Finally, residual demand is met
by OPEC. This behavior implies that, if the United States were to increase domestic production of
crude oil and natural gas condensates, the result would likely be an equal decrease in imports.
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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Contents
Introduction and Background ...................................................................................................... 1
Legislative Issues ........................................................................................................................ 2
U.S. Oil and Gas Supply and Demand ......................................................................................... 3
U.S. Oil Markets ................................................................................................................... 3
U.S. Natural Gas Markets...................................................................................................... 6
Economic Effects: Oil Market ............................................................................................... 7
Economic Effects: Natural Gas Market.................................................................................. 9
Greater OCS Access and Supply ........................................................................................... 9
Oil and Gas Reserves and Resources in the OCS ....................................................................... 10
Resource Estimation and Technological Change............................................................ 10
OCS Resource Estimates..................................................................................................... 13
Resource Estimates by Planning Area.................................................................................. 13
Resource Estimates by Water Depth .................................................................................... 15
The OCS Leasing Process and Program..................................................................................... 15
OCS Revenues .......................................................................................................................... 17
Revenue Sharing or Not? .................................................................................................... 17
Royalty Revenue Estimates ........................................................................................... 19
Environmental Concerns Associated with Offshore Exploration and Development .................... 19
Offshore Areas Currently Protected ..................................................................................... 19
General Environmental Regulations and Requirements for Offshore Exploration and
Production ....................................................................................................................... 21
Environmental Impact Statements ....................................................................................... 23
Oil Spills and Leaks ............................................................................................................ 23
Seismic Surveys and Industrial Noise.................................................................................. 25
Appendix. Definition of Terms .................................................................................................. 27

Figures
Figure 1. OCS Natural Gas Resource Estimates......................................................................... 12

Tables
Table 1. U.S. Petroleum Consumption, 2004-2008 ...................................................................... 3
Table 2. U.S. Petroleum Supply, 2004-2008 ................................................................................ 4
Table 3. U.S. Offshore Crude Oil Production, 2004-2008 ............................................................ 5
Table 4. U.S. Proved Crude Oil Reserves, 2004-2008 .................................................................. 5
Table 5. U.S. Natural Gas Consumption, 2004-2008.................................................................... 6
Table 6. U.S. Natural Gas Supply ................................................................................................ 7
Table 7. U.S. Natural Gas Proved Reserves ................................................................................. 7
Table 8. MMS Assessment of UTRR in the OCS by Planning Areas .......................................... 14
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Table 9. Lease Expirations and Relinquishments, 2001-2007..................................................... 16
Table 10. Number of Spill Incidents Between 1996 and 2008 .................................................... 25

Contacts
Author Contact Information ...................................................................................................... 28

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Introduction and Background
Congress is currently debating how much of the outer continental shelf (OCS) should be open for
oil and gas development. Opening up the OCS 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). Industry might be reluctant to invest in any new resource assessments unless they are
confident that the OCS will remain open for 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.
Given that numerous offshore leases are already in the exploration and development process and
many more lay idle and terminate before any exploration occurs, would a revised leasing
schedule that recognizes the end of the moratoria have any significant impact on domestic
production in the OCS or to the overall U.S. energy supply in the foreseeable future?
The offshore leasing moratoria began with the FY1982 Interior Appropriations Act (P.L. 97-100),
which prohibited new leases off the shore of California. The imposition of other moratoria came
about after many coastal states and environmental groups contended that leasing tracts in
environmentally sensitive areas might lead to activities that could cause economic or irreversible
environmental damage. Eventually, the moratoria were expanded to include New England, the
Georges Bank, the mid-Atlantic, the Pacific Northwest, a portion of Alaska, and much of the
eastern Gulf of Mexico. Because of environmental and economic concerns, Congress for the past
two decades has supported annual moratoria on leasing and drilling in the OCS. Congress enacted
the moratoria for each of fiscal years 1982-2008 through the annual Interior Appropriations bill.
Leasing was allowed in most of the Gulf of Mexico and most of the Alaskan coast. In 1990,
President George H.W. Bush established an additional executive moratorium on new OCS oil and
gas leasing until 2002, which President Clinton extended to 2012. In 2008, the George W. Bush
Administration lifted the executive moratorium on offshore drilling, and Congress chose not to
renew the longstanding OCS oil and gas moratoria (along the Atlantic and Pacific coasts) in the
Continuing Appropriations Act, 2009 (P.L. 110-329) or the Omnibus Appropriations Act, 2009
(P.L. 111-8).
Following the elimination of the OCS moratoria, the Bush Administration, on January 16, 2009,
introduced a new draft of a proposed five-year leasing program for 2010-2015. If finalized by the
Secretary of the Interior, this new program would supersede the current 2007-2012 leasing
program.1 The proposed program would take advantage of the recent lifting of the OCS moratoria
by including several lease sales in the Atlantic and Pacific regional planning areas. However,
under the Obama Administration, the Interior Secretary Salazar announced in February 2009 a
180-day extension of the comment period on the new five-year leasing program draft proposal.

1 A five-year leasing program is required under section 18 of the Outer Continental Shelf Lands Act of 1953 (OCSLA),
as amended (P.L. 93-627, 43 U.S.C. 1331, et seq.).
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This extension will also provide the Department of the Interior (DOI) an opportunity to assess the
quality of information available on the OCS. In April 2009, the Minerals Management Service
(MMS) published a report on energy resources in the OCS2 as part of its strategy to develop a
comprehensive approach for development of offshore energy resources. Secretary Salazar also
conducted a series of public meetings in April 2009 in Atlantic City, NJ, New Orleans, LA, San
Francisco, CA, and Anchorage, AK, to gather additional input on the management of the OCS. If
the existing five-year leasing program (2007-2012), which does not include leasing in the former
moratoria areas, were to stay in effect, the MMS would then initiate preparation for the next five-
year program (2012-2017) in 2010.
The eastern Gulf of Mexico and a portion of the central Gulf of Mexico 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.
In addition, the DOI issued the final regulatory framework for Renewable Energy and Alternate
Uses of Existing Facilities on the Outer Continental Shelf on April 29, 2009.3 Although the
pursuit of renewable energy resources on the OCS is an important issue, it will not be treated in
this report, which focuses on oil and gas resources.
In another important OCS development, on April 17, 2009, a three-judge panel for the U.S. Court
of Appeals for the District of Columbia Circuit “vacated” the current five-year leasing program
and sent it back to the Secretary of the Interior for reconsideration. The implications of this
decision (it is unclear whether the decision affects only lease sale #193 in the Alaskan Chukchi
Sea, or all lease sales in the five-year program) are unclear and beyond the scope of this report,
but the decision reinforces the need for the Secretary to pursue a new five-year plan.
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 may be unlikely in the 111th
Congress, some Members of Congress have expressed interest in protecting selected areas of the
OCS (e.g., Georges Bank in the North Atlantic Planning Area or Northern California) or buffer
zones of 25 or 50 miles off the coast. Some have argued for open but restricted access. The
President has the administrative authority to place areas of the OCS under a leasing and

2 Report to the Secretary, U.S. Dept. of the Interior, Survey of Available Data on the OCS Resources and Identification
of Data Gaps, Executive Summary, OCS Report, MMS 2009-015, April 2009.
3 U.S. DOI, MMS, Renewable Energy and Alternate Uses of Existing Facilities on the Outer Continental Shelf, Docket
ID: MMS-2008-OMM-0012, April 2009.
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development moratoria,4 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.
Congress may support or object to the draft proposed five-year leasing program for 2010-2015
(proposed by the Bush Administration and currently being re-examined by the Obama
Administration) which would implement a new leasing program two years ahead of the current
schedule (2007-2012).5 Congress may choose to fund seismic studies for the OCS (authorized
under the Energy Policy Act of 2005). 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
legislative issue is whether coastal producing states should receive a greater share of those
revenues.
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.
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 five years.
Table 1. U.S. Petroleum Consumption, 2004-2008
(millions of barrels per day)
All Petroleum
Gasoline
Products
2004 9.10
20.73
2005 9.16
20.80
2006 9.25
20.69
2007 9.29
20.68
2008 8.97
19.48
Source: Energy Information Administration, Monthly Energy Review, February 2009.

4 OCSLA Section 12(a)
5 Congress does not formally vote on the 5-year Leasing Program but may object in a number of ways including not
funding any pre-leasing or leasing activity through the Interior Appropriations bill.
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Table 1 shows that almost half of this consumption has been in the form of motor gasoline used
in automobiles and light trucks. The data for 2008, which shows declines in both gasoline and
total petroleum product consumption, reflects 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.
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 has declined over the past five years, which is likely part of a sectoral decline in crude oil
production that has occurred since the mid-1970s when U.S. production peaked.
A characteristic of the U.S. oil market, as well as the world oil market, is that the accessing
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 by OPEC.6 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, 2004-2008
(millions of barrels per day)
Crude Oil

Production
Net Imports
2004 5.42
12.10
2005 5.18
12.55
2006 5.10
12.39
2007 5.06
12.04
2008 4.95
11.04
Source: Energy Information Administration, available at
http://www.eia.doe.go/oil_gas/petroleum/info_glance/petroleum.html.
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 at least 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.
Offshore production of crude oil accounted for approximately 30% of total U.S. production of
crude oil in 2008, down from 35% in 2004. Offshore production, as shown in Table 3, is divided

6 This viewpoint is substantiated by Energy Information Administration data which shows that excess supply in the
world tends to reside in OPEC.
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between production in federal and state waters.7 Within the federal waters category, 95% of crude
oil production is from the Gulf of Mexico, and 5% is from waters off the coast of California. The
state offshore production is largely raised from the waters off Alaska, where 78% of the state
offshore total of crude oil was produced in 2008.
Table 3. U.S. Offshore Crude Oil Production, 2004-2008
(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
0.292
Source: Energy Information Administration, available at http://www.eia.doe.gov (op. cit., Table 2 Source).
Notes: Data for 2008 are estimates based on Energy Information Administration data for the period January
through November 2008.
Production of crude oil depends on the existence of a proved reserve base. The data in Table 4
shows that, while the total of U.S. proved reserves has remained relatively steady, the reserve
base in the federal offshore areas has declined by approximately 17% in the four-year period
2004-2007. 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.
Table 4. U.S. Proved Crude Oil Reserves, 2004-2008
(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 N/A
N/A
Source: Energy Information Administration, available at http://www.eia.doe.gov (op. cit., Table 2 Source).
Notes: Data for 2008 are not available.
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

7 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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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 five years.
Table 5. U.S. Natural Gas Consumption, 2004-2008
(trillion cubic feet)
Delivered to
Total

Consumers
Consumption
2004 20.725
22.339
2005 20.315
22.011
2006 19.958
21.685
2007 21.226
23.047
2008 21.324
23.237
Source: Energy Information Administration, available at http://www.eia.doe.gov/oil_gas/natural_gas/info_glance/
natural_gas.html
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 2008, approximately 23% was used by
residential customers, 15% was used by commercial customers, 31% was used by industrial
customers, and 31% was used in electric power generation. Over the five year period 2004-2008,
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 8%. The use of natural gas for electric power generation
increased by approximately 22% over the period.
The 2004-2008 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
(trillion cubic feet)
Domestic

Production
Imports
2004 18.59
4.26
2005 18.05
4.34
2006 18.50
4.19
2007 19.09
4.60
2008 20.57
3.96
Source: Energy Information Administration, available at http://www.eia.doe.gov (op. cit., Table 5 Source).

In 2008, the United States produced about 84% of the natural gas it consumed, with 90% of the
imported volumes arriving from Canada via pipeline. Liquefied Natural Gas (LNG) accounted for
about 9% of imports, or about 1.5% of total U.S. consumption. LNG imports largely come from
Trinidad, although Egypt, Nigeria, Norway, and Qatar also exported to the United States in 2008.
U.S. production of natural gas has increased since 2006 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. 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 around 1%-2%.
U.S. proved natural gas reserves have increased over the period 2004-2008 by approximately
24%, 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, non-conventional deposits of
natural gas, such as shale gas. Offshore resources have declined by about 25% over the period.
Table 7. U.S. Natural Gas Proved Reserves
(trillion cubic feet)
Offshore
Offshore
Total

State
Federal
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 N/A
N/A
N/A
Source: Energy Information Administration, available at http://www.eia.doe.gov (op. cit., Table 5 Source).
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,
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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.
Another factor that has increased in importance over the 2004 through 2008 period has been 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, is 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 five to ten 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.
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. As recently as 2008, construction and development costs for petroleum
investment projects were escalating sharply, 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.
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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.
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.
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 5.0 million barrels per day8 (mbd) to 7.3 mbd by 2030
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 1.4 mbd to 2.7 mbd by 2030 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 rise from 3.0 tcf in 2007 to 4.9 tcf in 2030. The EIA estimates are uncertain
as to how much of the increased natural gas production would come from the formerly restricted
areas.10

8Testimony of Dr. Howard Gruenspecht, Acting Administrator, Energy Information Administration, U.S. Department
of Energy, before the Subcommittee on Energy and Mineral Resources, Committee on Natural Resources, U.S. House
of Representatives March 5, 2009.
9 U.S. DOE/EIA, Annual Energy Outlook, 2009.
10 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.
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Based on mean resource estimates by the Minerals Management Service (MMS), a report
prepared for the American Petroleum Institute 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 MMS 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 MMS, deepwater oil already accounts for more than 70% of offshore production and 18.5%
of total U.S. crude oil production. Since 2002, the number of shallow water lease sales has
dropped from 418 to 264 while the number of deepwater lease sales rose from 281 to 633.
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 ultra-deep (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?
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.
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

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.
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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 MMS 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 MMS and Department of Energy
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.

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.
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.
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Analysis of Estimates
The assessments of UTRR on the U.S. OCS by the MMS 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. MMS 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 is 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.
Figure 1. OCS Natural Gas Resource Estimates

Source: Figure 1. American Petroleum Institute, 2009.
Notes: Changes in estimates for undiscovered technical y 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.

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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OCS Resource Estimates
For offshore oil, under the Known Resources category (proved reserves, unproved reserves, and
reserve appreciation), the MMS 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 MMS 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 MMS 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 MMS
five-year leasing program.
MMS estimates the amount newly available (with the moratoria ended) at around 13.9 Bbbl.17 For
natural gas, the MMS 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 MMS
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.
Of the total 1.7 billion acres of the OCS, there are about 181 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 MMS estimates. There are 1,600
leases in production (10.5 million acres) out of 8,124 leases (on 43 million acres) administered by
the MMS 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 ultra-
deepwater (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 MMS 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 MMS assessments, the areas of greatest resource potential are located in the

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.
18 U.S. DOI, MMS, Budget Justifications, FY2010, p. 9.
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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. MMS Assessment of UTRR in the OCS by Planning Areas
Natural Gas
Planning Area
Oil (Bbbl)
(Tcf)
Atlantic

North Atlantic
1.91
17.99
Mid Atlantic
1.50
15.13
South Atlantic
0.41
3.86
Total Atlantic
3.82
36.99
Gulf of Mexico


Eastern
3.88
21.51
Central
30.32
144.77
Western
10.70
66.25
Straits of Florida
0.02
0.02
Total Gulf of Mexico
44.92
232.54
Pacific

Washington/Oregon
0.40
2.28
Northern California
2.08
3.58
Central California
2.31
2.41
Southern California
5.74
5.74
Total Pacific
10.53
18.29
Alaska

Beaufort Sea
8.22
27.64
Cook Inlet
1.01
1.20
Gulf of Alaska
0.63
4.65
Kodiak
0.05
1.84
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
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Natural Gas
Planning Area
Oil (Bbbl)
(Tcf)
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
Resource Estimates by Water Depth
MMS Planning Areas differ considerably based on both water depth and distance from shore.
(See MMS 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 MMS 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
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, record-
setting bonus bids of $3.7 billion were accepted by the MMS 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 sale 224 will require a royalty
rate of 18.75% in all water depths. According to MMS Congressional Affairs representatives, this
higher rate (18.75%) is likely to remain in place for future lease sales. The Secretary of the

19 U.S. Department of the Interior, FY2002 Budget Justifications, p. 63.
20 A royalty-in-kind payment would be in the form of barrels of oil or cubic feet of natural gas.
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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 sixty 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 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 specify the length of the extension nor the conditions or
requirements for an extension. Also, it is not clear how often the MMS grant extensions.
Many leases expire before exploration or production occurs. Data from the MMS 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/MMS

21 The annual rental rate is 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.
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.
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Nineteen lease sales are scheduled for the 2007-2012 leasing program.23 Seven 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 and lease sale 208 was held in March 2009. 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 has generally expressed support for MMS efforts to facilitate
development of deepwater and ultra deepwater oil and gas in the Gulf of Mexico and in the
Alaskan OCS. However, the Administration extended the public comment period on the Draft
Proposed Program. Also, the Court of Appeals for the District of Columbia Circuit recently
decided to vacate the current leasing program; thus, the MMS will likely conduct a more
thorough environmental analyses in preparing its next five-year leasing program.
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.
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 $18 billion in FY2008 by the MMS.
During the previous 10 fiscal years (1998-2007), revenues from federal OCS leases ranged from a
low of $3.2 billion in 1999 to a high of $7.6 billion in FY2006. Changing prices for oil and gas
are the most significant factors in the revenue swings. Of the $18 billion offshore revenue in
FY2008, $8.3 billion was from royalties and $9.5 billion came from bonus bids.
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,24
the National Historic Preservation Fund,25 and the U.S. Treasury. States receive 27% of all OCS

23 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.
24 For details on the Land and Water Conservation Fund, see CRS Report RL33531, Land and Water Conservation
Fund: Overview, Funding History, and Current Issues, by Carol Hardy Vincent.
25 Under the National Historic Preservation Act (16 U.S.C. 470 et. seq.), the National Historic Preservation Fund is
(continued...)
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receipts closest to state offshore lands under section 8(g)26of the OCSLA amendments of 1985
(P.L. 99-272). In FY2008, this share was over $100 million out of about $2.5 billion in total state
on-shore and offshore receipts. A dispute over what was meant by a “fair and equitable” division
of the 8(g) receipts was settled by the 1985 OCSLA amendments.27
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 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. The MMS
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 is 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.

(...continued)
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.
26 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.
27 U.S. Department of the Interior, Minerals Management Service, Mineral Revenues 2000, p. 95.
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Royalty Revenue Estimates
The ICF International report28 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.29
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.
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.
Environmental Concerns Associated with Offshore
Exploration and Development
Consideration of offshore development for any purpose may raise concerns over the possible
impacts on the marine and coastal environment. 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. However, both technology and
regulatory oversight have improved since that event. This section describes some of the
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 1992.30 This legislation provides authority for the Secretary of Commerce, under certain
conditions, to:

28 Strengthening Our Economy: The Untapped U.S. Oil and Gas Resources, December 5, 2008.
29 Ibid, p. 9.
30 Listed in order of creation. For more information, see Legislative History of the National Marine Sanctuaries Act at
(continued...)
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…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
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 MMS 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 MMS 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. The MMS 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.

(...continued)
http://sanctuaries.noaa.gov/about/legislation/leg_history.html.
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National Marine Sanctuaries Located in Continental U.S. Coastal Waters31

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.

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,32 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 MMS to EPA for all OCS areas outside the Central and Western

31 http://sanctuaries.noaa.gov/welcome.html
32 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 Adam Vann.
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Gulf of Mexico, and require MMS 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 MMS, 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. The MMS 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. The MMS 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, MMS has issued Notice to Lessees on awareness and elimination of
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
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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 2009-01533 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
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 and perhaps oil into the water. With the drilling of oil wells

33 Op. cit.
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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. However, the industry has made progress
in reducing that risk of oil spills, as described in the Minerals Management Service’s Draft
Proposed Outer Continental Shelf (OCS) Oil and Gas Leasing Program, 2010-2015:34
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 5-
year 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)35 and the accompanying reduction in the risk, oil spills
may still occur. For example, 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.

34 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
35 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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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
Source: U.S. Department of the Interior, Minerals Management Service, Spills - Statistics and Summaries 1996-
2008, http://www.mms.gov/incidents/spills1996-2008.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 Minerals Management Service requires 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.36
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

36 Ibid.
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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,37 whereas other studies suggest little or no effect on other fish species.38 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.39 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.


37 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. 2238-
2249.
38 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.
39 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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Appendix. Definition of Terms40
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.



40 Definitions of terms taken from Report to the Secretary, op. cit., MMS 2009-015, Appendix A, List of Terms Used.
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Author Contact Information

Marc Humphries
Gene Whitney
Analyst in Energy Policy
Section Research Manager
mhumphries@crs.loc.gov, 7-7264
gwhitney@crs.loc.gov, 7-7231
Robert Pirog

Specialist in Energy Economics
rpirog@crs.loc.gov, 7-6847




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