Oil and Gas Royalties
Royalty Relief Will Likely Cost the Government Billions, but the Final Costs Have Yet to Be Determined Gao ID: GAO-07-369T January 18, 2007Oil and gas production from federal lands and waters is vital to meeting the nation's energy needs. As such, oil and gas companies lease federal lands and waters and pay royalties to the federal government based on a percentage of the oil and gas that they produce. The Minerals Management Service (MMS), an agency in the Department of the Interior, is responsible for collecting royalties from these leases. In order to promote oil and gas production, the federal government at times and in specific cases has provided "royalty relief," waiving or reducing the royalties that companies must pay. However, as production from these leases grows and oil and gas prices have risen since a major 1995 royalty relief act, questions have emerged about the financial impacts of royalty relief. Based on our work to date, GAO's statement addresses (1) the likely fiscal impacts of royalty relief on leases issued under the Outer Continental Shelf Deep Water Royalty Relief Act of 1995 and (2) other authority for granting royalty relief that could further impact future royalty revenue. To address these issues our ongoing work has included, among other things, analyses of key production data maintained by MMS; and reviews of appropriate portions of the Outer Continental Shelf Deep Water Royalty Relief Act of 1995, the Energy Policy Act of 2005, and Interior's regulations on royalty relief.
While precise estimates remain elusive at this time, our work to date shows that royalty relief under the Outer Continental Shelf Deep Water Royalty Relief Act of 1995 will likely cost billions of dollars in forgone royalty revenue--at least $1 billion of which has already been lost. In October 2004, MMS estimated that forgone royalties on deep water leases issued under the act from 1996 through 2000 could be as high as $80 billion. However, there is much uncertainty in these estimates. This uncertainty stems from ongoing legal challenges and other factors that make it unclear how many leases will ultimately receive royalty relief and the inherent complexity in forecasting future royalties. We are currently assessing MMS's estimate in light of changing oil and gas prices, revised estimates of future oil and gas production, and other factors. Additional royalty relief that can further impact future royalty revenues is currently provided under the Secretary of the Interior's discretionary authority and the Energy Policy Act of 2005. Discretionary programs include royalty relief for certain deep water leases issued after 2000, certain deep gas wells drilled in shallow waters, and wells nearing the end of their productive lives. The Energy Policy Act of 2005 mandates relief for leases issued in the Gulf of Mexico during the five years following the act's passage, provides relief for some gas wells that would not have previously qualified for royalty relief, and addresses relief in certain areas of Alaska.
GAO-07-369T, Oil and Gas Royalties: Royalty Relief Will Likely Cost the Government Billions, but the Final Costs Have Yet to Be Determined
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Testimony:
Before the Committee on Energy and Natural Resources, United States
Senate:
United States Government Accountability Office:
GAO:
For Release on Delivery Expected at 9:30 a.m. EST:
Thursday, January 18, 2007:
Oil And Gas Royalties:
Royalty Relief Will Likely Cost the Government Billions, but the Final
Costs Have Yet to Be Determined:
Statement of Mark E. Gaffigan, Acting Director Natural Resources and
Environment:
GAO-07-369T:
GAO Highlights:
Highlights of GAO-07-369T, a testimony before the Committee on Energy
and Natural Resources, United States Senate
Why GAO Did This Study:
Oil and gas production from federal lands and waters is vital to
meeting the nation‘s energy needs. As such, oil and gas companies lease
federal lands and waters and pay royalties to the federal government
based on a percentage of the oil and gas that they produce. The
Minerals Management Service (MMS), an agency in the Department of the
Interior, is responsible for collecting royalties from these leases. In
order to promote oil and gas production, the federal government at
times and in specific cases has provided ’royalty relief,“ waiving or
reducing the royalties that companies must pay. However, as production
from these leases grows and oil and gas prices have risen since a major
1995 royalty relief act, questions have emerged about the financial
impacts of royalty relief.
Based on our work to date, GAO‘s statement addresses (1) the likely
fiscal impacts of royalty relief on leases issued under the Outer
Continental Shelf Deep Water Royalty Relief Act of 1995 and (2) other
authority for granting royalty relief that could further impact future
royalty revenue.
To address these issues our ongoing work has included, among other
things, analyses of key production data maintained by MMS; and reviews
of appropriate portions of the Outer Continental Shelf Deep Water
Royalty Relief Act of 1995, the Energy Policy Act of 2005, and
Interior‘s regulations on royalty relief.
What GAO Found:
While precise estimates remain elusive at this time, our work to date
shows that royalty relief under the Outer Continental Shelf Deep Water
Royalty Relief Act of 1995 will likely cost billions of dollars in
forgone royalty revenue”at least $1 billion of which has already been
lost. In October 2004, MMS estimated that forgone royalties on deep
water leases issued under the act from 1996 through 2000 could be as
high as $80 billion. However, there is much uncertainty in these
estimates. This uncertainty stems from ongoing legal challenges and
other factors that make it unclear how many leases will ultimately
receive royalty relief and the inherent complexity in forecasting
future royalties. We are currently assessing MMS‘s estimate in light of
changing oil and gas prices, revised estimates of future oil and gas
production, and other factors.
Additional royalty relief that can further impact future royalty
revenues is currently provided under the Secretary of the Interior‘s
discretionary authority and the Energy Policy Act of 2005.
Discretionary programs include royalty relief for certain deep water
leases issued after 2000, certain deep gas wells drilled in shallow
waters, and wells nearing the end of their productive lives. The Energy
Policy Act of 2005 mandates relief for leases issued in the Gulf of
Mexico during the five years following the act‘s passage, provides
relief for some gas wells that would not have previously qualified for
royalty relief, and addresses relief in certain areas of Alaska.
Figure: Royalty Relief Zones in the Gulf of Mexico:
[See PDF for Image]
Source: Minerals Management Service, the Department of the Interior.
[End of Figure]
[Hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-07-369T].
To view the full product, including the scope and methodology, click on
the link above. For more information, contact Mark Gaffigan at 202-512-
3841 or gaffiganm@gao.gov.
[End of Section]
Mr. Chairman and Members of the Committee:
We appreciate the opportunity to participate in the Committee's hearing
on federal royalties obtained from the sale of oil and natural gas
produced from federal lands and waters. Oil and gas production from
federal lands and waters is vital to meeting the nation's energy needs,
supplying about 35 percent of all the oil and about 25 percent of all
the natural gas produced in the United States in fiscal year 2005. Oil
and gas companies that lease federal lands and waters agree to pay the
federal government royalties on the resources extracted and produced
from the lease. In fiscal year 2006, oil and gas companies received
over $77 billion from the sale of oil and gas produced from federal
lands and waters, and the Minerals Management Service (MMS), the
Department of the Interior's (Interior) agency responsible for
collecting royalties, reported that these companies paid the federal
government about $10 billion in oil and gas royalties. Clearly, such
large and financially significant resources must be carefully developed
and managed so that our nation's rising energy needs are met while at
the same time the American people are ensured of receiving a fair rate
of return on publicly owned resources, especially in light of the
nation's current and long-range fiscal challenges.
In order to promote oil and gas production, the federal government has
at times and in specific cases provided "royalty relief"--the waiver or
reduction of royalties that companies would otherwise be obligated to
pay. When the government grants royalty relief, it typically specifies
the amounts of oil and gas production that will be exempt from
royalties and may also specify that royalty relief is applicable only
if oil and gas prices remain below certain levels, known as "price
thresholds." For example, the Outer Continental Shelf Deep Water
Royalty Relief Act of 1995, also known as the Deep Water Royalty Relief
Act (DWRRA), mandated royalty relief for oil and gas leases issued in
the deep waters of the Gulf of Mexico from 1996 to 2000. These deep
water regions are particularly costly to explore and develop. However,
as production from these leases has grown, and as oil and gas prices
have risen far above 1995 levels, serious questions have been raised
about the extent to which taxpayer interests have been protected. These
concerns were brought into stark relief when it was learned that MMS
issued leases in 1998 and 1999 that failed to include in the lease
contracts the price thresholds above which royalty relief would no
longer be applicable, making large volumes of oil and natural gas
exempt from royalties and significantly affecting the amount of royalty
revenues collected by the federal government. Although leases are no
longer issued under DWRRA, further royalty relief is currently
available under other legislation and programs, raising the prospect
that the federal government may be forgoing additional royalty
revenues.
Recently, congressional committees, the Department of the Interior's
Office of the Inspector General,[Footnote 1] public interest groups,
and the press have questioned whether our nation's oil and gas
royalties are being properly managed. Many of these entities have also
amplified questions about whether the oil and gas industry is paying
its fair share of royalties, especially in light of rapidly rising oil
and gas prices, record industry profits, and a highly constrained
federal budgetary environment. GAO has expressed similar concerns, and
the U.S. Comptroller General has highlighted royalty relief as an area
needing additional oversight by the 110th Congress.[Footnote 2]
You asked us today to address royalty relief issues based on our
ongoing work for this Committee. Specifically, my testimony (1)
discusses the likely fiscal impacts of royalty relief for leases issued
under the Deep Water Royalty Relief Act of 1995 and (2) describes other
authorities for granting royalty relief that could further impact
future royalty collections. To address these issues, our ongoing work
has included interviews of MMS personnel in the Economics Division in
Herndon, Virginia and the Gulf of Mexico OCS Region in New Orleans,
Louisiana. We have collected and are analyzing key production data
maintained by MMS and are examining numerous documents and studies. We
are also reviewing appropriate portions of the Deep Water Royalty
Relief Act of 1995, the Energy Policy Act of 2005, and Interior's
royalty relief regulations. Our work follows the issuance of our report
last year explaining why oil and gas royalties have not risen at the
same pace as rising oil and gas prices.[Footnote 3] In addition, we are
conducting other work for your Committee on federal oil and gas royalty
rates and the diligent development of federal oil and gas resources.
Our work is being done in accordance with generally accepted government
auditing standards.
In summary, we have found the following:
* Our work to date shows that the likely fiscal impact of leases issued
under the Deep Water Royalty Relief Act of 1995 is in the billions of
dollars in lost royalty revenues, but precise estimates of the costs
are not possible at this time for several reasons. First, MMS's failure
to include price thresholds for leases issued in 1998 and 1999 along
with current attempts to renegotiate these leases have created
uncertainty about which leases will ultimately receive relief. MMS
estimates that the failure to include these price thresholds during a
period of higher oil and gas prices could cost up to $10 billion in
forgone royalty revenue. To date, about $1 billion has already been
lost. In addition, a recent lawsuit questions whether MMS has the
authority to set price thresholds for the leases issued from 1996
through 2000. Depending on the outcome of this litigation, MMS
preliminary estimates indicate that this could result in up to $60
billion in additional forgone royalty revenue. Beyond the problematic
implementation of the royalty relief provisions, assessing the ultimate
fiscal impact of royalty relief is a complex task, involving inherent
uncertainty about future production and prices. We are currently
assessing MMS's estimates of royalty relief costs in light of two years
worth of additional production data and several other variables,
including changing oil and gas prices, revised estimates of the amount
of oil and gas that these leases are expected to produce, the
availability of deep water rigs to drill untested leases, and the
present value of these royalty payments. In addition, any loss in
royalty revenues may be partially mitigated by the potential benefits
of royalty relief, such as increased production or increased fees that
companies are willing to pay the federal government to acquire these
leases.
* Additional royalty relief, potentially affecting future federal
royalty collection, is offered under other programs and legislation.
More specifically, royalty relief can be provided under two existing
authorities: (1) the Secretary of the Interior's discretionary
authority and (2) the Energy Policy Act of 2005. MMS currently
administers several royalty relief programs in the Gulf of Mexico under
discretionary authority provided by the 1978 amendments to the Outer
Continental Shelf Lands Act of 1953. These programs largely address
royalty relief for certain leases issued in deep waters after 2000,
certain deep gas wells drilled in shallow waters, and wells nearing the
end of their productive lives. In addition, the Congress authorized
additional royalty relief under provisions of the Energy Policy Act of
2005. Certain provisions in the Energy Policy Act of 2005 are similar
to those in DWRRA in that they mandate royalty relief for leases issued
in the Gulf of Mexico during the five years following the act's
passage. The Energy Policy Act of 2005 also extends royalty relief to
gas produced in the Gulf of Mexico from certain new wells that
previously would not have qualified for royalty relief. Other
provisions in the act address royalty relief in areas of Alaska where
there currently is little or no production.
Background:
The Department of the Interior (Interior), created by the Congress in
1849, oversees and manages the nation's publicly owned natural
resources, including parks, wildlife habitat, and crude oil and natural
gas resources on over 500 million acres onshore and in the waters of
the Outer Continental Shelf. In this capacity, Interior is authorized
to lease federal oil and gas resources and to collect the royalties
associated with their production. Onshore, Interior's Bureau of Land
Management is responsible for leasing federal oil and natural gas
resources, whereas offshore, MMS has leasing authority. To lease lands
or waters for oil and gas exploration, companies generally must first
pay the federal government a sum of money that is determined through a
competitive auction. This money is called a bonus bid. After the lease
is awarded and production begins, the companies must also pay royalties
to MMS based on a percentage of the cash value of the oil and natural
gas produced and sold.[Footnote 4] Royalty rates for onshore leases are
generally 12 and a half percent whereas offshore, they range from 12
and a half percent for water depths greater than 400 meters to 16 and
two-thirds percent for water depths less than 400 meters. However, the
Secretary of the Interior recently announced plans to raise the royalty
rate to 16 and two-thirds percent for most future leases issued in
waters deeper than 400 meters. MMS also has the option of taking a
percentage of the actual oil and natural gas produced, referred to as
"taking royalties in kind," and selling it themselves or using it for
other purposes, such as filling the nation's Strategic Petroleum
Reserve.
The Deep Water Royalty Relief Act Will Likely Cost the Federal
Government Billions of Dollars in Forgone Royalty Revenues, but Precise
Estimates Remain Elusive:
Based on our work to date, the Deep Water Royalty Relief Act (DWRRA)
will likely cost the federal government billions of dollars in forgone
royalties, but precise estimates of the costs are not possible at this
time for several reasons. First, the failure of MMS to include price
thresholds in the 1998 and 1999 leases and current attempts to
renegotiate these leases has created uncertainty about which leases
will ultimately receive relief. Second, a recent lawsuit is questioning
whether MMS has the authority to set price thresholds for the leases
issue from 1996 through 2000. The outcome of this litigation could
dramatically affect the amount of forgone revenues. Finally, assessing
the ultimate fiscal impact of royalty relief is an inherently complex
task, involving uncertainty about future production and prices. In
October 2004, MMS preliminarily estimated that the total costs of
royalty relief for deep water leases issued under the act could be as
high as $80 billion, depending on which leases ultimately received
relief. MMS made assumptions about several conditions when generating
this estimate and these assumptions need to be updated in 2007 to more
accurately portray potential losses. In addition, the costs of forgone
royalties need to be measured against any potential benefits of royalty
relief, including accelerated drilling and production of oil and gas
resources, increased oil and gas production, and increased fees that
companies are willing to pay through bonus bids for these leases.
Implementing Royalty Relief Has Been Problematic and Resulted In
Unanticipated Costs:
The Congress passed DWRRA in 1995, when oil and gas prices were low and
production was declining both onshore and in the shallow waters of the
Gulf of Mexico. The act contains provisions to encourage the
exploration and development of oil and gas resources in waters deeper
than 200 meters lying largely in the western and central planning areas
of the Gulf of Mexico. The act mandates that royalty relief apply to
leases issued in these waters during the five years following the act's
passage--from November 28, 1995 through November 28, 2000.
As a safeguard against giving away all royalties, two mechanisms are
commonly used to ensure that royalty relief is limited and available
only under certain conditions. The first mechanism limits royalty
relief to specified volumes of oil and gas production called "royalty
suspension volumes," which are dependent upon water depth. Royalty
suspension volumes establish production thresholds above which royalty
relief no longer applies. That is, once total production for a lease
reaches the suspension volume, the lessee must begin paying royalties.
Royalty suspension volumes are expressed in barrels of oil equivalent,
which is a term that allows oil and gas companies to combine oil and
gas volumes into a single measure, based on the relative amounts of
energy they contain.[Footnote 5] The royalty suspension volumes
applicable under DWRRA are as follows: (1) not less than 17.5 million
barrels of oil equivalent for leases in waters of 200 to 400 meters,
(2) not less than 52.5 million barrels of oil equivalent for leases in
waters of 400 to 800 meters, and (3) not less than 87.5 million barrels
of oil equivalent for leases in waters greater than 800 meters. Hence,
there are incentives to drill in increasingly deeper waters. Before
1994, companies drilled few wells in waters deeper than 500 meters. MMS
attributes additional leasing and drilling in deep waters to the
passage of these incentives but also cites other factors for increased
activity, including improved three-dimensional seismic surveys, some
key deep water discoveries, high deep water production rates, and the
evolution of deep water development technology.
After the passage of DWRRA, uncertainty existed as to how royalty
suspension volumes would apply. Interior officials employed with the
department when DWRRA was passed said that they recommended to the
Congress that the act should state that royalty suspension volumes
apply to the production volume from an entire field. However, oil and
gas companies paying royalties under the act interpreted the royalty
suspension volumes as applying to individual leases within a field.
This is important because an oil and gas field commonly consists of
more than one lease, meaning that if royalty suspension volumes are set
for each lease within a field rather than for the entire field,
companies are likely to owe fewer royalties. For example, if a royalty
suspension volume is based on an entire field composed of three leases,
a company producing oil and gas from a 210 million barrel-oil field---
where the royalty suspension volume is set at 100 million---would be
obligated to pay royalties on 110 million barrels (210 minus 100).
However, if the same 210-million barrel field had the same suspension
volume of 100 million barrels applied to each of the three leases, and
70 million barrels were produced from each of the three leases, no
royalties would be due because no lease would have exceeded its royalty
suspension volume. After passage of the act, MMS implemented royalty
relief on a field-basis and was sued by the industry. Interior lost the
case in the Fifth Circuit Court of Appeals.[Footnote 6] In October
2004, MMS estimated that this decision will cost the federal government
up to $10 billion in forgone future royalty revenues.
A second mechanism that can be used to limit royalty relief and
safeguard against giving away all royalties is the price threshold. A
price threshold is the price of oil or gas above which royalty relief
no longer applies. Hence, royalty relief is allowed only so long as oil
and gas prices remain below a certain specified price. At the time of
the passage of DWRRA, oil and gas prices were low--West Texas
Intermediate, a key benchmark for domestic oil, was about $18 per
barrel, and the average U.S. wellhead price for natural gas was about
$1.60 per million British thermal units. In an attempt to balance the
desire to encourage production and ensure a fair return to the American
people, MMS relied on a provision in the act which states that
royalties may be suspended based on the price of production from the
lease. MMS then established price thresholds of $28 per barrel for oil
and $3.50 per million British thermal units for gas, with adjustments
each year since 1994 for inflation, that were to be applied to leases
issued under DWRRA.
As with the application of royalty suspension volumes, problems arose
with the application of these price thresholds. From 1996 through 2000-
-the five years after passage of DWRRA--MMS issued 3,401 leases under
authority of the act. MMS included price thresholds in 2,370 leases
issued in 1996, 1997, and 2000 but did not include price thresholds in
1,031 leases issued in 1998 and 1999. This failure to include price
thresholds has been the subject of congressional hearings and
investigations by Interior's Office of the Inspector General. In
October 2004, MMS estimated that the cost of not including price
thresholds on the 1998 and 1999 leases could be as high as $10 billion.
MMS also estimated that through 2006, about $1 billion had already been
lost. To stem further losses, MMS is currently attempting to
renegotiate the leases issued in 1998 and 1999 with the oil and gas
companies that hold them. To date, MMS has announced successful
negotiations with five of the companies holding these leases and has
either not negotiated or not successfully negotiated with 50 other
companies.
In addition to forgone royalty revenues from leases issued in 1998 and
1999, leases issued under DWRRA in the other three years--1996, 1997,
and 2000--are subject to losing royalty revenues due to legal
challenges regarding price thresholds. In 2006, Kerr McGee Corporation
sued MMS over the application of price thresholds to leases issued
between November 28, 1995 and November 28, 2000, claiming that the act
did not authorize Interior to apply price thresholds to those leases.
[Footnote 7] MMS estimated in October 2004 that if price thresholds are
disallowed for the leases it issued in 1996, 1997, and 2000, an
additional $60 billion in royalty revenue could be lost.
Assessing the Fiscal Impact of Royalty Relief Is Inherently Complex:
Trying to predict the fiscal impacts of royalty relief is a complex and
time-consuming task involving considerable uncertainty. We reviewed
MMS's 2004 estimates and concluded that they had followed standard
engineering and financial practices and had generated the estimates in
good faith. However, any analysis of forgone royalties involves
estimating how much oil and gas will be produced in the future, when it
will be produced, and at what prices. While there are standard
engineering techniques for predicting oil and gas volumes that will
eventually be recovered from a lease that is already producing, there
is always some level of uncertainty involved. Predicting how much oil
and gas will be recovered from leases that are capable of producing but
not yet connected to production infrastructure is more challenging but
certainly possible. Predicting production from leases not yet drilled
is the most challenging aspect of such an analysis, but there are
standard geological, engineering, and statistical methods that can shed
light on what reasonably could be expected from the inventory of 1996
through 2000 leases. Overall, the volume of oil and gas that will
ultimately be produced is highly dependent upon price and technology,
with higher prices and better technology inducing greater exploration,
and ultimately production, from the remaining leases. Future oil
prices, however, are highly uncertain, as witnessed by the rapidly
increasing oil and gas prices over the past several years. It is
therefore prudent to assess anticipated royalty losses using a range of
oil and gas prices rather than a single assumed price, as was used in
the MMS estimate.
Given the degree of uncertainty in predicting future royalty revenues
from deepwater oil and gas leases, we are using current data to
carefully examine MMS's 2004 estimate that up to $80 billion in future
royalty revenues could be lost. There are now two additional years of
production data for these leases, which will greatly improve the
accuracy of estimating future production and its timing. We are also
examining the impact of several variables, including changing oil and
gas prices, revised estimates of the amount of oil and gas that these
leases were originally expected to produce, the availability of deep
water rigs to drill untested leases, and the present value of royalty
payments.
To fully evaluate the impacts of royalty relief, one must consider the
potential benefits in addition to the costs of lost royalty revenue.
For example, a potential benefit of royalty relief is that it may
encourage oil and gas exploration that might not otherwise occur.
Successful exploration could result in the production of additional oil
and gas, which would benefit the country by increasing domestic
supplies and creating employment. While GAO has not assessed the
potential benefits of royalty relief, others have, including the
Congressional Budget Office (CBO) in 1994, and consultants under
contract with MMS in 2004.[Footnote 8] The CBO analysis was theoretical
and forward-looking and concluded that the likely impact of royalty
relief on new production would be very small and that the overall
impact on federal royalty revenues was also likely to be small.
However, CBO cautioned that the government could experience significant
net losses if royalty relief was granted on leases that would have
produced without the relief. The consultant's 2004 study stated that
potential benefits could include increases in the number of leases
sold, increases in the number of wells drilled and fields discovered,
and increases in bonus bids--the amount of money that companies are
willing to pay the federal government for acquiring leases. However,
questions remain about the extent to which such benefits would offset
the cost of lost royalty revenues.
Additional Programs and Legislation Authorize Royalty Relief,
Potentially Affecting Future Federal Royalty Collection:
Although leases are no longer issued under the Deep Water Royalty
Relief Act of 1995, royalty relief can be provided under two existing
authorities: (1) the Secretary of the Interior's discretionary
authority and (2) the Energy Policy Act of 2005. The Outer Continental
Shelf Lands Act of 1953, as amended, granted the Secretary of the
Interior the discretionary authority to reduce or eliminate royalties
for leases issued in the Gulf of Mexico in order to promote increased
production. The Secretary's exercising of this authority can
effectively relieve the oil and gas producer from paying royalties. MMS
administers several royalty relief programs in the Gulf of Mexico under
this discretionary authority. MMS intends for these discretionary
programs to provide royalty relief for leases in deep waters that were
issued after 2000, deep gas wells located in shallow waters, wells
nearing the end of their productive lives, and special cases not
covered by other programs. The Congress also authorized additional
royalty relief under the Energy Policy Act of 2005, which mandates
relief for leases issued in the Gulf of Mexico during the five years
following the act's passage, provides relief for some wells that would
not have previously qualified for royalty relief, and addresses relief
in certain areas of Alaska.
MMS Currently Administers Royalty Relief Using Discretionary Authority:
Under discretionary authority, MMS administers a deep-water royalty
relief program for leases that it issued after 2000. This program is
similar to the program that DWRRA mandated for leases issued during the
five years following its passage (1996 through 2000) in that royalty
relief is dependent upon water depth and applicable royalty suspension
volumes. However, this current program is implemented solely under the
discretion of MMS on a sale-by-sale basis. Unlike under DWRRA, the
price thresholds and the water depths to which royalty relief applies
vary somewhat by lease sale. For example, price thresholds for leases
issued in 2001 were $28 per barrel for oil and $3.50 per million
British thermal units for natural gas, with adjustments for inflation
since 2000. As of March 2006, MMS reported that it issued 1,897 leases
with royalty relief under this discretionary authority, but only 9 of
these leases were producing.
To encourage the drilling of deep gas wells in the shallow waters of
the Gulf of Mexico, MMS implements another program, the "deep gas in
shallow water" program, under final regulations it promulgated in
January 2004. MMS initiated this program to encourage additional
production after noting that gas production had been steadily declining
since 1997. To qualify for royalty relief, wells must be drilled in
less than 200 meters of water and must produce gas from intervals below
15,000 feet. The program exempts from royalties from 15 to 25 billion
cubic feet of gas per well. According to MMS's analysis, these gas
volumes approximate the smallest reservoirs that could be economically
developed without the benefit of an existing platform and under full
royalty rates. In 2001, MMS reported that the average size of 95
percent of the gas reservoirs below 15,000 feet was 15.7 billion cubic
feet, effectively making nearly all of this production exempt from
royalties had it been eligible for royalty relief at that
time.[Footnote 9] This program also specifies a price threshold for
natural gas of $9.91 per million British thermal units in 2006,
substantially exceeding the average NYMEX futures price of $6.98 for
2006, and ensuring that all gas production is exempt from royalties in
2006.
Finally, MMS administers two additional royalty relief programs in the
Gulf of Mexico under its discretionary authority. One program applies
to leases nearing the end of their productive lives. MMS intends that
its provisions will encourage the production of low volumes of oil and
gas that would not be economical without royalty relief. Lessees must
apply for this program under existing regulations. MMS administers
another program for special situations not covered by the other
programs. Lessees who believe that other more formal programs do not
provide adequate encouragement to increase production or development
can request royalty relief by making their case and submitting the
appropriate data. As of March 2006, no leases were receiving royalty
relief under the "end of productive life," and only three leases were
receiving royalty relief under the "special situations" programs.
The Energy Policy Act of 2005 Authorizes Additional Royalty Relief:
The Congress authorized additional royalty relief under the Energy
Policy Act of 2005. Royalty relief provisions are contained in three
specific sections of the act, which in effect: (1) mandate royalty
relief for deep water leases sold in the Gulf of Mexico during the five
years following passage of the act, (2) extend royalty relief in the
Gulf of Mexico to deep gas produced in waters of more than 200 meters
and less than 400 meters, and (3) specify that royalty relief also
applies to certain areas off the shore of Alaska. In the first two
situations, the act specifies the amount of oil and/or gas production
that would qualify for royalty relief and provides that the Secretary
may make royalty relief dependent upon market prices.
Section 345 of the Energy Policy Act of 2005 mandates royalty relief
for leases located in deep waters in the central and western Gulf of
Mexico sold during the five years after the act's passage. Similar to
provisions in DWRRA, specific amounts of oil and gas are exempt from
royalties due to royalty suspension volumes corresponding to the depth
of water in which the leases are located. However, production volumes
are smaller than those authorized under DWRRA, and this specific
section of the Energy Policy Act clearly states that the Secretary may
place limitations on royalty relief based on market prices. For the
three sales that MMS conducted since the passage of the act, MMS
included prices thresholds establishing the prices above which royalty
relief would no longer apply. These price thresholds were $39 per
barrel for oil and $6.50 per million British thermal units for gas,
adjusted upward for inflation that has occurred since 2004. The royalty-
free amounts, referred to as royalty suspension volumes, are as
follows: 5 million barrels of oil equivalent per lease between 400 and
800 meters; 9 million barrels of oil equivalent per lease between 800
and 1,600 meters; 12 million barrels of oil equivalent per lease
between 1,600 and 2,000 meters; and 16 million barrels of oil
equivalent per lease in water greater than 2,000 meters. MMS has
already issued 1,105 leases under this section of the act.
Section 344 of the Energy Policy Act of 2005 contains provisions that
authorize royalty relief for deep gas wells in additional waters of the
Gulf of Mexico that effectively expands the existing royalty-relief
program for "deep gas in shallow water" that MMS administers under pre-
existing regulations. The existing program has now expanded from waters
less than 200 meters to waters less than 400 meters. A provision within
the act exempts from royalties gas that is produced from intervals in a
well below 15,000 feet so long as the well is located in waters of the
specified depth. Although the act does not specifically cite the amount
of gas to be exempt from royalties, it provides that this amount should
not be less than the existing program, which currently ranges from 15
to 25 billion cubic feet. The act also contains an additional incentive
that could encourage deeper drilling--royalty relief is authorized on
not less than 35 billion cubic feet of gas produced from intervals in
wells greater than 20,000 feet deep. The act also states that the
Secretary may place limitations on royalty relief based on market
prices.
Finally, the Energy Policy Act of 2005 contains provisions addressing
royalty relief in Alaska that MMS is already providing. Section 346 of
the act amends the Outer Continental Shelf Lands Act of 1953 by
authorizing royalty relief for oil and gas produced off the shore of
Alaska. MMS has previously included royalty relief provisions within
notices for sales in the Beaufort Sea of Alaska in 2003 and 2005. All
of these sales offered royalty relief for anywhere from 10 million to
45 million barrels of oil, depending on the size of the lease and the
depth of water. Whether leases will be eligible for royalty relief and
the amount of this royalty relief is also dependent on the price of
oil. There currently is no production in the Beaufort Sea. Although
there have been no sales to date under this provision of the act, MMS
is proposing royalty relief for a sale in the Beaufort Sea in 2007.
Section 347 of the Energy Policy Act also states that the Secretary may
reduce the royalty on leases within the Naval Petroleum Reserve of
Alaska in order to encourage the greatest ultimate recovery of oil or
gas or in the interest of conservation. Although this authority already
exists under the Naval Petroleum Reserves Production Act of 1976, as
amended, the Secretary must now consult with the State of Alaska, the
North Slope Borough, and any Regional Corporation whose lands may be
affected.
Conclusions:
In order to meet U.S. energy demands, environmentally responsible
development of our nation's oil and gas resources should be part of any
national energy plan. Development, however, should not mean that the
American people forgo a reasonable rate of return for the extraction
and sale of these resources, especially in light of the current and
long-range fiscal challenges facing our nation, high oil and gas
prices, and record industry profits. Striking a balance between
encouraging domestic production in order to meet the nation's
increasing energy needs and ensuring a fair rate of return for the
American people will be challenging. Given the record of legal
challenges and mistakes made in implementing royalty relief to date, we
believe this balance must be struck in careful consideration of both
the costs and benefits of all royalty relief. As the Congress continues
its oversight of these important issues, GAO looks forward to
supporting its efforts with additional information and analysis on
royalty relief and related issues.
Mr. Chairman, this concludes my prepared statement. I would be pleased
to respond to any questions that you or other Members of the Committee
may have at this time.
GAO Contact and Staff Acknowledgments:
For further information about this testimony, please contact me, Mark
Gaffigan, at 202-512-3841 or gaffiganm@gao.gov. Contact points for our
Offices of Congressional Relations and Public Affairs may be found on
the last page of this statement. Contributors to this testimony include
Dan Haas, Assistant Director; Ron Belak; John Delicath; Glenn Fischer;
Frank Rusco; and Barbara Timmerman.
FOOTNOTES
[1] Minerals Management Service's Compliance Review Process, Department
of the Interior Office of the Inspector General, Report No. C-IN-MMS-
0006-2006 (Washington, D.C.: December, 2006).
[2] Suggested Areas for Oversight for the 110th Congress, GAO-07-235R
(Washington, D.C.: November 17, 2006).
[3] Royalty Revenues: Total Revenues Have Not Increased at the Same
Pace as Rising Natural Gas Prices due to Decreasing Production Sold,
GAO-06-786BR (Washington, D.C.: June 21, 2006).
[4] Specifically, royalties are computed as a percentage of the monies
received from the sale of oil and gas, with the total federal royalty
revenue equal to the volume sold multiplied by the sales price
multiplied by the royalty rate.
[5] One barrel of oil equals one barrel of oil equivalent. One thousand
cubic feet of gas (mcf) is converted to barrels of oil equivalent by
dividing it by 5.62.
[6] Santa Fe Snyder Corp. v. Norton, 385 F.3d 884 (5th Cir. 2004).
[7] Kerr-McGee (Andarko) suit 3/17/06, W.Dist. LA, CV06-0439LC
[8] Waiving Royalties for Producers of Oil and Gas from Deep Waters,
Congressional Budget Office, May 1994. Effects of Royalty Incentives
for Gulf of Mexico Oil and Gas Leases, P.K. Ashton, L.O. Upton III, and
M.H. Rothkopf, under Contract No. 0103CT71722, U.S. Department of the
Interior, Minerals Management Service, Economics Division, Herndon, VA,
OCS Study 2004-077.
[9] The average of the other 5 percent was 105 billion cubic feet, and
these reservoirs are within the highly productive Norphlet Trend.
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