Oil and Gas Royalties: Royalty Relief Will Likely Cost the	 
Government Billions, but the Final Costs Have Yet to Be 	 
Determined (18-JAN-07, GAO-07-369T).				 
                                                                 
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.	 
-------------------------Indexing Terms------------------------- 
REPORTNUM:   GAO-07-369T					        
    ACCNO:   A64970						        
  TITLE:     Oil and Gas Royalties: Royalty Relief Will Likely Cost   
the Government Billions, but the Final Costs Have Yet to Be	 
Determined							 
     DATE:   01/18/2007 
  SUBJECT:   Energy policy					 
	     Federal legislation				 
	     Financial analysis 				 
	     Gas leases 					 
	     Gas resources					 
	     Losses						 
	     Oil leases 					 
	     Policy evaluation					 
	     Prices and pricing 				 
	     Public lands					 
	     Royalty payments					 
	     Cost estimates					 
	     Gulf of Mexico					 

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GAO-07-369T

   

     * [1]Background
     * [2]The Deep Water Royalty Relief Act Will Likely Cost the Feder

          * [3]Implementing Royalty Relief Has Been Problematic and Resulte
          * [4]Assessing the Fiscal Impact of Royalty Relief Is Inherently

     * [5]Additional Programs and Legislation Authorize Royalty Relief

          * [6]MMS Currently Administers Royalty Relief Using Discretionary
          * [7]The Energy Policy Act of 2005 Authorizes Additional Royalty

     * [8]Conclusions
     * [9]GAO Contact and Staff Acknowledgments
     * [10]GAO's Mission
     * [11]Obtaining Copies of GAO Reports and Testimony

          * [12]Order by Mail or Phone

     * [13]To Report Fraud, Waste, and Abuse in Federal Programs
     * [14]Congressional Relations
     * [15]Public Affairs

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

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,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.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.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.

1Minerals 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).

2Suggested Areas for Oversight for the 110th Congress, [16]GAO-07-235R
(Washington, D.C.: November 17, 2006).

3Royalty Revenues: Total Revenues Have Not Increased at the Same Pace as
Rising Natural Gas Prices due to Decreasing Production Sold,
[17]GAO-06-786BR (Washington, D.C.: June 21, 2006).

In summary, we have found the following:

           o 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.

           o 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.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.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.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. 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 2004.8
           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.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 [email protected] . 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.
			  
4Specifically, 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.

5One 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.

6Santa Fe Snyder Corp. v. Norton, 385 F.3d 884 (5th Cir. 2004).

7Kerr-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.

9The 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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Highlights of [26]GAO-07-369T , a testimony before the Committee on Energy
and Natural Resources, United States Senate

January 18, 2007

OIL AND GAS ROYALTIES

Royalty Relief Will Likely Cost the Government Billions, but the Final
Costs Have Yet to Be Determined

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.

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.

Royalty Relief Zones in the Gulf of Mexico

References

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