Oil and Gas Royalties: Royalty Relief Will Likely Cost the Government Billions, but the Final Costs Have Yet to Be Determined
Published: 2007-01-18T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: 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.
section_title: What GAO Found
paragraphs: 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.

section_title: Letter
paragraphs: 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, 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.
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.  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.
subsections: section_title: Background
paragraphs: 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. 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.
section_title: The Deep Water Royalty Relief Act Will Likely Cost the Federal Government Billions of Dollars in Forgone Royalty Revenues, but Precise Estimates Remain Elusive
paragraphs: 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.
subsections: section_title: Implementing Royalty Relief Has Been Problematic and Resulted In Unanticipated Costs
paragraphs: 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. 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. 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.  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.
section_title: Assessing the Fiscal Impact of Royalty Relief Is Inherently Complex
paragraphs: 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.  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.
section_title: Additional Programs and Legislation Authorize Royalty Relief, Potentially Affecting Future Federal Royalty Collection
paragraphs: 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.
subsections: section_title: MMS Currently Administers Royalty Relief Using Discretionary Authority
paragraphs: 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.  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.
section_title: The Energy Policy Act of 2005 Authorizes Additional Royalty Relief
paragraphs: 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.
section_title: Conclusions
paragraphs: 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.
section_title: GAO Contact and Staff Acknowledgments
paragraphs: 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.
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