This is the accessible text file for GAO report number GAO-14-50 entitled 'Oil and Gas Resources: Actions Needed for Interior to Better Ensure a Fair Return' which was released on December 17, 2013. This text file was formatted by the U.S. Government Accountability Office (GAO) to be accessible to users with visual impairments, as part of a longer term project to improve GAO products' accessibility. Every attempt has been made to maintain the structural and data integrity of the original printed product. Accessibility features, such as text descriptions of tables, consecutively numbered footnotes placed at the end of the file, and the text of agency comment letters, are provided but may not exactly duplicate the presentation or format of the printed version. The portable document format (PDF) file is an exact electronic replica of the printed version. We welcome your feedback. Please E-mail your comments regarding the contents or accessibility features of this document to Webmaster@gao.gov. This is a work of the U.S. government and is not subject to copyright protection in the United States. It may be reproduced and distributed in its entirety without further permission from GAO. Because this work may contain copyrighted images or other material, permission from the copyright holder may be necessary if you wish to reproduce this material separately. United States Government Accountability Office: GAO: Report to the Chairman, Committee on Energy and Natural Resources, U.S. Senate: December 2013: Oil and Gas Resources: Actions Needed for Interior to Better Ensure a Fair Return: GAO-14-50: GAO Highlights: Highlights of GAO-14-50, a report to the Chairman, Committee on Energy and Natural Resources, U.S. Senate. Why GAO Did This Study: In fiscal year 2012, companies received over $66 billion from the sale of oil and gas produced from federal lands and waters, and they paid $10 billion to the federal government for developing these resources according to the Department of the Interior. The federal government seeks a fair return on its share of revenue from leasing and production activities on federal lands and waters through the federal oil and gas fiscal system. Under the fiscal system, companies pay royalties, rents, and other payments—payments generally specified in lease terms—and taxes on profits from the sale of oil and gas produced from federal leases. In May 2007, GAO found, based on several studies, that the government received one of the lowest percentages of value of oil and gas produced in the world. In September 2008, GAO found that Interior had not evaluated the federal oil and gas fiscal system for over 25 years and recommended that a periodic assessment was needed. GAO was asked to review Interior’s collection of oil and gas revenues. This report examines steps Interior has taken to ensure the public receives a fair return on oil and gas resources since 2007. GAO reviewed applicable law and regulations; examined prior GAO studies, Interior policies and documents; and interviewed officials. What GAO Found: Interior has taken some steps intended to help ensure a fair return on federal oil and gas resources but does not have documented procedures for periodically conducting assessments of the fiscal system. Specifically, Interior has taken the following steps: * Changed offshore lease terms and considered but has not changed onshore lease terms. Interior changed certain offshore lease terms— including raising royalty rates twice in response to changing market conditions. For onshore resources, which are subject to many of the same market conditions, Interior has considered but not made changes to royalty rates. Interior officials are currently unable to make timely adjustments to onshore royalty rates. Current regulations generally provide for a fixed onshore royalty rate that limits Interior’s flexibility to make timely adjustments. * Contracted for studies of various aspects of the fiscal system. Interior contracted for three studies examining its fiscal system including a study done in 2011, in response to GAO’s September 2008 report that compared the U.S. government’s oil and gas fiscal system to other resource owners. Interior officials said the reports provided some useful information such as how fiscal terms in the United States compared to other resource owners. * Interior is examining potential regulatory changes that could simplify royalty payments. Interior is examining potential regulatory changes that could simplify royalty payments. GAO found in the past that complex valuation regulations can result in inaccurate royalty payments made by industry, and this could increase costs to ensure accurate royalty payments because of the need for potentially detailed and time-consuming audits of records. In May 2011, Interior published the Advance Notice Of Proposed Rulemaking for a proposed rule currently undergoing internal review. According to officials, the proposed rule is expected to be published in 2014, and officials explained that it took several years due to factors including the complexity of oil and gas valuation. Interior does not have documented procedures in place for determining when to conduct periodic assessments of the fiscal system. Although Interior recently contracted for such an assessment, it was the first in well over 25 years. Without documented procedures, Interior will not have reasonable assurance that it will consistently conduct such assessments in the future and, without periodically conducting such assessments, Interior cannot know whether there is a proper balance between the attractiveness of federal leases for investment and appropriate returns for federal oil and gas resources, limiting Interior’s ability to ensure a fair return. Further, Interior does not have documented procedures for determining whether and how to make changes to new offshore lease terms. Without documented procedures for determining whether and how to make changes to new offshore lease terms, Interior’s rationale is not transparent and may result in inconsistent decisions. Such inconsistencies would undermine Interior’s credibility and ability to better ensure a fair return on federal oil and gas resources. What GAO Recommends: GAO recommendations include that Interior establish documented procedures for (1) periodically assessing the fiscal system and (2) determining whether and how to change new offshore lease terms. Interior concurred with GAO’s recommendations. View [hyperlink, http://www.gao.gov/products/GAO-14-50]. For more information, contact Frank Rusco at (202) 512-3841 or ruscof@gao.gov. [End of section] Contents: Letter: Background: Interior Has Taken Some Steps to Help Ensure a Fair Return but Does Not Have Procedures for Periodically Conducting Assessments of the Fiscal System: Conclusions: Recommendations for Executive Action: Agency Comments: Appendix I: Comments from the Department of the Interior: Appendix II: GAO Contact and Staff Acknowledgments: Tables: Table 1: History of Lease Terms for Gulf of Mexico Outer Continental Shelf Oil and Gas Leases 2005-2013: Table 2: Interior-Contracted Studies of the Oil and Gas Fiscal System 2009-2013: Figures: Figure 1: Royalty Rates and Oil Prices, January 2000 through July 2013: Figure 2: Royalty Rates and Gas Prices, January 2000 through July 2013: Abbreviations: BLM: Bureau of Land Management: BOEM: Bureau of Ocean Energy Management: MMS: Minerals Management Service: ONRR: Office of Natural Resources Revenue: [End of section] GAO: United States Government Accountability Office: 441 G St. N.W. Washington, DC 20548: December 6, 2013: The Honorable Ron Wyden: Chairman: Committee on Energy and Natural Resources: United States Senate: Dear Mr. Chairman: Production of oil and natural gas from leases on federal lands and waters is an important part of the nation's energy portfolio and a significant source of revenue for the federal government. Domestic and foreign companies received over $66 billion from the sale of oil and gas produced from federal lands and waters in fiscal year 2012, according to the Department of the Interior. Interior reported collecting about $9.7 billion in 2012 from royalties and other payments from these companies, making oil and gas resources one of the federal government's largest nontax sources of revenue. The terms and conditions under which the government collects these revenues are referred to as the "oil and gas fiscal system" and generally include royalties and other payments for the rights to explore, develop, and sell oil and gas resources. However, over the past several decades, we, and others, have identified problems with Interior's management of the federal oil and gas fiscal system. For example, in 1982, a task force convened by Interior found that management of the fiscal system needed a thorough overhaul and provided 60 recommendations for improving the fiscal accountability of the nation's onshore and offshore resources.[Footnote 1] Upon the completion of the task force's work, the Secretary of the Interior informed Congress, in March 1983, that Interior had refined the system and that a "full and fair return" to the American people would be assured. In May 2007, we found that, based on the results of a number of studies, the government receives one of the lowest government takes--commonly understood to be the total revenue, as a percentage of the value of oil and natural gas produced--in the world.[Footnote 2] In addition, in September 2008, we found that Interior did not routinely evaluate the federal oil and gas fiscal system and suggested that Congress should consider directing the Secretary of the Interior to (1) convene an independent panel to conduct a comprehensive review of the oil and gas fiscal system and (2) establish procedures to periodically evaluate the state of the fiscal system.[Footnote 3] In 2011, in part because of the challenges identified in our past work concerning Interior not having reasonable assurance that it is collecting its share of revenue from oil and gas produced on federal lands, we added Interior's management of federal oil and gas resources to GAO's list of programs at high risk of fraud, waste, abuse, and mismanagement. [Footnote 4] Interior has oversight responsibility for the development of federal oil and gas resources located under over 260 million surface onshore acres, 700 million subsurface onshore acres, and more than 1.7 billion offshore acres in the waters of the outer continental shelf.[Footnote 5] Companies that develop and produce oil and gas from these federal lands and waters do so over a specified period of time under leases obtained from and administered by agencies of Interior--the Bureau of Land Management (BLM) for onshore leases and the Bureau of Ocean Energy Management (BOEM) for offshore leases. Interior's Office of Natural Resources Revenue (ONRR) is responsible for collecting revenues from onshore and offshore leases. Interior acts on behalf of the American people to manage the federal oil and gas system to ensure a fair return to the public for the development of oil and gas resources. For offshore resources, one of the stated purposes of the Outer Continental Shelf Lands Act, as amended--which governs the management of oil and gas resources--is to ensure the public "a fair and equitable return" on the resources on the outer continental shelf. The law directs the Secretary of the Interior to conduct leasing activities to assure receipt of fair market value for the lands leased and the rights conveyed by the federal government. Further, for onshore resources, Interior relies on the competitive leasing process required by the Mineral Leasing Act, as amended, to ensure fair market value for onshore oil and gas resources. Broadly, we refer to the government collecting an appropriate share of revenue from leasing and production activities on federal lands and waters as ensuring a fair return. Because the revenues these leases generate depend, in part, on the amounts of oil and natural gas that companies produce from them, the federal government has sought to design fiscal systems that balance the goal of providing a fair return with sufficient financial incentives for companies to commit resources to exploring, developing, and producing oil and gas from their leases. You asked us to review Interior's collection of oil and gas revenues as part of our ongoing efforts to support congressional oversight of GAO's high-risk areas. This report examines the steps Interior has taken to ensure that the public receives a fair return on federal oil and gas resources since 2007. To conduct this work, we reviewed applicable law, regulations, and guidance that govern Interior's management of oil and gas resources including the Outer Continental Shelf Lands Act, the Mineral Leasing Act, and the Federal Onshore Oil and Gas Leasing Reform Act; examined our prior reports and Interior leasing program policies and documents; and interviewed Interior officials from BOEM, BLM, ONRR, and the Solicitor's Office. We also conducted a high-level review of the Interior-contracted studies of the fiscal system in order to summarize the studies' purpose and goals. We also compared actions that Interior took to standards for internal control in the federal government.[Footnote 6] We conducted this performance audit from October 2012 to December 2013 in accordance with generally accepted government auditing standards. Those standards require that we plan and perform the audit to obtain sufficient, appropriate evidence to provide a reasonable basis for our findings and conclusions based on our audit objectives. We believe that the evidence obtained provides a reasonable basis for our findings and conclusions based on our audit objectives. Background: This section describes (1) the federal oil and gas fiscal system, (2) leasing processes, and (3) the history of oil and gas management challenges. Created by Congress in 1849, Interior oversees the nation's publicly owned natural resources including parks, wildlife habitat, and crude oil and natural gas resources on millions of acres onshore and offshore in the waters of the outer continental shelf. With regard to oil and gas in particular, Interior leases federal lands and waters (also referred to as submerged lands), issues permits for oil and gas drilling, and is responsible for ensuring that the federal government receives payment from the private companies that extract oil and gas from federal leases. The Federal Oil and Gas Fiscal System: The oil and gas fiscal system defines the applicable payments to the government from companies that lease federal lands and waters for oil and gas development. These payments include royalties, rents, and other payments--items generally specified within the lease terms. The revenues collected by the federal government on oil and gas development are shared with states, as directed by statute, and the remaining funds are deposited in the U.S. Treasury. In addition to the collection of these payments by Interior, the federal government assesses taxes on the profits companies earn on the sale of oil and gas produced from federal leases. Under the oil and gas fiscal system, companies bid on leases that Interior makes available. Interior awards the lease to the highest bidder generally based on a lump-sum payment called a bonus bid that is due when the lease is issued. The lease is a contract and conveys the rights to explore for and produce the oil and gas in a specified area to a company that holds the lease. The company is then subject to the payment of rental rates until production begins and then to payment of royalties on any oil and gas that is eventually produced on the lease. The royalty rate is a percentage of the value of production, and the royalty owed is the volume of production times the unit value of production times the royalty rate. The federal government receives royalty payments once production starts. In fiscal year 2012, the $9.7 billion in oil and gas revenue collected included royalties (about $8.5 billion or 87 percent), bonus bids (about $947 million or 10 percent),[Footnote 7] and rental fees (about $272 million or 3 percent). Currently Interior has the authority to change certain lease terms-- such as the duration of the lease, royalty rates, and rental fees-- within the overall oil and gas fiscal system. For new offshore leases, Interior is allowed by statute to change the lease terms for the bonus bid structure, rent, and royalty rates.[Footnote 8] For new onshore leases, Interior is generally allowed by statute to change these same lease terms but with certain limits on flexibility. For onshore leases, Interior's regulations--issued in the 1980s--currently establish a royalty rate of 12.5 percent.[Footnote 9] As such, changes to onshore royalty rates would require Interior to revise its regulations. With regard to taxes on corporate profits, only Congress may change the tax components of the oil and gas fiscal system as Interior does not have the authority to do so. For both offshore and onshore leases, ONRR collects revenue from companies for the royalties, rents, bonuses, and other revenues generated throughout the leasing process. In this regard, ONRR has the responsibility to ensure that these revenues are accurately reported and paid in compliance with laws, regulations, and lease terms. ONRR establishes the regulations for how oil and gas are valued for royalty purposes, which affects the royalties that companies pay. Leasing Processes: Interior's processes for issuing federal leases vary depending on whether they are offshore or onshore. Offshore Leases: For offshore leases, management of oil and gas resources is primarily governed by the Outer Continental Shelf Lands Act, which sets forth procedures for leasing, exploration, and development and production of those resources. BOEM is the bureau within Interior responsible for implementing these requirements of the act related to preparing the leasing program. The act calls for the preparation of an oil and gas leasing program designed to best meet the nation's energy needs while also taking into account a range of principles and considerations specified by the act. Specifically, the act provides that "management of the outer Continental Shelf shall be conducted in a manner which considers economic, social, and environmental values of the renewable and nonrenewable resources contained in the outer Continental Shelf, and the potential impact of oil and gas exploration on other resource values of the outer Continental Shelf and the marine, coastal, and human environments."[Footnote 10] Furthermore, the act provides that the outer continental shelf is a "vital national resource reserve held by the federal government for the public, which should be made available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs."[Footnote 11] The act grants the Secretary the authority to issue leases and states that "leasing activities shall be conducted to assure receipt of fair market value for the lands leased and the rights conveyed by the Federal Government."[Footnote 12] The Outer Continental Shelf Lands Act requires the Secretary of the Interior to prepare an oil and gas leasing program that consists of a 5-year schedule of proposed lease sales that shows the size, timing, and location of leasing activity as precisely as possible. Every 5 years, Interior selects the areas it will offer for leasing and establishes a schedule for individual lease sales. These leases are offered for competitive bidding, and all eligible companies are invited to submit written sealed bids for the lease and rights to explore, develop, and produce oil and gas resources on these leases. These rights last for a set period of time, referred to as the initial period of the lease,[Footnote 13] which varies depending on the water depth.[Footnote 14] Interior estimates the fair market value of each lease, and the minimally acceptable bid is derived from this estimate. The bidder that submits the highest bonus bid that meets or exceeds Interior's minimum bid is awarded the lease. If a high bid does not satisfy any of the required conditions, the bid is rejected. In the event that no bid is received or no bids equal or exceed the minimum bid, Interior may choose to withdraw the lease--possibly offering it again at a future date. Onshore Leases: For onshore leases, BLM's current leasing process was established in the Mineral Leasing Act of 1920, as amended, and the Mineral Leasing Act for Acquired Lands of 1947, as amended. Interior relies on the competitive leasing process required by the Mineral Leasing Act to ensure fair market value for onshore oil and gas resources. In addition, the Federal Land Policy and Management Act, though not specific to federal oil and gas resources, calls for the management of public lands in a manner that protects historical and environmental resources, provides for recreational and other uses, and ensures "fair market value" is received for their use and resources. BLM offers parcels of land nominated by industry and the public, as well as some it identifies. As with offshore leases, Interior initially offers onshore leases through a competitive bidding process; however, bonus bids are received in an oral auction rather than in a sealed written form, and Interior does not evaluate bid adequacy on a parcel-by- parcel basis. Instead, by law, it requires a uniform national minimum acceptable bid of $2 per acre that the Secretary has the authority to raise. If Interior receives any bids on an offered lease, the lease is awarded to the highest bidder. All onshore leases that do not receive any bids in the initial offer must be offered noncompetitively the day after and remain available for noncompetitive leasing for a period of 2 years after the competitive lease sale. Any of these available leases may be acquired noncompetitively on a first-come, first-served basis for the minimum acceptable bid. About 40 percent of existing BLM oil and gas leases were issued as noncompetitive leases.[Footnote 15] For all competitively issued leases, the winning bidder must pay Interior the full amount of the bonus bid to become the lessee. The lessee then pays a fixed amount of rent each year until the lease begins producing or the lease terminates, expires, is canceled, suspended, or relinquished. History of Oil and Gas Management Challenges: In the 1970s and early 1980s, Interior's management of the oil and gas revenue collection system faced criticism by us and Interior's Office of the Inspector General. Interior's Inspector General issued five reports critical of the program between 1969 and 1977 and, in 1981, we reported that Interior was not collecting potentially hundreds of millions in royalties due from federal oil and gas leases.[Footnote 16] In response, in 1981, the Secretary of the Interior established the Commission on Fiscal Accountability of the Nation's Energy Resources, better known as the Linowes Commission named for the chairman of the commission, to investigate allegations of irregularities in royalty payments, among other issues. The Linowes Commission raised a number of serious concerns and in its report stated that "management of royalties for the nation's energy resources has been a failure for more than 20 years. Because the Federal government has not adequately managed this multibillion dollar enterprise, the oil and gas industry is not paying all the royalties it rightly owes."[Footnote 17] The report cited a range of problems, including the failure to verify data reported by companies and late payments and underpayments, and concluded that, "[i]n short, the industry is essentially on an honor system." Among its 60 recommendations for improving the fiscal accountability of onshore and offshore resources, the commission called for raising onshore royalty rates to "appropriate levels." Specifically, the commission recommended that the onshore royalty rate for oil and gas be raised from 12.5 percent to 16.67 percent generally for new and renegotiated leases consistent with offshore royalty rates of 16.67 percent in place at that time. Following the work of the commission, Interior and Congress took several actions aimed at improving management of revenue collection. In particular, the Secretary of the Interior, by secretarial order, reorganized the task of administering revenue collection under a new bureau; specifically, the Minerals Management Service (MMS) was created within Interior, in part, from the division of the U.S. Geological Survey--which was originally tasked with administering revenue collection, among other duties--to improve management of federal leasing revenues.[Footnote 18] In addition, Congress passed legislation aimed at improving the collection of revenue including the Federal Oil and Gas Royalty Management Act of 1982 and the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996. In 2007, Interior's Subcommittee on Royalty Management--a subcommittee of the Royalty Policy Committee chartered to provide advice on royalty management issues and other mineral-related policies to the Secretary and other departmental officials responsible for managing mineral leasing activities--reported that a number of aspects of royalty management activities required prompt and, in some cases, significant management attention to ensure public confidence.[Footnote 19] In particular, the report included over 100 recommendations to improve Interior's management of oil and gas resources, including those aimed at revising its valuation regulations and guidelines that govern the valuation of oil and gas resources for royalty purposes. According to Interior documentation, as of August 2012, 15 recommendations remain open. In our May 2007 report, we found that, based on results of a number of studies, the government receives one of the lowest government takes in the world.[Footnote 20] In September 2008,[Footnote 21] we found that the fiscal system needed comprehensive reassessment and that Interior did not routinely evaluate the federal oil and gas fiscal system. Interior disagreed with recommendations in the draft report that it perform a comprehensive review of the fiscal system using an independent panel and adopt policies and procedures to keep abreast of important changes in the oil and gas market and in other countries' efforts to adjust their oil and gas management practices in light of these changes. Thus, in the final report, we suggested that Congress should consider directing the Secretary of the Interior to (1) convene an independent panel to perform a comprehensive review of the federal system for collecting oil and gas revenue and (2) establish procedures for periodically collecting data and information and conducting analyses to determine how the federal government take and the attractiveness for oil and gas investors in each federal oil and gas region compare to those of other resource owners and report this information to the Congress. Actions taken in response to this suggestion are discussed later in this report. In 2011, in part because of the challenges identified in our past work, we added Interior's management of federal oil and gas resources to our list of programs at high risk of fraud, waste, abuse, and mismanagement. [Footnote 22] In the 2013 update of the high-risk list, we found that some progress had been made related to Interior's management of federal oil and gas resources and narrowed the federal oil and gas high-risk area to focus, in part, on the remaining issues related to revenue collection and ensuring that the public is getting an appropriate share of oil and gas revenues.[Footnote 23] Interior Has Taken Some Steps to Help Ensure a Fair Return but Does Not Have Procedures for Periodically Conducting Assessments of the Fiscal System: Interior has taken some steps to help ensure a fair return on federal oil and gas resources since our 2007 report, including: (1) changing offshore lease terms, while considering but not making changes to onshore lease terms; (2) contracting for studies of various aspects of the fiscal system; and (3) examining potential regulatory changes that could simplify royalty payments and collections. However, Interior does not have documented procedures in place for determining when to periodically conduct assessments of the fiscal system to ensure a fair return or for determining whether and how to make changes to lease terms for new offshore leases. Interior Has Taken Some Steps Aimed at Ensuring a Fair Return: Interior has taken some steps aimed at ensuring a fair return, including changing offshore lease terms--such as increasing royalty rates, minimum bids, and rental rates--but onshore lease terms have not changed in recent years though onshore and offshore leasing programs are subject to many of the same market conditions. For example, while onshore royalty rates have remained at 12.5 percent, certain offshore royalty rates began increasing in 2007 to the current offshore royalty rate of 18.75 percent. Figures 1 and 2 depict changes to offshore and onshore royalty rates along with oil and gas price fluctuations, respectively, from January 2000 through July 2013. In addition, Interior has contracted for studies of various aspects of its fiscal system, including an assessment of how the federal fiscal system compared with the systems of other oil and gas resource owners (including owners in other countries); an analysis of policies that affect the pace of leasing in the Gulf of Mexico; and an analysis of the benefits, costs, and economic impacts of raising onshore royalty rates. Interior is also examining potential regulatory changes that could simplify royalty payments and collections. Figure 1: Royalty Rates and Oil Prices, January 2000 through July 2013: [Refer to PDF for image: multiple line graph] Oil price: dollars per barrel in 2012 dollars. January 2000; Oil price: $37.10; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2000; Oil price: $39.46; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2001; Oil price: $38.80; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2001; Oil price: $34.19; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2002; Oil price: $25.57; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2002; Oil price: $34.38; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2003; Oil price: $41.64; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2003; Oil price: $38.40; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2004; Oil price: $42.53; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2004; Oil price: $49.43; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. January 2005; Oil price: $56.39; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2005; Oil price: $69.32; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. January 2006; Oil price: $75.83; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2006; Oil price: $83.95; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. January 2007; Oil price: $61.83; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2007; Oil price: $81.70; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 16.7%. January 2008; Oil price: $101.12; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 16.7%. July 2008; Oil price: $139.21; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2009; Oil price: $45.35; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2009; Oil price: $68.39; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2010; Oil price: $83.00; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2010; Oil price: $80.37; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2011; Oil price: $92.96; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2011; Oil price: $98.88; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2012; Oil price: $101.57; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2012; Oil price: $88.09; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2013; Oil price: $94.48; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2013; Oil price: $102.88; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. Sources: GAO analysis of Energy Information Administration and Interior data. [End of figure] Figure 2: Royalty Rates and Gas Prices, January 2000 through July 2013: [Refer to PDF for image: multiple line graph] Natural gas price: dollars per million British thermal units in 2012 dollars. January 2000; Natural gas price: $3.29; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2000; Natural gas price: $5.30; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2001; Natural gas price: $10.71; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2001; Natural gas price: $4.02; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2002; Natural gas price: $3.01; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2002; Natural gas price: $3.81; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2003; Natural gas price: $6.86; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; July 2003; Natural gas price: $6.28; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%; January 2004; Natural gas price: $7.61; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2004; Natural gas price: $7.19; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. January 2005; Natural gas price: $7.40; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2005; Natural gas price: $8.97; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. January 2006; Natural gas price: $10.06; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2006; Natural gas price: $6.96; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. January 2007; Natural gas price: $7.43; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 12.5%. July 2007; Natural gas price: $6.86; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 16.7%. January 2008; Natural gas price: $8.69; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 16.8%: Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 16.7%. July 2008; Natural gas price: $139.21; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2009; Natural gas price: $5.70; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2009; Natural gas price: $3.60; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2010; Natural gas price: $6.18; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2010; Natural gas price: $4.88; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2011; Natural gas price: $4.68; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2011; Natural gas price: $4.49; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2012; Natural gas price: $2.70; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2012; Natural gas price: $2.96; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. January 2013; Natural gas price: $3.32; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. July 2013; Natural gas price: $3.56; Onshore royalty rate and offshore royalty rate (Alaska): 12.5%; Offshore royalty rate in water depths less than 400 meters (Gulf of Mexico): 18.8%; Offshore royalty rate in water depths greater than or equal to 400 meters (Gulf of Mexico): 18.8%. Sources: GAO analysis of Energy Information Administration and Interior data. [End of figure] Interior Changed Offshore Lease Terms: In recent years, Interior changed some offshore lease terms in an effort to ensure a fair return on oil and gas resources. Since 2007, Interior increased offshore lease terms including royalty rates, rental rates, and the minimum bid for certain offshore leases as follows: * Increased royalty rates. From 2007 through 2008, Interior increased royalty rates for new leases by 50 percent. In 2007, Interior increased the royalty rate for new Gulf of Mexico leases from 12.5 percent to 16.67 percent for new leases in water depths greater than 400 meters. In 2008, Interior increased the rate again for all Gulf of Mexico leases to 18.75 percent. As of August 2013, all Gulf of Mexico royalty rates for new leases are 18.75 percent.[Footnote 24] According to Interior officials and documents, incremental increases in royalty rates were instituted in response to a variety of factors including (1) increased oil and gas prices; (2) perceived improvements in exploration and production technologies, especially in deep water; and (3) the competitive market for offshore leases. Interior estimated that the royalty rate increase from 16.67 percent to 18.75 percent would result in a net increase in the total Gulf of Mexico federal revenues from bonuses, rents, and royalties from new leases of $4.3 billion, a 5 percent increase from $87.4 to $91.7 billion over 30 years.[Footnote 25] After this 2008 royalty rate increase, Interior documents stated that demand remained strong for newly offered leases in the Gulf of Mexico and that Interior observed strong bidding interest in the three subsequent lease sales.[Footnote 26] * Escalating and increased rental rates. Interior established escalating rental rates--rates that increase over the duration of the lease--to encourage faster exploration and development of leases, or earlier relinquishment when exploration is unlikely to be undertaken by the lessee. Specifically, in 2007, Interior implemented escalating rental rates for leases offered in less than 400 meters of water--and in 2009, for leases offered in at least 400 meters of water.[Footnote 27] Also, in 2009, Interior increased rental rates for new Gulf of Mexico leases in all water depths. Interior estimated that the increased rental rates and escalating rent rates in water depths greater than 400 meters would result in five fewer lease tracts receiving bids but an increase in rental revenue of $57 million over the initial lease term for leases resulting from that sale. $27 million of this $57 million was attributed to the increase in base rental rates.[Footnote 28] In addition, the increased rental rates did not appear to reduce the number of lease blocks to be explored, according to Interior documents. * Increased minimum bids. In 2011, Interior increased the minimum bid for leases offered in at least 400 meters of water in the Gulf of Mexico to $100 per acre, up from $37.50 per acre.[Footnote 29] According to Interior's Proposed Final Outer Continental Shelf Oil & Gas Leasing Program 2012-2017, the minimum bid was raised, in part, to account for increases in oil prices and to encourage optimal timing of leasing. Interior officials told us that a review of the minimum bid was initiated because the minimum bid had not been changed in some time. In addition, Interior analysis showed that a minimum bid of $100 per acre would be generally equivalent to the cost of the minimum bid in the past, going back to 1999, adjusted for differences in prices, costs, and royalty rates. For details on the recent history of lease terms in the Gulf of Mexico, see table 1; changes in lease terms are highlighted in gray. Table 1: History of Lease Terms for Gulf of Mexico Outer Continental Shelf Oil and Gas Leases 2005-2013: Lease sale: 196; Sale date: 8/17/2005; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 6.25; 200-400: 9.50; 400-800: 9.50; 800-1,600: 9.50; 1,600-2,000: 9.50; More than 2,000: 9.50. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 37.50; 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 0-200: 16.67%[A]; 200-400: 16.67%; 400-800: 12.50%[A]; 800-1,600: 12.50%[A]; 1,600-2,000: 12.50%[A]; More than 2,000: 12.50%[A]. Lease sale: 198 and 200; Sale date: 3/15/2006-8/16/2006; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 6.25; 200-400: 9.50; 400-800: 9.50; 800-1,600: 9.50; 1,600-2,000: 9.50; More than 2,000: 9.50. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 37.50; 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 0-200: 16.67%[A]; 200-400: 16.67%[A]; 400-800: 12.50%[A]; 800-1,600: 12.50%[A]; 1,600-2,000: 12.50%[A]; More than 2,000: 12.50%[A]. Lease sale: 204 and 205; Sale date: 8/22/2007-10/3/2007; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 6.25[B]; 200-400: 9.5[B]; 400-800: 9.50; 800-1,600: 9.50; 1,600-2,000: 9.50; More than 2,000: 9.50. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 37.50; 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 0-200: 16.67%[A]; 200-400: 16.67%[A]; 400-800: 16.67%[A]; 800-1,600: 16.67%[A]; 1,600-2,000: 16.67%[A]; More than 2,000: 16.67%[A]. Lease sale: 224; Sale date: 3/19/2008; Lease terms: Rent ($/acre); Water depth (meters): 800-1,600: 9.50; 1,600-2,000: 9.50; More than 2,000: 9.50. Lease terms: Minimum bid ($/acre); Water depth (meters): 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 800-1,600: 18.75%; 1,600-2,000: 18.75%; More than 2,000: 18.75%. Lease sale: 206 and 207; Sale date: 3/19/2008-8/20/2008; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 6.25[B]; 200-400: 9.5[B]; 400-800: 9.50; 800-1,600: 9.50; 1,600-2,000: 9.50; More than 2,000: 9.50. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 37.50; 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 0-200: 18.75%[A]; 200-400: 18.75%[A]; 400-800: 18.75%[A]; 800-1,600: 18.75%[A]; 1,600-2,000: 18.75%[A]; More than 2,000: 18.75%[A]. Lease sale: 208; Sale date: 3/18/2009; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 7.00[B]; 200-400: 11.00[B]; 400-800: 11.00[B]; 800-1,600: 11.00[B]; 1,600-2,000: 11.00[B]; More than 2,000: 11.00[B]. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 37.50; 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 0-200: 18.75%[A]; 200-400: 18.75%[A]; 400-800: 18.75%[A]; 800-1,600: 18.75%[A]; 1,600-2,000: 18.75%[A]; More than 2,000: 18.75%[A]. Lease sale: 210 and 213; Sale date: 8/19/2009 -3/17/2010; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 7.00[B]; 200-400: 11.00[B]; 400-800: 11.00[B]; 800-1,600: 11.00[B]; 1,600-2,000: 11.00[B]; More than 2,000: 11.00[B]. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 37.50; 800-1,600: 37.50; 1,600-2,000: 37.50; More than 2,000: 37.50. Lease terms: Royalty rate; Water depth (meters): 0-200: 18.75%[A]; 200-400: 18.75%[A]; 400-800: 18.75%[A]; 800-1,600: 18.75%[A]; 1,600-2,000: 18.75%[A]; More than 2,000: 18.75%[A]. Lease sale: 218 to 229; Sale date: 12/14/2011-3/20/2013; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 7.00[B]; 200-400: 11.00[B]; 400-800: 11.00[B]; 800-1,600: 11.00[B]; 1,600-2,000: 11.00[B]; More than 2,000: 11.00[B]. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 100.00; 800-1,600: 100.00; 1,600-2,000: 100.00; More than 2,000: 100.00. Lease terms: Royalty rate; Water depth (meters): 0-200: 18.75%[A]; 200-400: 18.75%[A]; 400-800: 18.75%; 800-1,600: 18.75%; 1,600-2,000: 18.75%; More than 2,000: 18.75%. Lease sale: 233; Sale date: 8/28/2013; Lease terms: Rent ($/acre); Water depth (meters): 0-200: 7.00[B]; 200-400: 11.00[B]; 400-800: 11.00[B]; 800-1,600: 11.00[B]; 1,600-2,000: 11.00[B]; More than 2,000: 11.00[B]. Lease terms: Minimum bid ($/acre); Water depth (meters): 0-200: 25.00; 200-400: 25.00; 400-800: 100.00; 800-1,600: 100.00; 1,600-2,000: 100.00; More than 2,000: 100.00. Lease terms: Royalty rate; Water depth (meters): 0-200: 18.75%[A]; 200-400: 18.75%[A]; 400-800: 18.75%; 800-1,600: 18.75%; 1,600-2,000: 18.75%; More than 2,000: 18.75%. Source: GAO analysis of Interior data. Note: One meter equals about 3.28 feet. [A] Leases may be eligible for royalty relief. Certain leases include royalty relief provisions for shallow water deep gas, and other leases may be eligible to apply for shallow water deep gas royalty relief. Leases resulting from sales held after 2000 may be issued with certain royalty relief provisions, and all leases obtained after 2000 in water depths greater than 200 meters are also eligible to apply for royalty relief. [B] Rent per acre is for years 1 through 5 of the lease; then the rental rate escalates in year 6 and, in some cases, increases again in subsequent years as well. [End of table] Interior has also taken actions to encourage the development of oil and gas resources, which reduces the time from when federal leases are issued and the federal government receives its share of revenue from them, in response to our October 2008 recommendation that the Secretary of the Interior develop a strategy to evaluate options to encourage faster development of its oil and gas leases.[Footnote 30] Specifically, in 2010, Interior shortened lease terms by reducing the duration of the initial period for Gulf of Mexico leases in water depths of 400 to less than 800 meters from an 8-year initial period to a 5-year initial period. For water depths of 800 to less than 1,600 meters, it reduced leases from a 10-year initial period to a 7-year initial period. According to Interior documents, these lease terms can generally be extended if the lessee begins drilling a well during the initial period. Interior Has Considered but Has Not Changed Onshore Lease Terms: For onshore resources, Interior has considered, but not made, changes to onshore lease terms in order to provide greater assurance that the public is getting a fair return on federal oil and gas resources. Interior acts on behalf of the American people to manage the federal oil and gas system to ensure a fair return to the public for the development of oil and gas resources. Interior officials told us that since 2009 the department has been considering increasing the onshore royalty rate--which is currently established in its regulations at 12.5 percent for both oil and gas.[Footnote 31] According to the officials, several factors prompted efforts to consider changing the royalty rates, including our September 2008 report,[Footnote 32] oil and gas prices, and Office of Management and Budget initiatives calling for increased revenue from onshore royalties.[Footnote 33] Although both onshore and offshore leasing programs are subject to many of the same market conditions, Interior officials are currently unable to make timely adjustments to onshore royalty rates because BLM's regulations generally establish a set royalty rate of 12.5 percent. This limits the bureau's flexibility because making adjustments to that rate require going through the rulemaking process, and the process can take several years according to Interior officials. Specifically, officials said that the public notice and comment period required as part of the rulemaking process could take 1 to 2 years, and proposed rules must also undergo review by the Office of Management and Budget. Interior officials told us that the department planned to publish a notice of proposed rulemaking in July 2012 to change BLM's regulations to set an onshore royalty rate of 18.75 percent for oil production on new federal competitive leases but leave the royalty rate for gas production unchanged at 12.5 percent. The planned regulatory revisions would have allowed the Secretary to review and revise royalty rates for new competitive leases as appropriate--similar to the authority that the Secretary has for revising offshore royalty rates. Officials told us that including the requirement for periodic review and revision of royalty rates would have given the Secretary greater flexibility to go forward with such reviews and revisions in the future. Interior discontinued its efforts to pursue the revised regulations because, according to Interior officials, the department does not have enough information to determine how to adjust onshore royalty rates. Rather, Interior plans to ask the public to comment on whether and how royalty rates for new federal onshore competitive oil and gas leases should be revised to better ensure a fair return to the public. Specifically, Interior officials told us they plan to ask for comments on the types of royalty rate structures that should be considered, such as whether BLM should develop a uniform rate for all leases or different rates by region, state, geologic formation, or resource type. Furthermore, Interior officials told us they would also ask for comments on whether sliding scale royalty rates--or rates that vary with the price of the commodity--might be appropriate in specific circumstances. An Advance Notice Of Proposed Rulemaking is under development, but officials told us that higher priority rulemaking initiatives, such as regulations for hydraulic fracturing and revisions to its oil and gas measurement regulations, precede it and that limited resources constrain their ability to meet program demands. As a result of not successfully changing federal regulations to provide itself with the flexibility needed to make timely adjustments to onshore lease terms, Interior's ability to ensure that the public is receiving a fair return is limited. Moreover, Interior continues to offer onshore leases with lease terms--terms lasting the life of the lease--that have not been adjusted in response to changing market conditions, potentially foregoing a considerable amount of revenue. For example, in 2011, Interior estimated that onshore royalty rate changes could increase revenue collections by about $1.25 billion over 10 years.[Footnote 34] Interior Contracted for Studies of Various Aspects of the Fiscal System: Interior contracted for several studies--including a study of how the federal oil and gas fiscal system compared with fiscal systems of other resource owners--that reviewed various aspects of the federal oil and gas fiscal system since 2007. In our September 2008 report,[Footnote 35] we found that Interior collected a lower government take for oil and gas production in the deep water of the U.S. Gulf of Mexico than all but 11 of 104 oil and gas resource owners whose revenue collection systems were evaluated in a comprehensive industry study, which included other countries as well as some states. [Footnote 36] We also found that Interior had not routinely evaluated the federal oil and gas fiscal system, monitored what other governments or resource owners were receiving for their resources, or evaluated and compared the attractiveness of federal lands and waters for investment with that of other regions.[Footnote 37] In response to our 2008 findings, Interior contracted for a study--the 2011 Comparative Assessment of the Federal Oil and Gas Fiscal System study-- that compared the federal oil and gas fiscal systems of selected federal oil and gas regions to that of other resource owners. In addition, Interior contracted for two other studies on the effect of different leasing and royalty rate policies on revenue, exploration, and production. See table 2 for a description of these studies. Table 2: Interior-Contracted Studies of the Oil and Gas Fiscal System 2009-2013: Study: Comparative Assessment of the Federal Oil and Gas Fiscal System (October 2011)[A]; Description of analysis conducted: Examines 29 fiscal systems-- including the current systems relating to federal offshore oil and gas resources in the Gulf of Mexico and onshore gas resources in Wyoming-- and describes the impact of various lease term changes on other aspects of the system such as the system's stability and competitiveness, pace of leasing, and revenue. The study provided information on fiscal system components, such as royalty rates and taxes, for specific areas within the United States and other countries. Identifies four fiscal-related factors--government take internal rate of return, profit-investment ratio, and progressivity--and constructs a hypothetical, composite index using these measures to compare fiscal systems. The report provides an assessment of how changes to the royalty rate could potentially affect industry interest in federal offerings. Study: Benefit-Cost and Economic Impact Analysis of Raising the Onshore Royalty Rates Associated with New Federal Oil and Gas Leasing (April 2011)[B]; Description of analysis conducted: Assesses the impacts of raising onshore royalty rates associated with new competitive leases and considers both fixed and sliding scale royalty rates. The study also addresses changes to the net economic benefits to the states and federal government, changes to the demand for federal leases and changes to production. Estimates the impact of royalty rate changes-- including sliding scale scenarios--on revenue and other parts of the revenue stream, such as bonus bids, and analyzes high and low price scenarios for oil and gas. Study: Policies to Affect the Pace of Leasing and Revenues in the Gulf of Mexico (August 2009/December 2010)[C]; Description of analysis conducted: Examines alternative leasing policies for outer continental shelf (OCS) oil and gas resources in the Central and Western Gulf of Mexico. The study focuses on tracts to be leased on the Central and Western Gulf of Mexico planning areas over the 50-year period from 2010-2060. Considers several leasing policies and estimates the impact on exploration, production, and revenues. The study analyzes alternative leasing systems and describes the goals and criteria for assessing alternative leasing systems. The study models the various potential leasing systems and compares them with the status quo. Leasing systems' alternatives considered include slowing the pace of leasing, changing royalty rates,raising minimum bids,profit sharing, raising area rental payments, using different bidding systems, implementation of work commitments, and reducing the length of the primary lease period. Source: GAO analysis of Interior-contracted studies. [A] IHS Cambridge Energy Research Associates, Comparative Assessment of the Federal Oil and Gas Fiscal System (October 2011). [B] Enegis, LLC, Benefit-Cost and Economic Impact Analysis of Raising the Onshore Royalty Rates Associated with New Federal Oil and Gas Leasing (April 2011). This report was contracted by BLM to help guide the decision-making process with regards to a proposed royalty rate rulemaking. The rulemaking is still under deliberation by the agency, and all materials related to this process are considered pre- decisional in nature by Interior. [C] Economic Analysis, Inc. and Marine Policy Center, Policies to Affect the Pace of Leasing and Revenues in the Gulf of Mexico (August 2009/December 2010). Each version of this study evaluates the same policy alternatives under different assumptions about the basic conditions for future development in the Gulf of Mexico such as the ultimate resource size in the Gulf of Mexico and lessee actions related to potential future effective tax rates. [End of table] According to Interior officials, the study conducted in response to our 2008 findings--the 2011 Comparative Assessment of the Federal Oil and Gas Fiscal System--provided some useful information about the fiscal system such as how fiscal terms in the United States compared with other resource owners, but it has not directly led to any changes to the fiscal system or lease terms for new federal oil and gas leases. Similarly, Interior officials told us that the other two studies have not yet led to revisions to the fiscal system or lease terms for new offshore or onshore leases. Rather, according to officials, additional internal analyses and modeling, as well as consultation with stakeholders--including oil and gas companies and the public--will continue to primarily inform future changes to the fiscal system. Moreover, Interior did not document any internal discussions or analysis of the three studies' findings. As part of the 2011 Comparative Assessment of the Federal Oil and Gas Fiscal System study, officials said that they obtained a model that can be employed in the future to conduct comparative analyses but currently have no plans to update the model or the data inputs used by the model. Officials told us that the study's findings reassured them that their own internal assessment related to the competitiveness of the offshore fiscal system was appropriate. In addition, officials said that the study provided additional information--mainly raising the issue of whether an appropriate return was being received for onshore resources--but that the study was not adequate to determine next steps for onshore lease terms. Interior Is Examining Potential Regulatory Changes that Could Simplify Royalty Payments and Collections: Interior is examining potential regulatory changes that could simplify royalty payments and collections. As we found in our past work, [Footnote 38] complex valuation regulations can result in inaccurate royalty payments made by industry, and this could increase ONRR's costs to ensure accurate royalty payments because of the need for potentially detailed and time-consuming audits of records. In May 2011, Interior published an Advance Notice Of Proposed Rulemaking requesting comments to inform potential changes to regulations intended to simplify royalty payments and collections. In addition to our work, others have identified numerous shortcomings in ONRR's royalty collection programs, in part because of its valuation regulations' complex requirements for calculating the value of oil and gas and associated deductions and allowances for activities such as transportation. In December 2007, Interior's Subcommittee on Royalty Management recommended that, by the end of fiscal year 2008, Interior publish proposed revisions to the gas valuation regulations to, among other goals, simplify the calculation of royalties and deductions for gas transportation and processing. Interior did not meet this time frame due to several factors including the complexity of oil and gas valuation, according to Interior officials. In May 2011, Interior published the Advance Notice Of Proposed Rulemaking in the Federal Register for the proposed rule, which according to Interior documents is intended, in part, to provide greater simplicity, certainty, clarity, and consistency in production valuation; decrease ONRR's costs to ensure compliance; decrease industry's compliance costs; and provide more certainty to ONRR and industry that companies pay every dollar due to the government.[Footnote 39] According to ONRR officials, the proposed regulations were undergoing internal review as of September 2013 and are expected to be published in the Federal Register in 2014. Interior Does Not Have Documented Procedures for Conducting Periodic Assessments of the Fiscal System or for Supporting Potential Changes to New Lease Terms: Interior does not have documented procedures in place for determining (1) when to conduct periodic assessments of the overall fiscal system or (2) whether and how to make changes to lease terms for new offshore leases. Interior Does Not Have Documented Procedures for Determining When to Conduct Periodic Assessments of the Overall Fiscal System: Interior does not have documented procedures in place for determining when to periodically conduct assessments of the overall fiscal system as a whole. Although Interior recently contracted for such an assessment, it was the first in well over 25 years. Without documented procedures, Interior cannot ensure that it will consistently conduct such assessments in the future, and without periodically conducting such assessments, Interior cannot know whether there is a proper balance between the attractiveness of federal leases for investment and appropriate returns for federal oil and gas resources, limiting Interior's ability to ensure a fair return on federal oil and gas resources. Internal control standards in the federal government call for agencies to clearly document internal controls and the documentation is "to appear in management directives, administrative policies, or operating manuals."[Footnote 40] Documented procedures of when Interior is to conduct such assessments--whether within specific time frames or the occurrence of certain market or industry changes-- could help provide the department with reasonable assurance that its staff knows when to conduct assessments of the overall fiscal system to help ensure those reviews are conducted systematically and consistently. In our September 2008 report, we found that the last time Interior conducted a comprehensive assessment of the federal oil and gas fiscal system was over 25 years ago. Additionally, we reported that, without routinely evaluating the federal oil and gas system as a whole, including monitoring what other resource owners worldwide are receiving for their energy resources or evaluating and comparing the attractiveness of the United States for oil and gas investment with that of other oil and gas regions, Interior cannot provide reasonable assurance that the public is getting an appropriate share of revenues.[Footnote 41] As mentioned previously, in response to our 2008 findings, Interior contracted for a study that compared the federal oil and gas fiscal system to that of other resource owners. As part of this study, officials said that they obtained a model that can be employed in the future to conduct comparative analyses; however, there are currently no plans to update the model or the data inputs used by the model. Interior officials told us that this type of comprehensive assessment would only be undertaken if fundamental shifts in the market occurred. According to officials, however, Interior does not have procedures or criteria in place for determining when such an assessment of the fiscal system should take place or what changes in the market or industry would signal that such a study should be done. Without procedures for determining when to conduct periodic assessments of the fiscal system as a whole, Interior cannot be reasonably assured that it will consistently conduct such assessments in the future, limiting its ability to be confident that the system is ensuring a fair return on federal oil and gas resources. According to the Office of Management and Budget, rigorous program evaluations can help determine whether government programs are achieving their intended outcomes to the extent possible.[Footnote 42] Moreover, Interior's oversight of federal land and waters is subject to the federal government's multiple, diverse objectives--fair return, protection of historical and environmental resources, and expeditious and orderly development, among other goals. Thus, Interior is confronted with evaluating these objectives in light of a complex set of factors--including market prices and how development opportunities in the United States compare with those of other resource owners. By having documented procedures, the department could help ensure that its evaluations take all of these factors into consideration. Further, these factors may change over time as the market for oil and gas changes, the technologies used to explore and produce oil and gas change, or as the broader economic climate changes, making it even more important that Interior has documented procedures for conducting periodic assessments of the federal oil and gas fiscal system. In addition, Interior has conducted some analyses to support changes to offshore lease terms in advance of offshore lease sales, which typically occur a few times a year--but the analyses conducted to support these changes are not a substitute for periodically assessing the oil and gas fiscal system as a whole. Since 2007, Interior has conducted some analyses for offshore lease sales in support of changes to royalty rates, rental rates, and the minimum bid. Based on our review of Interior documents from several lease sales from 2007 to 2011, we found that the analyses the department conducted to support proposed changes to offshore lease terms generally involved estimating the impacts of a proposed change on revenue, bidding activity, and potential oil and gas production. In addition, Interior's documentation shows that the department took into consideration technological and market conditions; policy goals, such as promoting development or enhancing revenues; and administrative benefits, such as making lease terms consistent across water depths. However, these analyses did not include an evaluation of what other resource owners worldwide are receiving for their energy resources or a comparison of the attractiveness of the United States for oil and gas investment with that of other oil and gas resource owners. In our September 2008 report, we suggested that Congress should consider directing the Secretary of the Interior to establish procedures for periodically collecting data and information and conducting analyses to determine how the federal government take and the attractiveness for oil and gas investors in each federal oil and gas region compare with those of other resource owners and report this information to Congress. Moreover, Interior has not conducted similar analysis for onshore lease sales. Interior officials explained that the mechanism for determining the value of onshore resources is directed by statute to be market-driven.[Footnote 43] Specifically, officials stated that fair market value for onshore lease sales is determined through the oral competitive bidding process required by the Mineral Leasing Act, rather than an evaluation of the geology and potential value of the oil and gas resource.[Footnote 44] Because the leasing process is established by statute, Interior officials told us that it has not recently examined whether alternative leasing systems might be more effective in ensuring fair market value. Interior Does Not Have Documented Procedures for Determining Whether and How to Make Changes to New Offshore Lease Terms: Interior does not have documented procedures for determining whether and how to make changes to new offshore lease terms--which are specified a few times per year ahead of each lease sale--consistent with federal standards for internal control. Without documented procedures for determining whether and how to make changes to new offshore lease terms, Interior is at risk of making inconsistent determinations about lease terms. Such inconsistent determinations would undermine its credibility and its ability to better ensure a fair return on oil and gas resources. Officials told us Interior does not have documented procedures or criteria for determining whether and how to make changes to offshore lease terms. Rather Interior officials said that they follow an informal process and establish offshore lease terms for each sale but that they do not have the time or resources to evaluate each lease term prior to each lease sale. However, based on our review of Interior documents, the analyses the department conducted to support proposed changes to offshore lease terms were inconsistent in the array of conditions and factors the department considered, and the level of analysis conducted in support of decisions to change lease terms varied and was not consistently or clearly documented. For example, as mentioned previously, escalating rental rates were implemented in two different sales--first, in 2007, in water depths less than 400 meters and then, in 2009, in water depths greater than 400 meters. The rationale provided for the first change was the policy goal to expedite drilling and compensate Interior, while the rationale in 2009 included specific estimates of the effects of an escalating rental rate on potential revenue and bidding, as well as consideration of market conditions. While both justifications may be warranted, because Interior does not have documented procedures specifying whether and how to support changes to its lease terms, Interior's approach to revising its lease terms appears to be inconsistent. In addition, our review of documents supporting two separate royalty rate changes in 2007 and 2008--the first in 25 years--found that Interior did not consistently document the justifications and analysis supporting the increases. Specifically, Interior documents for the 2008 royalty rate increase cite reasons similar to the 2007 royalty rate increase--generally significant changes in market conditions--but because the second increase took place less than a year after the implementation of the first increase, it is unclear what significant changes in market conditions occurred to prompt the consideration of the second increase in royalty rates. Internal control standards in the federal government call for agencies to clearly document transactions and other significant events and that documentation should be readily available for examination.[Footnote 45] While both royalty rate increases may have been warranted, clear documentation of the justifications and analysis supporting royalty rate increases would make Interior's decisions to change the royalty rates transparent and could inform future decision making related to changing rates. Such transparency can be particularly helpful in the event that key staff retire or leave federal service. Documentation of internal discussions that took place prior to the second royalty rate increase show that prior to being able to assess the impacts of increasing the royalty rate from 12.5 percent to 16.67 percent in 2007, Interior was considering an additional royalty rate increase. In addition, Interior documents show Interior program officials' concerns about an additional increase in royalty rates; specifically, officials urged the need to analyze the impact of the first increase, and they also noted potential negative effects of an increase including delaying investment and production in certain areas of the Gulf of Mexico. By having documented procedures for determining whether and how to make future changes to offshore leasing terms, Interior could increase its consistency and thus enhance its credibility in the conditions and factors the department considered and the level of analysis conducted. Conclusions: Interior has taken several steps intended to help ensure that the public receives a fair return on oil and gas produced from federal leases. However, even with these recent steps, it is not clear that Interior's efforts, by themselves, provide long-lasting assurance that federal resources will provide a fair return. This is especially true in light of the absence of documented procedures for Interior to determine when it will periodically conduct assessments of the overall federal oil and gas fiscal system and whether and how to make changes to new offshore lease terms, as well as Interior's limited flexibility to make changes to new onshore lease terms. Ensuring that the federal government is obtaining fair return for the resources it manages on behalf of its citizens is especially important as the country faces ongoing fiscal challenges. Although leasing programs for both onshore and offshore areas are subject to many of the same market conditions, and Interior has increased offshore royalty rates, officials overseeing onshore leasing are currently unable to make timely adjustments to onshore royalty rates because, in general, BLM's regulations fix the rate at 12.5 percent, potentially limiting Interior's ability to ensure that the public is receiving a fair return and potentially resulting in foregone revenue. In particular, while Interior has changed offshore lease terms several times over the past few years in response to changes in market conditions--many of which also affect onshore areas-- to better ensure a fair return, Interior has not successfully changed BLM's regulations to provide itself with the flexibility needed to change onshore lease terms in a timely manner despite considering increasing the onshore royalty rate since 2009. As a result, Interior continues to offer onshore leases with lease terms--terms lasting the life of the lease--that have not been adjusted in response to changing market conditions, potentially foregoing a considerable amount of revenue. Key among Interior's efforts to ensure a fair return, to address a GAO recommendation, Interior completed an assessment--the Comparative Assessment of the Federal Oil and Gas Fiscal System--which examined how the fiscal system of selected federal oil and gas regions compared with fiscal systems of other resources owners. Interior officials told us, however, that it has no plans to update the assessment, increasing the risk that this progress may be fleeting and that, as we found in 2008, it could be years before another assessment is completed during which time there could be significant changes in market conditions. Furthermore, without documented procedures in place for conducting periodic assessments of the fiscal system--such as when such an assessment of the fiscal system should take place or what changes in the market or industry would signal that such a study should be done, Interior cannot know whether there is a proper balance between the attractiveness of federal leases for investment and appropriate returns for federal oil and gas resources, limiting Interior's ability to ensure a fair return. Finally, while Interior has made changes to its offshore lease terms, for example increasing royalty rates in some instances from 12.5 percent to 18.75 percent, Interior does not have documented procedures for determining whether and how to make changes to lease terms for new offshore leases. Without such documented procedures, Interior's rationale is not transparent, and it is at risk of making inconsistent determinations about lease terms. Such inconsistency would undermine its credibility and ability to better ensure a fair return on oil and gas resources. Additionally, Interior has not clearly documented the justifications and analysis supporting changes to lease terms, including royalty rate increases. As a result, the department's decisions to change lease terms are not transparent and, without documentation of these decisions, its future efforts to change rates may be impeded. Recommendations for Executive Action: To better ensure that the government receives a fair return on its oil and gas resources, we recommend that the Secretary of the Interior take the following three actions: * Take steps, within existing authority, to revise BLM's regulations to provide for flexibility to the bureau to make changes to onshore royalty rates, similar to that which is already available for offshore leases, to enhance Interior's ability to make timely adjustments to the terms for federal onshore leases. * Establish documented procedures for determining when to conduct periodic assessments of the overall fiscal system. Such procedures should identify generally when such an assessment should be done or what changes in the market or industry would signal that such an assessment should be done. Additionally, the assessment should include determining how the government's share of revenue from the federal oil and gas fiscal system and the attractiveness for oil and gas investors in each federal oil and gas region compare with those of other resource owners. * Establish documented procedures for determining whether and how to adjust lease terms for new offshore leases, including documenting the justification and analysis supporting any adjustments. Agency Comments: We provided a draft of this report to Interior for review and comment. Interior generally agreed with our findings and concurred with our recommendations. As agreed with your office, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies of this report to the Secretary of the Interior, the appropriate congressional committees, and other interested parties. In addition, this report will be available at no charge on the GAO website at [hyperlink, http://www.gao.gov]. If you or your staff members have any questions about this report, please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report. GAO staff members who made major contributions to this report are listed in appendix II. Sincerely yours, Signed by: Frank Rusco: Director, Natural Resources and Environment: [End of section] Appendix I: Comments from the Department of the Interior: United States Department of the Interior: Office of The Secretary: Washington, D.C. 20240: November 25, 2013: Mr. Frank Rusco: Director, Natural Resources and Environment: Government Accountability Office: 441 G Street, N.W. Washington, D.C. 20548: Dear Mr. Rusco: Thank you for the opportunity to review and comment on the Government Accountability Office (GAO) draft report entitled, Oil and Gas Resources: Actions Needed for Interior to Better Ensure a Fair Return (GAO-14-50). The draft GAO report includes three recommendations for the Department of the Interior (DOI). GAO's recommendations are to revise Bureau of Land Management (BLM) regulations to provide for flexibility in making changes to onshore royalty rates and adjusting federal onshore lease terms, establish documented procedures for periodically reviewing the overall oil and gas fiscal systems, and establish documented procedures for determining whether and how to adjust new offshore lease terms. DOI generally agrees with GAO's findings and concurs with the recommendations. Technical comments have been provided separately. Additionally, 001 appreciates your consideration of comments provided at the exit conference in September 2013. In response to Recommendation One, the BLM will move forward with a rulemaking process to revise its existing regulations to allow the Secretary broad flexibility in setting onshore royalty rates. In response to Recommendation Two, the Bureau of Ocean Energy Management (BOEM) and the BLM will periodically examine the need for conducting updated assessments regarding the overall configuration and parameters of onshore and offshore oil and gas fiscal systems. The factors to be considered in determining when to conduct these assessments could include consideration of the extent of recent changes in market conditions, resource prices, new discoveries, technological advances, and the portion of economic rents captured by the Federal Government. The Department also recognizes the importance of evaluating the Federal oil and gas fiscal system relative to other resource owners. In response to Recommendation Three, BOEM proposes to document the procedures it will follow for analyzing fiscal terms for individual lease sales under prevailing and expected future market conditions. These procedures could include a description of the variables to be considered, the types of analysis these variables will be subject to, the outputs to be generated by the analysis, and suggestions on how the findings could be used to develop policy recommendations on program configuration. If you have any questions about this response, please contact Andrea Nygren, BOEM Audit Liaison Officer, on (202) 208-4343; LaVanna Stevenson-Ran-is, BLM Audit Liaison Officer, on (202) 912-7077; or Gwenna Zacchini, Office of Natural Resource Revenue Audit Liaison Officer, on (303) 231-3513. Sincerely, Signed by: Rhea Suh: Assistant Secretary: Policy, Management and Budget: [End of section] Appendix II: GAO Contact and Staff Acknowledgments: GAO Contact: Frank Rusco, (202) 512-3841 or ruscof@gao.gov: Staff Acknowledgments: In addition to the individual named above, Jon Ludwigson (Assistant Director), Janice Ceperich, Glenn Fischer, Cindy Gilbert, Michael Kendix, Alison O'Neill, Dan Royer, Kiki Theodoropoulos, and Barbara Timmerman made key contributions to this report. [End of section] Footnotes: [1] Fiscal Accountability of the Nation's Energy Resources (January 1982). [2] GAO, Oil and Gas Royalties: A Comparison of the Share of Revenue Received from Oil and Gas Production by the Federal Government and Other Resource Owners, [hyperlink, http://www.gao.gov/products/GAO-07-676R] (Washington, D.C.: May 1, 2007). The government take, which accrues to any government, is largely determined by the government's oil and gas fiscal system. In the United States, this fiscal system consists of both terms specified in the lease, such as the royalty rate and rent, as well as the corporate taxes paid by the company on profits from the sale of oil and gas produced from federal leases. [3] GAO, Oil and Gas Royalties: The Federal System for Collecting Oil and Gas Revenues Needs Comprehensive Reassessment, [hyperlink, http://www.gao.gov/products/GAO-08-691] (Washington, D.C.: Sept. 3, 2008). The status of these actions is discussed later in this report. [4] GAO, High-Risk Series: An Update, [hyperlink, http://www.gao.gov/products/GAO-11-278] (Washington, D.C.: Feb. 16, 2011). [5] The outer continental shelf (submerged lands) is outside the territorial jurisdiction of all 50 states but within U.S. jurisdiction and control and consists of submerged federal lands, generally extending seaward between 3 and 200 nautical miles off the U.S. coastline. [6] GAO, Standards for Internal Control in the Federal Government, [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1] (Washington, D.C.: November 1999). [7] Lease sale 222 was held in June 2012 and resulted in bonus revenues of $1.68 billion; however, since certain bid review procedures were not completed by the end of the fiscal year, not all of these bonuses are included in the revenue amount for bonus bids. [8] 43 U.S.C. §1337 provides that Interior can make changes so long as there is only one bid variable or "flexible" term. The bid variable or "flexible" term does not fluctuate over the life of the lease but is the term on which bidders compete for the award through the level of the bid made. [9] By statute, the Secretary of the Interior must first offer parcels at competitive lease sales and may only issue noncompetitive leases after the department has offered the lands competitively at an oral auction and not received a bid. For onshore leases issued noncompetitively, the Mineral Leasing Act sets a 12.5 percent royalty rate by statute. [10] 43 U.S.C. §1344(a)(1). [11] 43 U.S.C. §1332(3). [12] 43 U.S.C. §1344(a)(4). [13] If a discovery is made within the initial term of the lease, the lease is extended for as long as oil and/or natural gas is produced in paying quantities or approved drilling operations are conducted. The term of the lease may also be extended if a suspension of production or suspension of operations has been granted or directed. [14] In the Gulf of Mexico, in a recent notice of sale in 2012, BOEM offered leases with an initial term of 5 years extended to 8 years if drilling begins during the initial 5-year period targeting hydrocarbons below a depth of at least 25,000 feet subsea for leases in less than 400 meters of water. For leases in 400 to 800 meters of water, the initial term was 5 years extended to 8 years if drilling begins during the initial 5-year period. For leases in 800 to 1,600 meters of water, the initial period was 7 years extended to 10 years if drilling begins during the initial 7-year period. For leases in over 1,600 meters of water, the initial period was 10 years. [15] BLM, Public Land Statistics 2012, Volume 197 (June 2013). As of September 30, 2012, BLM reported 27,747 competitive oil and gas leases covering 22.2 million acres and 18,411 noncompetitive oil and gas leases covering 14.8 million acres. [16] GAO, Oil and Gas Royalty Collections: Longstanding Problems Costing Millions, [hyperlink, http://www.gao.gov/products/GAO/AFMD-82-6] (Washington, D.C.: Oct. 29, 1981). In our October 1981 report, we recommended that Interior, as part of its efforts to develop a new royalty accounting system, should (1) monitor the development of the new system and (2) include as part of these redesign efforts a plan for, among other actions, monitoring and reconciling records, inspecting leases, and verifying production and sales data. Interior did not take action to implement either of these recommendations in part because it had initiated a new review of its revenue collection system that covered many of the same issues we identified. [17] Fiscal Accountability of the Nation's Energy Resources (January 1982). [18] In 2010, following the explosion of the Deepwater Horizon drilling rig in the Gulf of Mexico, Interior announced that it was going to reorganize its offshore oversight and revenue collection functions. Specifically, Interior eventually restructured MMS into three separate bureaus--BOEM, responsible for offshore leasing and resource management; the Bureau of Safety and Environmental Enforcement, responsible for issuing oil and natural gas drilling permits, environmental safety and regulation, and conducting inspections for offshore leases; and ONRR, responsible for revenue collection for both offshore and onshore leases. [19] Subcommittee on Royalty Management, Royalty Policy Committee, Report to the Royalty Policy Committee: Mineral Revenue Collection from Federal and Indian Lands and the Outer Continental Shelf (Washington, D.C.: 2007). [20] [hyperlink, http://www.gao.gov/products/GAO-07-676R]. [21] [hyperlink, http://www.gao.gov/products/GAO-08-691]. [22] [hyperlink, http://www.gao.gov/products/GAO-11-278]. [23] GAO, High-Risk Series: An Update, [hyperlink, http://www.gao.gov/products/GAO-13-283] (Washington, D.C.: Feb. 14, 2013). [24] Although the outer continental shelf leases for the Gulf of Mexico have increased royalty rates, the outer continental shelf leases for Alaska have remained at a 12.5 percent royalty rate for about 30 years. [25] The revenue estimates are nominal dollars unadjusted for inflation. [26] Interior's analysis included estimates for increasing royalty rates beyond 18.75 percent. Specifically, it estimated that royalty rate increases from 18.75 to 21.875 percent would cause production losses of 2 to 6 percent with royalty revenue increases of 11 to 17 percent. According to the analysis, the effect of increased royalty rates, depending on the size of the change, would be less production, but with the potential for higher revenues from royalties in the future. Interior found that a large increase in the royalty rate could curtail expected returns to lessees to such a large extent that it might unduly reduce leasing and future production by proportions greater than suggested in its analysis. Much higher royalty rates could also curtail production from new leases in the future as production declines in the later phases of a lease's productive life. [27] Under this change, the prevailing rental rates for new leases in water depths of less than 200 meters would be $7/acre for the first 5 years with increases to $14/acre in year 6, $21/acre in year 7, and $28/acre in year 8. For new leases in water depths from 200 to 400 meters, rental rates increase from $11/acre to $22/acre in year 6, $33/acre in year 7, and $44/acre in year 8. For new leases in water depths from 400 to 800 meters, rental rates increase from $11/acre to $16/acre in years 6 through 8. For new leases in water depths greater than 800 meters, rental rates increase from $11/acre to $16/acre in years 6 through 10. [28] The revenue estimates are in nominal dollars unadjusted for inflation for leases resulting from sale 208 and the revenue estimates for the increase in base rental rates include estimates for the initial lease term. [29] The Gulf of Mexico minimum bid remains at $25 per acre in water depths of less than 400 meters. The most recent minimum bids in Alaska were $25 per hectare (about $10 per acre) in the Chukchi Sea, Cook Inlet, and in Zone B (deeper water areas) of the Beaufort Sea; and $37.50 per hectare (about $15 per acre) in Zone A (near shore areas) of the Beaufort Sea. [30] GAO, Oil and Gas Leasing: Interior Could Do More to Encourage Diligent Development, [hyperlink, http://www.gao.gov/products/GAO-09-74] (Washington, D.C.: Oct. 3, 2008). [31] For onshore leases issued noncompetitively, the Mineral Leasing Act sets a 12.5 percent royalty rate by statute. [32] [hyperlink, http://www.gao.gov/products/GAO-08-691]. [33] According to Interior's Fiscal Year 2014 Budget Justifications and Performance Information, the administration proposed a package of legislative and administrative proposals to reform the management of Interior's onshore and offshore oil and gas leasing programs, with a key focus on improving the return to taxpayers from the sale of these federal resources and on improving transparency and oversight. Proposed changes included advancing royalty reforms such as evaluating minimum royalty rates for oil, gas, and similar products; adjusting onshore royalty rates; analyzing a price-based tiered royalty rate; and repealing legislatively-mandated royalty relief. The budget proposals for the past 4 years have included the goal of increasing onshore royalty rates. [34] According to officials, Interior developed this estimate in support of the budget in 2011. The estimate is based on a royalty rate of 18.75 percent for oil and gas. Actual changes in revenue collections resulting from a royalty rate increase would be highly dependent on market prices and production. [35] [hyperlink, http://www.gao.gov/products/GAO-08-691]. [36] Wood Mackenzie, Government Take: Comparing the Attractiveness and Stability of Global Fiscal Systems (June 2007). [37] In the draft of our September 2008 report that we sent to Interior for comment, we made recommendations to address these issues. In its response, Interior stated that it did not fully concur with our recommendations because it had already contracted for a study that would address many of the issues we raised. However, because Interior's ongoing study was limited in scope and to a specific region in the Gulf of Mexico, rather than a review of the entire federal oil and gas fiscal system as we recommended, we did not find the department's stated rationale for not agreeing fully with our recommendations to be convincing. After Interior disagreed with our draft recommendations, for our final report we changed our recommendation to Interior into a "Matter for Congressional Consideration" that Congress should consider directing the Secretary of the Interior to (1) convene an independent panel to perform a comprehensive review of the federal system for collecting oil and gas revenue and (2) establish procedures for periodically collecting data and information and conducting analyses to determine how the federal government take and the attractiveness for oil and gas investors in each federal oil and gas region compare to those of other resource owners and report this information to Congress. Although Interior initially disagreed with this recommendation, in 2010, it contracted for the study comparing the federal oil and gas fiscal systems with those of other countries. [38] GAO, Mineral Revenues: MMS Could Do More to Improve the Accuracy of Key Data Used to Collect and Verify Oil and Gas Royalties, [hyperlink, http://www.gao.gov/products/GAO-09-549] (Washington, D.C.: July 15, 2009). [39] 76 Fed. Reg. 30878 (May 27, 2011). [40] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1]. [41] [hyperlink, http://www.gao.gov/products/GAO-08-691]. [42] Office of Management and Budget, Increased Emphasis on Program Evaluations, M-10-01, Memorandum for the Heads of Executive Departments and Agencies (Washington, D.C.: The White House, Oct. 7, 2009). [43] The Federal Onshore Oil and Gas Leasing Reform Act of 1987 requires that all public lands available for oil and gas leasing be offered first by competitive leasing. BLM is required to accept the highest bid received that exceeds the minimum bid value of $2 per acre or fraction thereof. 30 U.S.C. § 226(b)(1). The law allows the Secretary to increase the $2 an acre minimum bid and directs that the House and Senate Committees on Natural Resources be notified 90 days before doing so. By statute, the Secretary of the Interior must first offer parcels at competitive lease sales and may only issue noncompetitive leases after the department has offered the lands competitively at an oral auction and not received a bid. The annual rental rate is $1.50 per acre for the first 5 years and $2.00 per acre each year thereafter. Royalty rates for onshore are generally 12.5 percent for both competitive and noncompetitive leases. However, there are a few exceptions such as sliding scale royalties on older leases and reduced royalty rates on certain oil leases with declining production and reinstated leases. See 43 C.F.R. § 3103.2-3. [44] Interior is prohibited by statute from evaluating the value of the lands proposed for lease onshore. 30 U.S.C. §226(b)(1). Concerned that BLM's onshore leasing system was not generating revenues comparable to what might be obtained through competitive leasing, Congress passed the Federal Onshore Oil and Gas Leasing Reform Act of 1987, which amended the Mineral Leasing Act of 1920. This act significantly changed the way BLM issues leases. Prior to the act, BLM was required to evaluate federal lands for oil and gas potential. The act requires the market, rather than administrative determinations, to set the value of leases by making all leases available for competitive leasing. [45] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1]. [End of section] GAO’s Mission: The Government Accountability Office, the audit, evaluation, and investigative arm of Congress, exists to support Congress in meeting its constitutional responsibilities and to help improve the performance and accountability of the federal government for the American people. 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