The Department of the Interior (Interior), created by the Congress in 1849, oversees and manages the nation’s publicly owned natural resources, including parks, wildlife habitat, and crude oil and natural gas resources on over 500 million acres onshore and in the waters of the Outer Continental Shelf. In this capacity, Interior is authorized to lease federal oil and gas resources and to collect the royalties associated with their production. Onshore, Interior’s Bureau of Land Management is responsible for leasing federal oil and natural gas resources, whereas offshore, MMS has leasing authority. To lease lands or waters for oil and gas exploration, companies generally must first pay the federal government a sum of money that is determined through a competitive auction. This money is called a bonus bid. After the lease is awarded and production begins, the companies must also pay royalties to MMS based on a percentage of the cash value of the oil and natural gas produced and sold. Royalty rates for onshore leases are generally 12 and a half percent whereas offshore, they range from 12 and a half percent for water depths greater than 400 meters to 16 and two-thirds percent for water depths less than 400 meters. However, the Secretary of the Interior recently announced plans to raise the royalty rate to 16 and two-thirds percent for most future leases issued in waters deeper than 400 meters. MMS also has the option of taking a percentage of the actual oil and natural gas produced, referred to as “taking royalties in kind,” and selling it themselves or using it for other purposes, such as filling the nation’s Strategic Petroleum Reserve. Based on our work to date, the Deep Water Royalty Relief Act (DWRRA) will likely cost the federal government billions of dollars in forgone royalties, but precise estimates of the costs are not possible at this time for several reasons. First, the failure of MMS to include price thresholds in the 1998 and 1999 leases and current attempts to renegotiate these leases has created uncertainty about which leases will ultimately receive relief. Second, a recent lawsuit is questioning whether MMS has the authority to set price thresholds for the leases issue from 1996 through 2000. The outcome of this litigation could dramatically affect the amount of forgone revenues. Finally, assessing the ultimate fiscal impact of royalty relief is an inherently complex task, involving uncertainty about future production and prices. In October 2004, MMS preliminarily estimated that the total costs of royalty relief for deep water leases issued under the act could be as high as $80 billion, depending on which leases ultimately received relief. MMS made assumptions about several conditions when generating this estimate and these assumptions need to be updated in 2007 to more accurately portray potential losses. In addition, the costs of forgone royalties need to be measured against any potential benefits of royalty relief, including accelerated drilling and production of oil and gas resources, increased oil and gas production, and increased fees that companies are willing to pay through bonus bids for these leases. The Congress passed DWRRA in 1995, when oil and gas prices were low and production was declining both onshore and in the shallow waters of the Gulf of Mexico. The act contains provisions to encourage the exploration and development of oil and gas resources in waters deeper than 200 meters lying largely in the western and central planning areas of the Gulf of Mexico. The act mandates that royalty relief apply to leases issued in these waters during the five years following the act’s passage— from November 28, 1995 through November 28, 2000. As a safeguard against giving away all royalties, two mechanisms are commonly used to ensure that royalty relief is limited and available only under certain conditions. The first mechanism limits royalty relief to specified volumes of oil and gas production called “royalty suspension volumes,” which are dependent upon water depth. Royalty suspension volumes establish production thresholds above which royalty relief no longer applies. That is, once total production for a lease reaches the suspension volume, the lessee must begin paying royalties. Royalty suspension volumes are expressed in barrels of oil equivalent, which is a term that allows oil and gas companies to combine oil and gas volumes into a single measure, based on the relative amounts of energy they contain. The royalty suspension volumes applicable under DWRRA are as follows: (1) not less than 17.5 million barrels of oil equivalent for leases in waters of 200 to 400 meters, (2) not less than 52.5 million barrels of oil equivalent for leases in waters of 400 to 800 meters, and (3) not less than 87.5 million barrels of oil equivalent for leases in waters greater than 800 meters. Hence, there are incentives to drill in increasingly deeper waters. Before 1994, companies drilled few wells in waters deeper than 500 meters. MMS attributes additional leasing and drilling in deep waters to the passage of these incentives but also cites other factors for increased activity, including improved three-dimensional seismic surveys, some key deep water discoveries, high deep water production rates, and the evolution of deep water development technology. After the passage of DWRRA, uncertainty existed as to how royalty suspension volumes would apply. Interior officials employed with the department when DWRRA was passed said that they recommended to the Congress that the act should state that royalty suspension volumes apply to the production volume from an entire field. However, oil and gas companies paying royalties under the act interpreted the royalty suspension volumes as applying to individual leases within a field. This is important because an oil and gas field commonly consists of more than one lease, meaning that if royalty suspension volumes are set for each lease within a field rather than for the entire field, companies are likely to owe fewer royalties. For example, if a royalty suspension volume is based on an entire field composed of three leases, a company producing oil and gas from a 210 million barrel-oil field—-where the royalty suspension volume is set at 100 million—-would be obligated to pay royalties on 110 million barrels (210 minus 100). However, if the same 210-million barrel field had the same suspension volume of 100 million barrels applied to each of the three leases, and 70 million barrels were produced from each of the three leases, no royalties would be due because no lease would have exceeded its royalty suspension volume. After passage of the act, MMS implemented royalty relief on a field-basis and was sued by the industry. Interior lost the case in the Fifth Circuit Court of Appeals. In October 2004, MMS estimated that this decision will cost the federal government up to $10 billion in forgone future royalty revenues. A second mechanism that can be used to limit royalty relief and safeguard against giving away all royalties is the price threshold. A price threshold is the price of oil or gas above which royalty relief no longer applies. Hence, royalty relief is allowed only so long as oil and gas prices remain below a certain specified price. At the time of the passage of DWRRA, oil and gas prices were low—West Texas Intermediate, a key benchmark for domestic oil, was about $18 per barrel, and the average U.S. wellhead price for natural gas was about $1.60 per million British thermal units. In an attempt to balance the desire to encourage production and ensure a fair return to the American people, MMS relied on a provision in the act which states that royalties may be suspended based on the price of production from the lease. MMS then established price thresholds of $28 per barrel for oil and $3.50 per million British thermal units for gas, with adjustments each year since 1994 for inflation, that were to be applied to leases issued under DWRRA. As with the application of royalty suspension volumes, problems arose with the application of these price thresholds. From 1996 through 2000— the five years after passage of DWRRA—MMS issued 3,401 leases under authority of the act. MMS included price thresholds in 2,370 leases issued in 1996, 1997, and 2000 but did not include price thresholds in 1,031 leases issued in 1998 and 1999. This failure to include price thresholds has been the subject of congressional hearings and investigations by Interior’s Office of the Inspector General. In October 2004, MMS estimated that the cost of not including price thresholds on the 1998 and 1999 leases could be as high as $10 billion. MMS also estimated that through 2006, about $1 billion had already been lost. To stem further losses, MMS is currently attempting to renegotiate the leases issued in 1998 and 1999 with the oil and gas companies that hold them. To date, MMS has announced successful negotiations with five of the companies holding these leases and has either not negotiated or not successfully negotiated with 50 other companies. In addition to forgone royalty revenues from leases issued in 1998 and 1999, leases issued under DWRRA in the other three years—1996, 1997, and 2000—are subject to losing royalty revenues due to legal challenges regarding price thresholds. In 2006, Kerr McGee Corporation sued MMS over the application of price thresholds to leases issued between November 28, 1995 and November 28, 2000, claiming that the act did not authorize Interior to apply price thresholds to those leases. MMS estimated in October 2004 that if price thresholds are disallowed for the leases it issued in 1996, 1997, and 2000, an additional $60 billion in royalty revenue could be lost. Trying to predict the fiscal impacts of royalty relief is a complex and time- consuming task involving considerable uncertainty. We reviewed MMS’s 2004 estimates and concluded that they had followed standard engineering and financial practices and had generated the estimates in good faith. However, any analysis of forgone royalties involves estimating how much oil and gas will be produced in the future, when it will be produced, and at what prices. While there are standard engineering techniques for predicting oil and gas volumes that will eventually be recovered from a lease that is already producing, there is always some level of uncertainty involved.