The Outer Continental Shelf (OCS) was the source of $18 billion of oil and natural gas during 1998. This amounted to 25% of the nation's natural gas production and nearly 20% of the nation's crude oil. Nearly all of this output comes from the Central and Western Gulf of Mexico, where supporting infrastructure is already in place and there is little environmental opposition. Except for one sale in Alaska, no leases have been auctioned since 1991 in any other OCS region. The deep waters off Alabama, Louisiana, and Texas are the current focus of producer interest in the OCS.

During 1998, the Interior Department's Minerals Management Service (MMS) collected $4.3 billion in royalties, rents, and bonus payments from new lease sales, a decline from the record level of $5.2 billion in 1997. Collections during FY1999 were only $3.3 billion, a decline which reflects the sharp drop in oil and gas prices. Oil prices began to recover in mid-1999 and were sharply higher at year-end. But, it is difficult to estimate the future course of OCS cash flow during a period of price volatility, and how revenue levels may be perceived in regard to funding new legislative proposals.

Significant federal revenue from OCS leasing and production has been designated for the Land and Water Conservation Fund (LWCF) and the National Historic Preservation Fund (NHPF). But more of these designated funds have gone into the general fund (in special accounts) of the U.S. Treasury than have actually been appropriated. That situation, coupled with the interest of states in getting a greater share of rising OCS receipts -- especially high in 1997 -- led to legislation late in the 105^th Congress.

Bills introduced in the 106^th Congress seek funding for coastal state impacts, LWCF, and wildlife programs (S. 25, H.R. 701). Other bills would provide funds for historic preservation and resource protection (S. 446, H.R. 798). A compromise version of H.R. 701 was reported out of the Resources Committee on November 10, 1999, by a 37-12 vote. The Clinton Administration proposed full $900 million funding for the LWCF in the FY2000 Budget under the Lands Legacy Initiative.

Moratoria on leasing in environmentally sensitive areas of the OCS have been an issue in nearly every Congress since the early 1980s. A 1997-2002 OCS leasing plan from MMS appears to have satisfied major interests, and a presidential directive bans all leasing activity in sensitive areas through 2012.

In August 1999, hearings were held on legislation (H.R. 33) to create a framework for decision making about oil and gas leasing off the Florida Gulf coast after 2002.

On October 13, 1999, the House-Senate conference committee overturned a Senate-passed funding ban on a new royalty valuation system. MMS issued new rules for gas and oil valuation to become effective June 1, 2000. But in March, a producer suit overturned the nondeductibility of marketing costs for gas. In April, a similar suit was filed with regard to oil.

MOST RECENT DEVELOPMENTS

Owing to low oil and gas prices during 1998 and early 1999, revenue collection from the OCS has sharply declined from the record $5.2 billion in 1997 and $4.3 billion in 1998. Collections for fiscal 1999 were $3.3 billion. It is not apparent what effect lower revenues (which should recover in 2000) might have had on appropriations of OCS revenues and other legislative proposals.

Legislation introduced in the 106^th Congress seeks to capture half of oil and gas revenues from the outer continental shelf (OCS) for coastal states. S. 25 was introduced early in the 106^th with this general goal, earmarking half of OCS monies for an array of projects. Similar legislation, H.R. 701, was introduced in the House. In November, 1999 the Resources Committee reported a compromise bill. In addition, two identical bills were introduced (S. 446/H.R. 798) that closely follow the Administration's Lands Legacy Initiative proposal. This proposal provides for full $900 million funding of the Land and Water Conservation Fund (LWCF) in future budgets.

MMS promulgated a new proposal for both oil and gas valuation. It is scheduled to become effective on June 1. But the Independent Petroleum Association of America filed suit in the U.S. District Court for D.C. on behalf of gas producers seeking to overturn the proposal's treatment of gas marketing expense. At issue was the so-called duty to market principle, under which MMS asserted that marketing costs should be included in the computation of gas price for royalty assessment. This would have increased producer royalty payments. But in March, the court found in favor of the producers, raising questions about the validity of the duty to market principle. A suit on behalf of the oil producers seeking to invalidate the duty to market provisions in MMS proposed oil rules was initiated by the IPAA and the American Petroleum Institute in April.

BACKGROUND AND ANALYSIS

As the technology for finding and producing underwater petroleum and natural gas developed after World War II, commercial interest arose in producing hydrocarbons on the outer continental shelf (OCS). The OCS is the federal portion of the continental shelf, extending outward from three nautical miles offshore to the 200-mile territorial limit. Offshore lands within three nautical miles belong to the states, except for western Florida and Texas, where state lands extend to the 9-nautical-mile line.

Responding to increasing interest in developing OCS oil and natural gas resources, Congress enacted the 1953 Outer Continental Shelf Lands Act (OCSLA). OCSLA as amended is intended to provide for orderly leasing of these lands, while affording protection for the environment and ensuring that the federal government received fair market value for both lands leased and the production that might result. The OCS program is carried out by the Minerals Management Service (MMS) of the Department of the Interior.

Between 1954 and 1998, bonuses (up-front cash payments to secure a lease tract) paid by successful OCS bidders have amounted to $60.9 billion. OCS lessors have paid an additional $1.5 billion in rents on leased tracts, and producers have paid the federal government royalties totaling $61.4 billion. Royalties are fixed at one-eighth or one-sixth of petroleum or natural gas value as it is removed from the lease. But because of concerns that MMS has been under collecting royalties, it has proposed a controversial method of determining the value of the resource upon which the royalty is computed. The Senate has attached a ban on implementing the new valuation program in the FY2000 Interior Department Appropriations bill.

There are a few royalty formula exceptions, including a handful of net-profit sharing and royalty-in-kind deals. In total, since the enactment of OCSLA, federal offshore lands have produced over $122 billion in government revenues.

In 1998, production on the federal OCS off Louisiana resulted in $2.2 billion (81%) of the $2.7 billion royalties received total for all of the OCS. The Texas offshore yielded $374 million. The bulk of OCS revenues have resulted from leases off Texas and Louisiana, which remain the interest center for future leasing, exploration and development. California and Alaska continue to be focal points of environmental concern, even though there is little current federal production in either locale. Prelease and leasing activity is banned in California until 2012; a few tracts on the Alaska OCS will be offered for sale in the current 5-year leasing plan.

Table 1 shows aggregate OCS hydrocarbon revenues from all sources during a recent 5-year period.

Table 1. OCS Revenues, 1994-98

($ in millions)

Source: Federal Offshore Statistics, 1997 and Minerals Management Service website http://www.mms.gov

Prior to the softening in oil and gas prices in 1998, the data highlighted a doubling of total revenues from 1995-1997, larger oil revenues due to increasing production, greater gas revenues due to both increased output and higher prices, and larger bonus bid receipts due to greater interest in offshore drilling, resulting from improved deep-water technology and a deep water royalty rate reduction enacted in 1995 (P.L. 104-58). Lease sales into the winter of 1998 resulted in record amounts.

But prices declined to the $10 per barrel area in late 1998 and early 1999. As a result, OCS receipts for FY1999 declined by over one-third to $3.3 billion. But prices began to rebound in the latter half of the year, averaging in the $25 per barrel area at year-end. FY 2000 results were $3.55 billion. In FY 2001, DOI projects revenues of $5.08 billion, a figure which includes $1.8 billion in disputed lease sale revenues held in escrow for many years. This revenue­a one time event­stemmed from a court ruling settling a border dispute between the federal government and Alaska. Revenue flows are projected to decline in out years, reaching $2.1 billion in FY2010.

How the late 1999 and early 2000 oil pricing events­which saw prices touching $30 per barrel -- will play out in the future is difficult to predict. A great deal hinges on the March 2000 OPEC meeting, where production levels will be reconsidered.

The Royalty Valuation Controversy

Debate has continued for several years regarding the way oil and natural gas produced from federal leases is valued for the purpose of determining the dollar amount of royalty owed by the producer. The royalty payment is computed as a percentage of the value of the resource as it leaves the lease. But under current market and regulatory conditions, even when sold in third-party transactions, the value is not always clearcut, because gathering and marketing costs are sometimes commingled and wrapped in a transaction where the commodity price may not be clearly visible.

Crude oil and natural gas royalty valuation issues have developed on different, although parallel, tracks. Historically, oil has been appraised at actual sale prices when crude is sold to third parties in arms-length transactions. Otherwise, it has been valued at posted prices. The posted price is a value established by oil producers in the field. The fact that producers set this price singlehandedly has led to a number of lawsuits wherein the fairness of posted prices as measures of the value of the oil in question have been disputed. Many of the disputes involved states suing for their share of royalties from production on state as well as federal lands. In recent years, a number of lawsuits were settled for amounts totaling $5 billion⁽¹⁾, including a $3.7 billion settlement in Alaska.

The history and current circumstances of natural gas valuation are a bit different than oil. Prior to the deregulation of both producer prices and pipeline rates, gas had been valued at the price paid the producer by the pipeline. But under regulation, nearly all gas was purchased by a pipeline for subsequent resale, so the sale price was easily determined (it was the price the producer received from the pipeline). This changed with deregulation. Pipelines no longer bought a significant share of natural gas production. In contrast, merchants and end users are the chief purchasers of gas from producers. Gathering and marketing costs, and each segment of transport cost, are itemized and billed separately in the deregulated format.

Critics of the current valuation system contend that the settlements in the royalty valuation suits are evidence that oil is being regularly undervalued in figuring royalty payments. They are especially vocal about situations where crude is sold to an affiliated party, and not in a third-party or true arms-length transaction. When there are no market transactions in a producing area to serve as a benchmark, current valuation rules do not provide objective pricing guides and the value of these crudes are determined by the producer alone.

The Minerals Management Service in the Department of Interior has been working on new valuation rules for oil and gas for several years. MMS proposed issuing final valuation regulations in 1998. The new regulations would value oil based on a series of benchmarks for each field. The benchmarks would be computed from oil traded on public markets, with transportation, location and quality differentials factored in. For gas, the rules would factor in marketing and gathering costs that producers had sought to exclude. The new rules would have likely resulted in higher royalty collections on both gas and oil. Their issuance was blocked until the end of FY1999 by last year's Interior Appropriations Bill.

Producer opposition to the new rules has been strong, and the debate over a legislative ban during consideration of the FY2000 Appropriations bill was lively. Senator Hutchison introduced an amendment to the FY2000 Interior Appropriations Bill extending the appropriation ban for another year. In debate, the proposed regulations were characterized as a tax increase imposed on producers. In fact, Senator Murkowski described the regulations as "another tax, a value-added tax, on oil produced in the United States on Federal leases."

Senators favoring a new valuations rule because of concerns about royalty under-collections mounted a filibuster led by Senator Boxer. Cloture was voted (60-39) on September 23. Senator Hutchison's amendment banning final regulation implementation was then passed by a 51-47 vote. On October 13, the Senate-passed version of H.R. 2466 was changed in House-Senate conference, and provision was made for a six-month GAO study, after which the new royalty plan can become effective.

The Administration opposed this plan and threatened to veto the original Interior and Related Agencies bill. A compromise­passed as H.R. 3194 in late November­was signed into law as PL. 106-113 on November 29, 1999. It contained valuation rule language delaying the implementation of a rule until March 15, 2000. The GAO study was dropped from the legislative language.

The MMS moved forward proposing new rules for oil and gas which would become effective June 1, 2000. For gas, MMS called for a valuation based on prices at the lease which included aggregation, marketing fees, storage and transfer costs. There are two issues here: pricing in non-arms-length transactions and what is to be included in (or excluded from) valuation price. For valuation of gas sold in non-market transactions, MMS proposed a system of market-derived index prices which would vary based on location.

While the index pricing proved to be relatively non-controversial, determining what is included or excluded in that price for royalty calculation led to legal action by gas producers. The key principle at issue in the suit filed by the Independent Petroleum Producers of America (IPAA) in U.S. District Court for Washington DC is referred to as "duty to market." MMS has contended that leases by their very nature contain an implied duty to produce and sell resources, and that the leaseholder is obligated to deliver the resources to market at his own cost. For gas, the costs involved are clearly delineated since, as a condition of deregulation, gas ancillary and transport costs are "unbundled." Unbundling means that all cost elements are priced separately so gas buyers can tell the cost of each component, from wellhead to burner-tip.

On March 28, 2000, the court ruled in favor of the IPAA, finding that gas marketing and related costs were not part of the sale proceeds attributable to production. The court ruled these costs were deductible from sales prices in determination of the value upon which royalty is calculated. This has the effect of lowering producer royalty payments. The court also questioned the "duty to market" principle which MMS has asserted supports including marketing and ancillary costs in royalty value.

With duty to market called into question by the court, in April 2000 IPAA and the American Petroleum Institute (API) filed suit in the same court over the crude oil valuation proposal. At issue with the oil valuation rule is primarily what might be included in price for royalty computation. As far as prices themselves are concerned, the issue is less about the pricing mechanism and more about inclusion of marketing and related costs in the price for royalty valuation. Essentially, the proposed rules would value crude -- other than that sold in arms-length transactions -- at benchmark prices based on crudes traded on public exchanges, such as the NYMEX (the commodity exchange where oil is traded).

MMS valuation rules become effective on June 1, 2000, unless modified or delayed by the court.

Disbursement of OCS Revenue

Determining an acceptable division of revenue from the OCS between adjacent coastal states and the federal government has proven to be a difficult problem. Although the OCS is federal territory, coastal states argue that they bear the brunt of remediating environmental impact and infrastructure wear-and-tear accompanying OCS oil and gas activity. These states also harbor concern about rapid development in shore side communities possibly needed to support offshore activity.

As a result, various revenue-sharing methods have evolved over the years, including a higher state percentage of revenues to the closest areas of the OCS and the designation of a portion of OCS revenues to the Land and Water Conservation Fund (LWCF). However, coastal states contend that the current system is not operating as promised -- due in part to Congress' unwillingness to appropriate funds -- and have backed legislative changes.

Existing Revenue Disbursement Mechanisms. OCS revenue is a major source of funds for the Land and Water Conservation Fund and the National Historic Preservation Fund. The 1978 amendments to the LWCF Act of 1965 require the National Park Service to accumulate $900 million (at the end of each fiscal year) in the fund. While most of the $900 million comes from OCS revenues, additional monies are provided by surplus property sales, Treasury motorboat fuel tax collections, and recreation use fees collected by the Departments of Interior and Agriculture. State and federal entities use these funds to acquire park and recreational lands. (For additional information, see CRS Report 97-792 ENR, Land and Water Conservation Fund: Current Status and Issues.)

The National Historic Preservation Act of 1966 was amended in 1976 to establish the Historic Preservation Fund, to be funded annually with $150 million from OCS revenues through FY1997. These monies were intended for matching grants to the states and to the National Trust for Historic Preservation. Although Congress did not extend the $150 million annual authorization after it expired, unappropriated monies not expended remain available for future appropriation.

Table 2 shows both LWCF and NHPF appropriations for the past several years . In round numbers, appropriated monies have run roughly one-quarter of those authorized. Unappropriated monies for both funds nominally are accounted for in a Treasury reserve account, although, in reality, they have been used primarily for deficit reduction.

Both the LWCF and the NHPF recently received somewhat higher funding, although both funds still hold large unappropriated balances.

The unappropriated balance for the LWCF currently stands at $11.83 billion. The NHPF, whose $150 million annual authorization was not extended after the end of FY1997, held $2.3 billion in its unappropriated receipt account as recorded by Treasury in September 1998. Combined, both accounts -- which are not "trust funds," but Treasury accounts that do not collect interest -- recorded total balances exceeding $14 billion. Funds from those accounts cannot be spent unless they are appropriated. And any increase in annual appropriations requires a tradeoff with other programs, absent a Budget Enforcement Act waiver. Under current budget requirements, any effort to allow the funds to be expended without being appropriated would require Congress to mandate an equivalent spending offset.

Table 2. LWCF and NHPF Appropriations, FY1994-99

($ millions)

Source: National Park Service Budget Office

* Includes $699.0 million from DOI Appropriation, Title V (P.L. 105-83) for priority land acquisition, exchanges and maintenance that was provided as part of the 1997 budget deal as a one-time item.

Another claim on OCS revenues results from state-federal sharing of resource rights on the so-called 8(g) lands. These lands -- defined in the 1978 amendments to OCSLA -- are submerged acreage lying outside the 3-nautical mile (nm) state-federal demarcation line (9 nm in the cases of western Florida and Texas), typically extending a total of 6 nm (or 12 nm) offshore. Section 8(g) provides for the "fair and equable" sharing of revenues from any of the zone's hydrocarbon resources that could be an extension of pools beneath federal and state waters.

A dispute over the meaning of "fair and equable" -- dating back to 1979 -- led to placing monies from 8(g) lands in escrow. The dispute was settled in the OCSLA amendments of 1985, which set the state share at 27% and called for disbursement of all the money held in escrow in FY1986-7. In addition to the $1.4 billion of escrow funds paid out in 1986-7, a total of $390 million in annual settlement payments to the states has been provided through 1997, with the annual payments to continue through 2001. The most recent settlement payment, for FY1997, was $65 million.

Going forward, recurring annual payments of 27% of royalties, rents and bonuses derived from the federal 8(g) zone drainage tracts are to continue for the life of production in the area.

A separate escrow account was established in a similar 1979 dispute involving Beaufort Sea, Alaska, monies. It was settled in 1988, when Congress passed further amendments (P.L. 100-202). This allowed a distribution of $323 million to Alaska in FY1988. Separate litigation (regarding another $1.4 billion from the Alaskan offshore) between the State of Alaska and the federal government involving disputes over the location of the 3-mile state-federal boundary was virtually settled in 1997. The state reportedly should receive roughly $300 million as the settlement is finalized, with the bulk of the disputed $1.4 billion being retained by the Treasury.

Revenue Sharing Legislation. The history of disputes between the federal government and states over OCS revenues -- and the reluctance of Congress to appropriate authorized funds -- led to the introduction of legislation in the 105^th Congress to allocate half of OCS rents, royalties and bonuses to coastal states. This allocation has a parallel in the on-shore revenue program for production from federal lands. With on-shore revenues, 50% is allocated to the state in which the lease is located, and 40% is earmarked for the Reclamation Fund. Only 10% goes to the Treasury.

Legislative debate over the allocation of OCS revenues to projects in coastal states began to intensify with bill introductions late in the 105^th Congress. With start of the 106^th and the introduction of H.R. 701 and S. 25, the OCS revenue expenditure discussion was continued.

During 1999, H.R. 701 moved though the legislative process further. Several hearings were held in the Resources Committee. On November 10, 1999, the committee the original language was recast into a broad-based compromise. The new language was voted out of committee by a 37 to 12 vote. As reported by the Resources Committee, H.R. 701 calls for annual dedicated funding at specified levels for a variety of programs. This funding would be distributed among the 50 states, so that even states not adjacent to producing areas would receive a share of OCS revenues. Programs would be funded at these amounts:

• Coastal Impact Assistance and Conservation­$1 billion
• Land & Waste Conservation Fund Revitalization­$900 million
• Wildlife Conservation and Restoration Fund­$350 million
• Urban Park & Restoration Fund­$125 million
• Historic Preservation Fund­$100 million
• Federal & Indian Lands Restoration­$200
• Conservation Easements & Species Recovery­$150 million
• Payments- in-Lieu of Taxes & Refuge Revenue Sharing­$200 million

In the Senate, the 3-title S. 25 remains in the hearing stage; 5 hearings were held during the 1999. S. 25­as it currently stands--proposes a permanent appropriation of one -half of OCS revenues to 30 coastal states for coastal impact assistance, land and water conservation and wildlife programs. Major titles provide for:

• OCS Impact Assistance -- 27% of revenues to be distributed by formula among 30 states for such projects as air and water quality, wetlands and coastline restoration, infrastructure, and public service needs. Distribution formula based on production, coastline miles, and population. Minimum state share set at 0.5%. Recipient states would be required to distribute 60% of funds to local governments.
• LWCF -- 16% of revenues to be used for federal land acquisition, state matching grant programs, and urban park and recreation programs; funding to be split 45%-45%-10% respectively. Federal land purchases (authorized by Act of Congress) from willing sellers only.
• Wildlife Conservation Programs -- 7% of revenues made available to state fish and game departments for conservation programs.

It is not clear if S. 25 will progress in the Senate Energy Committee, and how House action might influence its direction. S. 25 might evolve on its own, or it could shift toward the H.R. 701 approach.

Other parallel bills were also introduced in the first session of the 106^th Congress. Hearings have been held on S. 446 and H.R. 798, which would provide $900 million as a permanent appropriation. (For more details, see CRS Report RL30133, Resource Protection and Recreation: A Comparison of Bills to Increase Funding.)

Proponents of increased funding cite benefits to infrastructure and other shoreside amenities. Those favoring the status quo generally wish to keep OCS revenues for deficit reduction. Other proponents of current law -- including those concerned about increased drilling activity -- view new funding as an incentive for state support for leasing in areas now off-limits. The latter may be moot, because leasing is controlled by the 1997-2002 Plan, which itself incorporates a long history of congressional moratoria and leasing bans imposed by the Administration.

Economics comes into play here too. The decision to bid on an available lease or produce oil is a corporate decision governed by the price of oil and the economics of its production. It is difficult to envision a grant to a state overwhelming the energy economics intrinsic in a given lease tract. Environmental opponents of legislation to give more OCS monies to states are concerned about creating financial incentives for states to support leasing they might otherwise oppose for environmental reasons. But no state has given any indication that it would seek new production in environmentally sensitive areas just to get a fractional interest in royalty revenue.

Those favoring legislative proposals which permanently allocate funding from OCS revenues focus on the consistent appropriation to the LWCF well below the level of OCS revenues designated to the fund. They also seek funding to mitigate shore-side infrastructure wear and tear from production-related activities and their impact on wetlands and other environmental assets. And it is contend further that consumers of underwater minerals should fund the protection and enhancement of other environmental amenities.

An additional consideration regarding permanent fixed funding based on a given level of OCS cash flow is the current instability of the revenue stream. Because oil and gas prices can be extremely volatile­and they have been during 1999­it may be risky to provide for permanent funding levels under the assumption the OCS revenues will directly or indirectly provide the cash flow.

OCS Leasing: Limitations, Moratoria and the 5-Year Leasing Plan

After the much-publicized oil spill off the coast of Santa Barbara, CA, in 1968, OCS activities have become subject to essentially three types of restrictions:

• administrative restrictions imposed by Presidents Bush and Clinton, currently in force through 2012;
• leasing moratoria imposed by Congress in annual appropriations bills; and
• restrictions embedded in a sequence of MMS 5-year leasing plans, most recently for 1997-2002.

Congressional leasing moratoria were included in annual Interior Department appropriations bills beginning with FY1982. The annual moratoria started with California offshore areas and were eventually expanded to include New England and the Georges Bank, the mid-Atlantic, and later a 50-mile-wide band off the Atlantic coast. Also included was the Pacific Northwest, much of Alaska, and the Eastern Gulf of Mexico off northwestern Florida.

In FY1999 appropriations legislation, both Houses incorporated the moratoria of past years' appropriations legislation by reference. But the Omnibus Appropriations Legislation containing the Interior Department funding questioned the need for further annual congressional moratoria in light of substantial administrative bans.

However, not all are convinced. Legislation has been introduced in the House (H.R. 33) that would establish a joint federal and state task force to study the OCS region off of Florida and evaluate what areas could safely support future oil and gas development. The Administration testified before a House Resources subcommittee in early August 1999 that the bill would duplicate functions presently carried out by MMS, and that current law and regulation provide adequately for such assessments. Representative Porter Goss (R.-Fla.), who introduced the bill, argues that there is a need to review current studies and to determine whether additional studies need to be made so that a decision regarding the Florida OCS can be made with more precision and certainty.

The current OCS leasing program is embodied in the MMS Final Outer Continental Shelf Oil & Gas Leasing Program, 1997 to 2002. This plan identifies all the individual tracts to be offered for sale during the period. It was formulated with extensive comment from virtually all stakeholders, and it includes the moratoria from the annual appropriations bills. Additionally, in 1990 President Bush issued a directive that the executive branch conduct no leasing or preleasing work on lands under legislative moratoria until the year 2000; in June 1998 President Clinton extended that ban until 2012.

The 1997-2002 leasing plan was designed to accommodate the sensitivities of as many major interest groups as possible. As a result, only lands in the Central and Western Gulf of Mexico and a few selected places off Alaska will be offered for lease. Oil and gas producers have expressed general satisfaction with the plan, because the Central and Western Gulf is the location of nearly all OCS hydrocarbon activity -- both active and prospective -- as well as the needed infrastructure. Beyond the appeal of looking for hydrocarbons in known oil- and gas-prone areas, producers seek to avoid environmentally controversial areas for reasons of public relations as well as economics.

OCS Lease Buybacks

The Department of the Interior halted the process of developing certain leases in environmentally critical areas. These include 23 tracts in Bristol Bay, AK, 53 off the coast of North Carolina, and 73 in South Florida, below 26 degrees N. Latitude. The leaseholders initiated litigation, demanding compensation from MMS, contending that the Government's development halt constituted breach of contract, and a taking of leaseholders' (purchased) property rights.

In August 1995, litigation was settled with regard to the Alaska and Florida leases in two agreements covering all remaining claimants. In one suit's settlement, Conoco was paid $23 million from the Justice Department's Claims and Judgments Fund. This circumvented the barrier to buybacks posed by a of lack of appropriated funds in DOI's budget.

In the second settlement, regarding leases in South Florida, seven other claimants will be paid a total of $175 million from the Judgment Fund. A claim by Shell had been settled several years earlier as part of a deal involving an offsetting claim on disputed royalty payments owed the federal government.

The leases off the North Carolina coast are currently in litigation. In March 1996, a U.S. Court of Federal Claims ruled that the government illegally barred seven oil companies holding leases from developing their tracts. The court determined that leaseholders should be paid fair market value for the tracts or be reimbursed for lost revenues from the tracts. The federal government brought the case to the Court of Appeals, which ruled 2 to 1 against the firms on a technicality. Further appeal is possible.

Development bans, and the process that ultimately resulted in the buybacks, introduced an element of uncertainty in the leasing process and led to litigation. The current leasing framework includes well-established moratoria and a comprehensive 5-year leasing plan that avoids tracts where development might encounter roadblocks. Thus, future bans on the development of leased tracts, and the litigation that has resulted, are much less likely.

LEGISLATION

H.R. 33 (Goss)
Imposes certain restrictions and requirements on the leasing under the Outer Continental Shelf Lands Act of lands offshore Florida, and for other purposes. Introduced January 6, 1999; referred to Committee on Resources and the Subcommittee on Energy and Mineral Resources. Hearings held August 5, 1999.

H.R. 701 (Young)
Conservation and Reinvestment Act of 1999. Provides OCS impact assistance to state and local governments. Introduced February 10, 1999; referred to the Committee on Resources. Hearing held March 10, 1999.

S. 25 (Landrieu)
Conservation and Reinvestment Act of 1999. Amends OCSLA, the Land and Water Conservation Fund Act of 1968, and the Federal Aid in Wildlife Restoration Act to provide funding of half the receipts of revenues from the outer continental shelf. Introduced January 19, 1999; referred to Committee on Energy and Natural Resources. Hearings held April 19, 20, April 27, May 4 and May 11, 1999.

S. 446 (Boxer)/H.R. 798 (Miller)
Resources 2000 Act. Provides permanent protection of the resources of the United States. Introduced February 23, 1999; Senate bill referred to the Committee on Energy and Natural Resources, and House bill referred to Committee on Resources. Hearings on S. 446 held by the Senate Committee on Energy and Natural Resources April 27, May 4, and May 11, 1999. Hearings on H.R. 798 held by the House Committee on Resources March 10, 1999.

FOR ADDITIONAL READING

U.S. Department of the Interior, Minerals Management Service. Proposed Final Outer Continental Shelf Oil & Gas Leasing Program -- 1997 to 2002. Decision Document. August 1996.

----. Mineral Revenues 1997: Report on Receipts from Federal and Indian Leases.

----. Federal Offshore Statistics: 1997 Leasing, Exploration, Production and Revenue as of December 31, 1997.

----. Minerals Management Service Web Site: http://www.mms.gov

CRS Products

CRS Issue Brief IB10015. Conserving Land Resources: The Clinton Administration Initiatives and Legislative Action. Updated regularly.

CRS Report RL30133. Resource Protection and Recreation: A Comparison of Bills to Increase Funding. April 9, 1999.

Footnotes

1. ^(back)See Senator Boxer at page S11323 of the Congressional Record, September 23, 1999.

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