Outer Continental Shelf Oil and Gas Leasing

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Proposed rule.

SUMMARY:

This proposed rule outlines why and how we may issue Outer Continental Shelf (OCS) leases after November 2000 with royalty suspensions. It also presents a plain-language revision of the existing rules for bidding systems and joint bidding restrictions. It does not change the current policies on royalty suspensions for leases issued before December 2000, though it does add one minor reporting requirement for leases issued with royalty suspension.

DATES:

We will consider all comments we receive by October 16, 2000. We will begin reviewing comments then and may not fully consider comments we receive after October 16, 2000.

ADDRESSES:

If you wish to comment, you may mail or hand-carry comments to the Department of the Interior; Minerals Management Service; Mail Stop 4024; 381 Elden Street; Herndon, Virginia 20170-4817; Attention: Rules Processing Team (RPT). The RPT's e-mail address is: rules.comment@MMS.gov.

Mail or hand-carry comments with respect to the information collection burden of the proposed rule to the Office of Information and Regulatory Affairs; Office of Management and Budget; Attention: Desk Officer for the Department of the Interior (OMB control number 1010-NEW); 725 17th Street, NW., Washington, DC 20503.

FOR FURTHER INFORMATION CONTACT:

Marshall Rose, Economics Division, at (703) 787-1536.

SUPPLEMENTARY INFORMATION:

The OCS Lands Act (OCSLA) (43 U.S.C. 1331 et seq.) is the authority for our regulations governing leasing of oil and gas resources on the OCS. Section 8(a)(1) of the OCSLA (43 U.S.C. 1337(a)(1)) provides authority for the Secretary of the Interior (Secretary) to offer leases under a variety of bidding systems. This proposed rule describes the bidding systems, our joint bidding requirements, a modified rental policy, and royalty suspension for certain leases.

Overview

The regulations at 30 CFR part 260 implement the Secretary's authority to encourage leasing competition through the use of appropriate bidding-system alternatives and a joint bidding ban among certain large companies. Also, these regulations implement the Secretary's authority to promote leasing interest in certain areas of the OCS through suspension of royalties. They describe:

(1) The characteristics of various bidding systems that we can use at OCS lease sales;

(2) The criteria for listing a company as a restricted joint bidder; and

(3) Our approach to offering royalty suspension for deep water leases.

Regulations at 30 CFR part 218 cover the rental and minimum royalty fees associated with leases.

Section 303 of the Outer Continental Shelf Deep Water Royalty Relief Act (Pub.L. 104-58) 43 U.S.C. 1337(3) (the Act), established authority for the Secretary to offer tracts with royalty suspensions for a period of time, volume of production, or value of production. Section 304 made all deep water (200 meters or greater) leases issued between 1996 and 2000 in the western and central Gulf of Mexico (GOM) and westernmost part of the eastern GOM eligible for royalty suspension for certain volumes of production. In addition to modifying our royalty suspension policy and extending it to certain deep water leases issued in sales held after November 2000, this proposed rule adds a minor reporting requirement at 30 CFR 260.114 for deep water leases issued before 2001. It also clarifies and rewrites in plain language current rental regulations at 30 CFR 218.151 to provide for lessees to pay rental fees during the period of royalty suspension.

Future Royalty Suspensions

For leases issued after November 2000, we offer incentives in lease terms to encourage more exploration and development than would otherwise occur in certain domestic areas. Suspension of royalty does this, in part, by raising the prospective rate of return relative to other domestic and foreign opportunities competing for investment by multi-national oil companies. Royalty suspension also may convert marginal prospects to profitable ones. Leasing incentives can encourage more examination of an important domestic oil and gas province. This examination not only improves understanding of the potential in the area but also stimulates development of technology necessary to exploit resources found there. Also, temporary incentives can promote development sooner rather than later by compounding the advantage of infrastructure that will be installed on many of the fields recently leased in the area.

Recent leasing experience supports the notion that royalty suspensions provide a powerful incentive. MMS issued the large majority of GOM deep water leases during the period of leasing with royalty suspension volumes mandated by the Act. Of the total of 1,906 central GOM leases now active in 800 meters or deeper water, we issued 79 percent (1,497) during the first 4 years of leasing under the Act. Of the total of 1,342 western GOM leases in 800 meters or deeper water, we issued 92 percent (1,231) since the Act. However, with so much acreage in their inventory, current operators may not be able to assess the hydrocarbon producibility of all of the leases they have acquired. Only about 40 vessels are currently available to drill in deep water, and they each can drill only about four wells per year on average. Many of the currently leased deep water tracts may simply be returned unexplored. Also, leasing statistics indicate less leasing interest as water depth increases, despite the royalty suspension incentives of the Act. In water deeper than 2,400 meters, only 15 percent of available tracts have been leased in the central GOM planning area. This compares with 60 percent of available tracts in water between 200 meters and 2,400 meters deep in the central GOM. For these reasons, we see value in continuing some form of leasing incentive, especially in the deepest part of the GOM. But, because of our experience under the Act, we also see a need to adjust the deep water leasing incentive to new circumstances.

We expect that generally smaller royalty suspensions than were mandated by the Act should suffice for several reasons.

(a) Oil and gas prices are higher than they have been in at least a decade, and many now expect them to remain high for some time.

(b) The current leasing density in much of the deep water portion of the central and western GOM will improve the economics of future leases in at least two ways. One, it will build a knowledge base on the unfamiliar geology in the GOM deep water. Discoveries on already-leased tracts will provide geologic analogs that reduce play risk and the uncertainty associated with estimating reserve volumes and production characteristics faced by future deep water lessees. Two, it will eventually support the installation of critical infrastructure such as pipelines and accessible processing capacity. Existing infrastructure improves the economics of nearby resources.

(c) Experience developing already-leased deep-water tracts will identify and demonstrate the most effective technologies for operating in this challenging environment. Thus, later deep-water projects should be more efficient and face less development risk than the pioneering projects.

(d) As explained in the next section, we propose to increase the value of a given royalty suspension volume by reducing uncertainty about how much royalty relief a lease would ultimately realize. Under volumes set in the Act, bidders contend not only with whether a lease has producible reserves but also whether production from neighboring leases will preempt some or all their royalty relief. We propose to eliminate the latter form of uncertainty.

(e) Finally, we may enlarge the scope of our discretionary royalty relief program under 30 CFR part 203, which can supplement the incentive provided by royalty suspensions in leasing terms.

Perhaps the biggest change we propose in this renewal of our leasing incentive program is to have flexibility in our pre-production royalty suspension lease terms. We plan to do this by reserving to the annual lease sale notices the size and scope of the royalty suspensions we will offer. The rapid change in the economics of deep water development makes rigid leasing incentives inappropriate. Royalty suspensions attuned to one set of price and cost expectations become unrealistic when price or cost conditions change significantly. If costs fall, for instance, not only may old incentive levels provide more relief than needed for newer leases but also may undermine general support for a program of leasing incentives. On the other hand, if market prices for oil and gas show a significant or sustained decline, royalty suspensions can be adjusted upward to ensure the appropriate level of incentives necessary to sustain deep water activities. Thus, we plan to review periodically and, when appropriate, adjust future leasing incentives. However, once established, we expect the royalty suspension volumes to be in place for at least 3 years to provide industry with the certainty needed to plan their lease acquisition and bidding strategies.

To help us design appropriate incentives, we would like comments on how best to answer the following questions:

• What factors should we consider, and how should we evaluate these factors, when we choose water depths beyond which bidders still need leasing incentives in the GOM?
• What elements besides water depth should we consider, and how should we consider them, when deciding how much royalty suspension to offer on new leases?
• Which of the following leasing policies would encourage more domestic investment, given equal expected rates of return, and why would it do so? One offering a:

(a) Substantial royalty suspension volume coupled with higher than normal royalty rates (e.g., 20 percent) for additional production between specified cumulative production volumes; or

(b) Modest royalty suspension volume but with only normal lease royalty rates for production above the royalty suspension volume?

• Does the likely increase in bid levels and shift of uncertainty from government to industry that are associated with royalty suspension adversely affect small companies relative to large companies?

Lease-Based Royalty Suspension

Aside from adjusting the size and scope of royalty suspensions with which we might issue new leases in deep water, we propose to simplify the way we apply royalty suspensions to leases. The following discusses the differences between how we apply royalty suspension to leases issued between 1996 and 2000 and how we propose to apply royalty suspension to leases issued in sales held after November 2000. Under current regulations, specific leases are eligible for the royalty suspension volumes assigned to a field. With this rule, we propose to assign a royalty suspension (RS) volume to individual RS leases. Among other things, that would mean the field to which we eventually assign the RS lease would not affect how much royalty suspension the lease realizes.

Assigning royalty suspension volumes to a field rather than to a lease leaves individual lessees eligible, but uncertain about how much royalty suspension they could eventually realize. Fields typically consist of multiple leases, so we established allocation rules that generally applied the royalty suspension volume to the earliest production in the field (first come, first served). If some leases in the field produce first, little if any royalty suspension volume may be left for other leases. Because the infrastructure should then be available for late-producing leases on the field, this result was appropriate. But, if different producers on the field develop independently, existing infrastructure may not benefit later leases. Thus, reserving some royalty suspension for later leases may be vital to encouraging full development of some fields. Generally, the prospect of having to share an unknown portion of a royalty suspension for a field with other leases lessens a bidder's certainty about the value of royalty relief on a particular tract. With so many tracts now leased in deep water, new leases may face a significant risk that the royalty suspension volume on their field will have already been depleted by others by the time they reach production stage. The existing rule assigned royalty suspension volumes to fields for a variety of reasons (see the interim rule in the Federal Register on March 25, 1996, 61 FR 12023-12026), in part because the size of the mandatory suspension volumes was based on the incentive amount needed to encourage field development. The Act did not mandate field-sized royalty suspension volumes for sales held after November 2000, so we now propose to grant royalty suspension volumes to individual leases, without regard to field allocation rules.

Lease-based royalty suspension also eliminates the unavoidable complexity associated with a field-based incentive approach. Fields may combine leases issued under different lease terms. Some fields may have leases issued with the Act's royalty suspension volume (eligible leases) and others issued before the Act (pre-Act leases) with no royalty suspension. The combination of leases issued under different terms obligated us to establish procedures that allocate field-based, royalty suspension volumes clearly. Existing regulations at 30 CFR 260.110(d) use 14 subparagraphs to describe the rules necessary to allocate field-based relief among multiple leases and the current categories of leases. A field-based incentive approach for new leases we issue in sales after November 2000 would require additional allocation procedures.

A lease-based royalty suspension does not eliminate the need for allocation rules for fields that combine different categories of leases, but it substantially reduces the number and complexity of those rules. It achieves this by phasing out the role a field designation plays. Leases issued in sales before November 2000 must follow the current field allocation rules. Leases issued in lease sales after November 2000 will not need field allocation rules. Their RS volume stays the same no matter to what field MMS assigns them. Where they occur in a field with leases issued in lease sales before November 2000, we propose special field allocation rules to account for how new RS leases affect field suspension volumes. Production from new leases that are issued with a lease-based RS volume and that are on fields with eligible leases counts against the field-size volume on a first come, first served basis. However, unlike the eligible leases, the field's RS leases may receive their full RS volume even after the field has produced the suspension volumes allowed for eligible leases. This is the simplest way to transition into a lease-based RS volume program, while remaining consistent with the field royalty suspension program.

Lease-based royalty suspensions avoid progressive complications associated with a field-based approach. A convenient simplification used in the existing leasing regulations is that all eligible leases in the same field share, on a first come, first served basis, the maximum royalty suspension volume available to any lease in the field. This simplification avoided windfalls to individual leases and complications in allocating the field's volume suspension among individual leases. Trying to continue volume suspension incentives on a field basis would further complicate our accounting for changes in the economics of exploration and development. When we offer leases after November 2000 with volume suspensions, we intend to issue the leases with sufficient RS volumes to fit the economic circumstances prevalent at the time without providing an outdated or excessive incentive. This also helps MMS to achieve the fair market value mandates of the OCSLA. Flexibility to revise RS volumes from time to time means we can identify changes—in technology, infrastructure availability, price expectations, etc.—that support a change in the size of royalty suspension. To try to account for this flexibility in a field-based, royalty suspension volume system would not help MMS achieve its fair market value mandate and would compound the allocation complexity mentioned above.

We designate a deep water lease issued in a sale after November 2000 with a royalty suspension volume as an RS lease. Where adopted, royalty suspension will continue to take the form of zero royalty for an explicit volume of production. However, instead of a field-sized, royalty suspension volume fixed in regulation within a designated water depth interval, we will offer RS leases with a lease-specific royalty suspension volume published in the Federal Register notices that announce each sale. We intend to do an analysis of how different royalty suspension volumes affect the economics of various development scenarios. That analysis will factor in changes in technology and infrastructure availability, as well as the sizes of the un-leased fields we foresee in the relevant water depths. To assign the appropriate volume to each RS lease, we intend to divide the amount of royalty suspension we consider necessary for a development by the typical number of participating leases. These RS volumes may vary by different water depth demarcations, and leases in some water depths may be issued with no volume suspension. We will propose specific suspension volumes in the Proposed Notices of Sale published in the Federal Register for public comment several months before each sale. After weighing any comments, we will establish the appropriate royalty suspension volumes for leases sold in that sale. We expect the volumes to be in place for sales held over the next 3 years.

We are currently in the process of determining the appropriate royalty suspension volumes for sales in the central and western GOM over the next 3 years. Part of this determination involves assessing the nature and extent of deep water oil and gas resources that could be leased in these sales. This assessment requires speculation about resource potential using the most current geologic and geophysical information, insight from recent discoveries, and estimates of how much remains undiscovered and un-leased. To insure we have the best available information on resource potential, we have been working collaboratively with industry representatives to identify the potential range and size of fields in the deep water GOM. We expect to complete our resource interpretations while these draft regulations are under public review.

At this point, we can say we presume that bidders have identified and acquired most profitable prospects, at least an ample supply of the ones on which they can assess the hydrocarbon potential over the next 5 to 10 years. Many of the remaining opportunities should be of a fill-in nature, especially in all but the deepest water. For this reason, we will be considering the merits of focusing incentives for upcoming sales on royalty suspension volumes appropriate to subsea developments that tie back to host platforms. The industry trade associations, in their August 3, 2000, letter to the Director of MMS, noted that many future discoveries that are close to existing infrastructure will be developed as tie-backs rather than stand-alone facilities because of the lower capital investments required. But they also pointed out that many companies may choose to develop some close-by fields with stand-alone facilities. The hosting potential of these close-by facilities can supplement the ability of royalty suspensions to improve lease profitability. Viewed another way, large stand-alone incentives appear unnecessarily costly at a time when remaining prospects will have access to already installed infrastructure on recently leased deep water tracts.

To help us evaluate these changes to the leasing program, we would like comments and answers to the following questions.

• Do you agree with our observation that a lease-based royalty relief program, providing a guaranteed royalty suspension volume to each lease regardless of which field it overlies, is preferable to a field-based royalty relief program, providing a royalty suspension volume to be claimed by the earliest producers on a field?
• Do you share our expectation that royalty suspension volumes tailored to a typical tie-back development will promote bidding and exploration in the deep water areas that will be available in the next several years?
• Is it reasonable to assume between 2 and 3 leases per field will be developed as a tie-back?
• What benefits would occur for bidders and lessees if we modified the volume suspensions offered on new leases every 3 years as opposed to more frequently?

Rental Payments

Under current rental regulations at 30 CFR 218.151 for OCS leases, the obligation to pay rental at the beginning of the lease year ends when a discovery is made on the lease. During the time between discovery and the start of production, MMS imposes a charge called a “minimum royalty,” which we typically set equal to the rental fee. Lessees pay minimum royalties at the end of the lease year. Once production begins, the minimum royalty applies if ordinary royalties fall below the annual amount associated with the minimum royalty. Thus, lessees pay a fee in one form or another for each year they hold a tract under lease.

The term “minimum royalties” during production of royalty suspension volumes seemed inconsistent with the royalty relief policies of the Act. Suspending minimum royalties meant collection of not even a holding fee during periods in which no royalty payments were due on production. The absence of a holding fee during the royalty suspension period on deep water leases has raised some concerns with the Department of the Interior's Office of the Inspector General. (See Evaluation Report—Opportunity to Increase Offshore Oil and Gas Rental Revenues,” Minerals Management Service, Report No. 99-I-387, March 1999.)

In response to those concerns and to reduce confusion, we propose to clarify and rewrite in plain language the definition of rentals for new leases issued after the effective date of this rule so that the same fee applies up to the commencement of royalty payments. After this point, minimum royalty obligations apply. In fact, this treatment is similar to the way we currently define rentals for net profit share leases. Collection of rental or holding fees during royalty suspension periods is analogous to their collection during the capital recovery period when net profit share leases pay no royalty.

Relief Suspension During High Prices

Our deep water leasing program has also applied the high oil or gas price threshold provision, specified in the Act explicitly for pre-Act leases to which we grant royalty suspension under 30 CFR part 203, to eligible leases issued under 30 CFR part 260. This provision requires payment of full royalties, notwithstanding any remaining royalty suspension volume, when market prices rise above prescribed levels or thresholds. We anticipate continuing this concept, but in a more flexible manner. Again, we intend to follow the general structure established by the Act of setting a clear price threshold above which royalties must be paid, yet production continues to count against any remaining royalty suspension volume. Also, as in the Act, we intend to escalate these price thresholds for inflation. But, rather than adopt the initial oil and gas price thresholds specified in the Act, we reserve the right to adjust these to be consistent with changing cost structures in deep water. We may specify in the Federal Register“Notice of OCS Lease Sale” new price thresholds above which full royalties are due on the leases sold in that particular sale. We may adjust these thresholds sale-by-sale. However, any adjustments would apply only to new leases issued at the upcoming sale, not leases issued previously. We also may change the price or the period of applicable production from a calendar year to a current year, rolling average year, monthly or quarterly, either retrospectively or prospectively. The Act retroactively applies royalties when prices in the previous calendar year exceed the threshold.

To select initial price thresholds for future lease sales, we will focus on recent price history, price forecasts, and a variation of our bid adequacy evaluations. Specifically, we will identify price increases from expected levels that make royalty suspension a benefit unnecessary to potential development sizes. We will do this by combining price history and forecasts with current estimates of minimum resource sizes necessary to be economic with a typical tie-back development.

To help us evaluate these proposed changes in lease terms, we would like comments on and answers to the following questions.

• What effect, if any, would rental obligations during periods of royalty-free production have on the way firms plan and manage a project?
• Do you agree with our observation that, given current costs, technology and development options in deep water and the dynamic nature of these factors, the program would benefit from periodic adjustments at the time of lease sales in price thresholds for new leases?
• Do you believe that adjustments in royalty obligations, other than retroactively for the previous calendar year are desirable? If so, why and what is the nature of the preferred adjustments?
• Do you agree with our preliminary findings that the applicable price thresholds should be 10 to 15 percent below the levels currently applicable under the Act, e.g., $28 rather than $31 per barrel for oil, and $3.45 rather than $3.90 per million British thermal units?

Change to Royalty Suspension Policy for Eligible Leases

One final item of note is a proposed requirement that a lessee with eligible leases issued with a royalty suspension volume notify the MMS Regional Supervisor for Production and Development before starting production. We would add this new provision to otherwise unchanged regulations covering eligible leases. Such notification would ensure that we can timely identify how much suspension volume is used by individual leases. The new provisions increase the variety of volume suspensions that fields may have as well as the amounts attributable to individual leases in the same field. In this situation, it is prudent to validate royalty suspensions at the time of initial lease production.

To help us evaluate this proposed change, we would like comments and answers to the following question:

• Does this additional notification step impose any meaningful burden on lessees?

Citation Correction in Part 256

In addition, we are correcting a citation error in § 256.40 that we discovered in developing the proposed part 260 regulations which reference this section.

Simplification of Valuation Basis

Finally, we take this opportunity to drop a reference in the new § 260.111, to the discontinued ceiling price provisions in other parts of the CFR.

Summary of Proposed Changes

To summarize, this proposed rule would adopt plain-language phrasing and would implement the system described above by changing the existing rules in five places.

• In § 218.151, we would add language to specify the rental policy for leases issued in sales after November 2000.
• In § 260.102, we would add definitions for RS leases and enhance the existing definition for eligible leases to be clear that it refers to leases issued between 1996 and 2000. Also, we would move the definition of a pre-Act lease from the existing § 260.110(d)(9) to § 260.102.
• We would renumber the old §§ 260.110(a)-(d) and § 260.111 as §§ 260.112-260.117 and § 260.130.
• We would add a new § 260.114(c) requiring notification of start of production by eligible leases.
• Finally, we would add new §§ 260.120-260.124 to explain the basic principles we will follow in future lease sale notices when describing how royalty suspension applies to RS leases. Sections 260.112-117 and 260.120-124 are similar but separate to facilitate referencing in leasing documents for RS leases as opposed to those for eligible leases, and to facilitate future changes we may make in the regulations for future leases. Also, the separation serves to highlight the shift from a rigid field-based, to a flexible lease-based, royalty suspension policy that we propose. The proposed rules assume RS leases receive the royalty suspension volume with which we issue them (except if prices rise enough to trigger payment of royalties). Eligible leases do not have that assurance, only the eligibility to share in a field's royalty suspension volume.

Procedural Matters

Public Comment Procedure

Our practice is to make comments, including names and home addresses of respondents, available for public review during regular business hours. Individual respondents may request that we withhold their home address from the record, which we will honor to the extent allowable by law. There may be circumstances in which we would withhold from the record a respondent's identity, as allowable by law. If you wish us to withhold your name and/or address, you must state this prominently at the beginning of your comment. We will not consider any anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

Regulatory Planning and Review (Executive Order 12866)

According to the criteria in Executive Order 12866, this rule is a significant regulatory action. The Office of Management and Budget (OMB) makes the final determination under Executive Order 12866.

a. This rule will not have an annual economic effect of $100 million or adversely affect an economic sector, jobs, the environment or other units of government. This action is a plain-language rewrite of current rules and clarification of policies that may be employed for issuing leases with royalty suspensions in lease sales held after November 2000. There is no assurance that the leasing system option provided in this rule will be used in all future offshore sales. For instance, sustained high prices or a shortage of unleased tracts may cause us to discontinue leasing incentives. Even when used, the leasing system option in this rule will not change substantially the net economic value of production from leases eligible for royalty suspension volumes. Royalty suspension should lead to higher bonuses because future production will be more profitable. Also, more tracts should receive bids because royalty relief makes smaller, more remote fields potentially profitable. But, because the government collects the fair market value of a tract in the up-front bid, the risk that the tract will not prove productive is shifted entirely to the bidder. We do not expect bonus bids to fully offset the anticipated royalty savings on a specific tract. Since these offsetting effects on revenue will play out over an extended period and involve uncertainties that will be assessed differently by the different bidders, we cannot predict the ultimate effect on government receipts. Most of the more prospective tracts have been leased already and the incentives we envision for the next several years are smaller than those mandated by the Act. Thus, we don't expect to see the level of bidding activity experienced in the last 5 years, nor the same level of future royalty reduction. At this point we can say that deep water royalty relief will serve primarily to accelerate the timing of production and redistribute realization of fair market value from royalty to bonus collection. As royalty suspension volumes are an incentive to production, they likely encourage timely exploration in hope of finding reserves, since royalty relief has no value unless and until production occurs. This acceleration will have a beneficial effect on offshore oil industry production and jobs in the near term.

b. This rule will not create inconsistencies with other agencies' actions because there are no changes in requirements from the existing rule.

c. This rule is an administrative change that will not affect entitlements, grants, user fees, loan programs, or their recipients. This rule has no effect on these programs or rights of the programs' recipients.

d. This rule will raise novel legal or policy issues. Although this action is basically the rewrite of an existing rule in plain language and sets up a more flexible framework to continue current royalty suspension policies for future sales, it comes at a time when oil and gas prices are unusually high. Some may question the need to continue leasing incentives. We believe royalty suspension remains necessary in a scaled-down and more flexible format because prices can fall as well as rise. Also, a continued program reduces disruptions associated with an abrupt termination of incentives and resultant pressure to continue the rigid, outdated and expiring terms of the Act.

Regulatory Flexibility (RF) Act

The Department certifies that this proposed rule would not have a significant economic effect on a substantial number of small entities under the RF Act (5 U.S.C. 601 et seq.). The provisions of this rule will not have a significant economic effect on offshore lessees and operators, including those that are classified as small businesses. The rule will authorize royalty relief to certain OCS leases awarded in sales held after November 2000. New regulatory provisions will offer firms, large and small, economic incentives to acquire and develop deep water leases in the GOM.

Companies that extract oil, gas, or natural gas liquids or are otherwise in oil and gas exploration and development activities acquire the vast majority of leases offered at OCS lease sales and will be most affected by this rule. The Small Business Administration (SBA) defines a small business as having:

• Annual revenues of $5 million or less for exploration service and field service companies.
• Fewer than 500 employees for drilling companies and for companies that extract oil, gas, or natural gas liquids.

Under the Standard Industrial Classification code, 1381, Drilling Oil and Gas Wells, MMS estimates that a total of 1,380 firms drill oil and gas wells onshore and offshore. The group most affected by this rule is the approximately 130 companies that are offshore lessees/operators. According to SBA criteria, 39 companies qualify as large firms, leaving up to 91 companies that may qualify as small firms with fewer than 500 employees. However, because of the extremely high cost and technical complexity involved in exploration and development in deep water, the vast majority of lessees/operators that will be affected by this rule will be large companies. Nineteen of the 26 lessee/operators that have registered a total of 211 discoveries by mid-year 2000 in deep water (200 meters and greater) are not small and these 19 large firms account for over 91 percent of the total discoveries. The proposed rule envisions limiting incentives to deeper water (800 meters and greater) than the Act, where the presence of large firms is even more prevalent. Virtually all of the prospective tracts in the part of deep water where small firms traditionally operate are already under lease.

This rule would add costs in two areas where there are no costs under the existing rules and the deep water royalty relief terms associated with eligible leases. First, lease terms for eligible leases suspended all payments, including rents and minimum royalties, after start of production on the lease and until the mandated royalty suspension volumes were fully produced. This rule would require that lessees of leases issued in sales after the effective date of this rule must continue to make annual rental payments after a discovery until established suspension volumes have been produced and lessees begin to make royalty payments on production at the lease-stipulated royalty rate. Rentals would replace minimum royalties between discovery and start of production for those leases. Experience to date (mid-2000) shows that only three leases issued with the royalty suspension terms set by the Act have gone into production. One of these three operators is a small business, and the other two might be. If that experience continues for leases issued after this rule, we might expect that perhaps one such lease may produce by 2004, and two more might produce by 2005. Thus, these new leases, irrespective of the size of the lessee, may owe extra rentals ($43,200/lease/year) of $172,800, or an average over the next 5 years of just below $35,000/year. This estimate presumes that these leases will pay rentals instead of “minimum royalties” between discovery and start of production.

Second, the rule would add the requirement that owners of eligible leases notify MMS prior to initiating production on the leases. We estimate it will take an operator one-half hour to draft, finalize, and send such a notification letter. We envision that this letter will be very brief and give only pertinent data such as lease number, area/block, date production is scheduled to commence, and language requesting confirmation of the amount of royalty relief applicable. We currently have six eligible leases with approved Development Operations Coordination Documents (DOCD) and 264 eligible leases with approved Plans of Exploration (POE). For this analysis, we assume that:

(1) All six leases with approved DOCDs will commence production within the first 5 years;

(2) Thirty percent (79) of the 264 leases with approved POEs will drill a discovery well; and

(3) Twenty-five percent (20) of those leases with a discovery well will obtain a DOCD and commence production. Based on these assumptions, we estimate that a total of 26 eligible leases will commence production within the next 5 years.

At an estimated paperwork cost of $50 per hour or $25 per notification, the total estimated cost of the notification requirement for the first 5 years in which the rule is in effect is $650 or $130 per year.

Thus, total estimated incremental costs associated with this proposed rule are slightly below $35,000 per year on average through 2005. The annual cost will be spread among lessees whose eligible leases commence production and eventually among leases issued after this rule becomes effective and that produce with a royalty suspension. Based on the ratios found above, small business may incur one-tenth to one-third of this incremental cost. The annual cost for a small business with a producing royalty suspension lease paying rental and several eligible leases commencing production could be approximately $44,000 per year. It is clear, however, that the magnitude of the costs do not impose a significant economic effect on a substantial number of small business entities engaged in multi-million dollar drilling and development activities.

Further, any costs associated with the rule must be viewed in light of the substantial economic benefits to be gained from the suspension of royalty payments on the established volume of production. While estimated averaged annual costs are just under $35,000 per year through 2005, lessees that produce stand to gain tens of millions of dollars in royalty relief from the rule. For example, the standard royalty portion (1/8) of say an eight MMBOE royalty suspension volume is worth between $20 and $30 million at current oil and gas prices. Again, small business may claim one-tenth to one-third of this benefit. The potential benefit of royalty relief to a small business can be as high as $5 million/year, far outweighing the $44,000 maximum cost/year for a small business operating in deep water.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the enforcement actions of MMS, call toll-free (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

This proposed rule is not a major rule under the SBREFA, 5 U.S.C. 804(2). This rule:

a. Does not have an annual effect on the economy of $100 million or more. This rule rewrites the existing rule and clarifies royalty suspension policies for future sales. This rule does not specify exact royalty suspension parameters, but describes concepts that we will follow in determining sale-specific royalty suspensions for designated tracts. While royalty suspension volumes for future sales are not likely to be as high as the current levels specified in the Act, they will still provide meaningful benefits to large and small business lessees.

In general, royalty suspension redistributes revenues—royalty payments decline during the royalty suspension period, while bonus payments before exploration and tax payments due on extra income to the lessee during the royalty suspension period increase. To benefit from the royalty suspension, the lease must produce. Because only a fraction of tracts leased ultimately produce oil and gas, a relatively small number of tracts actually receive a royalty suspension. To determine the annual effect of the royalty relief system on the economy, both the effects on bonus bids and future royalties need to be considered. For purposes of illustration, consider the experience from sales where leases have had time to run the course of the original lease term. Data for leases issued during the period 1983 to 1988 (when no royalty suspension volumes were offered but also when many of the best prospects were leased) show that, on average, only about 15 percent go into production. Also, estimates for sales between 1996 and 2000 suggest that bidders bid about a $500,000 premium per royalty suspension lease. Using a ratio of seven leases issued for every one (15 percent) that produces, the Government can expect to collect perhaps $3.5 million in extra bonus revenues for each lease that uses a royalty suspension. If royalty suspension causes some leases to be bid on that otherwise would not be, the Government would collect even more extra bonus. Unfortunately we have no good estimates of this second kind of extra bonus. Nonetheless, the extra bonus from the seven-plus leases will be offset by collection of about $20 million less in royalties from the one that produces (e.g., 1/8 of eight MMBOE times $20/BOE over the production period (e.g., 2010 to 2020). If extra taxes reclaim about 1/4 of the royalty cost savings, those are comparable sums on a present value basis (e.g., 7 × $0.5 approximately = $20 (1−$0.25) × 0.26 where 0.26 is a discount factor for payments received 10 to 20 years in the future). Thus, even when scaled up to cover sales of hundreds of leases in any one year, this rule will not have an annual effect on the economy of $100 million or more.

b. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. Oil prices are not based on the production from any one region, but are based on worldwide production and demand at any point in time. While gas prices are more localized, they correlate to oil prices. The rule does not change any existing leasing policies, so it should not cause prices to increase.

c. Does not have significant adverse effects on competition, employment, investment, innovation, or the ability of United States-based enterprises to compete with foreign-based enterprises. Leasing on the United States OCS is limited to residents of the United States or companies incorporated in the United States. This rule does not change that requirement, so it does not change the ability of United States firms to compete in any way.

Unfunded Mandates Reform Act (UMRA)

This rule does not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on State, local, or tribal governments. The rule describes the existing regulation in “plain language” and clarifies royalty suspension policies for OCS lease sales held after November 2000. A statement containing additional UMRA (2 U.S.C. 1531 et seq.) information is not required.

Takings Implications Assessment (Executive Order 12630)

According to Executive Order 12630, the rule does not have significant Takings Implications. A Takings Implication Assessment is not required because the rule would not take away or restrict a bidders right to acquire OCS leases.

Federalism (Executive Order 13132)

According to Executive Order 13132, this rule does not have Federalism implications. This rule does not substantially and directly affect the relationship between the Federal and State Governments. This rule affects the collection of royalty revenues and rentals from lessees in the deep water GOM, all of which are outside State jurisdiction. States have no role in this activity with or without this rule. This rule does not impose costs on States or localities. States and local governments play no part in the administration of the deep water royalty relief or rental programs.

Civil Justice Reform (Executive Order 12988)

According to Executive Order 12988, the Office of the Solicitor has determined that this rule does not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order.

Paperwork Reduction Act (PRA)

The proposed revisions to 30 CFR parts 218 and 256 do not contain any information collection subject to the PRA and do not require that a form OMB 83-I be submitted to OMB for review and approval under § 3507(d) of the PRA.

The proposed revisions to 30 CFR part 260 contain information collection subject to the PRA, and a form OMB 83-I has been submitted to OMB for review and approval under § 3507(d) of the PRA. The proposed revisions also contain references to approved information collection requirements in 30 CFR parts 203 and 256. OMB control numbers for the information collections in parts 203 and 256 are 1010-0071 and 1010-0006.

The title of the collection of information for the revised part 260 is “30 CFR 260—Outer Continental Shelf Oil and Gas Leasing” (OMB control number 1010-NEW). Respondents include approximately 130 Federal OCS oil and gas lessees. The frequency of response is on occasion. Responses to this collection of information are required to obtain or retain a benefit. MMS will protect proprietary information according to the Freedom of Information Act and 30 CFR 250.196, “Data and information to be made available to the public.”

This rulemaking imposes only one new information collection burden. Under § 260.114(c), respondents must notify MMS of their intention to begin production, and they must request confirmation of the size of the royalty suspension volume that applies to their eligible lease. We estimate the burden to be one-half hour per notification, and that we would receive five-to-six notices annually. MMS will use the information collected to avoid errors about the shares of the royalty suspension volume for a field available to individual leases on the field.

The current part 260 regulations contain a provision for a lessee or other affected lessees to request reconsideration of MMS's assignment of a lease that has a qualifying well to an existing field or designate a new field (current § 260.110(d)(2)). At the time the current regulations were drafted, appeals and reconsiderations were considered exempt under the PRA. In the proposed part 260, §§ 260.114 and 260.124 contain this same provision. However, appeals and reconsiderations are no longer considered exempt, and our submission to OMB for information collection approval also includes the estimated burden for these sections. We estimate the burden can range between 80 and 1,000 hours per request for reconsideration. That wide range reflects the fact that fields can underlie from 1 to more than 10 leases, can include from one to several dozen reservoirs, or can require simple to complex geological and geophysical interpretations. Because a favorable field assignment can save a lessee tens of millions of dollars in royalties, we may get as many simple as complex appeals. For purposes of estimating burden, we assume that we receive three or four annually, uniformly spread over the simple to complex range with an average burden of 400 hours. MMS uses the information collected to reconsider and adjust, if necessary, the initial field assignment for a lease.

We estimate the total annual reporting “hour” burden for the proposed 30 CFR part 260 regulations to be about 1,600 hours. There are no recordkeeping requirements.

As part of our continuing effort to reduce paperwork and respondent burdens, MMS invites the public and other Federal agencies to comment on any aspect of the reporting burden in part 260. You may submit your comments directly to the Office of Information and Regulatory Affairs, OMB. Send a copy of your comments to MMS. Refer to the “Addresses” section for mailing instructions. MMS will summarize written responses to this notice and address them in the final rule preamble. All comments will become a matter of public record.

The PRA provides that an agency may not conduct or sponsor and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. In order for MMS to have final regulations in effect before the final notice of the next lease sale, the comment period on this NPR is limited to 30 days. OMB may make a decision concerning the collection of information contained in these proposed regulations after. Therefore, a comment to OMB is best assured of having its full effect if OMB receives it by October 16, 2000.

1. MMS specifically solicits comments on the following questions:

(a) Is the proposed collection of information necessary for MMS to properly perform its functions, and will it be useful?

(b) Are the estimates of the burden hours of the proposed collection reasonable?

(c) Do you have any suggestions that would enhance the quality, clarity, or usefulness of the information to be collected?

(d) Is there a way to minimize the information collection burden on those who are to respond, including the use of appropriate automated electronic, mechanical, or other forms of information technology?

2. In addition, the PRA requires agencies to estimate the total annual reporting and recordkeeping “non-hour cost” burden resulting from the collection of information. We have not identified any such burdens.

National Environmental Policy Act (NEPA) of 1969

This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the NEPA is not required.

Government-to-Government Relationship With Tribes

According to the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951) and 512 DM 2, we have determined that there are no effects from this action on federally recognized Indian tribes.

Clarity of this Regulation

Executive Order 12866 requires each agency to write regulations that are easy to understand. We invite your comments about how to make this rule easier to understand, including answers to questions like the following:

(1) Are the characteristics of the alternative bidding systems clearly stated?

(2) Is the approach for granting royalty suspension to post-2000 leases clearly described?

(3) Are the requirements to be listed as a restricted joint bidder clearly stated?

(4) Does the rule contain technical language or jargon that interferes with its clarity?

(5) Does the format of the rule (grouping and ordering of sections, use of headings, etc.) increase or reduce its clarity?

(6) Would the rule be easier to understand if it were divided into more, but shorter sections?

(7) Is there anything else we can do to make the rule easier to understand?

Send a copy of any comments that concern how we could make this rule easier to understand to Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, N.W., Washington, D.C. 20240. You may also e-mail your comments to Exsec@ios.doi.gov.

List of Subjects

30 CFR Part 218

• Continental shelf
• Mineral royalties
• Public lands—Mineral resources

30 CFR Part 256

• Administrative practice and procedure
• Continental shelf
• Environmental protection
• Government contracts
• Mineral royalties
• Oil and gas exploration
• Pipelines
• Public lands—mineral resources
• Public lands—rights-of-way
• Reporting and recordkeeping requirements
• Surety bonds

30 CFR Part 260

• Continental shelf
• Mineral royalties
• Oil and gas leasing
• Reporting requirements

For the reasons stated in the preamble, the Minerals Management Service (MMS) proposes to amend 30 CFR parts 218, 256, and 260 as follows:

PART 218—COLLECTION OF ROYALTIES, RENTALS, BONUSES AND OTHER MONIES DUE THE FEDERAL GOVERNMENT

1. The authority citation for part 218 continues to read as follows:

Authority: 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C.A. 3335; 43 U.S.C. 1301 et seq., 1331 et seq., 1801 et seq.

2. In § 218.151, the section heading is revised; an introductory paragraph is added; paragraphs (a) and (b) are revised to read as set forth below; paragraphs (c) and (d) are removed; and paragraph (e) is redesignated as paragraph (c).

(b) This paragraph applies to any lease created by segregating a portion of a producing lease when there is no actual or allocated production on the segregated portion. The lessee must pay an annual rental for the segregated portion at the rate specified in the lease. The lessee must pay the rental as shown in the following table.

(c) * * *

PART 256—LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF

3. The authority citation for part 256 continues to read as follows:

Authority: 42 U.S.C. 6213 and 43 U.S.C. 1331, et seq. 4. In § 256.40, the introductory paragraph is revised to read as follows:

PART 260—OUTER CONTINENTAL SHELF OIL AND GAS LEASING

Authority: 43 U.S.C. 1331 et seq.

Subpart A—General Provisions

Subpart B—Bidding Systems

General Provisions

Subpart C—[Reserved]

Subpart D—Joint Bidding