Chapter 3A Design and Rationale of the Final Rule on the Deep Water Royalty Relief Act

• Jurisdiction: United States

Oil and Gas Development on the Outer Continental Shelf
(Oct 1998)
CHAPTER 3A
Design and Rationale of the Final Rule on the Deep Water Royalty Relief Act
J. Michael Melancon
M.B. Rose
T.W. Farndon
S.J. Fraser
Minerals Management Service
New Orleans, Louisiana

This paper was prepared for presentation at the 1998 Offshore Technology Conference held in Houston, Texas, 4-7 May 1998.

This paper was selected for presentation by the OTC Program Committee following review of information contained in the abstract submitted by the authors. Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the authors. The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words, illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract

Following passage of the Deep Water Royalty Relief Act in November 1995, the Minerals Management Service (MMS) implemented its deep water royalty relief program for existing leases (any in most areas of the Gulf of Mexico that were issued before the act and are located in water deeper than 200 meters) with publication of an interim rule in May 1996. Comments subsequently received from the oil and gas industry focused on six core issues: categorical qualification, application timing, certification, complexity, treatment of historic costs, and criteria for material changes and redeterminations. The first half of this paper reviews the basic relief qualification process and summarizes the changes MMS made in the program in response to industry comments as well as the reasons for making these changes. The final rule was published in January 1998.

Inquiries and initial applications submitted under the Act identified some oversights and omissions in the evaluation and implementation procedures. These included possible changes to the field composition after an application, poor representation of the geologic data, the effect of ownership changes on sunk cost, justifying the development option chosen over alternatives, unanticipated cost arrangements and structures, wide and skewed cost distributions, contingency and excessive overhead cost factors, and evaluating fields that mix pre- and post-Act leases. These issues prompted MMS to reexamine policy on field assessment, certain costing issues, potential alternative development systems, and field configurations. The second half of this paper reviews the lessons learned so far from experience with eight implementation issues.

This paper should afford those who seek deep water royalty relief in the future a better understanding of the process. The Act directs that MMS grant royalty relief only where it is economically necessary. However, forecasting the economics of a deep water oil and gas project is complex and subject to substantial uncertainty. Among other things, current economic assessments can be overtaken by rapid technological advances, by dramatic price or cost changes, or by increased experience and understanding of deep water oil and gas development. The MMS will balance this uncertainty with industry needs because royalty relief may well be a necessary condition for development of some significantly sized deep water fields.

Introduction

In the 10 years preceding passage of the Outer Continental Shelf Deep Water Royalty Relief Act (DWRRA) in 1995, production of oil from the Gulf of Mexico Outer Continental Shelf (OCS) was remarkably steady. For the years 1985 through 1994, annual oil production in the Gulf of Mexico Federal OCS (as measured by published crude oil and condensate sales volume) varied from a low of 272 to a high of 312 million barrels. The stability of these results was somewhat surprising, given the small proportion of production that emerged from newly discovered fields in this period.

Over 90 percent of the total production for the period was from shallow water leases (i.e., those in less than 200 meters of water). Thus, based on trends existing in the early to mid1990's, a decline in Gulf of Mexico Federal OCS oil production by the turn of the century appeared inevitable. Under these circumstances, the Minerals Management Service (MMS) backed policies designed to encourage development of frontier areas of the OCS.

Nevertheless, MMS initially expressed several concerns upon reviewing early bills relating to royalty relief on deep water leases. These forerunner bills emphasized across-the-board royalty relief for existing leases based on capital recovery cost concepts. Both congressional funding rules for new programs (i.e., "Pay-as-you-go" provisions) and MMS responsibilities to ensure receipt of fair market value, mitigated against broad scale royalty relief unrelated to need. Further, because of experience with profit share leases, MMS was apprehensive about another capital recovery system that required extensive and continuing administrative and accounting burdens.

The final version of the deep water bill addressed these concerns. It authorized MMS to provide relief for existing leases only if royalties would make a difference with regards to developing or not developing a field. Also, the form of relief

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would involve only a simple suspension of royalty payments for a predetermined amount of production. With these modifications in place, the royalty incentives language was added to the Senate's Alaskan Power Administration bill. Now supported by both MMS and the Department of Energy, the bill passed both houses of Congress by about a two to one margin, and was signed as Public Law 104-58 by President Clinton on November 28, 1995.

This paper focuses on those elements of the DWRRA that relate to existing deepwater leases. Note, however, that the Act added several new responsibilities and requirements for other categories of leases as well. For example, the Secretary of the Interior's authority to reduce or eliminate royalties was explicitly extended to nonproducing lease in most areas of the Gulf of Mexico, regardless of water depth.

Also, all new deep water fields leased in the Gulf of Mexico region through the year 2000 have automatic royalty volume suspensions similar to the large minimums (from 17.5 to 87.5 million barrels of oil equivalent, depending on water depth) specified for qualified existing deep water leases. It is instructive to observe that in the 2 calender years preceding passage of the DWRRA, bidding for newly issued leases in deep water was modest at best: 78 tracts in 1993, and 71 tracts in 1994. Subsequently, bidding on deep water tracts exploded: 334 in 1995, 877 in 1996, and 1,280 in 1997. Clearly, the mandated royalty suspensions available to new fields, regardless of economic need, played an important role in this outcome.

In implementing the DWRRA, the MMS issued an interim rule in May 1996 and a final rule in January 1998. Along the way MMS conducted a 2-day public workshop attended by over 200 participants, held an industry session at offices of the American Petroleum Institute and reviewed numerous comments submitted in response to the proposed rules. In the end, the final rule consisted of the following major elements for deep water royalty relief for existing fields, some of which will be discussed later in the paper.

• Stipulated minimum royalty suspensions volumes are related to the fields upon which the leases reside, not to each individual lease on the field.

• To receive approval of relief, the MMS must be convinced by a documented, quantitative analysis both that the field is unprofitable without relief and that it can be made profitable with relief.

• Companies may avail themselves of a two-stage application process, but MMS is not bound by its findings in the first stage.

• Royalty relief, if approved, is conditional on the fulfillment of several performance conditions associated with the actual timing, cost, and type of development system, in comparison to equivalent elements presented in the application for relief.

• Royalty relief, if rejected, may be reapplied for under certain conditions involving designated changes in geologic information, resource prices, or cost.

• Special rules have been designed to handle particularly complex issues associated with evaluating applications (e.g., allocation of royalty relief among leases in a field, eligibility of cost elements, treatment of input uncertainty, quantification of financing terms, and provisions for selecting the appropriate development systems, costs, and timing scenarios).

In all of these cases, the goal was to balance the intent of the Act, fairness to individual applicants, and MMS's programmatic responsibility to serve and protect the public interest. This paper describes how MMS chose to achieve this balance. The first section reviews the basic relief determination process. The following section summarizes how MMS responded to six major issues raised in comments on the interim rule. Then a section discusses implementation problems encountered during 18 months of operation under the interim rule, and the concluding section offers some general observations on the process and MMS's experience.

Deep Water Royalty Relief Process

Leases in existence before November 1995 whose lessees desire royalty relief for a deep water Gulf of Mexico field must apply to the MMS regional office. Applicants need to demonstrate that the field actually can be produced economically with relief from Federal royalties. MMS then determines whether the field could be produced economically without relief from Federal...