An economic study indicates that deepwater Gulf of Mexico properties have not been a windfall for the oil and gas industry, even with the Deep Water Royalty Relief Program.
Although the program has spurred a leasing boom in deepwater Gulf of Mexico (OGJ, May 8, 2000, p. 24), by our calculations, the industry is yet to experience a calendar year of positive after-tax cash flow.
One benefit of the royalty relief program has been that it has diverted billions of dollars, which otherwise might have gone overseas, to bonus payments, lease rentals, seismic, geological studies, drilling, construction, and operations in the Gulf of Mexico, thus creating thousands of US jobs.
But the expiration of the automatic Deep Water Royalty Relief Program on Nov. 28, 2000, unless extended, may well end the leasing boom in the deepwater Gulf of Mexico that has surpassed the expectations of government and industry.
The leasing and exploration of tracts in water depths greater than 1,000 ft began in 1974. From 1974 through 1999, industry has invested more than $35 billion for leasing, evaluating, exploring, developing, and operating in deepwater. Of this $35 billion, more than $15 billion are yet to be recovered.
Twenty-six years is a long time to wait for positive cash flow, with payout projected to be at least 3 years away.
With robust prices, 2000 might well be the first year that the industry's deepwater exploitation realizes a positive annual after-tax cash flow.
Royalty relief
The automatic royalty relief for deepwater may expire, although it is believed that the US Minerals Management Service (MMS) plans to continue the discretionary royalty relief portion of the program.
Under the discretionary program, MMS has authority to grant royalty relief on an ad hoc basis when it concludes that royalty relief is economically necessary for the development or continuation of a producing property.
The problem with such a discretionary program is that no company can incorporate the suspension of royalties into its preleasing economics. As a consequence, the discretionary portion does nothing to stimulate leasing and causes companies to hesitate in entering or continuing deepwater operations.
If oil and gas are found in subcommercial quantities, the discretionary portion of the program might allow the project to go forward, but it does nothing to stimulate exploration.
Under the automatic suspension of royalties, the program suspends royalties for any new leases in water deeper than 200 m issued within 5 years of Nov. 28, 1995. This automatic suspension of predefined royalty levels, based on water depth, allows companies to incorporate royalty relief into their exploration economics before leasing or exploration drilling.
Deepwater production
According to the US Department of Interior, Gulf of Mexico oil production could increase to 1.8 million b/d in 2001, nearly double the oil production from the Gulf of Mexico in 1995, when the royalty relief act was enacted.
Deepwater production facilities are expensive and the economics of spending more than $1 billion on a single facility challenge even the largest of companies. For example, ExxonMobil Inc.'s Hoover/Diana platform, in 4,800-ft water, cost $1.1 billion, and Shell Oil Co.'s Ursa platform came in at $1.45 billion.1 Only the largest oil companies have the financial ability to handle the requisite capital programs to chase and develop deepwater reserves.
The question facing the Department of the Interior is how to make the Gulf of Mexico competitive with other provinces around the world?
Sizable expenditures are being spent for finding oil and gas in deepwater basins around the world. ExxonMobil's senior vice-president for exploration, Harry Longwell, observed that deep water is the hottest exploration play in the world right now. Shell and ExxonMobil expect to spend about $1 billion/year each on deepwater projects.
To date, about 40 billion bbl of oil have been discovered in the world's deepwater areas. Both ExxonMobil and Shell suggest that this amount could well grow to 100 billion bbl or about 10% of current estimated recoverable oil reserves.1
The current Gulf of Mexico developments are primarily standalone projects. But to allow for the full development of its deepwater areas, it is critical that a sufficient infrastructure be installed to allow for exploration and development of smaller fields and satellite accumulations.
The policy implications for continuing automatic royalty relief relate directly to whether the economics associated with field size expected today in deepwater Gulf of Mexico justify commercial production.
Our analysis reveals that without automatic royalty relief many deepwater Gulf of Mexico projects simply will not be drilled or, for that matter, developed. And the choking off of such exploration and related development will limit the installation of an infrastructure, thus further retarding development.
This analysis of the deepwater Gulf of Mexico is from the viewpoint of an exploration manager making recommendations as to where to allocate limited capital, or a senior executive staff or board of directors in choosing where to invest.
Deepwater prospects
Norland Consultants, in its latest deepwater research report, estimates that some $76 billion could be spent in deep water over the next 5 years, mostly off Brazil, West Africa, and Gulf of Mexico. West Africa has some of the best prospects and will capture the lion's share of the capital investment.2
Fig. 1a illustrates that average field size in deepwater Gulf of Mexico is substantially smaller than off Nigeria, Angola, or Brazil. Besides field size, it should be noted that deepwater Gulf of Mexico is a more mature play. The play began in the 1970s, became popular in the 1980s, and boomed in the 1990s.
Deepwater plays in Brazil and West Africa are more recent, while deepwater activity in the Gulf of Mexico has entered mid-life (Fig. 1b).
As expected, average field size decreases as a play matures. Although large fields will likely still be found in deepwater Gulf of Mexico, these large discoveries will increasingly become rare.
When comparing anticipated exploratory deepwater results among competing regions, the relative impact of the country's fiscal regime is extremely important.
A recent Wood Mackenzie Consultants, Edinburgh, study indicates that while the expected economic benefit per barrel of reserves discovered in the deepwater Gulf of Mexico is greater than Angola, Brazil, and Nigeria, the significantly greater reserves per discovery in these three areas yields far better economics (Fig. 1c).
The policy question for the MMS and the business decision for the oil industry is whether deepwater Gulf of Mexico economics justify continued enthusiasm in light of the current expected field size and, if not, how important is royalty relief?
Nearly 1,200 deepwater leases will be expiring between 2000 and 2006 (Fig. 2a). The discussion over extending royalty relief, to a large extent, involves leases that were recently held by industry and that did not prove successful or failed to be highgraded and drilled.
From Fig. 2a, one should note that deepwater Gulf of Mexico has reached mid-life. The leases that will come up for bid in the near term will consist of acreage that industry has either reviewed and decided not to acquire, been acquired, highgraded and drilled, or been acquired, highgraded, and not drilled.
Table 1 lists the number of leases expiring and ultimately available for re-leasing. These number about 1,326 through 2006. It is interesting to note that the US collected $660.6 million from bonus payments from leases that contained royalty relief and will be relinquished by 2006 after being evaluated and not drilled or drilled and released.
A substantial number of the leases have and, with some extrapolation, will be drilled by the time these leases expire. Many will have multiple wells drilled. Table 1 illustrates that the deepwater Gulf of Mexico is not virgin acreage but rather an area that has received significant evaluation, highgrading, and drilling.
To raise the price of "used" acreage by eliminating automatic royalty relief, in the face of increasing demand and decreasing US production, does not necessarily fit with perpetuating a high level of activity and investment in the competitive environment.
In a competitive environment, the US ignores competing oil and gas environments, at its peril.
The US has been successful in attracting a number of the foreign super-majors into the deepwater Gulf of Mexico and, more recently, has attracted several large foreign independents. Pierre Jungels, the chief executive officer of Enterprise Oil plc, the UK's largest independent, has invested substantial sums exploring and now developing deepwater Gulf of Mexico projects.
Enterprise Oil appreciated the competitive environment of the Gulf of Mexico created, in part, as a consequence of royalty relief. In considering the benefits of automatic royalty relief, Jungels says the UK, Norway, and Ireland have removed royalty from their offshore tax system on the ground that it is a regressive tax that is detrimental to development.
"Clearly the competition for the US is just across the Atlantic."
Major companies
It is interesting to observe that the super majors have been in the deepwater Gulf of Mexico for 2 decades. As with many new plays, the early entrants captured some of the best acreage. BP, Shell, and ExxonMobil hold a commanding acreage position and the lion's share of the deepwater production in the Gulf of Mexico (Fig. 2b).
Fig. 2b depicts three major events:
- Early entrance into deepwater by the super-majors.
- Substantially super-major leasing after the introduction of the royalty relief program.
- Curtailment of leasing by the super-majors in recent years.
A few large companies are dominating worldwide deep water. Although 29 operators are currently considering deepwater developments, only seven companies hold 77% of these deepwater developments, as follows: BP, Shell, ExxonMobil, TotalElfFina, Chevron Corp., Texaco Inc., and Petrobras.2
As a policy issue, is the US effectively reserving the deepwater Gulf of Mexico for the largest companies or will the US apply the business acumen to allow fields that are below the threshold levels of the largest companies to be commercially viable and developed by the independent oil and gas sector?
Exploration hot spots
The recent deepwater Gulf of Mexico lease sales have witnessed a falloff in the number of leases acquired by the super majors, which may portend a de-emphasis of the deepwater Gulf of Mexico by these companies.
It is interesting to note that the Gulf of Mexico did not make the top ten list of exploration hot spots in the most recent Robertson Research International survey.
Robertson Research, which asks international oil companies to rate their level of interest in new global exploration and production ventures in 146 countries, found the countries having the most interest were Libya, Iran, UK, Australia, Algeria, Iraq, Indonesia, Angola, Brazil, and Egypt (OGJ, Vol. 98, No. 24, June 12, 2000, p. 8).
Gulf of Mexico economics
We recently completed an economic evaluation, focused on water depths in excess of 1,000 ft, that attempted to capture both exploration and production expenditures as well as production and revenues on a historic and projected basis.
Public record data, published industry estimates, press release data as well as selected commercial services were utilized to capture the economic results for all defined developments as of Jan. 1, 2000. Future oil and gas prices were derived from prices implicit in the Nymex forward curves.
The analysis shows that deepwater Gulf of Mexico has by no means been a windfall to the industry. As previously mentioned, more than $15 billion in expenditures have yet to be recovered and 2000 might well be the first year that the industry realizes positive annual after-tax cash flow (Fig. 3a).
Projected after-tax return, including all reasonably defined developments, is only 9.4% on a money-of-the-day basis. The real return, using the annual GNP deflator, is only 7.2% after tax.
Industry expectations are clearly based upon returns well in excess of historic results and incremental returns on successful projects can and will be comfortably in excess of 30%.
Through the execution of relative competitive advantage, Shell, BP, and ExxonMobil have dominated the deepwater Gulf of Mexico, participating at least in part in nearly every development in excess of 150 million boe. Their domination in early leasehold positions has been well documented.
Excluding these three companies, the aggregate returns in the deep water for the balance of the industry are 4.8% nominal and 3.0% real. Companies earning no more than 5% returns did not overlook the added incentive implicit in deepwater royalty relief.
The aggregate returns of the largest three, which used to be five, are slightly higher than the industry total, but still less than 10% nominal. Although the poor compound returns are primarily attributed to decades of negative cash flows, projected peak production at currently robust oil and gas price assumptions over the next decade exceed all but the most optimistic of forecasts from previous years.
A similar analysis made 2 years ago would not have anticipated any aggregate positive return for the industry and, if oil and gas prices fall, our rate-of-return analysis will look optimistic.
Perhaps the most significant impact of royalty relief is that it allows a greater number of reserve accumulations to become economically attractive. With a relatively mature play, the expected average field size distribution continues to diminish. Without presumptive royalty relief, the expectations of finding economic accumulations diminish even faster.
Fig. 3b shows the impact of royalty relief on field size. In 1,200-m water, the minimum economic field size to generate a 15% before-tax return decreases from 92 million to 79 million boe. For most industry participants, presumptive returns in excess of 15% before-tax are required before capital will be allocated to a project or program.
The MMS currently projects that 10.2 billion boe remain to be discovered in field sizes of less than 100 million boe in water depths between 800 and 3,000 m. If the impact of royalty relief results in a 20% reduction in minimum economic field size, an incremental 1.6 billion boe could potentially be developed that otherwise would go unexploited.
The nature of the existing royalty relief structure ensures that, in relative terms, it mostly impacts marginal field developments. Encouraging additional infrastructure makes even more satellite accumulations economic.
A 50% increase in the number of projected developments of 15-50 million boe accumulations would add an additional 1.3 billion boe that otherwise would not be developed according to MMS potential reserve estimates. Consequently, nearly 3.0 billion boe might well remain unexploited if the royalty relief program is discontinued.
The program provides a valuable incentive without creating an economic windfall. As shown in Fig. 3b, the pretax rate of return for a 100-million-bbl field increases to 9.8 % from 5.2%, while for a 140 million-boe field, the rate of return increases to 18.5% from 14.5%.
When evaluating the prospective economics of a potential distribution in anticipated prospect reserves, returns of 9.8-18.5% with royalty relief compared to 5.2-14.5% without it may be the difference between funding a prospect and moving on to other prospects outside of the US.
Those opposed to the automatic royalty relief portion of the program might argue that as long as the MMS is authorized to grant royalty relief on a discretionary basis, marginal fields can be granted royalty relief on an ad hoc basis and made commercial.
No doubt some fields will be handled in that way, but the incentive to explore will be substantially reduced without the automatic provision because no company will incorporate discretionary, ad hoc royalty relief into exploration economics.
If exploration is less, less infrastructure will be installed, thus preventing smaller fields and satellites to be drilled.
The Independent Petroleum Association of America (IPAA) has stated that independents hold 42% of the active leases in the deepwater Gulf of Mexico and it is becoming increasingly worried about the extension of the royalty relief program.
Earl Sims, vice-chairman of IPPA's offshore committee, says without the continuation of deepwater royalty relief, "no doubt there will be less activity. It represents a significant incentive."3
Ben Dillion, IPAA vice-president of public resources says "Without incentives, marginal fields in 200-800 m of water, which is the traditional stomping grounds for independents, likely will fail to reach the economic threshold for development."3
Dillion predicted that independents likely will be discouraged from evaluating their leases if adequate incentives are not adopted. The IPAA is concerned that without royalty relief, leasing activity will fall and the industry will find it difficult to meet the projected 29 tcf of natural gas demand forecasted in the US by 2010.3
Failure to extend the program will certainly result in fewer leases, fewer exploration wells, and less oil and gas discovered.
The US Energy Information Administration (EIA) in an extensive analysis performed on the economics of deepwater royalty relief, concluded that "the program may be strongest in reducing the likelihood of losses as an important element in promoting additional investments in deepwater projects" (OGJ, Vol. 98, No. 24, June 12, 2000, p. 7).
The EIA found that the "royalty relief program increases the expected value return from the deepwater projects. However, it also enhances the perceived returns in a fundamental way that is more readily apparent when such a project is assessed under conditions of uncertainty."
The continuation of the automatic royalty relief is unlikely to have a cost. For example, incremental bonuses have, to date, far outweighed the financial impact of royalty suspension.
If history is a guide, similar bonus differentials can be expected if the automatic royalty suspensions are continued.
Moreover, projects benefiting from royalty relief will more quickly become taxable and give back to the US Treasury Department some of the benefits bestowed by the royalty relief program.
Beyond the financial benefits of increased bonus and taxes, it can be expected that there will be an increase in rental payments, to say nothing of the associated, likely benefits of job creation and more oil and gas production.
References
- Wall Street Journal, July 3, 2000.
- Hart's E&P, Deep Water Technology Supplement, July 2000, p. 8.
- Platt's Oilgram News, May 4, 2000, p. 4.
The authors
Andrew B. Derman is a senior partner with Thompson & Knight LLP in Dallas. He heads the firm?s Inter- national Energy Practice group. He was formerly an executive with Oryx Energy Co. Derman holds a BA from New York University and a JD from Temple University Law School and is board certified in Texas in the field of oil, gas, and mineral law.
Gregg Jacobson is vice-president of Randall & Dewey Inc., a Houston-based transaction advisory firm. He heads the firm?s petroleum advisory group that provides strategic and technical consulting to the upstream oil and gas industry. He previously was the director of business development and planning for Oryx Energy Co. Jacobson has a BS in petroleum engineering from Texas A&M University.