Andrew DermanThe U.S. Outer Continental Shelf (OCS) provides data that give insights into the effect of bonuses on the dynamics of fiscal system analysis and design.
Thompson & Knight, P.C.
Daniel Johnston & Co. Inc.
Much of the focus of fiscal system/contract analysis, design, and negotiations in the upstream sector of the petroleum industry is on the division of profits such as government or state "take."
Take statistics associated with various countries' fiscal systems and contracts are important and widely used, but these statistics have weaknesses. The key weaknesses are signature bonuses and government participation (back in).
Both of these are timing issues. Thus, it is important to characterize how the government obtains its share of profits.
On the basis of typical government take calculations, the U.S. OCS terms are considered to be some of the best in the world, in the upper quintile. The terms are good but not that good.
Government take typically consists of four main elements:
- Signature bonus
- Profits-based elements (ordinary income taxes, levies, profit oil splits, special petroleum taxes, withholding taxes, etc.)
- Government participation.
Signature bonusesAbout 40% of the countries have or require signature bonuses, but often it is one among many bid parameters.
In the U.S., however, the bonus for all practical purposes is the sole determining factor. This can cause a significant difference in fiscal analysis because signature bonuses do not receive adequate characterization in typical take statistics.
For example, a $5 million signature (or signing) bonus for a given block could represent an infinite government take if no oil is found. The same could also be true of a $1 bonus.
But if a discovery is made, almost any bonus could seem trivial in the take context. For example, with a 10 million bbl field and a $15/bbl oil price, a $5 million bonus would represent about 0.33% of total revenue and would barely be noticed in a typical take calculation.
Yet the bonus is extremely important.
Bonuses paid on blocks where no discovery is made do not get collapsed into typical take statistics. In a country/region or particular play type where the success probability (chance factor) is about 20%, four out of five bonuses are not factored into the take calculations.
The wealth of public information from the U.S. OCS provides a means of quantifying the effect of bonuses in this context.
BonusesLicenses in the U.S. OCS are awarded on the basis of a bonus bid system. From inception in 1953 to 1997, 18,291 tracts (94.8 million acres) were licensed.
U.S. licenses (blocks) are small by world standards, averaging 5,200 acres. In many other parts of the world, a block can be from 250,000 to 500,000 acres, or more.
While it is not uncommon to have blocks in excess of 1 million acres in underexplored or nonexplored basins, once hydrocarbons are found, blocks tend to be smaller. A company may obtain a 5 million-acre block in Africa and a 5-acre parcel in the U.S.
In the U.S. OCS since 1953, the average bonus has been $3.2 million ($627/acre). However, the average bid in the past 10 years since 1988 has been $0.5 million ($122/acre). By international standards this is relatively large. It would equate to a $30 million bonus for a 250,000-acre block.
Cumulative U.S. government revenue from bonuses during the period 1953-1997 is $59.4 billion. This is slightly more than the government revenues from royalties.
RoyaltiesCumulative U.S. government revenues from royalties during the period 1953-1997 are $57.9 billion. The typical royalty in the OCS is one-sixth or 16.6667%. However, there are some one-eighth (12.5%) royalties for licenses in water depths greater than 400 m.
About 16% of the oil production has a one-eighth royalty and 10% of the gas fields have a one-eighth royalty. Thus, the average royalty rate during 1953-1997 is 16.01% for oil and 16.26% for gas production.
Royalty reliefIn recent years, deep water has captured the imagination of the global oil and gas industry mostly because of the geological potential. But, the deepwater frontier comes with some heavy baggage.
In addition to field size distributions, almost everything else is an order of magnitude greater in deep water compared to shelf areas, particularly drilling costs and lead times.
The Deep Water Royalty Relief Act of 1995 was enacted on Nov. 28, 1995. It provides royalty relief automatically for licenses awarded after that date. The act allows the U.S. Secretary of the Interior to offer tracts for lease with suspensions of royalties for a volume, value, or period of production.
Prior to this, the only difference between the shallow water and deepwater terms in the U.S. OCS was the royalty rate. For water depths less than 400 m, the rate was one-sixth (16.66%), and for water depths in excess of 400 m, it was one-eighth (12.5%).
This modest difference did not provide adequate incentive to encourage the desired activity level in deep water. The act provides royalty relief based on cumulative production and water depth (Table 1 [60,649 bytes]).
On June 3, 1998, the Minerals Management Service (MMS) automatically awarded deepwater royalty relief to Walter Oil & Gas Corp. for its East Breaks Block 168 field in about 202 m of water. This was the first "new lease" (issued after Nov. 28, 1995) to benefit from the act.
Royalty relief is not automatic for licenses that were awarded prior to the act, but it can be obtained if there is sufficient proof that a discovery would not be otherwise economic.
According to MMS, deepwater royalty relief has contributed to record breaking lease sales in the Central and Western Gulf of Mexico over the last 2 years (Table 2 [44,570 bytes]). All of the sales listed came after the Deepwater Royalty Relief Act.
In Sale 171, Aug. 26, 1998, in the Western Gulf, over 90% of the $553 million in high bids was offered on tracts in very deep water (800 m or greater). Sale 171 was the sixth sale in which deepwater tracts were eligible for royalty relief under the act.
Bonuses vs. royaltiesIn the U.S. OCS, annual government revenues from bonuses were typically greater than from royalties until the early/mid-1980s. Yet, by 1997 the cumulative bonuses were still greater than cumulative royalties ( Fig. 1 [90,729 bytes]).
If licensing efforts were to halt now, there would be no more bonuses from these blocks but royalty payments would continue for years. Cumulative royalties could amount to about $90-100 billion. This is about double the total bonuses. Fig. 2 [106,652 bytes] shows this. In Fig. 2, it is assumed that royalties would continue but would decline at a rate of 10%/year.
Fig. 2 also depicts cumulative royalties from a present value point of view (discounted at 10%). It is assumed that the weighted average point in time between bonus payment and the associated royalty payments (should they occur) is 8 years.
The cumulative discounted royalties are about $45 billion compared to the cumulative bonuses of $59.4 billion.
In terms of present value, bonuses out-weigh royalties 2 to 1. The reason is that there is typically a huge timing difference between the bonus payment and the associated royalty payments.
The weighted-average point in time that royalties are received, following the bonus payment from a block, can be on the order of 8-12 years or more for the shelf and much longer for deep water.
Table 3 [33,206 bytes] illustrates the sequence of events for a typical shallow water continental shelf field.
Timing differenceTypically, a lag of several years occurs between the time at which a bonus is paid for rights on a Gulf of Mexico shelf block and the time of the discovery, if there is one.
In the mid-1970s, the weighted-average time between discovery and production was 4.5 years on the shelf. This gap had closed to less than 1 year by the early 1990s for discoveries on the shelf that can easily be tied-back to existing infrastructure.
This is not the current situation in deep water. Lead times between discovery and production in the deep water range from 5 to 15 years, if the discovery is large enough. The deep water also requires larger fields to justify development.
There is a difference between technical success (finding something) and commercial success (finding something large enough to develop). This difference is much greater in deep water. Furthermore, deep water requires more time for exploration.
The most common statistics cited in fiscal system comparisons are the take statistics. The U.S. OCS is commonly described as a 50/50 split similar to that shown in Column 1 of Table 4 [82,470 bytes]. The same result would be achieved had the analysis been done using cash flow analysis, which is usually the source of these statistics.
The typical bonus paid in the U.S. OCS is insignificant when compared to the total revenues generated by a producing field. Thus, the bonuses disappear in these take statistics.
What about the blocks that received bonuses where no discovery is made?
The analysis in Table 4 assumes that the total costs associated with obtaining the revenues are 35% of gross revenues. Therefore, the total economic profits are 65% of revenues.
Government take is the percentage share of the economic profits obtained by the government through bonuses, royalties, taxes, etc.
The information from the MMS provides a means of quantifying the effect of bonuses in the OCS region. Bonuses outweigh royalties in terms of present value, and the effect is shown in Column 2 of Table 4.
From this perspective, the government take is over 70%. Much tougher than the world average from an oil company point of view.
The effect in the U.S. is more dynamic because there are no other bid parameters. Surprisingly, there are parallels between the U.S. OCS and systems where licenses are awarded on the basis of a work program bid, without bonuses, such as in the U.K.
U.K.In the U.K., competition for blocks is not based on a bonus payment but rather a work program. To capture a block, a company may well feel motivated to bid an aggressive work program.
If a particular block could be adequately tested with, for instance, two wells then a potential bidder may feel compelled to bid more than two wells to win the tender.
A recent example is the bidding battle over BP's Suilven discovery in the West of Shetland Block 204/19, June 1996.
It was believed that the discovery extended into adjacent Blocks 204/14 and 204/15 with a number of additional prospects. BP applied to the U.K. Department of Trade and Industry to nominate these blocks for licensing out of round.1
Six companies met the award criteria, but the ARCO consortium including Conoco, British-Borneo, and Ranger Oil submitted the most aggressive work program.2
Just as in a bonus bidding system where "winners curse" exists and there is always "money-left-on-the-table," work program bidding can create the same effect.
Petroleum companies are nearly unanimous in their preference of work program bidding vs. bonus bidding. However, the portion of a work program bid that exceeds what might be considered adequate to test the potential of a block has many of the same characteristics as a bonus bid.
Take statisticsMost published government take statistics are based upon the division of profits from an undiscounted (nominal) and unrisked point of view. Because of this, bonuses manage to effectively disappear.
This is one main reason why take statistics cannot be taken too seriously. They are important but not perfect.
The dynamic difference between bonuses and royalties becomes even more dramatic in the deepwater environment. Here, costs and lead times are greater. Also, the difference between technical success and commercial success is greater.
Threshold field size for development in deep water is greater relative to shallow water because of the lack of infrastructure and the additional costs.
Deepwater terms in the U.S. OCS will be rated fairly high because of royalty relief. Government take, ignoring bonuses, can be as low as 35% if the royalty holiday covers all production from a field.
When bonuses are factored into the analysis, as was done in Table 4, the government take increases substantially and can be viewed to exceed 60%.
This result is exacerbated by the fact that many companies treat seismic and other geological and geophysical costs, as well as exploration and support administration costs, in the same way as they treat bonuses.
Only those costs that are directly related to a lease financially burden the lease. Thus, the cost of a regional seismic campaign, an area-wide geological and geophysical study, or the exploration and support administrative costs often are not included in the economics related to a specific project.
This is particularly true of the Gulf of Mexico where the average block size is about 5,000 acres.
The U.S. OCS terms are regarded favorably by the petroleum industry because of the following combination of factors:
- Competitive fiscal terms compared to other countries
- Good geopotential
- Lack of ringfencing that allows unsuccessful exploration costs to be deducted outside a given license.
From a macro-view, these statistics have comparative value, but they have their weaknesses.
To the extent the weaknesses are recognized and appreciated, the statistics can be used as an effective tool for comparing and analyzing fiscal regimes.
U.S. OCS terms are good but certainly no give-away. The government is not leaving any money on the table, and for the petroleum industry there is no windfall in sight.
- "BP discloses new West of Shetland strike," OGJ, Mar. 10, 1997, p. 31.
- "ARCO wins hot West of Shetland blocks," OGJ, Dec. 15, 1997, p. 27.
- Dodson, J., and LeBlanc, L., "Vast acreage off U.S. shores await enlightened legislation," 1996 Offshore Atlas of World Oil & Gas Theatres, PennWell, Tulsa.
- Johnston, D., "Different fiscal systems complicate reserve values," OGJ, May 29, 1995, pp. 39-42.
- Johnston, D., "Global petroleum fiscal systems compared by contractor take," OGJ, Dec. 12, 1994, pp. 47-50.
- Johnston, D., International Petroleum Fiscal Systems and Production-Sharing Contracts, PennWell, Tulsa, 1994.
- Johnston, D., International Petroleum Fiscal Systems and Production Sharing Contracts-Course Workbook, 1999.
- Van Meurs, A.P., and Seck, A., "Government takes decline as nations diversify terms to attract investment," OGJ, May 26, 1997, pp. 35-40.
- Van Meurs, P., World Fiscal Systems for Gas-1997, Barrows Co., New York.
- Annual Review of Petroleum Fiscal Regimes, 1998, Petroconsultants, London.
- Mineral Revenues 1997 Report on Receipts From Federal and Indian Leases, U.S. Department of the Interior, Minerals Management Service.
Andrew Derman is a shareholder with Thompson & Knight, P.C. in Dallas. He heads the firm's International Energy Practice group. He was formerly an executive with Oryx Energy Co. where he managed several business functions. Derman currently represents host governments and large and small oil and gas companies in matters ranging from acquisitions, divestments, trades, and contract renegotiations, to legal and commercial advice, negotiations and contract drafting. Derman is author of five books and numerous articles on legal and financial issues.
Daniel Johnston is an independent consultant to the international petroleum industry. He has worked for a number of government-owned national oil companies, major oil companies, and independent companies. He has a BS in geology from Northern Arizona University and a masters in business administration from the University of Texas at Austin. Johnston is the author of three PennWell books including "International Petroleum Fiscal Systems and Production Sharing Contracts."
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