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 KAZAKHSTAN International Business Magazine №3, 2003
 Production Sharing Agreements: Theory and Practical Applications
Production Sharing Agreements: Theory and Practical Applications
This article was published using materials provided by the U.S. Agency for International Development (USAID) funded Central Asia Natural Resources Management Program (NRMP). In July 2003, NRMP conducted a workshop on oil and gas investment agreements for the Ministry of energy and mineral resources and other Kazakhstan governmental representatives. A sample Production Sharing Agreement (PSA) spreadsheet model was presented, including various parameters, such as obligations of oil companies, bonus payments, royalties, and profit-oil payments. This information is especially important in view of the ongoing government efforts to draft a PSA Law.
The three predominant types of agreements between governments and oil companies used in contemporary world practice are:
• Production Sharing Agreements,
• Concession Agreements, and
• Joint-venture Agreements*.
* Joint-Venture Agreements simply provide for equity participation by the resource owner, either on a concession type of contract or (more commonly in the oil industry) in connection with Production Sharing Agreements.
All three have one thing in common - they convey authorization from a resource owner to a contractor to develop and produce his resource for a fee.
Concession Agreements have been around for as long as there has been oil production. The Agreement provides a concession of exploration, development, and production of rights to an investor who in turn would reimburse the resource owner with a stated percentage of the produced resources.
One of the defining characteristic of Concession Agreements used to be that Concessions were thought to confer title of the oil in the ground to the oil company, thus causing debates regarding ownership of the oil. At the present moment, modern legislation of many countries include provisions that clearly state that the Government is the resource owner. Private subsoil property rights are recognized only in the USA and South Africa.
The essential difference between Concession Agreements and Production Sharing Agreements is that the latter provide for payment to the resource owner after the recovery of production costs. The payment mechanisms to the resource owner are the sole differences between the three types of agreements.
By permitting the investor to recover his expenses first, Production Sharing Agreements have become popular with the high-risk oil industry, since they carry lowest risks for the investor. As a general rule, Production Sharing Agreements are on the progressive side of the risk continuum, as opposed to the generally regressive Concession Agreements.
Attraction of investment into oil and gas sector
In the final analysis, capturing the economic rent is what oil negotiations and petroleum agreements are all about. “Economic rent” is defined as gross revenue minus total cost, including exploration, development and operating cost, and competitive profit.
Oil companies primarily consider competitive profit, which must include all types of risks, including the very significant geological risks that characterize the oil industry. Considering the fact that about 9 out of 10 exploratory ventures fail, those failures need to be covered through profits from the successful exploratory and production projects. Accordingly, to find one commercial well, ten exploratory wells have to be drilled on average. If true, the risk compensation for exploratory expenses has to be ten times the amount spent on any given wildcat well. Thus, if drilling a wildcat costs $5m, the eventual discovery well must yield $50m to compensate for 9 failures, in current (discounted) dollars. This does not include risk-compensated rewards for appraisal, development, and production operation costs.
Oil company profits depend essentially on either finding and successfully producing a commercial field capable of generating the necessary cash flows, or the fiscal structure designed to permit significant profits to oil companies. Only large multinational oil companies or consortiums can participate in exploration and development of oil fields in high risk markets, including offshore operations.
Geological risk is only one area where Kazakhstan must compete with other countries for oil investments. There are other risks such as fiscal arrangements, transportation costs to markets, the perception of the investment community regarding the host Government’s political stability, and its integrity in honoring the sanctity of contracts, and others.
One risk that has received increasing attention in the past few years is Government corruption. A German non-profit organization, Transparency International ( publishes a so-called “Corruption Index” that currently rates 102 countries as to their corruptive practices (Finland was at the top, i.e., the least corrupted country, and Bangladesh at the bottom in 2002).
An oil company’s best opportunity is provided by the producing country that, all other things equal, offers the highest prospective internal rate of return. For an oil-producing country, some of the prospective parameters are beyond control: nearness to markets, general prospectivity of the productive region, and others. However, some parameters are under the oil-producing country’s control, notably its fiscal terms.
A country without natural advantages should adjust the parameters it can control, i.e., progressive fiscal structures and open, transparent, efficient and, hopefully, one-variable competitive bidding procedures in order to establish competitive investment conditions
While the US fiscal regime in awarding government owned resources to a contractor is considered regressive, the bidding procedures used by the U.S. Government are very efficient. These are true auctions with essentially no negotiations. All the bidding parameters are known in advance, including a fixed royalty rate, and there is only one bidding variable, the lease bonus. This enables the Government to open all sealed bids at the same time in a public meeting and to announce a winner (or reject all bids as too low) without further proceedings.
If contracts include bonus provisions, it is necessary to consider the issue of bonus recovery upon beginning of production. Generally, bonuses included in the PSAs are not subject to recovery.
Because lease bonuses, like signature bonuses, are very speculative in nature in the sense that not much is known about the block to be awarded, they are among the riskiest means of collecting rent, from the oil company’s point of view. During the Arab oil embargo, when oil prices shot up, it was widely speculated that world oil prices would rise to $100 per barrel (in 1974-dollars). This drove lease bonuses to their all-time highs up to $100m for a standard block of 23 square kilometers compared to the best offers amounting to $10m in 2002. When crude-oil prices failed to go up further and even dropped as low as $10 four years later, most of the speculative lease bonuses turned into losing investments. Billions of dollars were lost on these speculative bids born from a panic mentality.
Compared to other means of rent collection, bonus collection discourages investments. Oil companies would rather have rents collected as production occurs than in the beginning of the contract, where there is no assurance of finding oil.
Royalties are said to be regressive not only due to their amounts but due to the high risk associated with this type of rent collection. Moreover, there exists a significant sensitivity of Internal Rate of Return Calculations (IRR) to royalty changes. When a field matures, its production declines and maintenance costs rise, driving up per-barrel production costs. Fields are abandoned prematurely and marginal (i.e., high-cost fields) will not be developed under highly regressive fiscal regimes. The U.S. Government has responded to this dilemma by reducing royalties for high-cost (such as deep-water) off-shore wells.
Capital Recovery
Set-Aside clauses for capital recovery are generally an integral part of PSAs. The question is what portion and what type of capital investment is subject to the Set-Aside, what level of Set-Aside, and relative to what variable (as a percentage of gross revenue, net revenue, profit oil, etc.). Set-Asides provisions can run all the way from zero to 100%.
Many times, especially on Production Sharing Agreements, deferred capital investments are subject to a recovery regime that runs in parallel to the usual depreciation regime. When present, this recovery mechanism generally applies to exploratory expenses, although it might conceivably replace the existing depreciation regime altogether.
The primary concept of a separate Capital Set-Aside system is to allow the investing oil company to recover its high-risk portion of capital investment or particularly expensive later investments (off-shore platforms, for example) early in the life of an oil field.
While used on occasion, a 100% Set-Aside implies the immediate and total recovery of all investments (expensing of capital investments), which may wipe out early-year profits. In the absence of royalties, this would deprive the Government of any and all income until all capital investments have been recovered. Not surprisingly, that the IRR is positively correlated to the type and amount of the Capital Set-Aside.
Given the very high early cash flow typical for oil production, capital recovery (unlike the IRR) is not particularly sensitive to a wide range of Set-Asides. Commonly, recovery is achieved within four years at Capital Set-Asides ranging from 50% to 100%.
During negotiations, the authorized state body and representatives of oil company review a list of expenses subject to recovery. This list is then attached as a separate appendix to the contract.
A model PSA should account for all factors that can potentially effect the cash flow. The theoretical economic PSA model prepared by NRMP representatives provides for a clear understanding of changes in government and oil company respective takes when major contract parameters, including royalty, corporate income taxes rates, production shares and others, change. The model clearly illustrates that the state’s share of the oil operations can be maximized by means of simple manipulations involving changes of corporate income tax rates and changing respective takes. In such case, there is no need for creation of complicated tax schemes. A clear and transparent model PSA allows for effective state control over PSA negotiations and realization.
Furthermore, NRMP representatives used theoretical examples to show the disadvantages of PSA. For instance, the government’s share during the initial period of oil production is lower in PSAs compared to Concession Agreements.
Protection of state interests in PSAs using preset “trigger” levels can also include provisions that allow for changes in the profit sharing only if certain specified “trigger” events take place as the project develops.
Crude oil prices profoundly affect both the exporting government and the oil company in any kind of petroleum agreements, including PSAs. A truly flexible rent extraction regime would tend to protect the Government’s interest in collecting its rent on the up-side of crude oil prices, while it would protect the oil company’s position and, therefore, work in its favor on the down-side.
Various PSA provisions provide for different ways of protection from outside factors. One of the mechanisms used is a so-called R-Factor. This method provides flexibility in case of upwards and downwards changes in crude oil prices. The Ecuador Risk Service Contract, for example, looks at the prime rate, the variation in crude oil prices, and five levels of production rates in calculating the service fee.
Another type of contract, using Rate of Return (ROR), will look at the Company’s IRR and apply a surtax (for example a 50% excess profits tax) as soon as the Company’s IRR has reached a stipulated trigger level. That arrangement meets essentially all contingencies, but it still permits IRR levels to rise substantially above the trigger level.
To deal with the unusually unexpected large field, either production rates or cumulative production can be used as a trigger for adjustments. It is not uncommon to have a series of triggers that would, for example, apply excess profits taxes on production that exceeds certain rates or on volumes that exceed certain levels, and to have still higher excess profits on a second, and third, etc. level of rates or volumes. But again, if oil prices rise, this escalation clause does nothing for the Government. Moreover, the volume-triggered excess profit tax tends to kill fields prematurely, while the production-rate trigger does not.
All of the Production Sharing Agreements have one thing in common: they have inflexible provisions for sharing the rent between the Government and the oil companies. Once the negotiations are finished and the Agreements are signed, there are no provisions for adjustments: neither up for unexpected windfalls such as the discovery of a multi-billion-barrel oil field, or an unexpected rise in crude-oil prices, nor down for smaller fields or declines in oil prices.
PSAs used at the present moment have built-in escalation clauses allowing for changing agreement conditions. However, agreements can be changed only to deal with obvious difficulties or with potential changes from the expected results. Flexible petroleum contracts are today gaining popularity worldwide.
Should there be stabilization clauses included in the contract and how should they be defined? If so, what is to be stabilized: Total Oil Company Take, IRR, or Current Annual Income?
The complete version of the training materials is available upon request from NRMP.

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