Energy Policy 39 (2011) 57–65

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Energy Policy

0301-42

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Economics of oil regulation and the Brazilian reform: Some issues

Adriana Hernandez-Perez n

Center for Economics and Oil Studies, IBRE/Fundac- ~ao Getulio Vargas, Brazil

a r t i c l e i n f o

Article history:

Received 8 February 2010

Accepted 2 September 2010Available online 12 October 2010

Keywords:

Regulation and development

Oil industry

Contract theory

Brazil

15/$ - see front matter & 2010 Elsevier Ltd. A

016/j.enpol.2010.09.004

+5521 37996918; fax +5521 37996867.

ail address: adriana.perez@fgv.br

a b s t r a c t

This paper reviews the economic fundamentals for regulation in the oil industry, with a focus on the

current regulatory proposal for the Brazilian oil industry. The observed exploration and production

(E&P) contracts foresee much of the characteristics of the optimal contract, with a remuneration

structure that combines upfront with future payments to mitigate uncertainty and incentivize

exploratory efforts. In Brazil, despite slow market deconcentration since 1997’s liberalization, the

current oil regulation is in general consistent with an optimal regulatory response. From an economic

standpoint, the 2009’s new regulatory proposal prompted by the major oil discoveries offshore in Brazil

reduces the power of incentive schemes with respect to exploratory and cost-reducing efforts while the

changes in the net risk of the E&P offshore activities are not so clear.

& 2010 Elsevier Ltd. All rights reserved.

1 When a well is drilled it reduces the field pressure in its surrounding within

1. Introduction

The new oil discoveries in the offshore Presalt layer of theBrazilian Santos and Campos sedimentary basins, estimated to beup to 15 billion barrels equivalent (boe), in addition to the current12 billion reserves, prompted a nationwide discussion over thedesign of the regulatory framework that would generate the bestsocio-economic value to the new reserves. On 31 August 2009, thefederal government proposed to the Brazilian Congress a new lawfor the exploration and production (E&P) of the oil industry for asubarea of these basins, the so-called Presalt area and other areasto be considered strategic.

The purpose of this paper is to review the economicfundamentals of the oil industry regulation with an applicationto the impact of these discoveries on the optimal regulatorydesign and how the new regulatory proposal under discussion inthe Brazilian Congress fine tunes with the theoretical prescription.

Despite the positive performance of Brazil’s oil industry notedsince 1997, the effectiveness of the Oil Act is constrained byconditions that are unattractive in terms of investment (and theentry of new players), even within a context of extremely positiveprospects for supplies, such as slow market deconcentration, andblocked access to infrastructure installed in mature areas..

We find that there is no economic justification for changing thecurrent regulation. However, the perceived changes in risks of theE&P activities in Brazil – commercial and geological – may call foradjustments in the remuneration instruments in place towardsmore or less cost reimbursement by the State. Further effortshould be devoted to strengthening the effectiveness of regula-tions in this industry, rectifying the flaws that hamper its

ll rights reserved.

efficiency and thus reduce the amount of wealth generated byE&P activities in Brazil.

This paper is organized as follows: the next section discussesthe relevant market failure in the oil industry that justifies itsregulation; Section 3 presents the Brazilian oil industry’s devel-opments and current discussion over regulatory reform; Section 4presents a model with the main features of the economicenvironment pertaining to the E&P activity, with respect to entryand reimbursement rules; Section 5 discusses the internationalexperience; and Section 6 discusses the Brazilian regulation andreform in light of the economic analysis and Section 7 concludes.

2. The relevant market failure

The economic regulation of any industry is justified by theexistence of a market failure that reduces the value creation insociety to an extent that the regulatory costs of these rectifica-tions are not socially prohibitive. In the oil industry, the relevantmarket failure is due to excessive competition for commonresources, known in economic literature as the common pool

problem. Due to the logic of oil migration and the multiplicity ofagents accessing a single reservoir, there are strong incentivesamong companies that independently exploit the commonresource to overdrill wells and produce excessively, resulting ina rapid drop in the reservoir pressure and curtailing its (primary)oil recovery capacity.1 Without the natural force of the reservoir

the field, resulting in the natural (primary) flow of oil to the surface. New wells

drilled results in pressure differences that attract the oil towards the low pressure

area, which steps up corporate output over the short term, while reducing total oil

field recovery capacities.

2 For a discussion on the informational aspects of oil auctions, see Crampton

(2006).

A. Hernandez-Perez / Energy Policy 39 (2011) 57–6558

pressure to extract the oil, costly energy is required for itsremoval, which is known as secondary or tertiary recovery,depending on the technology adopted.

In order to mitigate the perverse effects of excessive competition,countries around the world allocate regional (or national) mono-polies, known as E&P blocks, to single companies (or consortia) sothat the E&P activities are carried out in a coordinated fashion andthe common pool problem is minimized. However, assigningmonopolies to oil companies does not imply that companies willmake the necessary efforts to find oil in a given area: companies canuse the area as a financial option, to be only exercised if oil prices aresufficiently high. In such case, the allocation of oil exploratory rightsmust be combined with the proper contractual incentives to aligncompany’s objectives to the State’s objectives.

By assigning E&P blocks to companies, the government conveys aprocurement to the companies to perform exploratory investigation,that is, a procurement contract for finding oil in the area, and, ifsuccessful, the development of an oil field. Here lies anotherimportant market failure in the oil industry: the State cannotobserve the oil companies’ actions with respect to exploratoryefforts to find oil and/or cost reducing efforts. If companies havedifferent objectives than the government’s, this asymmetry ofinformation between the parties of the E&P regulatory contractcan lead to efficiency losses and lower revenue to be accrued to theState.

One important aspect of the oil industry is the inherent risk of itsactivity. There are three sources of risk in the industry: geological,commercial and political. We shall discuss them in what follows.

The investment on exploratory efforts does not imply that thecompany will find oil, though these variables are positivelycorrelated. A company may spend years investigating thegeological features of an area without finding any commerciallyviable oil field. This uncertainty with regard to finding oil, referredin the industry as geological risk, implies that the company knowsmuch less about the area before its acquisition than after.

The commercial risk can be of two kinds: one related to oilprice volatility, which affects oil companies’ plans to the extentthat industry’s investment cycle lasts 20–25 years, and cost-related risk. Recently, a diversity of elements has been added tothe latter, as the cheap oil becomes increasingly rare andindustries are pushed to frontier areas, as in the case of theBrazilian Presalt. Environmental concerns contribute to anincrease in the industry’s commercial risk as new regulatoryrequirements are imposed on the activity, such as decommission-ing programs for recycling segments of oil field installations, andthe capture and safe storage of CO2 emissions from oil exploita-tion. Uncertainty with respect to the actual costs of an oil fielddevelopment may favor contracts that dilute the risk between theState and oil companies. However, as rules and costs prospectsbecome more accurate, it will be possible for the State to assumeless risk from the activity, concentrating its proceeds on fixedtransfers or gross revenues based transfers.

Finally, there is the political risk (or State opportunism). Sincecorporate exploration and development investments are ‘sunk’ inthe country, the company loses its bargaining power and may beheld hostage by State opportunism from the host country. It isnoted that this shift in the negotiating relationship between theparties occurs at the beginning of 20–25 years contract. This meansthat, unless the operating costs or international oil prices varysignificantly, this is one of the main sources of corporateuncertainty regarding the safety of investments, ranking close togeological uncertainty. The track-record of breaching agree-ments through tax hikes or oil industry nationalizations helpsexplain the number of E&P contracts whose clauses would allowthe rapid recovery of costs sunk in the activities at the start of theagreement.

In summary, provided the State wants to align contractedcompanies’ objectives to society’s, the contractual clauses shouldbe such that this objective is attained given the geologic character-istics of the area, the industry’s technological developments and thecountry’s political history with respect to property rights.

3. Recent developments in Brazilian oil industry

In Brazil, until 1997, when the Oil Act (Law no. 9478) waspromulgated, the common pool problem was ‘solved’ through theassignment of a national monopoly to Petrobras, which held theexclusivity over exploratory and production activities. The society’ssolution to the incentive problems with regard to exploratoryinvestigation, cost minimization and production control was givingthese exclusive control rights to a fully owned state company,Petrobras. From 1997 onwards, the national monopoly solutionshifted to the auctioning of local monopolies, the so-called E&Pblocks, to interested oil companies, and the society’s control overthe oil industry activities changed from State direct control to Stateregulation. Furthermore, Petrobras was partially privatized, withfederal government keeping its control rights.

The current ANP auction design allocates oil tracks to thecompanies that propose the best score out of three dimensions ina multi-unit first price sealed bid auction, which consists of (1) anupfront payment of a signature bonus, (2) local content sharesover total exploratory and development expenditures, and (3)exploratory and development efforts.

Besides the auction’s commitments, the bidder pays a royaltyrate on the revenues it earns from hydrocarbons sale production,which varies from 5% to 10% plus, for very productive fields, ashare of profits after revenue taxes and royalties, known as‘Special Participation’.

As determined by the Decree 2.705/98 of 2008, the SpecialParticipation is progressive according to the field production level, butit taxes profits instead of gross revenue, as is the case of royalties

payments, reaching no more than 40% over profits. The use of aproduction trigger is specific to the Decree. The 1997 Oil Act allowsthe Special Participation to be triggered for highly profitable fields andnot only highly productive ones. Finally, the Special Participation ishigher for production on onshore fields than on offshore ones, as canbe seen from Fig. 1, and also varies according to the production year,increasing with it (Fig. 1, we only show taxation after the 3rd year).

Along the 10 auctions that took place yearly from 1999 to2008, Petrobras won most of the blocks it has bidded for (220 outof 244 offshore tracks and 192 out of 231 onshore tracks), whichgives it dominant status on the Brazilian exploratory activities.Nevertheless, it holds several partnerships with other oilcompanies (small and large ones), with whom it alternates theblocks’ direct operatorship over E&P activities. Petrobras’s out-standing results from the bidding rounds may be explained by theuncertain nature of the exploratory activity in the industry and itsstrategic implication over the rival companies’ behavior, whichboots its competitive advantage during these auctions.2

Given the industry’s long investment cycle, the arrival of newcompanies in the national market has not changed the marketstructure in the oil production activity. Very few blocks were fullydeveloped into active productive oil fields. Therefore, Petrobrasalso remains the dominant producer, with participation in morethan 98% of Brazilian’s hydrocarbon production (oil and gas).

Fig. 2 shows that most of the current oil production isconcentrated on offshore fields (left vertical axis in thousands

0%5%

10%15%20%25%30%35%40%

0 5000 10000 15000

Thousands m3 oil equivalent

Onshore Offshore, less than 400m depth

Offshore, more than 400m depth

Fig. 1. Special participation effective tax after the 3rd year field production, per location.

Fig. 2. Brazilian oil production and proven reserves 1953–2008.

A. Hernandez-Perez / Energy Policy 39 (2011) 57–65 59

barrels per day) vis-�a-vis its oil reserves (right axis in millions ofbarrels). It illustrates the result of its long lasting strategy towardsexploring the outer continental shelf. Onshore production hasbeen stable for 20 years already.

The unparalleled discoveries of oil resources holding between5 and 8 billion bbl in the Tupi area, and 3–4 billion bbl at Iara, inthe off-shore Presalt layer of the Santos Basin motivated thediscussions for a new regulatory framework. The main motivationof the regulatory change was the perceived reduction in theexploratory risk of E&P activity for that area and the increase ofthe expected amount of the State’s fiscal revenue. The full lawpackage includes the introduction of a new E&P contract for thearea, known in the industry as the Production Sharing Contract,the creation of a national company to represent the State on thesecontracts, the creation of the so-called Social Fund to collect ashare of the State receipts from the oil production, and thecapitalization of Petrobras based on a stock market sale of state-owned 5 billion boe of yet to be produced oil resources.

While it is not clear that there is a reduction in the geologicalrisk, the proposed regulation introduces a set of changes that goesmuch beyond the regulatory solution for the reduction of theperceived risk. The introduction of the new contract for thePresalt area is the sole change related to this specific objective. Inthis matter, it has the purpose of enhancing the State’s direct

participation in the area’s E&P activity through a higher stake onits costs. For such matter the State would fully reimburse the oilcompanies’ field development and operational cost and explora-tory expenditures through tax exemptions, whenever it issuccessful in finding a commercial oil field in the area.

The new model would also change the bidding rules.Companies would bid over the government share of the oil fieldproduction and the winner would participate on a compulsoryconsortium with Petrobras, which would hold the monopoly ofthe operatorship in all offered tracks within the Presalt area. Allremaining areas would be under the current 1997 Oil Act’sauctioning and contract rules.

4. A model for E&P contracts

In this section, we propose a framework of analysis for theprocurement policy in a monopoly context of E&P blocks, whenthe State has to select the contractor and its contract. Thisframework follows the standard model on regulation of naturalmonopoly under information asymmetry (Laffont and Tirole,1993). Here, the uncertainty over the E&P block’s economic valueand the need to incentivize unobservable efforts, such as the case

5 Given that society is interested in the LP type, the other binding constraint is

A. Hernandez-Perez / Energy Policy 39 (2011) 57–6560

of exploratory (and also cost reducing) efforts, are considered theregulator’s fundamental problem.

For simplicity, assume that the State only requests thecontracted oil company to find oil. The size of the oil field isassumed to be observable ex-post, that is, after the realization ofthe E&P contract. However, the field size is composed by y, anexogenous parameter to the company that captures its privatevaluation of the block, and also the company’s effort to find oil,denoted by e. Both variables are unobserved by the State. Weassume an additive functional form Z(y, e)¼y+e, where Z(y, e) isthe size of the oil field. Note that by exerting effort e, the companyincreases the size of the discovery. This can be interpreted as areduced form of the company’s investment function to find thebest prospect out of the possible prospects in the area.3

Denote t the transfer received by the agent. Since size isobservable, one can restate this transfer as a transfer net of oilfield size’s benefits, that is, ~t ¼ t�Zðy,eÞ: The State’s payoff is givenby V¼S�t+Z(y, e) and the company’s payoff becomes U¼t�c(e)where c040, c0040.4 The differences in objective functionsgenerate the potential misalignment between State and com-pany’s objective.

Assume further that the State knows the distribution of thecompany’s prospectivity y, that can assume two values, yAfy,yg,where yoy. This distribution is given by (v,1�v), for 0ovo1.We will refer to the y company as the low prospectivity (LP)company, and the y as the high prospectivity (HP) one.

The State cannot observe either effort or y. An HP company canexert effort e�Dy and still have the same oil field size as an LPcompany exerting the same effort e. Here lies the asymmetry ofinformation between the State and the contracted oil company:the State does not know how interesting an E&P block is and italso does not know how much effort is being exerted by thecompany to increase the size, ant therefore, the social value, of thediscovery.

As in a usual principal-agent problem in the theory ofcontracts, by applying the revelation principle, one can restrictto offer direct revelation mechanisms of contracts where theplayers exchange messages over transfers and filed sizes as afunction of their announced evaluations. According to thisprinciple, these mechanisms would be truth telling. Then, it issufficient for the State to propose contracts that solve its expectedpayoff, given the distribution of y, subject to incentive compat-ibility constraints (ICC) and participation constraints (PC).Formally, the State solves

Maxfðt ,zÞ,ðt,zÞgEy ½S�tþZ�

Subject to

U ¼ t�cðZ�yÞZt�cðZ�yÞ

U ¼ t�cðZ�yÞZt�cðZ�yÞU Z0

UZ0

where the first two constraints are the ICCs for each type ofcompany, y,y, are the last two are the respective PCs.

Note that in the complete information case only the PCs wouldbe necessary since companies’ evaluations and efforts becomeperfectly observable. Under information asymmetry, the State hasto give up some (informational) rent to incentivize companies to

3 Another interpretation of the effort function is that it entails the dedication

to oil field development according to international best technical practices.4 In order to prevent stochastic mechanisms from being optimal we assume

c00040.

tell the truth about prospectivity and exploratory efforts, inparticular the HP one, whose ICC is binding.5

Optimizing with respect to transfers and size targets amountsto optimizing with respect to efforts and utility levels, whichyields the standard first order conditions for principal agentproblems in this regulatory context:

cuðeÞ ¼ 1

cuðeÞ ¼ 1�1�v

vjuðeÞ

where jðeÞ ¼cðeÞ�cðe�DyÞ.6 Here, the asymmetry of informationleads the State to propose a screening device where theexploratory effort of the LP company is distorted in order tominimize the informational rent to be transferred to the HP one.On the top of that, the low cost company exerts the first besteffort, that is, the level of effort that the State would implement ifhe could observe the HP company’s private valuation. As a result,HP is the residual claimant of his exploratory efforts, whichentails a contract referred in the literature as a high-poweredincentive contract. The LP company is awarded a contract where itis only partially residual claimant for his efforts, a contractrefereed to as low-powered.7 The transfer the company receives isa function of its prospectivity in the explored area.

In sum, the optimal E&P contract to be proposed to an oilcompany by the State under information asymmetry cannot bethe same across companies given the diversity of types and giventhe HP company’s incentive to pretend being LP.

In general, high-powered incentive contracts respond to theneed to replicate the correct (market) incentives for thecontracted (or regulated) companies and, from the standpoint ofefficient outcome, high incentive contracts are ideal. However,most of the contracts in effect blend these aspects of high and lowincentive agreements, with fixed remuneration that is indepen-dent of field size, with other remuneration proportional to thesize. The problems arising from the marked asymmetry ofinformation over essential characteristics of the contractedcompanies favor the choice of low incentive contracts.

In effect, there is evidence that in the oil industry, there adiversity of E&P contracts with respect to incentives to elicitexploratory efforts (this will be discussed in the next section).They range from fully reimbursement of costs to partial or eitherno reimbursement. In the following, we discuss some diversionsof this model and its application to the oil industry.

4.1. Shutdown policy

If the State finds that the informational rent to be given up tothe efficient company is prohibitive, then it can restrict itself toproposing E&P contracts only to the HP type. In such case, it canpropose one unique type of contract, the high-powered one,without the need to give up informational rent, as the screeningmechanism becomes irrelevant.

4.2. Distribution of types

If the distribution over the HP company becomes morefavorable, that is, if the probability of y becomes ~vov, then,

the LP’s PC. The remaining constraints are redundant and can be verified ex-post.

Then, the State solves the problem: Maxfðe ,U Þ,ðe ,U ÞgEy ½Z�t�

subject to

U ¼UþcðeÞ�cðe�DyÞ and U ¼ 0, where t¼U+c(e).6 Note that j( � ) has the same properties as c( � ).7 The optimal reimbursement rule for a State is to propose a non-linear

reimbursement rule contingent on ex-post observed field sizes.

A. Hernandez-Perez / Energy Policy 39 (2011) 57–65 61

there is a higher probability that the State will give up excessiveinformation rent to the efficient company, which in turn pushesthe optimal contract towards a lower incentive contract. In suchcase, the State is less fearful of giving up informational rent to theHP company because there are lower chances that the LPcompany will be selected.

4.3. Risk aversion

The uncertainty problem is an essential feature of the oilindustry. Typically, the company does not know the prospectivityof the area before the contract, which has sharp effects on the waythe State contract with companies.

Theoretically, the ex-ante participation constraints are re-placed by the following one:

vUþð1�vÞUZ0

Combined with the relevant ICC in the State’s maximizationproblem, when the companies are risk neutral, this means thatthe optimal contract will transfer all the risk to them, with thefirst best high-powered incentive scheme being implementedindependently of the company’s type. This means that the oilcompany is rewarded when it finds the area promising andpunished otherwise, a tough prescription in terms of itsimplementation.

Under risk aversion, this strong result is no longer valid as theex-ante participation constraint becomes

vuðU Þþð1�vÞuðUÞZ0

where u( � ) is a utility function, defined on the company’smonetary gains from prospectivity, such that u040 , u00o0 andu(0)¼0.8 In such case, the company is adversely affected thehigher the difference between the payoffs it receives in each stateof the nature. To guarantee participation of the company, theState has to pay a risk premium, which weakens the incentives. Asresult, the power of incentives reduces with risk aversion.

Another form of tackling uncertainty is opening an exit doorfor the company in the E&P contract. Provided that the State’sinterest is preserved in terms of E&P activities in the area, it isinteresting to allow some contractual flexibility among theconcessionaires and entering companies. Locking a company toa block whose economic value is uncertain may convey aprohibitive risk to a candidate company.

Another solution is to favor information exchange throughopen auctions, instead of sealed bid auctions. This would promotekeener competition among the bidders. Crampton (2006) statesthat, in contexts with low probabilities of collusion among theparticipants, it is possible to boost revenues through an openauction with public bidding.

Still, much care is due when proposing an auction rule. Theeconomic literature on auctions is very rich in defining the bestauction design to elicit the optimal contracts under informationasymmetry. In such case, considerations over proper allocation ofE&P blocks, risk aversion of bidders, the informational nature ofthe object and synergies from buying multiple objects becomerelevant. These aspects are discussed in Klemperer (2004) andMilgrom (2001).

If companies are encouraged through the auction mechanismto earmark an important portion of their future revenues, it ispossible that the winners may treat the blocks as a ‘buy option’ asoccurred with the auctioning of third generation (3 G) mobiletelephony spectra in the USA: some of the winners never paid a

8 This function is known as Von Neumann–Morgenstern utility function.

single dollar to the State (Klemperer, 2004). Contracts whoseremuneration rules are based on the gross revenues normallydistort investment decisions on margins, and lucrative projectsmay become quite unattractive if the government imposes heavytaxes on gross revenues. For contracts whose remuneration rulesare based on profits, investment decisions are not altered ex-post.

However, poor profit prospects in marginal areas lessen theincentive to allocate investments to exploration activities.9 Thesemechanisms have the disadvantage of increasing the probabilitiesof default by the winner, meaning that the winner will hardly findoptimal to develop the oil field. In fact, the higher the royalty, thelower the incentive to develop an oil field because it raises thebreak-even profit condition.

In the auction literature, E&P blocks are portrayed as examplesof common value objects, that is, objects with common economicvalue among the bidders in an auction, as no one knows beforethe auction (or even years later) how much recoverable oil isavailable in that block, its economic value and its developmentcosts. Formally, the prospectivity parameters yi are correlated, buteach company knows yi only.

This informational feature would have important conse-quences over the bidder�s behavior in an auction, in particularunder some auction rules, which would in turn decrease itseconomic value. The most important phenomenon is known asthe winner’s curse, which decreases the bidder’s aggressivenessduring the auction and it is due to the fact that each company onlyobserves a sign of the block’s economic value. As winning theblock in the auction would be bad news for the awarded companybecause it means it has an overoptimistic sign compared to allother bidding companies. Because of that, they tend to bid lower,as a precaution. In addition, this strategic behavior is magnified asthe number of bidders rises or the presence of a bidder withsuperior information, leading to poor results in a society’s revenuemaximization perspective.

Regarding correlation among neighboring tracks, there are twotypes of synergies that are important within the oil industrycontext: the geological and the economic synergy. Both imply thatthe value of a set of neighboring blocks is higher than the sum oftheir individual values. This is due to the possibility of neighbor-ing blocks sharing the same oil and gas reserves (geologicalsynergy), or the same infrastructure (economic synergy). Here,information constraints prevent the State (or the regulator) fromproposing blocks that perfectly demarcate the country’s portfolioof oil fields, as two or more blocks often share commonpools. There are at least two regulatory solutions that canrestore the efficient recovery of the oil. One is to allow theacquisition of clusters of oil-bearing blocks, as suggested inCrampton (2006). However, this option is seldom applied to oilblock auctions. Other is to set specific rules that force companiesin neighboring consortia to coordinate their operations incommon fields.

When there is economic synergy between neighboringactivities, the absence of infrastructure sharing provisions maywell undermine the feasibility of smaller projects whose lowprofits do not justify the construction of specific infrastructure.For example, in a mature area, blocking access to installedinfrastructure may step up the costs of an E&P project, as thecompany must bear the costs of replicating the existinginfrastructure. This is reflected in lower bids cast at auctions by(smaller) companies and fewer mature (and marginal) areas beingdeveloped.

9 However, this may be mitigated by a minimum exploration program. The

Brazilian regulation conveys an interesting case in the industry.

A. Hernandez-Perez / Energy Policy 39 (2011) 57–6562

5. Hybrid models for E&P contracts

In the previous section, we discussed the optimality of E&Pcontracts between the State and the oil (regulated) company.However, the scope of the State in the industry and the role ofcompetition among oil companies varies greatly among countries.In some nations, the State-owned company works as a regulator,while in others it plays a direct role in production. In such cases, itcan have the sole monopoly over E&P activities whereas in othersit competes with private companies for exploratory areas.

When the State-owned enterprise plays an active role in theindustry, it may internalize a valuable learning curve (dynamicefficiency), which can foster its continued sustainability in theindustry. The theoretical evidence shows that economic activitiesperformed by the State, despite tighter government controls,tends to weaken incentives leading to innovation and costreducing efforts, resulting in lower dynamic efficiency andproduction in the industry (Hart, 2003; Shleifer, 1998). Still, thereis strong evidence that competition, more than asset ownership, isthe driving force for efficiency in many industries. Then, whenfaced with competition, state companies tend to perform as wellas private ones.

When the company is the operator in the consortium, that is,the company responsible for the day to day activities for fielddevelopment and production, it has the advantage that itsconsortium partners, who oversee the operator’s actions andinvestment decisions, can elicit significant pressure for costscutting efforts or can provide new technological solutions(productive efficiency). Notably, this advantage can be reducedif the company is the sole operator of larger areas. For instance,the monopoly of operations in a frontier area that requires thedevelopment of new technologies may lessen the capacity of thepartners to distinguish between ‘right’ and ‘wrong’ choices and,therefore, their ability to propose and develop new technologicalsolutions.

Also, the monopoly of operatorship leads to the loss of thebenchmark analysis and, for this reason, it weakens the pressureto cut on costs and to find solutions for field development(Shleifer, 1985). One side effect is that it may curtail the incentiveof non-operating partners, due to the nature of their ancillaryroles, to monitor and contribute to the field development andproduction. Of course, these implications also hold for privatemonopolies.

Thus, it is vital that potential gains in learning curves and jointR&D efforts (greater dynamic efficiency) resulting from centra-lized operations by a national company are offset by losses in thevalue generated through lower capacities to conduct comparativeanalyses of operator performances (lower production efficiency),as well as less variability in technological solutions (lowerdynamic efficiency) and the resulting loss of interest among otherE&P companies as ancillaries for implementing project (lowerallocation efficiency).

When the State-owned company does not have the monopolyover E&P activities, States can use other selection mechanismsthan auctions. Beauty contests, as the competitive tenders areknown in the literature, are characterized by the selection ofcompanies by criteria that are frequently subjective and conse-quently more open to discretionary decisions taken by theadjudication panel (Klemperer, 2004; Pratt and Valletti, 2001).Along these lines, the choice of the participants to this panelbecomes very important. Different panels (in different countries)select different companies, which gives rise to legal challengesand consequently higher costs for society.

Moreover, the assignment of these powers to the adjudicationpanel is accompanied by a higher risk of corruption: the larger theproject, the more significant the repercussions of its profitability

in terms of distorting public functions. When the costs of checkingthe merits of decisions and the effectiveness of the punishment incase of deviation are prohibitive, this option proves extremelyburdensome for society.

This arrangement also requires much information in terms ofefficiently matching company profiles to E&P blocks. Typically,companies have a rational strategy of stating which of them arethe best qualified for the business in question – in a contest to seewho ‘shouts loudest’ – leaving the adjudication panel in a delicatesituation. At auctions, companies are forced to ‘prove’ theircapabilities with corresponding bids.

6. International experience on aligning E&P incentives

In the light of the theoretical discussion, the purpose of thissection is to analyze the economics of contracts adopted by the oilindustry according to their incentives to find oil. There are severalremuneration structures, grounded on gross revenues, profits ortotal output, which may give rise to the same volume of resourcesin any given year. Essentially, they are a function of oil prices, fieldproduction and costs, which are all success contingent remunera-tion rules. However, these combinations have very differenteffects on the economic context, specifically with regard toexploratory and cost-reducing efforts among the contractedcompanies.

In the oil industry, E&P contracts are classified in two maincategories: Production Sharing Contracts (PSCs) and the Tax &Royalties Contracts (T&Rs), as discussed in Johnston (2003). ThePSCs assign ownership of oil output to the State instead of thecompany, as opposed to typical T&Rs.

While the ownership distinction over the produced oil isirrelevant from the economic standpoint – production is easilymonitored trough contracts – none of these contracts can beportrayed as more or less powered than the other in terms of thepower of incentives elicited by them. There is no essentialdifference between these contracts. Nonetheless, PSCs are usuallyassociated with contracts whose reimbursement rules are basedon the profits of the oil company, with the State remuneratingpart (or all) of the costs incurred by the contracted company,whereas T&Rs are normally associated with remuneration rulesbased on total gross revenues, regardless of the costs of thecontracted company.

Still, any E&P contract, whether based on T&R or PSC, mayinclude reimbursement rules of any type. Both may ensure rapidrecovery of costs by the operator. In T&Rs, this may take placethrough progressive royalties on the total gross revenues or taxeson profits. For PSCs, this is usually handled through immediateremuneration of the project’s exploratory and development costs,before any transfer assigned to the State. PSCs typically includeroyalties on the remuneration paid to the State.

Table 1 shows some examples of PSCs payment structure, onwhich royalties are paid in addition to a progressive taxation onthe profits based on the field’s internal rate of return (IRR) oroutput. In Sakhalin II field, located in Russia, for instance, the Statetaxes a minimum 10% of profits if the IRR falls below 17.5%, whilea maximum 70%, should the IRR top 24%. In this respect, theobserved contracts are in line with the theoretical prescriptionthat uncertainty should be mitigated by smoother payoffs acrossstates of nature, as the reimbursement rules are function of thefield’s IRR or production volume, which are proxies of field sizeand profitability.

For T&Rs contracts, we find similar schedules. In Brazil, forinstance, very productive areas also have a progressive schedulewith respect to the year of production. This enables the companyto rapidly recover its development costs.

Table 1Production sharing agreement (PSA) clauses in selected producer countries.

Source: Deutsche Bank (2008).

Country Azerbaijan Kazakhstan Russia Angola Nigeria

Field/block ACG Karachaganak Sakhalin II Block 17 Bonga

Royalties None None 6% of revenues None 0–12% (depth dependent)

PSA’s trigger IRR IRR IRR IRR Output

Share for the state, conditional on triggerMinimum 30% 20% 10% 25% 20%

IRRo16.75% IRRo0% IRRo17.5% IRRo15% Qo350 mb

Maximum 80% 80% 70% 80% 60%

IRR422.75% IRR420% IRR424% IRR430% Q41500 mb

Income tax 25% 30% 32% 50% 50%

Note: IRR stands for internal rate of return, and mb for millions barrels per day.

81%

66%

73%

42%

74%71%

78%

69%

59%63% 64%

59% 61%

81%

62%

76%

64%

72%67% 65% 65%

47% 49% 49%

35%

75%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0

100

200

300

400

500

600

700

800

900

1000

Aze

rbai

jan

Equa

toria

l Gui

nea

Nig

eria

Cha

d

Bang

lade

sh

Mya

nmar

Alg

eria

Indo

nesi

a

Indi

a

Con

go B

razz

aville

Rus

sia

Mau

ritan

ia

Chi

na

Ang

ola

Trin

idad

and

Tob

ago

Mal

aysi

a

Kaz

akhs

tan

Om

an

Ven

ezue

la

Egyp

t

Braz

il

Uni

ted

Sta

tes

Uni

ted

Kin

gdom

Aus

tralia

Can

ada

Nor

way

Production Sharing Contract Tax&Royalties

Political Stability Gov. Take (%)

Fig. 3. Political stability and government takes by major type of E&P contract by country.

Source: Kaufmann et al. (2006) and Jojarth (2008). The vertical scale is the governance rating for political stability.

A. Hernandez-Perez / Energy Policy 39 (2011) 57–65 63

As far as risks are concerned, the geological and thecommercial risks are commonly mitigated by States through astructure of payment composed by advance payments (signaturebonuses in Brazilian auctions or no payments at all in Norway),made before oil is discovered, and future payments. For the latter,the operators may compete through upfront payment, bestbusiness plan for the area and/or their willingness to share thetotal gross revenues, profits or output should a commercialdiscovery be made.

The adoption of PSC contracts are usually attributed to thecountry’s weak institutional indicators. Fig. 3 shows the relation-ship between political stability and government take by T&R andPSC contracts for various countries.10 It is possible to distinguish

10 The government take concept is usually defined as a percentage of all the

payments owed throughout the lifetime of an exploration project to governments,

as a proportion of the cash flow after reimbursing all the capital invested in the

project and its operating costs. Examples of payments to governments include

the profiles of companies that choose T&R as being those withhigher institutional quality ratings, on average. It seems that theupfront recovery of exploratory and development costs in case ofsuccess, typical of a PSC contract, allows for high governmenttakes despite the countries’ high political risk. This mitigates thehold-up problem among companies, which are wary of operatingin a country with a track-record of opportunistic government.Notably, even countries with institutional profiles that areadverse for private investment, such as Venezuela and Egypt,adopt T&Rs with similar government takes.

In the context of auctions, there is no record of synergies beingtaken into account. Bidders typically make simultaneous bids forneighboring blocks without the option to get clusters of blocks.

(footnote continued)

royalties, income tax, a portion of the production, profits, signature bonus, added

value taxes, excess profits taxes, charges imposed on State-owned oil companies,

import taxes, etc.

A. Hernandez-Perez / Energy Policy 39 (2011) 57–6564

However, there are some regulatory instruments that allow forthe geological and (seldom) economic coordination of activities.In the industry, such instrument is known as unitizationagreements, where companies are mandated to coordinate theiractivities. Countries often adopt this regulatory rule, taking suchsynergies into account—especially geological synergies. It isimportant to note that the imposition of unitization agreementsis not a trivial exercise. It requires the alignment of diverginginterests in terms of sharing the gains and costs of a blockexploration and development project. Along these lines, the roleplayed by regulation in these agreements becomes relevant, byminimizing the costs of the negotiating procedures.

In summary, the observed E&P contracts emerge as solutionsto a bilateral negotiation between sovereign States and oilcompanies, where E&P incentives are traded off with rent to oilcompanies, which varies according to field productivity and itseconomic environment, in particular with respect to the indus-try’s uncertainty.

7. New incentives from the Brazilian oil regulation proposal

The regulatory reform, proposed on August 2009, for the E&Pactivities in the non-leased areas of the Presalt and other strategicareas opens up possibilities that the forthcoming area-specificcontracts enhances the reimbursement of costs by the Statethrough the introduction of the PSC. The geologic specificregulation aims at tackling highly productive fields and for such,it aims at designing a ‘y contract’, that is, a contract specific to acompany willing to develop this type of field, following the formalnotation from Section 4.

As discussed, once the contract is designed to the HP companyonly, it becomes unnecessary to incentivize the company not topretend to be an LP.11 In such context, a high powered scheme,where the company is the residual claimant of its extra gains fromfield enhancement is the optimal contract.

Given that the current regulation allows for enhanced costreimbursement through the Special Participation instrument in itscurrent T&Rs contracting system for highly productive fields,there is no difference between these contracts from thestandpoint of incentives to find oil. All that would be needed isto calibrate the Special Participation to the new economic context,realigning the reimbursement rules to Brazilian society’s interest.

Pushing cost reimbursement towards the State, as proposed bythe new regulation, would be justified in situations where agentsare averse to risk and uncertainties are exacerbated. For example,should technological uncertainty be sufficiently high, morecompanies will view E&P project as prohibitive. This wouldincrease the State’s role on taking more risk, provided the E&Ppresalt project has a social value that is high enough. Liquidityconstraints may also be eased through rules of this type, pavingthe way for new companies to enter the market. However, it is notclear that the net effect on risk has increased so strongly in thepresalt area. In addition to the technological challenges to itsdevelopment, there is an increased perception of the environ-mental damages of the oil industry activity, especially on offshorefields, despite the alleged reduction in the presalt geological risk.

The asymmetry of information between State and oil compa-nies with respect to E&P activities can be extended to costsconcerns. The increase in the State’s stake on profits would alsoimply a loss of economic value due to weaker cost-reductionincentives (production inefficiency) with higher exposure tobusiness risks, greater incentives for cooking the books, whichin turn increases the regulatory costs.

11 As discussed in the section on the shutdown of the LP company policy.

According to the new proposal, there would be also a newplayer, a State company, representing directly the federalgovernment, to be part of the new PSC. Among its rights andduties, this company would have the right to veto Petrobras’operational decisions and audit costs. It seems clear that this addsto the commercial and political risks of the E&P activities in thearea for both Petrobras and its partners.

Besides the change in the reimbursement structure for thePresalt area, the proposal gives the monopoly over the operator-ship of the E&P activities in this area to Petrobras. Despite thepotential geological or technological synergy of such marketdesign, the disadvantages are not negligible, as less competitionleads to fewer incentives to innovate, to lower costs and to invest.Also, the fact that different companies have different priorsregarding a track’s prospectivity conveys another justification forcompetition as a unique company would not see the samepotential that other companies would, leading to the under-development of the area.

If Petrobras is to be given the preference over presalt E&Pactivities, it also should be given the opportunity to resell ordelegate operatorship to oil companies that have more optimisticpriors for the area. The strengthening of the secondary market ofoperatorship may be essential for restoring the efficiency of ex-

post inadequate matches. However, constraints over operatorshipnegotiation may lessen potential synergies from closer super-vision of investment decisions, exchanges of expertise and theclustering of efforts within the Presalt area. Such measures are notincluded in the regulatory proposal.

Finally, the regulatory proposal includes many other importantaspects such as the creation of a sovereign fund to collect thegovernment take from PSC contracts, and a potential dramaticchange in the distribution of this government take amongmunicipalities, states and federal government. However, theseissues are beyond the scope of this article.

8. Conclusions

This article presents an overview of the economics of upstreamoil industry regulation. We identified the basic market failures ofthe industry – the common pool problem and the asymmetry ofinformation among State and oil companies – to propose theregulatory mechanisms that minimize the welfare losses fromsuch economic environment. Optimal regulation should beresponsive to companies’ perception of risk and the State’s urgeto maximize government take without sacrificing too muchexploratory, development and cost-reduction incentives.

We find that the observed E&P contracts foresee much of thecharacteristics of the optimal contract, with a remunerationstructure that combines upfront with future payments to mitigateuncertainty and incentivize exploratory efforts. Furthermore,States typically allocate E&P blocks through auctions or compe-titive tenders in order to assign them to the company with thebest business plan.

In Brazil, the current oil regulation is in general consistent withan optimal response to the industry’s market failure. However,the slow market deconcentration and the absence of economicunitization may be responsible for fewer mature areas beingexplored and developed.

With the major discoveries in the Santos and Campos offshoresedimentary basins, the federal government proposed a newregulation to the industry in August 2009. We find that there is noeconomic justification for altering the T&R to the PSC contractualscheme for the area, as the former may well encompass significantaspects of the latter in terms of control over oil incomes and theactivities of the contracted companies. The benefits of market

A. Hernandez-Perez / Energy Policy 39 (2011) 57–65 65

concentration to Petrobras, deriving from economies of scale andmore concentrated research and development efforts, must beweighed against potential losses in dynamic efficiency within acontext where the multiplicity of operators with their widelyvarying types of expertise allocate exploration and developmentefforts to frontier areas. Furthermore, market deconcentrationbuttresses benchmarking analyses of corporate performances as aregulatory oversight tool, in addition to a partner (non-operator)company, which imposes the correct incentives on the operators.Further effort must be dedicated to underpinning the effectiveimplementation of regulations in this industry, ironing out flowsthat lessen efficiency and thus reduce the amount of wealthgenerated by oil E&P activities.

Acknowledgments

The author thanks the comments from participants in thePetrobras/IBRE-FGV lecture cycles, as well as Samuel Pessoa onprevious versions. Any errors or omissions are the responsibilityof the author.

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