Evaluating Performance of Production Sharing Contract and Concessionary System: An Overview and...

JoOST(2015) 41-54 © STM Journals 2015. All Rights Reserved Page 41

Journal of Offshore Structure and Technology ISSN: 2349-8956(online)

Volume 2, Issue 1

www.stmjournals.com

Evaluating Performance of Production Sharing Contract

and Concessionary System: An Overview and Assessment

Based on Examples from Selected Countries

P. B. Jadhav*, L.K. Kshirsagar Department of Petroleum Engineering, Maharashtra Institute of Technology,

Pune, Maharashtra, India

Abstract Exploration and production of hydrocarbons in different regions is controlled by regulatory

system which is classified in to concessionary and contractual system. The contractual system

is further divided in to production sharing and service contracts. Generally, any fiscal system

is designed to facilitate maximum benefit to the host government keeping in mind risk taken by

the operator in discovering and developing the resources to provide them profitability in oil

price dynamics. Main objective of present study is to take an overview of the fiscal systems in

operation all over the globe, their comparison based on salient points focussing on

advantages and disadvantages of each and finally their quantitative assessment carried out on

four geographic regions, namely India, Brazil, Nigeria and Norway. These examples are

taken specifically considering their resources, regularity framework, and efficiency. It is seen

that the concessionary system is adopted by countries with higher potential for production and

thus examples were taken from areas where working condition is difficult and environment is

harsh. The production sharing contract is a reasonably common fiscal system known for

intricacy in the sharing of production and tax structure. Quantitative analysis of these systems

is attempted here for India, Brazil, Nigeria and Norway. The assessment was based on

parameters given in the fiscal terms of selected countries with uniform production and

variable cost estimation. Four different oil price scenarios including one scenario based on

cyclicity of oil price were considered for comparison. NPV for operators and proportional

share with government were calculated (three different scenario) and possible reasons for the

variation are discussed.

Keywords: Fiscal system, production sharing, royalty, tax, oil price, NPV

*Author for Correspondence E-mail: [email protected]

`

INTRODUCTION Hydrocarbon deposits in most of the regions of

the globe are classified under “Strategic

Mineral” which recognizes government

ownership of this most important natural

resource. Risk and uncertainty are the terms

often discussed in connection with these

deposits as they are found below the surface at

some depth and excepting a few surface

indications, their presence needs to be

interpreted using signatures, quality data and

skills.

This requires long term investment and also

aggressive mind-set of companies for taking

risk. Use of state of art technology thus has

become essential which is available only with

major and individual international companies

and also with National oil companies. Often

lack of technology but good potential of the

region along with fiscal terms and geopolitical

stability have been the prime factors for oil

companies to take risk and enter in to fiscal

terms. Execution of an effective regime for

petroleum development is strongly influenced

by geological prospects of a country and the

technological and financial resources needed

for exploration and production of

hydrocarbons. Not only company management

needs to have aim for high investment but also

expertise in broad areas of exploration and

development of hydrocarbons throughout the

tenure of the project. Returns for long term

investments are possible only after commercial

production of hydrocarbons. Therefore

sustainability of funds is one of the concerns.

mailto:[email protected]

Production Sharing Contract and Concessionary System Jadhav and Kshirsagar


Access to the potential areas is possible for

any company only after acquiring rights for

the area and decision on economic rent. Any

oil and gas project needs to undergo following

stages with definite time tags during the

project tenure, which generally comprises of

25 to 35 years and classified into leasing,

exploration, appraisal, development,

production, and decommissioning. These long

term project cycles are coupled with great

uncertainties with regard to resource prices

and project output along with production, cost,

technological and strategic uncertainties [1].

The petroleum fiscal system came in to

existence in late 1970s essentially due to

concessions for the international companies

became a topic of continuous criticism. Since

then the fiscal system is classified in to

different contractual terms to maintain

equilibrium between government rights and

profitability of companies working as

operators.

The petroleum fiscal regime of a country is a

set of laws, regulations and agreements which

govern the economic benefits derived from

petroleum exploration and production. It takes

in to consideration the oilfield characteristics

into account: the probability to discover, the

size and quality of the deposit, the investment

needed and the quality of political institutions

(Julie ING, 2011). This aspect is discussed at

length by Johnston [2]. Aim of this paper is to

take an overview of the petroleum fiscal

systems in operation and compare selective

fiscal systems with common database.

UNCERTAINTY AND RISK Any project dealing with exploration,

development and production of oil and gas

involves different levels and types of

uncertainty and risk. Tordo classified this in to

following three categories [3]:

Geological Risk: related to presence of oil

and gas, and also size of discovery.

Exploration in frontier basins has higher

risk than matured basins as quality data on

different essential parameters is available

in case of matured basins which is

inclusive of volume of deposit, poroperm

relationship, reservoir heterogeneity at

different scales and appropriate location

for wells to be drilled [4].

Financial risk: dealing with project and

economic variables. The geological

uncertainties create constraints in the

understanding and assessment of quality

of oil, potential of production levels,

sensitivity of costs and future market

trend.

Political: realization of geopolitical

situation over project tenure is another

uncertainty particularity in sensitive areas

with higher resource potential.

Discussions at length are available in plenty on

these aspects (e.g. Johnston, Ross, Blake and

Roberts, Schiozer et al., Suslick and Schiozer)

[4–6].

PETROLEUM FISCAL SYSTEMS The petroleum fiscal system is broadly

classified in to two types in general;

concessionary type and contractual which is

commonly used by different countries for the

exploration and production of hydrocarbons

(Figure 1).

Concessionary system was previously also

called as Royalty and Tax (R and T) system.

Following is the approximate distribution of

these systems in different geographic regions

(Table 1). As seen from Figure 1 that

production sharing and service contracts are

sub types of contractual type. Significant

amount of work is available on both systems

(Burrows, Johnston, Bindemann [7], Mazeel

[8]). Though similar parameters are used in

both systems, their implementation is

strikingly different (Table 1).

Concessionary System

Concession or license agreements have

evolved considerably since their introduction

in the early 1900s as the acreage offered, to an

operating company which may be an

International Oil Company, IOC or a

representation of a consortium, were large

with duration of fifty to even ninety years [9].

The concession is secured by paying a

signature bonus or a license fee to the

government and thereafter government

received royalty and tax after production of

hydrocarbons [8]. Brazil has adopted a system

of bidding for offering of blocks under this

system.

Journal of Offshore Structure and Technology

Volume 2, Issue 1

ISSN: 2349-8956(online)


Fig. 1: Petroleum Regulatory Framework [9].

Table 1: Petroleum Fiscal Systems around the World.

No Geographic Region Concessionary System Production Sharing Service Contracts

1 N. America Canada, USA

2 South America Argentina, Bolivia, Columbia,

Paraguay, Costa Rica, T & T (On)

Cuba, Guatemala, Jamaica, Panama,

Uruguay, T & T (off)

Brazil, Haiti, Peru,

Venezuela, Chile, Ecuador,

3 Middle East Abu Dhabi, Turkey, Neutral Zone Bahrain, Iraq, Oman, Qatar, Libya, Yemen, Syria

Iran, Kuwait, Saudi Arabia

4 Asia Pacific Australia, Brunei, New Zealand, Thailand

Bangladesh, India, China, Indonesia, Malaysia, Myanmar, Cambodia

Philippines

5 Africa S Africa, Senegal, Morocco,

Madagascar, Ghana, Mali

Algeria, Angola, Egypt, Gabon,

Kenya, Libya, Nigeria, Sudan,

6 Europe Netherlands, Norway, Spain, UK,

Iceland, Portugal, Italy

Albania, Malta, Russia, Georgia,

Kazakhstan

The company after winning the rights is

entitled for 100% risk and has right for all

production at the wellhead and are given the

right to export the crude oil or gas produced,

subject to some obligations such as meeting

national consumption and acquisition of local

content [10]. It is seen that UK, Norway and

Australia no longer impose royalties on oil,

but just a rent and a heavy tax while high level

of royalties is practiced in large oil producing

and exporting countries, and in the states

interested in attracting foreign investment, the

average tax rate is about 12–13% [9]. A brief

comparison between different systems with

concessionary is given in Table 2 and also

given approximate distribution of cash flow in

Table 3.

Contractual System

The contractual system is classified into

production sharing contract and service

contracts (Figure 1). Though production

sharing contract is more common in operation

but many regions with higher production

capacity have executed service contracts

(Table 1). Ghandi and Lin have taken an

overview of service contracts in case of eight

important countries [11]. A contractual

system has a long term fiscal framework that

administers the relationship between

government and operating company during

which the operator obtain rights for

exploration and production with 100% risk. In

the event that a commercial discovery is made,

the operator is entitled to share the production


JoOST(2015) 41-54 © STM Journals 2015. All Rights Reserved 4

with the government and also for cost recovery

[12]. The fiscal conditions quoted in the

regulations vary significantly and thus it is

necessary to find equivalence of discovery size

for valid comparison of profitability of project.

A pure service contract is the one where the

contractor carries out exploration and/or

development work on behalf of the host

government for a fee and the contractor bears

no exploration risk [8]. It is noted by Ghandi

and Lin that the service contract framework is

prone to high potential losses even if the host

government adopts maximization profit policy

[11].

A generalized comparison between all fiscal

systems is given in Table 2.

Table 2: Salient Points of Different Contractual Systems (Reorganized using Different Sources).

Parameter Concessionary Production Sharing Service Contracts

Ownership

Rights

Owned by an individual or Government.

Rights are transferred to the contract

company.

Owned by Government.

Operator is hired for exploration

and production.

Owned by Government.

No transfer of rights. Contract for

production after exploration.

Bonus Paid before any investment. In few cases, Yes. --

Ring fencing Less likely. Most likely. --

Royalty Specified on volume produced. Specified. --

Cost recovery No cost recovery limit. Cost recovery limit is specified. Production is given to Government and fee is entitled to service company

inclusive of cost recovery. Profit

petroleum

Lifting entitlement is all excluding

royalty.

Shared between Government

and Operator.

Tax Special oil tax. Income tax. Income Tax.

Income tax.

Government

control

Low. The operator is allowed to sell the

produced oil and gas subject to conditions quoted in system.

High. High.

Title transfer rights

At the wellhead. At the export point.

Many geographic regions like Nigeria, Brazil

etc. offer both concessionary and also

production sharing contracts. The most

important point in deciding whether the

system is repressive or progressive [13, 14],

Johnston and Johnston, 2015 is recognition of

Government take in the contract and also cost

recovery limit. Contracts or service tenure of

any project varies from 25 to 35 years and thus

sustainability is an important issue in the

realization of uncertainties of many parameters

like reserves, recovery and production, quality

of oil, price elasticity and geopolitics added to

that of geological uncertainties [15].

Designing of efficient and stable fiscal system

is always a challenge which needs discussion

on public platform (e.g. Rangarajan

Committee and Kelkar Committee, India). It is

necessary to understand sensitivity of different

parameters recognized in the fiscal system to

develop a balance between government and

operator perception even at worst scenario.

Most important objective in any system is to

maximize the value of its petroleum resources

while attracting sufficient interest of the

operator for investing in E&P activities while

objective of the operator is to ensure that the

rate of return of the capital employed is

consistent with the project’s risk and with the

strategic objectives of the corporation. Tissot,

based on his assessment classified the systems

in to regressive and progressive (Figure 2)

[16]. Regressive fiscal regime has more

payments prior to commencement of

commercial production while in the

progressive system more payments are made

after generation of revenue. Tissot, believed

that contractual systems are more stable. The

regulatory system needs sustained efforts in

modification of various parameters for the

benefit of operators. Reforms in the fiscal

system allowed Mexico, Brazil and Norway to

earn more profit in spite of presence of

difficult working conditions and harsh

environment. However this has resulted in

lesser attention on exploration work thus

reducing the ability to replace hydrocarbon

reserves [16].


Volume 2, Issue 1



Fig. 2: Regressive and Progressive Fiscal Systems (23).

The comparison between two systems is given

further in the following example. It is assumed

that price of oil is $ 60/barrel and distribution

for one barrel is shown as per the terms and

conditions in both the systems for their

assessment.

It is seen from Table 3 that concessionary

system provides better revenue generation to

host government while operator earns

comparatively better in the contractual system.

This may also be considered as simplified

conclusion which needs to be assessed by

comparing actual data.

Brazil has adopted both systems

simultaneously in the Sub-salt region. They

have used concessionary system for the

improvement of existing regimes and allowed

implementation of contractual system for new

blocks to establish additional presence of

hydrocarbons. The problem associated with

this is presence of two different regulatory

systems for same objective which is

challenging and difficult to maintain harmony

in system [16]. However because of potential

of the region, response for both systems was

good which led to rapid growth of reserves

and production.

Tissot in 2010 concluded that most of the

fiscal models failed to respond to the high

price increases of the last decade. Therefore to

hold valid comparison between different

contractual systems, examples of four

countries from different geographic regions

are taken here for emphasizing efficiency and

intricacy to find out competent system.

Table 3: Distribution of One Barrel in Concessionary and Production Sharing Systems.

Parameter Concessionary Production Sharing

Government Operator Government Operator

Royalty $ 24 Up to 40% $ 12 Up to 20%

Cost recovery About 50% after royalty if

applicable $ 18

Up to 50% after

royalty $ 24

Profit petroleum 14.4 60 (G): 40 (O) 9.6

Taxes $ 1.8 10% Provincial

Income Tax $ 6.48 40% 3.84 40% –3.84

Net Income after Tax

$ 9.72 5.64

Total $ 32.28 $ 27.72 $ 30.24 $ 29.76

Percent distribution 53.8% 46.2% 50.4% 49.6%



COMPARISON OF FISCAL SYSTEM

OF SELECTIVE COUNTRIES Four different counties, India, Norway,

Mexico and Nigeria are considered here for

their strategic importance. India has limited

resources of hydrocarbons with high

dependence on import of oil. Also significant

portion of India is still to explore in spite of

greater potential. Norway is one of the major

oil producing countries with rapid strides in

the growth since major discoveries in North

Sea. Though major resources are located at

deepwater and also in harsh environment,

Norway has shown sustainability to remain in

top oil producing countries.

Brazil has emerged as major player because of

major discoveries in sub-salt. Nigeria has

reported significant number of commercial

discoveries in deepwater and thus will have

greater potential to be one of the leading oil

producers of the world.

Fig. 3: Evolution of Proven Reserves in Brazil, Norway, Nigeria and India.

(Based on BP Statistical Review 2014).

Fig. 4: Comparison between Production and Consumption of Oil. Data for Consumption

for Nigeria is not available.

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

1980 1985 1990 1995 2000 2005 2010 2015

Bil

lio

n B

arre

ls

Year

E V O L U T I O N O F P R O V E N R E S E R V E S

Brazil Norway

Nigeria India

-

500

1000

1500

2000

2500

3000

3500

4000

Th

ou

san

d B

arre

ls p

er d

ay

Year

Production and Consumption of Oil Brazil P

Brazil C

Norway P

Norway C

Nigeria P

India P

India C


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The reserves of India and Norway are almost

similar while Brazil and Nigeria have shown

continuous increase in proven reserves in last

fifteen years (Figure 3). Reserves accretion is

maximum in Nigeria, and India has remained

steady at 5.5 billion barrels. As given before,

the growth of reserves in Norway was on

decline but has taken a rise in last five years.

India has largest gap between production and

consumption (the ratio is 0.28, Figure 4).

Norway and Nigeria are producing more than

consumption, while Brazil has marginally

higher consumption than production (0.85). It

can be said that Norway and Nigeria are oil

exporting counties while Brazil and India are

oil importing countries with India having very

high proportion of import of oil and also

resources constrains. Oil production in Brazil

and Nigeria are cost sensitive, while Norway

has harsh environment.

Technology growth in Norway and Brazil is

significant while skilled manpower is available

in abundance in India. Nigeria is weaker in all

these aspects including geopolitical issuers. It

is seen from above table that the fiscal system

is modified in Nigeria in last 50 years and

discoveries in deepwater led to increase in

reserves and now is considered as one of the

countries of export of oil.

The contractual system has seen modification

thrice (1993, 2000 and 2005) in last twenty

years. Presently royalty is 8% for water depth

more than 500 m and other conditions like cost

recoveries are modified. Petroleum profit tax

is added for deepwater (Table 4).

Regulatory risk is higher for Nigeria in spite of

maximum potential out of four discussed.

Norway and Mexico have better investment in

exploration which has resulted in to large

discoveries. Production rate is also higher

there than India and Nigeria.

Regulatory risk is very low is Norway (13%)

in spite of higher government rate and harsh

environment. Brazil too has comparatively

lower regulatory risk (43%) compared to India

and Nigeria and higher government take than

India. This is essentially because of greater

potential in hydrocarbon resources and lesser

risk in spite of higher exploration risk. India

has relatively lower government take (BCG)

[17].

Nigeria officially has created a free zone

“Onne oil and gas” to provide an ideal

infrastructure to create a nucleus to support oil

and gas industry of west coast Africa and

distribution centre for all companies to

combine effectiveness of private sector and

support of government (PWC) [18].

This is the only free zone with no taxation,

attractive free zone incentives and fast track

procedures which resulted in to presence of

112 major companies and more than 7000 job

opportunities (Onne free zone presentation)

which has resulted in to significant increase in

the oil and gas activities along west coast of

Africa.Following table has summarized

generalized fiscal regime in selected four

countries.

SAMPLE DATA FOR COMPARISON

OF REGULATORY SYSTEMS IN

FOUR COUNTRIES Following is the sample data taken from

available database on public domain (source

unknown) for the valid comparison of the

regulatory systems in all four regions. Most of

the data is same for all countries analyzed.

Contract term is considered as twenty five

years inclusive of first five years for

exploration and development and twenty years

for production.

The OOIP is on the higher side if considered

the average field size of India. Regulatory

norms given in the fiscal system by India,

Brazil, Nigeria and Norway are used here for

comparison (Table 4). Though the project

tenure is not the same for all system, here for

computation and assessment, the tenure is

considered as twenty five years. Similarly

CAPEX is considered as two times higher in

Nigeria, Brazil and Norway compared to India

though in reality the cost in these regions is

much higher.

Very steep rise in the production in the initial

stages, followed by a plateau like position,

trailed by a decline of 11% per annum is

considered (Figure 5).



Table 4: Comparison of Fiscal Regimes of Selected Countries [1].

Parameter Brazil India Nigeria Norway

Government

Objective

Retain a level of

control, self-sufficiency

to reduce gas import,

maximize government

rent.

Retain a level of

control, transparency,

maximizing profit.

Member of OPEC,

NNPC is owner on

behalf of government.

All control.

Fair revenue share,

retain a level of

control on production,

environmental control.

Regulatory

system

Concessionary, very

active government

participation.

PSC, participation of

NOCs. Till now tine

rounds of NELP.

Upto 1970:

concessionary,

1970–90: Joint Ventures

for shallow water and on

land, and since then

Production sharing for

deepwater.

Concessionary, active

government

participation.

Adopted policy

Petrobras as default

operator for higher

efficiency in potential

areas.

NOCs have large

stakes.

NNPC has large stakes

in JVs and PSC.

High taxation, simple

tax system.

Fiscal terms Up to 35 years Upto 35 years Initially 30 years Up to 40 years

Royalty 10% 10%, varies on land

and offshore.

0 to 20%. Decreases in

offshore with increase in

water depth, zero for

depth greater than

1000 m.

------

Cost Recovery Up to 100%. Capped at 80%. Deductible in special

tax.

Profit Oil based on Multiple

Investment factor, MI.

Sliding scale. Based on

R factor.

Tax

Corporate 34%

Special Participation

40%.

30 to 50%.

Income tax: 67.5% first

five years

(new comers)

85% first five years (all

companies)

85% subsequent years

(for all) VAT 5%.

Corporate 28%,

Special oil tax 50%,

Environmental Tax.

Government

take average 72% 57–70%% 64–91% 79%

Advantages

Rapid growth of

reserves and

production, transparent

system, strengthening

of NOC.

Higher production

gives better revenue for

government. Ring-

fencing is allowed for

development cost.

Minimum risk for

government. New

system promises

transparency and more

structured framework.

Suitable in low price,

high government take.

Disadvantage High cost for operators

and delay. Resources constrains.

Significant delay.

Uncertainties over

regulations and security

issues.

No clear

differentiation in

complex fields.

Exploration

CAPEX $ 37 Billion $ 13 Billion $ 12 Billion $ 21 billion

Production rate

(MM BOED) 2.4 1.7 1.1 3.9

Regularity risk 43% 60% 83% 13%

Overall ranking

on relative

performance

(BGC) [1]

4 8 3 12


Volume 2, Issue 1



Table 5: Basic Data used for the Comparison of Regulatory Systems.

Input Variables Input Variables

OOIP 1.86 Billion bbl. Reserves 371.6 MM bbl.

Recovery% 20% Initial rate 7400 BOPD

Time to plateau 3 Plateau rate 94500 BOPD

Plateau span 4 Exploration and Development span 5

Production time 20 CAPEX/bbl. $ 5.28 average

Decline% 11% OPEX/bbl. $ 5.05 average

Oil Price Four scenario, Low, medium,

high and sliding. Inflation 2.5 to 3.5%

Hurdle rate 15% Regulatory system As per the country norms

Cost recovery 60% for India

80% for Nigeria Government take

Three cases for India 50, 60

and 70%.

Nigeria 30%

The oil price thus initiated at $ 45/bbl (low),

$ 60/bbl (medium) and $ 75 (high) with an

escalation of 2.50% per year throughout the

project tenure (Figure 6); while in the fourth

case, the basic oil price considered was

$ 70/bbl followed by rise in 3.50% and drop in

price by 15% was envisaged after every five

years again rise from for next five years by

3.50% (Figure 6). As a result of this, the oil

price variation in this is between low and

medium range (Figure 6), and thus seems

more realistic in nature. Cumulative increment

in oil price from the first to final year of

production for first three scenarios is observed

to be 63 to 69% while for the sliding case oil

price because of volatility has remained the

same.

Fig. 5: Production Forecast used for Calculations. Annual Production is in Millions of Barrels.

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

MM

bb

l/Y

ear

Year

Production Forecast



Fig. 6: Oil Price Elasticity used in the Calculation.

No assumptions on quality of oil are made

here and thus question of oil price differential

is ruled out. Exploration and production cost is

considered as two times higher in Brazil,

Nigeria and Norway as compared to India

because of harsh environment and difficult

geographic locations. All calculations were

based on the terms and conditions given in

Tordo, 2009, Mmawke and Ajienka [19],

Mazeel [15], BCG benchmark [1], and

Echendu et al. [20].

Hurdle rate for calculation is considered as

uniform (Table 5). Production sharing was

considered in the case of India and Nigeria in

which the operator is allowed to recover the

cost of exploration and development after

commencement of commercial production.

The concept of Investment Multiple and R

factor on sliding scale was considered for the

calculation of profit petroleum. Though cost

recovery was considered as lower for India

(60%), government share in the three profit

petroleum was taken as 50, 60 and 70%

because of lower investment multiple. On the

other hand in case of Nigeria cost recovery

was allowed at higher rate (80%) because of

higher exploration and development cost and

government proportion was reduced to 30%

due to lower R values. Tax used in case of

India was 35% while the taxation in Nigeria

increases upto 67.5% with presence of 5%

VAT (Tax of 85% was not used because of

presence of cost recovery in present

calculations). Brazil has participation tax of

40% and corporate tax of 34% with royalty of

10%, while Norway has presence of corporate

tax of 28% and special tax of 50%. It is

allowed to use depreciation for deduction of

exploration and development cost.

Detailed spreadsheet analyses carried out for

these four scenario gave us comprehensive

knowledge of NPV for the operator (India

70%, Figure 7) and their proportion share

during project tenure (Figure 8). It is seen that

NPV received by the operator in case of India

is significantly lower in all scenario as

compared to all three counrties while NPV is

almost similar in Brazil and Norway which are

considered as representative cases of

consessionary system. In spite of higher cost

but because of lower R values, the NPV values

in Nigeria are much higer than India. It

45.00

50.00

55.00

60.00

65.00

70.00

75.00

80.00

85.00

90.00

95.00

100.00

105.00

110.00

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

$/b

bl

Year

Oil Price Variation L

M

H

A


Volume 2, Issue 1



apperas that government share in case of India

when considered 70 percent resulted in to

lower NPV for the operator though cost was

fifty percent less than Nigeria. Share of

government in case of consessioray system

was constant and varied between 64 and 65%.

Nigeria due to higher tax regime has

government share in between 60 and 70%.

Fig. 7: NPV Calculations for the Scenarios Developed.

COMPARISON WITH CHANGE IN

PRODUCTION SHARING BETWEEN

GOVERNMENT AND OPERATOR:

INDIAN CONTEXT Since the profitability of the operator was

minimum in case of India, we have attempted

another variation in sharing parameter.

Keeping all calculations common, variation in

the production sharing between Government

and Operator were tried at 70:30, 60:40 and

50:50 percent respectively.

The results are produced in Figures 9 and 10.

Though the oil price dynamics do not have

significant impact on variation in the

proportional share between government and

operator, if distribution of revenue including

cost recovery is considered, however change

in the share of government in production

sharing significantly modified the proportional

share of operator in distribution of one barrel

(Figure 9). The percent share was lowest in

high price (22%; with G 70% and O 30%) and

highest in low price (35%; with G and O 50%

each). Medium oil price scenario and oil price

sliding scenario have similarity in the percent

share of both government and operator.

When we try to understand profitability for the

operator at 15% hurdle rate, (Figure 10), then,

as expected profitability in terms of NPV

decreases with increase in the proportional

share of government. But it is also seen that

NPV is 207.37 million dollars, is high price,

even at the government proportional share of

70% while at low price even at 50%

proportional share NPV for operator is

192.25 million dollars. If this comparison

further extended to the NPV of different

regions (Figures 7 and 10) then even the high

price at 50% of government share in the

production yielded a profit equivalent to

306 million dollars which is higher than

Nigeria but lesser than NPV of Brazil and

Norway visualized in high price. This is in

spite of higher cost estimation for those

regions.



Fig. 8: Comparison in the Proportional Share between Government and Operator.

Fig. 9: Effect of Change in Production Sharing Percent on Revenue Earning for Government in

Different Oil Price Dynamics.

Fig. 10: Effect of Variation in Production Sharing on Profitability of Operator.

Calculated at 15% Hurdle Rate.


Volume 2, Issue 1



CONCLUSION An attempt is made to take an overview of the

regulatory systems, concessionary and

contractual, in different regions of petroleum

industry. The concessionary system though

considered as regressive is adopted essentially

by oil exporting courtiers with requirement of

higher cost because of greater risk and harsh-

difficult environment. Their tax regime is also

on higher side and in general the regulatory

system maintains a uniform sharing of 65 and

35% between government and operator.

Contractual system is inclusive of production

sharing and service contracts. Production

sharing is adopted in most of the countries

with low and medium cost estimations.

Though considered as progressive system but

profitability of the operators depends on

sharing of production between government

and operators. This is supported by oil price

dynamics. Another important aspect in this is

cost recovery which allows greater share for

the operator while elucidating distribution of

one barrel. Quantitative assessment of both

systems thus helped us to explain impact of oil

price and sharing of production probably the

most important factors in the discussion of

profitability of the operator.

ACKNOWLEDGEMENT Authors are thankful to Maharashtra Institute

of Technology for providing support and

facilities to carry out this work. Thanks are

particularly to Prof V D Karad for

encouragement and support. This work is

carried out with the support from ONGC

Chair, Department of Petroleum Engineering,

Maharashtra Institute of Technology, Pune,

India.

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Cite this Article Jadhav PB, Kshirsagar L. K. Evaluating

Performance of Production Sharing

Contract and Concessionary System:

An Overview and Assessment Based on

Examples from Selected Countries.

Journal of Offshore Structure and

Technology. 2015; 2(1): 41–54p.

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