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Formulation Of Profitability Of New Exploration Block

This report is aimed to summarise the understanding of Indian Petroleum fiscal system and its application in the NELP bidding round. The study has been undertaken considering one exploration blocks from an investor’s perspective. The study deals with the measurement of the profitability potential. The economic modelling has been carried out using the production profile data for offshore block MB/OSN/2005/4. The assumptions for the oil & gas prices as well as the exploration and development costs are as per the DGH documents. The sensitivity analysis has been carried out in order to find the impact of the oil & gas price, cost and the discount rate. The analysis shows the significant effect of oil price on the project economics.

1. Introduction

Government of India liberalized the Oil & Gas sector by introducing the NELP (New Exploration & Licensing Policy) regime in 1997. Under this regime, the participation of private players and foreign investors in Oil & Gas Exploration & Production was encouraged through offering of an attractive investment climate like 100% FDI participation permitted. This is turn has posed many opportunities for private players to increase their investment in to the Indian E&P sector.

NELP has provided a major impetus to exploration efforts in the country. According to the DGH statistics, the areas under exploration have increased more than 4 times to 48% of Indian sedimentary basin area, up from 11% before implementation of NELP. Implementation of NELP has resulted in 68 oil and gas discoveries made in 19 exploration blocks. Hydrocarbon reserves accretion has been more than 600 Million Metric Tonne of oil equivalent.

With the Indian hydrocarbon prospectivity looking impressive and with the NELP regime offering good commercial terms, a potential investor could stand to gain substantial investment returns by reaping the benefits if participating under NELP.

It is interesting to examine the investor’s approach towards assessing the profitability potential of an investment opportunity presented under the NELP. Such an examination would be important for two reasons. First that it would show the economic viability of undertaking a typical exploration project under NELP. In this project, an attempt has been made to undertake the economic assessment of exploration blocks awarded under NELP for the reasons cited above. The blocks which have been awarded are currently being operated by the Gujarat State Petroleum Corporation (GSPC), one of most successful E&P operators in India in recent years.

New Exploration and Licensing Policy (NELP) was launched in 1997 with an objective to accelerate exploration and production activities in the upstream sector and attract private investment in the sector. The policy framework provided a level playing field to the domestic public sector, private companies and foreign companies by offering similar regulatory, fiscal and contractual terms for exploration and production of oil and gas. This was a major change from the pre NELP regime under which ONGC and OIL were granted with "Petroleum Exploration Lease" on a nomination basis. Under NELP, the companies were awarded licenses for exploration blocks on the basis of international competitive bidding. In order to maintain greater transparency in the bidding process, the award of blocks is made on the basis of quantitative bid evaluation criteria, which are made public in the notice inviting offers. The salient features offered under the NELP policy can be summarized as under:

Fast track approval mechanism through single window Empowered Committee of Secretaries.

Foreign participation permitted up to 100%.

Model Production Sharing Contract ("PSC") to aid in negotiation.

No commitment for any minimum expenditure.

The limit for recovering cost recovery is biddable up to 100%.

No signing, production or discovery bonus is to be paid.

Contractors are free to market oil and gas in the domestic market at market determined price.

Securitization of participating interest for raising project finance is allowed.

There is no bank guarantee requirement for the work programme.

Participation is permitted through unincorporated joint ventures

The contract assures fiscal stability (clauses for change in tax laws).

Transactions under production sharing contracts expressed in USD.

(Source: DGH, MOPNG)

NELP has provided a major impetus to exploration efforts in the country. According to the DGH statistics, the areas under exploration have increased more than 4 times to 48% of Indian sedimentary basin area, up from 11% before implementation of NELP. Implementation of NELP has resulted in 68 oil and gas discoveries made in 19 exploration blocks. Hydrocarbon reserves accretion has been more than 600 Million Metric Tonne of oil equivalent.

With the Indian hydrocarbon prospectively looking impressive and with the NELP regime offering good commercial terms, a potential investor could stand to gain substantial investment returns by reaping the benefits if participating under NELP.

Figure 1 P&D Department Activities

[Source: GSPC P&D Department]


Develop an economic model that supports company’s investment decision making process for the upstream projects company has considered to be potentially value adding to its upstream portfolio. The methodology followed is to critically examine the impact of project specific parameters on the techno-economic feasibility of upstream projects undertaken by company. To meet this aim, this case study has examined one upstream project (see Table 1) undertaken by company with respective techno-economic evaluation objectives shown below the exhibit.

Table 1 List of Block Considered

Upstream Project

Operator & Partners

Acreage Awarded




(NELP Round V)


Techno economic Evaluation Objectives:

Project was evaluated assuming the evaluation was at the pre-bidding stage and the operator sought to generate block profitability potential through economic analysis.

In order for commencement of study, the following study objectives were followed


Review literature of global petroleum fiscal systems to examine key fiscal terms favourable to investors

Review of India’s NELP regime through examination of bidding evaluation criteria offered under the forthcoming licensing round.

Building of an economic model in line with the design and structure of the Indian Petroleum fiscal regime or NELP PSC

Carrying out economic modelling on the above project to simulate project economics under the hypothetical cases specified

Undertake analysis and interpretation of results to provide the operator with information necessary for making the effective investment decision i.e identify whether the project is a value adding opportunity and complements company’s upstream portfolio

Draw key conclusions and recommendations after discussion and analysis of results.



Literature Review

This chapter aims to address the first study objective i.e. Review literature of global petroleum fiscal systems to examine key fiscal terms favourable to investors. This is done with an objective to examine the typical manner in which an oil investor examines an investment opportunity in the upstream sector.

Petroleum Fiscal System

The petroleum fiscal systems exist for the negotiation between the host government and oil companies. These fiscal systems are numerous due to the scope of flexibility and change in economic as well as political conditions.

The objectives of a government are to ‘maximize the wealth from its natural resources by encouraging appropriate levels of exploration and development activity and get as high share of the profit as possible’. The objectives of oil companied are ‘build equity as well as increase shareholder interest and maximize the wealth by finding and producing oil & gas reserves at the lowest possible cost and the highest profitable margin.

The petroleum fiscal system assists in achieving mutuality of interests between the two parties by creating a win-win situation for between government as well as oil companies. This can be achieved by enabling provisions for Recovery of costs & Division of profits arising from the petroleum operations. The bargaining relationship depends mainly on profitability and risk. It is crucial to relate the fiscal packages on the geological basis and where on the geological learning curve that province is. The figure shows the geological learning curve.

Recoverable Years


Figure 2- Geological Learning Curve

[Source: Slatsveen, 2005]

The petroleum fiscal system can be classified in two categories namely: Concessionary system and Contractual system. Concessionary system is where private ownership of mineral resources is allowed once they are successfully exploited and produced by a company. The state is liable to collected the economic rents (explained later) generated through taxes and royalties. This type of system is followed in Western countries such as United States, UK, Norway, Brazil etc.

The contractual systems are where the government will retain ownership of the petroleum resources produced by a company but will guarantee a return of the share of production or revenue from the sale of oil & gas depending upon the terms negotiated in the contractual arrangement in the PSC (Production Sharing Contracts). Another type of contract is the Service Contract (SC), where the contractor is given a fee for its Exploration & Production activities. So, in the PSCs the contractors are awarded in kind whereas in SCs, the contractors are awarded in Cash. SCs can further classified between Pure Service contract and Risk Service contract. It depends upon whether the fees are based on flat rate (Pure) or on profit (Risk). Contractual arrangement is common in developing countries like China, India, Angola, Indonesia etc. The rationale for such system is that the natural wealth is the property of the sovereign state and should therefore be used first and foremost for the benefit and welfare for its citizens.

Figure 3- Various Petroleum Fiscal Arrangements

[Adapted From Johnston, 1994

Economic Rent

The difference between the value of production and the costs to extract is known as economic rent in the petroleum industry (Johnston, 1994). The costs consists of Exploration, Development as well as production costs. The economic rent also refers to the ‘excess profits’ associated with the surplus profit remained after all costs are recovered. It is then this excess profit which is shared between a host government and the petroleum industry.

Host governments collect as much economic rent as possible through upstream fiscal instruments namely royalties, taxes, bonuses etc. One of the most challenging and interesting area for examination of fiscal system with regard to collection of economic rent lies within the negotiation process of the fiscal terms, which refer to the agreement between host government and oil companies to explore, develop and produce hydrocarbons. These terms are negotiated in two fundamental types of petroleum fiscal systems (Slatsveen, 2005).

The challenge is to how to capture rent when many of the exploration ventures are failures. Thus, the profit margins should be large enough to accommodate these failures.

Fiscal Components of the fiscal systems

Fiscal instruments are employed to collect economic rent regardless of the classification of the fiscal regime. The concessionary system has at the fundamental level, the following components.

Royalty- It is the secure minimum payment based on gross revenue from sale of crude oil and natural gas.

Deductibles- They are the operating costs and depreciation of the capitalised assets, amortisation.

Tax-It is deducted from the taxable income (Gross Revenue- All deductions). This is generally at the country’s basic corporate tax rate which is higher than the regular income tax.

Cost Oil/Cost Petroleum- The exploration, development and operating costs which can be recovered depending on contract terms are known as Cost oil or Cost Petroleum.

Profit Oil/Profit Petroleum- The profit remaining after recovering costs and payment of Royalty is known as Profit Oil or Profit Petroleum. It is shared between the host government and the contractor depending on the contract terms.

Production Sharing Contracts

The production sharing contracts and concessionary system may differ in terms of ownership of the resource, but financially they have the same implications (Johnston, 1994). In this study, we would be focusing on Indian PSC regime as set out in the second objective i.e. Review of India’s NELP regime through examination of bidding evaluation criteria offered under the forthcoming licensing round. India introduced New Exploration & Licensing Policy (NELP) in 1997, in order to open the market for private players. There have been seven bidding rounds up to now and about 167 PSCs have been signed till date. The NELP-8 round has also been declared as on April 9, 2009. Government has also released Petroleum Tax Guide (PTG) in 1999 to clarify the Tax implications for the operators and investors.

The financial implications of the production sharing contracts can be expected as shown in the figure.

Figure 4- Flow Diagram for PSC

[Source: Venugopal, 2005]


The royalties are the fixed minimum payment levied on the production of the reserves. It creates an up-front revenue stream which is assessed on volume or value of reserves (Venugopal, 2005).

The royalties are often considered a disincentive to investment and are typically only deductible in home jurisdiction. They might cause investment distortions as it leads to payment from the Gross Revenues rather than Net Income, but can give early revenues to the Government as well gives relatively stable incomes to the Government.

Four major disincentive effects of royalties

It can reduce profitability of a field as the burden of Royalty decreases the contractor’s take.

The pay-back or the recovery of costs can be slower with higher royalty levied.

A field viable on pre-tax basis can be made non-viable after royalty deductions.

The instances of premature abandonment increases as the royalties are levied on gross revenues.

Royalties can be fixed or on the biddable terms. In the Indian PSC regime, the royalties are fixed, levied on the basis of the hydrocarbon type and by on land and offshore areas. However, in the more sophisticated PSCs it can be on the sliding scale of revenues.

Cost Oil

A portion of produced oil that the operator applies on an annual basis to recover defined costs specified by a production sharing contract is known as Cost Oil (Schlumberger Oilfield Glossary). The cost oil can be zero to hundred percent and it is often biddable. The revenues remaining after the cost recovery is shared between the contractor and the host government. The cost recovery works in two ways: At the pace of development costs incurred or based on the amount of oil production available for cost recovery. Typically, the slower cost recovery can cause following effects:

Might cause investment distortions due to the depreciation rules; the timing of the recovery of investments costs.

Due to the discounting and inflationary effect the tax share of the costs is lower than the tax share of incomes.

A fiscal regime that allows cost recovery up to 100 percent is favoured by the investors.

Profit Oil

Under the production sharing contract, the amount of production remained after deducting cost oil production is divided between the investor and the host government. This remaining production is known as profit oil (Schlumberger Oilfield Glossary). It is biddable and negotiable under the PSCs. The contractor’s share of profit oil is usually subject to taxation depending on the company’s prevailing income tax rate. The contractors generally bid for profit sharing split based on the geological potential of the field. Thus, it is not the governments that always determine the appropriate divisions of the profit; the oil companies help define what the market can bear (Johnston, 1994). The profit oil split is particularly effective when it is applied on an incremental basis on varying field sizes.

The profit petroleum is shared between the government and the contractor depending on a Pre-Tax Investment Multiple (PTIM) ratio. PTIM ratio is calculated using the Contractors’ Cash Flow in the previous year and is determined by dividing the accumulated Contractors’ Net Cash Income by Accumulated Investment by the Contractors. Such ratio for the profit oil split would ensure the accommodation of unexpected changes in oil prices (Venugopal, 2005). This also ensures that government share is low in initial years when the revenues are less and recovery is slow. As the ratio increases, the share of profit to the government increases.


Taxes are generally levied on the contractor’s share of profit oil and this is usually at the country’s prevailing corporate tax rates. Taxes are more attractive to investors than the royalties as it is based on the profits unlike the royalties, which are based on the gross revenues. The tax incentive can be definitely more useful for the contractors in the case of discovery and subsequent production. The tax holidays applied in the early years can make a field more viable in terms of present value (Johnston, 1994). Tax holidays represent surplus NPV available in initial field production years.


1. The Government share of Profit Petroleum will be calculated for the purpose of fiscal evaluation under three Scenarios of production profile and prices of oil and gas, such as Low, Most likely and High.

2. The block-wise Production profile for computation of Government Share is given . The Production profile are assumed only for the purpose of fiscal evaluation and are not indicative of actual or expected production.

3. Following nine scenarios, based on production profiles and prices, will be considered for evaluation of fiscal package based on the weighted average of Net Present Value (NPV) of Government share of Profit Petroleum under each scenario.

4. Weights will be assigned for NPV of Government Share of Profit Petroleum for the 9 scenarios as under for all types of blocks:

5. The exploration cost and development cost assumed for the purpose of fiscal evaluation is given in Annexure-II. Production cost is assumed at US $ 3 per barrel of oil and oil equivalent gas (O+OEG). The costs are assumed only for the purpose of fiscal evaluation and are not indicative of actual or expected cost.

6. First seven years are assumed for exploration phase for Type S blocks & onland blocks (other than frontier area blocks) and shallow water blocks. The Production is assumed to commence from 8th year. For the purpose of evaluation, it is assumed that exploration cost is spread over @ 10%, 10%, 20%, 20%, 20%, 10% and 10% over the 7 year period of exploration phase and development cost is equally spread over in 7th and 8th year.

7. First eight years are assumed for exploration phase for Frontier Area onland blocks and Deep water blocks. The Production is assumed to commence from 9th year. For the purpose of evaluation, it is assumed that exploration cost is spread over @ 10%, 10%, 20%, 20%, 20%, 10%, 5% and 5% over the 8 year period of exploration phase and development cost is equally spread over 8th and 9th year.





To accomplish the techno-economic objectives (as below) for the respective upstream project considered by GSPC, an economic based model was developed guided by the literature review discussed.

Project 1 being an exploration block MB-OSN-2005/6, was evaluated assuming the evaluation was at the pre-bidding stage and the operator sought to generate block profitability potential through economic analysis.

Measuring the Profitability Potential

The section deals with examining the profitability potential of an exploration prospect in the block MB-OSN-2005/6.

Company needs to determine the profitability potential of this block located in Mumbai Offshore basin. The sensitivity of the Post Tax Net Cash Flow (PTNCF) to variation in Oil prices, Production costs and discount factors in three likely reserve sizes (reserve sizes as given by the DGH) was examined using following method of sensitivity analysis generation (Nath, 2007):

A base case is specified through the variable set and compute.

The variables are then changed to factor in various scenarios that are likely to occur.

The results for change in factor are plotted graphically to analyse the sensitivity of the project with respect to change in each factor.

Thus the graphical relation in fiscal system analysis is employed.

1) Discounted Net Cash Flow (Before Tax & After Tax) - Cash flows are discounted at a certain rate to account for time value of money. The greater the value of ‘free net cash flow’ generated, more profit can be generated from the field.

2) Net Present Value (NPV) - NPV is the sum of discounted Net Cash Flows and represents a value which factors in the time value of money. If NPV is positive, the project should be accepted.

3) Internal Rate of Return (IRR) - IRR is the discount rate at which the Net Present Value is zero. Internal Rate of return indicates the project efficiency and robustness. If the IRR is higher than the discount rate i.e. opportunity cost of capital, the project should be accepted. If IRR is lower, the project should ordinarily not be considered for further development.

4) Government Take – Sum of the components of government take namely Royalty, Profit Oil and Taxes (Johnston 1994). This shows the impact of the fiscal system on the cash flow of the oil/gas field. Take is represented as a percentage of the total project net cash flow.

5) Payback period – The time until cumulative net cash flow becomes positive.

Prospect at a glance

Project Name- Hypothetical Development of Block MB-OSN-2005/6


Block Name- MB-OSN-2005/6 in the Mumbai Offshore Basin

Production reserves-

Low Production- 103.4 MMbbl

Medium Production- 129.25 MMbbl

High Production- 155.10 MMbbl

Economic Modelling

Economic modelling is carried out considering the fiscal regime prevailing in India under the NELP. The results show the Pre-Tax and Post-Tax Net Cash Flows under different scenarios of Oil Price, Production profiles as well as Production costs. Further analysis is carried out in the subsequent chapters to understand effects of Government take as well as the exogenous variables such Oil Prices, Production Costs and the Production profiles.

The cash flow modelling is prepared using the methodology utilised by Venugopal.S (2005). Accordingly a representation of the Cash flow model is given in the following figure.

Figure 5- Flow Diagram for Cash Flow Model

[Venugopal, 2005]

Data used for the modelling

The three cases are taken for the production profiles: Low Production, Most likely production and High Production. The total production output is as under:

Case 1- Low Production: 103.40 MMbbl

Case 2- Most Likely Production: 129.25 MMbbl

Case 3- High Production: 155.10 MMbbl

The variables in each case are Oil & Gas Price and Production Cost. It is assumed that the Oil & Gas prices are changing together, i.e. there is a correlation between the prices of the oil & gas prices. This is assumed as the gas prices have historically been linked intrinsically to the oil prices .The summary of variables is listed in the table below:


Oil Prices


Oil Price1


Oil Price2


Oil Price3


Gas Prices


Gas Price1


Gas Price2


Gas Price3




Cost 1


Cost 2


Cost 3

70Table 2 Summary of Assumptions

Summary of the expenditures

The expenditures assumed here are as per the data given by DGH (Directorate General of Hydrocarbon) for the block MB-OSN-2005/6 given in the pre-bidding documents. These are mainly the Exploration & Development costs. These costs are summarised as follows:


Exploration Costs



Development Costs



The exploration costs are incurred during the first seven years of the project life. These costs are taken according to DGH guidelines. The development costs are incurred in the seventh & eighth year of the project.





















The prevailing rate of Royalty has been considered for the calculation of the Royalty paid. The rates of Royalties are as shown in the table. Since, this is a shallow offshore block the corresponding rate has been considered.




Deep water



On land



Shallow Offshore



The tranches of Profit sharing is taken according to NELP-V formulae. The profit sharing percentages to be offered were as per the terms negotiated in the PSC of this block signed between GSPC and the Government of India.

Profit Sharing Tranches

% to GOI

PTIM 0 - 1.5


PTIM 1.5 - 2.0


PTIM 2.0 - 2.5


PTIM 2.5 - 3.0


PTIM 3.0 - 3.5


PTIM > 3.5


Having acquired the necessary information as discussed in 3.1-Part-1, a cash flow model has been appended in Annexure [A] to this report. Results of the economic modelling have been discussed in the subsequent chapter.



Analysis & Interpretation

Summary of results

The results from the cash flow model yield the Net Present Value (NPV) which is the sum of all discounted Net cash flows (Before Tax & Post Tax). Oil companies use the NPV values to measure the profitability potential of the project. Positive NPV values are considered to render the project economic and therefore accepted for project development. The NPV results under the different scenarios has been shown below and the detailed cash flow mode has been appended in Annexure A

Discounting for NPV


IRR (%)


Nominal Pre-Tax Net Cash Flow



Pre-Tax Net Cash Flow @ 10%


Pre-Tax Net Cash Flow @ 20%


Pre-Tax Net Cash Flow @ 30%


Pre-Tax Net Cash Flow @ 40%


Pre-Tax Net Cash Flow @ 50%



Nominal Post-Tax Net Cash Flow



Post-Tax Net Cash Flow @ 10%


Post-Tax Net Cash Flow @ 20%


Post-Tax Net Cash Flow @ 30%


Post-Tax Net Cash Flow @ 40%


Post-Tax Net Cash Flow @ 50%



Analysis of Results

The results show that the Post Tax Contractor Net Cash Flow (PTNCF) is positive in the medium and high price scenario. The general trend of the NPV can be shown as the chart-1.

Chart 1 Post Tax Net Cash Flow

The chart shows that the PTNCF increases with each production profile for the similar Oil & Gas price and Production costs.

Price Sensitivity

The above figure shows that the project viability largely depends on the Crude Oil & Gas prices. Since the field is having large oil reserves compared to the reserves of Natural gas, the oil price variation becomes critical. The chart-2 shows the Oil price sensitivity. The resultant chart shows that as the production increases, the sensitivity to the oil price increases. This is apparent from the chart as the slope of the curve gets steeper with each production profile i.e. the slope of the curve for the low production is less than the high production profile price sensitivity. This shows that as the production increases the project viability and the revenue is more vulnerable to the price variation.

Chart 2 Price Sensitivity

Sensitivity for low production

The cost sensitivity decreases with the higher production reserves. This is mainly because with higher production profiles, the increase in revenue offsets the loss due to higher costs and vice-versa. This is apparent by the negative slop of the curve and the data point converges as the production cost increases.

Chart 3 Sensitivity for case 3

The chart-3 shows the sensitivity with the change in production profile.

Discount Rate Sensitivity

Each cash flow must factor in the ‘time value of money’; to know the value of the project in today’s money considering the future risks represented by factors such as inflation (increases costs and reduces purchasing power). Discounting is done to factor in this risk element to thereby generate the discounted net cash flows, adjusting for the effects of inflation. Chart-4 shows the NPV value at the various discount rates, plotted at the each of the production profile with base case scenario of Price and cost. The chart shows that the curves of various production profiles diverge as the discount rate for the NPV calculation increases.

Chart- 4 Discount Rate Sensitivity

IRR (Internal Rate of Return)

The internal rate of return (IRR) is the discount rate at which the NPV (Net Present Value) of the project equals to zero. IRR indicates the discount rate below which all investment will be with positive NPV. The results for the IRR are calculated in the above table.

Pay-Back Calculation

The Pay-back period is defined as the time required by the project’s positive net cash flow to recoup initial capital expenditure (Venugopal, 2005). The chart shows that the pay-back period decreases with the increase in the production profile. The chart for payback is shown in the Appendix 5.

Effect of Fiscal Components

The various fiscal components like Royalty, government share of Profit oil, Taxes and cost recovery affects the project economics. The Post Tax NCF (PTNCF) is the residual left after deducting the above components from the gross revenue. The contractor is therefore more interested in maximizing the PTNCF from the project.

It is however, interesting to note how the change in production profile impacts these components. While, it is obvious that the absolute figure increases with the increase in the production reserve, the more interesting notion is the relative variation of each component.

Chart 5 Effect of Fiscal Components- Low Production

The chart of percentage contribution of each component shows that the share of Profit oil decreases in percentage with the increase in production reserves. This is in-line with the criticism of NELP regime being regressive rather than progressive.

Chart 6 Effect of Fiscal Components- Most Likely Production

Also, the percentage of government share increases in the later years as the production declines. The faster cost recovery ensures lower risk to the contractor but the net cash flow to the contractor decreases in the later years.

Chart 7 Effect of Fiscal Components- High Production



Conclusions & Recommendations

This report could hopefully draw meaningful conclusions towards determining profitability potential of the block as considered. The author’s learning has been enhanced in case of recommending the effects of each parameter on the final contractor Net Cash Flow.

The exercise was dealt with analysis and measurement of profitability potential of an exploration block.

From the analysis it can be concluded that, the project economics for an exploration prospect is the most sensitive to the oil price. It is also evident that the project seems viable with a reasonably good IRR after multiplying the probability of occurrences of each scenario.

The project is highly vulnerable to Oil Price uncertainty as the production increases the project viability and the revenue is more vulnerable to the price variation.

The payback period tend to decrease with the increase in the production. The payback period for the high production is quite less.

The contactor is interested in increasing the post tax net cash flow.


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