The Economics of Upstream Petroleum Project

(2009)

Benny Lubiantara

1. Introduction

Projects in the upstream petroleum industry are characterized by large capital investment, in

addition to that, there some other factors that make this sector different from other investment

opportunities, such as: time lag between expenditures and revenues, high levels of uncertainty

& risk, and of course, most of the projects involve high technology.

2. The Life Cycle of Petroleum Projects 1

The phases of typical oil and gas project can be described as follows: Pre Licensing

Prospecting, Mineral Acquisition/Contracting, Exploration, Appraisal, Development,

Production, and Closure.

Pre Licensing Prospecting

Pre-license prospecting typically involves the geological evaluation of relatively large

areas before acquisition of any petroleum rights.

Mineral Acquisition/Contracting

Mineral interest acquisition involves the activities related to obtaining the mineral

rights to explore for, develop and produce oil or gas in a particular area. Typically the

oil and gas company receives a mineral interest if the negotiation is successful. A

mineral interest is an interest in a property that gives the owner the right to share in the

proceeds from oil or gas produced.

Exploration

1 Wright, Gallun, International Petroleum Accounting, 2005, p.8 -18

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Exploration is detailed examination of an area for which a mineral interest has been

acquired. Generally, the geographical area has demonstrated sufficient potential to

justify further exploration to determine whether oil and gas are present in commercial

quantities.

Appraisal

Appraisal phase involves confirming and evaluating the presence and extent of

reserves that have been indicated by previous Geological and Geophysical testing and

exploratory drilling. Exploratory wells may have found reserves; however, appraisal is

necessary in order to justify the capital expenditure related to the development and

production of the reserves – in other words confirming that the reserves are

commercial.

Development

This phase involves undertaking the steps necessary to actually achieve commercial

production. Typically this have involves: drilling additional wells necessary to

produce the commercial reserves, constructing platforms and gas treatment plans,

constructing equipment and facilities necessary for getting the oil and gas to the

surface and for handling, storing, and processing or treating the oil and gas,

constructing pipelines, storage facilities and waste disposal system.

Production

The production phase involves extracting the oil and gas from the reservoir and

treating the oil and gas in order to assure that it meets marketing standards.

Closure

At the end of the productive life of an oil and gas field, the site typically must be

restored to its pre-existing condition. Accordingly, the closure phase includes plugging

and abandoning wells, removing equipment and facilities, rehabilitating and restoring

the operational site and abandoning the site.

3. Basic Concept of Oil and Gas Fields Development

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The purpose of this section is to briefly describe the basic concept of field development. Plan

of Development (POD) is the document submitted by the International Oil Companies to the

authorized government body for their approval. The POD documents provide a brief

description of the technical information on which the development is based.

Conceptually, oilfield (or gas field) plan of development cover aspects, such as: reserves, field

scenario, drilling, production forecast, field facilities and abandonment/site restoration as

shown in figure 1.

Figure 1. Elements of Oil Plan of Development

3.1. Reserves

Reserves are defined as those quantities of petroleum which are anticipated to be

commercially recovered from known accumulations from a given date forward. According to

Society of Petroleum Engineers (SPE)2, reserves can be divided into three categories, namely:

proved, probable and possible reserves.

Proved reserves are those quantities of petroleum which, by analysis of geological and

engineering data, can be estimated with reasonable certainty to be commercially recoverable,

2 SPE Guidelines for the Evaluation of Petroleum Reserves and Resources, 20013

from a given date forward, from known reservoirs and under current economic conditions,

operating methods, and government regulations.

Probable reserves are those unproved reserves which analysis of geological and engineering

data suggests are more likely than not to be recoverable. In this context, when probabilistic

methods are used, there should be at least a 50% probability that the quantities actually

recovered will equal or exceed the sum of estimated proved plus probable reserves.

Possible reserves are those unproved reserves which analysis of geological and engineering

data suggests are less likely to be recoverable than probable reserves.

In the POD documents, the reserves that is normally used for technical design as well as the

economic calculation are the proved reserves, surely, some companies have their own

methods or formula for further discount to reflect the reserve‘s risk

3.2. Field Scenario

It contents a brief review that sets out clearly the principles and objectives when making field

management decisions and conducting field operations and, in particular, how economic

recovery of oil will be maximized over field life. Field development scenario is one of the

most important sections in the plan of development; it also discusses other aspects, such as:

whether the field development will be in phases or in full development, production

mechanism, number of wells, etc.

3.3. Drilling

The oil wells are drilled with the main objectives to obtain the information and to produce the

hydrocarbon (oil and/or gas). Drilling operation are carried out during all stages of the project

life cycle, expenditure for drilling represent a large portion of the total project’s capital

expenditure (Capex); typically 20-60%3. Therefore, drilling aspects are also covered in the

plan of development documents.

3.4. Production Forecast

3 Frank Jahn, Mark Cook, Mark Graham, Hydrocarbon Exploration and Production, 2nd Edition, 2008, p. 47

4

Based on the reserves estimated (proved reserves), field scenario and drilling program,

production forecast can be developed. Typical production profile can be seen in figure 2. The

production will reach a peak level after one or two year of start-up, it will stay peak for certain

period which is called “plateau period”, the field will then naturally decline due to lower

pressure support, the declining production will continue until the field reach its economic

limit4.

Figure 2. Typical Production Profile

3.5. Field Facilities

Wherever the oilfield is located (offshore or onshore), the surface facilities is one the most

important factor that have to be considered in developing the field. Jahn, Cook and Graham

(2008)5 write that:

“ ….Oil and gas are rarely produced from a reservoir already at an export

quality; more commonly, the process engineer is faced with a mixture of oil, gas

and water as well as small volume of substances, which have to be separated and

treated for export or disposal. Surface facilities have to be designed to cope with

produced volumes which change quite considerably over the field lifetime,

4 The economic limit is the level of production rate (in barrel oil per day) where the net cash flow of the field equal to zero. The continue production beyond this point will cause economic loss.

5 Frank Jahn, Mark Cook, Mark Graham, Hydrocarbon Exploration and Production, 2nd Edition, 2008, p. 265

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whilst the specification for the end product, for example export crude, generally

remains constant. The consequences of a badly designed process can be, for

example, reduced throughput or expensive plants modifications after production

start-up. However, building in overcapacity or unnecessary process flexibility

can also be very costly.”

In most fields, the surface facilities can be grouped into four parts: wells, gathering system,

processing plant and export facilities. Surface facilities are the main component of capital

expenditure in the field development.

3.6. Abandonment and Site Restoration

Eventually every field development will reach the end of ist economic life time. If options for

extending the field life have been exhausted, then abandonment and site restoration (also

called decommissioning) will be necessary. Decommissioning is the process by which the

operator of an oil or gas installations will plan, gain approval and implement the removal,

disposal or re-use of an installation when it is no longer needed for ist current purpose.

Decommissioning cost refer to the future costs associated with the dismantlement,

abandonment, restoration and reclamation of oil and gas wells, properties, and other facilities,

such as plants, pipelines, and storage facilities6. The cost of decommissioning may be

considerable, and comes of course at the point when the project is no longer generating

funds7.

4. Types of Petroleum Arrangements

6 C.J Wright, R.A Gallun, International Petroleum Accounting, 2005, p. 60

7 Richard Seba, Economics of Worldwide Petroleum Production, 3rd Edition, 2008, p. 419

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The principal forms of contract that are currently employed between host country and

petroleum companies can be grouped into three broad categories: the concession agreement,

the production sharing contract and the service contract as shown in Figure 58.

Figure 3. Petroleum Arrangements

McMichael and Young expanded the Johnston’s classification in Figure 4 by including three

additional types of agreements; purchase contracts, loan agreements, and revenue sharing

contract9.

Figure 4. SPE Petroleum Arrangements

8 Daniel Johnston, International Fiscal System and Production Sharing Contract, Penwell, 1994, p. 25

9 McMichael and Young, Chapter 9, Reserves Recognition under Production Sharing and Other Non-traditional Agreements, in SPE Guidelines for the Evaluation of Petroleum Reserves and Resources, 2001, p.118

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4.1 Concessionary System

The concession was the original system used in world petroleum arrangements, and it is still

the most widely used today. Under a concession, Contractor is given the exclusive right to

explore for hydrocarbon in the given concession area, to produce any discovery therein, to

acquire ownership of the oil and gas ultimately produced, and to freely dispose of all such

production. In fact, many improvements have been made to the basic and traditional

concession to update it and achieve the objectives of government policy. These improvements

are mainly related to an increase in the government take through additional payments (high

royalty, excess profit tax) and a better control of petroleum activities by introduction of state

participation10,11

The main features of the early concession are as follows:

10 Le Leuch, Chapter 5: Contractual Flexibility in New Petroleum Investment Contract, in Beredjick & Walde, Petroleum Investment Policies in Developing Countries, 1988. p. 89

11 King & Spalding LLP, An Introduction to Upstream Government Petroleum Contract: Their Evolution and Current Use, OGEL, 2005, p. 15

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o International Oil Company (IOC), at its own risk and expense, generally has the

exclusive right to explore for and exploit petroleum reserves in the concession

area.

o The IOC owns the production from within its concession area

o The IOC pays the royalty either in Cash or Production.

o The IOC pays taxes to the host country on profit it derives from the production

o A Great disadvantage to the host government of the concession agreement is that it

greatly limits the involvement by the host government.

In the modern concession12, the concession area is only limited for certain block (instead of

the whole country or province which was normally found in the early type of concession

agreement), the period is generally shorter13. Unlike the earlier agreements, the modern

concession contains clauses specifically imposing a scheme of development based upon a

monetary commitment for each year of the term. A company holding concession is obligated

to a work program and to the relinquishment of a portion of the acreage on a specified

schedule14.

4.2 Production Sharing Contract

The concept of production sharing originated in Indonesia where the first agreement of this

type was signed in 196615; the concept is now used in numerous countries. It is important to

remember that the production sharing concept was designed to give the government a greater

degree of control over the operations of oil companies. The success of the production sharing

concept is mainly due to political motivations, because under the agreement the oil company

is referred to as a contractor and is only entitled to a portion of the production16.

12 It is now also known as a “Royalty/Tax” system.

13 20 years instead of 60 years in average

14 Smith, Dzienkowski, A Fifty-Year Prospective on World Petroleum Arragements, OGEL, 2005, p.36

15 The first PSC was signed in 1966 between the Independent Indonesia American Petroleum Company (IIAPCO) and The State Oil Company Permina (now PERTAMINA).

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In a production-sharing contract between a contractor and a host country, the contractor

typically bears all risk and costs for exploration, development, and production. In return, if

exploration is successful, the contractor is given the opportunity to recover the investment

from production, subject to specific limits and terms. The contractor also receives a stipulated

share of the production remaining after cost recovery, referred to as profit hydrocarbons.

Ownership is retained by the host government; however, the contractor normally receives title

to the prescribed share of the volumes as they are produced17.

The main features of Production Sharing Contract (PSC) are as follows:

o The IOC is appointed by the host government as the contractor for certain area.

o The IOC operates at its sole risk and expense under the control of the host

government.

o Any production belongs to the host government

o The IOC is entitled to a recovery of its costs out of the production from the

contractual area.

o After cost recovery, the balance of production is shared on a pre-determined

percentage split between the host government and the IOC.

o The income of the IOC is liable to taxation

o Equipment and installations are the property of the host government

4.3 Service Contract

16 Le Leuch, Chapter 5: Contractual Flexibility in New Petroleum Investment Contract, in Beredjick & Walde, Petroleum Investment Policies in Developing Countries, 1988. p. 90

17 See McMichael and Young (2001), p.119

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The term service contract encompass those various contract in which the host government

contract with a service company or an International Oil Company for the performance of

services related to the exploitation of petroleum resources18.

The risk service contract appears similar to the production sharing contract but differs in

certain important matters. Its basic distinctive feature is that it reimburses the contractor in

cash, not in crude oil, although it may have provisions permitting the contractor to buy back

an amount of crude oil at an international selling price equivalent to the amount to be paid to

the contractor19.

4.3.1 Pure Service Contract

A pure-service contract is an agreement between a contractor and a host country that typically

covers a defined technical service to be provided or completed during a specific period of

time. The service company investment is typically limited to the value of equipment, tools,

and personnel used to perform the service. In most cases, the service contractor's

reimbursement is fixed by the terms of the contract with little exposure to either project

performance or market factors. Payment for services is normally based on daily or hourly

rates, a fixed rate, or some other specified amount. Payments may be made at specified

intervals or at the completion of the service. Payments, in some cases, may be tied to the field

performance, operating cost reductions, or other important metrics20.

4.3.2 Risk Service Contract

These agreements are very similar to the production-sharing agreements with the exception of

contractor payment. With a risk service contract, the contractor usually receives a defined

share of production (in kind). As in the production-sharing contract, the contractor provides

the capital and technical expertise required for exploration and development. If exploration

efforts are successful, the contractor can recover those costs from the sale revenues and

receive a share of profits through a contract-defined mechanism.

5. “Project Based“ System

18 Ramadan, Zekri, Development of a Petroleum Contractual Strategy Model, SPE 84852, 2003, p. 4

19 See Le Leuch (1988), p. 92

20 See McMichael and Young (2001), p.11911

Before we move to the detail project cash flow analysis, it is very essential to understand the

relation among the reservoir, property (contract terms) and the project itself. Figure 5 help us

to clarify the concept.

Figure 5. The Project Based System21

The current SPE system is based on project (“project based system”); there are three

elements: Reservoir, Project and Property (Lease). Reservoir is “basic resource entity” where

we have to estimate the volume of the reserves (“in-place volumes”), Project is “basic entity”

for investment tracking, production and cash flow schedule. When the company invest, they

surely expect to produce certain quantities of the reservoir. Project involves extraction

activities and any necessary process needed before the product is sent to the market

(consumer). Property or lease is related to the ownership and type of contract as well as the

terms and conditions.

6. Oil (Gas) Field Economics

21 Source SPE, Oil and Gas Reserves Committee (OGRC)12

Figure 6 shows the general concept of constructing the project economics model, there are

three categories of information needed; first, the sub-surface and surface information, second,

fiscal terms and conditions and third, the oil or gas price assumptions.

Sub-surface information include the estimated amount of reserves, expected production

profile, number of development drilling wells, etc. Surface facilities include the production

facilities (onshore or offshore), pipeline, storage, etc. fiscal terms are depending upon the type

of contract as well as the terms and conditions which can be found in the detail contract.

Generally, the oil price assumptions are provided by head office of the IOC, in many cases, it

may also be assumed that oil prices are flat during the contract period or in other cases, it is

assumed that the prices are escalated.

Figure 6. Constructing the Field Economics Model

Production Rate

Facilities Design

Capex Opex

Fiscal Terms

Oil Price

Field Economics

Reserves

7. Typical Economic Assumptions and Data Input

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Production & Cost:

Exploration: X years, Development (drilling, facilities, etc): Y years

Production period: 20 – 30 years

Reserves recovered during contract period: XYZ million barrels

Production decline rate : X%

Operating / Production Cost = X $/barrel

Finding & Development Cost =X $/barrel

Discount rate: 10% - 15%

8. Steps for Constructing Cash Flows

First, let us begin with two main types of upstream petroleum contract, namely: Concession or

Royalty Tax (R/T) and Production Sharing Contract. (For the purpose of this illustration,

these two type of contracts are selected, even though the case for service contract is not

discussed, the calculation steps are basically the same, in many cases, in fact, the calculation

for service contract model tends to be more simple).

The main difference between Concession or Royalty Tax (R/T) and Production Sharing

Contract as shown in figure 7 below is that the cost recovery mechanism. In Royalty Tax

(R/T) system, there is no cost recovery mechanism, therefore, the cost recovery ceiling

normally is not recognized22, the profit oil split is also not available. In many cases, the

calculation steps for Royalty Tax (R/T) system are tend to be more simple than PSC.

Figure 7 simply shows the general flow chart, some detail elements of contracts such as:

bonus, capital depreciation methods, domestic market obligations (DMO) if any, taxes other

than corporate income tax, are not available in the figure.

Figure 7. Division of Gross Production

22 Of course, it is alwalys possible to introduce something new, including applying the cost recovery ceiling in Royalty Tax system.

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PSC system tends to be slightly more complicated as shown in figure 8, in many countracts,

the royalty is applied in the PSC system. It is common in the PSC terms that the cost recovery

allowed to be recovered each year is limited to a certain percentage of Gross Revenue (so-

called "cost recovery limit")23. If the actual cost is more than the limit, the unrecovered cost is

carried forward to the following year. If the actual cost is less than the cost recovery limit,

then there is "excess cost oil". The treatment for excess cost oil can be divided into three

categories:

1. The excess costs are divided between government and IOC similar to the profit oil

split.

2. The excess cost oil is divided between government and IOC with a certain split

(difference with the profit oil split).

3. The excess cost oil is not divided between government and IOC, all excess costs oil

goes directly to the government.

23 The range of cost recovery ceiling is 30% - 80% of gross revenue (Johnston, 2006)15

Profit oil is shared between the government and IOC, the share may be fixed, or sliding scale

to certain parameters, such as: Production Rate, ROR, “R” Factor or directly linked to oil

prices.

Figure 8. Flow of Gross Production (PSC)

Figure 9 and Figure 10 shows the formula to calculate the project economics indicators for

each system.

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Figure 9. Cash Flow Calculation for Royalty Tax System

Figure 10. Cash Flow Calculation for PSC

Based on the production and cost data, production profile and oil (gas) price forecast, the

project cash flow profile is developed. It is worth noting that a good skill in excel spreadsheet

is valuable, especially if the system involve sliding scale profit oil split, cost recovery limit,

etc. When the cash flow profiles are developed, the next step is to let excel functions to

calcucate the investment parameters, such as: IRR and NPV and Profit to investment,

discounted payback, etc.

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9. Sensitivity Analysis

In order to investigate the economic performance in the base case input data, sensitivity

analysis is performed. This indicates how robust the model is to variations in one or more

parameters, and also highlights which of inputs in the model is the most sensitive. These

inputs can then be addressed more specifically.

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