Group K Final (1)

8/3/2019 Group K Final (1)

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Table of Contents

1. Introduction ................................................................................................................. 4

2. Executive Summary .................................................................................................... 5

3. Field Description ......................................................................................................... 6

3.1 Geographical Location ................................................................................................ 6

3.2 Weather Conditions ..................................................................................................... 6

3.3 Geotechnical Characteristic ......................................................................................... 7

3.4 Reservoir Properties .................................................................................................... 7

4. Technical proposal ...................................................................................................... 8

4.1 Objective ..................................................................................................................... 8

4.2

Methodology ............................................................................................................... 8

5 Factors Affecting the Various Development Phases ................................................. 10

5.1 The Exploration Phase .............................................................................................. 10

5.2 The Appraisal Phase .................................................................................................. 10

5.3 The Production Phase ................................................................................................ 11




7.5 Equipment Maintenance Schedule ............................................................................ 26

8 Political, Socio-Economic Consideration ................................................................. 27

8.1 Political background .................................................................................................. 27

8.2 Monopoly of Petrobras .............................................................................................. 28

8.3 Enhanced Safety Regulations .................................................................................... 29

9 Environmental Considerations .................................................................................. 30

9.1

Environmental Impacts ............................................................................................. 30

9.2 Environmental Policies of the Brazilian Government ............................................... 30

10 Financial and Economic Overview ........................................................................... 33

10.1 General Data .............................................................................................................. 33

10.2

Feasibility Study ........................................................................................................ 36

10.2.1 Scenario 1: Offloading to Existing Network via Pipelines ....................................... 37

10.2.2 Scenario 2 : Offloading to Shuttle Tankers Using CALM BUOY ........................... 39

10.2.3 Scenario 3 : Offloading by Aft Reel System on FPSO To Shuttle Tanker (Oil) &Gas via Pipeline to Network ................................................................................................ 41

10 3 U t i t C id ti 45




1. Introduction

The place of Oil & Gas in the world’s economy is ever on the increase as the present day

civilization largely depends on oil/gas for its everyday needs; as it is responsible for over

80% of the global industrial energy requirement. In recent years, oil & gas consumption has

skyrocketed unprecedentedly. In the International Energy Outlook 2010, world marketed

energy consumption increases by 49 percent from 2007 to 2035. Total energy demand in the

non-OECD countries increases by 84 percent, compared with an increase of 14 percent in the

OECD countries (IEO, 2010).

According to some current estimates, much of the so-called “easy oil” – usually meaning

conventional resources onshore, in shallow water and in benign environments offshore – has

already been found, and much has already been produced. At the same time, as stated earlier

the world’s demand for energy continues to grow. As a result of this expected growing

energy gap, new areas for exploration and production are increasingly being considered,

including deeper water and harsher environments. Another reason for growing interest in new

offshore areas is technology breakthroughs, including improvements in sub-salt seismic

imaging for deepwater and improved Health Safety Environment (HSE) measures for harsh




2. Executive Summary

This report is commissioned to examine in detail the techno-economical potential for field

development of offshore oil & gas in the Module 4 of Marlim Sul Field, Campos Basin,

Brazil, including project design and management, planning and environmental management.

The paramount objective of K RUDE is to facilitate oil extraction from the sea bed in the most

economical and environmentally friendly way. It involves:

Identifying technical challenges in the various E&P phases.

Provide solutions to overcome them.

Study and analysis of various production scenarios.

Conducting cost analysis of the feasible scenarios and their comparison.

K RUDE identified that the main focus while providing technical solutions to the challenges

should be in the production phase of the field development programme. Also the

technological solutions proposed are currently under R&D and serves the purpose efficiently

in the ultra deep waters of the Campos Basin.

K RUDE has managed to make the methodology as foolproof as possible. In order to

d t i th t ff ti f th t KRUDE h d th h i d




3. Field Description

3.1 Geographical Location

Marlim Sul field is one of the lucrative fields located in the Campos basin, 140kms off the

northern coast of the Rio de Janeiro state in Brazil and is expected to reach its peak oil

production capacity of 390,000 bopd and compress 6 billion cubic meters of gas by 2013.

Module 4, which is currently in the exploration stage, is located south east of the field in

water depths of more than 2000 meters and well test results show that 13-17° API heavy oil is

expected from turbidite reservoirs .




3.3 Geotechnical Characteristic

The geotechnical characteristic of the seabed comprises of soft, lightly over consolidated, fine

grained sediments, located on the lower continental slope where seafloor gradient is relatively

high (>10 degrees) with low sea bed temperatures typically around 4ºC (Mastrangelo et al,

2003) .

3.4 Reservoir Properties




4. Technical proposal

4.1 Objective

A huge investment is involved in the development of the Module 4 of the Marlim Sul field.

The paramount fact here would be to make this investment fruitful and make sure that it is

carried out in the most cost-efficient manner.

K RUDE will initially conduct a review of the:

1. Technical challenges in the various E&P phases

2. Provide solutions to overcome them.

3. While doing so technical, political, social and environmental factors will also be

considered.

4. Various production scenarios will be studied and analyzed.

5. Cost analysis of feasible scenario will be conducted and compared.

6. Conclude by identifying and proposing the most technically feasible and cost effective

solution to be used in the Module 4 of Marlim Sul field development programme.

4.2 Methodology




In terms of mooring systems, we will focus on the effectiveness of Taut Leg Mooring System

developed by Petrobras. Generally spread mooring has been used for production platforms in

Marlim Sul.

We will also study the technical and cost advantages of the use of shuttle tanker using stern

offloading system and evaluate its suitability for offloading operations in Module-4 and

networking solutions with the other production facilities within the field.

Economic maximization, production optimization, least CAPEX & OPEX requirements,

equipment’s reliability based maintenance approach; technical, environmental and political

issues are the cardinal focus of the project. Great emphasis will have to be laid on flow

assurance, heat management, separation process and impact on the environment. Assessment

of exploration and production options will primarily be based on technical feasibility. For

field development planning, reserves’ management, well planning, production logging and

most importantly production optimization with respect to field life, the approach shall be

examined in the course of this project for optimum production. Other aspects have also been

considered, including constructability, capital costs, environmental considerations,

operations, maintenance and repair, abandonment and decommissioning.




5 Factors Affecting the Various Development Phases

The following potential factors have been identified, associated with each development Phase

of the project along with possible solutions depending on available R&D

5.1 The Exploration Phase

Activities during the exploration phase include seismic surveys, testing, and exploratory

drilling. Accurate data collected in this phase will benefit the development of the field.

Neighbouring modules indicates that the Module 4 lies in water depth of 2000 meters or more

and horizontal and high angle wells could be drilled into poorly consolidated reservoirs.The

subsurface terrain is uncertain and identifying the reservoirs properties accurately will be a

challenge.

Using latest technologies such as 3D/4D surveying available on Fugro-Geoteam’s flagship C-

class vessel Geo Carribean could be employed to obtain accurate reservoir data and with

presently developed software to provide a better human interface. The technology of 4D

seismic is expected to help the mapping of water paths, supporting future operations of

drilling (Bruhn et al, 2003).

It i th ti i th t f ff h h il fi ld th V l f I f ti f




acquired from these will help evaluate the well for development activities and determine

strategies.

5.3 The Production Phase

Large volumes of heavy (13-17ºAPI) and high viscosity (20-400 cp at the reservoir

conditions) oil have been found in the deep and ultra-deep water Campos Basin and

preliminary study predict the same for Module 4. The economic oil production from these

accumulations relies on a group of new production technologies including mainly long

horizontal or multilateral wells producing with high power Electrical Submersible Pumps

(ESPs), hydraulic pumps or submarine multiphase pumps (SMPs) to compensate the decrease

in productivity caused by the high oil viscosity. Efficient heat management systems, compact

oil-water separation systems, pumping and off loading systems on board FPSO are currently

being developed for heavy oils (Bruhn et al, 2003).

An alternative technology to cold recovery is also under R&D. The technology is designed to

extract heavy oil from formations such as tar/oil sands with a calculated recovery of 90% or

more. The process mechanically injects a heated solution delivered deep into the formation

by a proprietary tool that melts the heavy tar oil to a thin viscosity and then extracts it to




Successful extended well tests (EWT) performed on the field during the previous stages will

determine the economic viability of this phase.

5.4 The De-Commissioning Phase

At the end of the production life, the project will be decommissioned and abandoned to

restore the site to a safe condition that minimises potential residual environmental impact and

permits reinstatement of activities such as fishing and unhindered navigation at the site. It is

estimated that the project life cycle is of 15 years, after which the FPSO could be dry docked

for future projects or scrapped. The ultimate disposition of the FPSO will depend upon its

condition at the end of the production life and upon the options available for further use.

Though the process facilities of these vessels are generally custom made for a specific

application, other major components including pressure vessels, piping, and equipment that

can be used on similar fields in future applications.

If initially designed with an eye towards an extended life, and the potential for expansion, the

equipment could more easily be converted and moved to another field with similar fluid

characteristics. FPSOs lend themselves readily to such conversions and movements because

f h i hi h Thi i i i h d f ff h k i h l i kl




6 Technological Solutions

6.1 3D/4D Surveying

The extensive use of 3D seismic as a reservoir characterization tool has optimized well

location and allowed the reduction of geological risks. Integration of high-resolution

stratigraphic analysis with 3D seismic inversion, geostatistic (stochastic) simulation of

reservoir properties constrained by seismic, well log and core data, 3D visualization, and

voxel-based automatic interpretation has guided the positioning of horizontal wells through

reservoirs. Additionally, 3D visualization techniques have provided a new environment for

teamwork, where seismic, well log, and core data are interpreted and added to detailed 3D

geological models and, subsequently, to robust reservoir simulation models.

The deepwater subsea wells must be designed to allow high production rates (typically

>10,000-15,000 bopd), with lifetime completions to avoid costly interventions. In order to

assure high productivity, pressure maintenance must be efficient; if water injection is

planned, the hydraulic connectivity between injector and producer wells must be guaranteed

by high-quality 3D seismic, well log correlation, and observed pressure profiles. Detailed

studies have been made in order to define the distribution and number of wells, since the




6.2 Extended well Test (EWTs)

EWTs in offshore fields are the best

way to reduce uncertainties and mitigate

the risks before approving huge

investments. The stratigraphy of the

Marlim Sul field is complex, which

makes the prediction and identification

of the reservoir compartments important

but difficult tasks. To investigate the

reservoir performance and anticipate

production problems, Extended Well

Tests will be implemented for the field.

The test will also help ascertain the use

of Horizontal wells, Improved Oil

recovery techniques (IOR), flow

assurance techniques, heating systems,

separation and treating systems, etc




The installation of ESPs inside the production well has a series of disadvantages, besides the

high intervention costs. It blocks the access to the well, requires large holes and casings and

imposes conditions on horizontal well geometry. Also, the annular space is a very valuable

asset, the use of ESP inside the well hinders the alternate use of it, such as cables and lines.

Based on these constraints Petrobras developed and built a system where the ESP is installed

outside the well.

6.4 Heavy Oil ProcessingRecent research shows that two new technologies are the most promising for heavy oil

separation: cyclones and electrostatic coalescers. Petrobras is presently taking part in the

R&D of these technologies. For offshore site evaluation of the technologies, P-34 Platform in

Jubarte field has been considered appropriate for testing systems sensitive to heavy oil field

conditions (WPC).

Cyclone Technology- has been famously used more recently for oily water separation with

hydrocyclones. Hydrocyclones, namely de-oilers, have become very popular due to their high

efficiency, compactness and absence of moving parts. Reduced residence time (1 to 2

seconds) and high efficiency (80 to 90%) in the treatment of oily waters with as much as




or liquid are directed to the underflow. The result is a process with typically a 2-3 second

retention time. This process provides a simple but effective separator with no moving parts.

Field tests are being conducted to evaluate performance for a wide range of API gravities

(from 13 to 22), water cuts and temperatures. This will allow the determination of the

operational envelop for heavy and extra-heavy crudes (CDS, Statiol, FMC Technologies).

Electrostatic Technology -




6.5 Crude Oil Pumping Systems

Conventional pump rooms on FPSO demand significant hull space and structural steel. Its

location at the bottom of the hull requires additional safety and a dedicated bilge system.

These issues and more can be

solved by having submersible

pumps.

Figure 5.7, Illustrates a typical

submersible pump arrangement.

The submerged pumping concepts

offers improved operational

reliability and eliminates potential

problems with inter tank pipelinecorrosion. The elimination of pipe

lines penetrating cargo tank

bulkheads has benefits of full

isolation of tanks, enabling a

bi i f k b




delivery of this second Hose Reel was extended by the supply of a Mooring Hawser Storage

Reel, also installed on the aft of ‘FPSO Marlim Sul’. Both the Hose Reel and Hawser Reel

are connected to the same Hydraulic Power Unit.

6.7 Taut Leg Mooring System

As water depth increases, conventional all-steel spread mooring systems show a number of

disadvantages: lower restoring efficiency, a high proportion of tether strength is consumed by

the vertical components of line tension, reduced pay-load of the vessel, large mooring radius

Figure 6.8: Stern Offloading System




6.8 Pressure Maintenance: (Water Alternate Gas) WAG

Offshore heavy oil reservoirs are a challenge for operators in Brazil. IOR (Improved Oil

Recovery) and EOR (Enhanced Oil Recovery) methods hold a key to economic feasibility of

heavy oil production. Chemical composition of the oil (inorganic salt deposition, mainly

Barium and Strontium sulphates and foaming tendency of heavy oil) is the key factor that

dictates the production challenge. Petrobras PRAVAP program has experimented with Water

Alternating Gas (WAG) method of enhancing heavy oil production. As the name implies, the

technique alternates injection of a suitable gaseous solvent and water. The gas serves as a

solvent to reduce the viscosity of the heavy oil while the water helps to push oil to the

producing well. Although the technique has been used to enhance recovery of light oil, WAG

has not yet been used for stimulating heavy oil production.




7 Project Strategy & Work Schedule

Some of the assumptions made in deriving the project strategy are that on the recoverable oil

reserves. According to Petrobras recoverable oil reserve in Marlim Sul is 2.42 Billion barrels

(OE, 2009) and the major part is in Module 1, 2, 3. If it is assumed that 25% of the reserves

are in Module 4, we could have 700 Million Barrels of reserves as a base case. Economics of

this assumption have been dealt later.

Secondly, it is also assumed that the exploration has already begun and drilling of test wellsand appraisal wells will be completed by 2013 from then on the production will start.

Uncertainty in the reservoir capacity, production rate, and Oil price is a major concern, since

the technology required for heavy oil processing, flow assurance and pressure maintenance in

ultra deep waters is currently being developed for large fields but has proven technology for

marginal fields. This could lead to comparatively higher CAPEX and OPEX costs to

conventional oil field development.

The conceptual study is essential to the development strategy for which a FEED (Front End

Engineering Design) study is carried out. The basic characteristics of the field put into

id i d i i l d d h bl d il d




understand the economics for the field development plan. Three scenarios consisting of FPSO

and differ only in their offloading systems. Two scenarios highlighting the uncertainty .All 5

scenarios will be modelled in IHS Que$tor Software to obtain production profiles and then

perform Cash flow analysis to get the NPV.

Safety is one of K RUDE’s concerns. We plan to apply Safety Management Systems (SMS)

on this venture. SMS will support controlling risk to protect company oil loss, ensure

employees and contractor’s personnel safety, controlling the effect of the project on theenvironment putting in our consideration accidents happened in this field. To ensure this, the

safety regulation proposed by the Brazilian Government will be strictly followed.

Half way through the production phase of the project life cycle a study will be carried out to

decide on FPSO and field decommissioning. Feasibility study of available options will be

carried out later.




7.1 Subsea Layout for Field’s Development

The main characteristics of the proposed field data for development are estimated as follows:

(Pinto C., 2003 and IHS Que$tor Software).

Recoverable reserves: 600-700 MMbbl

Expected Field life: 15 years

Oil Quality: 13-17° API, Gravity

Water depth: 2000M-2500M

Reservoir depth: 4000M-5000M (pre salt)

Reservoir thickness: 320-460M

Reservoir pressure: 60 Bar

Reservoir temperature: 40- 60 °C

Production wells: 20

Water injection wells: 08

Gas injection wells: 03




7.2 Production Platform Details

Production Facility proposed for the Module 4 is that of an FPSO. This decision was taken

depending upon the suitability of FPSOBR design by Petrobras which is being specially

designed for operations in the Campos basin.

Also, the recent possibility of KEPPEL’s Brazilian shipyard BrasFELS to carry out the

conversion to FPSO successfully and provide post production support, thus fulfilling

Brazilian government’s requirement to have 68 % local content in its offshore infrastructure,helps our decision.

Technically, FPSO’s with their large displacement can support large topsides hence enabling

subsequent additions for heavy oil processing. For benign environments, FPSOs may be

spread-moored, making very high riser counts possible. Conversions and reuse of the

facilities is also very common, reduced CAPEX and short lead times are advantageous for

early production systems. (OffshoreMarine, Sep-Oct-2010)

350-400 million USD (Data is similar to latest P57 FPSO by Petrobras/BrasFELS)

FPSO- (conversion),




7.3 Top Side Processing Facilities

Siri pilot project in the Campos basin has been using FPSO Cidade de Rio das Ostras since

2008. The field has similar oil properties and hence we propose to use similar topside

processing plants. The plant design takes into consideration oil treatment (retention time,

process temperature, equipments and chemicals) and water treatment (flotation, hydro

cyclone, water properties). The processing plant meets the present requirement of 120-140°C

operation temperatures making it a feasible choice (Sayd A.D, 2009)




7.4 Project Schedule

See Appendix for Full view:




ACTIVITIES Daily Weekly Monthly Quarterly Half ‐yearly Annually 4 years

WELL HEAD VISUAL INSPECTION X

CHRISTMAS TREE INSPECTION X

SUBSEA MANIFOLD X

PLEM X

FLOWLINE INSPECTION X

RISERS X

PLET X

MOORING LINES X

SPREAD MOORING/TAUT MOORING SYSTEM X

Preventive Maintenance Scheduling

7.5 Equipment Maintenance Schedule

The maintenance philosophy embraces the following:

Application of Risk Based Inspection to Inspection Planning

Application of Computerized Maintenance Management System (CMMS) to predictive

and preventive maintenance.

Improved safety and quality conditions

Increased capacity and throughput

Reduced equipment downtime

Reduced maintenance cost




8 Political, Socio-Economic Consideration

8.1 Political backgroundPetrobras, the largest Brazilian state-owned company, has dominated all aspects of Brazil's

oil and gas market from upstream to downstream until 1997, when the government opened

the offshore market to outside competition. Brazil enacted Federal Law No. 9474 to ensure

the flexibility of the state monopoly in the Brazil oil and gas industry. According to the law,

the bidding rounds are the key of the planning of the expansion of the Brazilian oil andnatural gas areas (Jacqueline M, 2007).

Nevertheless, with unstinted support of Brazilian government Petrobras continues to play a

role as the sole operator of most offshore oil and gas projects, with a few international

companies such as Shell, ExxonMobil, BP and Chevron and some Brazil-based companies

such as OGX participating (Silvestre B., 2011 ).

The government issued the proposed regulatory framework to govern development of its pre-

salt fields in August 2009. The framework largely comprises four sections (Staff, 2010).

To establish new Production Share Agreements (PSAs) to exploit the pre-salt reserves, in




City Service Tax (ISS), at a maximum tax rate of 5%;

Social Integration Contribution (PIS), at a tax rate of 1.65%,

Social Security Contribution ("COFINS"), at a tax rate of 7.6%. (Knight, 2008)

The Oil Act established a new regulatory framework for the industry and created the National

Petroleum Agency—ANP .The new production-sharing regime of ANP fortified a politically-

protected state capitalism with broad discretionary powers and little transparency. The rules

would also increase the government take of profits from oil production, possibly reducing the

incentive for private companies to participate. In addition, PSA structure proposed in the

legislation would give non-operating partners little influence over project decisions (Ocra

Worlwide, 2009).

All operating decisions, including contracting of personnel, suppliers and service providers,

would be subject to veto by political appointees in a new state company, PetroSal Petróleo,

created to supervise these ventures. The new law makes it mandatory that 68% of the project

content comes from within the local Brazilian market. This creates job opportunities for a

large part of the population.

8.2 Monopoly of Petrobras




8.3 Enhanced Safety Regulations

The difficulties of petroleum exploration and production in deep waters were maximized in

April 2010 as the aftermath of the BP’s oil spill in the Gulf of Mexico. The accident resulted

in many political, economic and ecological ramifications, including additional insurance and

credit costs for deep-water operations (Institute, 2011).

According to Petrobras, there were signals of more regulation prior to the spill in the Gulf,

and the inability of BP to stop the spill is likely to only accelerate the regulatory process.

Strengthened safety regulations will have a two-fold potential effect.

Petrobras is currently undertaking a $119 billion exploration and production project, the

largest of its kind. Tighter regulation may slow this project and significantly increase its

costs. Petrobras plans to pay for the project through an extremely large public offering. The

uncertainty and costs surround potential regulation have the potential of negatively impactingthe company’s share price and, as a result, the amount of capital the company can be raised

through share offerings.On the other hands, the safety concerns about the deepwater and

ultra-deepwater drilling, as well as the role of the government in the whole process have been

reconsidered by BP incident. It is found in current Brazilian policy that Specialists point out

a few political flaws in what is considered to be the responsibilities of the Brazilian




9 Environmental Considerations

9.1 Environmental ImpactsThe main concern regarding the environment is associated with the flawless extraction of oil.

Even a slight amount of oil spill can cause vast environmental pollution by affecting the

ecology. The area of the oil well inhabits around 832 species, including more than 200 fish,

200 birds, 100 molluscs, 100 crustaceans, 4 sea turtles, and 29 marine mammals. It includes

the endangered Kemp’s Ridley turtle, the Green turtle, the Loggerhead turtle, the Hawksbillturtle, the Leatherback turtles, Dolphins and Whales (Ramires). K RUDE is well aware of the

fact that with the start of the project, the species that live in this area might be under threat

and necessary action will be taken in order to prevent any mishaps. About 10% of marine

pollution is caused by offshore drilling. The adverse affect on the environment if the

extraction technology falters during the project will be massive.

Machines used to clear the site and drill for oil create dust and harmful emissions, including

nitrogen oxides and carbon monoxide. These emissions reduce air quality, harm plants

and animals and sometimes cause an odour. The physical presence of the FPSO and other

drilling equipments can really disturb the wildlife of the place. (Madison, 2010).




Government has imposed certain policies that are mandatory while drilling offshore Brazil.

The Oil and Gas Division of the Office of Mines and Minerals of the Brazilian Department of

Natural Resources regulates oil drilling in Brazil. The Oil and Gas Division sets restrictions

on drilling for responsible development of oil resources in the country without harming

residents and the environment. The Underground Injection Control Program of the Brazilian

Ministry regulates the injection of saltwater into disposal wells in Brazil. When pumped to

the surface, the oil usually contains large amounts of saltwater. This must have proper

disposal so it doesn't contaminate groundwater used for drinking (Hamilton, 2008).

According to the MARPOL 1973/78 Convention, the water that is associated with the oil

produced by the wells is discharged to the sea. The temperature of the cooling water

discharged will be a maximum of 40 degree Celsius. The Brazilian Government has

identified four international standards relating to Oil spill response plans (Mariano, 2007):

International Finance corporation Environmental, Health and Safety Guidelines

(December 2000).

International Petroleum Industry Environmental Conservation Association, Contingency

planning for Oil Spills (March 2000).







10 Financial and Economic Overview

10.1 General DataThe profit from oil production varies depending on oil prices and taxation. The higher oil

prices leads to the more benefit from oil. Otherwise, the higher taxation produces the less

benefit of it. Thus, concise data is essential to evaluate correct results.

1) Taxation = $8.5 / bbl

According to Global Finance Magazine, in terms of production-sharing pact, companies

working in the field will have to pay the government $8.5 per barrel of oil extracted that

means the consortium hands over a percentage of oil to the Brazilian government (Platt,

2010)

2) Oil Prices

(1) Liquid Oil Prices

i) Historical Trend

YearAVR.

OilPrice

1978 $13.08




ii) Expected Oil Prices Trend

According to EIA2010, future oil prices are projected to a continuous increase to $170.0 as

follow (EIA, 2010).

Figure 10.2 Expected Oil Prices changes

(2) Natural Gas Prices

i) Historical Trend

Oil Prices

Year $/bbl

2011 $126.87

2012 $133.21

2013 $137.21

2014 $141.33

2015 $145.57

2016

$149.93

2017 $154.43

2018 $157.52

2019 $159.09

2020 $160.69

2021 $162.29

2022 $163.92

2023 $164.74

2024 $165.56

2025 $166.39

2026

$167.22 2027 $167.22




ii) Expected NG Prices TrendThe Expected NG Prices are assumed as following the historical trends.

Figure 10.4 Future NG Prices changes

Natural Gas

Year mmBUT

2011 $4.03

2012 $4.23

2013 $4.44

2014 $4.67

2015 $4.90

2016 $5.14

2017 $5.40

2018 $5.67

2019 $5.95

2020 $5.66

2021

$6.22

2022 $6.84

2023 $7.53

2024 $8.28

2025 $8.32

2026 $7.49

2027 $6.74




10.2 Feasibility Study

K RUDE has to estimate the project profit and expenditures such as operating and capital cost

to decided if the project is economically viable. K RUDE has designed three possible

scenarios of the project to compare amongst each other to determine the economically

feasible option. Additional two scenarios have been considered to determine the economic

viability taking into consideration the uncertainties of crude oil price and estimated oil

reserves.

All Scenarios have the same basic definition as all use FPSO ,20 production wells, 8 water

injection wells, 3 gas injection wells, Subsea cluster layout, and reservoir properties (also see

project proposal) except for the offloading system in their respective cases and were

modelled for optimum production profile, CAPEX and OPEX using IHS Que$tor Software.

1. Offloading to existing network via pipelines.

2. Offloading to shuttle tanker via CALM Buoy.

3. Offloading aft reel system on FPSO (oil) to shuttle tanker and gas via pipeline.

3.1. Uncertainty: Drop in oil/Gas Prices.

3.2. Uncertainty: Drop in estimated oil reserves.




10.2.1 Scenario 1: Offloading to Existing Network via Pipelines

Scenerio 1 concideres all basic definitions except that the oil and gas is being offloaded using

25 km of pipeline to the nearest platform, from where oil and gas is further transported using

the existing network.

For daily production,the scenerion conciders 3 years to reach the maximum production rate of

180,000 bopd after which 7 years of pleatau period is assumed,then a steady decline is

observed.

Cost assumtion of the project is showin in the appendix. And the production rate for the




The operating cost for the entire project thus is assumed to be $ 2,505,994,000 .The total cost of the decommissioning $1,623,463,000

Year RevenueCumulative

RevenueExpenses

Cumulative

ExpensesNet Profit

- 2011 $7,027,211,000 $7,027,211,000 $500,000,000 $500,000,000 $6,527,211,000

0 2012 $0 $7,027,211,000 $6,527,211,000 $7,027,211,000 $0

1 2013 $2,918,616,170 $9,945,827,170 $4,104,003,160 $11,131,214,160 -$1,185,386,990

2 2014 $6,010,488,902 $15,956,316,072 $2,036,567,162 $13,167,781,322 $2,788,534,749

3 2015 $9,283,400,788 $25,239,716,859 $2,385,599,045 $15,553,380,367 $9,686,336,492

4 2016 $9,564,157,682 $34,803,874,541 $2,574,252,833 $18,127,633,200 $16,676,241,341

5 2017 $9,853,450,026 $44,657,324,568 $2,871,833,036 $20,999,466,236 $23,657,858,331

6 2018 $10,054,248,019 $54,711,572,587 $2,968,513,063 $23,967,979,300 $30,743,593,287

7 2019 $10,160,011,089 $64,871,583,676 $3,217,247,934 $27,185,227,233 $37,686,356,442

8 2020 $10,253,388,772 $75,124,972,447 $3,450,212,669 $30,635,439,902 $44,489,532,545

9 2021 $10,367,639,619 $85,492,612,066 $1,153,923,475 $31,789,363,378 $53,703,248,689

10 2022 $10,484,204,671 $95,976,816,737 $984,138,475 $32,773,501,853 $63,203,314,884

11 2023 $8,640,550,401 $104,617,367,138 $561,949,472 $33,335,451,325 $71,281,915,813

12 2024 $5,749,599,633 $110,366,966,772 $423,717,129 $33,759,168,454 $76,607,798,318




10.2.2 Scenario 2 : Offloading to Shuttle Tankers Using CALM Buoy

Scenerio 2 concideres all basic definitions except that the oil and gas is being offloaded to a

shuttle tanker using a CALM buoy

The FPSO is designed to have a storage capacity for 8.5 days. For daily production,the

scenerion conciders 2 years to reach the maximum production rate of 180,000 bopd after

which 7 years of pleatau period is assumed,then a steady decline is observed.




The total capital cost assumed for the project is $ 7,298,115,000. The operating cost for the entire project thus is assumed to be $ 4,985,443,000

The total cost of the decommissioning $ 1,844,543,000


RevenueExpenses

Cumulative

ExpensesNet Profit

- 2011 $7,798,115,000 $7,798,115,000 $500,000,000 $500,000,000 $7,298,115,000

0 2012 $0 $7,798,115,000 $7,298,115,000 $7,798,115,000 $0

1 2013 $2,912,778,584 $10,710,893,584 $6,739,176,144 $14,537,291,144 -$3,826,397,560

2 2014 $5,998,755,353 $16,709,648,937 $2,267,410,475 $16,804,701,619 -$95,052,682

3 2015 $9,265,712,463 $25,975,361,400 $2,685,271,327 $19,489,972,946 $6,485,388,454

4 2016 $9,545,584,941 $35,520,946,342 $2,844,183,601 $22,334,156,547 $13,186,789,795

5 2017 $9,833,948,649 $45,354,894,991 $3,506,742,748 $25,840,899,295$19,513,995,696

6 2018 $10,033,771,573 $55,388,666,564 $3,281,393,192 $29,122,292,487 $26,266,374,077

7 2019 $10,138,510,820 $65,527,177,383 $3,617,251,410 $32,739,543,897 $32,787,633,487

8 2020 $10,232,963,516 $75,760,140,900 $3,829,414,093 $36,568,957,990 $39,191,182,910

9 2021 $10,345,171,838 $86,105,312,738 $1,655,800,712 $38,224,758,702 $47,880,554,037

10 2022 $9,256,797,146 $95,362,109,884 $1,064,740,809 $39,289,499,511 $56,072,610,373




10.2.3 Scenario 3 : Offloading by Aft Reel System on FPSO To Shuttle

Tanker (Oil) & Gas via Pipeline to Network

Scenerio 3 concideres all basic definitions except that the oil is being offloaded to a shuttle

tanker using a Aft Hose reel system mounted on the FPSO and gas is being offloaded using

25 km of pipeline to the nearest platform, from where gas is further transported using the

existing network.




The Total Capital cost assumed for the project is $ 5,365,123,350. The Operating Cost for the entire project thus is assumed to be $ 3,725,418,000

The Total Cost of the Decommissioning $ 1,178,161,000


RevenueExpenses

Cumulative

ExpensesNet Profit

- 2011 $5,865,123,350 $5,865,123,350 $500,000,000 $500,000,000 $5,365,123,350

0 2012 $0 $5,865,123,350 $5,365,123,350 $5,865,123,350 $0

1 2013 $3,508,569,356 $9,373,692,706 $5,088,683,381 $10,953,806,731 -$1,580,114,026

2 2014 $7,252,739,327 $16,626,432,032 $1,800,889,542 $12,754,696,274 $3,871,735,758

3 2015 $11,244,993,425 $27,871,425,457 $2,175,673,683 $14,930,369,956 $12,941,055,501

4 2016 $11,623,829,951 $39,495,255,408 $2,295,613,960 $17,225,983,916 $22,269,271,492

5 2017 $12,016,105,909 $51,511,361,317 $2,681,289,230 $19,907,273,146 $31,604,088,170

6 2018 $12,325,036,696 $63,836,398,012 $2,624,535,933 $22,531,809,079 $41,304,588,933

7 2019 $12,544,339,199 $76,380,737,211 $2,887,486,720 $25,419,295,799 $50,961,441,412

8 2020 $12,518,500,476 $88,899,237,688 $3,036,626,162 $28,455,921,961$60,443,315,727

9 2021 $12,859,262,494 $101,758,500,182 $1,301,928,040 $29,757,850,001 $72,000,650,181

10 2022 $11,704,303,636 $113,462,803,818 $941,995,138 $30,699,845,139 $82,762,958,679

11 2023 $9,355,468,561 $122,818,272,378 $609,258,439 $31,309,103,577 $91,509,168,801

12 2024 $7,488,975,837 $130,307,248,216 $488,930,878 $31,798,034,455 $98,509,213,760

13 2025 $5,864,587,064 $136,171,835,280 $857,022,011 $32,655,056,466 $103,516,778,814

14 2026 $4,471,800,016 $140,643,635,296 $567,700,265 $33,222,756,731 $107,420,878,565

15 2027 $3,403,789,624 $144,047,424,920 $567,939,388 $33,790,696,119 $110,256,728,801




Compared to other two scenarios, Scenario 3 is more lucrative and optimistic. The last year

Net profit is expected to $109,785,464,401 which is $ 27,625,974,551 higher than Scenario 1.

The figure below shows the Net Cash Flow for Scenario 3. K RUDE evaluated 5, 10, 15% of

Net Present Value. The table demonstrates NPV > 0 which means the project is worth

developing.

Year

NCF Discount Factor & NPV Discount Factor & NPV Discount Factor & NPV

NCF

Cumulative NCF

5%

NPV

5%

Cumulative NPV

5%

10%

NPV10%

Cumulative NPV

10%

15%

NPV15%

Cumulative NPV

15%

‐ 2011 $5,865,123,350 $5,865,123,350 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0 2012 $0 $5,865,123,350 1.000 $0 $0 1.000 $0 $0 1.000 $0 $0

1 2013 $3,508,569,356 $9,373,692,706 0.952

$3,341,494,62

4

$3,341,494,624 0.909

$3,189,608,50

5

$3,189,608,505 0.870

$3,050,929,87

4

$3,050,929,874

2 2014 $7,252,739,327 $16,626,432,032 0.907

$6,578,448,36

9

$9,919,942,993 0.826

$5,993,999,44

3

$9,183,607,949 0.756

$5,484,112,91

2

$8,535,042,787

3 2015

$11,244,993,42

5

$27,871,425,457 0.864

$9,713,848,11

6

$19,633,791,10

9

0.751

$8,448,529,99

6

$17,632,137,94

5

0.658

$7,393,765,71

0

$15,928,808,49

7

4 2016

$11,623,829,95

1

$39,495,255,408 0.823

$9,562,953,66

7

$29,196,744,77

6

0.683

$7,939,232,25

9

$25,571,370,20

4

0.572

$6,645,962,50

1

$22,574,770,99

8

5 2017

$12,016,105,90

9

$51,511,361,317 0.784

$9,414,933,39

9

$38,611,678,17

5

0.621

$7,461,056,37

9

$33,032,426,58

3

0.497

$5,974,128,30

7

$28,548,899,30

5

6 2018

$12,325,036,69

6

$63,836,398,012 0.746

$9,197,132,14

6

$47,808,810,32

1

0.564

$6,957,161,90

2

$39,989,588,48

5

0.432

$5,328,453,48

4

$33,877,352,78

9

7 2019

$12,544,339,19

9

$76,380,737,211 0.711

$8,915,027,66

8

$56,723,837,98

9

0.513

$6,437,229,49

8

$46,426,817,98

2

0.376

$4,715,881,74

6

$38,593,234,53

5

8 2020

$12,518,500,47

6

$88,899,237,688 0.677

$8,473,013,87

6

$65,196,851,86

4

0.467

$5,839,972,86

1

$52,266,790,84

4

0.327

$4,092,320,01

2

$42,685,554,54

7

9 2021

$12,859,262,49

4

$101,758,500,18

2

0.645

$8,289,195,26

0

$73,486,047,12

4

0.424

$5,453,582,59

8

$57,720,373,44

2

0.284

$3,655,404,97

4

$46,340,959,52

0

1

0

2022

$11,704,303,63

6

$113,462,803,81

8

0.614

$7,185,427,12

5

$80,671,474,25

0

0.386

$4,512,515,72

4

$62,232,889,16

6

0.247

$2,893,124,85

5

$49,234,084,37

5




Figure 10.13 NCF & NPV diagram for Scenario 3




10.3 Uncertainty Consideration

1) Oil Prices Drop

From the data above, it is obvious that Scenario 3 is the most profitable plan. Oil prices are

the most sensitive value to develop offshore oil field due to the value determines developers’

profits. However, oil price is always unpredictable. In case, K RUDE computes Net profit

when oil prices drops to $40.0 / barrel. The prices of NG also follow the same trend of liquid

oil prices.Year Oil price NG price

11 $126.87 $4.03

2012 $133.21 $4.23

2013 $106.57 $3.39

2014 $85.26 $2.71

2015 $68.21 $2.17

2016 $54.56 $1.73

2017

$43.65

$1.39

2018 $41.47 $1.32

2019 $41.47 $1.32

2020 $41.47 $1.32

2021 $41.47 $1.25

2022 $41.47 $1.25

2023 $41.68 $1.26

2024 $41.88 $1.26




Result

The table above demonstrates Net profit is proportional to oil prices. Considering original

scenario 3, the revised scenario 3 produces only $23,017,362,986. Considering NPV > 0

referred to the appendix, though oil prices drastically drops the project is still worth doing.

2) Oil Production Drop

The other uncertainty is considering the reservoir capacity, in this case it is assumed that the

recoverable reserves in reduced to 400 MMbbl of oil. The number of wells and peak

production rate is kept the same (same as scenario 3). production life has been reduced to 10

years including 3 years to reach a plateau period of 3 years and then an exponential decline.




Gasproduction Years

Production Units 1 2 3 4 5 6 7 8 9 10

Daily MMsm³/day 0.302 0.605 0.907 1.210 1.210 1.210 0.973 0.619 0.394 0.251

Annual MMsm³/yr 105.866 211.732 317.598 423.464 423.464 423.464 340.665 216.751 137.910 87.747

Cumulative MMsm³ 105.866 317.598 635.197 1,058.661 1,482.125 1,905.590 2,246.255 2,463.006 2,600.916 2,688.663

Table 10.19 NG production table for Modified Scenario (3.2)

Result

Year Revenue

Cumulative

Revenue

Expenses

Cumulative

Expenses

Net Profit

‐ 2011 $5,768,900,210 $5,768,900,210 $500,000,000 $500,000,000 $5,268,900,210

0 2012 $0 $5,768,900,210 $5,268,900,210 $5,768,900,210 $0

1 2013 $2,631,427,017 $8,400,327,227 $3,714,898,135 $9,483,798,345

‐$1,083,471,119

2 2014 $5,439,554,495 $13,839,881,722 $1,682,524,762 $11,166,323,107 $2,673,558,614




Figure 10.21 Revenues and Expenses diagram for Modified Scenario (3.2)

10.5 Conclusion

Approaches to develop Marlim Sul field vary depending on techniques and machineries as

developers choose. K RUDE undertook three feasible scenarios to guide the most lucrative




In the Second case, K RUDE assumed the oil production finishes in ten years due to less oil

storage than expectation.

Figure 10.22 Overall Cumulative NCF




Figure 10.25 Overall 5% Cumulative

The graphs above show Net Present value of each Scenarios. K RUDE evaluated 5,10 and

15% of NPV for each scenarios being aware of decline in market value.

The evaluation shows that the third scenario is most profitable project with highest curves in

all graphs. In oil prices’ sensibility, although Net Present Value decreased NPV kept




11 Decommissioning

Decommissioning and abandonment will be carried out in accordance with the regulations of

the Brazilian government, good practice standards and licence requirements at the time.

K RUDE’s plan will include details on all aspects of facility and well decommissioning and

abandonment. The plan will also address issues identified by a health and safety risk

assessment of the decommissioning itself and the abandonment phase for the long term

prospect. Potential environmental and social risks will also be addressed (McGennis

E.,2007).

During the time of abandonment, the following infrastructure is of concern:

FPSO vessel

20 production wells,8 water injection wells,3 gas injection wells

Moorings legs from the FPSO Subsea Equipment

Risers

Manifolds

Decommissioning simply means uninstalling all the components used in the project. Subsea




All the available well data must be examined in advance, for existing information which

will guarantee the best possible resolution in the decommissioning problem.

11.1 Regulation and Authority

The decommissioning process of ships is becoming more complex. In general, all these ships

contain many types of hazardous materials such as asbestos, polychlorinated biphenyls, lead

and cadmium. International conventions pertaining to the decommissioning of oil and gas

projects cover both the removal of installations and disposal of wastes (Dimakopoulos, 2005)They include:

The United Nations Convention on the Law of Seas, 1982.

The 1989 IMO guidelines on the decommissioning.

The Oslo and Paris Conversion for the Protection of the Marine Environment.

Occupational Safety and Health in the Iron and Steel Industry, 1983

Safety in the Use of Asbestos, 1984

Radiation Protection of Workers (lionising Radiations), 1987

Safety in the Use of Chemicals at Work, 1993

Recording and Notification of Occupational Accidents and Diseases, 1995




12 Conclusion

1. As stated earlier conventional reserves are now getting exhausted and so developing the

fields of unconventional nature hold a great challenge. Module 4 of the Marlim Sul which

has 14-17 API of unconventional oil will require technological solution as that of using

Horizontal drilling, use of artificial pumping devices like ESPs’, heating solutions, heavy

oil processing technologies like electrostatic technology or cyclone technology. These

technological solutions and their continuous development hold the key to offshore heavy

oil field development.

2. It was observed that drilling costs account for 50-60% of the production costs thus

indicating that clear understanding of reservoir properties using latest seismic technology

and the data gathered form EWTs’ hold the key to successful project planning,

implementation and economics.

3. Brazilian government is dedicated towards its people and their safety and environment.

68% of the infrastructure that will be used in Brazilian oil fields will have to be locally

made, thus generating thousands of jobs. The government is presently considering

passing strict regulations for the offshore oil and gas exploration. New licensing laws and




13 Project Future priorities

1. The production facilities at Module 4 will require technological innovations or

improvement in the existing ones, because of the unconventional oil properties of the

reservoir. This will add up to the project costs as new sophisticated machineries become

available in the market. Our study does not consider this rise in CAPEX. The IHS

Que$tor software does not show significant difference between CAPEX of 16° API and

25° API oil (difference is 100 million $). Possibility to overrun the budget exists.

2. Successful production procedures at Module 4 will help Petorobras to further develop this

technology to a mature level and economically develop fields having unconventional oil

within Brazilian waters and elsewhere. This will also help other operators around the

world to study this technology and prepare themselves to the challenge of heavy oil

production as convention oil reserves decrease globally.




14 References

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D., Ceciliano M.M., 2003. Petrobras S. A.:OTC 15283, Offshore Heavy Oil in Campos

Basin: The Petrobras Experience.

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Campos Basin - 25 Years of Production and its Contribution to the Oil Industry; Petróleo

Brasileiro S.A

4. Mastrangelo C. F., SPE; Barusco P. J.; Formigli J. M., SPE; Dias R., 2003. Petrobras,

OTC 15224, From Early Production Systems to the Development of Ultra Deepwater Fields –

Experience and Critical Issues of Floating Production Units, Petróleo Brasileiro S.A

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Petrobras.

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06, 2011, from Rigzone: http://www.rigzone.com/news/article.asp?a_id=94647

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15 Appendix



Conversion Today's Price



mmBTU GJ GJ m³ mmBTU m³ Item Price Unit Item Price Unit

1.00 1.05 1.00 26.80 1.00 28.26 NG 4.03 $/mmBTU NG 142.59 $/1000m³

Oil bbl L m³ L m³ Oil bbl Oil 126.87 $/bbl Oil 797.99 $/m³

1.00 158.99 1.00 1,000.00 1.00 6.29

Item Price Unit Item Price Unit

NG 7.00 $/mmBTU NG 247.67 $/1000m³

Oil 85.00 $/bbl Oil 534.63 $/m³

From yr -5 - 1 5.00% From yr 5 - 6 2.00% From yr 11 - 14 0.50% From yr 16 - 20 0.00% From yr -5 - 3 0.50% From yr 8 -5.00% From yr 12 - 13 0.50%

From yr 1 - 5 3.00% From yr 6 - 10 1.00% From yr 14 - 16 0.00% From yr 20 0.00% From yr 4 - 7 5.00% From yr 9 -12 10.00% From yr 14 - 15 -10.00%

750,000 bbl Tax $8.50 Economic Life 15 years

119,240 m³ Start Value -$7,027,211,000 USD

E nd o f e co no mi c l if e V al ue - $2 ,2 62 ,5 73 ,8 70 U SD

Exploreation phase Apprasalphase Production phase

Production Year -6 -5 -4 -3 -2 -1 1 2 3 4 5 6 7 8

Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Oil price per bbl $126.87 $133.21 $137.21 $141.33 $145.57 $149.93 $154.43 $157.52 $159.09 $160.69

NG price per mmBTU $4.03 $4.05 $4.07 $4.09 $4.11 $4.32 $4.53 $4.76 $5.00 $4.75

Daily liquids productionin bpd (bbl) 0 0 60,000 120,000 180,000 180,000 180,000 180,000 180,000 180,000

Yearly Production in bbl 0 0 21,000,000 42,000,000 63,000,000 63,000,000 63,000,000 63,000,000 63,000,000 63,000,000

Gas production mmBTU) 0 0 26,118 52,235 78,353 78,353 78,353 78,353 78,353 78,353

Yearly Gas Production 0 0 9,141,155 18,282,310 27,423,466 27,423,466 27,423,466 27,423,466 27,423,466 27,423,466

4,152

Opening Balance $0 $ 6,5 27, 21 1,0 00 $0 - $1, 185 ,3 86, 99 0 $2, 78 8,5 34 ,74 9 $9 ,6 86, 336 ,4 92 $ 16, 67 6,2 41 ,34 1 $2 3,6 57, 85 8,3 31 $3 0, 743 ,5 93, 287 $ 37, 68 6,3 56 ,44 2

Loan $7,027,211,000 $0 $0 $0 $0 $0 $0 $0 $0 $0

Cash Revenue $0 $ 0 $2 ,9 18, 616 ,1 70 $ 6, 010 ,48 8, 902 $9, 28 3,4 00 ,78 8 $9 ,5 64, 157 ,6 82 $ 9,8 53 ,45 0, 026 $1 0,0 54, 24 8,0 19 $1 0, 160 ,0 11, 089 $ 10, 25 3,3 88 ,77 2

TOTAL RECEIPTS $ 7, 02 7, 21 1, 00 0 $ 0 $ 2, 91 8, 61 6, 17 0 $ 6, 01 0, 48 8, 90 2 $ 9, 28 3, 40 0, 78 8 $ 9, 56 4, 15 7, 68 2 $ 9, 85 3, 45 0, 02 6 $ 10 ,0 54 ,2 48 ,0 19 $ 10 ,1 60 ,0 11 ,0 89 $ 10 ,2 53 ,3 88 ,7 72

Cash Payments

CAPEX -$500,000,000 -$6,527,211,000 $0 $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsumable$0 $0 -$234,533,000 -$14,452,000 -$15,661,000 -$17,151,000 -$17,151,000 -$17,151,000 -$17,151,000 -$16,536,000

Inspectionandmaintenan$0 $0 -$522,543,000 - $3 3, 06 7, 00 0 - $3 3, 06 7, 00 0 - $3 3, 06 7, 00 0 - $3 3, 06 7, 00 0 - $3 3, 41 7, 00 0 - $4 5, 98 6, 00 0 - $3 3, 06 7, 00 0

Operatingpersonnel $0 $0 -$143,220,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000

Insurance$0 $0 -$409,380,000 -$27,292,000 -$27,292,000 -$27,292,000 -$27,292,000 -$27,292,000 -$27,292,000 -$27,292,000

Wells$0 $0 -$305,104,000 $0 $0 $0 -$89,452,000 $0 $0 $0

Field/projectcosts$0 $0

-$425,518,000 -$22,545,000 -$22,847,000 -$23,219,000 -$45,582,000 -$23,307,000 -$26,449,000 -$23,066,000

Tariffcosts $0 $0 -$465,696,000 -$20,930,000 -$41,860,000 -$62,790,000 -$62,790,000 -$62,790,000 -$62,790,000 -$51,685,000

Loan repayments $0 $0 -$1,101,866,685 - $1 ,2 34 ,0 90 ,6 87 - $1 ,3 82 ,1 81 ,5 69 - $1 ,5 48 ,0 43 ,3 58 - $1 ,7 33 ,8 08 ,5 61 - $1 ,9 41 ,8 65 ,5 88 - $2 ,1 74 ,8 89 ,4 59 - $2 ,4 35 ,8 76 ,1 94

Tax payments $0 $0 -$178,500,000 -$357,000,000 -$535,500,000 -$535,500,000 -$535,500,000 -$535,500,000 -$535,500,000 -$535,500,000

Depreciation $0 $0 -$317,642,475 -$317,642,475 -$317,642,475 -$317,642,475 -$317,642,475 -$317,642,475 -$317,642,475 -$317,642,475

TotalPayments - $5 00 ,0 00 ,0 00 - $6 ,5 27 ,2 11 ,0 00 - $4 ,1 04 ,0 03 ,1 60 - $2 ,0 36 ,5 67 ,1 62 - $2 ,3 85 ,5 99 ,0 45 - $2 ,5 74 ,2 52 ,8 33 - $2 ,8 71 ,8 33 ,0 36 - $2 ,9 68 ,5 13 ,0 63 - $3 ,2 17 ,2 47 ,9 34 - $3 ,4 50 ,2 12 ,6 69

Cash Book Balance $ 6, 52 7, 21 1, 00 0 $ 0 - $1 ,1 85 ,3 86 ,9 90 $ 2, 78 8, 53 4, 74 9 $ 9, 68 6, 33 6, 49 2 $ 16 ,6 76 ,2 41 ,3 41 $ 23 ,6 57 ,8 58 ,3 31 $ 30 ,7 43 ,5 93 ,2 87 $ 37 ,6 86 ,3 56 ,4 42 $ 44 ,4 89 ,5 32 ,5 45

Net Cash Flow $ 6, 52 7, 21 1, 00 0 - $6 ,5 27 ,2 11 ,0 00 - $1 ,1 85 ,3 86 ,9 90 $ 3, 97 3, 92 1, 73 9 $ 6, 89 7, 80 1, 74 3 $ 6, 98 9, 90 4, 84 9 $ 6, 98 1, 61 6, 99 0 $ 7, 08 5, 73 4, 95 6 $ 6, 94 2, 76 3, 15 5 $ 6, 80 3, 17 6, 10 3

Cumulative Net Cash Flow $ 6, 52 7, 21 1, 00 0 $ 0 - $1 ,1 85 ,3 86 ,9 90 $ 2, 78 8, 53 4, 74 9 $ 9, 68 6, 33 6, 49 2 $ 16 ,6 76 ,2 41 ,3 41 $ 23 ,6 57 ,8 58 ,3 31 $ 30 ,7 43 ,5 93 ,2 87 $ 37 ,6 86 ,3 56 ,4 42 $ 44 ,4 89 ,5 32 ,5 45

Exploration Period

Conversion Today s Price

2014Price

Sensitivity Analysis (Factorfor oilprice perbbl)

Depreciation

FPSO Capacity

Exploration Period

Exploration Period

Sensitivity Analysis (Factorfor oilprice perbbl)

Scenario 1: Offloading to Existing Network

via Pipelines

Production Year 9 10 11 12 13 14 15 16 17



Production Year 9 10 11 12 13 14 15 16 17

Year 2021 2022 2023 2024 2025 2026 2027 2028 2029

Oil price per bbl $162.29 $163.92 $164.74 $165.56 $166.39 $167.22 $167.22

NG price per mmBTU $5.22 $5.74 $6.32 $6.95 $6.99 $6.29 $5.66

Daily liquids productionin bp 180,000 180,000 147,399 97,443 64,418 42,586 28,153

Ye arly Production in bbl 63,000,000 63,000,000 51,589,820 34,105,192 22,546,388 14,905,051 9,853,487

Gas production mmBTU) 78,353 78,353 64,162 42,416 28,041 18,537 12,255

Ye arly Gas Production 27,423,466 27,423,466 22,456,693 14,845,755 9,814,287 6,488,066 4,289,155

Opening Balance $ 44 ,4 89 ,5 32 ,5 45 $ 53 ,7 03 ,2 48 ,6 89 $ 63 ,2 03 ,3 14 ,8 84 $ 71 ,2 81 ,9 15 ,8 13 $ 76 ,6 07 ,7 98 ,3 18 $ 79 ,6 85 ,4 94 ,1 22 $ 81 ,6 55 ,5 41 ,6 67

Loan $0 $0 $0 $0 $0 $0 $0

Cash Revenue $10,367,639,619.11 $10,484,204,671.09 $8,640,550,400.76 $5 ,749,599,633.45 $3 ,819,971,700.47 $2,533,189,074.94 $1 ,671,953,619.72

TOTAL RECEIPTS $ 10 ,3 67 ,6 39 ,6 19 $ 10 ,4 84 ,2 04 ,6 71 $ 8, 64 0, 55 0, 40 1 $ 5, 74 9, 59 9, 63 3 $ 3, 81 9, 97 1, 70 0 $ 2, 53 3, 18 9, 07 5 $ 1, 67 1, 95 3, 62 0

Cash Payments

CAPEX $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsumable-$ 15, 71 4,0 00 - $1 5, 249 ,0 00 -$ 14 ,97 7, 000 - $1 4,8 12, 00 0 - $1 4, 709 ,0 00 -$ 14 ,64 4, 000 - $14 ,6 01, 00 0

Inspectionandmaintenan-$ 33, 06 7,0 00 - $3 3, 067 ,0 00 -$ 33 ,41 7, 000 - $4 5,9 86, 00 0 - $3 3, 067 ,0 00 -$ 33 ,06 7, 000 - $33 ,0 67, 00 0

Operatingpersonnel-$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000

Insurance-$ 27, 29 2,0 00 - $2 7, 292 ,0 00 -$ 27 ,29 2, 000 - $2 7,2 92, 00 0 - $2 7, 292 ,0 00 -$ 27 ,29 2, 000 - $27 ,2 92, 00 0

Wells-$126,200,000 $0 $0 $0 -$89,452,000 $0 $0

Field/projectcosts-$ 54, 41 0,0 00 - $2 2, 744 ,0 00 -$ 22 ,76 3, 000 - $2 5,8 64, 00 0 - $4 4, 972 ,0 00 -$ 22 ,59 3, 000 - $22 ,5 82, 00 0

Tariffcosts-$ 34, 55 0,0 00 - $2 3, 096 ,0 00 -$ 15 ,43 9, 000 - $1 0,3 21, 00 0 - $6 ,8 99, 00 0 -$ 4, 612 ,00 0 - $3,0 83, 00 0

Loan repayments $0 $0 $0 $0 $0 $0 $0

Tax payments - $5 35 ,5 00 ,0 00 - $5 35 ,5 00 ,0 00 - $4 38 ,5 13 ,4 72 - $2 89 ,8 94 ,1 29 - $1 91 ,6 44 ,2 97 - $1 26 ,6 92 ,9 30 - $8 3, 75 4, 63 7

Depreciation -$317,642,475 -$317,642,475 $0 $0 $0 $0 $0

Decommission costs $0 $0 $0 $0 -$324,692,600 -$324,692,600 -$324,692,600 -$324,692,600 -$324,692,600

TotalPayments - $1 ,1 53 ,9 23 ,4 75 - $9 84 ,1 38 ,4 75 - $5 61 ,9 49 ,4 72 - $4 23 ,7 17 ,1 29 - $7 42 ,2 75 ,8 97 - $5 63 ,1 41 ,5 30 - $5 18 ,6 20 ,2 37 - $3 24 ,6 92 ,6 00 - $3 24 ,6 92 ,6 00

Cash Book Balance $ 53 ,7 03 ,2 48 ,6 89 $ 63 ,2 03 ,3 14 ,8 84 $ 71 ,2 81 ,9 15 ,8 13 $ 76 ,6 07 ,7 98 ,3 18 $ 79 ,6 85 ,4 94 ,1 22 $ 81 ,6 55 ,5 41 ,6 67 $ 82 ,8 08 ,8 75 ,0 50 $ 82 ,4 84 ,1 82 ,4 50 $ 82 ,1 59 ,4 89 ,8 50

Net Cash Flow $ 9, 21 3, 71 6, 14 4 $ 9, 50 0, 06 6, 19 6 $ 8, 07 8, 60 0, 92 9 $ 5, 32 5, 88 2, 50 5 $ 3, 07 7, 69 5, 80 4 $ 1, 97 0, 04 7, 54 5 $ 1, 15 3, 33 3, 38 3 - $3 24 ,6 92 ,6 00 - $3 24 ,6 92 ,6 00

Cumulative Net Cash Flow $ 53 ,7 03 ,2 48 ,6 89 $ 63 ,2 03 ,3 14 ,8 84 $ 71 ,2 81 ,9 15 ,8 13 $ 76 ,6 07 ,7 98 ,3 18 $ 79 ,6 85 ,4 94 ,1 22 $ 81 ,6 55 ,5 41 ,6 67 $ 82 ,8 08 ,8 75 ,0 50 $ 82 ,4 84 ,1 82 ,4 50 $ 82 ,1 59 ,4 89 ,8 50

Survey of the field -$500,000,000 No. of years 10 Total loan Payback Remain

Sub total -$5,498,318,000 Interest Rate 12% year 1 2011 -$7,027,211,000 $ 0 - $7 ,0 27 ,2 11 ,0 00

Contengency -$1,028,893,000 year 2 2012 -$7,870,476,320 $0 -$7,870,476,320

Loan -$7,027,211,000 y ea r 3 2 01 3 - $8 ,8 14 ,9 33 ,4 78 - $1 ,1 01 ,8 66 ,6 85 -$ 7, 71 3, 06 6, 79 4

year 4 2014 -$8,638,634,809 -$1,234,090,687 -$7,404,544,122

year 5 2015 -$8,293,089,416 -$1,382,181,569 -$6,910,907,847

year 6 2016 -$7,740,216,789 -$1,548,043,358 -$6,192,173,431

year 7 2017 -$6,935,234,243 -$1,733,808,561 -$5,201,425,682

year 8 2018 -$5,825,596,764 -$1,941,865,588 -$3,883,731,176

year 9 2019 -$4,349,778,917 -$2,174,889,459 -$2,174,889,459

year 10 2020 -$2,435,876,194 -$2,435,876,194 $0

Decommision

Scenario 1: Offloading to Existing

Network via Pipelines

Year NCF Discount Factor & NPVDis count Factor & NPV Di scount Factor & NPV



Year

NCF Cumul ative NCF 5% NPV 5% Cumul ati ve NPV 5% 10% NPV10% Cumul ati ve NPV 10% 15% NPV15% umulative NPV 15%

- 2011 $6,527,211,000 $6,527,211,000 - - - - - - - - -

0 2012 -$6 ,527 ,211 ,000 $0 1 .000 -$6 ,527 ,211 ,000 -$6 ,527 ,211 ,000 1 .000 -$6 ,527 ,211 ,000 -$6 ,527 ,211 ,000 1 .000 -$6 ,527 ,211 ,000 -$6 ,527 ,211 ,000

1 2013 -$1,185,386,990 -$1,185,386,990 0.952 -$1,128,939,991 -$7,656,150,991 0.909 -$1,077,624,537 -$7,604,835,537 0.870 -$1,030,771,296 -$7,557,982,296

2 2014 $3,973,921,739 $2,788,534,749 0.907 $3,604,464,163 -$4,051,686,828 0.826 $3,284,232,842 -$4,320,602,694 0.756 $3,004,855,758 -$4,553,126,538

3 2015 $6, 897, 801, 743 $9, 686, 336, 492 0 .864 $5, 958, 580, 493 $1, 906, 893, 665 0 .751 $5, 182, 420, 543 $861, 817, 849 0 .658 $4, 535, 416, 614 -$17, 709, 924

4 2016 $6,989,904,849 $16,676,241,341 0.823 $5,750,612,018 $7,657,505,682 0.683 $4,774,199,063 $5,636,016,912 0.572 $3,996,500,784 $3,978,790,859

5 2017 $6,981,616,990 $23,657,858,331 0.784 $5,470,279,596 $13,127,785,279 0.621 $4,335,034,859 $9,971,051,771 0.497 $3,471,097,542 $7,449,888,402

6 2018 $7,085,734,956 $30,743,593,287 0.746 $5,287,484,521 $18,415,269,799 0.564 $3,999,712,658 $13,970,764,429 0.432 $3,063,358,759 $10,513,247,161

7 2019 $6,942,763,155 $37,686,356,442 0.711 $4,934,092,154 $23,349,361,953 0.513 $3,562,735,276 $17,533,499,705 0.376 $2,610,041,829 $13,123,288,990

8 2020 $6,803,176,103 $44,489,532,545 0.677 $4,604,657,373 $27,954,019,326 0.467 $3,173,731,861 $20,707,231,566 0.327 $2,223,970,336 $15,347,259,326

9 2021 $9,213,716,144 $53,703,248,689 0.645 $5,939,243,578 $33,893,262,904 0.424 $3,907,515,073 $24,614,746,639 0.284 $2,619,113,175 $17,966,372,501

10 2022 $9,500,066,196 $63,203,314,884 0.614 $5,832,216,547 $39,725,479,451 0.386 $3,662,686,771 $28,277,433,410 0.247 $2,348,271,071 $20,314,643,571

11 2023 $8,078,600,929 $71,281,915,813 0.585 $4,723,390,648 $44,448,870,099 0.350 $2,831,500,342 $31,108,933,752 0.215 $1,736,440,519 $22,051,084,090

12 2024 $5,325,882,505 $76,607,798,318 0.557 $2,965,650,663 $47,414,520,762 0.319 $1,696,990,297 $32,805,924,049 0.187 $995,445,521 $23,046,529,611

13 2025 $3,077,695,804 $79,685,494,122 0.530 $1,632,167,796 $49,046,688,558 0.290 $891,498,846 $33,697,422,895 0.163 $500,211,610 $23,546,741,221

14 2026 $1,970,047,545 $81,655,541,667 0.505 $995,007,881 $50,041,696,439 0.263 $518,775,091 $34,216,197,986 0.141 $278,424,176 $23,825,165,397

15 2027 $1,153,333,383 $82,808,875,050 0.481 $554,773,077 $50,596,469,516 0.239 $276,098,842 $34,492,296,828 0.123 $141,738,312 $23,966,903,710

16 2028 -$324,692,600 $82,484,182,450 0.458 -$148,745,421 $50,447,724,095 0.218 -$70,662,570 $34,421,634,258 0.107 -$34,698,200 $23,932,205,510

17 2029 -$324,692,600 $82,159,489,850 0.436 -$141,662,306 $50,306,061,789 0.198 -$64,238,700 $34,357,395,559 0.093 -$30,172,348 $23,902,033,162

- 2011 $7, 027, 211, 000 $7, 027, 211, 000 $500, 000, 000 $500, 000, 000 $6,527,211,000

0 2012 $0 $7,027,211,000 $6,527,211,000 $7,027,211,000 $0

1 2013 $2,918,616,170 $9,945,827,170 $4,104,003,160 $11,131,214,160 -$1,185,386,990

2 2014 $6,010,488,902 $15,956,316,072 $2,036,567,162 $13,167,781,322 $2,788,534,749

3 2015 $9,283,400,788 $25,239,716,859 $2,385,599,045 $15,553,380,367 $9,686,336,492

4 2016 $9,564,157,682 $34,803,874,541 $2,574,252,833 $18,127,633,200 $16,676,241,341

5 2017 $9,853,450,026 $44,657,324,568 $2,871,833,036 $20,999,466,236 $23,657,858,331

6 2018 $10,054,248,019 $54,711,572,587 $2,968,513,063 $23,967,979,300 $30,743,593,287

7 2019 $10,160,011,089 $64,871,583,676 $3,217,247,934 $27,185,227,233 $37,686,356,442

8 2020 $10,253,388,772 $75,124,972,447 $3,450,212,669 $30,635,439,902 $44,489,532,545

9 2021 $10,367,639,619 $85,492,612,066 $1,153,923,475 $31,789,363,378 $53,703,248,689

10 2022 $10,484,204,671 $95,976,816,737 $984,138,475 $32,773,501,853 $63,203,314,884

11 2023 $8,640,550,401 $104,617,367,138 $561,949,472 $33,335,451,325 $71,281,915,813

12 2024 $5,749,599,633 $110,366,966,772 $423,717,129 $33,759,168,454 $76,607,798,318

13 2025 $3,819,971,700 $114,186,938,472 $742,275,897 $34,501,444,350 $79,685,494,122

14 2026 $2,533,189,075 $116,720,127,547 $563,141,530 $35,064,585,880 $81,655,541,667

15 2027 $1,671,953,620 $118,392,081,167 $518,620,237 $35,583,206,117 $82,808,875,050

16 2028 $0 $118,392,081,167 $324,692,600 $35,907,898,717 $82,484,182,450

17 2029 $0 $118,392,081,167 $324,692,600 $36,232,591,317 $82,159,489,850


Revenue

ExpensesCumulative

Expenses

Net Profit

NCF Discount Factor & NPVDis count Factor & NPV Di scount Factor & NPV

-$20,000,000,000

$0

$20,000,000,000

$40,000,000,000

$60,000,000,000

$80,000,000,000

$100,000,000,000

$120,000,000,000

$140,000,000,000

Cumulative

Revenue

Cumulative

Expenses

Net Profit

Total expenses VS

Revenue

-$8,000,000,000

-$6,000,000,000

-$4,000,000,000

-$2,000,000,000

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

NCF

NPV 5%

NPV10%

NPV15%

NCF VS NPV

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

Revenue

Expenses

Revenue & Expenses

-$20,000,000,000

-$10,000,000,000

$0

$10,000,000,000

$20,000,000,000

$30,000,000,000

$40,000,000,000

$50,000,000,000

$60,000,000,000

$70,000,000,000

$80,000,000,000

$90,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

Cumulative NCF

Cumulative NPV 5%

Cumulative NPV 10%

Cumulative NPV 15%

Culmulative NCF VS NPV

Scenario 1: Offloading to

Existing Network via

Natural GasOil Prices



Natural Gas

Year $/bbl Year mmBUT

2011 $126.87 2011 $4.03

2012 $133.21 2012 $4.05

2013 $137.21 2013 $4.07

2014 $141.33 2014 $4.09

2015 $145.57 2015 $4.11

2016 $149.93 2016 $4.32

2017 $154.43 2017 $4.53

2018 $157.52 2018 $4.76

2019 $159.09 2019 $5.00

2020 $160.69 2020 $4.75

2021 $162.29 2021 $5.22

2022 $163.92 2022 $5.74

2023 $164.74 2023 $6.32

2024 $165.56 2024 $6.95

2025 $166.39 2025 $6.99

2026 $167.22 2026 $6.29

2027 $167.22 2027 $5.66

Yea r Amount ABS Amount Year mmBUT Year bbl/day m³/day bbl/year m³/year

2011 $0 $0 2011 0 2011 0 0 0 0

2012 $0 $0 2012 0 2012 0 0 0 0

2013 -$178 ,500 ,000 $178, 500, 000 2013 26,118 2013 60,000 7,154 21,000,000 3,338,733

2014 -$357 ,000 ,000 $357, 000, 000 2014 52,235 2014 120,000 14,309 42,000,000 6,677,466

2015 -$535 ,500 ,000 $535, 500, 000 2015 78,353 2015 180,000 21,463 63,000,000 10,016,200

2016 -$535 ,500 ,000 $535, 500, 000 2016 78,353 2016 180,000 28,618 63,000,000 10,016,200

2017 -$535 ,500 ,000 $535, 500, 000 2017 78,353 2017 180,000 28,618 63,000,000 10,016,200

2018 -$535 ,500 ,000 $535, 500, 000 2018 78,353 2018 180,000 28,618 63,000,000 10,016,200

2019 -$535 ,500 ,000 $535, 500, 000 2019 78,353 2019 180,000 28,618 63,000,000 10,016,200

2020 -$535 ,500 ,000 $535, 500, 000 2020 78,353 2020 180,000 28,618 63,000,000 10,016,200

2021 -$535 ,500 ,000 $535, 500, 000 2021 78,353 2021 180,000 28,618 27,423,466 4,359,983

2022 -$535 ,500 ,000 $535, 500, 000 2022 78,353 2022 180,000 28,618 27,423,466 4,359,983

2023 -$438 ,513 ,472 $438, 513, 472 2023 64,162 2023 147,399 23,565 22,456,693 3,570,329

2024 -$289 ,894 ,129 $289, 894, 129 2024 42,416 2024 97,443 15,766 14,845,755 2,360,286

2025 -$191 ,644 ,297 $191, 644, 297 2025 28,041 2025 64,418 10,548 9,814,287 1,560,347

2026 -$126 ,692 ,930 $126, 692, 930 2026 18,537 2026 42,586 7,057 6,488,066 1,031,520

20 27 - $83 ,75 4, 63 7 $ 83 ,7 54, 63 7 2 027 12,255 2027 28,153 4,721 4,289,155 681,921

Total Taxes paid $5, 949, 999, 464

Liquid Oil ProductionDaily production of NG

Oil Prices

Taxation

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

mmBUT / day

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

2011 2013 2015 2017 2019 2021 2023 2025 2027

bbl/day

$0

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

Taxation

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

mmBUT

mmBUT

mmBUT

$0.00$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

$140.00

$160.00

$180.00

$/bbl

General Data

Scenario 1: Offloading to

Existing Network via Pipelines

S 2 Off C S

OFFSHOREPROJECTSUMMARY



Currency Rate/$

Offshore Brazil $ 1.00

Contingency S.America $ 1.00

Equipment GulfofMexico $ 1.00Materials GulfofMexico $ 1.00

Fabrication S.America $ 1.00

Linepipe GulfofMexico $ 1.00

Installation S.America $ 1.00

Design&PM S.America $ 1.00

Opex S.America $ 1.00

Certification S.America $ 1.00

Freight S.America $ 1.00

S.America

300.00 700.00

110.00 2000.00

333.00 7000.00

1.10 193.00

367.00 11.80

110.00 5.92

61.80

1.10

16.00 0.00

0.30 30.00

10.00

km

Mbbl/day Reservoirdepth m

Reservoirpressure bara

Reservoirlength km

Country Brazil

Initialwatercut %

Designgrossliquidsflowrate

Scen.2:OffloadingbyCALMBuoytoShuttleTanker

SantosBasin

Oilfield

Oil

FPSO+Subsea

Waterinjectioncapacityfactor

Region LatinAmerica

MMbbl

m

ppm

Reservoirwidth

°API

%

Procurementstrategy

Technicaldatabase

Mbbl/day

MMscf/day

Mbbl/day

MMscf/day

nm³/m³

Reserves

Waterdepth

H2Scontent

Gasmolecularweight

Fluidcharacteristics

Oildensity@STP

CO2content

Production profile characteristics

Designoilproductionflowrate

Designassociatedgasflowrate

Designwaterinjectionflowrate

Designgasinjectionrate

Gasoilratio

Designfactor

Projectname

Basin

Unitset

Developmenttype

Developmentconcept

Overallinput





1.00 1.05 1.00 26.80 1.00 28.26 NG 4.03 $/mmBTU NG 142.59 $/1000m³


1.00 158.99 1.00 1,000.00 1.00 6.29


NG 7.00 $/mmBTU NG 247.67 $/1000m³

Oil 85.00 $/bbl Oil 534.63 $/m³


From yr 1 - 5 3.00% From yr 6 - 10 1.00% From yr 14 - 16 0.00% From yr 20 0.00% From yr 4 - 7 5.00% From yr 9 -12 10.00% From yr 14 - 15 -10.00%


119,240 m³ Start Value -$7,798,115,000 US D

End of economic life Valu -$2,510,784,326 USD

Exploreation phase Apprasal phase Production phase

Production Year -6 -5 -4 -3 -2 -1 1 2 3 4 5 6 7 8

Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Oil price per bbl $126.87 $133.21 $137.21 $141.33 $145.57 $149.93 $154.43 $157.52 $159.09 $160.69


Daily liquids productioni 0 0 0 0 0 0 60,000 120,000 180,000 180,000 180,000 180,000 180,000 180,000

Yearly Production in bbl 0 0 0 0 0 0 21,000,000 42,000,000 63,000,000 63,000,000 63,000,000 63,000,000 63,000,000 63,000,000

Gas production mmBTU) 0 0 0 0 0 0 22,020 44,040 66,060 66,060 66,060 66,060 66,060 66,060

Yearly Gas Production 0 0 0 0 0 0 7,707,000 15,414,000 23,121,000 23,121,000 23,121,000 23,121,000 23,121,000 23,121,000

3,501

Opening Balance $0 $7,298,115,000 $0 -$3,826,397,560 -$95,052,682 $6,485,388,454 $13,186,789,795 $19,513,995,696 $26,266,374,077 $32,787,633,487

Loan $7,798,115,000 $0 $0 $0 $0 $0 $0 $0 $0 $0

Cash Revenue $0 $0 $2,912,778,584 $5,998,755,353 $9,265,712,463 $9,545,584,941 $9,833,948,649 $10,033,771,573 $10,138,510,820 $10,232,963,516

TOTAL RECEIPTS $7,798,115,000 $0 $2,912,778,584 $5,998,755,353 $9,265,712,463 $9,545,584,941 $9,833,948,649 $10,033,771,573 $10,138,510,820 $10,232,963,516

Cash Payments

CAPEX -$500,000,000 -$7,298,115,000 $0 $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsuma $0 $0 - $214,232,000 -$13,310,000 - $13,949,000 -$14,573,000 -$14,573,000 -$14,573,000 -$14,573,000 -$14,573,000

Inspectionandmainte $0 $0 -$743,417,000 - $4 6, 62 1, 00 0 - $4 6, 62 1, 00 0 - $4 6, 62 1, 00 0 - $4 6, 62 1, 00 0 - $4 6, 76 8, 00 0 - $6 8, 52 5, 00 0 - $4 6, 62 1, 00 0

Operatingpersonnel $0 $0 - $176,700,000 -$11,780,000 - $11,780,000 -$11,780,000 -$11,780,000 -$11,780,000 -$11,780,000 -$11,780,000

Insurance $0 $0 - $875,775,000 -$58,385,000 - $58,385,000 -$58,385,000 -$58,385,000 -$58,385,000 -$58,385,000 -$58,385,000

Wells $0 $0 -$1,314,092,000 $0 -$40,060,000 $0 -$365,132,000 $0 -$40,060,000 $0

Field/projectcosts$0 $0

-$856,227,000 -$34,202,000 -$44,377,000 -$34,518,000 -$125,801,000 -$34,555,000 -$50,009,000 -$34,518,000

Tariffcosts $0 $0 - $805,000,000 -$24,150,000 - $48,300,000 -$72,450,000 -$72,450,000 -$72,450,000 -$72,450,000 -$72,450,000

Loan repayments $0 $0 -$1,222,744,432 -$1,369,473,764 -$1,533,810,616 -$1,717,867,889 -$1,924,012,036 -$2,154,893,480 -$2,413,480,698 -$2,703,098,382

Tax payments $ 0 $0 - $178, 500, 000 - $35 7,00 0,000 - $535, 500, 000 - $535,5 00,0 00 - $53 5,50 0,000 - $535 ,500, 000 - $535, 500,0 00 - $5 35,50 0,00 0

Depreciation $0 $0 -$352,488,712 -$352,488,712 -$352,488,712 -$352,488,712 -$352,488,712 -$352,488,712 -$352,488,712 -$352,488,712

Total Payments -$500,000,000 -$7,298,115,000 - $6,739,176,144 - $2,267,410,475 -$2,685,271,327 -$2,844,183,601 - $3,506,742,748 -$3,281,393,192 -$3,617,251,410 -$3,829,414,093

Cash Book Balance $ 7,29 8,11 5,00 0 $ 0 -$3 ,8 26 ,3 97 ,5 60 -$9 5,05 2,68 2 $ 6,48 5,38 8,45 4 $ 13 ,1 86 ,7 89 ,7 95 $ 19 ,5 13 ,9 95 ,6 96 $ 26 ,2 66 ,3 74 ,0 77 $ 32 ,7 87 ,6 33 ,4 87 $ 39 ,1 91 ,1 82 ,9 10

Net Cash Flow $7,298,115,000 -$7,298,115,000 -$3,826,397,560 $3,731,344,878 $6,580,441,136 $6,701,401,340 $6,327,205,901 $6,752,378,381 $6,521,259,410 $6,403,549,423

Cumulative Net Cash Flo $7,298,115,000 $0 -$3,826,397,560 -$95,052,682 $6,485,388,454 $13,186,789,795 $19,513,995,696 $26,266,374,077 $32,787,633,487 $39,191,182,910

2014 Price

Sensitivity Analysis (Factor for oil price per bbl) Sensitivity Analysis (Factor for oil price per bbl)

Depreciation

FPSO Capacity

Exploration Period

Exploration Period

Exploration Period

Scenario 2 : Offloading to Shuttle

Tankers Using CALM BUOY

Production Year 9 10 11 12 13 14 15 16 17



Year 2021 2022 2023 2024 2025 2026 2027 2028 2029

Oil price per bbl $162.29 $163.92 $164.74 $165.56 $166.39 $167.22 $167.22


Daily liquids productioni 180,000 159,303 124,129 96,721 75,365 58,724 45,758

Y ea rl y P ro duc ti on i n b bl 63,0 00,00 0 5 5,755 ,894 43, 444, 993 33, 852,3 39 2 6,37 7,742 20 ,553, 537 16,0 15,31 6

Gas production mmBTU) 66,060 58,464 45,555 35,497 27,659 21,552 16,793

Y ea rl y G as P ro duc ti on 23,1 21,00 0 2 0,462 ,413 15, 944, 312 12, 423,8 08 9, 680, 631 7, 543,1 48 5 ,877 ,621

Opening Balance $39,191,182,910 $47,880,554,037 $56,072,610,373 $62,680,858,718 $67,841,131,519 $71,043,810,048 $73,788,961,884

Loan $0 $0 $0 $0 $0 $0 $0

Cash Revenue $10,345,171,838.33 $9,256,797,145.85 $7,257,661,783.06 $5,690,903,679.36 $4,456,523,939.40 $3,484,353,501.30 $2,711,313,126.76

TOTAL RECEIPTS $10,345,171,838 $9,256,797,146 $7,257,661,783 $5,690,903,679 $4,456,523,939 $3,484,353,501 $2,711,313,127

Cash Payments

CAPEX $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsuma - $1 4, 57 3, 00 0 - $1 4, 57 3, 00 0 - $1 4, 47 4, 00 0 - $1 4, 30 7, 00 0 - $1 4, 17 6, 00 0 - $1 4, 07 5, 00 0 - $1 3, 99 6, 00 0

Inspectionandmainte - $4 6, 62 1, 00 0 - $4 6, 62 1, 00 0 - $4 6, 76 8, 00 0 - $6 8, 52 5, 00 0 - $4 6, 62 1, 00 0 - $4 6, 62 1, 00 0 - $4 6, 62 1, 00 0

Operatingpersonnel - $1 1, 78 0, 00 0 - $1 1, 78 0, 00 0 - $1 1, 78 0, 00 0 - $1 1, 78 0, 00 0 - $1 1, 78 0, 00 0 - $1 1, 78 0, 00 0 - $1 1, 78 0, 00 0

Insurance - $5 8, 38 5, 00 0 - $5 8, 38 5, 00 0 - $5 8, 38 5, 00 0 - $5 8, 38 5, 00 0 - $5 8, 38 5, 00 0 - $5 8, 38 5, 00 0 - $5 8, 38 5, 00 0

Wells -$423,588,000 $0 -$40,060,000 $0 -$365,132,000 $0 -$40,060,000

Field/projectcosts - $1 40 ,4 15 ,0 00 - $3 4, 51 8, 00 0 - $4 4, 54 5, 00 0 - $3 9, 92 7, 00 0 - $1 25 ,7 02 ,0 00 - $3 4, 39 3, 00 0 - $4 4, 38 9, 00 0

Tariffcosts - $7 2, 45 0, 00 0 - $7 2, 45 0, 00 0 - $6 4, 11 9, 00 0 - $4 9, 96 2, 00 0 - $3 8, 93 0, 00 0 - $3 0, 33 4, 00 0 - $2 3, 63 7, 00 0

Loan repayments $0 $0 $0 $0 $0 $0 $0

Tax payments -$5 35 ,5 00 ,0 00 -$4 73 ,9 25 ,0 98 -$3 69 ,2 82 ,4 39 -$2 87 ,7 44 ,8 78 -$2 24 ,2 10 ,8 11 -$1 74 ,7 05 ,0 65 -$1 36 ,1 30 ,1 88

Depreciation -$352,488,712 -$352,488,712 $0 $0 $0 $0 $0


Total Payments -$1 ,6 55 ,8 00 ,7 12 -$1 ,0 64 ,7 40 ,8 09 -$6 49 ,4 13 ,4 39 -$5 30 ,6 30 ,8 78 -$1 ,2 53 ,8 45 ,4 11 -$7 39 ,2 01 ,6 65 -$7 43 ,9 06 ,7 88 -$3 68 ,9 08 ,6 00 -$3 68 ,9 08 ,6 00

Cash Book Balance $47,880,554,037 $56,072,610,373 $62,680,858,718 $67,841,131,519 $71,043,810,048 $73,788,961,884 $75,756,368,223 $75,387,459,623 $75,018,551,023

Net Cash Flow $ 8, 68 9, 37 1, 12 7 $ 8, 19 2, 05 6, 33 7 $ 6, 60 8, 24 8, 34 4 $ 5, 16 0, 27 2, 80 1 $ 3, 20 2, 67 8, 52 9 $ 2, 74 5, 15 1, 83 6 $ 1, 96 7, 40 6, 33 9 -$3 68 ,9 08 ,6 00 -$3 68 ,9 08 ,6 00

Cumulative Net Cash Flo $47,880,554,037 $56,072,610,373 $62,680,858,718 $67,841,131,519 $71,043,810,048 $73,788,961,884 $75,756,368,223 $75,387,459,623 $75,018,551,023


Sub total -$6,136,359,000 Interest Rate 12% year 1 2011 -$7,798,115,000 $0 -$7,798,115,000

Contengency -$1,161,756,000 year 2 2012 -$8,733,888,800 $0 -$8,733,888,800

Lo an -$7 ,79 8,1 15,00 0 year 3 2013 -$9,781,955,456 -$1,222,744,432 -$8,559,211,024

year 4 2014 -$9,586,316,347 -$1,369,473,764 -$8,216,842,583

year 5 2015 -$9,202,863,693 -$1,533,810,616 -$7,669,053,078

year 6 2016 -$8,589,339,447 -$1,717,867,889 -$6,871,471,557

year 7 2017 -$7,696,048,144 -$1,924,012,036 -$5,772,036,108

year 8 2018 -$6,464,680,441 -$2,154,893,480 -$4,309,786,961

year 9 2019 -$4,826,961,396 -$2,413,480,698 -$2,413,480,698

year 10 2020 -$2,703,098,382 -$2,703,098,382 $0

Decommision

Scenario 2 : Offloading to Shuttle

Tankers Using CALM BUOY

Year NCF Discount Factor & NPVDiscount Factor & NPV Discount Factor & NPV



NCF Cumulative NCF 5% NPV 5% Cumulative NPV 5% 10% NPV10% Cumulative NPV 10% 1 5% NPV15% Cumulative NPV 15%

- 0 $7,798,115,000 $7,798,115,000 - - - - - - - - -

0 0 $0 $7,798,115,000 1.000 $0 $0 1.000 $0 $0 1.000 $0 $0

1 0 $2,912,778,584 $10,710,893,584 0.952 $2,774,074,842 $2,774,074,842 0.909 $2,647,980,531 $2,647,980,531 0.870 $2,532,850,942 $2,532,850,942

2 0 $5,998,755,353 $16,709,648,937 0.907 $5,441,047,939 $8,215,122,781 0.826 $4,957,649,052 $7,605,629,583 0.756 $4,535,920,872 $7,068,771,814

3 0 $9,265,712,463 $25,975,361,400 0.864 $8,004,070,803 $16,219,193,584 0.751 $6,961,466,915 $14,567,096,497 0.658 $6,092,356,350 $13,161,128,164

4 0 $9,545,584,941 $35,520,946,342 0.823 $7,853,176,355 $24,072,369,939 0.683 $6,519,762,954 $21,086,859,452 0.572 $5,457,719,171 $18,618,847,335

5 0 $9,833,948,649 $45,354,894,991 0.784 $7,705,156,086 $31,777,526,025 0.621 $6,106,108,406 $27,192,967,858 0.497 $4,889,210,484 $23,508,057,820

6 0 $10,033,771,573 $55,388,666,564 0.746 $7,487,354,834 $39,264,880,859 0.564 $5,663,802,473 $32,856,770,331 0.432 $4,337,876,342 $27,845,934,162

7 0 $10,138,510,820 $65,527,177,383 0.711 $7,205,250,355 $46,470,131,214 0.513 $5,202,659,134 $38,059,429,465 0.376 $3,811,441,747 $31,657,375,909

8 0 $10,232,963,516 $75,760,140,900 0.677 $6,926,072,498 $53,396,203,712 0.467 $4,773,753,002 $42,833,182,467 0.327 $3,345,173,925 $35,002,549,8349 0 $10,345,171,838 $86,105,312,738 0.645 $6,668,590,007 $60,064,793,719 0.424 $4,387,362,738 $47,220,545,205 0.284 $2,940,743,500 $37,943,293,334

10 0 $9,256,797,146 $95,362,109,884 0.614 $5,682,870,453 $65,747,664,172 0.386 $3,568,896,021 $50,789,441,226 0.247 $2,288,138,682 $40,231,432,016

11 0 $7,257,661,783 $102,619,771,667 0.585 $4,243,404,532 $69,991,068,704 0.350 $2,543,766,179 $53,333,207,406 0.215 $1,559,985,213 $41,791,417,229

12 #REF! $5,690,903,679 $108,310,675,346 0.557 $3,168,908,112 $73,159,976,816 0.319 $1,813,297,293 $55,146,504,698 0.187 $1,063,670,589 $42,855,087,817

13 #REF! $4,456,523,939 $112,767,199,286 0.530 $2,363,389,795 $75,523,366,610 0.290 $1,290,896,243 $56,437,400,941 0.163 $724,309,730 $43,579,397,547

14 #REF! $3,484,353,501 $116,251,552,787 0.505 $1,759,835,290 $77,283,201,901 0.263 $917,539,178 $57,354,940,119 0.141 $492,439,004 $44,071,836,552

15 #REF! $2,711,313,127 $118,962,865,914 0.481 $1,304,187,972 $78,587,389,873 0.239 $649,066,806 $58,004,006,925 0.123 $333,205,431 $44,405,041,982

16 2028 $0 $118,962,865,914 0.458 $0 $78,587,389,873 0.218 $0 $58,004,006,925 0.107 $0 $44,405,041,982

17 2029 $0 $118,962,865,914 0.436 $0 $78,587,389,873 0.198 $0 $58,004,006,925 0.093 $0 $44,405,041,982

- 0 $7,798,115,000 $7,798,115,000 $500,000,000 $500,000,000 $7,298,115,000

0 0 $0 $7 ,7 98 ,1 15 ,0 00 $7, 298 ,1 15 ,0 00 $7 ,7 98 ,1 15 ,000 $0

1 0 $2,912,778,584 $10,710,893,584 $6,739,176,144 $14,537,291,144 -$3,826,397,560

2 0 $5,998,755,353 $16,709,648,937 $2,267,410,475 $16,804,701,619 -$95,052,682

3 0 $9,265,712,463 $25,975,361,400 $2,685,271,327 $19,489,972,946 $6,485,388,454

4 0 $9,545,584,941 $35,520,946,342 $2,844,183,601 $22,334,156,547 $13,186,789,795

5 0 $9,833,948,649 $45,354,894,991 $3,506,742,748 $25,840,899,295 $19,513,995,696

6 0 $10,033,771,573 $55,388,666,564 $3,281,393,192 $29,122,292,487 $26,266,374,077

7 0 $10,138,510,820 $65,527,177,383 $3,617,251,410 $32,739,543,897 $32,787,633,487

8 0 $10,232,963,516 $75,760,140,900 $3,829,414,093 $36,568,957,990 $39,191,182,910

9 0 $10,345,171,838 $86,105,312,738 $1,655,800,712 $38,224,758,702 $47,880,554,037

10 0 $9,256,797,146 $95,362,109,884 $1,064,740,809 $39,289,499,511 $56,072,610,373

11 0 $7,257,661,783 $102,619,771,667 $649,413,439 $39,938,912,949 $62,680,858,718

12 #REF! $5,690,903,679 $108,310,675,346 $530,630,878 $40,469,543,828 $67,841,131,519

13 #REF! $4,456,523,939 $112,767,199,286 $1,253,845,411 $41,723,389,238 $71,043,810,04814 #REF! $3,484,353,501 $116,251,552,787 $739,201,665 $42,462,590,903 $73,788,961,884

15 #REF! $2,711,313,127 $118,962,865,914 $743,906,788 $43,206,497,691 $75,756,368,223

16 2028 $0 $118,962,865,914 $368,908,600 $43,575,406,291 $75,387,459,623

17 2029 $0 $118,962,865,914 $368,908,600 $43,944,314,891 $75,018,551,023


RevenueExpenses

Cumulative

ExpensesNet Profit

-$20,000,000,000

$0

$20,000,000,000

$40,000,000,000

$60,000,000,000

$80,000,000,000

$100,000,000,000

$120,000,000,000

$140,000,000,000

Cumulative

Revenue

Cumulative

Expenses

Net Profit

Total

expenses VS

Revenue

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

0 0 0 0 0 0 0 0 0 2029

NCF

NPV 5%

NPV10%

NPV15%

NCF VS NPV

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

Revenue

Expenses

Revenue & Expenses

$0

$20,000,000,000

$40,000,000,000

$60,000,000,000

$80,000,000,000

$100,000,000,000

$120,000,000,000

$140,000,000,000

0 0 0 0 0 0 0 0 0

2 0 2 9

Cumulative NCF

Cumulative NPV

5%

Cumulative NPV

10%

Cumulative NPV

15%


Scenario 2 : Offloading to

Shuttle Tankers Using CALM

BUOY

axation Daily production of NG



Year Amount ABS Amount Year mmBUT

2011 $0 $0 2011 0

2012 $0 $0 2012 0

2013 -$178,500,000 $178,500,000 2013 26,118

2014 -$357,000,000 $357,000,000 2014 52,235

2015 -$535,500,000 $535,500,000 2015 78,353

2016 -$535,500,000 $535,500,000 2016 78,353

2017 -$535,500,000 $535,500,000 2017 78,353

2018 -$535,500,000 $535,500,000 2018 78,3532019 -$535,500,000 $535,500,000 2019 78,353

2020 -$535,500,000 $535,500,000 2020 78,353

2021 -$535,500,000 $535,500,000 2021 78,353

2022 -$473,925,098 $473,925,098 2022 78,353

2023 -$369,282,439 $369,282,439 2023 64,162

2024 -$287,744,878 $287,744,878 2024 42,416

2025 -$224,210,811 $224,210,811 2025 28,041

2026 -$174,705,065 $174,705,065 2026 18,537

2027 -$136,130,188 $136,130,188 2027 12,255

Taxes paid $5,949,998,478

Production

Year bbl/day m³/day bbl/year m³/year

2011 0 0 0 0

2012 0 0 0 0

2013 60,000 7,154 21,000,000 3,338,733

2014 120,000 14,309 42,000,000 6,677,466

2015 180,000 21,463 63,000,000 10,016,200

2016 180,000 28,618 63,000,000 10,016,200

2017 180,000 28,618 63,000,000 10,016,200

2018 180,000 28,618 63,000,000 10,016,200

2019 180,000 28,618 63,000,000 10,016,200

2020 180,000 28,618 63,000,000 10,016,2002021 180,000 28,618 27,423,466 4,359,983

2022 180,000 28,618 27,423,466 4,359,983

2023 147,399 23,565 22,456,693 3,570,329

2024 97,443 15,766 14,845,755 2,360,286

2025 64,418 10,548 9,814,287 1,560,347

2026 42,586 7,057 6,488,066 1,031,520

2027 28,153 4,721 4,289,155 681,921

y p

$0

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

Taxation

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

bbl/day

bbl/day

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

mmBUT

mmBUT

Scenario 2 : Offloading to

Shuttle Tankers Using CALM

BUOY

Scen 3:Aft offloading reel+gas pipeline


Project name



Currency Rate/$

Offshore Brazil1 $ 1.00


Equipment S.America $ 1.00Materials GulfofMexico $ 1.00








S.America

300.00 700.00

71.20 2000.00

333.00 7000.00

1.10 400.00

367.00 11.80

71.20 5.92

40.00

1.10

16.00 0.00

0.30 30.00

10.00

km



Reservoirlength km

Country Brazil

Initialwatercut %


Scen.3:Aftoffloadingreel+gaspipeline

CamposBasin

Oilfield

Oil

FPSO+Subsea


Region LatinAmerica

MMbbl

m

ppm

Reservoirwidth

°API

%

Procurementstrategy

Technicaldatabase

Mbbl/day

MMscf/day

Mbbl/day

MMscf/day

nm³/m³

Reserves

Waterdepth

H2Scontent

Gasmolecularweight


Oildensity@STP

CO2content






Gasoilratio

Designfactor

Projectname

Basin

Unitset

Developmenttype

Developmentconcept

Overallinput





1.00 1.05 1.00 26.80 1.00 28.26 NG 4.03 $/mmBTU NG 142.59 $/1000m³


1.00 158.99 1.00 1,000.00 1.00 6.29


NG 7.00 $/mmBTU NG 247.67 $/1000m³

Oil 85.00 $/bbl Oil 534.63 $/m³


From yr 1 - 5 3.00% From yr 6 - 10 1.00% From yr 14 - 16 0.00% From yr 20 0.00% From yr -2 - 7 5.00% From yr 9 -12 10.00% From yr 14 - 15 -10.00%


119,240 m³ S ta rt V al ue - $5,865 ,123 ,350 U SD

End of economic life Va -$1,888,412,748 USD


Production Year -6 -5 -4 -3 -2 -1 1 2 3 4 5 6 7 8

Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Oil price per bbl $126.87 $133.21 $137.21 $141.33 $145.57 $149.93 $154.43 $157.52 $159.09 $160.69


Daily liquids productio 0 0 0 0 0 0 60,000 120,000 180,000 180,000 180,000 180,000 180,000 180,000

Yearly Production in bb 0 0 0 0 0 0 21,000,000 42,000,000 63,000,000 63,000,000 63,000,000 63,000,000 63,000,000 63,000,000

Gas production mmBT 0 0 0 0 0 0 403 807 1,210 1,210 1,210 1,210 1,210 1,210


64

Opening Balance $ 0 $ 5, 36 5, 12 3, 35 0 $ 0 -$1 ,5 80 ,1 14 ,0 26 $ 3, 87 1, 73 5, 75 8 $ 12 ,9 41 ,0 55 ,5 01 $ 22 ,2 69 ,2 71 ,4 92 $ 31 ,6 04 ,0 88 ,1 70 $ 41 ,3 04 ,5 88 ,9 33 $ 50 ,9 61 ,4 41 ,4 12

Loan $5,865,123,350 $0 $0 $0 $0 $0 $0 $0 $0 $0

Cash Revenue $0 $0 $3,508,569,356 $7,252,739,327 $11,244,993,425 $11,623,829,951 $12,016,105,909 $12,325,036,696 $12,544,339,199 $12,518,500,476

TOTAL RECEIPTS $5,865,123,350 $0 $3,508,569,356 $7,252,739,327 $11,244,993,425 $11,623,829,951 $12,016,105,909 $12,325,036,696 $12,544,339,199 $12,518,500,476

Cash Payments

CAPEX -$500,000,000 -$5,365,123,350 $0 $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsu $0 $0 - $257 ,816, 000 - $13,88 8,00 0 - $15, 970, 000 - $18,60 0,00 0 - $18, 600, 000 - $18,60 0,00 0 - $18, 600, 000 - $18,6 00,00 0

Inspectionandmaint $0 $0 -$614,439,000 -$3 8, 51 1, 00 0 -$3 8, 51 1, 00 0 -$3 8, 51 1, 00 0 -$3 8, 51 1, 00 0 -$3 8, 69 2, 00 0 -$5 6, 71 7, 00 0 -$3 8, 51 1, 00 0


Insurance $0 $0 - $548 ,730, 000 - $36,58 2,00 0 - $36, 582, 000 - $36,58 2,00 0 - $36, 582, 000 - $36,58 2,00 0 - $36, 582, 000 - $36,5 82,00 0

Wells $0 $0 -$754,670,000 $0 -$36,744,000 $0 -$184,504,000 $0 -$36,744,000 $0

Field/projectcosts $0 $0 -$601,543,000 -$26,087,000 -$35,794,000 -$27,265,000 -$73,391,000 -$27,310,000 -$41,003,000 -$27,265,000

Tariffcosts $0 $0 - $805 ,000, 000 - $24,15 0,00 0 - $48, 300, 000 - $72,45 0,00 0 - $72, 450, 000 - $72,45 0,00 0 - $72, 450, 000 - $72,4 50,00 0

Loan repayments $0 $0 -$919,651,341 -$1,030,009,502 -$1,153,610,643 -$1,292,043,920 -$1,447,089,190 -$1,620,739,893 -$1,815,228,680 -$2,033,056,121

Tax payments $ 0 $ 0 - $1 78 ,5 00 ,0 00 - $3 57 ,0 00 ,0 00 - $5 35 ,5 00 ,0 00 - $5 35 ,5 00 ,0 00 - $5 35 ,5 00 ,0 00 - $5 35 ,5 00 ,0 00 - $5 35 ,5 00 ,0 00 - $5 35 ,5 00 ,0 00

Depreciation $0 $0 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040

Total Payments -$500,000,000 -$5,365,123,350 -$5,088,683,381 -$1,800,889,542 -$2,175,673,683 -$2,295,613,960 -$2,681,289,230 -$2,624,535,933 -$2,887,486,720 -$3,036,626,162

Cash Book Balance $5,365,123,350 $0 -$1,580,114,026 $3,871,735,758 $12,941,055,501 $22,269,271,492 $31,604,088,170 $41,304,588,933 $50,961,441,412 $60,443,315,727

Net Cash Flow $5,365,123,350 -$5,365,123,350 -$1,580,114,026 $5,451,849,784 $9,069,319,742 $9,328,215,991 $9,334,816,679 $9,700,500,763 $9,656,852,479 $9,481,874,315

Cumulative Net Cash Fl $5,365,123,350 $0 -$1,580,114,026 $3,871,735,758 $12,941,055,501 $22,269,271,492 $31,604,088,170 $41,304,588,933 $50,961,441,412 $60,443,315,727

2014 Price


Depreciation

FPSO Capacity

Exploration Period

Exploration Period

Exploration Period

Scenario 3 : Offloading by Aft Reel System on FPSO To

Shuttle Tanker (Oil) & Gas via Pipeline to Network

Production Year 9 10 11 12 13 14 15 16 17



Year 2021 2022 2023 2024 2025 2026 2027 2028 2029

Oil price per bbl $162.29 $163.92 $164.74 $165.56 $166.39 $167.22 $167.22


Daily liquids productio 180,000 159,303 124,129 96,721 75,365 58,724 45,758

Y ea rl y P ro du ct io n i n b b 6 3, 00 0, 00 0 5 5, 75 5, 89 4 4 3, 44 4, 99 3 3 3, 85 2, 33 9 2 6, 37 7, 74 2 2 0, 55 3, 53 7 1 6, 01 5, 31 6

Gas production mmBT 1,210 1,071 834 650 507 395 308

Yearly Gas Product ion 4 23 ,4 64 ,3 92 3 74 ,7 71 ,9 95 2 92 ,0 22 ,3 40 2 27 ,5 43 ,8 09 1 77 ,3 02 ,1 37 1 38 ,1 53 ,8 26 1 07 ,6 49 ,4 62

Opening Balance $60,443,315,727 $72,000,650,181 $82,762,958,679 $91,509,168,801 $98,509,213,760 $103,516,778,814 $107,420,878,565

Loan $0 $0 $0 $0 $0 $0 $0

Cash Revenue $12,859,262,494.38 $11,704,303,635.71 $9,355,468,560.58 $7,488,975,837.30 $5,864,587,064.01 $4,471,800,016.36 $3,403,789,623.77

TOTAL RECEIPTS $12,859,262,494 $11,704,303,636 $9,355,468,561 $7,488,975,837 $5,864,587,064 $4,471,800,016 $3,403,789,624

Cash Payments

CAPEX $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsu -$1 8, 60 0, 00 0 -$1 8, 60 0, 00 0 -$1 7, 95 6, 00 0 -$1 6, 96 8, 00 0 -$1 6, 29 0, 00 0 -$1 5, 81 8, 00 0 -$1 5, 48 3, 00 0

Inspectionandmaint -$3 8, 51 1, 00 0 -$3 8, 51 1, 00 0 -$3 8, 69 2, 00 0 -$5 6, 71 7, 00 0 -$3 8, 51 1, 00 0 -$3 8, 51 1, 00 0 -$3 8, 51 1, 00 0

Operatingpersonnel - $9 ,5 48 ,0 00 - $9 ,5 48 ,0 00 - $9 ,5 48 ,0 00 - $9 ,5 48 ,0 00 - $9 ,5 48 ,0 00 - $9 ,5 48 ,0 00 - $9 ,5 48 ,0 00

Insurance -$3 6, 58 2, 00 0 -$3 6, 58 2, 00 0 -$3 6, 58 2, 00 0 -$3 6, 58 2, 00 0 -$3 6, 58 2, 00 0 -$3 6, 58 2, 00 0 -$3 6, 58 2, 00 0

Wells -$238,686,000 $0 -$36,744,000 $0 -$184,504,000 $0 -$36,744,000

Field/projectcosts -$8 6, 93 7, 00 0 -$2 7, 26 5, 00 0 -$3 6, 33 5, 00 0 -$3 1, 40 9, 00 0 -$7 2, 81 4, 00 0 -$2 6, 57 0, 00 0 -$3 5, 67 2, 00 0

Tariffcosts -$7 2, 45 0, 00 0 -$7 2, 45 0, 00 0 -$6 4, 11 9, 00 0 -$4 9, 96 2, 00 0 -$3 8, 93 0, 00 0 -$3 0, 33 4, 00 0 -$2 3, 63 7, 00 0

Loan repayments $0 $0 $0 $0 $0 $0 $0

Tax payments -535500000 -473925097.5 -369282438.6 -287744878.2 -224210810.7 -174705064.9 -136130187.6

Depreciation -$265,114,040 -$265,114,040 $0 $0 $0 $0 $0


Total Payme nts -$1 ,3 01 ,9 28 ,0 40 -$9 41 ,9 95 ,1 38 -$6 09 ,2 58 ,4 39 -$4 88 ,9 30 ,8 78 -$8 57 ,0 22 ,0 11 -$5 67 ,7 00 ,2 65 -$5 67 ,9 39 ,3 88 -$2 35 ,6 32 ,2 00 -$2 35 ,6 32 ,2 00


Net Cash Flow $11,557,334,454 $10,762,308,498 $8,746,210,122 $7,000,044,959 $5,007,565,053 $3,904,099,751 $2,835,850,236 -$235,632,200 -$235,632,200

Cumulative Net Cash Fl $72,000,650,181 $82,762,958,679 $91,509,168,801 $98,509,213,760 $103,516,778,814 $107,420,878,565 $110,256,728,801 $110,021,096,601 $109,785,464,401


Sub total -$3,855,156,000 Interest Rate 12% year 1 2011 -$5,865,123,350 $ 0 - $5 ,8 65 ,1 23 ,3 50

Contengency/Project c -$1,509,967,350 year 2 2012 -$6,568,938,152 $0 -$6,568,938,152

Loan - $5 ,865,123,350 y ea r 3 2013 - $7 ,357, 210, 730 - $919, 651, 341 - $6,43 7,55 9,389

year 4 2014 -$7,210,066,516 -$1,030,009,502 -$6,180,057,013

year 5 2015 -$6,921,663,855 -$1,153,610,643 -$5,768,053,213

year 6 2016 -$6,460,219,598 -$1,292,043,920 -$5,168,175,678

year 7 2017 -$5,788,356,760 -$1,447,089,190 -$4,341,267,570

year 8 2018 -$4,862,219,678 -$1,620,739,893 -$3,241,479,785

year 9 2019 -$3,630,457,360 -$1,815,228,680 -$1,815,228,680

year 10 2020 -$2,033,056,121 -$2,033,056,121 $0

Decommision

Scenario 3 : Offloading by Aft Reel System on FPSO To

Shuttle Tanker (Oil) & Gas via Pipeline to Network

Year NCF

l l l l

Discount Factor & NPVDiscount Factor & NPV Discount Factor & NPV

Scenario 3 :



NCF Cumulative NCF 5% NPV 5% Cumulative NPV 5% 10% NPV10% Cumulative NPV 10% 15% NPV15% Cumulative NPV 15%

- 2011 $5,865,123,350 $5,865,123,350 - - - - - - - - -

0 2012 $0 $5,865,123,350 1.000 $0 $0 1.000 $0 $0 1.000 $0 $0

1 2 01 3 $ 3, 50 8, 56 9, 35 6 $ 9, 37 3, 69 2, 70 6 0 .9 52 $ 3, 34 1, 49 4, 62 4 $ 3, 34 1, 49 4, 62 4 0 .9 09 $ 3, 18 9, 60 8, 50 5 $ 3, 18 9, 60 8, 50 5 0 .8 70 $ 3, 05 0, 92 9, 87 4 $ 3, 05 0, 92 9, 87 4

2 2 01 4 $ 7, 25 2, 73 9, 32 7 $ 16 ,6 26 ,4 32 ,0 32 0 .9 07 $ 6, 57 8, 44 8, 36 9 $ 9, 91 9, 94 2, 99 3 0 .8 26 $ 5, 99 3, 99 9, 44 3 $ 9, 18 3, 60 7, 94 9 0 .7 56 $ 5, 48 4, 11 2, 91 2 $ 8, 53 5, 04 2, 78 7

3 2015 $11,244,993,425 $27,871,425,457 0.864 $9,713,848,116 $19,633,791,109 0.751 $8,448,529,996 $17,632,137,945 0.658 $7,393,765,710 $15,928,808,497

4 2016 $11,623,829,951 $39,495,255,408 0.823 $9,562,953,667 $29,196,744,776 0.683 $7,939,232,259 $25,571,370,204 0.572 $6,645,962,501 $22,574,770,998

5 2017 $12,016,105,909 $51,511,361,317 0.784 $9,414,933,399 $38,611,678,175 0.621 $7,461,056,379 $33,032,426,583 0.497 $5,974,128,307 $28,548,899,305

6 2018 $12,325,036,696 $63,836,398,012 0.746 $9,197,132,146 $47,808,810,321 0.564 $6,957,161,902 $39,989,588,485 0.432 $5,328,453,484 $33,877,352,789

7 2019 $12,544,339,199 $76,380,737,211 0.711 $8,915,027,668 $56,723,837,989 0.513 $6,437,229,498 $46,426,817,982 0.376 $4,715,881,746 $38,593,234,535

8 2020 $12,518,500,476 $88,899,237,688 0.677 $8,473,013,876 $65,196,851,864 0.467 $5,839,972,861 $52,266,790,844 0.327 $4,092,320,012 $42,685,554,547

9 2021 $12,859,262,494 $101,758,500,182 0.645 $8,289,195,260 $73,486,047,124 0.424 $5,453,582,598 $57,720,373,442 0.284 $3,655,404,974 $46,340,959,520

10 2022 $11,704,303,636 $113,462,803,818 0.614 $7,185,427,125 $80,671,474,250 0.386 $4,512,515,724 $62,232,889,166 0.247 $2,893,124,855 $49,234,084,375

11 2023 $9,355,468,561 $122,818,272,378 0.585 $5,469,948,707 $86,141,422,957 0.350 $3,279,034,657 $65,511,923,823 0.215 $2,010,894,562 $51,244,978,937

12 2024 $7,488,975,837 $130,307,248,216 0.557 $4,170,141,970 $90,311,564,927 0.319 $2,386,218,495 $67,898,142,318 0.187 $1,399,743,132 $52,644,722,069

1 3 2 02 5 $ 5, 86 4, 58 7, 06 4 $ 13 6, 17 1, 83 5, 28 0 0 .5 30 $ 3, 11 0, 11 5, 73 3 $ 93 ,4 21 ,6 80 ,6 60 0 .2 90 $ 1, 69 8, 76 1, 97 4 $ 69 ,5 96 ,9 04 ,2 92 0. 16 3 $ 95 3, 15 9, 35 2 $ 53 ,5 97 ,8 81 ,4 21

1 4 2 02 6 $ 4, 47 1, 80 0, 01 6 $ 14 0, 64 3, 63 5, 29 6 0 .5 05 $ 2, 25 8, 56 2, 88 0 $ 95 ,6 80 ,2 43 ,5 40 0 .2 63 $ 1, 17 7, 56 4, 70 7 $ 70 ,7 74 ,4 69 ,0 00 0. 14 1 $ 63 1, 99 3, 49 5 $ 54 ,2 29 ,8 74 ,9 16

1 5 2 02 7 $ 3, 40 3, 78 9, 62 4 $ 14 4, 04 7, 42 4, 92 0 0 .4 81 $ 1, 63 7, 28 1, 00 7 $ 97 ,3 17 ,5 24 ,5 47 0 .2 39 $ 81 4, 84 0, 17 4 $ 71 ,5 89 ,3 09 ,1 73 0. 12 3 $ 41 8, 30 6, 97 4 $ 54 ,6 48 ,1 81 ,8 90

16 2028 $0 $144,047,424,920 0.458 $0 $97,317,524,547 0.218 $0 $71,589,309,173 0.107 $0 $54,648,181,890

17 2029 $0 $144,047,424,920 0.436 $0 $97,317,524,547 0.198 $0 $71,589,309,173 0.093 $0 $54,648,181,890

- 2 01 1 $ 5, 86 5, 12 3, 35 0 $ 5, 86 5, 12 3, 35 0 $ 50 0, 00 0, 00 0 $ 50 0, 00 0, 00 0 $5,365,123,350

0 2 012 $0 $5,865,123,350 $5,365,123,350 $5,865,123,350 $0

1 2013 $3,508,569,356 $9,373,692,706 $5,088,683,381 $10,953,806,731 -$1,580,114,026

2 2014 $7,252,739,327 $16,626,432,032 $1,800,889,542 $12,754,696,274 $3,871,735,758

3 2015 $11,244,993,425 $27,871,425,457 $2,175,673,683 $14,930,369,956 $12,941,055,501

4 2016 $11,623,829,951 $39,495,255,408 $2,295,613,960 $17,225,983,916 $22,269,271,492

5 2017 $12,016,105,909 $51,511,361,317 $2,681,289,230 $19,907,273,146 $31,604,088,170

6 2018 $12,325,036,696 $63,836,398,012 $2,624,535,933 $22,531,809,079 $41,304,588,933

7 2019 $12,544,339,199 $76,380,737,211 $2,887,486,720 $25,419,295,799 $50,961,441,412

8 2020 $12,518,500,476 $88,899,237,688 $3,036,626,162 $28,455,921,961 $60,443,315,727

9 2021 $12,859,262,494 $101,758,500,182 $1,301,928,040 $29,757,850,001 $72,000,650,181

10 2022 $11,704,303,636 $113,462,803,818 $941,995,138 $30,699,845,139 $82,762,958,679

11 2023 $9,355,468,561 $122,818,272,378 $609,258,439 $31,309,103,577 $91,509,168,801

12 2024 $7,488,975,837 $130,307,248,216 $488,930,878 $31,798,034,455 $98,509,213,760

13 2025 $5,864,587,064 $136,171,835,280 $857,022,011 $32,655,056,466 $103,516,778,814

14 2026 $4,471,800,016 $140,643,635,296 $567,700,265 $33,222,756,731 $107,420,878,565

15 2027 $3,403,789,624 $144,047,424,920 $567,939,388 $33,790,696,119 $110,256,728,801

16 2028 $0 $144,047,424,920 $235,632,200 $34,026,328,319 $110,021,096,601

17 2029 $0 $144,047,424,920 $235,632,200 $34,261,960,519 $109,785,464,401

Cumulative

RevenueExpenses

Cumulative

ExpensesNet ProfitYear Revenue

-$20,000,000,000

$0

$20,000,000,000

$40,000,000,000

$60,000,000,000

$80,000,000,000

$100,000,000,000

$120,000,000,000

$140,000,000,000

$160,000,000,000

Cumulative

Revenue

Cumulative

Expenses

Net Profit

Total

expenses VS

Revenue

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

$14,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

NCF

NPV 5%

NPV10%

NPV15%

NCF VS NPV

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000$14,000,000,000

Revenue

Expenses

Revenue & Expenses

$0

$20,000,000,000

$40,000,000,000

$60,000,000,000

$80,000,000,000

$100,000,000,000

$120,000,000,000

$140,000,000,000

$160,000,000,000Cumulative NCF

Cumulative NPV

5%

Cumulative NPV

10%

Cumulative NPV

15%


Scenario 3 :Offloading by Aft Reel

System on FPSO To

Shuttle Tanker (Oil) &

Gas via Pipeline to

Network

Project name


Scen. 3.1:Aft reel + gas pipeline (400MMbbl)



Currency Rate/$

Offshore Brazil1 $ 1.00


Equipment S.America $ 1.00Materials GulfofMexico $ 1.00








S.America

300.00 400.00

71.20 2000.00

333.00 7000.00

1.10 400.00

367.00 8.94

71.20 4.47

40.00

1.10

16.00 0.00

0.30 30.00

10.00

Projectname

Basin

Unitset

Developmenttype

Developmentconcept

Overallinput





Gasoilratio

Designfactor


Oildensity@STP

CO2content


Reserves

Waterdepth

H2Scontent

Gasmolecularweight

Procurementstrategy

Technicaldatabase

Mbbl/day

MMscf/day

Mbbl/day

MMscf/day

nm³/m³

°API

%

MMbbl

m

ppm

Scen.3.1:Aftreel gaspipeline(400MMbbl)

CamposBasin

Oilfield

Oil

FPSO+Subsea


Region LatinAmerica

Country Brazil

Initialwatercut %


Reservoirwidth km



Reservoirlength km

Daily production of NGTaxation




2011 $0 $0 2011 0

2012 $0 $0 2012 0

2013 -$178,500,000 $178,500,000 2013 403

2014 -$357,000,000 $357,000,000 2014 807

2015 -$535,500,000 $535,500,000 2015 1,210

2016 -$535,500,000 $535,500,000 2016 1,210

2017 -$535,500,000 $535,500,000 2017 1,210

2018 -$535,500,000 $535,500,000 2018 1,210

2019 -$535,500,000 $535,500,000 2019 1,210

2020 -$535,500,000 $535,500,000 2020 1,210

2021 -$535,500,000 $535,500,000 2021 1,210

2022 -$473,925,098 $473,925,098 2022 1,071

2023 -$369,282,439 $369,282,439 2023 834

2024 -$287,744,878 $287,744,878 2024 650

2025 -$224,210,811 $224,210,811 2025 507

2026 -$174,705,065 $174,705,065 2026 395

2027 -$136,130,188 $136,130,188 2027 308

$5,949,998,478

ily Production


2011 0 0 0 0

2012 0 0 0 0

2013 60,000 9,539 21,000,000 3,338,733

2014 120,000 19,078 42,000,000 6,677,466

2015 180,000 28,618 63,000,000 10,016,200

2016 180,000 28,618 63,000,000 10,016,200

2017 180,000 28,618 63,000,000 10,016,200

2018 180,000 28,618 63,000,000 10,016,200

2019 180,000 28,618 63,000,000 10,016,200

2020 180,000 28,618 63,000,000 10,016,2002021 180,000 28,618 63,000,000 10,016,200

2022 159,303 25,327 55,755,894 8,864,479

2023 124,129 19,735 43,444,993 6,907,202

2024 96,721 15,377 33,852,339 5,382,092

2025 75,365 11,982 26,377,742 4,193,726

2026 58,724 9,336 20,553,537 3,267,751

2027 45,758 7,275 16,015,316 2,546,232

Total Taxes paid

$0

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

Taxation

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

bbl/day

bbl/day

0

200

400

600

800

1,000

1,200

1,400

2011 2013 2015 2017 2019 2021 2023 2025 2027

mmBUT

mmBUT

Scenario 3 :Offloading by Aft Reel System on

FPSO To Shuttle Tanker (Oil) & Gas

via Pipeline to Network





mmBTU GJ GJ m mmBTU m Item Price Unit Item Price Unit

1.00 1.05 1.00 26.80 1.00 28.26 NG 4.03 $/mmBTU NG 142.59 $/1000m³


1.00 158.99 1.00 1,000.00 1.00 6.29


NG 7.00 $/mmBTU NG 247.67 $/1000m³

Oil 85.00 $/bbl Oil 534.63 $/m³

From yr -5 - 1 5.00% From yr 6 -5.00% From yr 11 - 14 0.50% From yr -5 - 0 5.00% From yr 6 -5.00% From yr 11 - 14 0.50%

From yr 1 - 5 -20.00% From yr 7- 10 0.00% From yr 15 0.00% From yr 1- 5 -20.00% From yr 7-10 0.00% From yr 15 0.00%


119,240 m³ Start Value -$5,865,123,350 US D

End of economic life Val -$1,888,412,748 USD


Production Year -6 -5 -4 -3 -2 -1 1 2 3 4 5 6 7 8

Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Oil price per bbl $126.87 $133.21 $106.57 $85.26 $68.21 $54.56 $43.65 $41.47 $41.47 $41.47




Gas production mmBTU) 0 0 0 0 0 0 403 807 1,210 1,210 1,210 1,210 1,210 1,210


Opening Balance $0 $5,365,123,350 $0 -$2,372,859,362 $171,569,527 $3,210,277,962 $5,086,169,696 $5,742,085,021 $6,287,893,416 $6,570,751,023

Loan $5,865,123,350 $0 $0 $0 $0 $0 $0 $0 $0 $0

Cash Revenue $0 $0 $2,715,824,020 $4,345,318,431 $5,214,382,117 $4,171,505,694 $3,337,204,555 $3,170,344,327 $3,170,344,327 $3,170,344,327

TOTAL RECEIPTS $5,865,123,350 $0 $2,715,824,020 $4,345,318,431 $5,214,382,117 $4,171,505,694 $3,337,204,555 $3,170,344,327 $3,170,344,327 $3,170,344,327

Cash Payments

CAPEX -$500,000,000 -$5,365,123,350 $0 $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsum $ 0 $0 - $257,8 16,0 00 - $1 3,88 8,000 - $15, 970, 000 - $1 8,60 0,000 - $18, 600, 000 - $1 8,60 0,000 - $18, 600, 000 - $18,60 0,00 0


Operatingpersonnel $0 $0 -$143,220,000 -$9,548,000 - $9,548,000 -$9,548,000 - $9,548,000 -$9,548,000 -$9,548,000 -$9,548,000

Insurance $ 0 $0 - $548,7 30,0 00 - $3 6,58 2,000 - $36, 582, 000 - $3 6,58 2,000 - $36, 582, 000 - $3 6,58 2,000 - $36, 582, 000 - $36,58 2,00 0

Wells $0 $0 -$754,670,000 $0 -$36,744,000 $0 -$184,504,000 $0 -$36,744,000 $0

Field/projectcosts $0 $0 -$601,543,000 -$26,087,000 -$35,794,000 -$27,265,000 -$73,391,000 -$27,310,0 00 -$41,003,000 -$27,265,000

Tariffcosts $ 0 $0 - $805,0 00,0 00 - $2 4,15 0,000 - $48, 300, 000 - $7 2,45 0,000 - $72, 450, 000 - $7 2,45 0,000 - $72, 450, 000 - $72,45 0,00 0

Loan repayments $0 $0 -$919,651,341 -$1,030,009,502 -$1,153,610,643 -$1,292,043,920 -$1,447,089,190 -$1,620,739,893 -$1,815,228,680 -$2,033,056,121

Tax payments $ 0 $0 - $178,5 00,0 00 - $357 ,000 ,000 - $535, 500,0 00 - $535 ,500 ,000 - $535, 500,0 00 - $535 ,500 ,000 - $535, 500,0 00 - $53 5,500 ,000

Depreciation $0 $0 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040 -$265,114,040

Total Payments -$500,000,000 - $5,365,123,350 -$5,088,683,381 -$1,800,889,542 -$2,175,673,683 -$2,295,613,960 -$2,681,289,230 -$2,624,535,933 -$2,887,486,720 -$3,036,626,162

Cash Book Balance $ 5,36 5,12 3,35 0 $ 0 -$2 ,3 72 ,8 59 ,3 62 $ 17 1,56 9,52 7 $ 3,21 0,27 7,96 2 $ 5,08 6,16 9,69 6 $ 5,74 2,08 5,02 1 $ 6,28 7,89 3,41 6 $ 6,57 0,75 1,02 3 $ 6,70 4,46 9,18 9

Net Cash Flow $ 5, 36 5, 12 3, 35 0 -$5 ,3 65 ,1 23 ,3 50 -$2 ,3 72 ,8 59 ,3 62 $ 2, 54 4, 42 8, 88 9 $ 3, 03 8, 70 8, 43 5 $ 1, 87 5, 89 1, 73 4 $ 65 5, 91 5, 32 5 $ 54 5, 80 8, 39 5 $ 28 2, 85 7, 60 7 $ 13 3, 71 8, 16 6

Cumulative Net Cash Flo $5,365,123,350 $0 -$2,372,859,362 $171,569,527 $3,210,277,962 $5,086,169,696 $5,742,085,021 $6,287,893,416 $6,570,751,023 $6,704,469,189

2014 Price

Sensitivity Analysis (Factor for oil price per bbl)

Depreciation

FPSO Capacity

Exploration Period

Exploration Period

Exploration Period

Sensitivity Analysis (Factor for oil price per bbl)

Scenario 3 -1 : Oil Prices drop

Production Year 9 10 11 12 13 14 15 16 17

Year 2021 2022 2023 2024 2025 2026 2027 2028 2029



Year 2021 2022 2023 2024 2025 2026 2027 2028 2029

Oil price per bbl $41.47 $41.47 $41.68 $41.88 $42.09 $42.30 $42.30


Daily liquids productioni 180,000 159,303 124,129 96,721 75,365 58,724 45,758

Y ea rl y P ro du ct io n i n b bl 6 3, 00 0, 00 0 5 5, 75 5, 89 4 4 3, 44 4, 99 3 3 3, 85 2, 33 9 2 6, 37 7, 74 2 2 0, 55 3, 53 7 1 6, 01 5, 31 6

Gas production mmBTU) 1,210 1,071 834 650 507 395 308

Yearly Gas Product ion 4 23 ,4 64 ,3 92 3 74 ,7 71 ,9 95 2 92 ,0 22 ,3 40 2 27 ,5 43 ,8 09 1 77 ,3 02 ,1 37 1 38 ,1 53 ,8 26 1 07 ,6 49 ,4 62

Opening Balance $6,704,469,189 $8,544,995,074 $10,384,116,243 $11,952,738,876 $13,169,297,966 $13,647,838,336 $14,126,011,637

Loan $0 $0 $0 $0 $0 $0 $0

Cash Revenue $3,142,453,924.61 $2,781,116,307.60 $2,177,881,071.51 $1,705,489,967.71 $1,335,562,381.26 $1,045,873,565.95 $814,944,688.39

TOTAL RECEIPTS $3,142,453,925 $2,781,116,308 $2,177,881,072 $1,705,489,968 $1,335,562,381 $1,045,873,566 $814,944,688

Cash Payments

CAPEX $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsum - $1 8, 60 0, 00 0 - $1 8, 60 0, 00 0 - $1 7, 95 6, 00 0 - $1 6, 96 8, 00 0 - $1 6, 29 0, 00 0 - $1 5, 81 8, 00 0 - $1 5, 48 3, 00 0

Inspectionandmainte - $3 8, 51 1, 00 0 - $3 8, 51 1, 00 0 - $3 8, 69 2, 00 0 - $5 6, 71 7, 00 0 - $3 8, 51 1, 00 0 - $3 8, 51 1, 00 0 - $3 8, 51 1, 00 0

Operatingpersonnel - $9,54 8,00 0 - $9, 548, 000 - $9,54 8,00 0 - $9, 548, 000 - $9,5 48,00 0 - $9, 548, 000 - $9,54 8,00 0

Insurance - $3 6, 58 2, 00 0 - $3 6, 58 2, 00 0 - $3 6, 58 2, 00 0 - $3 6, 58 2, 00 0 - $3 6, 58 2, 00 0 - $3 6, 58 2, 00 0 - $3 6, 58 2, 00 0

Wells -$238,686,000 $0 -$36,744,000 $0 -$184,504,000 $0 -$36,744,000

Field/projectcosts - $8 6, 93 7, 00 0 - $2 7, 26 5, 00 0 - $3 6, 33 5, 00 0 - $3 1, 40 9, 00 0 - $7 2, 81 4, 00 0 - $2 6, 57 0, 00 0 - $3 5, 67 2, 00 0

Tariffcosts - $7 2, 45 0, 00 0 - $7 2, 45 0, 00 0 - $6 4, 11 9, 00 0 - $4 9, 96 2, 00 0 - $3 8, 93 0, 00 0 - $3 0, 33 4, 00 0 - $2 3, 63 7, 00 0

Loan repayments $0 $0 $0 $0 $0 $0 $0

Tax payments -$5 35 ,5 00 ,0 00 -$4 73 ,9 25 ,0 98 -$3 69 ,2 82 ,4 39 -$2 87 ,7 44 ,8 78 -$2 24 ,2 10 ,8 11 -$1 74 ,7 05 ,0 65 -$1 36 ,1 30 ,1 88

Depreciation -$265,114,040 -$265,114,040 $0 $0 $0 $0 $0


Total Payments -$1 ,3 01 ,9 28 ,0 40 -$9 41 ,9 95 ,1 38 -$6 09 ,2 58 ,4 39 -$4 88 ,9 30 ,8 78 -$8 57 ,0 22 ,0 11 -$5 67 ,7 00 ,2 65 -$5 67 ,9 39 ,3 88 -$2 35 ,6 32 ,2 00 -$2 35 ,6 32 ,2 00


Net Cash Flow $ 1, 84 0, 52 5, 88 4 $ 1, 83 9, 12 1, 17 0 $ 1, 56 8, 62 2, 63 3 $ 1, 21 6, 55 9, 08 9 $ 47 8, 54 0, 37 1 $ 47 8, 17 3, 30 1 $ 24 7, 00 5, 30 1 -$2 35 ,6 32 ,2 00 -$2 35 ,6 32 ,2 00


Decommision

Scenario 3 -1 : Oil Prices drop


Discount Factor & NPVDiscount Factor & NPV Discount Factor & NPVYear NCF

Scenario 3 1 : Oil




- 2011 $5,865,123,350 $5,865,123,350 - - - - - - - - -

0 2012 $0 $5,865,123,350 1.000 $0 $0 1.000 $0 $0 1.000 $0 $0

1 2013 $2,715,824,020 $ 8, 58 0, 94 7, 37 0 0 .9 52 $ 2, 58 6, 49 9, 06 6 $ 2, 58 6, 49 9, 06 6 0 .9 09 $ 2, 46 8, 93 0, 92 7 $ 2, 46 8, 93 0, 92 7 0 .8 70 $ 2, 36 1, 58 6, 10 4 $ 2, 36 1, 58 6, 10 4

2 2014 $4,345,318,431 $ 12 ,9 26 ,2 65 ,8 01 0 .9 07 $ 3, 94 1, 33 1, 91 0 $ 6, 52 7, 83 0, 97 7 0 .8 26 $ 3, 59 1, 17 2, 25 7 $ 6, 06 0, 10 3, 18 4 0 .7 56 $ 3, 28 5, 68 5, 01 4 $ 5, 64 7, 27 1, 11 8

3 2015 $5,214,382,117 $ 18 ,1 40 ,6 47 ,9 18 0 .8 64 $ 4, 50 4, 37 9, 32 6 $ 11 ,0 32 ,2 10 ,3 03 0 .7 51 $ 3, 91 7, 64 2, 46 2 $ 9, 97 7, 74 5, 64 7 0 .6 58 $ 3, 42 8, 54 0, 88 4 $ 9, 07 5, 81 2, 00 2

4 2016 $4,171,505,694 $ 22 ,3 12 ,1 53 ,6 12 0 .8 23 $ 3, 43 1, 90 8, 05 8 $ 14 ,4 64 ,1 18 ,3 61 0 .6 83 $ 2, 84 9, 19 4, 51 8 $ 12 ,8 26 ,9 40 ,1 65 0 .5 72 $ 2, 38 5, 07 1, 92 0 $ 11 ,4 60 ,8 83 ,9 22

5 2017 $3,337,204,555 $ 25 ,6 49 ,3 58 ,1 67 0 .7 84 $ 2, 61 4, 78 7, 09 2 $ 17 ,0 78 ,9 05 ,4 53 0 .6 21 $ 2, 07 2, 14 1, 46 8 $ 14 ,8 99 ,0 81 ,6 32 0 .4 97 $ 1, 65 9, 18 0, 46 6 $ 13 ,1 20 ,0 64 ,3 88

6 2018 $3,170,344,327 $ 28 ,8 19 ,7 02 ,4 95 0 .7 46 $ 2, 36 5, 75 9, 75 0 $ 19 ,4 44 ,6 65 ,2 03 0 .5 64 $ 1, 78 9, 57 6, 72 2 $ 16 ,6 88 ,6 58 ,3 55 0 .4 32 $ 1, 37 0, 62 7, 34 1 $ 14 ,4 90 ,6 91 ,7 29

7 2019 $3,170,344,327 $ 31 ,9 90 ,0 46 ,8 22 0 .7 11 $ 2, 25 3, 10 4, 52 4 $ 21 ,6 97 ,7 69 ,7 26 0 .5 13 $ 1, 62 6, 88 7, 92 9 $ 18 ,3 15 ,5 46 ,2 84 0 .3 76 $ 1, 19 1, 84 9, 86 2 $ 15 ,6 82 ,5 41 ,5 91

8 2020 $3,170,344,327 $ 35 ,1 60 ,3 91 ,1 50 0 .6 77 $ 2, 14 5, 81 3, 83 2 $ 23 ,8 43 ,5 83 ,5 58 0 .4 67 $ 1, 47 8, 98 9, 02 7 $ 19 ,7 94 ,5 35 ,3 10 0 .3 27 $ 1, 03 6, 39 1, 18 4 $ 16 ,7 18 ,9 32 ,7 75

9 2021 $3,142,453,925 $ 38 ,3 02 ,8 45 ,0 74 0 .6 45 $ 2, 02 5, 65 3, 81 9 $ 25 ,8 69 ,2 37 ,3 77 0 .4 24 $ 1, 33 2, 70 7, 22 5 $ 21 ,1 27 ,2 42 ,5 36 0 .2 84 $ 89 3, 28 1, 53 2 $ 17 ,6 12 ,2 14 ,3 08

10 2022 $2,781,116,308 $ 41 ,0 83 ,9 61 ,3 82 0 .6 14 $ 1, 70 7, 36 4, 16 1 $ 27 ,5 76 ,6 01 ,5 38 0 .3 86 $ 1, 07 2, 24 0, 73 0 $ 22 ,1 99 ,4 83 ,2 65 0 .2 47 $ 68 7, 44 9, 41 7 $ 18 ,2 99 ,6 63 ,7 25

11 2023 $2,177,881,072 $ 43 ,2 61 ,8 42 ,4 54 0 .5 85 $ 1, 27 3, 36 1, 95 7 $ 28 ,8 49 ,9 63 ,4 94 0 .3 50 $ 76 3, 33 4, 02 9 $ 22 ,9 62 ,8 17 ,2 94 0 .2 15 $ 46 8, 12 0, 77 6 $ 18 ,7 67 ,7 84 ,5 01

12 2024 $1,705,489,968 $ 44 ,9 67 ,3 32 ,4 21 0 .5 57 $ 94 9, 68 0, 63 0 $ 29 ,7 99 ,6 44 ,1 25 0 .3 19 $ 54 3, 42 1, 66 3 $ 23 ,5 06 ,2 38 ,9 57 0 .1 87 $ 31 8, 76 8, 27 0 $ 19 ,0 86 ,5 52 ,7 71

13 2025 $1,335,562,381 $ 46 ,3 02 ,8 94 ,8 02 0 .5 30 $ 70 8, 27 7, 24 6 $ 30 ,5 07 ,9 21 ,3 70 0 .2 90 $ 38 6, 86 4, 84 9 $ 23 ,8 93 ,1 03 ,8 06 0 .1 63 $ 21 7, 06 6, 22 5 $ 19 ,3 03 ,6 18 ,9 96

14 2026 $1,045,873,566 $ 47 ,3 48 ,7 68 ,3 68 0 .5 05 $ 52 8, 23 7, 22 1 $ 31 ,0 36 ,1 58 ,5 92 0 .2 63 $ 27 5, 41 1, 19 8 $ 24 ,1 68 ,5 15 ,0 04 0 .1 41 $ 14 7, 81 1, 90 7 $ 19 ,4 51 ,4 30 ,9 03

15 2027 $814,944,688 $ 48 ,1 63 ,7 13 ,0 57 0 .4 81 $ 39 2, 00 2, 32 9 $ 31 ,4 28 ,1 60 ,9 21 0 .2 39 $ 19 5, 09 1, 27 9 $ 24 ,3 63 ,6 06 ,2 83 0 .1 23 $ 10 0, 15 2, 20 8 $ 19 ,5 51 ,5 83 ,1 11

16 2028 $0 $48,163,713,057 0.458 $0 $31,428,160,921 0.218 $0 $24,363,606,283 0.107 $0 $19,551,583,111

17 2029 $0 $48,163,713,057 0.436 $0 $31,428,160,921 0.198 $0 $24,363,606,283 0.093 $0 $19,551,583,111

- 2011 $5,865,123,350 $5,865,123,350 $500,000,000 $500,000,000 $5,365,123,350

0 2012 $0 $5,865,123,350 $5,365,123,350 $5,865,123,350 $0

1 2013 $2,715,824,020 $8,580,947,370 $5,088,683,381 $10,953,806,731 -$2,372,859,362

2 2014 $4,345,318,431 $12,926,265,801 $1,800,889,542 $12,754,696,274 $171,569,527

3 2015 $5,214,382,117 $18,140,647,918 $2,175,673,683 $14,930,369,956 $3,210,277,962

4 2016 $4,171,505,694 $22,312,153,612 $2,295,613,960 $17,225,983,916 $5,086,169,696

5 2017 $3,337,204,555 $25,649,358,167 $2,681,289,230 $19,907,273,146 $5,742,085,021

6 2018 $3,170,344,327 $28,819,702,495 $2,624,535,933 $22,531,809,079 $6,287,893,416

7 2019 $3,170,344,327 $31,990,046,822 $2,887,486,720 $25,419,295,799 $6,570,751,023

8 2020 $3,170,344,327 $35,160,391,150 $3,036,626,162 $28,455,921,961 $6,704,469,189

9 2021 $3,142,453,925 $38,302,845,074 $1,301,928,040 $29,757,850,001 $8,544,995,074

10 2022 $2,781,116,308 $41,083,961,382 $941,995,138 $30,699,845,139 $10,384,116,243

11 2023 $2,177,881,072 $43,261,842,454 $609,258,439 $31,309,103,577 $11,952,738,876

12 2024 $1,705,489,968 $44,967,332,421 $488,930,878 $31,798,034,455 $13,169,297,966

13 2025 $1,335,562,381 $46,302,894,802 $857,022,011 $32,655,056,466 $13,647,838,33614 2026 $1,045,873,566 $47,348,768,368 $567,700,265 $33,222,756,731 $14,126,011,637

15 2027 $814,944,688 $48,163,713,057 $567,939,388 $33,790,696,119 $14,373,016,938

16 2028 $0 $48,163,713,057 $235,632,200 $34,026,328,319 $14,137,384,738

17 2029 $0 $48,163,713,057 $235,632,200 $34,261,960,519 $13,901,752,538


RevenueExpenses

Cumulative

ExpensesNet Profit

-$10,000,000,000

$0

$10,000,000,000

$20,000,000,000

$30,000,000,000

$40,000,000,000

$50,000,000,000

$60,000,000,000

Cumulative

Revenue

Cumulative

Expenses

Net Profit

Total

expenses VS

Revenue

$0

$1,000,000,000

$2,000,000,000

$3,000,000,000

$4,000,000,000

$5,000,000,000

$6,000,000,000

$7,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

NCF

NPV 5%

NPV10%

NPV15%

NCF VS NPV

$0

$1,000,000,000

$2,000,000,000

$3,000,000,000

$4,000,000,000

$5,000,000,000

$6,000,000,000

$7,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

Revenue

Expenses

Revenue & Expenses

$0

$10,000,000,000

$20,000,000,000

$30,000,000,000

$40,000,000,000

$50,000,000,000

$60,000,000,000

2 0 1 1

2 0 1 3

2 0 1 5

2 0 1 7

2 0 1 9

2 0 2 1

2 0 2 3

2 0 2 5

2 0 2 7

2 0 2 9

Cumulative NCF

Cumulative NPV 5%

Cumulative NPV

10%

Cumulative NPV

15%


Scenario 3 -1 : Oil

Prices drop

Taxation


Daily production of NG

mmBUT




2011 $0 $0 2011 0

2012 $0 $0 2012 0

2013 ######## $178,500,000 2013 403

2014 ######## $357,000,000 2014 807

2015 ######## $535,500,000 2015 1,210

2016 ######## $535,500,000 2016 1,210

2017 ######## $535,500,000 2017 1,210

2018 ######## $535,500,000 2018 1,210

2019 ######## $535,500,000 2019 1,210

2020 ######## $535,500,000 2020 1,210

2021 ######## $535,500,000 2021 1,210

2022 ######## $473,925,098 2022 1,071

2023 ######## $369,282,439 2023 834

2024 ######## $287,744,878 2024 650

2025 ######## $224,210,811 2025 507

2026 ######## $174,705,065 2026 395

2027 ######## $136,130,188 2027 308

tal Taxes paid $5,949,998,478

ily Production


2011 0 0 0 0

2012 0 0 0 0

2013 60,000 7,154 21,000,000 3,338,733

2014 120,000 14,309 42,000,000 6,677,466

2015 180,000 21,463 63,000,000 10,016,200

2016 180,000 28,618 63,000,000 10,016,200

2017 180,000 28,618 63,000,000 10,016,200

2018 180,000 28,618 63,000,000 10,016,200

2019 180,000 28,618 63,000,000 10,016,200

2020 180,000 28,618 63,000,000 10,016,2002021 180,000 28,618 27,423,466 4,359,983

2022 159,303 28,618 27,423,466 4,359,983

2023 124,129 23,565 22,456,693 3,570,329

2024 96,721 15,766 14,845,755 2,360,286

2025 75,365 10,548 9,814,287 1,560,347

2026 58,724 7,057 6,488,066 1,031,520

2027 45,758 4,721 4,289,155 681,921

$0

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

Taxation

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

bbl/day

bbl/day

0

200

400

600

800

1,000

1,200

1,400

201120132015201720192021202320252027

mmBUT

mmBUT

Scenario 3 -1 : OilPrices drop





1.00 1.05 1.00 26.80 1.00 28.26 NG 4.03 $/mmBTU NG 142.59 $/1000m³


1.00 158.99 1.00 1,000.00 1.00 6.29


NG 7.00 $/mmBTU NG 247.67 $/1000m³

Oil 85.00 $/bbl Oil 534.63 $/m³


From yr 1 - 5 3.00% From yr 6 - 10 1.00% From yr 14 - 16 0.00% From yr 20 0.00% From yr -2 - 7 5.00% From yr 9 -12 10.00% From yr 14 - 15 -10.00%


119,240 m³ Start Value -$5,768,900,210 US D

End of economic life Valu -$1,857,431,472 USD


Production Year -6 -5 -4 -3 -2 -1 1 2 3 4 5 6 7 8

Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Oil price per bbl $126.87 $133.21 $137.21 $141.33 $145.57 $149.93 $154.43 $157.52 $159.09 $160.69




Gas production mmBTU) 0 0 0 0 0 0 302 605 907 1,210 1,210 1,210 973 619


48

Opening Balance $0 $5,268,900,210 $0 -$1,083,471,119 $2,673,558,614 $9,103,539,580 $18,479,240,285 $27,843,431,348 $37,576,154,407 $44,920,331,548

Loan $5,768,900,210 $0 $0 $0 $0 $0 $0 $0 $0 $0

Cash Revenue $0 $0 $2,631,427,017 $5,439,554,495 $8,433,745,069 $11,623,829,951 $12,016,105,909 $12,325,036,696 $10,091,555,956 $6,407,624,261

TOTAL RECEIPTS $5,768,900,210 $0 $2,631,427,017 $ 5,439,554,495 $8,433,745,069 $11,623,829,951 $12,016,105,909 $12,325,036,696 $10,091,555,956 $6,407,624,261

Cash Payments

CAPEX -$500,000,000 -$5,268,900,210 $0 $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsuma $0 $0 - $164,977,000 -$13,453,000 - $14,852,000 -$16,568,000 -$18,602,000 -$18,602,000 -$18,602,000 -$17,535,000



Insurance $0 $0 - $359,250,000 -$35,925,000 - $35,925,000 -$35,925,000 -$35,925,000 -$35,925,000 -$35,925,000 -$35,925,000

Wells $0 $0 -$533,422,000 $0 -$36,744,000 $0 -$184,504,000 $0 -$36,744,000 $0

Field/projectcosts $0 $0 -$402,778,000 -$25,721,000 -$35,257,000 -$26,500,000 -$73,134,000 -$27,054,000 -$40,748,000 -$26,742,000

Tariffcosts $0 $0 - $460,001,000 -$18,113,000 - $36,225,000 -$54,338,000 -$72,450,000 -$72,450,000 -$72,450,000 -$58,284,000

Loan repayments $0 $0 -$904,563,553 -$1,013,111,179 -$1,134,684,521 -$1,270,846,663 -$1,423,348,263 -$1,594,150,054 -$1,785,448,061 -$1,999,701,828

Tax payments $ 0 $0 - $133, 875, 000 - $26 7,75 0,000 - $401, 625, 000 - $535,5 00,0 00 - $53 5,50 0,000 - $535 ,500, 000 - $430, 794,1 72 - $2 74,09 6,94 9

Depreciation $0 $0 -$260,764,583 -$260,764,583 -$260,764,583 -$260,764,583 -$260,764,583 -$260,764,583 -$260,764,583 -$260,764,583

Total Payments -$500,000,000 -$5,268,900,210 - $3,714,898,135 - $1,682,524,762 -$2,003,764,103 -$2,248,129,246 - $2,651,914,845 -$2,592,313,637 -$2,747,378,815 -$2,720,736,360

Cash Book Balance $ 5,26 8,90 0,21 0 $ 0 -$1 ,0 83 ,4 71 ,1 19 $ 2,67 3,55 8,61 4 $ 9,10 3,53 9,58 0 $ 18 ,4 79 ,2 40 ,2 85 $ 27 ,8 43 ,4 31 ,3 48 $ 37 ,5 76 ,1 54 ,4 07 $ 44 ,9 20 ,3 31 ,5 48 $ 48 ,6 07 ,2 19 ,4 49

Net Cash Flow $5,268,900,210 -$5,268,900,210 -$1,083,471,119 $3,757,029,733 $6,429,980,965 $9,375,700,705 $9,364,191,063 $9,732,723,059 $7,344,177,141 $3,686,887,901

Cumulative Net Cash Flo $5,268,900,210 $0 -$1,083,471,119 $2,673,558,614 $ 9,103,539,580 $18,479,240,285 $27,843,431,348 $37,576,154,407 $44,920,331,548 $48,607,219,449

2014 Price


Depreciation

FPSO Capacity

Exploration Period

Exploration Period

Exploration Period

Scenario 3 -2 : Oil Production drop

Production Year 9 10 11 12 13 14 15 16 17

Year 2021 2022 2023 2024 2025 2026 2027 2028 2029



Oil price per bbl $162.29 $163.92 $164.74 $165.56 $166.39 $167.22 $167.22


Daily liquids productioni 58,621 37,298 0 0 0 0 0

Yearly Production in bbl 20,517,274 13,054,314 0 0 0 0 0

Gas production mmBTU) 394 251 0 0 0 0 0

Yearly Gas Production 137,910,079 87,746,619 0 0 0 0 0

Opening Balance $48,607,219,449 $51,666,398,727 $53,654,218,777 $53,236,530,377 $53,004,624,977 $52,772,719,577 $52,772,719,577

Loan $0 $0 $0 $0 $0 $0 $0

Cash Revenue $4,187,889,089.98 $2,740,367,699.08 $0.00 $0.00 $0.00 $0.00 $0.00

TOTAL RECEIPTS $4,187,889,090 $2,740,367,699 $0 $0 $0 $0 $0

Cash Payments

CAPEX $0 $0 $0 $0 $0 $0 $0

OPEX

Logisticsandconsuma -$16,185,000 -$15,481,000 -$15,097,000 $0 $0 $0 $0

Inspectionandmainte -$38,139,000 -$38,139,000 -$38,139,000 $0 $0 $0 $0

Operatingpersonnel -$9,548,000 -$9,548,000 -$9,548,000 $0 $0 $0 $0

Insurance -$35,925,000 -$35,925,000 -$35,925,000 $0 $0 $0 $0

Wells -$238,686,000 $0 -$36,744,000 $0 $0 $0 $0

Field/projectcosts -$86,076,000 -$26,228,000 -$35,318,000 $0 $0 $0 $0

Tariffcosts -$37,084,000 -$23,595,000 -$15,012,000 $0 $0 $0 $0

Loan repayments $0 $0 $0 $0 $0 $0 $0

Tax payments -174396829.4 -110961665.9 0 0 0 0 0

Depreciation -$260,764,583 -$260,764,583 $0 $0 $0 $0 $0

Decommission costs -$231,905,400 -$231,905,400 -$231,905,400 -$231,905,400 -$231,905,400 $0 $0 $0 $0

Total Payments -$1,128,709,812 -$752,547,648 -$417,688,400 -$231,905,400 -$231,905,400 $0 $0 $0 $0


Net Cash Flow $3,059,179,278 $1,987,820,051 -$417,688,400 -$231,905,400 -$231,905,400 $0 $0 $0 $0


Decommision


Year


Discount Factor & NPVDiscount Factor & NPV Discount Factor & NPVNCF

Scenario 3 -2 : Oil



- 2011 $5,768,900,210 $5,768,900,210 - - - - - - - - -

0 2012 $0 $5,768,900,210 1.000 $0 $0 1.000 $0 $0 1.000 $0 $0

1 2013 $2,631,427,017 $8,400,327,227 0.952 $2,506,120,968 $2,506,120,968 0.909 $2,392,206,379 $2,392,206,379 0.870 $2,288,197,406 $2,288,197,406

2 2014 $5,439,554,495 $13,839,881,722 0.907 $4,933,836,277 $7,439,957,245 0.826 $4,495,499,583 $6,887,705,961 0.756 $4,113,084,684 $6,401,282,090

3 2015 $8,433,745,069 $22,273,626,790 0.864 $7,285,386,087 $14,725,343,332 0.751 $6,336,397,497 $13,224,103,458 0.658 $5,545,324,283 $11,946,606,373

4 2016 $11,623,829,951 $33,897,456,741 0.823 $9,562,953,667 $24,288,296,999 0.683 $7,939,232,259 $21,163,335,718 0.572 $6,645,962,501 $18,592,568,874

5 2017 $12,016,105,909 $45,913,562,650 0.784 $9,414,933,399 $33,703,230,397 0.621 $7,461,056,379 $28,624,392,097 0.497 $5,974,128,307 $24,566,697,180

6 2018 $12,325,036,696 $58,238,599,346 0.746 $9,197,132,146 $42,900,362,544 0.564 $6,957,161,902 $35,581,553,998 0.432 $5,328,453,484 $29,895,150,664

7 2019 $10,091,555,956 $68,330,155,302 0.711 $7,171,880,410 $50,072,242,954 0.513 $5,178,563,864 $40,760,117,863 0.376 $3,793,789,674 $33,688,940,339

8 2020 $6,407,624,261 $74,737,779,563 0.677 $4,336,932,317 $54,409,175,271 0.467 $2,989,204,007 $43,749,321,870 0.327 $2,094,663,737 $35,783,604,076

9 2021 $4,187,889,090 $78,925,668,653 0.645 $2,699,550,648 $57,108,725,918 0.424 $1,776,073,789 $45,525,395,659 0.284 $1,190,459,454 $36,974,063,530

10 2022 $2,740,367,699 $81,666,036,352 0.614 $1,682,348,050 $58,791,073,968 0.386 $1,056,530,377 $46,581,926,036 0.247 $677,376,984 $37,651,440,514

11 2023 $0 $81,666,036,352 0.585 $0 $58,791,073,968 0.350 $0 $46,581,926,036 0.215 $0 $37,651,440,514

12 2024 $0 $81,666,036,352 0.557 $0 $58,791,073,968 0.319 $0 $46,581,926,036 0.187 $0 $37,651,440,514

13 2025 $0 $81,666,036,352 0.530 $0 $58,791,073,968 0.290 $0 $46,581,926,036 0.163 $0 $37,651,440,514

- 2011 $5,768,900,210 $5,768,900,210 $500,000,000 $500,000,000 $5,268,900,210

0 2 012 $ 0 $5 ,76 8, 90 0, 21 0 $ 5, 268, 900, 210 $ 5, 76 8, 900, 210 $0

1 2013 $2,631,427,017 $8,400,327,227 $3,714,898,135 $9,483,798,345 -$1,083,471,119

2 2014 $5,439,554,495 $13,839,881,722 $1,682,524,762 $11,166,323,107 $2,673,558,614

3 2015 $8,433,745,069 $22,273,626,790 $2,003,764,103 $13,170,087,211 $9,103,539,580

4 2016 $11,623,829,951 $33,897,456,741 $2,248,129,246 $15,418,216,456 $18,479,240,285

5 2017 $12,016,105,909 $45,913,562,650 $2,651,914,845 $18,070,131,302 $27,843,431,348

6 2018 $12,325,036,696 $58,238,599,346 $2,592,313,637 $20,662,444,939 $37,576,154,407

7 2019 $10,091,555,956 $68,330,155,302 $2,747,378,815 $23,409,823,754 $44,920,331,548

8 2020 $6,407,624,261 $74,737,779,563 $2,720,736,360 $26,130,560,114 $48,607,219,449

9 2021 $4,187,889,090 $78,925,668,653 $1,128,709,812 $27,259,269,926 $51,666,398,727

10 2022 $2,740,367,699 $81,666,036,352 $752,547,648 $28,011,817,574 $53,654,218,777

1 1 2 02 3 $ 0 $8 1, 66 6, 03 6, 35 2 $ 41 7, 68 8, 40 0 $ 2 8, 42 9, 50 5, 97 4 $53,236,530,377

1 2 2 02 4 $ 0 $8 1, 66 6, 03 6, 35 2 $ 23 1, 90 5, 40 0 $ 2 8, 66 1, 41 1, 37 4 $53,004,624,977

1 3 2 02 5 $ 0 $8 1, 66 6, 03 6, 35 2 $ 23 1, 90 5, 40 0 $ 2 8, 89 3, 31 6, 77 4 $52,772,719,577


RevenueExpenses

Cumulative

ExpensesNet Profit

-$10,000,000,000

$0

$10,000,000,000

$20,000,000,000

$30,000,000,000

$40,000,000,000

$50,000,000,000

$60,000,000,000

$70,000,000,000

$80,000,000,000

$90,000,000,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

Cumulative

Revenue

CumulativeExpenses

Net Profit

Totalexpenses

VS Revenue

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

$14,000,000,000

NCF

NPV 5%

NPV10%

NPV15%

NCF VS NPV

$0

$2,000,000,000

$4,000,000,000

$6,000,000,000

$8,000,000,000

$10,000,000,000

$12,000,000,000

$14,000,000,000

Revenue

Expenses

Revenue & Expenses

$0

$10,000,000,000

$20,000,000,000

$30,000,000,000

$40,000,000,000

$50,000,000,000

$60,000,000,000

$70,000,000,000

$80,000,000,000

$90,000,000,000

Cumulative NCF

Cumulative NPV 5%

Cumulative NPV

10%

Cumulative NPV

15%


Scenario 3 2 : Oil

Production drop

Daily production of NG

Y A ABS A

Taxation

BUT




2011 $0 $0 2011 0

2012 $0 $0 2012 0

2013 -$178,500,000 $178,500,000 2013 403

2014 -$357,000,000 $357,000,000 2014 807

2015 -$535,500,000 $535,500,000 2015 1,210

2016 -$535,500,000 $535,500,000 2016 1,210

2017 -$535,500,000 $535,500,000 2017 1,210

2018 -$535,500,000 $535,500,000 2018 1,2102019 -$535,500,000 $535,500,000 2019 1,210

2020 -$535,500,000 $535,500,000 2020 1,210

2021 -$535,500,000 $535,500,000 2021 1,210

2022 -$473,925,098 $473,925,098 2022 1,071

2023 -$369,282,439 $369,282,439 2023 834

2024 -$287,744,878 $287,744,878 2024 650

2025 -$224,210,811 $224,210,811 2025 507

2026 -$174,705,065 $174,705,065 2026 395

2027 -$136,130,188 $136,130,188 2027 308

Total Taxes paid ##########

Year bb l/day m³/day bbl/year m³/year

2011 0 0 0 0

2012 0 0 0 0

2013 45,000 7,154 21,000,000 3,338,733

2014 90,000 14,309 42,000,000 6,677,466

2015 135,000 21,463 63,000,000 10,016,200

2016 180,000 28,618 63,000,000 10,016,200

2017 180,000 28,618 63,000,000 10,016,200

2018 180,000 28,618 63,000,000 10,016,200

2019 144,805 23,022 63,000,000 10,016,2002020 92,133 14,648 63,000,000 10,016,200

2021 58,621 9 ,320 63,000,000 10,016,200

2022 37,298 5,930 55,755,894 8,864,479

Daily Production

$0

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

2 0 1 1

2 0 1 2

2 0 1 3

2 0 1 4

2 0 1 5

2 0 1 6

2 0 1 7

2 0 1 8

2 0 1 9

2 0 2 0

2 0 2 1

2 0 2 2

2 0 2 3

2 0 2 4

2 0 2 5

2 0 2 6

2 0 2 7

Taxation

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

201120122013201420152016201720182019202020212022

bbl/day

bbl/day

0

200

400

600

800

1,000

1,200

1,400

2011 2013 2015 2017 2019 2021 2023 2025 2027

mmBUT

mmBUT


Documents

Group K Final (1)