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
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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
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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
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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
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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 .
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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
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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
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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.
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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
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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
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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
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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
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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
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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
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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 -
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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
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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
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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.
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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
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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$tor Software to obtain production profiles and then
perform Cash flow analysis to get the NPV.
Safety is one of K RUDE’s concerns. We plan to apply Safety Management Systems (SMS)
on this venture. SMS will support controlling risk to protect company oil loss, ensure
employees and contractor’s personnel safety, controlling the effect of the project on theenvironment putting in our consideration accidents happened in this field. To ensure this, the
safety regulation proposed by the Brazilian Government will be strictly followed.
Half way through the production phase of the project life cycle a study will be carried out to
decide on FPSO and field decommissioning. Feasibility study of available options will be
carried out later.
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7.1 Subsea Layout for Field’s Development
The main characteristics of the proposed field data for development are estimated as follows:
(Pinto C., 2003 and IHS Que$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
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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),
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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)
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7.4 Project Schedule
See Appendix for Full view:
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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
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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
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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
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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
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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).
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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).
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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
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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
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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 $6.74
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10.2 Feasibility Study
K RUDE has to estimate the project profit and expenditures such as operating and capital cost
to decided if the project is economically viable. K RUDE has designed three possible
scenarios of the project to compare amongst each other to determine the economically
feasible option. Additional two scenarios have been considered to determine the economic
viability taking into consideration the uncertainties of crude oil price and estimated oil
reserves.
All Scenarios have the same basic definition as all use FPSO ,20 production wells, 8 water
injection wells, 3 gas injection wells, Subsea cluster layout, and reservoir properties (also see
project proposal) except for the offloading system in their respective cases and were
modelled for optimum production profile, CAPEX and OPEX using IHS Que$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.
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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
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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
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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.
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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
Year RevenueCumulative
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
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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.
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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
Year RevenueCumulative
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
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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
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Figure 10.13 NCF & NPV diagram for Scenario 3
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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
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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.
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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
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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
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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
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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
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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
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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
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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
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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.
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14 References
1. Bruhn C., Gomes J., Lucchese C. ,Johann P.; 2003. Petrobras E&P, Rio de Janeiro, Brazil;
OTC 15220, Campos Basin: Reservoir Characterization and Management – Historical
Overview and Future Challenges.
2. Pinto C., Branco M. , J.S. de Matos, Vieira P.M., S. da Silva Guedes, Pedroso C., Coelho
D., Ceciliano M.M., 2003. Petrobras S. A.:OTC 15283, Offshore Heavy Oil in Campos
Basin: The Petrobras Experience.
3. Da Costa Fraga C.T., Borges F.A, Bellot. C., Beltrão R., M.I. Assayag; 2003; OTC 15219;
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.
6. Henriques C.C.D, Brandao F.N.;2007; OTC 18681; From P-34 to P-50: FPSO Evolution
7. Santos A.B., Henriques C.C.D,Alvares J.M.H.; 2004; OTC 16705; Improvements
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14. F, J. M., 2010; Does Oil Make Leaders Unaccountable? Evidence from brazil's oil shore
oil boom Department of Economics, Pontif cia Universidade Cat olica do Rio de Janeiro
(PUC-Rio). Brazil.
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Change-Oil-Exploration-Policy-38309.html
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push. Retrieved April 06, 2011, from ForexPros: http://www.forexpros.com/news/general-
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26. Staff, R., 2010, June; Analysis: Pre-Salt Could Brighten Offshore Brazil. Retrieved April
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15 Appendix
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Conversion Today's Price
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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
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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
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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
Year RevenueCumulative
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
8/3/2019 Group K Final (1)
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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
$/bbl
General Data
Scenario 1: Offloading to
Existing Network via Pipelines
S 2 Off C S
OFFSHOREPROJECTSUMMARY
8/3/2019 Group K Final (1)
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Currency Rate/$
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
Conversion Today's Price
8/3/2019 Group K Final (1)
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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 -$7,798,115,000 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
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 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
8/3/2019 Group K Final (1)
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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 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
Decommission costs $0 $0 $0 $0 -$368,908,600 -$368,908,600 -$368,908,600 -$368,908,600 -$368,908,600
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
Survey of the field -$500,000,000 No. of years 10 Total loan Payback Remain
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
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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
Year RevenueCumulative
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%
Culmulative NCF VS NPV
Scenario 2 : Offloading to
Shuttle Tankers Using CALM
BUOY
axation Daily production of NG
8/3/2019 Group K Final (1)
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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
$600,000,000
2 0 1 1
2 0 1 2
2 0 1 3
2 0 1 4
2 0 1 5
2 0 1 6
2 0 1 7
2 0 1 8
2 0 1 9
2 0 2 0
2 0 2 1
2 0 2 2
2 0 2 3
2 0 2 4
2 0 2 5
2 0 2 6
2 0 2 7
Taxation
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
bbl/day
bbl/day
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
mmBUT
mmBUT
Scenario 2 : Offloading to
Shuttle Tankers Using CALM
BUOY
Scen 3:Aft offloading reel+gas pipeline
OFFSHOREPROJECTSUMMARY
Project name
8/3/2019 Group K Final (1)
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Currency Rate/$
Offshore Brazil1 $ 1.00
Contingency S.America $ 1.00
Equipment S.America $ 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
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
Mbbl/day Reservoirdepth m
Reservoirpressure bara
Reservoirlength km
Country Brazil
Initialwatercut %
Designgrossliquidsflowrate
Scen.3:Aftoffloadingreel+gaspipeline
CamposBasin
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
Conversion Today's Price
8/3/2019 Group K Final (1)
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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 -2 - 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 S ta rt V al ue - $5,865 ,123 ,350 U SD
End of economic life Va -$1,888,412,748 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
NG price per mmBTU $4.03 $4.23 $4.44 $4.67 $4.90 $5.14 $5.40 $5.67 $5.95 $5.66
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
Yearly Gas Production 0 0 0 0 0 0 141,154,797 282,309,594 423,464,392 423,464,392 423,464,392 423,464,392 423,464,392 423,464,392
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
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 ,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
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 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
8/3/2019 Group K Final (1)
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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 $6.22 $6.84 $7.53 $8.28 $8.32 $7.49 $6.74
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
Decommission costs $0 $0 $0 $0 -$235,632,200 -$235,632,200 -$235,632,200 -$235,632,200 -$235,632,200
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
Cash Book Balance $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
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
Survey of the field -$500,000,000 No. of years 10 Total loan Payback Remain
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 :
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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
$160,000,000,000Cumulative NCF
Cumulative NPV
5%
Cumulative NPV
10%
Cumulative NPV
15%
Culmulative NCF VS NPV
Scenario 3 :Offloading by Aft Reel
System on FPSO To
Shuttle Tanker (Oil) &
Gas via Pipeline to
Network
Project name
OFFSHOREPROJECTSUMMARY
Scen. 3.1:Aft reel + gas pipeline (400MMbbl)
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 73/82
Currency Rate/$
Offshore Brazil1 $ 1.00
Contingency S.America $ 1.00
Equipment S.America $ 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
300.00 400.00
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
Designoilproductionflowrate
Designassociatedgasflowrate
Designwaterinjectionflowrate
Designgasinjectionrate
Gasoilratio
Designfactor
Fluidcharacteristics
Oildensity@STP
CO2content
Production profile characteristics
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
Waterinjectioncapacityfactor
Region LatinAmerica
Country Brazil
Initialwatercut %
Designgrossliquidsflowrate
Reservoirwidth km
Mbbl/day Reservoirdepth m
Reservoirpressure bara
Reservoirlength km
Daily production of NGTaxation
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 74/82
Year Amount ABS Amount Year mmBUT
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
Year bbl/day m³/day bbl/year m³/year
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 m³ mmBTU m³ Item Price Unit Item Price Unit
Conversion Today's Price
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 75/82
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
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 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%
750,000 bbl Tax $8.50 Economic Life 15 years
119,240 m³ Start Value -$5,865,123,350 US D
End of economic life Val -$1,888,412,748 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 $106.57 $85.26 $68.21 $54.56 $43.65 $41.47 $41.47 $41.47
NG price per mmBTU $4.03 $4.23 $3.39 $2.71 $2.17 $1.73 $1.39 $1.32 $1.32 $1.32
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 0 403 807 1,210 1,210 1,210 1,210 1,210 1,210
Yearly Gas Production 0 0 0 0 0 0 141,154,797 282,309,594 423,464,392 423,464,392 423,464,392 423,464,392 423,464,392 423,464,39264
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
Inspectionandmainte $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
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
8/3/2019 Group K Final (1)
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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
NG price per mmBTU $1.25 $1.25 $1.26 $1.26 $1.27 $1.28 $1.28
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
Decommission costs $0 $0 $0 $0 -$235,632,200 -$235,632,200 -$235,632,200 -$235,632,200 -$235,632,200
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
Cash Book Balance $8,544,995,074 $10,384,116,243 $11,952,738,876 $13,169,297,966 $13,647,838,336 $14,126,011,637 $14,373,016,938 $14,137,384,738 $13,901,752,538
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
Cumulative Net Cash Flo $8,544,995,074 $10,384,116,243 $11,952,738,876 $13,169,297,966 $13,647,838,336 $14,126,011,637 $14,373,016,938 $14,137,384,738 $13,901,752,538
Decommision
Scenario 3 -1 : Oil Prices drop
NCF Cumulative NCF 5% NPV 5% Cumulative NPV 5% 10% NPV10% Cumulative NPV 10% 15% NPV15% Cumulative NPV 15%
Discount Factor & NPVDiscount Factor & NPV Discount Factor & NPVYear NCF
Scenario 3 1 : Oil
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 77/82
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 $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
Year RevenueCumulative
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%
Culmulative NCF VS NPV
Scenario 3 -1 : Oil
Prices drop
Taxation
Year Amount ABS Amount Year mmBUT
Daily production of NG
mmBUT
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 78/82
Year Amount ABS Amount Year 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
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 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
mmBTU GJ GJ m³ mmBTU m³ Item Price Unit Item Price Unit
Conversion Today's Price
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 79/82
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 -2 - 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 -$5,768,900,210 US D
End of economic life Valu -$1,857,431,472 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
NG price per mmBTU $4.03 $4.23 $4.44 $4.67 $4.90 $5.14 $5.40 $5.67 $5.95 $5.66
Daily liquids productioni 0 0 0 0 0 0 45,000 90,000 135,000 180,000 180,000 180,000 144,805 92,133
Yearly Production in bbl 0 0 0 0 0 0 15,750,000 31,500,000 47,250,000 63,000,000 63,000,000 63,000,000 50,681,667 32,246,700
Gas production mmBTU) 0 0 0 0 0 0 302 605 907 1,210 1,210 1,210 973 619
Yearly Gas Production 0 0 0 0 0 0 105,866,098 211,732,196 317,598,294 423,464,392 423,464,392 423,464,392 340,664,784 216,751,257
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
Inspectionandmainte $0 $0 -$399,787,000 - $3 8, 13 9, 00 0 - $3 8, 13 9, 00 0 - $3 8, 13 9, 00 0 - $3 8, 13 9, 00 0 - $3 8, 32 0, 00 0 - $5 6, 35 5, 00 0 - $3 8, 13 9, 00 0
Operatingpersonnel $0 $0 -$95,480,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000 -$9,548,000
Insurance $0 $0 - $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
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 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
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 80/82
Oil price per bbl $162.29 $163.92 $164.74 $165.56 $166.39 $167.22 $167.22
NG price per mmBTU $6.22 $6.84 $7.53 $8.28 $8.32 $7.49 $6.74
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
Cash Book Balance $51,666,398,727 $53,654,218,777 $53,236,530,377 $53,004,624,977 $52,772,719,577 $52,772,719,577 $52,772,719,577 $52,772,719,577 $52,772,719,577
Net Cash Flow $3,059,179,278 $1,987,820,051 -$417,688,400 -$231,905,400 -$231,905,400 $0 $0 $0 $0
Cumulative Net Cash Flo $51,666,398,727 $53,654,218,777 $53,236,530,377 $53,004,624,977 $52,772,719,577 $52,772,719,577 $52,772,719,577 $52,772,719,577 $52,772,719,577
Decommision
Scenario 3 -2 : Oil Production drop
Year
NCF Cumulative NCF 5% NPV 5% Cumulative NPV 5% 10% NPV10% Cumulative NPV 10% 15% NPV15% Cumulative NPV 15%
Discount Factor & NPVDiscount Factor & NPV Discount Factor & NPVNCF
Scenario 3 -2 : Oil
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 81/82
- 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
Year RevenueCumulative
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%
Culmulative NCF VS NPV
Scenario 3 2 : Oil
Production drop
Daily production of NG
Y A ABS A
Taxation
BUT
8/3/2019 Group K Final (1)
http://slidepdf.com/reader/full/group-k-final-1 82/82
Year Amount ABS Amount Year mmBUT
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
Scenario 3 -2 : Oil Production drop
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