Eksplorasi Hidrokarbon

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Natural Gas Hydrate

Economics

Widodo W. Purwanto

Departemen Teknik KimiaUniversitas Indonesia

Natural Gas Economics 2012


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Content

Gas hydrate reserves

Gas hydrate production technology

Ocean gas transportation (GTS)

Economic aspects


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What is Natural Gas Hydrates?

Gas hydrates are crystallinesubstances composed of water and gasin which a solid water-latticeaccommodates gas molecules in a

cagelike structure (clathrate)

Type of gas hydrates

1. Unconventional gas reserves

2. Synthetic gas hydrate
http://www.google.co.id/imgres?imgurl=http://www.neptune.washington.edu/documents/GASHDR/hydrate_geomar_med.jpg&imgrefurl=http://www.neptune.washington.edu/research/index.jsp%3Fkeywords%3DGASHDR%26title%3DGas%2520Hydrates&usg=__8vgs1xcHUSbfi2KBtIhpwW3snn4=&h=423&w=360&sz=56&hl=id&start=1&um=1&itbs=1&tbnid=70iQf4LQ-GMEhM:&tbnh=126&tbnw=107&prev=/images%3Fq%3Dnatural%2Bgas%2Bhydrate%26um%3D1%26hl%3Did%26sa%3DX%26tbs%3Disch:1http://www.google.co.id/imgres?imgurl=http://www.neptune.washington.edu/documents/GASHDR/hydrate_geomar_med.jpg&imgrefurl=http://www.neptune.washington.edu/research/index.jsp%3Fkeywords%3DGASHDR%26title%3DGas%2520Hydrates&usg=__8vgs1xcHUSbfi2KBtIhpwW3snn4=&h=423&w=360&sz=56&hl=id&start=1&um=1&itbs=1&tbnid=70iQf4LQ-GMEhM:&tbnh=126&tbnw=107&prev=/images%3Fq%3Dnatural%2Bgas%2Bhydrate%26um%3D1%26hl%3Did%26sa%3DX%26tbs%3Disch:1


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Hydrate Structures

Sources: U.S. Geological Survey and Texas A&M University

Concentrates gas with a ratio of ~ 1:160

One cubic foot of gas hydratecontains

160 cubic feet of gas at standard

temperature and pressure

Type I Type II Type H

Source: U.S. Geological Survey


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Gas Hydrates Potential

where?

860 tcf?


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The gas hydrate resouce

pyramid


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Global estimates place the gas volume(primarily methane) resident in oceanic naturalgas hydrate deposits in the range of 30,000 to49,100,000 trillion cubic feet (Tcf), and incontinental natural gas hydrate deposits in therange of 5,000 to 12,000,000 Tcf.

Comparatively, current worldwide natural gasresources are about 13,000 Tcf and natural

gas reserves are about 5,000 Tcf.


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Gas hydrate stability


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Migration of gas along faults and

hydrate formation


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Technology of NGH Recovery from

Seafloor Reserves

(a) presence of gases (e.g.,

methane, ethane,

propane) shifts the

boundary curve to the

right

(b) presence of chemical

inhibitors (e.g., methanol)

shifts the boundary curve

to the left.


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Ruppel, 2011


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P-T equilibrium curve for water-

methane system

Makogon, 2010


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Gas Hydrates Production Technology

(a) thermal injection

(b) depressurization

(c) inhibitor injection.


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Ruppel, 2011


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Seafloor Reserves

(a) Thermal injection:

The use of a heat source of energy toraise the reservoir T, thus breaking thehydrogen bonds in the hydrate to releasethe gas

Hot water, steam and brine are commonly

used


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Seafloor Reserves

(b) Depressurization:

When the reservoirs P is reduced,

hydrate dissociates by absorbing energy

from the surrounding reservoirs Tdecreases.

Hydrate will continue to dissociate until

sufficient gas evolves to achieve the

equilibrium P. at the lower T.


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Seafloor Reserves

(c) Inhibitor injection

By injecting chemicals to the sub-sea

hydrates, dissociation will occur.

The chemicals decrease the stability of thehydrate by changing the equilibrium T or P.

Alcohols (methanol) and glycols are

commonly used.


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Seafloor Reserves

Disadvantages

Thermal stimulation

requires much materials

poses environmental effects

Depressurisation

forms ice and/or reforms gas hydrate due to the

endothermic gas hydrate dissociation

Inhibitor injection

poses environmental effects.

causes corrosion on pipelines if air dissolves in theinhibitor


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Effect of depressurization, temperature

stimulation and inhibitors on the hydrate

stability curve


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CO2 injection

The figure illustrates themolecular mining method bymeans of CO2 injection in orderto extract CH4 from gas hydratereservoirs. The concept iscomposed of three steps as

follows; 1) injection of hot seawater into the hydrate layer todissociate the hydrates, 2)produce gas from the hydrate, 3)inject CO2 to form carbon dioxidehydrate with residual water tohold the sea bed stable


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Why the interest in Gas Hydrates?

Safety:Hydrates plug flowlines

Hydrates can be geohazards

Resource:Methane Hydrates are a source of natural gas

Environmental:

Sensitive Communities use hydrates as food

Methane Hydrates can contribute to global warming


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Heat From BuriedPipelines CauseHydrate Dissociation

Hydrates DissociationAffects Foundation of

Surface Facilities?

Heat From ProductionWells Causes HydrateDissociation

Hydrates Form On

Exterior of SubseaEquipment

Potential Impact of Natural Gas Hydrates

in the Seafloor Sediments On Deepwater

Production Facilities

99-00075


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Ocean NGH transportation concept


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Physical PropertyData for NGH and LNG

Natural Gas

Hydrate (NGH)

Liquefied Natural Gas

(LNG)

Modes of

Transport and

Storage

Solid Liquid

Temperature to be

maintained

-200C -1620C

Gravity 0.85 - 0.95 0.42 - 0.47

Contents in 1 m3

Natural Gas:

170Nm3

Water: 0.8 m3Natural Gas: 600 Nm

3

NGH and LNG Comparison


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Properties of Gas Storage Media

much gas can be stored at milder conditions


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Dissociation of the hydrates

Hydrate dissociates quickly under standard temperature andpressure. The dissociation of the hydrates containing methanemolecules occurs satisfying the following reaction equation(Sloan et al, 2003):

CH4.6H2O (solid) CH4 (gas) + 6 H2O (liquid)

The value of H dissociation is 10 20 kcal/mol of gasdissociated. Thus, the dissociation requires an external energysource to propagate along the right hand side. It is necessarytherefore to cool down its temperature to -80oC to stop itsdissociation completely.

It is confirmed, however, that under a certain condition thehydrate does but very slowly dissociate even if it is kept underthe a standard condition (non-equilibrium area) which would,otherwise, bring about a complete dissociation. Thisphenomenon is called "self-preservation effect" -20oC


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Methane hydrate pellets under

condition of self-preservation


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NGH pellet production


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NGH carriers


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Flow sheet NGH production

Javanmardi et al, 2005


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Javanmardi et al, 2005


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Cost Estimation


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Capex Distance


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CNG Marine Economics


Widodo W. Purwanto



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Outline

Overview of CNG MarineTechnology

Simple Economic Analysis ofCNG Marine


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CNG ships add value for producers


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Overview of CNG Marine


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CNG Process


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CNG marine transport chain


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CNG Specification

Component Limit

Methane min. 88%

Ethane max. 6%

C3+ max. 3%

Oxygen max. 1%

CO2+N2 range 1.5-4.5% (CO2 maks 3%)

Sulphur max. 16 ppm (H2S mak 4 ppm)

Water max. 65-112 mg/m3 (4-7 lb/MMscf)

Wobbe Index 46-52 MJ/m


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Gas Capacity


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CNG Logistic parameters


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Logistic Equations

unloadingtravelloadingroundtrip tttht *2)()/(

)(tan)(

hkmTugspeed

kmceDishttravel

hxMMscfdgasRate

MMscfVht

l

eb

loading 24)(_

)()(

arg )()( htht unloadingloading

)(

)(arg_

ht

hteBNumber

loading

roundtrip

eBNumberht

htTugNumber

roundtrip

travel arg_)(

)(*2_

-Tug speed : 12 knot- GTM Volume : 134 MMscf- Load Factor : 100 %


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Hub-and-Spoke & Milk-Run


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CNG M i T h l


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CNG Marine TechnologyProvider

COSELLE (USA)

TransCANADA (Canada )VOTRANS (USA)

TransOCEAN (Canada)

KNUTSEN (Norwegia)
http://www.transcanada.com/index.htmlhttp://www.transcanada.com/index.htmlhttp://www.knutsenoas.com/http://www.knutsenoas.com/


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Coselle (USA)


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Coselle (USA)

C ll St k d i


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Coselle Stack designstacking & support


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Cosselle arrangement in barge


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Cosselle arrangement in barge

C ll CNG T & B


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Coselle CNG Tug & Bargesystem


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Votrans-Enersea (USA)

Votrans pressure vessel


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specification


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P i d t b fi ti


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Pressurized tube configurationsin Votrans CNG ship

Press ri ed t be config rations


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Pressurized tube configurationsin Votrans CNG ship


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TransCanada

Specification

Storage Capacity Barge mounted 25+ mmscf ship up to 1 bcf

Storage System

Pressure vessel consists of a high strength steelinner liner and heads and wrapped with

external glass fiber.

Weight is 60% of equivalent steel vessel

Storage vessel size 42 to 60 inch diameter, 20, 40, 80 ft long

Gas Pressure Up to 3600 psi (1500 psi mid-scalemum)

Gas Temperature Ambient

Vessel Size Typical size 3200 dwt
http://www.transcanada.com/index.htmlhttp://www.transcanada.com/index.html


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Gas Transport Module (GTM)


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Demonstration GTM

CNG Ship & Barge mounted


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CNG Ship & Barge mountedmodule

Large Articulated Tug Barge


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Large Articulated Tug Barge

(AT/B)


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TransOcean (Canada)

Specification

Storage Capacity 150 mmcf to 1.2 bcf

Storage System

Pressure vessel consists of a high density polyethylene liner withstainless steel end bosses and wrapped with external glass

and/or carbon fiber. Weight is one third of equivalent steel

vessel

Storage vessel size

42 to 60 inch diameter, 40 to 120 ft longGas Pressure 3600 psi

Gas Temperature 5 oC

Vessel Size Panamax for 500 mmscf


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TransOcean Module
http://www.knutsenoas.com/http://www.knutsenoas.com/


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Knutsen (Norway)
http://www.knutsenoas.com/http://www.knutsenoas.com/


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Knutsen Large Size

Knutsen Transportation


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Knutsen Transportationspecification

Specification Standard Size Small SizeLarge Size

No. of gas Cylinders 2672 870 3900

Volume of Gas Carried 20 MSm3 3.4 MSm3 30 MSm3

Length, o.a 276 m 182 m 325 m

Length, b.p 260 m 171.5 m 311 m

Beam (Bm) 54 m 9 m 59 m

Dm 29 m 16 m 29 m

Tdesign 13.5 m 8.5 m 15 m

Tballast abt. 11 m 7.3 m 11.6 m

DWT up to 20000 tons 3500 tons 30000 tons

Service Speed 15.5 knots 18 knots 18 knots

Pipe Data 42 in Dia.

19-38 m legth

Steel High Strength (X80)

CNG Licensors Comparison


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CNG Licensors Comparison

Parameter

Licensors

Cossele Vortrans TransOcean TransCanada Knutsen

Ratio Capacity (cf/ft3) 263 389 111 248 267

MaterialCarbon

SteelCarbon Steel

Fiber

Reinforced

Plastic

Composite

Pressure

Vessel

Carbon Steel

MaturityPrototype

Testing

Prototype

Testing

Prototype

Testing

Prototype

Testing

Prototype

Testing

Operability

a. Loading/Unloading STL STL FPSO FPSO STL

b. Temperature (

o

C) 10 -20 5 Ambient Ambientc. Pressure (psi) 3600 1885 3600 3600 3640

Safety good good fair fair fair

CertificationABS,

DNVABS, DNV ABS ABS DNV


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Simple Economic Analysisof CNG

Assumptions for Economic


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Assumptions for Economic

Analysis

Capacities: 1, 0.6, and 0.4 MTPA

Rule of Thumb

Distance 2100 km ~ Donggi-West Java

Cost of capital 12%

Life service 20 years

Product cost CNG = Wellhead + (Capex + OM)Full chain

Capex O&M cost of CNG


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Capex O&M cost of CNG(high case)

ComponentCapex

(US$)Share(%)

O&M

(US$/year)

Share (%)

Tug 50,960,000 10.7% 12,700,000 58.9%

Barge 77,400,000 16.3% 2,000,000 9.3%

GTM 277,200,000 58.3% 1,300,000 6.0%

Transporter 405,560,000 85.3% 16,000,000 74.1%

Gas Treating 30,388,205 6.4% 3,765,654 17.4%

Loading 23,011,896 4.8% 702,285 3.3%

Unloading 16,325,829 3.4% 1,112,299 5.2%

Total 475,285,930 100.0% 21,580,239 100.0%

Source:TransCanada for 0.5 mtpa, 2130 km

US$ 950/tpa, and O&M cost 43 US$/ton (US$ 0.83/mmbtu).


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CapEx Marine

8 5 .3 %

6 .4 %

4 .8 %

3 .4 %

Transporter Gas Treating Loading Unloading

Capital Cost Breakdown


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Capital Cost Breakdown

Economides, SPE 2008

C & O&M (l )


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Capex & O&M (low case)

Source: Hanranhan, 2006

250 mmscfd (1.92 mtpa)and distance 750 nautical miles (~1400 km)

US$ 511-766/tpa, and O&M cost is 13 US$/ton (US$ 0.25/mmbtu).


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C ( )


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Capex (high case)

Capital Cost (full chain of CNG) = $ 475,360,000.00

Size = 0.5 mtpa

Duration = 20 years

Cost of Capital (i) = 12 %

Cost Recovery Factor (CRF) = 0.1339

CNG (1) CNG (2) CNG (3)

Size of CNG (mtpa) 1 0.6 0.4

Capex $ 772,224,598.26 $ 540,069,319.88 $ 406,617,087.56

Capex /mtpa $ 772,224,598.26 $ 900,115,533.14 $ 1,016,542,718.90

Capex/tpa $ 772.22 $ 900.12 $ 1,016.54

Annual Capex $ 103,400,873.71 $ 72,315,281.93 $ 54,446,028.02

Capex/mmbtu $ 2.21 $ 2.58 $ 2.91

C (l )


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Capex (low case)

Capital Cost (full chain of CNG) = $ 1,115,000.00

Size of 1 train = 1.93 mtpa

Duration = 20 years

Cost of Capital (i) = 12 %

Cost Recovery Factor (CRF) = 0.1339

CNG (1) CNG (2) CNG (3)

Size of CNG (mtpa) 1 0.6 0.4

Capex $ 703,695,463.18 $ 492,142,222.68 $ 370,532,874.00

Capex /mtpa $ 703,695,463.18 $ 820,237,037.81 $ 926,332,185.00

Capex/tpa $ 703.70 $ 820.24 $ 926.33

Annual Capex $ 94,224,822.52 $ 65,897,843.62 $ 49,614,351.83

Capital Cost/mmbtu $ 1.81 $ 2.11 $ 2.39


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Product cost of CNG (high case)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

1 mtpa 0.6 mtpa 0.4 mtpa

CNG Plant Capacity

Cost(US$/mmBtu) O&M cost

Capex

Wellhead

P d f CNG (l )


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0.00

1.00

2.00

3.00

4.00

5.00

1 mtpa 0.6 mtpa 0.4 mtpaCNG Plant Capacity

Cost(US$/m

mBtu) O&M cost

Capex

Wellhead

Product cost of CNG (low case)

CNG P d t l ti


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Product Cost per mmbtu

Natural Gas (wellhead)

CapexO&M

Cost of Product

$ 1.5 2.0

$ 1.81

2.21$ 0.25 0.83

$ 3.56 5.04

$ 1.5 2.0

$ 2.11

2.58$ 0.25 0.83$ 3.86 5.41

$ 1.5 2.0

$ 2.39

2.91$ 0.25 0.83

$ 4.14 5.74

CNG1 mtpa

CNG0.6 mtpa

CNG0.4 mtpa

CNG Product valuation

Technical Aspect comparison


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Technical Aspect comparison

E i l A t


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Economical Aspect

CNG : simple and inexpensive onshore

facilities

80-90% of the investment is in shipsand pressure containers

Business opportunities


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Wellhead gas2 US$/mmbtu

Potential Gas Price5 US$/mmbtu(1/2 diesel price

~ 9 US$/mmbtu)


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Xiuli Wang, 2008


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Xiuli Wang, 2008


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Widodo W. Purwanto, *Hanan NugrohoDepartemen Teknik Kimia

Universitas Indonesia

*Bappenas

Natural Gas Contracts(supply, transport and sales)

Lecture-3

Natural Gas Economic 2012

O tli


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Outline

Types and key elements of

natural gas contract

LNG contracts


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Types and key elements

of gas contract

Natural gas value chain and


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gas contract agreement

GSA Between ?


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GS et ee

Produ

cers

Consumer

Trader


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Natural gas EP Contract


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Natural gas EP Contract

Conssesion contractProduction Sharing Contract

Conssesion contract


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Conssesion contracts: Tax/royalty conssesioncontract, conventional type North america,

Argentina, Australia, part Middle east

PSC


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PSC

Production sharing contract (PSC), morecomplexAsia, Africa, part of South america

and Middle East

Gas sales agreements


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Gas sales agreementsThe gas sales agreement (GSA) is also known as a gas purchase

agreement (GPA) or a gas sales and purchase agreement (GSPA). Theseagreements between a producing company or sales agent (seller) and a

consuming company (buyer)

Term. The term of a GSA can be as short as one day or as long as the

economic life of the field from which the gas is produced, the terms could

reach 20 or 30 years.

Quantity. Broadly speaking, there are two distinct types of volume

commitments contracts:

Depletion contracts and the more common supply contracts. Under depletion

contracts, also called output contracts, the producing company dedicates theentire production from a particular field or reserve to a buyer.

In contrast, supply contracts commit the seller to supply a fixed volume of gas to

the buyer for fixed term, typically 20 to 25 years. The seller is responsible for

sourcing the gas, either from its own reserves or from third parties.

Two major types ofvolume gas contracts


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volume gas contractsDepletion contract

Allocation of all the reserves economically recoverablefrom a field or accumulation to the buyer

This type of contract is generally preferred by the

producer

Part of the risk is transferred to the buyer

The price will tend to be lower

The producer agree to supply an annual volume of gas

for a number of defined yearsGas supplies originates from several sources

This does not necessitate to show reserves to the buyer

This type of contract is generally preferred by the buyer

Supply contract

Gas sales aggrement (cont)


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Gas sales aggrement (cont )

Price terms. Gas must be priced at a level competitive with alternate fuels in themarketplace and provide an adequate return for all parties in the chain. Pricing may be

fixed, fixed with escalators, or floating.

Delivery obligation. The terms of delivery may be firm or flexible. Firm delivery

implies an obligation by the producing company or seller to deliver the specified

quantities over the term of the contract. If the delivery obligation is not fulfilled, the

seller may be obliged to pay damages or cover the costs of alternate fuels used by the

buyer. Flexible delivery obligates the producing company to make attempts to fulfill the

delivery obligation but does not require fulfillment of all the delivery obligations.

Take-or-pay (TOP) obligations. The basic premise of take-or-pay (TOP) is that the

buyer is obliged to pay for a percentage of the contracted quantity.

Delivery point. This is the physical location where gas is delivered to the buyer. It

could be at the gate of the power plant, the hub for a city grid, an interconnection of

two pipeline systems, the site of a compressor, international border, or the fence of anLNG plant.

Gas quality. The GSA clearly states the quality of gas, including its maximum and

minimum heating values (in Btu/MMcf units); maximum level of impurities like oxygen,

CO2, SOx, and NOx; the delivery pressure; and water vapor content..

Key provisions of contracts


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Key provisions of contracts

Contract Duration


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Volume capacity and tolerance


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Volume, capacity and tolerance

Volume. The first is the amount of gas, which can be sold and purchased,the total amount of gas, which can be taken over the life of the contract.

Capacity, which is represented by the minimum rate at which the seller must

offer gas and the maximum rate at which the buyer may take gas. The

capacity is usually expressed as a daily quantity.

Tolerance clauses to allow to some extent for the unforeseen. Tolerances

affect the contract volumes only partially, but may affect any penalties due

for failure to live up to the contract.



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Annual Contract Quantity (ACQ). It represents the maximum annualquantity the supplier is obligated deliver to the buyer

The ACQ may be stated as an independent figure in the contract or

alternatively it can be sometimes expressed as the multiple of a Daily

Contract Quantity (DCQ)

ACQ = 365*DCQ.Daily Delivered Rate (DDR) expresses the rate at which the sellers

facilities must be capable of delivering gas. It is usually expressed as

a multiple of the DCQ. The DCQ is multiplied by the fraction 1/load

factor.




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Load factor is a very important component of the contract,because it determines buyers flexibility. Lower load factor and

therefore higher daily volume flexibility offers to the buyer the

possibility to purchase more in the period, when he desires it.

Downward Quantity Tolerances states the amount by which abuyer may fall short of its full Annual Contract Quantity (in a Take

or Pay gas sales contract) without incurring sanctions. If there is

no provision requiring the buyer to take supplementary volumes in

subsequent years to make good for the deficiency, the ACQ

becomes in effect the ACQ minus the DQT which we call AnnualMinimum Quantity (AMQ).



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LNG Contracts

Types of LNG Sales Contracts


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ypes o G Sa es Co t acts

FOB (Free on Board)

- delivery point at connection between ship and loading facility

CIF (Cost, Insurance, Freight)

- delivery point at the buyers receiving terminal

- risk of loss passes to the buyers at loading point or an agreed pointon the trip

DES (Delivered Ex. Ship)

- delivery point at flange connecting ship to receiving

terminal

- the seller bears all costs and risks up to terminal

Shipping terms


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pp g

Deliveries may be on Free-on-board (FOB) basis, where the buyer

takes ownership of LNG as it is loaded on ships at the export LNGfacility. The buyer is responsible for LNG delivery, either on its own

ships or ships chartered by the buyer. The contracted sales price

does not include transportation costs.

Cost-insurance-freight (CIF) basis, where the buyer takes legal

ownership of the LNG at some point during the voyage from theloading port to the receiving port. The seller is responsible for the

LNG delivery, and the contracted sales price includes insurance and

transportation costs.

Delivered ex-ship (DES) basis, where the buyer takes ownership of

the LNG at the receiving port. The seller is responsible for LNGdelivery, and the contracted sales price includes insurance and

transportation costs.

Main Terms of LNG Contracts


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Duration

QuantitiesBuild up volume

Annual Contract Quantity (ACQ)

Downward Quantity Tolerance

Upward variation

Take-or-Pay clauses

Shipping Agreements

PriceQuality

Build up and Plateau Arrangements


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Main Terms of LNG contracts (1)


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( )

DurationMostly long term contracts, 20 years

Trend toward medium and Short Term contracts,SPOT with deregulation

Buyers and Sellers prefer Long Term, to securefinancing of infrastructure

Build up volumeSellers prefer fast build up to recover investment

Buyers prefer slow build up to follow marketgrowth

Compromise to be found



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( )

Plateau QuantitiesACQ (Annual Contract Quantity), expressed in

energy (TBtu/year) or in number of cargoes per year

DQT (Downward Quantity Tolerance): volume

that the buyer can defer without going to Take or Payobligation. Generally 10% with a maximum on cumulated

volume. May be subject to Make Up arrangement.

Upward Variation: additional volumes required bybuyers, depending seller ability to supply.



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( )

Take or Pay clausesObligation for the buyer to pay a cargo, even if

he cannot take it for market or other reasons

Transfer the market risk to the buyer, and

secures cash flow for the seller

The Downward Quantity Tolerance is negotiated,

generally leading to a Take-or-Pay level of 90%

(DOT=10%)

Volume under Take-or-Pay called Minimum Bill



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( )

PricesBase price

Escalation formula: crude oil linkage

Frequency of calculation: quarterly or

monthly

Procedures for renegotiation, either

regular (every 5 years) or according to

change in context.

LNG Project Structure (1)


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Bontang LNG Project Organization


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Japanese

BuyerOffshore

Badak Train F

Project Finance


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PT Badak LNG Plant

Pertamina

Trustee

Turn key

contractors

Gov. of

Indonesia

BanksE. Kalimantan

Gas Producers

Plant use &

operation

agreements

Gas Supply

agreements

Producers

agreements

PSC

Loan

agreements

Offshore

proceeds

account, NY

Processing

agreements

Source: International Advisory & Finance

LNG Terminal - Tolling Model

Contractual Structure Diagram


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LNG ProducerLNG Producer

END USERS LNG Receiving Terminal

Terminal Used Agreement

(TUA)

Gas Sales

Agreement

LNG Vessel Owner

Time Charter

Party Agreement

Company

Operation & Maintenance

Agreement

LNG Terminal - Merchant Model



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LNG ProducerLNG Producer

END USERS

LNG Receiving Terminal

LNG Sale and Purchase

Agreement

Gas Sales

Agreements

LNG Vessel Owner

Time Charter

Party Agreement

Time CharterParty Agreement

Company

Operation & MaintenanceAgreement


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Gas contract and price vision


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Structure of Natural Gas


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Structure of Natural Gas

Industry/Market- lecture 1

Natural Gas Economic 2012

Widodo W. PurwantoDepartemen Teknik Kimia

Outline


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What is natural gas?

Structure of natural gas industry

What is natural gas market?

Gas trading & infrastructures

What is natural gas?


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Natural gas components


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Natural gas problem is volume

F th t t


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For the same energy content:

Characteristics and conversion factors


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1 m3 of LNG = 630 m3 of gas 1 Ton of LNG = 2.22 m3 of LNG = 52 MMBtu

1,400 m3 of gas = 1.3 Ton of crude oil

49,500 Cft of gas = 9.0 bl of crude oil

1 Million Tons/year of LNG = 130 MMCFD of gas sales

= 142 MMCFD of gas at LNG plant inlet

A ship of 135,000 m3 = 60,000 Tons of LNG = 3 BCF of gas

1 TCF of natural gas eq. to 1 Million Tons of LNG for 20 years

Average Heating Values: Natural Gas: 1,000 Btu/Cft

Crude Oil: 5.8 MMBtu/Bl.

Oil and Gas Industry


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Oil and Gas Industry

The natural gas value chain


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Upstream Midstream Downstream


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Natural gas transportation


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SUPPLY MARKETS

Pipeline

Liquefied natural gas (LNG)

Compressed natural gas (CNG)

Gas to Liquids (GTL)

Gas to Chemicals (GTC)

Gas to Wire (GTW)

Physical conversion : pipeline, CNG, LNG, GTSChemical conversion : GTL, GTC, GTW

Gas to Solid (GTS)

Structure of Natural Gas Industry


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Key Dates in the Deregulation of

the US Natural Gas Industry


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Development of Competition in the British Gas Market


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LNG market structure


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Why Regulate?


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Avoid monopolyRegulation: exclusive teritories, setting

rate/tariff etc

Who ragulates: Regulatory Commission orGov.

Regulatory process: rolemaking, rate cases,

certificate cases, service standard, complaintcases

Aim of Regulation


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Approaches to Regulation


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Policy instruments


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Why Deregulation?


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Competitive gas market

The market maturation cycle: regulation,

deregulation, commoditization, value-

added servicesMarket dynamics

Natural gas industry-Indonesia


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TGI, Nusantara Regas

Pertagas/Pertamina?

PGN

Small CNG companiesPertamina,

Total Conoco


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Natural gas industry (USA)


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Natural gas industry (USA)


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Natural gas industry (UK)


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Natural gas industry (ARGENTINA)


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Natural gas industry (Thailand)

UNOCAL OthersTOTALPTTEP


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PTT Transmission

Company

PTT Distribution

Pipeline Co.

PTT Co Ltd/Plc

(Supply & Marketing)

Transmission

Companies

Distribution

Companies

Supply & Marketing

Companies

100% shareholding

EGAT Private Power Producers

IPP / SPP

End Users

Industrial Sector


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What is


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Market consist of


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The physical (cash) market: business activity,supply and demand fundamental,

transportation and physical transaction

Financial Market: Value, pricing and trading


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IGU 2006


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Gas production/consumption by region


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Gas consumption per capita


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Chart of natural gas trade


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Major gas trade movements


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Gas

domestic vs. export


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Produksi 8.13 bcf/d ~ ~

Demand gas 3.38 bcf/d 9.15 bcfd 13.22 bcfd

Ekspor 4.75 bcf/d

Impor 1.02 bcfd 5.09 bcfd

2005 KEN (2025)

Domestic gas market


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Gas Pipeline Network

Medan Block

W t N t

Block B-Duyong


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Corridor-Singapore

Planned

Samarinda

Duri-Grissik

West Natuna

- Singapore

So. Palembang Block

Jawa Barat

Jawa Timur

Bunyu

Bontang

Pare-Pare

Vogel Kop

Existing

Future

Gas supply EU


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Gas supply EU


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JAPAN Gas Facilities


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Japan gas pipeline supply option


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TAGP


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Australia gas network


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US gas market


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US gas network


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North America gas supply


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LNG Economics


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Widodo W. Purwanto



LNG Technology Chain


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LNG Trade History


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1964

First plant in Algeria (Arzew), delivery to UK1969 First LNG deliveries to Japan (from Alaska)

1970s Start up of Indonesia (Arun, Bontang), Abu Dhabi,Libya, Brunei projects

1980s Start up of Malaysia, Australia projects

1990s

Start up of Qatargas, Nigeria, Trinidad and RasGasprojects

2000 Start up of Oman LNG project

2006 Australia

2007 Norway

2009

Qatar II ( 7.8 Mtpa)

2009 Rusia

2010 Peru


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LNG Plant


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LNG Plant


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LNG Plant


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Global LNG Capacity


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LNG capacity and technology


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LNG tech comparison


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Floating LNG


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World largest LNG exporter


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LNG Supply: A plethora of new projects


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LNG Terminal


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Start-up LNG Terminal


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LNG Terminal Capacity


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LNG Terminal

Send-out capacity


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LNG Fleet and Order


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LNG carrier types


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LNG ship capacity and age


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LNG Chain Costs by Liquefaction,Shipping & Regasification


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Investment Costs: Site Preparation, Gas Treatment, Liquefaction,Utilities & Ancillaries, LNG Storage & Loading, Other InfrastructureOperating Costs: Personnel Expenses, Maintenance Cost,Consumables, Overheads, Insurance and Taxes, Variable Costs

Investment Costs: Tanker CapacityOperating Costs: Fixed Costs (crew), Maintenence Expenses,Insurance, Overheads, Variable Costs (fuel, consumables, port charges,taxes)

Investment Costs: LNG unloading facilities, LNG Storage, LNGvaporization and sendout, Utilities, InfrastructureOperating Costs: Fixed Costs, Maintenance Expenses, Insurance,Overheads, Variable Costs (power, fuel, consumables)

PEUI -2007

Typical Costs for a project of 8 MTons/year


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Cost Element US$ (2003) US$/MMBTU

(Billion)

Gas Production 1.0 - 2.0 0.5 - 1.0

Liquefaction 1.2 - 1.8 0.8 - 1.2

Shipping 1.0 - 2.0 0.5 - 1.0

Regasification 0.5 - 1.0 0.3 - 0.6

Total 3.7 - 6.8 2.1 - 3.8

PEUI -2007


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Liquefaction cost

Capital Expenditure LNG plant


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100,000 GPD = 160 TPD = 0.05 MTPA

Reducing LNG costs: a trend that is reversing?


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Source: LNG Focus, 2006


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Mid-Scale LNG costs


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Source: Linde

Full chain base load LNGcapital cost breakdown


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Source: Patel Foster Wheeler

Capex breakdown (Technip-Coplexip)

2 Train plant 45-65%Utilities 8-15%


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Offside 20-40%Common 7-10%

Total LNG plant 100%Others 15-30%

Total LNG project 115-130%

Train: common/inlet facilities, impurities removal (acid gas, water,mercury, sulfur), refrigeration/liquefaction, fractionation.

Utilities: power generation, cooling water, other water, steamfuel, air and nitrogen

Offside: LPG storage & loading, condensate storage & loading,loading jetty, flare and liquid blow-down, other fire protection,drainage & waste treatment

Common: site infrastructure, control room, DCS,ESD, telecom, administration& maintenance building

Others: gas pipeline, site preparation, material offloading, residential area, sparepart, movable, training and start-up.

Liquefaction cost component

Plant capacity: 5 mtpa


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p y pTotal plant capital cost $ 1.2 billionUtilization rate 90%

Annual cost of capital $ 155 milion

Per Mcf cost of capital $0.72/McfFuel $0.08/Mcf Taxes $0.15/Mcf Operating costs $0.2/Mcf

Total cost of liquefaction $1.15/Mcf

Source: Bob Shively & John Ferrare, 2005


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Liquefaction cost componentKapasitas 500 MMscfd

Train 3,85 MTPA

200.000.000 MMBtu/Year


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Capex 700 USD/TPA

Capex total 2.692.307.692 USD

Life time 20 Year

Cost of Capital 10,00% %

CRF 0,1175

Capex Annual 316.237.451 USD/YearCapex Cost 1,58 USD/MMBtu

O&M 107.692.308 USD/Year (4% dari capex)

O&M Cost 0,54 USD/MMBtu

Biaya Bahan

Bakar 50 MMscfd (10% feed)

17.750.000 MMBtu/Year4 USD/MMBtu

71.000.000 USD/Year

Fuel Cost 0,355 USD/MMBtu

Liquefaction Cost 2,47 USD/MMBtu

Liquefaction Capital vs. Capacity


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PEUI -2007

Capital investmentsSmall Scale LNG plant


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Small scale LNG infrastructure


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Shipping cost


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Shipping Cost

T k t


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Tanker cost

Mid Size (138,000 m3)1993 ~ US$ 320 million/ship

2005 ~ US$ 170 million/shipLarge size (216,000 m3) ~ US$ 210 million

Daily carter rate

US$ 27,000/day

US$ 150,000/day

PEUI -2007

LNG vessel cost


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Fleet utilization and short term charter rates


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Shipping costKapasitas 500 MMscfd O&M 21.600.000

USD/ Year

(4%Capex)

200.000.000 MMBtu/Year Portfees/station 80.000 USD

8.538.462 m3 LNG/year port charges 4.793.522 USD/ Year

Kapasitas

Tanker 150 m3 untuk LNG labor 5.301.195 USD/Year

95% Insurance 6 027 907

USD (15% OPEX

total)


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95% Insurance 6.027.907 total)

Kapasitas Aktual 142,5 m3 Misc 4.018.605

USD (10% OPEX

total)

64.772 Ton LNG OPEX total 41.741.229 USD/ Year

t loading 12 hour OPEX Cost 0,21 USD/MMBtu

t unloading 12 hour Boil off 0,03

(3% actual

capacity)

Kecepatan 18 knot Fuel Mix 0,5

33,34 km/jam 972 ton

Jarak 3564 km 50.523 MMBtu

day/year 350 hari LNG Price 12

USD/MMBtu

(ICP/8)

Waktu

Perjalanan 107 Jam 303.136 USD/Trip

Roundtrip (PP) 238 Jam 27

MMBtu/liter

(Fuel Oil)

9,91 Hari 688.554 Litre (Fuel Oil)

days in port 67,75 hari/Year Fuel Oil Price 1 USD/Liter

Waktu berlayar

/ Year 282,25 Hari 688.554 USD/Trip

28,48 trip/Year Total per Trip 991.690 USD/Trip

Kapasitas

angkut 4.058.882 m3 LNG/kapal/Year Total per year 59.421.125 USD/ Year

Jumlah Kapal 3 FUEL Cost 0,3 USD/MMBtu

Capex 180.000.000 USD/kapal Shipping Cost 0,82 USD/MMBtu

540.000.000 USD

Durasi 20 Year

CoCapital 10%

CRF 0,1175

Shipping cost


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Source: Henry Lee, 2005

Shipping cost


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Characteristics of trips


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Typical Delivered cost of LNG


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Shipping cost f (distance)

H L


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Henry Lee:

US $/mmbtu = (distance + 1650)/16107

distance is round trip in nautical miles

distance is round trip in km

US $/mmbtu = 7 x 10-5 distance + 0.102


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Regasification cost


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CAPEX LNG Terminal

Hazira India 2.5 mtpa (330 mmscfd) - US$ 600 million

Sempra 7.5 mtpa (1bcfd) US$ 800 -1000 million

Q l 2 b fd (2009/20 0) j


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Exxon-Qatar Petroleum, 2 bcfd, (2009/2010), jetty, 5 x

150,000 m3 full containement, 1.3 billion US$

Ken UK, 1.7 bcfd, 3 x 190,000 m3 full containement, 1

billion US$Fujian/CNOOC, 350 mmscfd, 2 x 160,000 full

containement, 250 mm US$ (2008)

Quentiro, Chile, 400 mmscfd, jetty, 2x 160,000 + 10,000m3 full containement, 775 mm US$ (2010)

Ecolectrica, Puerto rico, jetty, 90 mmscfd, 160,000

double containement, 150 mm US$ (2000)

LNG Regas cost


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Small LNG terminal (dedicated)

(165 m3 - for Power generation) 1000 MW needs 130 mmscfd of gas


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Typical Cost Breakdown Regas


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Regasification costKapasitas regas 400 MMscfd

0,01072 Bcmd

140.000.000 MMBtu/Year

Capex 110.000.000 USD/Bcmy

412.720.000 USD


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Durasi 20

CoCapital 10,00%

CRF 0,1175

Capex Annual 48.477.936 USD/Year

Capex Cost 0,34 USD/MMBtu

O&M 20.636.000 USD/Year (5% capex)

O&M Cost 0,15 USD/MMBtu

boil off 0,15%

Konsumsi bahan bakar 1,50% % Kapasitas storage

6 MMscfd

2.100.000 MMBtu/year

Fuel Price 12 USD/MMBtu

25.200.000 USD/Year

Fuel Cost 0,18 USD/MMBtu

Regas Cost 0,67 USD/MMBtu

Natural Gas Pipeline Economics


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Widodo W. Purwanto



Type of natural gas transportation

How to bring natural gas from the fields to potential gas markets?


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Physical transportation : pipeline, LNG, CNG, GTHChemical conversion : GTL, GTC, GTW

How to bring natural gas from the fields to potential gas markets?

GAS

SUPPLY

GAS

MARKETS

Pipeline

Liquefied Natural Gas (LNG)

Compressed Natural Gas (CNG)

Gas to Liquids (GTL)

Gas to Chemicals (GTC)

Gas to Wire (GTW)

Gas to hydrate (GTH)

Concept map natural gas transportation


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Source: Hetland


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The European Gas Pipeline


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The most extensive gas pipeline networks


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IGU, 2010


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Warner ten Kate et al, IEA, 2013


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NATUNA SEA

MALAYSIAKerteh

Kuala Lumpur

The Sumatran Gas Hub


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J A V A S E A

J A V A

Jakarta

SouthJambiB PSC Corridor PSC

SUMATRA

Batam

Singapore

Duri 1. Corridor Block to Duri 540 Km 1999

2. Corridor Block to Singapore 530 Km 2003

3. Corridor Block to PLN Jkt 606 Km 2006

------------

1676 Km======

600 Kms


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Source: Baskoro, 2011


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Source: Baskoro, 2011


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Nautical mile =1.85 km


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Engineering Yardsticks

Gas velocity: 5 15 m/secPressures at consumers: 20-30 bar

Transmission pipeline pressure: 60 bar-100 bar


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p p pCompressor: interval of 150-200 kmOnshore pipeline CAPEX: ~20,000 US$/in-km

Annual operating cost of pipeline 0.5 -1.5% of the

total investment costAnnual operating cost of compressor 4-5% ofthe total investment cost

Offshore gas velocity: up to 30 m/secOffshore pipeline pressure: 100-130 barOffshore pipeline CAPEX: ~40,000 US$/in-km

Pipeline cost formula

Cost (in millions US$/mile) = 563,000 +35,600 x DD pipeline diameter in inches


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( $/ ) , ,D: pipeline diameter in inches

Cost (in millions US$/km) = 350,000 + 871,000 x d

d: pipeline diameter in meters

Source: Seddon, 2006

Pipeline Cost


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Source: Mohitpour

Steel price

$9002006


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Steel Plate Price per Net Ton

$450

$800

$850

$0 $200 $400 $600 $800 $1.000

2003

2004

2005

Pipe material cost


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Cost ratio

Compressor cost formula

Cost (in millions US$) = 2,970,000 +1,120 x P

P: compressor power in hp


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P: compressor power in hp

Cost (in millions US) = 2,970,000 + 1,500 x p

p: compressor power in kW


Rule of thumb: Pressure drop, Power & Fuelconsumption

50 km pipeline, 24 in, 200 PJ/y (500


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p p , , J/y (mmscfd) dP=10 bar ~1.8 MW

Fuel consumption on annual basis 31.5

GJ/kW ~ 22.3 mmbtu/hp 50-60 km, fuel consumption 3% of the gas

transmitted


Principal working assumptions forpipeline and LNG cost study


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PT Perusahaan Gas Negara

for the South Sumatra to West Java Phase II Gas Pipeline Project


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Tipikal Cost breakdownpipa gas PGN


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Levelized costKapasitas 700

mmscfd (kap.

Troughput)

5

Million Metric Ton Per

Annum (MTPA)

245.000.000MMBTU/Year

258,475 PJ/Year

Tekanan gas 70 Bar

Flowrate gas pipa 10 m3/sKec gas 15 m/s

Diameter 0 92 m


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Diameter 0,92 m

36,27inch

Distance 1000 km

Capex 70.000 USD/in km

2.538.553.781USD

Durasi 20

CoCapital 10,00%

CRF 0,1175Capex Annual 298.177.575 USD/Year

Capex pipeline 1,22 USD/MMBTU

Distance Between

Compresion 50 km

Number stasion 20

Power Required/stasion 6,14

MW (Gas Usage &

Value Sheddon hal. 90)

Compresor Price 2.979.210 USD

Compression Capex 59.584.200 USD6.998.738USD/Year

Compressor Cost $ 0,03 USD/MMBTU

O&M $ 129.906.899 USD/Year (5% Capex)

Unit Cost O&M $ 0,53 USD/MMBTU

Transportation Cost 1,78 USD/MMBTU


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BPH, 2011


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BPH, 2011


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BPH, 2011


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No. Name of Project Loan Condition

1 W. Java Transmission System

financing pipeline project


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2 Gas Distribution (Jakarta, Bogor, Medan) I = 12 %, grace period = 5 years, loan period = 15 years

3 Gas Distribution (Surabaya) i = 13 %, grace period = 5 years, loan period = 15 years

4 Grissik - Duri i = 15 %, grace period = 4 years, loan period = 20 years

5 Grissik Batam - Singapore i = 15 %, grace period = 4 years, loan period = 20 years

6 S.Sumatra - W.Java i = 0.95 % and 0.75%, grace period = 10 years, loan period = 40 years

7 W. Java Trans & Distribution Expansion i = %, grace period = years, loan period = years

8 Cirebon - Semarang

9 Semarang - Gresik

10 E. Kalimantan Central Java

$ (MM)D (inc Funding Owner No Name of Project Year L (km

Financing the project: from public to private


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1 W. Java Transmission System 1978 200+ 28 120 Pertamina Pertamina

2 Gas Distribution (Jakarta, Bogor, Medan) 1986 34 IBRD PGN

3 Gas Distribution (Surabaya) 1990 86 IBRD PGN

4 Grissik - Duri 1995 544 28 310 ADB, EIB PGN5 Grissik Batam - Singapore 2001 478 28 415 ADB, EIB PGN

6 S.Sumatra - W.Java 2004 520 28, 32 440 JBIC, PGN PGN7 W. Java Trans & Distribution Expansion 2005 120 PGN, IBRD PGN8 Cirebon - Semarang 230 Private Private

9 Semarang - Gresik 250 Private Private10 E. Kalimantan Central Java 1,219 1,600 (est.) Private Private

Source: Bappenas


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Natural Gas Price & Tariff

Lecture-2


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Widodo W. Purwanto

Departemen Teknik Kimia

Universitas Indonesia


Outline

Type of natural gas price


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Natural gas pricing mechanism

LNG Price

Tariff

There is no World Prices for gas yet

Market maturity In developmentMature

Oil and gas are different commodities


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Regional differences

Different outlets

Risks

Regional

No captive market

Market risk

International

Captive markets

Exploration risks

Oil is an internationally traded commodity.. But the isolated regional nature of

gas markets, coupled with heavy government intervention in gas pricing, has

led to wide variations in pricing practices. There is no world gas price.

Jensen, 2011

World Natural gas and LNG Prices


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Asian LNG Import Prices


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Source: IGU, 2011


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Harga gas bumi dalam rantai nilainya


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Source: Weijermars, 2011

Pembentukan harga gas wholesale(border/hub)


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Source: IGU, 2011


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Mekanisme Pricing

Gas on gas competition

Oil price escalation

l l l


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Bilateral monopoly

Netback from final product

Regulation on a cost of service basis

Regulation on a social and political basis

Regulation below cost

No pricing

Source: IGU, 2011

World gas price formation, 2007


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Source: IGU, 2011


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Source: IGU, 2011


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Gas-on-gas competition is the dominant pricingmechanisms in the US and the UK. It means that the gasprice is determined by the interplay of gas supply and

demand over a variety of different periods (daily, weekly,monthly, quarterly, seasonally, annually or longer). Tradingtakes place at physical hubs, e.g. Henry Hub, or notionalhubs such as the NBP in the UK. Trading is likely to besupported by developed futures markets (NYMEX or ICE)and online commodity exchanges (ICE or OCM).

Oil price escalation is the dominant pricing mechanism inContinental Europe and Asia. It means that the gas price iscontractually linked, usually through a base price and an

escalation clause, to the prices of one or more competingfuels, in Europe typically gas oil and/or fuel oil, in Asia typicallycrude oil. Occasionally, coal prices are part of the escalationclause, as are electricity prices. The escalation clause ensuresthat when an escalator value changes, the gas price isadjusted by a fraction of the escalator value change dependingon the so-called pass-through factor.

The gas price under oil price escalation will likely be above the

market-clearing price if oil prices are very high, and below if oilprices are very low. Thus by summer 2008, when oil priceswere in the $120-130/bbl range, gas prices may have beenclose to P2, while at low oil prices they could be around P3. Ifoil prices are in the fuel-switching range, the oil indexed gasprices will presumably be close to P1.

The demand curve is inelastic at high prices and lowprices, where there is little scope for fuel-switching,and elastic in the middle range where demand for gascan change readily depending on relative fuel prices;

The supply curve is identical to the long run marginalcost curve; and

The average cost curve cuts the long run marginalcost curve at its low point, and then the demand curveat a lower price than the competitive market price.

Bilateral monopoly negotiations were the dominant pricingmechanism in interstate gas dealings in the former East

Bloc including the Former Soviet Union (FSU) and Central

and Eastern Europe. The gas price was determined for aperiod of time typically one year through bilateralnegotiations at government level. There were often elementsof barter with the buyers paying for portions of their gassupply in transit services or by participating in fielddevelopment and pipeline building projects.The underlying valuation of the gas, the capital goods and

the services that changed hands in the intra-East Bloc gastrade was opaque, with politics playing a major rolealongside economics.

Examples of gas pricing based on bilateral negotiations

Netback from final product means that the price receivedby the gas supplier reflects the price received by the buyerfor his final product. For instance, the price received by thegas supplier from the power sector may be set in relationto, and allowed to fluctuate with, the price of electricity.Netback based pricing is also common where the gas isused as a feedstock for chemical production, such asammonia or methanol, and represents the major variablecost in producing the product.

Under cost of service based regulation the price is


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Examples of gas pricing based on bilateral negotiationsmay still be found in countries where one dominantsupplier, e.g., the national oil company, faces one or acouple of dominant buyers, say, the state owned powercompany and maybe 1-2 large industrial companies. Anumber of immature developing country gas markets have

this structure.

determined, or approved, by a regulatory authority, orpossibly a Ministry, so as to cover the cost of service,

including the recovery of investment and a reasonablerate of return, in the same way as pipeline service tariffsare regulated in the US. Normally, cost of service based

prices are published by the regulatory authority.Pakistan provides an example of cost of service basedprices, with the wellhead price being the target.

Prices may also be regulated on an irregular social andpolitical basis reflecting the regulators perceptions ofsocial needs and/or gas supply cost developments, or

possibly as a revenue raising exercise for thegovernment. In all probability the gas company wouldbe state-owned.

Many Non-OECD countries still practice below costregulation, meaning that the gas price is knowingly setbelow the sum of production and transportation costs as aform of state subsidy to the population. Again the gascompany would be state-owned.In some countries where a substantial proportion ofindigenous gas supply comes from oil fields with gas caps

or gas-condensate fields, the marginal cost of producingthis gas may be close to zero and as such it could be soldat a very low wholesale price and still be profitable.

However, to the extent it is sold below the average cost ofproduction and transportation it would still be included inthe regulation below cost category.


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Harga gas wellhead, wholesale, retail di AS


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Source: Weijermars, 2011


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Perbandingan nilai gas bumi

25

30


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0

5

10

15

20

LNG - Badak Pipeline - Java Methanol GTL (FT

Diesel)

DME

US

$/MMBtu

Distribution

Processing

Netback

Cost component of pipeline gas


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Kondisi Industri Gas Bumi Saat IniSebagai negara produsen gas - dapat memenuhi gas untukkepentingan dalam negeri sekaligus untuk penerimaan negara

dari ekspor gasHarga gas domestik harga subsidi/regulated pricemenyebabkan keengganan pemasok gas memenuhi kebutuhan


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menyebabkan keengganan pemasok gas memenuhi kebutuhandalam negeri, yang berakibat kekurangan gas bagi konsumendomestik dan investasi infratsruktur gas tersendat

Renegosiasifixed gas contract untuk beberapa koridor (JambiMerang, ONWJ, Conoco Natuna B., Pagar Dewa..)

Mekanisme pasar gas masih belum jelas

Walupun potensi permintaan gas domestik tinggi, namun hargagas domestik belum memberikan sinyal yang benar bagi

konsumen dan produsen.Belum adanya transparansi cost breakdown dari sisi produsendan konsumen

Harga gas domestik vs. Harga LNG


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Source: PGE, 2012

Oil/Gas Price ratio


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Rasio harga minyak bumi terhadap

harga gas bumi

12

14

16

18

20

NG US

NG Uni Eropa

LNG Jepang

NG PGN


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0

2

4

6

8

10

12

1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Rata-rata rasio harga minyak bumi terhadap gas di:

- US sebesar 8,7 - Uni Eropa sebesar 7,6

- Jepang sebesar 6,2 - PGN berkisar 8-18

Pusat permintaan gas domestik -Jawa dan Sumatra


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Source: PGE, 2012


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Source: PGE, 2012

Usulan Pengembangan Pasar danHarga Gas Domestik

Dengan adanya Regas LNG dan pipa transmisi

diperlukan pengembangan wholesaleborder/hub (Jawa, Sumatra)


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Mengembangkan formula harga gas hub oil

price escalation,..Transparansi cost breakdown dari sisi produsen

dan konsumen termasuk transporter

Harga gas end-user, wholesale + toll fee, margindownstream + tax

Usulan Pengembangan Pasar danHarga Gas Domestik (lanj.)

Perlu inovasi strategi mitigasi kedala-kendala

yang ada dalam pengembangan pasar gasdomestik termasuk pengembangan


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domestik termasuk pengembangan

infrastruktur gas (institusi, regulasi,

ekonomi,dll)Mengembangkan hybrid market (central

planed dan Market oriented), Thurber, PES,

2011 sebagai langkah awal pengembanganpasar gas domestik ke depan.

Instrumen Kebijakan dalamRantai Nilai Gas Bumi


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Source: Thurber and Chang, 2011


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Gas Hub?

Source: PGN and PGE


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LNG trade


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LNG Pricing Formulae in Asia (1)

1988 2004

Prices linked 85% to crude oil

10-15% premium over crude at around $18/bbl

L i d li t hi h il i d


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Lower premium declines at higher oil prices and no

premium above $28-$30/bbl

S shaped curve in some contracts

2004+

New indices and price mechanisms to reflect

changing markets?


Reference Oil Price: JCC Japanese Custom Cleared averageprice1988 2004

Price applies over an agreed range ($11 to $30/bbl), outsidethat range there is an agreement to meet and discuss

Such a pricing basis initially developed with Japanese buyers


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Such a pricing basis initially developed with Japanese buyersbut has been adopted by S. Korea and Taiwan

In Japan the basic formula has been modified by adopting anS shaped curve

No S curves in S. Korea and Taiwan contracts


Most contracts for LNG sold on an ex-ship basis use the

following pricing formula:

P(LNG) = A x P (Crude Oil) + B

where


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where

P(LNG) = price of LNG in cents$/MMBtu

P (Crude Oil) =price of crude oil in $/bbl

B = a constant in cents/MMBtu

In many contracts:

A = 14.85

B = 70 to 90 cents

Basic LNG Pricing Formulae in Asia


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Asian S Curve Price Formula


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LNG Pricing Formulae in AsiaLinkage to crude oil is about 85%

In most contracts the average of Japanese Custom Cleared

(JCC) crude prices are used, but Indonesia uses the averageprice of Indonesian crude exports

Inclusion of constant results in premium over crude oil parity


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Inclusion of constant results in premium over crude oil parityof about 10-15% at $18/bbl

Premium erodes as oil price increase and disappears ataround $28-30/bbl

Most price negotiations focus on the constant

The 14.85 factor is used in many contract is not exclusive(especially in FOB contracts)

Tipikal formula harga LNG


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Different Tariffication Methods for GasTransportation

Tariffication according to the distance: bookingcapacity along each section of the tariff routeTariffication according to pondered distance


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(average distance)

Tariffication Entry-Exit: booking capacity at entry

and exit, without taking into account physical flowsbetween these two points

Tariffication post-stamp: a unique tariff applied forinjection and withdrawal on the overall territory


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