indonesian energy report pdf 468 kb 30287

Indonesian energy report

Financial institutionsEnErgyinFrastructurE and commoditiEstransporttEchnology

A norton rose group guideAugust 2010


norton rose group august 2010 Edition no. nr8180 08/10the whole or extracts thereof may not be copied or reproduced without the publishers prior written permission.

this publication is written as a general guide only. it does not contain definitive legal advice and should not be regarded as a comprehensive statement of the law and practice relating to this area. up-to-date specific advice should be sought in relation to any particular matter. For more information on the issues reported here, please get in touch with us.

no individual who is a member, partner, shareholder, employee or consultant of, in or to any constituent part of norton rose group (whether or not such individual is described as a partner) accepts or assumes responsibility, or has any liability, to any person in respect of this publication. any reference to a partner means a member of norton rose llp or norton rose australia or a consultant or employee of norton rose llp or one of its affiliates with equivalent standing and qualifications.

Preface

indonesia is a resource rich country with a growing demand for energy. the established oil and gas industries continue to offer good opportunities for developers, but unconventional forms of energy also offer exciting new upstream potential. coalbed methane, shale gas and geothermal energy are among the sizeable and under-developed opportunities available in indonesia.

on the downstream side, indonesias need for new electricity generating capacity continues. the financial closing of recent independent power projects (ipps) in march 2010 indicates that indonesian ipps are clearly back in business. the troubled times of the 1997 asian financial crisis are a distant memory: existing ipps have performed well and pln has shown a strong payment record. the confidence of developers and financiers has now reached a critical tipping point.

this report looks at current developments in the indonesian oil, gas and power industries. We look at the industry structure, the regulatory environment and current opportunities for investors.

this report has been produced from publicly available information sources. care has been taken to check the reliability of the source, but we have been unable to verify the accuracy of all the information contained in this report. the facts contained in this report are subject to change.

please refer to the contacts listed at the back of this report, if we can assist you with any further information.

Contents

08 Executive summary

11 oil

24 gas

34 Electricity

48 definitions

50 norton rose group

51 contacts


08 Norton Rose Group

Executive summary

Oil

indonesia currently produces nearly 950,000 bbl/d of oil, but many of its fields are mature and production is declining. indonesia became a net importer of oil in 2004 and for that reason, it opted to withdraw from opEc in 2008.

chevron operates indonesias two largest oil fields the minas and duri fields where chevron employs steam flooding techniques to enhance production. indonesias largest new field development is the cepu block operated by Exxonmobil.

the oil and gas law (law 22 of 2001) (law 22) ended the monopoly control of the state-owned oil enterprise, pertamina, in the downstream sector. since the enactment of law 22 and the implementing downstream regulations, more than 25 companies have obtained licences for various downstream activities.

in 2003 pertamina was converted from a state-owned enterprise into a state-owned limited liability company. pertamina will be privatised at some point in the future, but tangible plans to carry out this goal are some way off. one of the key obstacles to further reform of the downstream oil sector in indonesia is the consumption subsidies for domestic retail fuel consumers. Whilst subsidies have been reduced, they have not yet been eliminated.

indonesia recently awarded 14 oil and gas blocks. repsol, talisman and ptt Exploration & production were some of the biggest winners of the blocks mostly offshore papua and the makassar strait.

indonesia caps the cost recovery available to contractors, as well as restricting the category of recoverable costs. this move has been widely blamed for the poor results in the 2008 and 2009 bid rounds. in January 2010 the government of indonesia (goi) announced plans to abandon the practice of capping cost recovery in order to encourage more investment in the upstream sector. revised regulation is keenly awaited.

migas launched an informal pre-bid round on 3 February 2010 for a total of 35 blocks. We understand that migas will officially open a bid round after gauging the level of interest gathered during this pre-bid round.

Gas

indonesia has proven gas reserves of approximately 98 tcf making it the tenth largest holder of gas reserves in the world. indonesia is home to southeast asias largest gas field, the natuna d-alpha block estimated to contain 46 tcf of recoverable reserves, which are largely undeveloped.

indonesia ranks eighth in world gas production. indonesia produced approximately 7.9 bcf/d of natural gas in 2009, about half of which was consumed domestically. several fields are expected to come on stream in 2010 and will boost production. indonesia exports gas to malaysia and singapore via pipeline. indonesia is also the worlds third largest lng exporter


Norton Rose Group 09

Executive summary

with projects at arun, Bontang and tangguh. Further liquefaction projects are planned, as well as regasification terminals to service east and west Java.

the goi requires gas producers with a psc signed after 23 november 2001 to supply 25 per cent of their gas production to the domestic market. however, this domestic obligation has failed to keep pace with growing domestic demand for gas from both the power and fertiliser industries. as a result the goi introduced a policy to redirect gas intended for export to domestic projects. to this end, gas has been diverted from the Bontang and arun lng projects. recently the goi has stated that producers will be allowed to export gas provided there are no domestic buyers. the ministry of Energy & mineral resources (mEmr) claims domestic customers will be given the first opportunity to negotiate the purchase of gas.

total is the largest gas producer with production of 2.57 bcf/d of gas. total produces 80 per cent of the feedstock gas for the Bontang lng project. several gas developments are taking place including chevrons ganal-rapak deepwater gas development, pertaminas natuna d-alpha field and conocophillips north Belut field development.

coal bed methane (cBm) offers huge potential to indonesia given that it holds the worlds second largest reserves, estimated to be 453 tcf. as yet there is no commercial production of cBm in indonesia. uncertainty in the legal and regulatory regime is the reason behind the lack of development to date, but this could change rapidly with the new regulations enacted in 2008. the first cBm cooperation contracts were awarded in 2008 and a further four are expected to be auctioned in mid 2010.

Electricity

indonesia has approximately 36 gW of installed generating capacity. some 87 per cent of indonesias generating capacity comes from conventional thermal sources oil, natural gas and coal. the electrification ratio is 65 per cent and there is a shortage of power with frequent black outs.

indonesias power sector is dominated by pln, formerly known as perusahaan listrik negara. pln is a vertically integrated monopoly and, until recently, was the sole buyer and seller of electricity in indonesia. pln operates around 85 per cent of the countrys generating capacity and all transmission and distribution activities. in recent years the majority of new projects have been developed by pln.

indonesia passed a new law for the electricity sector in september 2009, law no. 30 of 2009, (law 30). law 30 ends plns monopoly over supply and distribution but does not go so far as to unbundle plns vertically integrated status. law 30, however, is already controversial and subject to judicial review. it is alleged by some to be unconstitutional. it will likely be some months before the outcome of the judicial review is made public.

like the oil industry, one of the key impediments to reforming indonesias electricity sector is the subsidisation of electricity prices. traditionally, the goi has set the retail tariff payable for electricity, which is often less than the cost of production, leaving pln with a funding shortfall for new generation projects. subsidies have been reduced, but not yet eliminated. pln has suggested retail prices for electricity may rise by 10 per cent in 2010.



in order to speed the development of much needed generating capacity the goi introduced the Fast track programme in 2006 with the aim of adding more than 10,000 mW of new capacity. much of the programme has been implemented by pln using chinese contractors and equipment suppliers, with chinese export finance and domestic loans. nearly half of the new capacity has now come on line and the rest is expected on line by 2013.

there had been little ipp activity in indonesia for ten years, but it appears that indonesia is entering into a new phase of ipp activity. in march 2010 the cirebon and paiton 3 coal-fired ipps reached financial close with a combined capital cost of more than us$2.7 billion. debt was provided by Korea Eximbank and/or Japan Bank for international cooperation (JBic), alongside international commercial lenders.

pln is now implementing the second phase of the Fast track programme. unlike the first phase of the programme, ipps will have a more significant role in the second phase. there are plans for 10,147 mW of new capacity comprised of 3,977 mW of geothermal, 3,312 coal-fired, 1,660 gas-fired and 1,198 hydro projects.

in parallel to the Fast track programme, pln is progressing the 2 x 800 mW coal-fired central Java ipp which is currently subject to tender. pln is expected to offer seven other coal-fired projects for private investment in 2010.

indonesia is thought to offer excellent geothermal potential with resources sufficient for as much as 28,000 mW of power generating capacity. the mEmr has issued 26 new geothermal working areas. of that number seven have been tendered, six are in the bidding process and 13 are ready to bid. up to 50 working areas are expected to be offered at a later date. in total, there are 44 geothermal projects included in the second phase of the Fast track programme, of which approximately 30 are intended to be awarded to ipps. in april the 330 mW sarulla ipp successfully agreed a revised tariff with pln securing the future for the project and boding well for other geothermal ipps.



Oil

Oil

Introduction

indonesia had 3.7 billion barrels of proved oil reserves as at the end of 2008. much of these reserves are located onshore. central sumatra is the countrys largest oil producing province and is the location of the large duri and minas oil fields. other significant oil field development and production is located offshore northwestern Java, East Kalimantan and the natuna sea. indonesia currently produces nearly 950,000 bbl/d of oil, but many of its fields are mature and production is declining.

Institutional framework

under indonesias 1945 constitution all natural resources within indonesian territory are owned and controlled by the state. the ministry of Energy & mineral resources (mEmr) is responsible for overseeing the states ownership and management of oil and gas resources in indonesia.

oil and gas remains within the primary jurisdiction of the central goi, however, local governments have certain controls and rights to share in the financial benefits of the oil and gas business. the degree of control retained by the goi continues to be a key area of contention for the governments of the oil and gas rich regions.

Law 22 and Pertamina

indonesia introduced a new legal regime for its oil and gas industry with the passing of the oil and gas law (law 22 of 2001) (law 22). there have been several implementing regulations promulgated under law 22, as well as directions and decrees, to give effect to the broad outline principles laid out in the primary legislation.

law 22 introduced a number of changes with clear political significance. the law restructured and liberalised the state control over the oil and gas industry. law 22 confirms the grant by the state to the goi of exclusive control over petroleum natural resources and the rights for oil and gas exploration and development. more significantly, it ends the monopoly control of the state-owned oil enterprise, pertamina. the law aims to encourage competition and open the downstream sector to private investment.

the law, together with subsequent implementing regulations, transferred pertaminas upstream and downstream supervisory role to two separate government agencies. the two regulatory agencies are Badan pelaksana Kegiatan usaha hulu minyak dan gas Bumi (Bpmigas) and Badan pengatur hilir minyak dan gas Bumi (Bph migas), which implement and supervise indonesian upstream and downstream activities respectively. Both agencies are responsible directly to the president of indonesia.



Bpmigas has succeeded to all of pertaminas interests it held in pscs and other contracts in which pertamina acted on behalf of the goi (and not in respect of participating interests held by pertamina as a contractor under those contracts). the key exception relates to production sharing arrangements with contractors under technical assistance agreements. such interests have been retained by pertamina for the balance of the term of those agreements. one of Bpmigass roles is to select the representative to sell the gois share of oil and gas production. there is no presumption that pertamina will be appointed in this role, and in practice it is usually the operator of the relevant block that is appointed.

Bph migas supervises all downstream activities, which include refining, storage, transportation, distribution and marketing of petroleum and petroleum products.

in 2003 pertamina was converted from a state-owned enterprise into a state-owned limited liability company, known as pt pertamina (persero) (pertamina). theoretically, pertamina now functions like any other private sector commercial oil and gas company. it does, however, enjoy a number of benefits or privileged positions, and also assumes several additional responsibilities, due to it being a state-owned business enterprise (Bumn) and also specifically in its own right. some of these are discussed in more detail below. the goi has expressed an intention that pertamina will be privatised at some point in the future, but tangible plans to carry out this goal are some way off.

pertamina engages in upstream and downstream oil and gas activities, as well as some grandfathered rights to exploit geothermal energy. pertamina pursues its own operations, as well as through partnerships.

law 22 ended pertaminas monopoly in the downstream sector. private companies may now engage in downstream activities provided that they have been granted a business licence by the goi. With distribution to over 2,500 fuel stations, pertamina continues to be dominant in the retail market, but this is expected to erode over time. since the enactment of law 22 and the implementing downstream regulations, more than 25 companies have obtained licences for various downstream activities. shell opened the first internationally branded petrol station in indonesia in october 2005. others now include petronas and total.

one of the key obstacles to further reform of the downstream oil sector in indonesia is the consumption subsidies for domestic retail fuel consumers. consumers are entitled to purchase oil products at a discount from market prices. discounted fuels are supplied under a public service obligation that has been awarded by tender or direct appointment by Bph migas each year since 2004. pertamina has been the sole selected distributor each year. however, in 2010 two private companies, pt aKr corporindo and a subsidiary of petronas, have also been awarded distribution rights in discrete locations. a significant portion of goi expenditure is consumed by funding these subsidies. over the years the goi has made attempts to reduce the subsidies, which was met with much political ill will. in 2005 subsidies were rolled back causing petrol and diesel prices to rise by 125 per cent. Whilst subsidies have been reduced, they have not yet been eliminated.


Indonesian energy report Oil

the goi has been running initiatives to encourage consumers to reduce their consumption of subsidised fuels. in one recent initiative, consumers have been encouraged to switch from kerosene to lpg. the goi claims that over us$1.3 billion in subsidies has been saved since the programme commenced in 2007 through to april 2010.

pertamina has ambitious investment plans for 2010 amounting to us$4.2 billion. it plans to fund its capital expenditure from borrowings of us$2.5 billion, which would include a 1 trillion rupiah domestic bond issuance. in april pertamina secured us$1.4 billion on loans from a syndicate of foreign banks including citi, hsBc and anZ. the us$4.2 billion war chest would be split between upstream projects (65 per cent) and downstream (35 per cent). pertamina is looking to make five to ten acquisitions, including taking licences in oil and gas businesses. pertamina is also looking to invest in new refining capacity (see oil refining below) and floating liquefied natural gas receiving terminals (see gas lng regasification below).

Private sector

more than 230 private contractors are active in indonesia, the largest including chevron, conocophillips, Exxonmobil, total and cnooc ltd. of these, about 170 are engaged in exploration activities.

chevron is indonesias largest oil producer and operates the duri and minas oil fields, which together account for more than 30 per cent of indonesias total oil production.

conocophillips operates seven pscs in indonesia, four offshore and three onshore. the largest producing blocks are the mature Block B in the south natuna sea and the corridor Block in sumatra.

Vico indonesia, the joint venture between Eni and Bp, is the third largest production sharing contractor in indonesia.

Exxonmobils oil production is expected to substantially increase in coming years as it continues its development of the cepu contract area onshore Java.

Cooperation contracts

all private companies wishing to explore or exploit oil and gas reserves must do so via cooperation contracts with Bpmigas. under these cooperation contracts the goi retains ownership of the oil and gas and the contractor bears all the risk and costs of exploration, development and production in return for an agreed share of the proceeds derived from subsequent sale of production.



under the prevailing regulations, cooperation contracts may have a term of up to 30 years, with provision for a further 20 year extension. they provide for an initial exploration period of six years, which can be extended once by up to four years. there are also provisions for the gradual relinquishment of a portion of the operational area, or complete relinquishment where approval for the initial field development has not been obtained or where the relevant activities have not been commenced within a five year period after the expiry of the exploration period. under regulations introduced in February 2010, a field may also be required to be relinquished if the contractor does not submit a development program within new expedited timeframes, and Bpmigas is required to recommend termination of the cooperation contract in the event of breach of the contract and/or legislation and regulations. additional mEmr regulations are expected to be passed in 2010 relating to the extension of cooperation contracts, and it is expected that these will contain certain preferential rights in favour of pertamina.

Every cooperation contract entered into with Bpmigas must be approved by the mEmr and notified in writing to the peoples representative assembly (dpr). Whilst the dpr does not have the right to approve the cooperation contract, the implication is that the terms of contract will be transparent.

the form of cooperation contract most commonly entered into in respect of upstream activities is the production sharing contract (psc). the first significant indonesian psc was signed in 1966 and since that time more than 200 pscs have been signed.

the current psc used by Bpmigas, on behalf of the goi, is substantially similar to the former version used by pertamina, with the key exception of the domestic supply requirement for natural gas. Key terms of the recent form of psc are summarised below:

Table: Typical key terms of the current Indonesian PSC

Key terms

Term 30 years, of which:

Exploration: six years, with one four year extension permissible.

Participating interest at the time of approving the first development plan, a local government business enterprise (Bumd) is given the opportunity to take a 10 per cent participating interest by paying a 10 per cent share of operating costs to date (in cash). if the Bumd does not take up the 10 per cent interest, it must then be offered to a Bumn, or a private national company wholly owned by indonesian citizens.

Time limits six months to commence petroleum operations from the date of signing.

three years to submit a development plan in respect of any discovery (may be extended by two years for technically difficult areas or where there is delay in determining gas sale and purchase arrangements).

Five years to commence petroleum operations from the end of the exploration period (which may be extended for gas discoveries).



Oil

Key terms

Relinquishment Within three years of signing the psc, the contractor must relinquish a portion of the original contract area, usually between 20-25 per cent. a further 15 per cent must be relinquished if the work commitment has not been completed in this time. By the end of the sixth contract year a total of 80 per cent must be relinquished. contractor may relinquish the contract after the first three years.

Performance bond a sum as security in respect of the work commitment for the first three years. the amount will be reduced annually by deducting the amount included in the work program and budget for the required activity.

Development plans, work programs and budgets

Bpmigas, mEmr and the applicable provincial government have the right to approve the initial development plans. Bpmigas approves all annual work programmes and budgets.

Domestic market obligation

crude oil: 25 per cent, to be sold at 25 per cent of the market price (such discounted price to apply for each field from the sixth year of production from that field onwards).

natural gas: 25 per cent of the contractors gas entitlement. domestic buyers are given a one year period in which to opt to purchase natural gas. Failing which the contractor may market the gas internationally with the gois consent.

Production share First tranche petroleum (Ftp): Ftp is taken each year before any deduction for operating costs. it is either taken solely by Bpmigas (typically around 10 per cent of petroleum produced for the year), or it is shared with the contractor in the same proportion as the profit oil/gas allocation (below) (typically around 20 per cent of petroleum produced for the year). Ftp effectively operates as a cap on cost recovery and guarantees Bpmigas a minimum income from the development.

thereafter, for volumes remaining after cost recovery:

crude oil: 37.5 per cent Bpmigas, 62.5 per cent contractor.

natural gas: 28.5714 per cent Bpmigas, 71.4286 per cent contractor.

the percentage splits may vary, and will usually be more attractive for the contractor for eg, deepwater and frontier blocks.

Title to equipment title to equipment purchased by the contractor passes to Bpmigas on importation. title to leased equipment does not pass and may be freely re-exported.

Decommissioning contractor must conduct an environmental baseline assessment and will be responsible for decommissioning at the end of the term. For pscs signed from 1995 onwards, the contractor must deposit abandonment and restoration funds as equity for decommissioning costs in an escrow account in an indonesian bank. such funds will be included within the allowable operating costs for cost recovery purposes.



Key terms

Transfers no transfers of a majority interest within the first three years. any transfer of an interest to an affiliated or non-affiliated company, and any proposed change of control, requires the prior approval of Bpmigas and the goi.

Tax contractors are subject to income tax and such tax is maintained under a tax equalisation clause.

Bonus payments a payment upon signature of the contract (secured by a signature bonus bond delivered pre-execution).

Equipment and services to be provided, if requested, during the first contract year.

Further bonus payments due upon cumulative production reaching specified thresholds.

these bonus payments are not cost recoverable.

Arbitration under uncitral rules at a location to be agreed.

historically the general after tax split between the goi and the contractors for natural gas has been 70:30 after the contractor has recovered its costs. generally, the current split is between 60:40 and 70:30, but, theoretically, the production split is open for negotiation. in addition to the production sharing, the goi also levies corporate taxes on the contractors.

in response to concerns over the nature of certain items being cost recovered by contractors, and the annual value of cost recoverable items during a period of declining production, ministerial regulations were recently passed setting out a negative list of cost items not eligible for cost recovery. new regulations are proposed for 2010 that will further regulate the cost recovery mechanism, potentially setting out an exhaustive list of cost items that are eligible for cost recovery and capping the annual cost recovery amount for a block by reference to its annual work program & budget for the year. the goi also moved cost recovery into the state budget process, thereby introducing an effective annual cap on cost recovery at the level stated in the budget. in 2009 the state budget capped aggregate cost recovery at us$11.05 billion. this was increased to us$12 billion for 2010. this move has been widely blamed for the poor results in recent bid rounds. in the period running from december 2008 through to november 2009, only 25 per cent of blocks offered for tender attracted a qualifying bid. in January 2010 the goi announced plans to abandon the practice of capping cost recovery, via the state budget, in order to encourage more investment in the upstream sector, and in april 2010 announced that the cap would not be included in the forthcoming draft legislation on the cost recovery mechanism.



Oil

Licensing rounds

2010 roundindonesia offered 24 new oil and gas blocks for tender in 2010 (launched on 28 december as the second round of 2009), consisting of 12 blocks offered by way of direct proposal and 12 by way of regular auction. the majority of the new blocks offered are in central and eastern indonesia, particularly cendrawasih Bay in papua and the makassar straits. the mEmr announced the winners of 14 blocks in may 2010, who include repsol (with three blocks offshore papua) and talisman and pttEp (offshore makassar strait).

migas launched an informal pre-bid round on 3 February 2010 for a total of 34 blocks with 18 blocks under regular tender and 16 blocks under direct proposal tender. it is not an official bid round. thus a bid deadline and bid documents are not available. it was understood that Bpmigas will officially open a bid round after gauging the level of interest gathered during this pre-bid round, and removing from the round blocks which fail to generate interest.

2009 roundthe gois licensing rounds for 2009 met with a lack luster response from oil and gas companies. only three of the 24 blocks made available in the First round between June and november secured investors. the reason for the lack of interest is said to stem from uncertainty amongst oil and gas companies given the gois plans to amend cost recovery legislation (see oil cooperation contracts above), as well as the remote location of the blocks and a lack of data on the blocks.

the energy minister, darwin saleh, has stated his intention to regain investor confidence and is said to be considering new upstream incentives for oil and gas producers, including a more favourable tax regime, amendment to the cost recovery regime, better production splits under new pscs and a more consultative ministry.

seven of the 24 blocks offered in the 2009 First round were offered by way of direct tender, drawing bids for five of the blocks. only two cooperation contracts were awarded. the north makassar block was awarded to niko resources together with Baruna nusantara Energy. the block covers 414,904 acres and lies adjacent and to the north of niko resources southeast ganal Block. niko resources and Baruna nusantara Energy have committed to a signature bonus of us$1 million and a work programme of us$15 million. the Blora block in central Java was awarded to sele raya who has committed to a three-year exploration programme of us$3.44 million.

seventeen blocks were auctioned via regular tender, but attracted only one bid. the successful bidder was Brilliance Energy who was awarded the sula i block in central sulawesi. the psc for the block requires Brilliance Energy to spend us$1 million by way of a signature bonus and us$16.3 million during a three-year exploration phase.

in 2009 sarana pembangunan riau and Kingswood capital signed a psc for the langgak block in riau province.



2008 roundin 2008 indonesia held two licensing rounds with a combination of regular tender and direct proposal tender methods. the first round offered 25 blocks, 22 of which were awarded to bidders. the second round offered 31 blocks, 16 of which were awarded to bidders.

indonesia continued to auction blocks from the 2008 bid round during 2009. in december 2009 the goi awarded five blocks from the 2008 round, details of which are set out in the table below. Eleven blocks remain unallocated.

Table: Awards made in December 2009

Block Awarded to

East Bula, offshore east indonesia

halmahera Kofiau, offshore south halmahera

West papua iV, offshore West papua

niko resources and Black gold Energy

andaman iii, offshore north sumatra talisman Energy

West glagah Kambuna, offshore north sumatra petronas and pertamina

together the successful bidders committed to spending us$20 million in signature bonuses, us$5.5 million in geological and geophysical studies, us$33 million in seismic studies and us$53 million on the drilling of three exploration wells.

Production

oil production in indonesia has steadily fallen over the last few years due to declining production at mature oil fields and exploration efforts that have failed to keep pace with the decline. indonesia produced approximately 950,000 bbl/d in 2009 from 969 wells. this compares to production of some 1.4 million bbl/d in 2000 and current domestic oil consumption of 1.5 million bbl/d.

indonesia became a net importer of oil in 2004. given the subsidies offered to domestic oil users, the acquisition of foreign oil has been a major drain on goi budgets. indonesia is keenly looking at ways of reducing its reliance on oil and as a consequence there is increased interest in the use of gas, coal, coalbed methane (cBm), crude palm oil and geothermal energy.

having joined opEc in 1962 indonesia withdrew from the organisation in 2008 acknowledging that it had become a net importer of oil and was no longer able to meet its production quota.

indonesias two largest fields, minas and duri, are located off the eastern coast of sumatra and are operated by chevron. Both are mature fields and production is declining. together, these fields account for over 30 per cent of indonesias total oil production.



Oil

it is generally thought that all of indonesias giant oil fields have now been discovered, exploited and production is now on the decline. the biggest oil field discovered in recent years is the cepu block in the border areas of central Java and East Java (discussed in oil production cepu below).

indonesia offers potential for increased production via enhanced oil recovery (Eor) techniques. there are several old wells that could benefit from Eor technology, but of crucial importance to this issue is the cost recovery mechanism adopted by the goi. With uncertainty surrounding regulation on cost recovery, appetite from iocs has been dampened.

pertamina is keen to see production increase by 10.93 per cent in 2010. to that end, the goi is keen to encourage new exploration, but recent bid rounds have been disappointing (see oil licensing rounds above). in 2009, only ten contractors increased their total oil production, and most contractors failed to meet their target production levels.

in 2009 contractors committed to spending us$16 billion via work plans agreed with the goi. most of the expected investment relates to producing fields and us$2.36 billion was committed to exploration activities. the goi estimates that 122 exploration wells will be drilled in 2010, including 42 relating to cBm reserves.

in addition, the goi has earmarked us$9.52 billion for investment in oil facilities in the period 2010-2014. the planned investment will take the form of rigs and refineries.

cepuindonesias largest new oil field development is the cepu oil project offshore Java. the block contains proved reserves of 600 million barrels of oil and 1.7 tcf of gas. it consists of four fields Banyu urip, Jambaran, alas tua and Kedung Keris. cepu is operated by Exxonmobil with a 45 per cent stake in the project, alongside pertamina (45 per cent) and local governments (10 per cent). pertamina has expressed an interest in raising its stake in the project to 50 per cent.

the fast-track phase one development of the Banyu urip field came on stream in late 2008 and as at april 2010 was reported to be producing 14,000 bbl/d, significantly lower than the 20,000 bbl/d that was initially anticipated. Full-scale production from the Banyu urip field is targeted at 165,000 bbl/d by 2011, but that deadline is expected to slip at least until 2012 and possibly as far as 2014.

production was suspended between april and august 2009, reportedly due to pipeline problems. the goi has blamed Exxonmobil for the delays at the project and has cancelled an incentive given to the project on the basis that it had not achieved a production output of 20,000 bbl/d by august 2009. the production company had been granted a 60 month exemption from the obligation to sell 25 per cent of its crude production in the domestic market. the operator refers to delays in receiving regulatory approval from Bpmigas, which is essential before the operator can open bidding for the Epc work on the blocks, as well as land acquisition issues and technical problems.

the project includes an Fpso moored off tuban in the Java sea.



duridiscovered in 1941, the duri field is one of the worlds largest oilfields and the biggest steamflood operation. steamflooding is an Eor method that injects steam into the reservoir to increase oil recovery. at the duri field, steamflooding has more than tripled oil production, and has enabled the recovery of more than 2 billion barrels of crude oil. duri is located in the rokan block with current oil production of nearly 200,000 bbl/d. the field is operated by pt chevron pacific indonesia, a chevron wholly-owned subsidiary. production commenced from the north duri Field area 12, an expansion of the main mature field development, at the end of 2008 and is expected to reach 34,000 bbl/d by 2012.

chevron has entered into an agreement with conocophillips for the long term supply of natural gas destined for Eor operations at the duri oilfield. chevron also plans to buy 50 mcf/d of natural gas from pt medco Energi for a three year period, also destined for duris steamflood operations.

minasminas, chevrons oil field in sumatra, is the largest field in asia with oil in place exceeding 4 billion barrels. chevron has invested in Eor operations for the field, including a us$400 million steamflooding system installed in 1995 serving the fields 13 zones. chevron is carrying out a chemical injection project with the aim of boosting oil recovery.

Bukit tuapetronas cargali owns and operates the Bukit tua project, part of the Ketapang psc, having acquired the project from conocophillips in 2008. recoverable reserves at the field are estimated at between 50-80 million barrels of oil and 100 bcf of gas. the development calls for an Fpso to handle between 20,000-30,000 bbl/d of oil and a total of 50,000 bbl/d of liquids, with a minimum storage capacity of 600,000 barrels. Worleyparsons has been awarded the FEEd contract for the Bukit tua development. Bukit tua is scheduled to start production in 2011 with production of 20,000 bbl/d and 50 mcf/d of flare gas.

the Ketapang psc also includes the Jenggolo oil and gas discovery and the payang gas discovery, both yet undeveloped.

mahakamtotal commenced development of the south mahakam, stupa, West stupa and East mandu discoveries in 2008 and production is scheduled to begin in late 2011. the south mahakam development is expected to yield 14,700 bbl/d of liquids and 114 mcf/d of gas.



Oil

Refining

despite liberalisation, pertamina is still dominant in indonesias downstream sector. it operates all nine of indonesias refineries.

indonesia imports 350,000-450,000 bbl/d of finished products per year, which is one-third of its total demand. the majority of the imported products are imported by pertamina.

indonesias nine refineries have a total production capacity of over one million bbl/d. all are operated by pertamina and are in need of modernisation.

Table: Indonesias largest refineries (by capacity)

Location Capacity (bbl/d)

dumai, central sumatra 120,000

musi, south sumatra 16,20030,00030,00035,00016,000

cilicap, southern Java 118,000230,000

Balikpapan, Kalimantan 60,000200,000

Balongan, West Java 125,000

sei pakning, riau province 50,000

Kasim, West papua 10,000

pangkalan Brandan, north sumatra 5,000

cepu 3,800

pertamina is planning to build three new refineries over the next eight years with a combined capacity of 650,000 bbl/d. the first of which is the 200,000 bbl/d refinery upgrade at Balongan, West Java, which is scheduled for completion in 2014. it will produce 103,000 bbl/d of premium, 54,000 bbl/d of kerosene and 103,000 bbl/d of diesel.



the second refinery on the schedule is the Banten Bay refinery to be built in Bojanegara, Banten. stX pan ocean limited, national iranian oil refining industries devt co, petrofield and pertamina have formed a joint venture to construct and operate the refinery. the initial processing capacity of the plant is expected to be 150,000 bbl/d and is expected to be operational by 2013 at a cost of us$4 billion. it will produce 42,000 bbl/d of premium, 30,000 bbl/d of kerosene and 58,000 bbl/d of diesel. a further 150,000 bbl/d capacity is also planned in a subsequent stage. the feasibility study is still in progress.

the third planned refinery is the East Java refinery to be located at tuban, East Java. it has a planned capacity of 200,000 bbl/d and is targeted for completion by 2017. this plant will produce 75,000 barrels of premium, 32,000 barrels of kerosene and 51,000 barrels of diesel per day.

pertamina has further plans to expand the cilacap refinery by an additional 60,000 bbl/d, the Balikpapan refinery by 40,000 bbl/d, the dumai refinery by 50,000 bbl/d and the pare pare refinery by 300,000 bbl/d.

there are also plans for private sector investment in a us$2 billion refinery project in Batam, near singapore.

indonesia has struggled to attract foreign investment in the refining sector given low internal rates of return and low margins on sale of oil products in the domestic market, which remain subsidised by the state. Foreign lenders have in the past refused to finance refinery projects in indonesia. not only is the internal rate of return small, but they fear that once subsidies are eventually removed, demand for refined products will decline and refining capacity may then exceed demand.

Transport

indonesia has a relatively modest network of oil pipelines. the largest pipelines link fields in central sumatra with ports on the straits of malacca, offshore northwest Java and eastern Kalimantan. pertamina operates 170 oil terminals.

laga ligo international has received initial approval from the city administration of Batam to build an us$800 million oil export terminal on the island of sambu Kecil. construction is schedule to start within the year and will take two years.

the port of sabang in aceh province on the island of pulau Weh, at the northern entrance to the malacca strait, is being made ready to accommodate super tankers and super cargo ships at a cost of some us$426-533 million. as an initial step, the port authority has appointed dublin port co. to manage the port.



Oil

Storage

aKr corporindo and Vopak have established a joint venture, Jakarta tank terminal, to construct and operate a petroleum terminal located at the tanjung priok port. the terminal will be the first independent petroleum storage terminal in indonesia and is expected to have a total storage capacity of 450,000 cubic meters. the first phase of 250,000 cubic meters, was commissioned in december 2009 and the project was officially inaugurated in april 2010. the second phase is expected to be completed in 2012, depending on market demand. once completed the facility will be one of the largest tank terminals in the private sector in indonesia.

sinopec is said to be in talks with Batam sentralindo for the purpose of forming a joint venture to construct and operate an oil storage complex with a 2.6 million cubic metres capacity and a supporting quay at a cost of us$815 million.

Coal-to-liquids

sasol group signed an mou with the goi in late 2009 to study the viability of an 80,000 barrel coal-to-liquid project in indonesia, estimated to cost approximately us$10 billion. sasol will partner with tambang Batubara Bukit asam (ptBa) who will contribute reserves of 1.8 billion tonnes to the project. the parties are seeking further partners to contribute coal reserves to the project. they are currently conducting due diligence on coal mines in Kalimantan.



Gas

Introduction

indonesia had proved natural gas reserves of approximately 112 tcf as at the end of 2008, making it the tenth largest holder of gas reserves in the world. the majority of gas reserves are located offshore from natuna island and in East Kalimantan, south sumatra and West papua. indonesia is home to southeast asias largest gas field, the natuna d-alpha block estimated to contain over 200 tcf of high carbon-dioxide gas, of which 46 tcf is considered likely to be commercially recoverable.

Industry structure and legal framework

see oil institutional framework and oil law 22 and pertamina above for the role of the goi, mEmr, Bpmigas, Bph migas and pertamina in the gas sector.

indonesias state gas pipeline company is pt perusahaan gas negara (pgn), which carries out natural gas transmission and distribution activities. this role should be distinguished both from Bpmigas, the oil and gas upstream regulatory agency, and from that of Bph migas, the oil and gas downstream regulatory agency who issues rights to private companies intending to distribute or transport natural gas through pipelines (as well as licences for other downstream business activities).

the gois gas pipelines are considered to be a natural monopoly and law 22 imposes the requirement for open access. otherwise, there is no requirement on operators of pipelines and storage facilities to expand their projects to accommodate third party access. Bph migas is responsible for regulation, stipulation and supervision of tariffs for pipeline and storage services. there is yet no developed regulatory system for natural gas distribution.

law 22 liberalised the supply and trading of natural gas. the law permits the direct negotiation of gas sales contracts by sellers and buyers and the trading of natural gas. the price of natural gas for households and small scale consumers is determined by Bph migas. Bph migas also grants business licences to those wishing to engage in gas trading. a licence is either for wholesale purposes or for limited trading purposes.

pertamina remains an important participant in indonesias natural gas industry. pertamina, together with total, Exxonmobil, Vico (Bp Eni joint venture), conocophillips, Bp, chevron and petrochina account for the vast majority of gas production. total is the largest producer with production of 2.57 bcf/d of gas. total produces 80 per cent of the feedstock gas for the Bontang lng project.



Gas

Production

indonesia produced approximately 7.9 bcf/d of natural gas in 2009, about half of which was consumed domestically. indonesia ranks eighth in world gas production. several fields are expected to come on stream in 2010 and will boost production.

indonesia exports gas by way of lng to markets in south Korea, Japan, taiwan, china and mexico and by pipeline to singapore and malaysia.

the goi requires gas producers to supply 25 per cent of their gas production to the domestic market. this applies to all gas ventures with a psc signed after 23 november 2001. however, this domestic obligation has failed to keep pace with growing domestic demand for gas. the fertiliser industry has suffered from a lack of gas feedstock resulting in reduced fertiliser production. pln also claims that it needs 2.233 bcf/d of gas for power generation in 2010, but estimated supply is only 1.258 bcf/d.

as a result the goi introduced a policy to redirect gas intended for export to domestic projects. the policy has not been without cost to goi as the cost of gas supplied domestically is subsided by the goi. the gas price is between one third and one half of the sale price which could be obtained from lng export. to this end, gas has been diverted from the Bontang and arun lng projects reducing the total number of cargoes of lng exported to customers. the cost to the goi in 2009 has been estimated to be in excess of us$1 billion.

more recently, the goi has stated that producers will be allowed to export gas provided there are no domestic buyers. the mEmr claims domestic customers will be given the first opportunity to negotiate the purchase of gas. if the producers and domestic customers fail to reach agreement, the producer may export gas with the consent of the minister.

Development

generalindonesia has ambitious plans to spend us$21.68 billion on new gas investments in the 2010-2014 period. it is not clear how much of this will be funded by the goi and how much will come from the private sector. the plans include two new gas rigs in lapangan rambutan in south sumatra and in pondok tengah in West Java at a total cost of us$2.42 billion. there are also plans for five new gas plants at Blok a in nanggroe aceh sarussalam, Jambi merang in Jambi, randublatung in central Java, gajah Baru in natuna offshore riau islands and Kepodang in Bawean offshore East Java. there are also plans for gas refineries in the form of lng and lpg.

ganal-rapakchevron is undertaking the ganal-rapak deep-water gas development off East Kalimantan. the development is expected to consist of two large barge based floating production units, similar to chevrons nearby development at West seno. the water depth of the two developments range from 3200 to 6000 feet. the project requires two barge based production units, 130 kms of gas export lines and 30 subsea wells. the maha, gendalo and gandang discoveries will be tied



to a processing facility at gendalo, which will be designed to process 700 mcf/d of gas and 25,000 bbl/d of liquids. a further production facility at gehem will process 420 mcf/d of gas and 30,000 bbl/d of liquids. the gas from the development will feed the Bontang lng project. the project is expected to cost us$7-8.5 billion.

chevron announced in december 2009 that it is looking for a partner to invest in the project. chevron currently holds 80 per cent, along with Eni (20 per cent). pertamina is said to be interested in acquiring a 10 per cent interest in the project. chevron and its partner(s) are expected to make the final investment decision on the project in 2011. First output is targeted for 2013 at an initial rate of 150,000 mcf/d, rising to 900,000 mcf/d by 2016.

natuna d-alpha blockpertamina is awaiting approval of terms by Bpmigas before it selects a partner to develop the remote offshore natuna d-alpha block. pertamina is thought to be looking for partners to take a 60 per cent share of the project. the block is estimated to contain 46 tcf of recoverable reserves, with a strong concentration of carbon dioxide. the goi has said that after the domestic market obligation has been met (25 per cent), the balance can be exported. this is good news for iocs interested in participating in the project given the opportunity to maximise revenues from an export led project.

Exxonmobil was the former operator of the block, but the goi transferred it to pertamina stating that Exxonmobil did not deliver a development plan for the block in the timeframe required.

offshore mahakamtotal is undertaking various developments of the fields within the offshore mahakam psc, off East Kalimantan. the block produces the majority of the feedstock for the Bontang lng project. total holds the fields jointly with inpex. the block currently produces 2.6 bcf/d of gas and further developments in south mahakam are expected to add an additional 114 mcf/d of gas and 14,700 bbl/d of liquids. pertamina has also expressed an interest in acquiring equity in the mahakam block, either when the contract is set for renewal in 2017, or possibly earlier.

north Belutconocophillips produced the first gas and condensate from its north Belut field at the end of 2009. the field produced 6,000 bbl/d of oil and 80,000-90,000 mcf/d of gas and production is expected to rise to 200,000 mcf/d of gas and 20,000 barrels of oil equivalent in condensates. the field is in natuna block B located in the south natuna sea. natuna block B produced 78,000 barrels of oil equivalent in 2008 and was expected to produce 53,000 barrels of oil equivalent in 2009. conocophillips operates the block with a 40 per cent stake, together with inpex (35 per cent) and chevron (24 per cent).



Gas

Block amedco Energi is awaiting approval for a 20-year extension of its psc for Block a in aceh. medco Energie applied for the extension in 2008, but the approval process has stalled at the local government level in aceh. medco Energie holds a 41.67 per cent stake in the development, along with premier oil (41.66 per cent) and Japan petroleum Exploration co. (16.67 per cent) the block is estimated to contain gas reserves of 500 bcf and can produce around 50-100 mcf/d for about 15 years.

JambaranExxonmobil expects to produce 500 mcf/d of gas from the Jambaran field in the cepu block commencing 2015. the block is estimated to contain 1.3 tcf of gas reserves. the goi is keen to accelerate the production schedule.

gajah Baru (new Elephant)development works are continuing at premier oils delayed gajah Baru (new Elephant) offshore project in the natuna sea. gajah Baru is expected to produce 140 mcf/d of gas, which will be sold to customers in singapore and Batam island via an existing subsea pipeline. First gas is expected in late 2011.

rubypearl Energy is proceeding with the FEEd work for its ruby gas project off East Kalimantan. ruby, the renamed makassar straits field, is expected to produce 100 mcf/d of gas, which will be sold into the domestic market. a possible destination for the gas is the Bontang lng project.

Wortel and oyongthe goi has recently approved santoss plans to develop the Wortel gas field. the Wortel field in the sampang block, offshore East Java, is estimated to contain recoverable reserves of about 150 bcf. santos operates the block with a 45 per cent share, along with singapore petroleum company (40 per cent) and cue Energy (15 per cent). the field is expected to start producing gas in 2011. santos has started gas production from its oyong phase two development in the same sampang block. the project is expected to reach plateau production of 50-60 mcf/d of gas, which will be sold to power grati for use at the grati power plant.

KerendanElnusa (of indonesia) and sound oil are seeking new partners to help restart exploration activity at their Bangkanai psc in central Kalimantan. Elnusa is aiming to commence production from the Keredan gas field in 2011. the field contains proven gas reserves of 187 bcf and proven and probable reserves of 238.5 bcf. the gas will likely be used for domestic power generation.



Pipelines

most gas pipelines in indonesia are project specific and are not interconnected. pt transgasindo, a company owned 60 per cent by pgn and 40 per cent by a consortium of conocophillips, petronas, talisman Energy and singapore petroleum, owns and operates two gas transmission pipelines, and pgn owns and operates the remaining two:

Table: Indonesias gas transmission lines

Pipeline Operational since Length (km) Owned by

grissik-duri 1998 536 pt transgasindo

grissik-singapore 2003 470 pt transgasindo

medan and Jakarta/Bogor 2000 536 pgn

south sumatra-West Java 2003 1,116 pgn

in January 1999, sembgas, signed an agreement to purchase West natuna gas from pertamina. the gas is transported to singapore via pipelines from three separate blocks. since January 2001, West natuna has supplied 325 mcf/d as part of a 22-year deal, while a pipeline from south sumatra began supplying 350 mcf/d of gas to singapore in 2006. in 2008 a further gas sales agreement was signed to export gas from West natuna sea Block a to sembgas in singapore. another 100 mcf/d of natural gas is anticipated to be delivered via the south sumatra pipeline from the conocophillips operated corridor Block to power singapores planned island power station, but the project has experienced numerous delays.

indonesia also pipes natural gas to malaysia via a 250 mcf/d pipeline from the conocophillips-operated natuna sea Block B.

pgn operates more than 3,187 kms of natural gas pipelines across nine regional networks, which serve around 84 million customers. however, the limited size of the network and the lack of interconnectivity has been an obstacle to further domestic consumption. as a result, indonesia still relies heavily on oil, but the goi has stated that it is keen to promote the use of gas.

indonesia is a keen proponent of the trans-asEan gas pipeline, which is a project aiming to link the gas networks of major consumers and producers in southeast asia.



Gas

LNG

liquefactionindonesia exported some 26.85 bcm of lng during 2008 to countries such as Japan, south Korea, china, taiwan and mexico, making it the worlds third largest lng exporter behind Qatar and malaysia.

indonesia has three lng liquefaction projects in operation, detailed in the table below:

Table: Indonesias LNG liquefaction projects

Project Location Capacity (mtpa) ShareholdersGas sourced from

Export destination

Bontang Badak, East Kalimantan

22.5(8 trains)

pertamina 55% Vico 20% total 10% Jilco 15%

total chevron Vico

Japan south Korea taiwan

arun north sumatra 10(6 trains)

pertamina 55% Exxonmobil 30% Jilco 15%

Exxonmobil Japan south Korea

tangguh West papua 7.6(2 trains)

Bp 37.16% cnooc 16.96% mitsubishi 16.3% nippon oil 12.23% Kg 10% lng Japan 7.35%

Bp china south Korea mexico Japan

BontangFrom a peak production level in 2001 of a bit over 21 mtpa, Bontangs production levels have dropped so that in 2009 it produced about 17.3 mtpa of lng. it began experiencing lng shortfalls in 2004, causing the goi to ask its Japanese buyers to cancel cargoes. maintaining Bontangs production has been difficult in part because of declining gas production, but also as a result of goi policy to divert gas for domestic use for fertiliser and lpg production.

the Bontang plant is expected to produce 279 cargos of lng in 2010, down from 296 cargoes in 2009.

total supplies 80 per cent of Bontangs natural gas from its fields in the mahakam psc area. totals psc for the mahakam block expires in 2017 and it has requested an extension from the goi. total is committed to spending us$8 billion on developing the block in the period to 2015. mahakam is expected to produce 2.55 bcf/d of gas and 97,200 bbl/d of condensates in 2010.

pertamina is said to be interested in acquiring up to a 25 per cent interest in the block. the mahakam block is currently held by total and inpex in equal shares.



Arunthe arun lng facility receives gas from Exxonmobils gas fields in aceh. Exxonmobil estimates that it has depleted more than 90 per cent of the reserves in these fields. as a consequence, arun lng expects that it will ship 36 cargoes of lng in 2010, down from 42 in 2009. Each cargo is 125,000 cubic meters.

like Bontang, the goi redirected gas produced from the aceh fields towards domestic consumption, thereby decreasing the natural gas available for export. to meet long term contractual obligations, the goi defers cargoes or purchases cargoes of lng on a spot basis.

Tangguhthe tangguh lng project consists of six gas field developments in the Wiriagar, Berau and muturi production sharing contracts in the Bentuni area of papua. gas is produced from two offshore platforms and transported via 22 kms of pipeline to two onshore liquefaction trains, each with a capacity of 3.8 mtpa.

the tangguh lng project exported its first cargo of lng in July 2009 and that year a total of 16 cargoes were shipped to buyers. the project suffered from initial technical problems causing delays and the project fell short of output targets for 2009. as a consequence, Bp was forced to purchase swap cargos from Bontang to meet its contractual commitments. in 2010 the project expects to ship 116 cargoes of lng to customers.

Earlier this year, the minister of Energy and mineral resources approved a long term supply deal between the tangguh project and tohoku Electric power of Japan. pursuant to the agreement, tangguh lng will supply 125,000 tonnes for 15 years.

in march 2010 chubu Electric power agreed to purchase 2 mtpa of lng from the tangguh project over a five year period.

Donggi Senoro LNGa consortium of mitsubishi corp (51 per cent), pertamina (29 per cent) and pt medco Energi internasional (20 per cent) have been planning a 2 mtpa project utilising gas from the senoro and matindok gas fields in central sulawesi at a cost of us$8 billion. the final investment decision is due within weeks and if positive, the project would be operational by 2014.

plans for the single train lng project in central sulawesi received a positive boost recently when the goi gave its approval for gas from the senoro fields to be exported, subject to minimum domestic obligations (expected to be 25-30 per cent).

preliminary heads of terms have been agreed with Kyushu Electric power company, chubu power company and Korea gas corporation for long term offtake of lng.



Gas

Abadi LNGinpex has plans to develop the abadi field as a floating lng project at an estimated cost of us$19.6 billion. Whilst the project has received initial approval from the goi on the basis of a floating lng design, the decision whether to base the liquefaction project onshore or offshore is still under consideration. the abadi field is located in the arafura sea in the masela psc about 170 kms west of saumlaki. the field is located at depths of 400 and 750 meters and is thought to contain reserves of up to 10 tcf.

Sengkang LNGEnergy World corporation is planning an lng project for its sengkang block in south sulawesi. the project would be developed in phases, starting with an initial phase of 2 mtpa increasing to 5 mtpa. the current reserves of the sengkang block are said to be 583 bcf of gas, but Energy World corporation claims potential reserves could be as high as 7 tcf.

pgn has signed a preliminary agreement with Energy World corporation for a five year supply of lng for domestic usage starting in 2012. this would be the first sale of lng for domestic use. the future of this sales agreement, of course, depends on plans to develop an lng regasification terminal in indonesia. Energy World has also reportedly signed an agreement to sell lng to tokyo gas, however Bpmigas has suggested this was done without gois approval.

regasificationpertamina and pgn are seeking an Epc contractor for a floating regasification terminal in West Java with the capacity of 3 mtpa of gas. the terminal will supply gas to a receiving point in muara Karang, north Jakarta, and eventually supply a power plant and other industry in West Java. pln has recently announced that it will no longer take part in the project, but would be a customer for the regasified lng. the parties aspire to have the project operational by 2012. gas would be sourced from gas fields in East Kalimantan.

pertamina is also considering building a floating lng receiving terminal in East Java, with a capacity of 1.5 mtpa. state gas distributor, pgn was originally associated with the project, but appears to have withdrawn from it.

pgn has plans to build an lng receiving terminal in north sumatra with capacity of 1.5 mtpa.

Coal bed methane

indonesia has the second largest cBm reserves in the world, after china. indonesia is estimated to have over 450 tcf of cBm reserves, which is about three times as much as indonesias potential and proved conventional natural gas reserves. proven cBm reserves are 112 tcf. clearly this is a key energy source for indonesia and is expected to grow in importance and activity in the coming years.



the potential for cBm development has been identified in all 11 of indonesias coal basins, but the south sumatra and Kutai basins offer the most promise with estimated reserves of 183 tcf and 80.4 tcf respectively.

as yet there is no commercial production of cBm reserves in indonesia. uncertainty in the legal and regulatory regime is one of the reasons behind the lack of development to date, but this could rapidly change with the new regulations enacted in 2008. the goi is targeting production of 1 bcf/d by 2025.

in 2008 the goi enacted regulations to facilitate the development of cBm projects. the cBm regulations clarify that cBm exploration and exploitation are subject to indonesian oil and gas regulations. the regulations create a new type of cBm tenure distinct from oil and gas concessions. they establish a competitive direct offer procedure for the award of cBm concessions.

under this procedure the contractor offers to carry out a joint study with Bpmigas involving seismic data collection and evaluation. the contractor bears the costs of this joint study. the goi evaluates the data and based on this evaluation will delineate the cBm block into a working area, which is tendered for open bidding from interested parties. the contractor that carried out the seismic study has the option of matching the highest bid received by Bpmigas in relation to the particular block in question.

cBm projects are conducted under a psc with Bpmigas. twenty one such contracts have been awarded to date. the psc for cBm projects is broadly similar to pscs for oil and gas projects. the goi has the right to take a minority participating interest in the development. the psc also contains a domestic market obligation requiring a proportion of the gas to be dedicated to the indonesian market. the goi provides a relatively better production split for cBm projects than oil and gas projects, with the contractors production share at 45 per cent.

in march 2010 the mEmr announced that four cBm blocks will be auctioned in June or July 2010 offering two contractual options a net psc (as described in the previous paragraph) or a gross psc. under a gross psc revenue is calculated from the cBm gross production, meaning that the output will be divided directly between the goi and the contractor without any reduction for cost recovery ie, there will be no cost recovery payments. this model of contract may find favour with contractors because it allows the commercialisation of cBm from the beginning of the exploration phase. unlike net pscs, contractors would not be obliged to complete the exploration phase and receive approval for the plan of development before commercialising the gas discovered.

one of the key areas of uncertainly before the new regulations were enacted was the priority to be given to overlapping concession holders as between oil and gas psc contracts and coal concession holders. the general rule is that the contractor of an existing concession (coal or oil and gas) has a preferential right over third parties to make a direct offer for cBm exploration or exploitation within its concession area. Where there are both oil and gas and coal concessions priority is given to the oil and gas contractor in overlapping areas.



Gas

medco Energi international, arrow Energy, Batavia Energy and pt Energi pasir hitam indonesia were awarded the first cBm psc in may 2008. they spudded their first cBm exploration well on their sekayu psc in the south sumatra basin in september 2009. they are targeting production to begin in 2011. in august 2009, cBm asia development acquired a 24 per cent interest in the psc.

Vico, opicoil, universe gas and oil and the goi signed a psc for the cBm reserves of the sanga-sanga block in East Kalimantan in december 2009. preliminary studies have revealed that the block may contain 4 tcf of cBm. it will potentially be the first cBm commercially produced in indonesia and is destined for the Bontang lng plant. in another first, indonesia is likely to become to first cBm to lng producer in the world. the psc for the cBm overlays the same acreage as the existing sanga-sanga conventional psc. the existing infrastructure is expected to allow rapid and efficient development of the cBm reserves. Vico is reported to have paid us$4 million by way of signature bonus and will implement a us$38 million work programme.

in november 2009 the goi awarded six cBm blocks, as set out in the table below:

Table: CBM awarded November 2009

Block Operator and partners

Barito pt transasia resources (operator) pt Jindal stainless indonesia

sanga-sanga Virginia indonesia co (operator) Bp opic lasmo (an Eni subsidiary) universe oil & gas Virginia international co

rengat indon cBm ltd

muara Enim pt pertamina hulu Energi metana sumatera pt trisula cBm Energy

Batang asin Bumi perdana Energy ltd glory Wealth pacific ltd

langgak p sarana pembangunan riau

Shale gas

the goi plans to commence studies in 2010 on the use of gas extracted from shale. preliminary studies have shown that indonesia has sizable shale gas reserves in its soil, but the exact volume has yet to be measured.



Electricity

Capacity

indonesia has about 36 gW of installed generating capacity. the state-owned electricity utility, pt perusahaan listrik negara (persero) (pln), controls about 21 gW and the balance is produced by captive power producers (13.5 gW) and independent power producers (ipps) (1.6 gW). many of plns plants are old and inefficient meaning that productive capacity is less than installed capacity.

some 87 per cent of indonesias generating capacity comes from conventional thermal sources oil, natural gas and coal. about 8 per cent comes from hydroelectric and 5 per cent from geothermal and other renewable sources.

indonesia suffers from a shortage of power and blackouts are frequent. pln anticipates that indonesia will need additional generation capacity of 57.4 gW by 2018, with pln controlling 61.5 per cent and 38.5 per cent controlled by ipps.

pln is indonesias largest consumer of oil, but as oil production declines in indonesia, the goi is keen to diversify the fuel sources for power generation in indonesia. pln plans to make greater use of gas, coal and geothermal energy.

the electrification ratio is 65 per cent and the goi plans to increase access to electricity to 93 per cent by 2025.

Institutional framework

ministry of Energy and mineral resourcesthe mEmr is the main policy making body for electricity. it is responsible for developing the electricity master plan and preparing laws and regulations related to electricity. mEmr establishes tariff and subsidy policies. it is also responsible for the issue of business licences.

plnindonesias power sector is dominated by pln, formerly known as perusahaan listrik negara. pln is a vertically integrated monopoly and, until recently, was the sole buyer and seller of electricity in indonesia. pln operates around 85 per cent of the countrys generating capacity and all transmission and distribution activities. in recent years the majority of new projects have been developed by pln.

pln has struggled to keep up with the demand for new power generation and transmission facilities. Fuel costs make up over 85 per cent of its operating expenses and tariffs are insufficient to cover the full costs of generation. the goi pays a subsidy to pln, in the nature of a public service obligation, but this has been inadequate to provide for plns capital expenditure requirements.



Electricity

Regulatory framework

law 30indonesia passed a new law for the electricity sector in september 2009, law no. 30 of 2009, (law 30). law 30 replaces law no. 22 of 2002, which was revoked by the constitutional court on the basis that its key provisions contravened the indonesian constitution. law no. 22 replaced the earlier law. no. 15 of 1985.

the new law 30, however, is already controversial and subject to judicial review. it is alleged by some to be unconstitutional. it will likely be some months before the outcome of the judicial review is made public.

law 30 introduces three key reforms:

pln will no longer have a monopoly in supply and distribution of electricity to consumers

private businesses may provide electricity for public use, but subject to a right of first priority granted to state-owned companies (ie, pln)

a greater role for provincial and regional governments in terms of support for future projects, licence granting and tariff fixing.

like many other indonesian laws, the statute itself provides broad outline principles and much of the detail will only become clear as implementing regulations are enacted. until this time, the implementation of the new law remains unclear.

law 30 does not contemplate the unbundling of pln, the creation of any independent market or network operator, or provide open access to plns transmission network. these were key aspects of the former law no. 22 of 2002 which were thought to contravene the indonesian constitution. however law 30 does refer to the lease price of electric power network suggesting that some form of open access is contemplated. this will require further clarification through regulation.

law 30 does, theoretically, end plns monopoly over supply and distribution of electricity to end users. the provision of electricity for public use may be carried out by state-owned companies (ie, pln), regional owned companies, private business entities, cooperatives and non-governmental organisations. a generator of electricity will now be able to sell power to parties other than pln.

the entity carrying out the provision of electricity for public use must obtain a business licence, which pln is deemed to hold for the next two years. the criteria for grant of business licences have not yet been identified.

pln is given the right of first refusal to supply electricity for public use. it is not clear how this right will be implemented in practice. law 30 does not set out a process (eg, public tender). Further, it is not clear whether pln may be permitted to exercise its right of first refusal and then gain assistance in the implementation of that right from the private sector. if substantial foreign investment is to be encouraged, one hopes that the first right of refusal will be used in a circumscribed fashion.



the provision of electricity for public use may be carried out as an integrated activity to cover all business activities, from construction and operation of a power project, to transmission, distribution and sale of electricity to end users, all within one business area. Business areas will be stipulated by the goi, but law 30 does not set out the criteria for the definition of a business area. it is also not clear whether one entity can hold licences for multiple business areas.

the goi and/or regional governments (in accordance with their respective authorities for the regions in question) must approve the tariff for electricity that is sold to end users by the holder of a business licence. this in turn must be approved by the central and local parliaments. they may stipulate different tariffs for different regions, which has sparked some concern amongst indonesians that consumers in remote regions may pay more than their metropolitan counterparts.

the new law gives greater protection to land owners. holders of business licences must compensate land owners for land that is utilised in the implementation of a generation or transmission project. the method for calculating the compensation will be specified in regulations.

law 30 allows the importation of electricity with approval from the goi where certain conditions are met ie, shortage of power within the applicable region and the import will not harm the national interest in terms of sovereignty, security and economic development. Export is also permitted provided that local demand has been satisfied, there is no subsidy on the tariff and it will not harm the quality and reliability of electricity supply in the local region.

like the oil industry, one of the key impediments to reforming indonesias electricity sector is the subsidisation of electricity prices. traditionally, the goi has set the retail tariff payable for electricity, which is often less than the cost of production, leaving pln with a funding shortfall for new generation projects. in 2009, the subsidy is thought to have been more than us$4.5 billion. the movement towards a market based consumer price is a key goal for the indonesian power sector, but will take time to fully implement. pln has suggested retail prices for electricity may rise by 10 per cent in 2010.

private sector participationthe tender process for plns new electricity projects was amended in 2005 and 2006 and mandates that sponsors must be selected through an open and transparent bidding process. however, there are still certain types of projects with can be awarded by direct appointment including projects using renewable sources, marginal gas and certain coal projects.

pursuant to goi regulations issued in 2010 (the so called negative list), foreign shareholding cannot exceed 95 per cent in the production, transmission and distribution of electricity. Further, all generating projects of less than 1 mW are reserved exclusively for indonesian developers.



Electricity

IPPs

historyindonesias ipp programme commenced in the early 1990s and by the time of the 1997 asian financial crisis pln had signed ppas with 27 ipps for an expected capacity of 11,000 mW. at the start of the ipp programme, indonesia was suffering from a supply shortage, but by the time of the asian financial crisis, the committed capacity under the ppas exceeded the short term demand. the ppas were criticised on a number of grounds, but mostly because they had resulted from a non-competitive process. all but one of the ppas had been concluded without competitive bidding and many were the result of an unsolicited bid.

the ppas provided for long term power prices of between 5.75 to 8 cents per kWh, which was in excess of plns own cost of generating power. the cost of the power was exacerbated by the fact that the ppas committed pln to a long term take-or-pay obligation to pay for power, even where that power would not be needed because of the over supply situation created by the amount of power committed under the ppas. Further, tariffs were denominated in us dollars.

given that the power prices paid by consumers in indonesia were (and still are) heavily subsidised (retail prices were less than half of the actual cost of generation), pln struggled with its commitments to the ipps. With the rapid devaluation of the rupiah in 1997, plns ability to honour its obligations to the ipps became untenable.

By 1997 4,000 mW of capacity had been installed by the ipps. pln attempted to plug the gap between the price payable to the ipps and the retail revenue by raising prices. in 1998 pln raised the price of electricity by 30 per cent, but the gap was too large to bridge and risked considerable political turmoil.

accordingly, pln was forced to breach the terms of the ppas. in some instances it ceased dispatching the power from the ipp. in other cases it refused to comply with the payment terms under the ppa. plns payment obligations under the initial projects were supported by the ministry of Finance and the subsequently the goi cancelled or postponed many of the ipps.

as a result of these cancellations, arbitration proceedings were commenced by some of the ipps including paiton, calEnergy and Karaha Bodas. the indonesian courts were accused of interfering in the arbitration process and refusing to enforce large arbitral awards, causing the investors to seek enforcement proceedings against indonesian assets overseas.

paiton i was one of the most famous victims of the crisis. the 1,230 mW coal-fired project was completed in 1999 by a consortium of Edison mission Energy, general Electric and mitsui at a cost of us$2.5 billion. pln could not afford to take the power from the newly completed project and failed to complete the transmission line to export power from the project. ultimately the ppa was renegotiated, with the first interim agreement reached in late 2000, with a downward revision to the tariff from 8.6 cents per kWh to what is believed to be 4.9 cents per kWh.



in late 1999 pln and some of the ipps went back to the negotiating table to restructure existing ppas. negotiations were not easy. While pln was desperate to force the price for power down, investors claimed that the new environment warranted a risk premium.

Equity investors and lenders were scarred by the experience and have awaited regulatory reform to create a more favourable environment for reentering the indonesian power market. the regulatory reform process in indonesia has not run swiftly or smoothly with the result that there has been relatively little foreign investment in the indonesian power sector for nearly ten years. as a result capacity additions have failed to keep up with demand. until the last two years, the majority of private sector participation in the electricity sector in indonesia was purely in the form of sale of equipment and construction for projects initiated by pln.

in 1999 pln and sumitomo corporation signed an agreement to revive hopewells abandoned tanjung Jati B project. sumitomo had been the Epc contractor at the time the partly constructed project was halted in 1998. the agreement with sumitomo corporation was on a build-lease-transfer basis.

By 2003, pln had renegotiated 14 of the ppas with tariffs mostly in the range of 4.2 to 4.93 cents per kWh. since this time, plns payment record has improved significantly.

in 2007 Energy World corporation limited, was the first ipp to receive uncovered financing in more than ten years for its sengkang gas-fired power project and associated gas field project in south sulawesi, indonesia. the sengkang ipp is the only gas-fired ipp in indonesia.

ppa and goi guaranteepln has been keen to develop an improved model form of ppa so as to speed negotiations with potential ipp developers and enhance the bankability of future ipps. the new model form of ppa is expected to be used for the central Java ipp, which is currently in a tender process.

presidential regulation no. 4/2010 has mandated that the mEmr and pln accelerate development of power plants utilising renewable energy, coal and natural gas. to that end the goi has said that it will guarantee the business feasibility of pln in accordance with prevailing laws and under provisions to be regulated by the ministry of Finance (moF). the moF regulations are keenly awaited.

recent projectsthere has been a recent surge of ipp activity with the cirebon and paiton 3 projects reaching financial close (explained below). the two projects benefited from JBic financing under the JBic overseas investment loan programme. paiton 3 is the first project under the umbrella note of mutual understanding for promoting independent power projects signed by JBic and the moF in 2006. JBic has committed to financing up to us$5 billion worth of infrastructure projects in indonesia.



Electricity

in august 2007 a consortium of marubeni corporation, Korea midland power co., ltd, pt. tripatra Engineers and constructors, and samtan co., ltd signed a 30-year ppa with pln for a 660 mW power plant to be built, owned and operated in the cirebon area in West Java. the consortium submitted the lowest tariff, which was 4.363 cents per kWh. this is the first ppa for a large scale ipp to be signed since the asian financial crisis of the late 1990s. the project is a coal-fired project utilising super-critical boiler technology at an expected cost of us$750 million. the project is already under construction utilising sponsors equity.

the cirebon project reached financial close in march 2010 on the us$595 million debt led by JBic and Korea Eximbank, alongside commercial banks Btmu, smBc, ing and mizuho. JBic and Korea Eximbank each lent directly as well as providing political risk cover in support of the commercial debt.

the consortium of tokyo Electric power company, ipm Eagle (a mitsui, international power joint venture), mitsui & co, international power and Batu hitam perkasa is undertaking a us$1.519 billion expansion of the paiton project (known as paiton 3). the 30-year ppa was signed with pln in august 2008. the paiton 3 project includes a single 815 mW super-critical coal-fired unit, which would be located within the existing paiton complex, and is expected to be fully operational in 2012.

paiton 3 also reached financial close in march 2010 on the us$1.215 billion debt for the project. the financing consists of a JBic direct loan of us$729 million along side us$486 million of commercial debt from a club of eight, mostly Japanese and French, banks. the commercial debt is covered by an extended political risk guarantee from JBic. loan tenor is 18 years. commentators describe the project as being more akin to the first set of ipps awarded in the 1990s given that it is an expansion on an existing project, as well as benefiting from the gois guarantee of plns obligations.

pln prequalified bidders for the proposed super-critical or ultra-super-critical coal-fired central Java ipp to be located in pemalang in november 2009. the project will have a capacity of up to 2 x 800 mW and is to be carried out on a Boo basis. the bidders are expected to complete the associated transmission project and acquire the land for the project and the transmission line. the prequalified consortia consist of china shenhua Energy company; china national technical import-Export corp and guandong yudean; gdF suez and J-power; Korea Electric power company; marubeni corporation; mitsubishi corporation; and mitsui and international power. the project is expected to begin construction in 2011 and be operational by 2014.

in late 2008 pln also signed a ppa with sumitomo corporation, through its wholly-owned unit pt central Jawa power, for the tanjung Jati B expansion project. the expansion will take the coal-fired project to a total of 2,640 mW from 1,320 mW at present. the investment is expected to be around us$1.2-1.5 billion, which will be largely funded by project financing from JBic and commercial banks. the ipp will sell electricity to pln at the price of 4.3 cents per kWh.



Fast Track Programme first phase

in 2006 the goi introduced the first phase of the Fast track programme to add 10,000 mW of generating capacity from new coal-fired power plants. the programme consists of ten projects, with a total of 7,460 mW, in Java, and another 23 projects with a total of 2,513 mW outside Java island.

much of the programme has been implemented by pln using chinese contractors and equipment suppliers, with chinese export finance and domestic loans. pln also utilised the proceeds of a us$1 billion international bond issue in 2006. see the table below:

Table: Fast Track Programme first phase lending programme

Location Capacity (MW) Lender Debt (US$)

pelabuhan ratu, West Java 1,050 china Exim 481

teluk naga, Banten 1,050

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