Indonesian energy report. Financial institutions Energy infrastructure and commodities Transport Technology

Indonesian energy report Financial institutions Energy infrastructure and commodities Transport Technology

Indonesian energy report A norton rose group guide AUGUST 2010

Norton Rose Group August 2010 Edition No. NR8180 08/10 The whole or extracts thereof may not be copied or reproduced without the publisher s 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, Indonesia s 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

Indonesian energy report 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 Indonesia s two largest oil fields the Minas and Duri fields where Chevron employs steam flooding techniques to enhance production. Indonesia s 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 stateowned 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 Asia s 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 world s third largest LNG exporter 08 Norton Rose Group

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 Chevron s Ganal-Rapak deepwater gas development, Pertamina s Natuna D-Alpha field and ConocoPhillips North Belut field development. Coal bed methane (CBM) offers huge potential to Indonesia given that it holds the world s 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 Indonesia s 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. Indonesia s 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 country s 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 PLN s monopoly over supply and distribution but does not go so far as to unbundle PLN s 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 Indonesia s 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. Norton Rose Group 09

Indonesian energy report 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. 10 Norton Rose Group

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 country s 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 Indonesia s 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 state s 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 Pertamina s 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. Norton Rose Group 11

Indonesian energy report BPMIGAS has succeeded to all of Pertamina s 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 BPMIGAS s roles is to select the representative to sell the GoI s 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 Pertamina s 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. 12 Norton Rose Group

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 Indonesia s largest oil producer and operates the Duri and Minas oil fields, which together account for more than 30 per cent of Indonesia s 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. ExxonMobil s 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. Norton Rose Group 13

Indonesian energy report 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 People s 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 Time limits 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. 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). 14 Norton Rose Group

Oil Key terms Relinquishment Performance bond Development plans, work programs and budgets 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. 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. 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 contractor s 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 GoI s 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 Decommissioning 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. 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. Norton Rose Group 15

Indonesian energy report Key terms Transfers Tax Bonus payments 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. Contractors are subject to income tax and such tax is maintained under a tax equalisation clause. 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. 16 Norton Rose Group

Oil Licensing rounds 2010 round Indonesia 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 round The GoI s 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 GoI s 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 Resource s 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. Norton Rose Group 17

Indonesian energy report 2008 round In 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 East Bula, offshore east Indonesia Awarded to Niko Resources and Black Gold Energy Halmahera Kofiau, offshore South Halmahera West Papua IV, offshore West Papua Andaman III, offshore North Sumatra West Glagah Kambuna, offshore North Sumatra Talisman Energy 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. Indonesia s 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 Indonesia s total oil production. 18 Norton Rose Group

Oil It is generally thought that all of Indonesia s 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. Cepu Indonesia s 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. Norton Rose Group 19

Indonesian energy report Duri Discovered in 1941, the Duri field is one of the world s 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 Duri s steamflood operations. Minas Minas, Chevron s 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 field s 13 zones. Chevron is carrying out a chemical injection project with the aim of boosting oil recovery. Bukit Tua Petronas 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. Mahakam Total 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. 20 Norton Rose Group

Oil Refining Despite liberalisation, Pertamina is still dominant in Indonesia s downstream sector. It operates all nine of Indonesia s 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. Indonesia s 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: Indonesia s largest refineries (by capacity) Location Capacity (bbl/d) Dumai, Central Sumatra 120,000 Musi, South Sumatra 16,200 30,000 30,000 35,000 16,000 Cilicap, Southern Java 118,000 230,000 Balikpapan, Kalimantan 60,000 200,000 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. Norton Rose Group 21

Indonesian energy report 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. 22 Norton Rose Group

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. Norton Rose Group 23

Indonesian energy report 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 Asia s 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. Indonesia s 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 GoI s 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 Indonesia s 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. 24 Norton Rose Group

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 General Indonesia 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-Rapak Chevron 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 Chevron s 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 Norton Rose Group 25

Indonesian energy report 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 block Pertamina 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 Mahakam Total 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 Belut ConocoPhillips 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). 26 Norton Rose Group