2025, Indonesia’s primary energy mix should contain 33% coal, 30% natural gas, 20% crude oil, 5% each of biofuels, geothermal and other renewable sources, and 2% liquid coal.
CALLING THE SHOTS: Created in 2001 to take over the role of regulator from state-owned oil and gas company Pertamina when it was incorporated as an limited liability company, the Executive Agency for Upstream Oil and Gas Activity (BPMIGAS) is in charge of supervising and establishing cooperation contracts or production sharing contracts (PSCs) between the government and oil and gas production contractors. Although the MEMR is the body responsible for entering into production-sharing contracts (PSCs) with oil companies, it falls upon BPMIGAS to manage and implement the agreements as well as serve as the upstream regulator.
Because many of the larger international oil companies such as ConocoPhillips and ExxonMobil tend to shun many of the smaller, lower-production oil and gas fields in favour of bigger game, BPMIGAS has been forced to set its sights beyond the major players and pursue smaller companies in its efforts to exploit these less plentiful reserves.
The increased efforts by the government to boost hydrocarbons production in recent years have been enough to interest an array of oil and gas companies, as noted in the number of production contracts signed. In the three years from 2008, an average of 29.67 contracts were signed each year, a significant improvement over the previous three-year periods from 2005-07 and 2002-04, which averaged 18.67 and 11 contracts per year, respectively. Yet despite this general upward trend, only 21 contracts were signed in 2010, a decrease from 34 in each of the previous two years.
However, the body will have its hands full in the coming years and tens of existing production contracts are due to expire by 2020. One of the most crucial of these is the Mahakam Block, which will After years of declining production and investment in Indonesia’s crucial oil and gas sector, a combination of new exploration contracts, renewed progress on developing potentially vast new offshore reserves, and continued acquisitions by the state oil and gas company are lending a more positive outlook to the country’s hydrocarbons segment. Meanwhile, the future looks promising in the electricity segment as the country rushes ahead with its plans to add more than 30 GW of new energy generation capacity before the end of the decade.
NUMBERS GAME: Crude oil and condensate production dropped off at an average rate of 4.1% per year from 2000 to 2010. This decline in production, combined with growing consumption, pushed Indonesia into the net oil importer column in 2004. The silver lining for the country’s hydrocarbons sector can be found in the growth of natural gas production, which has taken some of the edge off falling petroleum output and will undoubtedly be a source of future success in the sector. Although its contribution towards the country’s coffers has dropped off in recent years, falling from 21.65% of government revenue in 2008 to a projected 13.4% in 2011, according to data from the Ministry of Finance, the oil and gas sector remains an important contributor to the nation’s economy. Indonesia was still very much dependent on hydrocarbons for its primary energy needs, accounting for 95.4% of the total in 2010, according to statistics from the Ministry of Energy and Mineral Resources (MEMR). Petroleum held the top spot, making up 43.9% of total production, followed by coal (30.7%) and natural gas (21%), with new and renewable energy sources accounting for the remaining 4.4%. This ratio is expected to undergo a substantial transformation over the next 15 years, with the county’s National Energy Policy for 2025 calling for a dramatic shift away from hydrocarbons and oil in particular. Upon completion of the policy period in expire in 2017 with future control of the country’s largest gas block currently being contested by both incumbent Total and state champion Pertamina.
In addition to Mahakam, 18 more contracts will terminate between 2010 and 2020, according to BPMIGAS, including the Sanga Sanga block in East Kalimantan, currently operated by Vico Indonesia and the South Natuna Sea Block B in the Riau Islands currently operated by ConocoPhillips Indonesia.
OIL: Indonesia had a total of 0.3% (4.2bn barrels) of the world’s proven oil reserves in 2010, according to the “BP Statistical Review of World Energy” published in June 2011. Additionally, BPMIGAS has estimated that proven and unproven reserves will amount to 7.56bn barrels at the end of 2011.
However, production of crude oil has been on the decline since the 1970s. More recently, national output decreased to 945,000 barrels per day (bpd) in 2010, slightly lower than 2009 levels of 979,000 bpd, but representing a more significant decline from 2001 production levels, which reached 1.34m bpd, according to BPMIGAS data. As a result, new exploration and production operations are moving toward the east of the country in deeper areas where extraction is more expensive.
As of December 2010 Chevron Pacific Indonesia was the single largest major producer of crude oil in the country, accounting for 43% of total production as a result of controlling many of the country’s most productive oil fields. State energy champion Pertamina ranked second with 23%, followed by PetroChina International and Total E&P Indonesia with 8% each; ConocoPhillips Indonesia produced 7% of the total; China National Offshore Oil Corporation (CNOOC) had 5%; and four other companies combining for the final 14%.
The country’s most productive oil fields are situated to the East of the island of Sumatra and include the Minas and Duri fields (both operated by Chevron).
In operation since the 1950s, these historically productive fields are now in decline and require enhanced recovery techniques to maintain output.
One existing project bucking this trend and gearing up for increased production in late 2011 was the Bany Urip field in East Java’s Cepu Block. A joint venture between ExxonMobil’s subsidiary Mobil Cepu, with 45% ownership; Pertamina, also with 45%; and four local government companies combining to have 10% ownership, Banyu Urip was awarded the first of five engineering, procurement and construction (EPC) contracts totalling $1.3bn for the development in August 2011.
Construction and development are expected to take 36 months, after which the full field is targeted to produce approximately 165,000 bpd. Infrastructure for the project will include 49 wells on three pads, a central processing facility, 95 km of pipeline, and a 1.7m-barrel capacity floating storage and offloading barge. The field first began producing in 2009.
In order to make up this shortfall between consumption and production, Indonesia has redoubled efforts in recent years to seek out new sources of energy. This is being accomplished by facilitating the development of domestic reserves by foreign oil and gas contractors as well as through a massive campaign by state oil and gas company Pertamina to secure new supplies both at home and abroad.
NEW PRODUCTION: Indonesia took another step toward boosting future domestic production capacity when BPMIGAS awarded 11 new PSCs to oil and gas contractors in November 2011. According to the terms of contract made public by the MEMR, the contractors paid a combined signing bonus of $36.08m to the government and have committed to paying another $201.3m for exploration activities over the next three years. These efforts will include geological and geophysical (G&G) studies, a 3850-km 2D seismic survey, a 1730-sq-km 3D seismic survey and the drilling of nine exploratory wells.
Four new working areas were also awarded in November 2011 as part of first phase of the oil and gas working area tender of 2011. The blocks and respective winning firms were the Offshore Timor Sea I, which will be explored by Hess; Halmahera II won by a consortium of Niko Resources Limited and Statoil; and West Aru blocks 1 and 2 contracted to BP Exploration Indonesia. Terms of the contract included winning companies paying a combined signing bonus of $19.35m to the government as well as commitments to invest $64.5m in exploratory activities during the first three years. These include a G&G survey, a 7500-km 2D seismic survey and a 5000-sq-km 3D seismic survey.
There are several large blocks with potentially substantial reserves. These include the East Natuna Block (formerly known as the Natuna D-Alpha Block), which is currently in the very early stages of development by French firm Total, Malaysia’s Petronas, the US’s ExxonMobil and Pertamina.
Additionally, there are the offshore Mahakam and Sebuku Blocks run by Total east of Kalimantan. Following the general trend of hydrocarbons production in the country, most of these large new fields contain primarily natural gas rather than crude oil.
HEAD OF STATE: Fuelled by a war chest of some Rp10.2trn ($1.2bn), state-owned Pertamina has embarked on an aggressive policy of expansion and acquisition by buying up oil and gas extraction rights from a number of different international operators in recent years.
As a result of this strategy, production of both crude oil and natural gas has increased substantially for the company over the course of the past five years. Crude oil output hit a total of 70.01m barrels in 2010, up from just 48.6m barrels in 2006 and 64.4m barrels in 2009. Pertamina’s net profits for 2010 came to Rp16.78trn ($2bn), up 3.5% from the Rp16.2trn ($1.9bn) recorded the previous year.
The company’s upstream activities are primarily carried out through its stable of subsidiaries including Pertamina EP (PEP), Pertamina Hulu Energi (PHE), PEP Randugunting and PEP Cepe. PEP’s primary responsibilities are to manage exploration and production fields within the country, while PHE is in charge of managing the company’s overseas production fields as well as some of the newer domestic production acquired after 2001. Support services, including exploration, are also carried out by Pertamina offshoots such as Pertamina Drilling Services (PDSI) and Elnusa.
Pertamina upped its stake in the West Madura Offshore Block in May 2011 – to 80% from its previous share of 50% – after the original 30-year production contract expired May 7. Under the initial agreement, Pertamina held a 50% share, with China’s CNOOC taking 25% and Kodeco of South Korea holding a 25% share. Under the new ownership structure, Kodeco retains the remaining 20% stake.
In September Pertamina subsidiary PHE purchased the oil and gas interests of Japanese company Inpex Corporation in the Offshore North-west Java Block (ONWJ), in which it held a 7.25% stake and the Offshore South-east Sumatra Block (OSSB), in which it held a 13% share. Combined with the 46% of the ONWJ purchased from BP West Java in June 2009 for $280m, Pertamina now owns 53.25% of shares of the block.
The ONWJ concession encompasses a total of 8300 sq km just offshore of West Java and includes 314 producing wells, 218 offshore structures and 1250 km of pipelines producing approximately 220m cu feet of natural gas and 28,000 bpd of oil. Pertamina’s share of offtake for the OSSB amounts to 5200 barrels of oil and 9m cu feet of gas per day.
CROSSING BORDERS: The company is looking to compete with oil and gas giants abroad, having expanded its reach into numerous exploration and production projects around the world over the course of the past decade. Overtures into foreign markets began in 2002 with Pertamina’s entrance into joint ventures in both Vietnam and Iraq. These movements were followed in rapid succession by forays into neighbouring Malaysia in 2005, Libya in 2006, Sudan in 2007, and Qatar and Australia in 2009.
Pertamina’s overseas conquests began paying dividends in 2010, when the offshore SK-305 Block located in Malaysia became Pertamina’s first overseas asset to begin actively producing. The company owns a 30% share in the project, with Petronas Carigali of Malaysia and PetroVietnam making up the rest of the ownership structure. Other international Pertamina blocks in the exploratory stages of development include the onshore Block 3WD in Iraq’s West Desert region, in which the company has 100% ownership; a 15% stake in the offshore Block 13 in Sudan along with partners China National Petroleum Company (CNCP), Sudapet, Dindir Petroleum International, Express Petroleum and Gas Company and Africa Energy; a 100% share in the 17-3 and 123-3 Blocks located offshore and onshore, respectively, in Libya; a 25% share in Qatar’s offshore Block 3 along with Wintershall, Cosmo Energy and E&D; a 10% share in offshore Vietnamese Blocks 10 and 11.1 in conjunction with Petronas Carigali, PetroVietnam and Quad Energy; and a 10% stake in Australia’s Block Basker, Manta, Gummy (BMG) along with Anzon Australia, Beach Petroleum, CIECO Exploration and Production, and Sojitz Energy Australia.
As the company continues to increase its reserves and production capacity, it also has its eye on bigger game – namely Indonesia’s single most productive gas block. The Mahakam Block located in East Kalimantan produces 2.5bn cu feet of gas per day and 9300 barrels of oil and condensate per day via the Tunu, Tambora, Peciko, Sisi and Nubi fields.
Apart from the size of reserves, the block is attractive to Pertamina because its current operating contract with French energy giant Total (working in conjunction with the Japanese Inpex Corporation) is set to expire in 2017 according to the original arrangement, first inked in 1967 and extended in 1997. Pertamina and the Indonesian government have made no secret of their desire to take control of the block and have been negotiating with Total for control of the project for years.
The initial proposal by Pertamina involved purchasing a 15% stake in the operation in 2011 followed by a gradual increase in share up to 45% by the time the contract expires in 2017, though the implementation of this plan was not yet successful at the time of print. As progress in negotiations has slowed significantly, the company has also tabled a second alternative proposal in which Pertamina would acquire a 51% stake in 2017. Even these substantial acquisitions do not tell the full story of the company’s aggressive tactics in securing new energy supplies. Pertamina has also failed in several domestic takeover bids, including trying to purchase a 10-15% participating interest in the Masela Block, as well as attempt at a 27.9% stake in Medco via its majority stakeholder Encore International.
REFINING: Indonesia’s refining capacity was just over 1m bpd at the end of 2010 and refining is carried out almost exclusively by Pertamina’s domestic facilities, mostly located on Java and Sumatra. With a capacity of 348,000 bpd, the Cilacap refinery is Pertamina’s largest facility, followed by Balikpapan with a capacity of 260,000 bpd, the Plaju and Dumai refineries with capacities of 127,000 bpd each, Bolongan with 125,000 bpd and Tuban with 100,000 bpd. The refineries of Sungai Pakning, Kasim, TWU and Cepu have capacities of 50,000 bpd or less.
SEEKING PARTNERSHIPS: With only around 70% of domestic demand met by the country’s existing capacity, Pertamina has also been looking for partners with which to expand current facilities or build new refineries. In August 2010 the company signed a deal with the Kuwait Petroleum Corporation to examine the feasibility of expanding the existing Bolongan site and has also been in negotiations with Saudi Aramco regarding the construction of a new 200,000-300,000-bpd refinery in East Java. As with these first two projects, plans for another 300, 000-bpd refinery located in Banten Bay have stalled due to the fact that low margins on refining projects make it difficult for them to be economically viable.
In the short term, any refining capacity increases will have to come in the form of expansion projects at existing refineries, such as Pertamina’s upgrade at the Cilicap facility, which is expected to boost output by some 62,000 bpd by 2014. The Balikpapan refinery is in the midst of a $1.7bn upgrade, which is intended to boost capacity by 40,000 bpd by 2014.
POWER TO THE PEOPLE: As of late 2010 Indonesia had a total installed electricity capacity of approximately 31 GW composed primarily (87%) of hydrocarbons generation including coal, oil and gas. Another 8% of capacity was provided by hydropower plants, with the remaining 5% supplied by geothermal and other assorted renewable sources.
At the same time, electricity consumption has also been climbing, growing from 120,162 GWh in 2004 to 169,786 GWh by 2010. Of the 2010 total, 131,710 GWh were produced by PLN assets, with IPP and PPU generators accounting for the remaining 30,076 GWh. In terms of distribution, residential household use accounted for the greatest consumption with 59,825 GWh or 35.2% of the total. This was followed by industrial consumption with 50,985 GWh (30% of the total), commercial with 22,157 GWh (13%), and public with 9330 GWh (5.5%).
Going forward the government is projecting electricity demand to increase by 9.5% annually for the next five years. A substantial portion of the growing demand will come from the continued electrification as traditional wood, charcoal and kerosene energy sources used for cooking, heating and light are replaced by electricity. According to PLN, national electrification rates have increased from 57% in 2000 to just over 67% in 2010 and are projected to hit 93% by 2025. Considering that only 8% of the population had access to electricity as late as 1980, this is an impressive improvement, though around 80m Indonesians are still without power at home.
In order to meet this demand, the government plans to increase domestic total power generation capacity to approximately 85,804 MW in 2019, according to the country’s supply plan for 2010-19 established by PLN in 2010. This plan relies on strong initial growth of cheap coal-fired power generation, which is supposed to increase from generating 44% of the nation’s total power in 2010 to around 52% by 2019, with later additions of renewable and gas-powered sources at the expense of petroleum fuel. Also by 2019, electricity generation is to be powered 51.8% by coal, 25.1% by gas, 10.7% by hydro, 8.3% by geothermal, 3.4% by diesel and 0.7% by other forms.
“The development of geothermal and liquefied natural gas (LNG) plants has the potential to be an extremely viable option for the electrification of regional communities,” said Handry Satriago, the president of GE Indonesia.
Electricity prices in Indonesia are relatively high compared to other countries in the region, with industrial consumers paying an average of $0. 11-0.12 per KWh, while subsidised household rates are approximately $0.06 per KWh. These subsidies cost the government roughly $5.5bn annually, according to the Indonesian Department of Finance (APBN).
SUPERPOWER: The power sector is dominated by state-owned power utility PLN, which operates through a vertically integrated framework as a power transmission system operator and distributor as well as the largest single power generator. A new energy law introduced in 2009 legally terminated PLN’s distribution monopoly, although no real challengers had entered the market as of late 2011 and PLN has retained its control over the sector.
In terms of generation, PLN accounts for approximately 86% of all power generation in the country with a total installed capacity of 26,895 MW in 2010. Coal-fired thermal power plants accounted for roughly one-third of its total power capacity with 9451 MW, according to company reports. This was followed by combined-cycle power plants with 6951 MW, hydropower plants with 3522 MW, diesel-fired thermal power plants (3268 MW), natural gas-powered thermal power plants (3223 MW) and geothermal power plants (438.75 MW). The remaining generation is filled by an oil-and-gas-fired power plant of 38.84 MW, as well as small-scale wind projects of 0.19 MW and 0.34 MW.
ON TRACK: In order to meet the power consumption demands of a large and rapidly growing population, the government outlined an ambitious multi-phase “fast-track” programme which will feed around 30 GW of new installed power into the country’s grid by 2020. Initiated in 2006 and amended in 2009, the first phase of the programme mandated the construction of 42 coal-fired power plants with an aggregate capacity of nearly 10,000 MW by 2012. By the end of 2011, 5830 MW had been installed, with another 2500 MW expected to be completed in 2012 and a final 1400 MW in 2013.
Phase two of the plan is decidedly more green-oriented, with 55% of the total new production slated for renewable power generation. Spanning the years 2010-14, the programme is targeting the installation of 10,153 MW, consisting of 3977 MW of geothermal production (39%), 3312 MW coal-powered production (33%), 1560 MW of combined-cycle production (15%), 1204 MW of hydropower production (12%) and 100 MW of gas turbine production (1%). Total investments are expected to reach $16.44bn, $11.11bn of which is earmarked for private sector development through IPPs.
A third and as of yet unrealised fast-track scheme is also planned to take the country up to the year 2020. Although the exact make up of the next phase of development has not been made public, PLN’s director for planning and technology, Nasri Sebayang, told the local press in November 2011 that the next instalment would focus on hydropower, comprising up to 5600 MW of new generation capacity by 2020.
OUTLOOK: Although the problems of declining domestic hydrocarbons production and increasing consumption will not ease Indonesia’s growing import requirements in the short term, the nation is taking strong measures to steady its course in the future. Commitments to diversify primary energy sources away from petroleum and into domestically abundant resources including coal and renewables will help in this effort, as will the exploitation of potentially vast gas fields in the medium and long term.
The country’s electricity sector is in for rapid expansion over the next 10 years, which will also provide ample opportunities for private investment, particularly in the areas of renewable energy. Indeed, many industry players see private sector participation as key for the future success of the sector. “Local banks cannot provide the long-term capital necessary for large-scale infrastructure projects,” Kian Min Low, the president-director of East Java-based Paiton Energy, told OBG. “As a result international financing is required, but without adequate government guarantees that can be extremely difficult to obtain.” The government is working to clarify its regulatory framework, and it is hoped that these proceedings will result in a more stable climate for investment.
You have reached the limit of premium articles you can view for free.
Choose from the options below to purchase print or digital editions of our Reports. You can also purchase a website subscription giving you unlimited access to all of our Reports online for 12 months.
If you have already purchased this Report or have a website subscription, please login to continue.