Endowed with substantial energy reserves spread across its vast territory, Indonesia has been among the region’s largest producers and exporters of fossil fuels for decades. While this trend shows little sign of changing, the sector is in the midst of a dramatic shift in the composition of its resources. With crude production in decline, natural gas is taking on an increasingly important role both in terms of exports and domestic use.

Coal production still dominates power generation and export revenue, although changing global markets and the progression of green technologies are leading to a new era of renewable energy. Through this evolution, the sector has remained a crucial contributor to government export revenues, accounting for more than one-fifth, or Rp272trn ($27.2bn), of all domestic revenue in 2011, according to Ministry of Finance data.

DECLINING PRODUCTION: Maturing production fields and recent declines in new exploration activity have contributed to an inexorable decline in oil production, which dipped to 942,000 barrels per day (bpd) in 2011, 5.6% off the 2010 pace and 32.2% down from the 1.39m bpd in 2001. The country became a net importer in 2003 when domestic consumption of 1.21m bpd exceeded Indonesia’s output of 1.18m bpd for the first time. These steady declines have been exacerbated by an increasing appetite for crude oil; the demand for this has grown from 1.14m bpd in 2001 to 1.43m bpd in 2011. Due to insufficient enhanced oil recovery techniques in legacy assets and the lack of exploitation of unconventional resources, imports must pick up the slack. Refinery capacity has been static recently and totalled 1.14m bpd in 2011. In terms of reserves, Indonesia possessed 4bn barrels of oil at the end of 2011 (down from 5.1bn in 2001), according to “BP’s Statistical Review of World Energy 2012”.

Foreign exploration and production companies are the primary participants in the oil and gas sector along with state-owned energy giant Pertamina and Medco Energi, the country’s largest-listed oil company. As of March 2012, Chevron Pacific Indonesia was responsible for producing 47% of the oil in the country, with Pertamina the second-largest operator with a 17% share. Other prominent players in the market include Total E&P Indonesia (10% share), Conoco Phillips Indonesia (7% share), Chevron Pacific Indonesia (4% share), CNOOC (4% share), PHE-ONWJ (4% share), Mobile Cepu (3% share) and PHE – West Madura Offshore (2% share), along with China’s PetroChina (2% share), according to data from former regulator BP Migas.

NEW HOPE: In the search to discover and develop new reserves of hydrocarbons, oil and gas companies have been casting an ever wider net in the face of higher oil prices and dwindling supplies. The number of exploratory working areas continues to grow, reaching 172 in 2011 after hitting 155 in 2010 and 141 in 2009, according to BP Migas. While not all of these surveys have proven fruitful, the number of viable working areas has crept incrementally upwards from 50 in 2002 to 73 in 2011. Despite an increase in conventional wildcat drilling that same year, particularly in deepwater and frontier areas including Tarakan, Makassar, Sema and the Arafura Sea, the results have by and large been unsuccessful. “Indonesia’s eastern areas around Papua New Guinea are completely unexplored, and this is the area into which all the big companies are moving,” Budiman Parhusip, president director of energy company Rukun Raharja, told OBG. “This is where the future growth opportunities for oil and gas lie.”

LOOKING AHEAD: Spurred on by new incentives such as more commercially favourable production splits and direct bidding options for new contracts in addition to the standard tendering process, upstream oil and gas investments continued to grow in 2011.

According to the Ministry of Energy and Mineral Resources (MEMR) data, expenditures in the sector totalled some $13.7bn in 2011, compared to $11.03bn the previous year. These included outlays of $9.1bn in production investments, $3.06bn in development, $920m for administration and $631m in exploration investments. Some believe that these investments must be increased again. “The government needs to focus on further developing and investing in the oil and gas sector to solve this shortage or else the country may find serious difficulties in achieving its ambitious growth targets in the next decade,” said Djadja Sudjadi, the president director of Khatulistiwa Raya Energy, an independent oil trading company and holding company for Khatulistiwa Resources.

A number of new deals were signed in 2012, including seven oil and gas cooperation contracts (kontrak kerja sama, KKS) by October 2012. Among these were four direct offer contracts for coal bed methane (two in central Kalimantan and one each in East Kalimantan and south Sumatra) and three regular bidding contracts for oil and gas concessions (in East Kalimantan, Bengkulu and Riau Islands). Then regulator BP Migas also launched a second phase of bidding in October 2012, offering up another 23 oil and gas blocks.

PROS AND CONS: Much of any oil production increase falls on the development of the Cepu Block located in East Java. A joint venture between ExxonMobil (45%), Pertamina (45%) and Cepu Block Cooperation Body (10%), the project is expected to reach a peak of some 165,000 bpd in the third quarter of 2014 – amounting to nearly 20% of the total 2011 output. The block also contains an estimated 1.3 tcf of natural gas within the Jambaran field. While optimism for Cepu’s future remains high, the venture got off to a somewhat rocky start with permit delays slowing down the construction of infrastructure. The project is currently operating at a modest output of 24,000 bpd. Tapping into one of the country’s largest unexploited reserves in the Banyu Urip field – estimated to hold 450m barrels – the $1.3bn project will require the construction of 49 oil wells, a 95-km pipeline to deliver the oil to offshore storage facilities, a floating storage facility and an offloading facility with the capacity for 1.7m barrels.

KEEPING THE LIGHTS ON: With Indonesia’s 248.6m inhabitants scattered across an archipelago encompassing 1.9m sq km of land area and located within 7.9m sq km of maritime territory, meeting the growing power requirements has always proven to be a challenging task. The government has utilised its substantial thermal coal reserves supplemented by other hydrocarbon and renewable sources to provide a stable and relatively inexpensive fuel supply for its national power infrastructure. In 2011 42.39% of all power generated was derived from coal-fired plants, with fuel oil and natural gas contributing 24.78% and 20.86% to the total, respectively, according to national energy company Perusahaan Listrik Negara (PLN). The remaining 11.97% was fuelled by renewable energy sources – 6.77% from hydropower and 5.20% from geothermal sources. This mix could change in the coming years, however. “We anticipate a falling demand for coal next year, which should, in my opinion, encourage miners to become more engaged in the power generation business,” said Henry Halomoan Sitanggang, the president director of Exploitasi Energi Indonesia, which is involved in coal mining and related activities. “The coal mining business model must shift towards the development of the energy sector.”

READY RESPONSE: As of 2012, combined installed capacity totalled 38,063 MW, according to the MEMR Directorate of Electricity. The vertically integrated state-run PLN owned 76% of this, with independent power producers (IPP) operating another 20% of capacity and public-private partnerships (PPP) making up the final 4%. Production of electric power in 2011 totalled 183,421 GWh, an increase of 8% over the 169,786 GWh output of the previous year, according to data from PLN. The company continued to produce the majority of the nation’s electricity in 2011, accounting for 128,853 GWh; rented power stations added another 13,885 GWh of this and power purchased from independent producers totalled 40,682 GWh. Output from rented power plants spiked 69% in 2011 as a result of PLN efforts to avert rolling power outages, while PLN-produced and independently produced generation experienced modest increases of 4% and 7%, respectively. Rented power plants, most of which are powered by fuel oil, were utilised in a greater capacity than projected, due to various construction delays in a number of coal-fired power stations and a shortage of fuel for natural gas-fired power plants.

NEW PROGRAMMES: The future growth of installed capacity will be dictated by the government’s twin 10,000-MW fast-track programmes (FTP-1 and FTP-2), which were created with the intention of bringing an additional 20 GW of installed capacity on-line by 2018. In doing so, the government hopes to achieve such economic objectives as reducing domestic oil consumption and imports, decreasing fuel costs for power generation and cutting back on electricity production costs, thus reducing power subsidies and eliminating electricity shortages.

Initiated in 2007, FTP-1 calls for the construction of 37 new coal-fired power plants with a combined total installed capacity of 9961 MW across the country by 2011 (later revised to 2014). The bulk of these will service the more populated islands of Java and Bali through the addition of 7490 MW spread across 10 separate projects. These will be complemented by 10 more power plants located in Sumatra totalling 1431 MW along with five projects in Kalimantan (625 MW in total), four each in Sulawesi (220 MW in total) and Nusa Tenggara (117 MW in total), and two each in Maluku (44 MW in total) and Papua (34 MW in total). Although delays have led to only around 45% of projects being on-line as of July 2012, the total number of new plants brought into operation in 2011 and 2012 was still impressive. These include the West Java 1 power plant in Indramayu with an installed capacity of 3 x 330 MW, the Banten 1 power plant in Suralaya with an installed capacity of 625 MW, the Tanjung Jati B Unit 3 with an installed capacity of 710 MW and the Banten 3 power plant located at Teluk Naga with a capacity of 3 x 315 MW.

CHANGING IT UP: The FTP-2 programme was launched in 2010 with a more diversified approach of bolstering power production across a range of technologies with greater participation from IPPs. This includes a heavy emphasis on alternative fuel sources, with 4925 MW of new geothermal power (49% of the total), 1753 MW of hydropower generation, 3025 MW of coal-fired power and 280 MW of gas turbine power plant capacity. New power plants scheduled to come on-line in 2013 as part of the FTP-2 are expected to add 294 MW of installed capacity to the national grid and include the Patuha geothermal power plant (60 MW of capacity), Bangkanai power plant (140 MW of capacity) and the steam-powered plants of Lombok (50 MW of capacity), Bau-Bau (20 MW of capacity), Ketapang (10 MW of capacity) and Merak (14 MW of capacity).

OUT WITH THE OLD: Indonesia’s power generation mix is expected to change going forward, according to PLN projections, so that by 2020, 64% of all electricity produced will come from coal, 17% from natural gas, 12% from geothermal, 6% from hydropower and only 1% from fuel oil, which is being phased out. In total, the national electricity general plan calls for an additional installed capacity of 156 GW by 2029 – adding an average of 7.8 GW per year. PLN will need to mobilise vast financial resources to achieve these ambitious growth targets. Based on estimates of PLN’s Electricity Supply Business Plan for 2011 to 2020, the power company will need to pour some $60.5bn into infrastructure projects. When taking into account total investments needed for the sector, including IPPs as well as transmission outlays, this figure balloons to $227.1bn by 2025.

PRIVATE SECTOR: Although private generation only makes up a fifth of all power produced in the country, there is a large movement to shifting more of this burden away from the state and onto the private sector. With state budgets stretched thin from growing energy subsidies as well as their own power infrastructure projects, increased private sector investment in electricity is in the best interest of both parties.

As of 2011 there were 28 IPPs operating in Indonesia, contributing a combined total of 5389 MW of installed capacity to the national grid, according to PLN. The independent companies run the gamut of size and technology with installed capacities ranging from 3 MW to 1230 MW powered by a mix of hydro, coal, gas and geothermal fuel sources.

While private investment under the FTP-1 was mostly limited to participation in energy performance contracts, the FTP-2 provides private companies many more opportunities for direct ownership and participation. About 63% of all projects are designated for IPP development, totalling 6290 MW, and leaving just over a third (37%) of the new generation capacity, or 3757 MW, to PLN. Many of the ventures are already proceeding at various stages of development, with 16 new power plants (totalling 4110 MW) either undergoing construction or in the financing stage at the end of 2011.

In addition to IPP projects that are 100% owned, operated and financed by private companies, regulations allow for PPP projects for which the government uses a bidding process and may provide either state support or a guarantee to the winning company. A deal for one such large-scale PPP project was signed by PLN and private power developer Bhimasena Power Indonesia in October 2011 for a new 2 x 1000 MW coal-fired thermal power plant to be built in the Central Java Province. Estimated to cost approximately Rp30trn ($3bn), the massive project will be operated on a 25-year build-own-operate-transfer contract by the winning consortium of J-Power Consortium, Ithocu and Adaro and is planned to come on-line by 2016.

DELAYS: While these successes paint a sunny picture of the private sector, growth could be much stronger if certain tweaks were made to the business environment. The primary drag on the sector has been the inability of some IPPs to obtain funding for their projects, leading to delay in the construction of new power plants. The most common cause of funding problems cited by these private companies is the lack of governmental guarantee or supporting policies for IPP implementation, and the legal and regulatory complications arising from the overlapping jurisdictions of the numerous state entities involved in the sector, including the Ministry of Finance, MEMR, Ministry of State-Owned Enterprises, Ministry of National Planning and Development/BAPPENAS, and other stakeholders.

CONSUMPTION: The ongoing flurry of new power generation capacity is a direct result of Indonesia’s high demand for electricity. Power usage has increased so rapidly that in 2011 PLN had to employ more costly fuel oil generation as a measure of last resort in order to prevent rolling blackouts in some areas of the country. According to PLN, this shortfall is due to factors such as the company’s under-investment in growth-sustaining measures and reductions in equipment performance from lack of maintenance.

Electricity sales have increased annually by an average rate of 8.31%, from 121,246 GWh in 2007 to 157,993 GWh by 2011, and are projected to continue growing by an average annual rate of 8.5% through 2020, according to data from PLN. Peak loads are similarly expected to grow at 8.4% on average per annum, from 27,792 MW in 2011 to 55,053 MW by 2020 as the number of customers increases by 2.7m per year and the electrification ratio expands to 94.4% of the population.

LOOKING AHEAD: In addition to the natural growth in consumption as the population increases, PLN must take into account the planned expansion of Indonesia’s heavy industrial sector. Industries such as smelting, which is projected to grow at a rapid pace due to government policies requiring domestic processing of raw materials, need a large and dependable power supply. The transmission system operator is planning to accommodate these new projects, and as a result PLN signed three memoranda of understanding (MoU) for power distribution cooperation in September 2012 alone. According to the terms of the deal PLN has agreed to supply 220 MW, 120 MW and 90 MW, to the three separate smelting operations of Central Omega Resources in Sulawesi and East Java, Bakti Bumi Sulawesi in Bantaeng, South Sulawesi, and Bukaka Teknik Utama in Palopo, Sulawesi, respectively.

Industrial customers consumed 54,725 GWh of electricity in 2011, second only to household consumers at 65,111 GWh, according to PLN data. Businesses accounted for an additional 28,309 GWh and assorted customers made up the remaining 9848 GWh.

LINKING UP: In addition to its role as the nation’s single largest power producer, PLN acts as the transmission system operator and primary electricity distributor. In terms of total national electrification, PLN data showed an increase from 67% in 2010 to some 74% by the end of 2011, while network losses decreased from 9.7% in 2010, to 9.41% by end-2011.

Apart from bolstering national infrastructure, the country has also taken strides to increase its interconnectivity with bordering nations. Recent efforts to improve cross-border power transportation capability include the signing of a MoU between PLN, its Malaysian counterpart Sarawak Energy and Indonesian coal mining company Bukit Asam to examine the potential of cross-border power transactions.

The deal’s main goal is to explore the feasibility of constructing a new mine-mouth coal-fired power plant located in Peranap approximately 250 km south-east of the town of Pekanbaru on the island of Sumatra. This would be operated by Bukit Asam with Malaysian national power operator Tenaga Nasional (TNB) lined up to purchase the offtake. The study will also investigate the connections and support infrastructure still needed, including an interconnection line from Telok Gong, Melaka to Garuda Sakti on Sumatra and the power plant to be constructed in Peranap.

UNDER THE SEA: To access the plentiful power supply in Sarawak, TNB will also have to finance and build a 275-KV undersea cable traversing the Strait of Melaka linking Melaka in Peninsular Malaysia to Sumatra at a projected cost of $378m. The total cost of the recent mine-mouth proposal (including a power plant and a transmission line) has been estimated at Rp7bn ($700,000). The crux of the concept comes from the two-way electricity exchange expected to start by 2017. To transfer excess electricity to Sumatra at night and Peninsular Malaysia by day, a second power plant must be constructed in Melaka that can also produce electricity at the same price as its Indonesian partner plant in order to be economically viable for both parties. This is not the case currently, and the future cost of fuel will be difficult to determine due to global energy prices and Malaysia’s heavily subsidised energy sector. The 2012 MoU comes on the heels of another interconnection cooperation deal to develop a new link in West Kalimantan that was signed in July 2011 by PLN and SEB.

Despite efforts to boost interconnectivity, Indonesia has also enacted legislation to place restrictions on cross-border power sales and purchases. As stipulated in government regulation no. 42/2012, sales by Indonesian companies may only be carried out if three criteria are met. First, the electricity needs of local and regional areas must be addressed; second, the selling price of electricity cannot include any subsidies; and third, the transaction must not interfere with the quality and reliability of local power supplies.

Similar measures have been enacted regarding purchases. These include requirements that power deals may be carried out only for the purpose of meeting the demand for local electric power, not have the potential to harm the interests of the state, do not neglect the development of domestic electricity supply and do not result in a dependency on electric power from abroad. Given the ambiguity and protectionist nature of some of these stipulations and the relatively low amounts of power able to be transported, it is unlikely that cross-border markets will significantly impact the country’s power structure in the near future.

ALTERNATIVE COSTS: After much debate, Indonesia’s well-established energy subsidisation policy should finally be revised to reduce costs that have been taking up increasingly alarming chunks of the nation’s budget. While raising petrol prices at the pump above $0.50 a litre would likely lead to uproar, the consequences of not doing so have become difficult to justify. The programme regularly accounts for a fifth of all government expenditure and is expected to exceed Rp300trn ($30bn) for 2012 – significantly higher than the Rp225trn ($22.5bn) allotted for energy subsidies in the year’s budget.

State oil and gas operator Pertamina, which is responsible for the distribution and sale of subsidised fuel through its public service obligation (PSO), also incurred losses in excess of Rp1trn ($100m) due to subsidisation costs exceeding the compensation granted in the government budget. Annual sales for the company amounted to 41.69m kilolitres (kl) of subsidised fuel and 22.91m kl of non-PSO fuel. Total subsidy reimbursement to Pertamina for these sales amounted to Rp156.52trn ($15.7bn), up 106% over the Rp75.98trn ($7.6bn) the previous year and accounting for 26.54% of the company’s total sales and other operating revenues. Electricity subsidies paid to state power provider PLN jumped from Rp58.11trn ($5.81bn) in 2010 to Rp93.18trn ($9.32bn) in 2011.

AUSTERITY: In order to cut back on costs, the government is planning to increase electricity tariffs by 15% starting in January 2013 in a move that is expected to shave off approximately Rp12trn ($1.2bn) from current subsidy payments. A similar measure for fuel subsidies was proposed back in April 2012 to increase fuel prices from Rp4500 ($0.45) a litre to Rp6000 ($0.60), but was subsequently nixed by lawmakers amid spirited public protests. The House of Representatives did manage to leave the door open to resume discussion of fuel price increases in 2013, however, by including a provision in the 2013 state budget law that allows energy prices to be adjusted in accordance with substantial deviations from key macroeconomic assumptions which affect government finances.

OUTLOOK: Indonesia’s oil and gas sector will remain a strong contributor to the country’s economy both in terms of export revenue through increasing shipments of natural gas as well as domestically through its taxation and production sharing agreements. Although the nation possesses substantial natural gas reserves and the sector may be capable of staving off further declines in crude production in the short term, the instability of the government’s regulatory regime is still the primary concern for investors. For the time being, the lure of the Indonesia’s lucrative hydrocarbons wealth is sufficient incentive to maintain investment in new exploration and production projects, but to continue sector growth the government may need to consider shoring up its regulatory framework to ensure lasting stability.