With an established reputation as an honest broker and investor in long-term strategic opportunities within South-east Asia, Brunei Darussalam has made a name for itself as a regional player. ASEAN itself has emerged as a major centre for activities in the upstream and downstream segments, with the Philippines, Myanmar, Malaysia and Thailand standing out as the most compelling cases.
Hopes of a path towards energy independence in the Philippines are gathering pace thanks to encouraging steps forward at the Malolos-1 onshore well in Cebu. Australian oil firm Gas2Grid said in July 2014 that it is in the process of applying to the Department of Energy (DoE) to increase production for a full appraisal of the field.
Early tests showed that the well is capable of producing 200 barrels per day (bpd) of crude, a level that couldn’t be maintained for short periods, according to the explorer. Thus far, estimates put total reserves at 20.4m barrels. But while the country’s offshore reserves are most often cited as the highest-potential energy reserves available, recent offshore developments have not been as promising. London-listed Dragon Oil confirmed in July 2014 that the Baragatan-1 offshore well in the Palawan basin, in which it has a 40% stake, was incapable of producing commercial hydrocarbons.
Previous testing at Malolos had shown that the field’s lower and upper oil-bearing sandstone areas were able to produce oil individually, but the well’s production rate was lower than hoped for. The company announced in June 2014 that measures to repair the pipeline had significantly improved the field’s sustained oil flow rate.
Although work on the field has been suspended while the company waits for final approval from the DoE, Dennis Morton, managing director at Gas2Grid, told local media in July 2014 that he expected the field to be able to produce at more commercial rates. “This is a resource well worth pursuing,” he said.
This is the first positive development since the DoE confirmed in January 2014 that Gas2Grid had found oil in the Malolos-1 fields. At the time, the firm estimated initial costs of the development to be between $500,000 and $1m. Despite efforts to develop renewable energy, the Philippines remains dependent on fossil fuels, with oil and mineral fuels accounting for 22% of imports between January and September 2013 and representing the third-largest category after raw materials and capital goods. Oil consumption increased 5.5% year-on-year to reach 298,000 bpd in 2013, according to BP’s “Statistical Review of World Energy 2014”. However, a lack of new production has led to decades of decline in annual domestic oil output, which stood at 8.57m barrels in 1979 but fell to less than 2m by 2012.
Exploring New Activities
The DoE reported that 1.44m barrels of oil were produced between January and September 2013, compared to 1.64m barrels for all of 2012, while five exploratory wells were drilled during 2013, including sites at Malampaya drilled by Shell Philippines Exploration and new wells at the Galoc offshore oilfield. Onshore developments included Malolos-1, as well as Duhat-2 in Onshore Leyte, which has been estimated to contain 88m barrels of oil – although safety concerns led Australia’s Otto Energy to abandon exploration in 2013.
New exploration has been a major government priority list. The DoE reported in its “2013 Energy Sector Achievement Report” that the country’s 16 sedimentary basins have a combined potential of 4.77bn barrels of fuel oil equivalent, or 689.8m tonnes of oil and gas reserves. In May 2014 the government launched a tender for exploration rights in 11 oil and gas blocks, with the majority of the blocks located near the main island of Luzon while one lies in a disputed area of the South China Sea. The DoE estimates that the area 7 block, located near Palawan, holds a resource potential of about 165m barrels of crude and 3.5trn standard cu feet (scf) of natural gas.
The Galoc field, located off the north-east coast of Palawan, remains the most productive reserve, with Otto Energy reporting the field produced 1.8m barrels in 2013. Production has been supplemented over the years by output from the Nido, Matinloc and North Matinloc fields, while Nido Petroleum announced in March 2014 that its revised estimate of proved developed reserves in Galoc had increased by 1.57m barrels, to 11m barrels in total.
A wave of energy exploration and extraction projects are expected to be rolled out in Indonesia in 2015 with an increased focus on developing new offshore reserves. A recent report on the regional energy sector by international bank JP Morgan said prospects for the industry in Indonesia had improved following the recent presidential election. The bank added that it expected the approval process for new oil and gas developments to be accelerated now that the vote had taken place, with a brighter outlook forecast for 2015, especially in the increasingly important offshore segment.
Heightened offshore activity spells good news, coming at a time when existing fields are struggling to meet production targets and paving the way for Indonesia to develop its downstream operations. However, competition from other South-east Asian countries might drive up costs and delay projects.
Shift In Tempo
Increased activity within the sector was evident in August 2014, when Malaysian oil field services provider Bumi Armada said a consortium in which one of its wholly owned unit is involved had been awarded a contract to provide a floating production, storage and offloading vessel for Indonesia’s Madura BD Field. Under the terms of the contract, valued at $1.18bn, Bumi Armada will supply services for the offshore project for a 10-year term with options for extension.
Indonesia is not the only South-east Asian country looking to forge ahead with new offshore projects. The Asian market is forecast to see a 54% rise in expenditure for offshore oil and gas infrastructure over the next five years, according to a report by London-based analysis firm Infield Systems. Southeast Asia will continue to drive demand in the region, particularly Malaysia. Vietnam is also considering boosting extraction operations in its waters next year and beyond, which could see competition for rigs and services increase yet further.
Indonesia, however, will be hoping that rising demand will also drive up foreign investment in downstream operations. In August 2014 the JX Nippon Oil & Energy Corporation indicated that it was considering developing a refinery in Indonesia. Tsutomu Sugimori, the company’s president, said the expanding Indonesian market, combined with its limited refining capacity, presented significant investment opportunities. “Indonesia has many requirements such as a need to upgrade refineries, increase refining capacity and improve ageing facilities, and we are looking for an opportunity to enter,” Sugimori told Reuters.
New investment in the energy industry could help ensure the long-term viability of the sector, according to Roberto Lorato, president director of Premier Oil Indonesia. “Indonesia has all that is needed not only to meet a growing local demand, but also to become a regional energy hub,” he told OBG. “What the country needs at the moment are larger investments in exploration and infrastructure development, and more attractive and stable commercial and fiscal terms in order to attract such large investments.”
Output from Indonesia’s existing fields is falling, with production unlikely to reach targets for 2014. Output for the first six months averaged 797,000 bpd, significantly below the 825,000 bpd produced the previous year and even the 818,000 bpd forecast in the revised 2014 budget. With oil consumption rising 1-2% annually, Indonesia will need to bring more reserves on-line if it is to make progress in bridging the supply gap.
Indonesia also subsidised domestic fuel supplies at a cost of $21bn for 2014, with outlays forecast to rise to $25bn in 2015. Import costs were also affected by the depreciation of the rupiah, which lost 10% against the dollar over 2014, putting further strain on state finances. Output is, however, expected to see a turnaround in 2015 when ExxonMobil’s Cepu block will provide up to 165,000 bpd of additional capacity. Bukit Tua oil field, which is now expected to start pumping in March 2015, will have the capacity to produce a further 200,000 bpd. When combined, the two initiatives will more than offset falling output from Indonesia’s ageing fields.
Looking To Myanmar
The energy sector is the great untapped potential on which Myanmar’s hopes are pinned. One of the world’s first oil producers, Myanmar is emerging in the 21st century as a significant producer of natural gas. With the lifting of international sanctions and the resolution of a maritime border dispute with Bangladesh, the government has moved quickly to accelerate investment by tendering out vast regions of the country and its offshore shelf to foreign investors. Drawn by the river delta geography and the productive history despite limited exploration, more than 60 international oil and gas companies are participating.
Myanmar’s numerous rivers are also well-suited to hydroelectric dams and hydropower is already the main source of the country’s meagre electric power production. The former military regime had planned to allow Chinese, Thai and Indian companies to develop dozens of dams geared mainly towards exports, but those plans were delayed due to popular opposition, difficulties obtaining financing and resistance from ethnic rebels in some areas. Currently, only several smaller dams are being built, but there is still strong interest from Chinese and Thai firms.
The greatest challenge will be to apply the country’s energy potential to promote general economic growth. Most recent major investments have been geared towards export, due to overly low electric power tariffs and an outdated gas distribution system. The energy deficit that results makes power supplies highly unreliable, stifles development and complicates expansion of the public energy grid to the parts of the country that are not yet connected.
Myanmar’s oldest oil fields, on the central Irrawaddy River around Chauk and Yenangyaung, brought oil and bitumen naturally to the surface. By the 18th century the region was home to a substantial indigenous oil industry. In the early 20th century, as global demand for oil surged, the Burmah Oil Company developed into one of the largest oil firms of the era, and founded a daughter company in Persia that would evolve into British Petroleum.
Following a military take-over in 1962, the oil and gas industry was organised under three state-owned companies: Myanma Oil and Gas Enterprise (MOGE), responsible for exploration and development, and gas transit; the Myanma Petrochemical Enterprise, which controlled processing; and Myanma Petroleum Products Enterprise, which managed the distribution and sale of oil products. These companies are today departments of the Ministry of Energy.
With no major discoveries in recent decades, crude oil production has fallen to 7000-7500 bpd. Most oil fields are operated by MOGE, except two privately operated projects. The Chauk and Yenangyaung fields were turned over to foreign joint venture Goldpetrol in 1996 under an improved petroleum recovery contract. Interra Resources, a Singapore-based independent, owns 60% of Goldpetrol, and ZhenHua Oil, a unit of Chinese industrial giant Norinco, has owned the 40% stake since 2010. The nearby Mann field was turned over in 1996 to a joint venture between US services firm Baker Hughes and Myanmar’s MPRL E&P, which took operations in 1999 when Baker Hughes withdrew. MPRL’s 15-year Performance Compensation Project was due to expire in 2013 and it is still unclear if it will be extended.
Modern Gas Producer
With small onshore gas fields already having been explored in the colonial era, offshore gas exploration in Myanmar was under way by the 1960s. The first find came in 1982 with the discovery of the Yadana gas field, around 64 km offshore of the Irrawaddy Delta. Development began after a re-organised military regime introduced reforms in the wake of 1988 protests. A licensing round in 1989-90 offered 16 blocks for production-sharing contracts (PSCs) to foreign investors, with majors Total, Unocal, Texaco, Shell and Amoco among the tender winners. The Yadana field was awarded in 1992 to Total, which remains the operator with a 31.2% stake. Stakes were farmed out to Unocal ( later acquired by Chevron), with 28.3%, and the Petroleum Authority of Thailand (PTT) with 25.5%. MOGE holds the remaining 15%. Because the project was initiated before international sanctions banned US and European companies from investing in Myanmar, Yadana and its investors were exempt.
After a $1.2bn investment, commercial production began in 2000 under a 30-year PSC. Output averaged about 730m standard cu feet per day (scfd) in 2012. About three-quarters of the gas is exported to Thailand through a pipeline operated by the partners that runs east under the Andaman Sea and overland to the Thai border, where PTT takes delivery. The remaining quarter of Yadana’s output is consumed domestically through two MOGE pipelines: one running under the sea to Yangon, launched in 2010, and an overland pipeline that runs north from south-east Myanmar towards Yangon.
A second major gas field, called Yetagun, was discovered in 1992 in blocks that Premier Oil, a UK independent, had been awarded in 1990. The project is located in shallow water northwest of the Mergui Archipelago. Premier farmed out stakes to Texaco, initially the operator, and Nippon Oil. However, sanctions led to first Texaco and later Premier backing out. Malaysian state oil and gas company Petroliam Nasional (Petronas) took, and PTT, the main customer, joined as partners. The current stakes in the project are Petronas with 40.9%, PTT and Nippon Oil with 19.3% each, and MOGE with 20.5%. Production started in 2000 and has risen with the addition of satellite fields. Investment totals $840m, including an undersea pipeline and an overland pipeline parallel with Yadana’s overland line. The field produces 500m scfd of gas, with 90% exported to Thailand and 10% delivered domestically through the overland pipeline. The field also yields about 11,500 bpd of condensate, which is refined domestically.
The military government has awarded other PSCs individually through direct negotiations with foreign investors. The next major discovery, the Shwe gas field, came in 2004 offshore of north-west Myanmar in blocks awarded to South Korea’s Daewoo International in 2000. Daewoo then obtained another PSC for a neighbouring block and discovered satellite fields. The South Korean firm is operator with a 51% stake, with partners including India’s ONGC Videsh (17%), India’s GAIL (8.5%), Korea Gas (8.5%) and MOGE (15%). The Shwe project was originally aimed at supplying gas to India, but backers were unable to secure pipeline access across Bangladesh. China then agreed to build an oil and gas pipeline from Myanmar’s Bay on the Bengal coast to the Chinese border. The gas line will carry Shwe’s output, while the other line will carry oil arriving by tanker from the Middle East.
Looking To New Partnerships
In June 2013 U Than Htay, Myanmar’s then energy minister, told Reuters that the China National Petroleum Company had spent $2bn on the gas pipeline, which was completed that month, and would spend $2.3bn on the oil pipeline, which was due to be completed later in 2013. The Daewoo-led consortium plans to invest $3.2bn and expects to produce 500m scfd of gas, according to OE Digital, a trade publication. About 80% of output will be exported. The gas pipeline was built with a larger capacity of 1.1bn scfd to accommodate future offshore discoveries or a potential addition of a liquid natural gas terminal.
The most recent major development, the Zawtika field was discovered by PTT in 2007 in a block southeast of Yadana. PTT is operator with an 80% stake to MOGE’s 20% under a 2003 PSC. The $2bn project is expected to produce 300m scfd, of which 80% will be exported to Thailand. Another 20% will be delivered domestically through a MOGE off-take pipeline. The project came on-line in March 2014. There were also two smaller but significant onshore gas finds north of Yangon in the 1990s: Shell discovered the Ahpyauk gas field in 1991, taken over by MOGE when Shell pulled out in 1993, and MOGE discovered the Nyaungdon gas field in 1999. Thanks to these finds Myanmar’s annual gas production surged from 60bn scf in the 1990s to 421bn scf in 2011, according to the US Energy Information Administration (EIA). Annual output is expected to reach 790bn scf by 2015 as Shwe and Zawtika ramp up production. By comparison, China produced 3.6trn scf in 2011, Indonesia 2.7trn, Malaysia 2.2trn, India 1.7trn, Thailand 1.3trn and Bangladesh 710m, according to the EIA.
Brunei Darussalam’s well-established energy companies and engineering and consulting firms, are well placed to take advantage of emerging opportunities in the region. Over the next 18 months other countries in the region may offer unique partnerships as the Sultanate ramps up downstream activities. The implementation of the ASEAN Economic Community in 2015 will also help to mitigate cross border risks, offering Bruneian companies a chance to participate in lucrative projects.
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