Dominated by hydrocarbons, the energy sector in Brunei Darussalam has seen production begin to falter in the past five years and, therefore, is now awaiting the results of exploration and development programmes being carried out by international oil companies. There remains a high degree of optimism that these efforts will bear fruit, with the government setting ambitious production targets over the next two decades. In the interim, the government faces the threat of revenue erosion from its biggest source of income.
However, despite this pause, there continues to be significant activity in the energy industry. From oil services firm contracts and midstream and downstream developments to requirements for local content and employment in the industry, much has happened within the sector in the past 12 months.
KEY FIGURES: The energy industry, and the hydrocarbons sector in particular, continues to dominate the economy. Oil and gas accounted for 67.7% of GDP or BN$13.9bn ($10.83bn) in 2011, according to the Department of Economic Planning and Development (JPKE). Oil and liquefied natural gas (LNG) exports reached 91.5% of total exports in 2011, according to the JPKE. Oil exports, including condensates and other liquids, reached an average of 154, 827 barrels per day (bpd) at an average price of $116.13 per barrel.
Given these figures, total oil exports should have reached a value of $6.57bn in 2011. LNG exports had a value of $5.93bn in the same year, at an average price of $16.49 per million British thermal units (mmbtu).
STATE OF PLAY: According to the BP Statistical Review 2012, Brunei Darussalam has proven oil reserves of 1.1bn barrels, the same figure as 2010. The country also has 10.2trn cu feet (tcf) of natural gas reserves, the same figure as 2010 and 0.1% of the global total, according to BP. The largest operator and producer in the country is Brunei Shell Petroleum (BSP) a 50:50 joint venture between the Royal Dutch Shell Group of companies and the government. Shell has had a presence in Brunei Darussalam for more than a century and was one of the six companies that first explored for oil in the Sultanate in 1899. The company now has become the predominant player in the sector, accounting for 90% of the country’s oil and gas revenues, according to its own reports. BSP produces over 350,000 barrel of oil equivalents per day in Brunei Darussalam (as of 2010, according to its statements to the press).
Indeed, BSP has a wide number of interests in Brunei Darussalam’s fragmented offshore and onshore oil reserves. The company operates in seven fields – Seria, South West Ampa, Fairley, Champion, Gannet, FairleyBaram and the Iron Duke. According to BSP’s latest public information, the most prolific field is the offshore Champion field, located 45 metres below sea level and 40 km off the Sultanate’s coastline, with 40% of the country’s reserves and a daily production level of 92,000 barrels (in 2010). Onshore, the oldest field, Seria, which produced its billionth barrel in 1991, still contributes 28,000 bpd. In total BSP operates in 4750 reservoirs in the Sultanate, illustrating the compartmentalised nature of the oil play in the country.
The other major operator in the country is Total, a French firm. The company has been present in the Sultanate since 1986 and operates the Maharaja Lela/Jamalulalam field, located in Block B. Total E&P Borneo is the operator of Block B, under a joint venture arrangement. The company holds a 37.5% stake in the project, while Shell Deepwater Borneo has a 35% interest and PetroleumBRUNEI, a government-owned oil company, holds the remaining 27.5%. In 2012 the average production of gas and condensate from the field reached 32,000 barrel of oil equivalents per day (boepd).
DWINDLING PRODUCTION: However, production from the country’s existing fields has been stalling and now dwindling. According to the BP Statistical Review 2012, Brunei Darussalam has worryingly low reserves to production ratio of 18.2 years. Production from existing fields peaked at about 210,000 bpd in 2006 and has been on the decline ever since. According to information from BSP, the company had 817 producing wells as recently as 2003. Given these figures, it is unsurprising that the overall output has decreased. Indeed, crude oil production fell by 7% in the first three quarters of 2011 alone, dropping from an average of 147,909 bpd in 2011 to 137,526 bpd in the third quarter of 2011. Similarly, natural gas production has experienced a noticeable decline in the last half decade, although at a much lower rate. Natural gas production has shown some fluctuation and is in a more robust state than oil production. Indeed, the latter, under current scenarios, shows signs of being in its final decline.
CAUSE FOR HOPE: Nonetheless, given the perceived potential for new finds and developments, the government remains bullish about production prospects over the medium term. The draft energy white paper of the Energy Department at the Prime Minister’s Office ( EDPMO), which is expected to be finalised and published at some point in 2013, lays out an ambitious key performance indicator of doubling oil and gas production from 400,000 boepd to 800,000 boepd by 2035.
Such a lofty target will require a coordinated effort, bolstering existing production and uncovering new reserves. “The only way they can achieve that is to make sure they have the acreage,” Rudy Borhan, general manager of QOS, a local oilfield services company, told OBG.
POLICY MOVES: In May 2012 Azhar Yahya, the permanent secretary for upstream activities at the EDPMO, stated that to achieve the white paper targets would require intensive exploration efforts, opening up a number of new blocks for additional operators, boosting production incentives for marginal reserves and increasing the use of new technologies.
Azhar suggested that production targets could not be met from new commercial blocks alone, and existing fields have to improve production. “We want to increase and accelerate the exploration programme in the existing producing blocks of BSP and Total so that we know the actual potential of those blocks. Therefore, we are not solely reliant on the success of the commercial blocks,” Azhar stated.
IMPROVING EXTRACTION: BSP has already begun the process of improving extraction from mature fields. In 2009, the company announced the Champion Water Flood Project as part of its secondary recovery operations. BSP plans to inject water into the field to increase the reservoir pressure and increase production by 200m barrels. As part of this process, the company is drilling more than 130 new wells and constructing nine new offshore structures. In August 2012 the French oilfield services firm, Technip, was awarded a contract by Swiber Offshore Construction to provide 12 flexible flow lines totalling 19 km in length to be used in the project.
Technip will complete the project in the first half of 2013 as the project becomes operational.
While BSP first injected treated seawater into its largest field in 1984, this is the first time it has made a concerted effort and taken a more holistic approach to water flooding to alter reservoir dynamics. Previous problems with water injection have included water overrun due to high-permeability sands in the field. The current project, which is founded on an integrated study for field redevelopment begun in 2003, could extend the life of the Champion field by 30 years.
OTHER METHODS: BSP has also been working on a number of other measures to improve production from the country’s oldest field, Seria. Since 2004, when new blocks were discovered on the northern flank of the Seria field, BSP has been deploying new technology to access this difficult oil.
In 2007 the company used the T201 rig to begin drilling 25 fish hook wells into the most inaccessible parts of the northern flank blocks. Indeed, the last well, Seria-892, is the longest fish hook well ever drilled, measuring over 4 km in length.
The company also began an enhanced oil recovery (EOR) pilot project in the more mature parts of the field in 2010. As of February 2012, the company had conducted a single well trial, assessing the functionality of the injecting process and the effectiveness of different alkali surfactants in different reservoir horizons. The use of water and chemical injection under the project could improve field pressure and pave the way for a large EOR project, extending the life of a field that has already been producing for over 80 years.
The government has put emphasis on EOR schemes. “On the EOR, we are looking at an increase of up to 25% from producing fields, assuming the EOR methods will help increase recovery rate from 40% to 50%,” Azhar stated. “In 2010 the recovery rate was at 29% and should reach 40%, based on the current project.”
NEW COMMERCIAL BLOCKS: However, bolstering recovery rates in mature and existing fields is only one part of the government’s strategy. Since 2007 the government has also been signing a number of production sharing contracts (PSCs) for the exploration and development of a number of new blocks. The first new contracts were for Blocks L and M. The latter, an onshore block covering 3011 sq km, was producing into the 1960s until decreasing rates and civil unrest in neighbouring countries saw the wells capped. It has since been taken over by a joint venture partnership of Polyard Petroleum International (39% and the field operator), KOV Borneo (36%), a wholly owned subsidiary of the Polish company, Kulczyk Oil Ventures; China Sino Oil Company (21%); and Jana Corporation (4%). Polyard purchased their stake in the block in September 2011, buying out the share held by Tap Energy (Borneo), part of Australia’s Tap Oil, for $2m.
Block L covers a 2220-sq-km area predominantly onshore with a small segment offshore. It is being developed by Kulczyk Oil Ventures (90% interest and operator), AED Oil and the local participant, QAF Brunei, a trend the state is looking to continue.
The third block under a PSC and already well into its exploration phase is commercial block 1. In 2010 Total E&P Deep Offshore Borneo took a majority interest (54%) in the block, becoming the operator. The other partners in the block are Billiton Petroleum Great Britain (22.5%), Hess (13.5%), Petronas Carigali Overseas from Malaysia (5%) and Canam Brunei, a wholly owned subsidiary of Murphy Oil (5%).
In September 2011 it was announced that Brunei Darussalam and Malaysia will jointly develop Block N and that demarcation of the land boundary was close to finalisation. In March 2012, a further memorandum of understanding for a land boundary survey and joint demarcation was announced between the two countries. Block N, which is currently held by the stateowned PetroleumBRUNEI, is an 883-sq-km offshore block. PetroleumBRUNEI also currently holds the offshore blocks P and Q, which are 1021 sq km and 1115 sq km in size, respectively. Azhar emphasised that, alongside the commercial blocks, these blocks will play a crucial role in helping the country to meet its production targets in the future.
SEARCHING FOR SIGNS: However, from the commercial blocks that have begun exploration, the early results have produced mixed results. Total has completed three wells in its initial exploration campaign in commercial block 1 and in parallel has completed a large scale seismic survey. While the company is still compiling results, initial indications are that there are no imminent results that could easily translate into developments.
The firm has had little indication that it will be able to jump into production anytime soon. Nonetheless, Total envisages an exploration period of six years and has said it still believes there is huge potential in its block. As Ludovic Le Gurun, the operations manager at Total E&P Borneo, told OBG, “I don’t think it’s on anyone’s mind to relinquish the block.” However, the news in the onshore blocks that already have a history of production in the 1950s and 1960s looks more positive. In Block L, Kulczyk Oil, the Polish oil firm, has a confirmed investment of $25m. The company has received a 12-month extension from August 27, 2012 to August 27, 2013 to drill its two commitment wells in phase II under its PSC. The drilling programme is expected to begin during April 2013 and be completed by August of that year. In 2012 the company received some 191.8 sq km of 3D seismic data covering the West Jerudong and Updip Lukut areas of Block L. This data seems to have given the firm substantial optimism.
NATURE OF FIELDS: The reality of exploration and development in the Sultanate is that there is no easy oil left. Beyond the mature Champion and Seria fields that require secondary and tertiary techniques and the latest technology, the potential new plays within the country are also largely in complex and, thus, expensive reservoirs. The onshore blocks are likely to remain the cheapest for development.
According to Kulczyk Oil Ventures, the cost of drilling a well in Block L came to approximately $9m. However, compared to the deepwater offshore prospects, these fields are straightforward.
The deepwater offshore blocks are inevitably technically difficult and thus costly for exploration and development. The fields are in water of a depth approximately 1500 metres. While not at the top limit of the range of what is drillable, this depth still poses significant challenges and costs. As well as the deep water, the play is expected to require deep wells and have the additional challenge of high pressure. However, operators suggest that it is not outside their scope of experience and that depth and pressure would be what the major companies have already been experiencing in the Gulf of Mexico and Gulf of Guinea, two other major deepwater regions.
In the latter, total costs of production, including capitalised and expensed costs for oil and gas property acquisition, exploration and development can in certain markets be firmly placed in the marginal category. For example, according to the 2011 annual report of the oil firm Kosmos, the operating cost of production in Ghana was $13.99 per barrel, but the total cost of production was over $100 per barrel in 2011. For a more mature deepwater offshore market, such as Angola, the cost of production (operating and capital expenses) was $40 per barrel in 2009, according to Reuters. Brunei Darussalam’s place along this spectrum, if it indeed begins production from deepwater prospects, is unclear. If it is at the upper end of this range, the country will obviously require the oil price to hold steady to make potential reserves commercially viable.
EXPENSIVE OPTIONS: While the Jubilee Field in Ghana has average water depths of almost 1250 metres, in commercial block 1 the operator Total E&P Deep Offshore Borneo suggests water depths are in the range of 1500 metres. As such, rig rates, the most important cost component, are similar to rates in the Gulf of Guinea. The ENSCO 8504 rig, a newly constructed rig built at a cost of some $500m, was commanding daily contract rates of $500,000 in commercial block 1 alone. According to a Borneo Bulletin report in June 2012, the rig was commanding rates of $1m a day for all services from BSP as they began a drilling campaign in three prospects in deepwater acreage, Pungguk Deep, Lapu Larong and Ciak.
For commercial block 1, beyond depth, the fields are also expected to be complex. The cost of production will remain on the low side but the development cost is expected to be extremely high. According to Le Gurun, two-thirds of the development wells are coming from wells that are deep, high pressure and high temperature. Initial suggestions are that pressure is around 700 bar and the temperature while flowing is likely to be 120°C. Total already have dealt with technically difficult reservoirs in Block B. The company is currently producing around 3.9 mmscf per day of natural gas and 5000 barrels per day of associated condensates. Total says gas production can be ramped up to 5m cu metres per day. In Block B, the company is dealing with reservoirs about 5000 metres deep. Indeed, Total has already drilled a 5699-metre well, the deepest in the Sultanate and one of the deepest in all of Asia. Given the complexities, operators will need to find substantial reserves to make the field investments worthwhile.
SWEET STUFF: One thing working in the investments’ favour is the light, sweet quality of Brunei Darussalam’s crude and the ability to sell at a premium. Indeed, according to the Department for Economic Planning and Development, the average oil price for Brunei Darussalam’s crude was almost $5 per barrel above the average Brent crude spot price, at $116.13 per barrel in 2011. The country’s largest export markets for crude petroleum in 2010, the latest year for which statistics are available, were South Korea (BN$1.4bn, or $1.1bn), Australia (BN$1.25bn, or $973.5m), Indonesia (BN$854.8m, or $665.7m), China (BN$750.9m, or $584.8m) and India (BN$667.9m, or $520.2m). The Sultanate continues to use its strong regional relationships to support its oil export strategy. China and India, the two most energy-hungry states in the region, have risen to the top of the agenda. In November 2011, for example, following a visit by China’s Premier Wen Jiabao, Brunei Darussalam agreed to increase oil exports to China from 13,000 bpd to 16,000 bpd.
In the natural gas market, Brunei Darussalam’s achieved LNG price was $12 per mmbtu above the Henry Hub spot price at $16.49 per mmbtu (compared to approximately $4 per mmbtu for Henry Hub, according to the US Energy Information Administration), the benchmark price for the US natural gas market.
The government has been able to achieve a price above the spot market price by locking in long-term contracts, with Japan and South Korea representing its most important destinations for LNG. In 2010 LNG exports to Japan reached a total of BN$4.8bn ($3.74bn), while those to South Korea hit some BN$611.7m ($476.4m). Brunei Darussalam now has a strong gas supply chain from field developments to the five LNG trains operated and owned by Brunei LNG, a joint venture partnership by the government (50%), Royal Dutch Shell (25%) and Mitsubishi Corporation (25%); the shipping networks overseen by Brunei Gas Carriers, a joint venture partnership between the government (80%), Shell Gas (10%) and Diamond Gas Carriers (10%); and Brunei Shell Tankers, a joint venture partnership between the government (50%), the Shell Petroleum Company (25%) and Diamond Gas Carriers (25%). As of late 2012 the government was still firming up renegotiation of these long-term LNG contracts.
CONTRACTS: Beyond the strong price that Brunei Darussalam is able to achieve for its crude and LNG, revenue generation for both the government and commercial block partners is likely to be determined by PSCs and PSAs. While BSP operates a concession, a legacy of longstanding agreements with the government, the new onshore and offshore blocks have been offered on a PSC or PSA basis. This brings the Sultanate into line with the industry standard in the region and reflects the additional risk associated with these new blocks.
Brunei Darussalam has been using the PSC model extensively since 2007. The EDPMO confirmed to OBG that most of the new ventures will be on a PSC basis and that they will use a contract in line with international standards for PSCs. This is seen as the best way to manage all the uncertainty and risk exposure associated with these new blocks, allowing the government to partake in a profit sharing partnership while also helping to minimise risk.
According to Kulczyk Oil Venture, under their PSA PetroleumBRUNEI, as a commercial operator for the government, has the right to take a 15% participating interest in Block L and previously Block M at any stage throughout the 30-year PSA. The exploration period for Block L is six years, divided into two phases. However, the exploration period has been extended by one year until August 2013. Under the PSA, the operator is required to spend a minimum of $25m in phase I and a further $16m in phase II exploration in Block L. Furthermore, the partners had to relinquish 50% of Block L in 2011, under the PSA.
While it is clear that there is a cost recovery mechanism in the PSC/PSAs, the specifics of the financial terms remain opaque. All oil and gas firms pay 55% in corporate tax and PetroleumBRUNEI has the right to take a 15% participating interest in certain blocks. However, agreements on cost and profit, the sharing agreement over the life of production and domestic market obligations have not been made public. According to a paper given at the 31st convention of the Indonesian Petroleum Association, based on an early Brunei Darussalam PSC model (2001), the petroleum revenue regime is competitive regionally from an investor’s perspective. The Sultanate’s present value index (PVI), a measure of profitability or value of a project to the amount invested, is 1.68, the region’s fourth highest.
STANDARD PRACTICE: Brunei Darussalam’s petroleum revenue regime is largely in line with regional and international practice and, as such, provides a comfortable environment for international oil firms. Also, as elsewhere in the world, rights to blocks that are awarded but do not see the agreed exploration activity take place within the time limit specified under the contract terms revert to the appropriate authority.
OVERSEAS INVESTMENTS: The third plank of government efforts to meet its ambitious production target is likely to be based on agreements with emerging producer nations. In December 2012, for example, following a visit by President Thein Sein of Myanmar, it was announced that PetroleumBRUNEI is looking at investing in Myanmar’s oil and gas sector.
The Brunei Times reported the minister of energy, Pehin Dato Yasmin Umar, as saying, “It’s an opportunity for us to develop joint cooperation in a lot of upstream activities. They will be bidding for the offshore and onshore concessions. It’s one of the ways for people in Brunei to venture outside Brunei Darussalam and do some work there.” This followed the signing of a memorandum of understanding between PetroleumBRUNEI and PetroVietnam in November 2012, following a visit by Vietnam’s president, Truong Tan Sang.
Nonetheless, these announcements illustrate the government’s attempts to play an active role in regional oil industries and book reserves overseas. While this will obviously be of benefit to PetroleumBRUNEI and the government, it could also present further opportunities for companies operating within the Sultanate’s oil and gas sector. “We’re trying to ride on the back of the government,” Rudy told OBG. “It can be very difficult to venture overseas. You need credentials and a link with the government.” Indeed, the government has made clear it would like to develop the internationalisation of local firms, a strategy that could help local oilfield services firms gain contracts in new markets.
Regarding the need to prepare local energy companies, Haji Awang bin Haji Ali, the managing director of QESS Energy Support Services, told OBG, “If Bruneian energy companies are truly going to become more independent there needs to be more technology transfer from international partners. Local companies can no longer be sleeping partners in Brunei Darussalam.”
However, it is not only in the oilfield services segment that opportunities might arise. “There are currently a few concerns over PetroleumBRUNEI’s technical ability as an operator,” Le Gurun told OBG. “So in the short term, they may be a block owner in foreign markets, but not operating in the field. They may have to engage an international oil company as a block operator, which could present opportunities in new markets.”
Total is not the only company to be positioning itself along these lines. Following the announcement of PetroleumBRUNEI’s interest in the upstream sector in Myanmar, Ken Marnoch, the managing director of BSP, told the Brunei Times, “Shell is interested in participating in Myanmar. PetroleumBRUNEI will have its own ambitions but if their ambitions coincide with Shell’s we’d be very happy to work with PetroleumBRUNEI.”
REFINERY & DOWNSTREAM: It is not only towards overseas ventures that the government is turning its attention. Its network of regional contacts is also paying dividends at home. Indeed, China’s Zhejiang Hengyi Group is set to invest BN$4bn ($3.12bn) in a new refinery and aromatics cracker complex in an industrial zone on Pulau Muara Besar island, off the Sultanate’s coast. The refinery would have a capacity of 135,000 bpd and hire 800 workers. This would represent the biggest foreign direct investment in the country.
The negotiations for the development of the refinery continue behind closed doors. The EDPMO told OBG plans for the new oil refinery are still on track and Hengyi should begin construction in the second quarter of 2013. The tentative date for the start of refinery operations is the first quarter of 2016.
However, precise details are not yet available, with negotiations still ongoing. It is still unclear how much of the additional capacity will have to go to the local market where the margins are thin and how Hengyi will recoup costs on its refining operations. Nonetheless, the EDPMO has made it clear that the plan is to make Brunei Darussalam self-sufficient in refined products with remaining capacity available for export.
PETROCHEMICALS FOCUS: Hengyi is likely to make its returns through the construction of its petrochemicals complex. According to a statement released to the Shenzhen Stock Exchange in April 2012, under the first phase of the project the company will build a 1.5m tonne per year light naphtha facility, a 1.5m tonne per year paraxylene unit as well as a 500,000-tonne-peryear benzene plant. Under the second phase, Hengyi will invest some $3.5bn to expand the refinery in order to produce olefins, according to the statement. The end products of these facilities are expected to be used for feedstock for Chinese factories in China.
The new development is likely to have a substantial impact at home as well. In November, the minister of energy, Pehin Dato Yasmin Umar, told the local press at a jobs fair that the government wants to make the Sultanate a distribution centre for oil and gas products in the broader region. Pehin Dato Yasmin stated that companies from Turkey, the UAE, Germany and Japan have already committed to investing in downstream projects within the country.
The government also plans to make an additional 0.5tcf of gas available for feedstock in future petrochemical projects. The EDPMO is also targeting further downstream activity off the back of the Brunei Darussalam methanol plant, completed at the end of 2009 and run by Brunei Methanol Company, 50% owned by MGC, 25% by PetroleumBRUNEI and 25% by ITC. The plant has a capacity of 850,000 metric tonnes per year and the EDPMO is looking for off-takers for the methanol to venture further downstream.
The most immediate impact of the new refinery, however, is likely to be on the domestic market for refined products and fuels. The current 12,000 bpd BSP refinery at Seria falls well short of meeting local market demand. In 2011, domestic consumption of petrol (of varying grades) reached 323m litres with a value of BN$152.9m ($119m), according to the JPKE.
In the same year, domestic diesel consumption reached 329m litres with a value of BN$149.6m ($116.5m), while jet fuel consumption was 133.3m litres with a value of BN$137m ($106.7m). Premium petrol consumption has been growing steadily, increasing by 5.9% to 1.55m barrels in 2010, the latest year for which statistics were available. Similarly, diesel increased by 10.04% to 1.85m barrels and jet fuel increased by 23.3% to 820,000 barrels in the same year.
As such, Brunei Darussalam’s current refining capacity is inadequate to meet demand. In April 2012 the Brunei Economic Development Board released a statement saying that BSP, BSM and Zhejiang Hengyi have signed a memorandum of understanding regarding the supply of crude oil to the refinery and the off-take of refined products into the domestic market. BSM is the sole oil marketing company in the Sultanate and is responsible for the distribution of refined products in the local market, including petrol, diesel, Jet A1 fuel, LPG, lubricants and bitumen.
BSM is a 50:50 joint venture between the government and Shell International. It sells its products at a heavily subsidised price, but maintains margins through a subsidy recovery programme. Fuel is sold at an average price of approximately BN$0.50 ($0.39) per litre. The company sees sales growth of 2% per annum in the market, a trend directly tied to population growth. BSM currently has 38 petrol stations (set to increased to 41 within the next five years) and 22 tankers for distribution in the country.
OUTLOOK: In many respects, the energy sector remains outward facing; the country leans heavily on hydrocarbons for export revenue. As such, the government is pushing hard to maximise output, a strategy that involves bolstering production from existing fields and ramping up the search for new ones. While the initial results have been mixed, the authorities remain confident the country can produce oil and gas up until at least 2050. Although the main focus remains on maximising income from oil and gas, the government is also looking to leverage its long history in hydrocarbons to explore opportunities overseas and to develop a distribution hub for refined products at home. This should not only boost revenue further, but provide opportunities for both local firms and labour to play a more active role.
Read More from OBG
