Indonesia grasps at ever-widening energy deficit
Southeast Asia's largest hydrocarbon producer has always thought carefully before acting and the present regime, now more than a year old, shows no signs of breaking with tradition
Indonesia's president, Joko Widodo, filled the country's oil and gas industry with hope when he came to office in October 2014. Expectations were high that the reform-minded leader would move fast to stave off an energy crunch.
But one year on, progress has been erratic. Jokowi, as he is known locally, has so far failed to reshape Indonesia's oil and gas regime to lure much-needed foreign investment.
His government has failed to pass a new oil and gas law - the last one was annulled in November 2012 - creating a drag on upstream investment in the archipelago. The lack of contractual, regulatory and fiscal certainty amid the low-oil price environment has conspired to delay or even derail some of the nation's proposed giant projects that would help tap the area's largest unexploited gas reserves. As a result, Indonesia is unlikely to see an uptick in investment soon.
The draft oil and gas law is expected to be ready in the first few months of 2016 and the timeline remains fluid as various political factions vie to influence the outcome. But even when it is finalised, industry players expect it to take at least another year to iron out the kinks.
Matters of concern
More worrying is the rising rhetoric of economic nationalism. The draft law not only proposes to hand significant privileges to national champion Pertamina, but includes plans to introduce a national oil and gas aggregator, which Sampe Purba, vice president of gas commercialisation at upstream regulator SKKMigas, described as "just short of a monopoly buyer" in recent talks with PE.
This has made foreign investors - such as ConocoPhillips and Chevron from the US, European majors Total, Shell and BP, Chinese Sinopec and China National Offshore Oil Corporation and Japanese Inpex - more nervous, as they fear the proposed aggregator concept will extract value from their upstream investments.
A circulating copy of the draft law signals that the aggregator will dictate pricing - based on field development economics - without explicitly taking into account the exploration risk to upstream producers.
But a spokesman for the energy ministry told PE that it is trying to solve the inefficient distribution of gas to markets, while encouraging investment in new infrastructure. Purba added: "Investors should be happy - we're guaranteeing them a market for their gas." The chief executive of local gas developer Ephindo Energy, Sammy Hamzah told PE he was confident the government would recognise the flaws in its proposed policy and that the issue would eventually be resolved.
On a more positive note, the Jokowi government is streamlining the arduous approvals process for oil and gas projects by introducing a one-stop shop. The number of permits needed from the energy ministry has so far been cut from 52 in 2014 to 42 in mid-2015. The government hopes to cut this to four within the next two years.
Jokowi also took an unprecedented decision in January 2015 when he announced no more subsidies on gasoline and a fixed subsidy for gasoil. It was a welcome move, given the nation spent close to $16bn on fuel subsidies in 2014 - three and a half times more than its healthcare spending.
It demonstrated Jokowi's determination to tackle tough issues. But politics eventually got the better of him. In mid-2015, the president bowed to pressure and agreed that fuel prices would be adjusted every three to six months and not on a monthly basis as had originally been decided.
So, despite the volatility in global oil markets, Indonesia has adjusted pump prices just twice so far this year as the government strives to maintain economic stability in the face of weaker growth.
The policy backtracking has left national oil company Pertamina carrying the losses on fuel subsidies. The company is not allowed to adjust pump prices in line with international markets and cannot claim subsidy payouts, which have officially been removed.
In October, the government assured Pertamina that it would eventually compensate it for the financial loss of around $1bn - money that could have otherwise gone towards boosting upstream production - from fuel sales during the January to August period.
Net energy exporter
Despite all the woes, Indonesia remains a net energy exporter. It is the largest coal exporter globally and the biggest exporter of gas and liquid biofuels regionally. But the nation is depending more on imported oil products and has become the second-largest oil importer in the region.
As domestic production wanes and consumption increases, the archipelago faces a crippling energy crunch. The upstream oil and gas sector is forecast to provide 47% of total primary energy needs in 2025, or 3.7m barrels of oil equivalent per day (boe/d). Analysts estimate a 2.5m boe/d shortfall of supply that year.
Muted activity in exploration drilling and disappointing reserve replacement rates suggests the government desperately needs to spur investment. Failure to do so would be disastrous for the rest of the economy.
Indonesia suspended its Opec membership in 2008, when it finally accepted its changing role from oil exporter to net importer. Yet in a surprise move, the nation asked the organisation to reactivate its membership as an observer.
The news reflects Jakarta's desire to build better ties with producers, thereby securing more competitively priced supplies as it becomes increasingly reliant on foreign oil.
Its exports of LNG have waned too and it will have to import it to meet expanding demand at home. Oil production continues to fall. It is expected to average around 769,000 b/d this year - or roughly half of the 1.65m b/d peak production seen in 1977 - while demand stands at 1.563m b/d, almost twice domestic output, reported Wood Mackenzie.
Gas production is expected to average 7.1bn cf/d in 2015, falling to around 6.2bn cf/d by the end of the decade unless new developments are sanctioned, data from the energy research firm shows. Demand this year is 3.62bn cf/d and expected to rise.
Under an ambitious electrification plan, Jokowi has pledged to deliver 35 GW of electricity across Indonesia by 2019. Under the plan, gas would supply a third of this new power.
But connecting gas reserves to markets remains a challenge for Indonesia given the lack of infrastructure connecting its 17,000 islands. Some $8bn will need to be invested in mini-LNG and floating storage and regasification units, said state utility PLN.
Without drastic action Indonesia's prospects of narrowing its ever-widening energy deficit are slim. To help plug the gap, some 12m tonnes per year (t/y) of LNG will be required by 2020, expects Syahrial Mukhtar, a strategic advisor at Pertamina. PLN, seemingly anticipating long delays in giant gas projects at home, has already signed deals to secure LNG imports from the US starting in 2018.
Two of Indonesia's proposed giant gas projects remain stalled, while the costly development of the offshore East Natuna (formerly Natuna D-Alpha) field - the region's largest unexploited gas structure, which has five times as much CO2 as methane - looks more remote than ever.
Data from Wood Mackenzie puts Indonesia's remaining reserves at 27.7bn boe, of which 10.2bn boe are on stream, under development or likely to be sanctioned in the next few years. A further 2.7bn boe could be potentially developed, based on their estimates.
Chevron's $12bn Indonesia Deepwater Development (IDD) project, as well as several other multi-billion dollar schemes, remain stuck on the drawing board, largely because of the uncertain investment environment. The IDD project covers five deep-water gas fields, four of which will be developed via two floating production units (FPUs).
The Gendalo FPU will receive gas from the Gendalo, Maha and Gandang fields, while the second floater would initially produce from the Gehem field. The fifth field, Bangka, is already being developed and expected to come on stream in 2016 as a tie-back to the US major's West Seno facilities. The two vessels will pump around 1.1bn cf/d of gas and 47,000 b/d of condensate.
But a major hurdle for the IDD project is that the Rapak and Ganal production-sharing contracts (PSCs), which cover the five fields, are set to expire in 2027 and 2028, respectively. Chevron is in talks with the authorities about contract extensions before taking a final investment decision, although no timeline has been given.
It seems unlikely that any contract extension can be concluded before the draft oil and gas law is approved by law makers. Even then, the draft law in its present format will hand Pertamina first right of refusal on expiring blocks, which means Chevron will have to negotiate a stake with the NOC if it plans to exercise its new rights.
Complicating matters further, regional governments are clamouring for stakes of up to 10% in expiring PSCs, although it's unclear if they will have the means to finance their share of developments.
Chevron, Indonesia's biggest oil producer, has a 63% stake in the IDD project. Partners in the Ganal PSC (Gendalo) and Rapak PSC (Gehem) include Italy's Eni on 20% and China's Sinopec on 17%. The deep-water Gendalo-Gehem fields lie in the Kutei basin off East Kalimantan and would be Indonesia's first ultra-deep water development.
Elsewhere, BP has pushed back the final investment decision on its third 3.8m t/y train at the Tangguh LNG export project in the West Papua province to mid-2016 at the earliest, as it needs to find more buyers. First gas will be delayed until 2020 from 2019 initially.
The $12bn expansion, which is in the front-end engineering and design phase, will sell 1.5m t/y to state utility PLN. Another 1m t/y will be shipped to Kansai Electric Power in Japan. But the UK major is still seeking buyers for the remaining 1.3m t/y of planned output.
The Tangguh partners - Cnooc, Mitsubishi, Inpex, Sumitomo and Mitsui - have agreed to supply 40% of Train 3's output to the domestic market, pleasing Indonesia's authorities.
Tangguh has sufficient feedstock gas and the land is already approved for a liquefaction project which could ultimately house eight trains. If Train 3 eventually goes ahead, it will boost the plant's nameplate capacity to 11.4m t/y.
Meanwhile, the Inpex-operated Abadi floating LNG (FLNG) project in the Masela Block was poised for government approval in early October for the scaled-up 7.5m t/y scheme before a government minister started lobbying SKK Migas to reconsider onshore liquefaction.
The Abadi field in the Arafura Sea in the eastern waters of the archipelago is one of the country's biggest deep-water gas projects and was expected to support rising energy demand by the end of the decade.
Coordinating maritime affairs minister Rizal Ramli, who entered the cabinet as recently as mid-August, suddenly cried foul, publicly demanding a whole review of the development, arguing that the scheme should be tied to an onshore LNG plant instead of an FLNG project, in order to create more jobs and direct economic benefits for locals.
Without revealing how he produced his estimates for such a hugely complex project, Rizal claimed an onshore plant on Aru Island would be much cheaper.
SKK Migas is now seeking an independent consultant to assess whether Abadi's gas should be processed offshore or onshore, which means further delays.
An SKK Migas official said in September that he thought Abadi might not start commercial operations until 2024. This would leave just four years until the existing Masela PSC is due to expire. Inpex has been in negotiations with the authorities about a new contract as part of its Abadi development plans. But again, until the new oil and gas law is finalised it's hard to see an extension being granted. The Japanese player operates the Masela Block with a 65% stake on behalf of partner Shell.
Despite all the gloom, elsewhere the Italian operator Eni is making progress with its fast-track development of the deep-water Jangkrik and Jangkrik North East fields. It is targeting production start-up in two years' time.
Jangkrik and the satellite Jangkrik North East field, both on the Muara Bakau PSC, were discovered in 2009 and 2011, respectively. The Jangkrik production vessel will be able to handle 450m cf/d of gas and 4,400 b/d of condensate.
Seven year deal
Eni signed a deal with Pertamina in June to sell it 1.4m t/y of LNG from the Jangkrik project for seven years, starting in 2017. The feedstock gas for Pertamina will be processed at the Bontang LNG plant in East Kalimantan. Eni will also sell pipeline gas to a local fertiliser producer, and other quantities could be sold locally too.
More than half of the project's gas has already been committed to Indonesian customers, compared with just 30% that was agreed in the development plan.
The Italian company operates the Muara Bakau PSC with a 55% stake on behalf of partners Engie (33.334%) and Saka Energi (11.666%).
But the development of Indonesia's biggest gas field, East Natuna, where recoverable reserves have been pegged at 46 trillion cf out of an estimated 222 trillion cf of gas in place, remains a long way off.
The giant field, which was discovered in the 1970s, remains unexploited as the development cost has been estimated at tens of billions of dollars. There are also many technical hurdles and environmental implications that need to be considered when bringing online what may be an extremely sour gas field with high CO2 content.
Pertamina operates East Natuna on behalf of its partners: the original operator ExxonMobil; France's Total; and Thailand's PTTEP. They expect it will take at least a decade to further appraise and, if deemed commercially viable, to carry out development. Peak production of 4bn cf/d is projected to continue for 20 years before natural field decline.
Meanwhile, uncertainty surrounding the ownership of Indonesia's giant but ageing offshore Mahakam Block could see production fall faster than expected.
Total and Inpex each own half of the block, which provides about a fifth of Indonesia's total gas production. It is a major supplier to the nearby Bontang LNG export plant. But in June, the government said it would hand a 70% operating stake to Pertamina when the PSC expires at the end of 2017.
The appointment of the NOC as the operator underscored Indonesia's aspirations to take a firmer grip on the nation's natural resources.
Negotiations continue with Total and Inpex for the remaining stake. But as the pair do not yet know what will happen starting 2018, they cannot firm up their investment plans for 2016, which could dent production.
SKK Migas has said that production from Mahakam could drop by as much as 26% in 2016 as the PSC's expiry draws near. It claims that Total and Inpex are not drilling as aggressively as before. Ouput from Mahakam is around 1.6bn cf/d plus 62,000 barrels of liquids.
Indonesia has significant unconventional gas potential, which could help boost its energy security. Official estimates put the country's shale gas potential at 574 trillion cf, while coalbed methane (CBM) resources are estimated at 453.3 trillion cf - which is much higher than conventional natural gas reserves. Those are pegged at 101.5 trillion cf.
The government is prioritising CBM development. At the end of October, it announced plans to introduce two new PSC models for non-conventional acreage with better fiscal terms, that it hopes will spur investment in the sector.
Players will now be offered either a net sliding scale or gross split sliding scale to replace the traditional PSC model, according to ministry of energy & mineral resources director general of oil and gas, Gusti Nyoman Wiratmaja.
"From now on we are going to offer another option, which is a net sliding scale production sharing contract, and also the option of gross split sliding scale," Wiratmaja told an investment seminar during a recent conference in Singapore.
The traditional unconventional PSC terms offer a fixed pre-tax profit split of 75:25 in favour of the contractor, but the new models both offer sliding scales.
For the net sliding-scale PSC, the contractors' take is between 99% for production below 1bn cf of gas and incrementally falling to 75% for output above 100bn cf, measured on a yearly basis.
On the gross split sliding scale PSC, contractors get 95% before tax on production below 5bn cf of gas and that falls in stages to 75% for output above 100bn cf. By making the split between the government and contractors more progressive, the government expects that CBM development will be more attractive to investors.
"The progression is aimed at giving a good pay-back period for investors because the development of non-conventional gas takes time and developers have to go through de-watering process and low output in the beginning" Wiratmaja said.
He added that the government is targeting CBM production of around 100m cf/d over the next five to ten years following the implementation of the new scheme. "We will see the start of big production in 2025. We hope that contractors of the current 54 blocks will start drilling following the new policy," he added. Since 2008, 54 working areas for CBM have been approved. But there has been little progress as the traditional commercial terms did not make economic sense for the marginal fields, while the technical regulations, which are being redrafted, complicated CBM's progress too.
Under a previous target, the government eyed CBM output of 500m cf/d in 2015. That was later drastically cut to 8.9m cf/d. Output in 2014 was only around 625,000 cf/d.
Indonesia also has an estimated 46 trillion cf of technically recoverable shale gas resources out of 303 trillion cf of shale gas in-place, according to the US Energy Information Administration (EIA).
This is a lot less than the 574 trillion cf estimated by Indonesia's upstream regulator; while a study from the Bandung Technology University puts it even higher at 1 quadrillion cf. But apart from optimism, there is no known rationale for these latter assessments.
Western Indonesia tends to be dominated by structurally simple, non-marine shales. On the other hand, geology of eastern Indonesia -Sulawesi, Seram, Buru and Irian Jaya - is tectonically more complex but has excellent marine-deposited shale source rocks, a report from US consultancy Advanced Resources International shows.
The nation has received more than 70 proposals for shale gas projects, the bulk of which focus on Sumatra, East Kalimantan, Central Kalimantan and West Papua. In November, Jakarta invited bids for three shale gas blocks - Blora, onshore Central and East Java; Batu Ampar in East Kalimantan; and Central Bangkanai, onshore Central and East Kalimantan. Basins in Sumatra lie close to markets in Java, the archipelago's most populous island; while basins in Kalimantan lie close to the 22.5m t/y Bontang LNG export terminal, which is operating well below its name-plate capacity. Any finds in Kalimantan could be brought to market through the LNG plant.
A $25bn refinery overhaul is on the drawing board as part of Jokowi's push to cut Indonesia's rising oil import dependence and boost energy security.
The nation is short of gasoline and gasoil. It typically imports between 9m and 10m barrels of gasoline and between 2.5m and 3.5m barrels of gasoil every month, making it the region's largest importer.
Pertamina has a total refining capacity of 1.04m b/d. But it typically churns out just 800,000 b/d to 850,000 b/d as its refineries are old and inefficient.
Given the continuing decline of Indonesia's oil production, the country will need to import more crude to feed any expansion in refining.
Under the ambitious upgrade and expansion plan, for which preliminary agreements were signed in December 2014, the refining capacity was expected to rise to 1.68m b/d over the next decade.
Four new refineries have been proposed, each with capacities ranging between 300,000 b/d and 350,000 b/d.
Talks have been ongoing with Japan's JX Nippon Oil & Energy to refurbish Pertamina's Balikpapan refinery, while Saudi Aramco, the country's largest crude supplier, is in discussions to revamp three other domestic plants.
But nearly one year on and the plans are already faltering. First it was the small, remote Plaju refinery, which was removed from the upgrade list as the additional investment was seen as uneconomical. China's Sinopec had initially been earmarked as a partner.
Meanwhile, talks with Saudi Aramco appear to have stalled. The main sticking point has been the extent of the potential partner's participation in Indonesia's retail fuel sector, which is dominated by Pertamina. More specifically, the size of the stake the Saudis might be able to get in the downstream market in exchange for participating in the upgrade project is a point of contention.
Indonesia is seen as a lucrative market with potential oil demand growing at 6% every year driven by the transport sector. But unless the nation can expand its refining capabilities, it will be the big refiners in South Korea, India and Singapore that will have to meet the Indonesia's expanding needs.
Pertamina has set a deadline to wrap up agreements for investment in the existing 348,000 b/d Cilacap and 260,000 b/d Balikpapan refineries before the end of 2015; and for the 125,000 b/d Balongan and 170,000 b/d Dumai plants by the end of 2016. Saudi Aramco was picked for the Dumai, Cilacap and Balongan refineries. Pertamina has said it will seek new partners if the companies fail to strike a deal by the deadline.
JX Nippon Oil & Energy was chosen for the Balikpapan refinery, with plans for a $5m joint investment nearly complete, Pertamina's chief executive, Dwi Soetjipto, said in Tokyo early November.
Indonesia has not had a successful refinery venture in decades, with the last project built in the mid-1990s. Since then, companies including China's Sinopec, Japan's Mitsui, Kuwait Petroleum and Saudi Aramco, have all explored projects that failed to materialise.
Pertamina has said it needs to build an additional five to eight refineries to meet domestic demand in 2025. But given its track record and the uncertain investment environment this seems ambitious.
Indonesia in numbers
Oil (42.3% of Indonesia's total energy demand) remains the dominant fuel followed by coal (34.8%), gas (19.8%), hydro (1.9%), and renewables in power (1.3%)
Indonesia produced 56% of its total oil consumption, the lowest proportion ever, and the seventh consecutive decline in this ratio
Natural gas production marginally recovered in 2014, after three consecutive years of declines, and remains 14% lower than the 2010 production peak
Domestic energy consumption doubled over the last 16 years, led by growth in fossil fuels
Indonesia's energy production grew by just 1.4%, its lowest growth rate since 1988
Oil production continued to decline, falling to its lowest level since 1969
Figures relate to 2014. Source: BP Statistical Review 2015