George Barber

Country Manager Indonesia at Terra Energy & Resource Technologies, (TERT) Inc.
Last Updated: June 10, 2017
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Exploration
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I was honored to be asked to write the following article for the Jakarta Post's special edition that was published for the Indonesian Petroleum Association (IPA) 2017 Conference and Exhibition.

This article covers four main areas for oil and natural gas prospecting in Indonesia as follows: Prospective, quality and depth of geological data, regulations, and incentives, and what needs to be done.

Prospective reserves similar to the Duri and Minas fields which were discovered during the second world war will be difficult to find and may not exist, but who knows for sure? 

The oil discovery in Cepu, Central - East Java area was only 600 MMBO. However, if we are looking for oil fields of 20 - 50 or 100 MMBO reserves that are close enough to processing facilities, it is believed that these fields do exist. 

The Pre-Tertiary Arafura - West Papua, Banda Arch and Bintuni - Salawati Basins are considered prospective for future exploration targets. The USGS has estimated that the mean total of undiscovered resources for oil, gas and NGL from the three geologic provinces, are 4.566 BBO, 60.836 TCFG and 1.839 BBNGL respectively. In Java, pre-volcanic resources along the island are good future exploration targets. There are many sedimentary basins covered by volcanic rocks from the young quaternary volcanoes, numerous oil and gas seeps that have occurred in the volcanic areas of Java Island, geochemically correlated to the pre-volcanic sources. This indicates the presence of active petroleum systems underneath the volcanic covers. Fractured basement reservoirs are also future exploration opportunities, both in Western and Eastern Indonesia. Lessons learned from global success stories are encouraging and need to be heeded by Indonesian Geoscientists.

Many of the deeper horizons have not been properly imaged; stratigraphic traps have not been fully explored. Basins below the young volcanic's can be explored using Innovative technology; so far Magnetotelluric, Gravity and Magnetics have been used to try to image these formations with limited success. 

It was stated recently by a respected Earth Scientist (ex Chevron) “that many of the so-called Mature Fields could be classified as New Fields” if new ideas for exploration are adopted. There is a huge potential to develop these, they can become like new discoveries, just by understanding the structure of the reservoirs in detail, albeit some of the reserves may be small in size from 20 to 100 MMBO, they may not be commercially attractive, but if we look at some fields in the USA that only produce 1 – 2 BPD, small fields can become prospective, using mobile processing plants is one answer. As we like to say, “there is more than one way to skin a cat”.

The quality and depth of data that is being offered to potential investors is generally poor, a lot of the data was gathered during 1960 - 2000, as well as data from the Dutch and Japanese occupation eras. Indonesia has complicated geology, deep-water areas, it covers a large area with difficult terrain, which means it is expensive and time-consuming to explore by traditional methods.

An experienced geologist stated that when they went exploring, “they knew that their chances of success were in the region of twenty percent”, this is far too low, the chances of success has to be increased to sixty or eighty percent. 

The reality is, Indonesia’s oil & gas potential is still not well explored, huge potential still awaits discovery. Innovative technology is required which can be integrated with existing data; this then becomes a new cycle of exploration, targeting the deep and smaller structural and stratigraphic traps, as well as the overlooked shallow targets, both onshore and offshore.

In regard to regulations and incentives, for Indonesia to be aware of its resources and reach its full potential, improvements are needed in the legal and regulatory frameworks as well as fiscal incentives to attract investment.

This needs consistency of regulations and not a constant change of ministers, changes of top positions in the state-owned oil company, all of whom have their own ideas, this has resulted in many changes of staff in key positions, which means there has been very little stability in policies. Indonesia has become more protective, giving more responsibility to the state-owned company; it is well known that national companies do not perform as well as private companies that are answerable to their shareholders. Indonesia’s resource industry is not the most attractive for local and international investors.

The government of Indonesia (GOI) has introduced several regulations such as the “Gross Split” scheme, although in my opinion, none of these address’s the real issue, which is simple “reliable resource data is required” the only way to obtain reliable data is to carry out exploration, the GOI is still expecting investors to be interested in tendering for a license, although the terms are not conducive for investors. If local banks and entrepreneurs will not invest in the exploration of their country’s resources as they consider that the risk is too high, how can Indonesia expect international investment? (if they even want it, as Indonesian politics has boosted the appeal of resource nationalism within policymaking circles). They cannot, although the GOI constantly states, we need investment to carry out exploration.

Credit has to be given to the regulators for addressing some of the problems, although one wonders if the bigger picture is being looked at. All anyone seems to talk about is the low price of oil, it is stated that exploration is too expensive and the cost of oil is too low, this is a "Chicken and Egg" situation, be time the price goes up (if ever) we start exploration, then the cost of oil comes down, the next excuse is that the cost of oil is too low to exploit what has been found, this is the scenario if we continue to explore with traditional methods. What happened when the price of oil was high?

It also does not help when amendments to the 2001 oil and gas law are delayed or pending at the “House of Representatives” for the past four years. Although it is understood that the final draft has just been submitted as I am publishing this article, although it is expected the regulations will be some time before it is finalized. 

What is the solution? The GOI along with the private sector of Indonesia should bring the banks on board to invest in their own country for a comprehensive knowledge of the country's resources, we all know that to explore the whole of Indonesia is not possible, due to terrain, geology, cost and time, which makes many parts of Indonesia unexplorable, therefore Indonesia will never know what resources it truly has, it will continue to say we are rich in resources without knowing where they are. Indonesia should know what resources it has, Indonesia can not keep saying it is rich in resources without being able to support this statement.

Therefore the GOI needs to be responsible for the exploration of their own country, both onshore and offshore, different methods of exploration that enhances traditional methods has to be used, methods that have been well proven but not believed by many geoscientists in Indonesia because they are not aware of other methods other than traditional methods, minds have to be opened to innovative ideas, not just “Smart Phone Technology”.

By having reliable resource data, it will attract investors, although if Indonesia continues to expect investors to take all of the risks, investment is not going to happen. Recently several blocks have been tendered with very little if any interest, sorry to say, it is not just the oil price that is unattractive, the terms and conditions are also unattractive, is anyone really asking the question, why are investors not interested? 

Anyone who tenders for a block needs to be assured that they have a reasonable chance of success, not a 10 - 20% chance of success, but a 60 – 80% chance, this then becomes interesting. The cost to tender can be increased as the data in the data bank means something, then the gross split may work, as the investor knows that they will get a return on their investment. 

The technology is available that allows Indonesia to be fully aware of its resource potential, which will allow traditional tools of exploration such as seismic to become a confirmation tool instead of an exploration tool, in areas that seismic is effective, not in volcanic areas. 

At the end of the day, if geologists are honest with themselves, they need help, they need data and they need jobs, exploration is not happening as it should for all the reasons that have been stated, the solutions are available.

We should not be drilling unless we know that the risk has been reduced, the cost of innovative exploration is a fraction of drilling a dry hole on land and offshore in deep water, Innovative Exploration Technology needs be used which supports and enhances the knowledge of any given area. The whole of Indonesia then becomes explorable.

Indonesia needs to invest in its self, it needs innovative ideas to achieve its goals. 

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Iran drives unplanned OPEC crude oil production outage to highest levels since late 2015

Unplanned crude oil production outages for the Organization of the Petroleum Exporting Countries (OPEC) averaged 2.5 million barrels per day (b/d) in the first half of 2019, the highest six-month average since the end of 2015. EIA estimates that in June, Iran alone accounted for more than 60% (1.7 million b/d) of all OPEC unplanned outages.

EIA differentiates among declines in production resulting from unplanned production outages, permanent losses of production capacity, and voluntary production cutbacks for OPEC members. Only the first of those categories is included in the historical unplanned production outage estimates that EIA publishes in its monthly Short-Term Energy Outlook (STEO).

Unplanned production outages include, but are not limited to, sanctions, armed conflicts, political disputes, labor actions, natural disasters, and unplanned maintenance. Unplanned outages can be short-lived or last for a number of years, but as long as the production capacity is not lost, EIA tracks these disruptions as outages rather than lost capacity.

Loss of production capacity includes natural capacity declines and declines resulting from irreparable damage that are unlikely to return within one year. This lost capacity cannot contribute to global supply without significant investment and lead time.

Voluntary cutbacks are associated with OPEC production agreements and only apply to OPEC members. Voluntary cutbacks count toward the country’s spare capacity but are not counted as unplanned production outages.

EIA defines spare crude oil production capacity—which only applies to OPEC members adhering to OPEC production agreements—as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices. EIA does not include unplanned crude oil production outages in its assessment of spare production capacity.

As an example, EIA considers Iranian production declines that result from U.S. sanctions to be unplanned production outages, making Iran a significant contributor to the total OPEC unplanned crude oil production outages. During the fourth quarter of 2015, before the Joint Comprehensive Plan of Action became effective in January 2016, EIA estimated that an average 800,000 b/d of Iranian production was disrupted. In the first quarter of 2019, the first full quarter since U.S. sanctions on Iran were re-imposed in November 2018, Iranian disruptions averaged 1.2 million b/d.

Another long-term contributor to EIA’s estimate of OPEC unplanned crude oil production outages is the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. Production halted there in 2014 because of a political dispute between the two countries. EIA attributes half of the PNZ’s estimated 500,000 b/d production capacity to each country.

In the July 2019 STEO, EIA only considered about 100,000 b/d of Venezuela’s 130,000 b/d production decline from January to February as an unplanned crude oil production outage. After a series of ongoing nationwide power outages in Venezuela that began on March 7 and cut electricity to the country's oil-producing areas, EIA estimates that PdVSA, Venezuela’s national oil company, could not restart the disrupted production because of deteriorating infrastructure, and the previously disrupted 100,000 b/d became lost capacity.

July, 18 2019
The Strait of Hormuz and Oil Prices

The UK has just designated the Persian Gulf as a level 3 risk for its ships – the highest level possible threat for British vessel traffic – as the confrontation between Iran with the US and its allies escalated. The strategically-important bit of water - and in particular the narrow Strait of Hormuz – is boiling over, and it seems as if full-blown military confrontation is inevitable.

The risk assessment comes as the British warship HMS Montrose had to escort the BP oil tanker British Heritage out of the Persian Gulf into the Indian Ocean from being blocked by Iranian vessels. The risk is particularly acute as Iran is spoiling for a fight after the Royal Marines seized the Iranian crude supertanker Grace-1 in Gibraltar on suspicions that it was violating sanctions by sending crude to war-torn Syria. Tensions over the Gibraltar seizure kept the British Heritage tanker in ‘safe’ Saudi Arabian waters for almost a week after making a U-turn from the Basrah oil terminal in Iraq on fears of Iranian reprisals, until the HMW Montrose came to its rescue. Iran’s Revolutionary Guard Corps have warned of further ‘reciprocation’ even as it denied the British Heritage incident ever occurred.

This is just the latest in a series of events around Iran that is rattling the oil world. Since the waivers on exports of Iranian crude by the USA expired in early May, there were four sabotage attacks on oil tankers in the region and two additional attacks in June, all near the major bunkering hub of Fujairah. Increased US military presence resulted in Iran downing an American drone, which almost led to a full-blown conflict were it not for a last-minute U-turn by President Donald Trump. Reports suggest that Iran’s Revolutionary Guard Corps have moved military equipment to its southern coast surrounding the narrow Strait of Hormuz, which is 39km at its narrowest. Up to a third of all seaborne petroleum trade passes through this chokepoint and while Iran would most likely overrun by US-led forces eventually if war breaks out, it could cause a major amount of damage in a little amount of time.

The risk has already driven up oil prices. While a risk premium has already been applied to current oil prices, some analysts are suggesting that further major spikes in crude oil prices could be incoming if Iran manages to close the Strait of Hormuz for an extended period of time. While international crude oil stocks will buffer any short-term impediment, if the Strait is closed for more than two weeks, crude oil prices could jump above US$100/b. If the Strait is closed for an extended period of time – and if the world has run down on its spare crude capacity – then prices could jump as high as US$325/b, according to a study conducted by the King Abdullah Petroleum Studies and Research Centre in Riyadh. This hasn’t happened yet, but the impact is already being felt beyond crude prices: insurance premiums for ships sailing to and fro the Persian Gulf rose tenfold in June, while the insurance-advice group Joint War Committee has designated the waters as a ‘Listed Area’, the highest risk classification on the scale. VLCC rates for trips in the Persian Gulf have also slipped, with traders cagey about sending ships into the potential conflict zone.

This will continue, as there is no end-game in sight for the Iranian issue. With the USA vague on what its eventual goals are and Iran in an aggressive mood at perceived injustice, the situation could explode in war or stay on steady heat for a longer while. Either way, this will have a major impact on the global crude markets. The boiling point has not been reached yet, but the waters of the Strait of Hormuz are certainly simmering.

The Strait of Hormuz:

  • Connects the Persian Gulf to the Gulf of Oman/Indian Ocean
  • Length: 167km
  • Width: 96km (widest) to 39km (narrowest)
  • Controlled by Iran, the UAE and Musandam (Oman)
  • The conduit for 33% of all LNG trade and 20% of total crude oil demand
July, 16 2019
Your Weekly Update: 8 - 12 July 2019

Market Watch 

Headline crude prices for the week beginning 8 July 2019 – Brent: US$64/b; WTI: US$57/b

  • Bolstered by the renewed OPEC+ supply pact but rattled by increasing tensions between Iran and the US, oil prices started the week steady after gaining over the previous week
  • With the OPEC+ supply deal extended to March 2020, focus will now shift to adherence and in particular, Russian commitments to the agreement that previously wavered over 1H19
  • More critical to the market is the escalating standoff between the US and Iran around the Straits of Hormuz and even beyond; British forces seized an oil tanker off Gibraltar that was suspected to carrying Iranian crude to Syria, drawing share criticism from Iran
  • Iran itself confirmed that it was raising its level of nuclear enrichment above levels agreed to in the 2015 deal that ended sanctions, and accused European signatories to the deal of ‘not doing enough’
  • Iranian forces also confronted a British tanker escorted by a warship in the Persian Gulf, with the narrow channel now a flashpoint for action
  • As a recipient of Middle Eastern crude, China has also raised security levels for its vessel passing through the Straits of Malacca after doing the same for the Straits of Hormuz, raising some eyebrows
  • While the confrontation – or lack of – between the US and Iran will be the main driver behind oil prices movement in the second half of 2019, the trade policies of the Trump administration that may now hit secondary Asian manufacturing nations such as Vietnam is also leaving the global economy increasingly fragile
  • Against this backdrop, the US active oil and gas rig count fell again, dropping five oil sites and gaining one gas site for a net loss of four rigs
  • As the Iranian situation deteriorates, the market will be pricing more risk premiums into traded prices, which should inch up towards the US$65-67/b range for Brent and US$59-61/b for WTI

Headlines of the week

Upstream

  • Marathon Oil has completed the sale of its UK businesses to RockRose Energy, handing over the Brae and Foinaven area fields for US$345 million
  • Despite pulling out from the UK North Sea, ConocoPhillips is still active in Norway, recently submitting a new plan to re-develop the Tor field in Great Ekofisk, which was shut down in 2015 despite only 20% of resources extracted
  • In a bit to boost national production, Nigerian independent Aiteo Eastern E&P has announced plans to spend up to US$15 billion over the next five years to drill new wells and re-visit existing assets
  • Eni and Vitol have been awarded rights to Block WB03 in the offshore Tano basin in Ghana, with Eni holding 70% and expanding its presence in the country
  • Total has approved Phase 3 development at the onshore Dunga field in Kazakhstan that will increase capacity by 10% to some 20,000 b/d by 2022
  • Eni has launched production from the Mizton field in Mexico’s Bay of Campeche Area 1 – the first new offshore new field development by an international firm since reforms in 2008
  • Halliburton and Kuwait Oil have signed an agreement to explore for oil offshore Kuwait which makes Kuwait’s first foray in offshore upstream services
  • Energean Oil & Gas has purchased Electricite de France’s Italian unit for US$850 million, gaining assets in Egypt, Italy, Algeria, Croatia and the North Sea to complement its existing fields in Israel and Greece

Midstream/Downstream

  • China will be launching a new low-sulfur bunker fuel oil contract on the Shanghai Futures Exchange by the end of 2019, just as new IMO regulations on marine fuel oil sulfur content caps kick into effect in 2020
  • Just as American crude production hits new highs, American refining capacity has also reached a new record high of 18.8 million b/d
  • China has issued a new round of crude oil import quotas for private oil refiners, allowing them to bring in an additional 56.85 million tonnes (~1 mmb/d) over the remainder of 2019
  • In the fallout over the contaminated crude scandal at the Druzhba pipeline, Russian pipeline operator Transneft has capped volumes of Rosneft crude that can be transported to Germany and Poland on the pipeline
  • The US Environmental Protection Agency (EPA) has proposed an increased biodiesel mandate to 20.04 billion gallons in 2020 up from 19.92 billion gallons in 2019, but may not extend the hardship waiver program which drew criticism
  • Iraq and Oman have signed a new MoU to cooperate in the oil and gas sector which includes plans for a shared Omani refinery processing Iraqi crude

Natural Gas/LNG

  • Kosmos Energy has struck new gas at the Greater Tortue Ahmeyim-1 well in the Albian reservoir offshore Mauritania and Senegal, which will support the Greater Tortue Ahmeyim LNG project that is on track for a 2022 start
  • Kenya and Tanzania have entered into talks to explore cross-border natural gas trading, aimed at delivering Tanzanian natural gas to Kenya to bypass requiring and building facilities for LNG imports
  • Energean Oil & Gas is reportedly looking to sell its stake in the major Glengorn gas discovery in the UK once its acquisition of Edison E&P is completed
  • Saudi Aramco has started work on the Jafurah gas terminal that will take unconventional gas from the Ghawar oil field to the coast for processing
July, 12 2019