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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Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b
Headlines of the week
Midstream & Downstream
The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.
The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.
Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.
For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.
All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.
Supermajor Financials: Q1 2019
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions
In its May 2019 edition of the Short-Term Energy Outlook (STEO), EIA revised its price forecast for Brent crude oil upward, reflecting price increases in recent months, more recent data, and changing expectations of global oil markets. Several supply constraints have caused oil markets to be generally tighter and oil prices to be higher so far in 2019 than previous STEOs expected.
Members of the Organization of the Petroleum Exporting Countries (OPEC) had agreed at a December 2018 meeting to cut crude oil production in the first six months of 2019; compliance with these cuts has been more effective than EIA initially expected. In the January STEO, OPEC’s crude oil and petroleum liquids production was expected to decline by 1.0 million b/d in 2019 compared with the 2018 level, but EIA now forecasts OPEC production to decline by 1.9 million b/d in the May STEO.
Within OPEC, EIA expects Iran’s liquid fuels production and exports to also decline. On April 22, 2019, the United States issued a statement indicating that it would not reissue waivers, which previously allowed eight countries to continue importing crude oil and condensate from Iran after their waivers expired on May 2. Although EIA’s previous forecasts had assumed that the United States would not reissue waivers, the increased certainty regarding waiver policy and enforcement led to lower forecasts of Iran’s crude oil production.
Venezuela—another OPEC member—has experienced declines in production and exports as a result of recurring power outages, political instability, and U.S. sanctions. In addition to supply constraints that have already materialized in 2019, political instability in Libya may further affect global supply. Any further escalation in conflict may damage crude oil infrastructure or result in a security environment where oil fields are shut in. Either situation could reduce global supply by more than EIA currently forecasts.
In the May STEO, total OPEC crude oil and other liquids supply was estimated at 37.3 million b/d in 2018, and EIA forecasts that it will average 35.4 million b/d in 2019. EIA assumes that the December 2018 agreement among OPEC members to limit production will expire following the June 2019 OPEC meeting.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions
U.S. crude oil and other liquids production is sensitive to changes in crude oil prices, taking into account a lag of several months for drilling operations to adjust. As crude oil prices have increased in recent months, so too have EIA’s domestic liquid fuels production forecasts for the remaining months of 2019.
U.S. crude oil and other liquids production, which grew by 2.2 million b/d in 2018, is forecast in EIA’s May STEO to grow by 2.0 million b/d in 2019, an increase of 310,000 b/d more than anticipated in the January STEO. In 2019, EIA expects overall U.S. crude oil and liquids production to average 19.9 million b/d, with crude oil production alone forecast to average 12.4 million b/d.
Relative to these changes in forecasted supply, EIA’s changes in forecasted demand were relatively minor. EIA expects that global oil markets will be tightest in the second and third quarters of 2019, resulting in draws in global inventories. By the fourth quarter of 2019, EIA expects that inventories will build again, and Brent crude oil prices will fall slightly.
More information about changes in STEO expectations for crude oil prices, supply, demand, and inventories is available in This Week in Petroleum.