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The title of this article is the title of a recent three day workshop that was organized by SkkMigas that had apparently been arranged due to the concern that Indonesia has with the ever-growing gap between the demand for oil and what is being produced in the country, as well as the ever-increasing concern about the economics of the country with the spending on infrastructure projects being a concern and development in the natural resource industry not being as expected.
There are other concerns, such as the ever-growing reliance on Pertamina to take over blocks from International companies, to develop existing and hopefully new blocks, or a recent headline: Pertamina sells off shares to stay afloat, or the concern of Pertamina to meet the government’s policy of ensuring the availability of Premium grade fuel at one price throughout the whole country. One senior person from Pertamina said to me recently, we will survive until the election, but what happens after that, who knows.
This makes one wonder, how will Pertamina develop new or existing blocks? How will they carry out the exploration that is needed to meet the subject of this opinion piece which is an interesting title in itself for many reasons. When I was asked about finding Giant Oil & Gas Fields by Badan Geology, I said, Pak, the chances of finding Giant Fields is fairly low, because if they were available they would have been found by now with existing methods of exploration. I was to learn that what they meant by Giant Fields is anything that contains a probable reserve of 500 million barrels of oil, (Giant oil and gas fields = those with 500 million barrels (79,000,000 m3) of ultimately recoverable oil or gas equivalent. Supergiant oil field = holds equivalent of 5.5bn barrels of oil reserves).
This is a different story then, as it is known that there are fields that contain this amount and above, just waiting to be confirmed and exploited, one such field has been known about for several years which contains something in the region of 1 billion barrels of oil, as well as gas and condensate, but due to political and other reasons this has not been developed until now.
The author of this article has written several times that Indonesia does have the potential to be self-supportive in resources, if only the knowledge of the country’s resources was known, sadly to say until now, the potential of the country’s resources is just that, potential. What has become apparent from the workshop organized by SkkMigas is that many people are concerned with the situation, but very few (if any) are prepared to take the risk for exploration, which does include the country’s own banks and entrepreneurs. What does risk mean? Put simply, it means loss of money. In my view, Indonesia is no different to any other country, the people in the country do not like to lose money, so why does Indonesia expect investors from other countries to lose money when they are not prepared to accept the risk themselves?
How to minimize the risk?, how to increase the success rate from 15%?, which is what Pertamina achieved last year for drilling of new wells, although this is not too far below the accepted success rate within the industry which is in the region of 20 – 25% (the normal). These figures can of course be argued about from company to company, but the overall success rate is low, if you were a gambling person, you would unlikely accept these odds. The answer is simple, technology, a technology that has been developed by people of the trade, not by some mad scientist, technology that has been used in different countries with a high success rate. Contrary to believe, Indonesia is no different to any other country when it comes to geology, yes Indonesia has complex geology such as volcanics in Java, deep water in East Indonesia, difficult terrain in Papua where some of the technology that is used today does not allow a detailed exploration survey to be carried out. I can name a number of other countries that have extremely complicated geology that has been successfully explored with technology. The old excuse that the technology has not been used in Indonesia does not wash, how can it be used if people do not want to accept technology readily? It does appear that SkkMigas is waking up, they realize that if they do not adapt to new technology faster, then the situation will not improve.
Technology that we take for granted has come a long way in the past twenty or more years, where did the technology come from? Normally technology comes from someone seeing a problem and asking a simple question, how can we do this better. I was giving a presentation the other day, when someone said, we have not been taught this in University, so how can we believe that this works, where I replied, it has been proven in many other countries with a high success rate, can you as a geologist work in another country, where the answer was “of course we can” where my reply was, if you can do this, why can technology that works in these countries not work in Indonesia? Technology that has been developed by people such as yourself which is based on geology, of course, there was no reply.
The point of this article is that Indonesia appears to be ready to accept technology, although there are still divisions within the government (ESDM) where you have so many different interests, what is required is that one central policy is required for technology and not so many different empires, it should be united.
Most people will accept technology from the medical industry that can save life’s, the same people in the exploration industry are reluctant to accept technology that not only improves the success rate of exploration but will create jobs for people as companies are exploring at reduced costs which in turn relates to reduced risk.
Indonesia does have the potential to meet its energy needs, to meet its goals that are agreed with increased success and reduced costs, as long as people are willing to accept technology and make decisions.
“Baby Giant Fields” are waiting to be discovered.
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Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that annual U.S. crude oil production will average 11.1 million b/d in 2021, down 0.2 million b/d from 2020 as result of a decline in drilling activity related to low oil prices. A production decline in 2021 would mark the second consecutive year of production declines. Responses to the COVID-19 pandemic led to supply and demand disruptions. EIA expects crude oil production to increase in 2022 by 0.4 million b/d because of increased drilling as prices remain at or near $50 per barrel (b).
The United States set annual natural gas production records in 2018 and 2019, largely because of increased drilling in shale and tight oil formations. The increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices. In 2020, marketed natural gas production fell by 2% from 2019 levels amid responses to COVID-19. EIA estimates that annual U.S. marketed natural gas production will decline another 2% to average 95.9 billion cubic feet per day (Bcf/d) in 2021. The fall in production will reverse in 2022, when EIA estimates that natural gas production will rise by 2% to 97.6 Bcf/d.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
EIA’s forecast for crude oil production is separated into three regions: the Lower 48 states excluding the Federal Gulf of Mexico (GOM) (81% of 2019 crude oil production), the GOM (15%), and Alaska (4%). EIA expects crude oil production in the U.S. Lower 48 states to decline through the first quarter of 2021 and then increase through the rest of the forecast period. As more new wells come online later in 2021, new well production will exceed the decline in legacy wells, driving the increase in overall crude oil production after the first quarter of 2021.
Associated natural gas production from oil-directed wells in the Permian Basin will fall because of lower West Texas Intermediate crude oil prices and reduced drilling activity in the first quarter of 2021. Natural gas production from dry regions such as Appalachia depends on the Henry Hub price. EIA forecasts the Henry Hub price will increase from $2.00 per million British thermal units (MMBtu) in 2020 to $3.01/MMBtu in 2021 and to $3.27/MMBtu in 2022, which will likely prompt an increase in Appalachia's natural gas production. However, natural gas production in Appalachia may be limited by pipeline constraints in 2021 if the Mountain Valley Pipeline (MVP) is delayed. The MVP is scheduled to enter service in late 2021, delivering natural gas from producing regions in northwestern West Virginia to southern Virginia. Natural gas takeaway capacity in the region is quickly filling up since the Atlantic Coast Pipeline was canceled in mid-2020.
Just when it seems that the drama of early December, when the nations of the OPEC+ club squabbled over how to implement and ease their collective supply quotas in 2021, would be repeated, a concession came from the most unlikely quarter of all. Saudi Arabia. OPEC’s swing producer and, especially in recent times, vocal judge, announced that it would voluntarily slash 1 million barrels per day of supply. The move took the oil markets by surprise, sending crude prices soaring but was also very unusual in that it was not even necessary at all.
After a day’s extension to the negotiations, the OPEC+ club had actually already agreed on the path forward for their supply deal through the remainder of Q1 2021. The nations of OPEC+ agreed to ease their overall supply quotas by 75,000 b/d in February and 120,000 b/d in March, bringing the total easing over three months to 695,000 b/d after the UAE spearheaded a revised increase of 500,000 b/d for January. The increases are actually very narrow ones; there were no adjustments for quotas for all OPEC+ members with the exception of Russia and Kazakshtan, who will be able to pump 195,000 additional barrels per day between them. That the increases for February and March were not higher or wider is a reflection of reality: despite Covid-19 vaccinations being rolled out globally, a new and more infectious variant of the coronavirus has started spreading across the world. In fact, there may even be at least of these mutations currently spreading, throwing into question the efficacy of vaccines and triggering new lockdowns. The original schedule of the April 2020 supply deal would have seen OPEC+ adding 2 million b/d of production from January 2021 onwards; the new tranches are far more measured and cognisant of the challenging market.
Then Saudi Arabia decides to shock the market by declaring that the Kingdom would slash an additional million barrels of crude supply above its current quota over February and March post-OPEC+ announcement. Which means that while countries such as Russia, the UAE and Nigeria are working to incrementally increase output, Saudi Arabia is actually subsidising those planned increases by making a massive additional voluntary cut. For a member that threw its weight around last year by unleashing taps to trigger a crude price war with Russia and has been emphasising the need for strict compliant by all members before allowing any collective increases to take place, this is uncharacteristic. Saudi Arabia may be OPEC’s swing producer, but it is certainly not that benevolent. Not least because it is expected to record a massive US$79 billion budget deficit for 2020 as low crude prices eat into the Kingdom’s finances.
So, why is Saudi Arabia doing this?
The last time the Saudis did this was in July 2020, when the severity of the Covid-19 pandemic was at devastating levels and crude prices needed some additional propping up. It succeeded. In January 2021, however, global crude prices are already at the US$50/b level and the market had already cheered the resolution of OPEC+’s positions for the next two months. There was no real urgent need to make voluntary cuts, especially since no other OPEC member would suit especially not the UAE with whom there has been a falling out.
The likeliest reason is leadership. Having failed to convince the rest of the OPEC+ gang to avoid any easing of quotas, Saudi Arabia could be wanting to prove its position by providing a measure of supply security at a time of major price sensitivity due to the Covid-19 resurgence. It will also provide some political ammunition for future negotiations when the group meets in March to decide plans for Q2 2021, turning this magnanimous move into an implicit threat. It could also be the case that Saudi Arabia is planning to pair its voluntary cut with field maintenance works, which would be a nice parallel to the usual refinery maintenance season in Asia where crude demand typically falls by 10-20% as units shut for routine inspections.
It could also be a projection of soft power. After isolating Qatar physically and economically since 2017 over accusations of terrorism support and proximity to Iran, four Middle Eastern states – Saudi Arabia, Bahrain, the UAE and Egypt – have agreed to restore and normalise ties with the peninsula. While acknowledging that a ‘trust deficit’ still remained, the accord avoids the awkward workarounds put in place to deal with the boycott and provides for road for cooperation ahead of a change on guard in the White House. Perhaps Qatar is even thinking of re-joining OPEC? As Saudi Arabia flexes its geopolitical muscle, it does need to pick its battles and re-assert its position. Showcasing political leadership as the world’s crude swing producer is as good a way of demonstrating that as any, even if it is planning to claim dues in the future.
It worked. It has successfully changed the market narrative from inter-OPEC+ squabbling to a more stabilised crude market. Saudi Arabia’s patience in prolonging this benevolent role is unknown, but for now, it has achieved what it wanted to achieve: return visibility to the Kingdom as the global oil leader, and having crude oil prices rise by nearly 10%.
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