Join NrgEdge to View Member's Profile. It's Free
Fill up your particulars with:
Fill up your particulars with:
It has been almost five years since the giant Khafji field shared between Saudi Arabia and Kuwait was shut down. Ostensibly on environmental concerns, this precipitated a halt of all activities in the so-called Neutral Zone – a colonial-era border relic that holds a significant amount of oil and gas. After years of stop-start negotiations, reports are now suggesting that the OPEC allies are close to a breakthrough on the matter, which could return up to 500,000 b/d of oil to the market at a crucial time for the global oil supply/demand balance.
Left undefined by the Uqair Convention of 1922 that otherwise established concrete borders for Saudi Arabia and Kuwait, the dry piece of land that is 8 times the size of Singapore was mostly ignored until 1938, when the Burgan oil field was discovered within Kuwait’s borders. A race for exploration began, with Saudi Arabia and Kuwait both awarding overlapping concessions to private companies and Getty Oil finally striking oil in 1948. The Wafra field was discovered in 1953, and in 1960, Japan’s Arabian Oil Company (which held an offshore concession awarded by Saudi Arabia in 1957 and another awarded by Kuwait in 1958) discovered the giant Khafji offshore field. Overlapping claims of sovereignty did not prevent exploitation of the resources, but opaque rights eventually led to a formal partition in 1970 where it was agreed that Saudi Arabia and Kuwait would split production equally under a joint operating agreement. The unique status of the Neutral Zone is exemplified by its structure – its largest onshore oil field (Wafra) is operated by Chevron, the only remaining place in Saudi Arabia and Kuwait where a major asset is held by an international firm.
And it was this arrangement that caused the current quandary. Chevron inherited the Neutral Zone assets through its merger with Texaco in 2001, which itself bought Getty Oil in 1984. In 2009, Saudi Arabia renewed Chevron’s concession for Wafra independently, angering Kuwait as the negotiations were performing without its consultation. Kuwait responded by attempting to evict Chevron from its offices in the Neutral Zone, claiming that the land was planned for the giant Ras al Zour refinery. More tit-for-tat moves escalated and eventually Saudi Arabia shut down Khafji in October 2014 and the entire Neutral Zone in May 2015, removing 500,000 b/d of crude oil from the market in one fell swoop.
That may be coming back now, with Saudi Energy Minister Khalid al-Falih stating that he hopes to reach a deal to resume production by the end of this year. It’ll be a boon not only to both countries, but also Chevron, which was in the midst of a full-field steam flood injection EOR project to boost production of heavy oil when the shutdown hit. Given that much time has elapsed, restoration of full production will take a while. If it does happen, however, those additional volumes could complicate mathematics as OPEC faces a scenario of managing global oil supply through its supply deal to account for lost volumes from Iran, Venezuela and Libya, but also surging American shale production. With total production capacity at a maximum of 600,000 b/d, Neutral Zone output is not small drop in the barrel.
But there is more than just restarting fields at stake. While Khafji and Wafra both have a long life left ahead of them (Wafra is estimated to have 4.9 billion recoverable barrels), the Neutral Zone also contains the offshore Dorra field – a politically-sensitive gas field shared with Iran. Plans to exploit Dorra have been shelved since 2013, but Dorra gas is badly needed to power domestic electricity demand in both Kuwait and Saudi Arabia. A restart will help in that matter, certainly in the long term. And it is the long term that is underpinning the renewed negotiations between Saudi Arabia and Kuwait, even if the short-term impact might be negative on global oil fundamentals.
About the Saudi - Kuwait Neutral Zone:
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.
Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.
Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.
Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.
But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.
Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.
Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)
| Region | Consumption (mmb/d)* | Refining Capacity (mmb/d) |
| North America | 22.71 | 22.33 |
| Latin America | 6.5 | 5.98 |
| Europe | 14.27 | 15.68 |
| CIS | 4.0 | 8.16 |
| Middle East | 9.0 | 9.7 |
| Africa | 3.96 | 3.4 |
| Asia-Pacific | 35 | 34.75 |
| Total | 95.44 | 100.05 |
*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)
Market Outlook:
End of Article
In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.
Find courses available for Virtual Instructor Led Training through latest video conferencing technology.
Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.
The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.
Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.
Source: U.S. Energy Information Administration
First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.
Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.
Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.
Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.
Principal contributor: Jesse Barnett
Key findings