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Last Updated: June 4, 2019
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Saudi Arabia direct use of crude oil for electric generation

Source: U.S. Energy Information Administration, Joint Organizations Data Initiative

In 2018, Saudi Arabia reported burning an average of 0.4 million barrels per day (b/d) of crude oil for power generation, the lowest amount since at least 2009, the earliest year that data are available from the Joint Organizations Data Initiative (JODI). Saudi Arabia burns considerably more crude oil directly for power generation than any other country. Between 2015 and 2017, Saudi Arabia used more than three times the amount of crude oil for power generation than Iraq, the second-largest user of crude oil for power during those years.

Saudi Arabia relies on crude oil and other fossil fuels, such as petroleum products and natural gas, for power generation. During the summer months, Saudi Arabia’s electricity consumption increases as domestic demand for air conditioning rises. Saudi Arabia’s direct crude oil burn for power generation reached a record high during the summer of 2015, averaging 0.9 million b/d from June to August. In comparison, direct crude oil burn in the summer of 2018 was 41% lower at 0.5 million b/d.

Despite steady increases in both population and electricity consumption, Saudi Arabia reduced its reliance on crude oil for power generation by increasing the use of other energy sources, such as natural gas and fuel oil. Most of the natural gas that Saudi Arabia produces is associated gas, which is natural gas produced along with crude oil from an oil well. Yet Saudi Arabia’s production of natural gas from wells not associated with oil production has also increased, leading to higher consumption of natural gas in the country.

Natural gas processing capacity is also increasing. Consumption of natural gas in Saudi Arabia reached 10.6 billion cubic feet per day in 2017, the latest year for which data are available.

In addition to natural gas, Saudi Arabia has also been using fuel oil as a partial replacement of crude oil in power generation. Saudi Arabian fuel oil consumption has increased despite fuel oil consumption declining in most regions of the world because of environmental concerns and competition with other fuels. Some trade press reportsindicate that one potential side effect of the upcoming changes to the sulfur limits in marine fuels in 2020 is that the stranded high-sulfur fuel oil could be sent to Saudi Arabia to further replace crude oil in power generation.

Saudi Arabia natural gas consumption

Source: U.S. Energy Information Administration, International Energy Statistics (left chart). U.S. Energy Information Administration, based on the Joint Organizations Data Initiative (right chart)

With less crude oil directly used for power generation, more crude oil is available for Saudi Arabia’s refining and exports. For many years, Saudi Arabia has worked to increase its domestic refinery capacity and is currently able to process 2.9 million b/d of crude oil. Crude oil refinery runs averaged 1.8 million b/d in 2009, and they subsequently rose to an average of 2.6 million b/d by 2018, according to JODI data. As a result of increased refinery runs, Saudi Arabia also increased the amount of petroleum products it could export and most recently exported an average of 2.0 million b/d of petroleum products in 2018.

Saudi Arabia crude oil refinery intake and petroleum product exports

Source: U.S. Energy Information Administration, Joint Organizations Data Initiative
Note: Jet fuel exports are counted within kerosene exports. Other petroleum products have negligible export values and are not shown.

More information about Saudi crude oil burn is available in EIA’s This Week in Petroleum.

generation international electricity Saudi Arabia crude oil oil petroleum
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Compliance Is Critical

The signs going into OPEC’s bi-annual meeting in Vienna were broadly positive. On one hand, you had some key members – including Iraq, surprisingly – stating the need for the broader OPEC+ club to make further cuts to its supply deal. On the other hand, there was Saudi Arabia, which needed a win to support Saudi Aramco’s upcoming IPO. What emerged was a little something for everyone, that was still broadly positive but scant on the details.

The headlines spinning out of the December 5 meeting was that the OPEC+ alliance agreed to slash a further 500,000 b/d, with Saudi Arabia pledging an additional voluntary cut of 400,000 b/d. Collectively, this would raise the club’s total supply reduction to 2.1 mmb/d – or over 2% of global oil demand – up from the previous 1.2 mmb/d target. Beneath those headlines, however, the details of the new adjustment to the deal were murkier.  The 500,000 b/d cut is, in fact, more of a formalisation of the current production levels within OPEC. It won’t remove additional barrels from the market, but it won’t add them back into global supply either.

Saudi Arabia is, once again, key to this equation. Even with the attacks on the heart of its crude processing facilities in September, Saudi Arabia has been shouldering the extra burden within the deal, making up for errant members that have consistently overshot their quotas. These include Nigeria and Iraq, and crucially Russia. The caveat that the new targets – especially Saudi Arabia’s voluntary portion – will only come into force if all members of the OPEC+ club implement 100% of their pledged cuts underscores the Kingdom’s new, more hardline stance that full compliance is required before it makes additional concessions. Because even with the declines in Venezuela and Iran, Saudi Arabia has trimmed its output to below 10 mmb/d in an attempt to show leadership through example. But its patience is now wearing thin.

But it is those details that are sketchy right now. OPEC states that the new deal formalises current production levels and will make up for Saudi overcompliance by ‘redistributing’ those volumes across other OPEC+ members. But no specifics on that split were given – a worrying sign that more arguments were coming – with the group preferring to meet compliance first before moving on to the fresh cuts.

Full adherence to the targets is tough. But it might get easier. Russia – which has only met its quota 3 months this year, when the Druzhba oil pipeline crisis hit – won a significant concession. Its argument that the only reason it was not hitting its target was due to condensate production, a by-product of its increasing natural gas output, was accepted; the quotas will exclude condensate, and Russian Energy Minister Alexander Novak was optimistic that it could meet its quota of a 300,000 b/d reduction for the first quarter of 2020. And the first quarter of 2020 is crucial, as that is the remaining length of the supply deal. Ahead of the March 31 expiry in 2020, OPEC has agreed to hold an extraordinary general meeting to assess the situation – the point which the deal either ends or is extended.

Underpinning this bet is some sentiment-based optimism from OPEC. The rise and rise of US shale has diluted OPEC’s impact over the past five years, requiring it to make deeper and deeper cuts that were muted by increasing amounts of American crude. But OPEC is betting that the wind will go out of US shale sails next year, hoping that it will allow output within OPEC+ to rise again. But low growth in US shale does not mean no growth. And perhaps for this reason, the price impact on the new OPEC decision has been muted. Despite the club’s attempt to prove that it is still effective, the market simply doesn’t believe the new cut will do much. Crude prices reflect that. Call it cynicism, but the market might have more faith if full compliance was reached and that is exactly what OPEC is striving towards. 

The OPEC+ supply deal: 

  • Reductions of 1.2 mmb/d, as of March 2019
  • A further reduction of 500,000 b/d, formalising October 2019 levels
  • A voluntary cut of 400,000 b/d from Saudi Arabia
  • New cuts will only be formalised once all members comply with their quotas, with full details unavailable
  • Errant members exceeding quotas: Russia, Kazakhstan, Iraq, Nigeria
December, 10 2019
INDONESIA’S DECOMMISSIONING CHALLENGE REPORT

A report by Nicholas Newman

Many of Indonesia’s oil and gas fields, both on and offshore, are coming to the end of their commercially viable operational lifespan. More than 60% of Indonesia’s oil and more than 30% of gas production comes from late-life-cycle resources spread across the world's largest island country. Despite investment and use of enhanced oil field recovery measures, as well as increasing automation to extend the economic lifespan of these assets, decommissioning will soon become necessary.

However Indonesia, like many countries new to the prospect of decommissioning energy infrastructure, face many key technological, fiscal, environmental, regulatory and industrial capacity issues, which need to be addressed by both government and industry decision makers.

This report, commissioned by the consulting and advisory arm of London and Aberdeen based Precision Media & Communications aims to takes a look at many of the issues Indonesia and other South East Asian oil producing nations are likely to face with the prospect of decommissioning the region's oil and gas aging energy infrastructure both onshore and offshore... To find out more Click here

December, 09 2019
Your Weekly Update: 2 - 6 December 2019

Market Watch  

Headline crude prices for the week beginning 2 December 2019 – Brent: US$61/b; WTI: US$55/b

  • As the posturing begins ahead of the OPEC meeting in Vienna, crude oil prices mounted gains as several OPEC members signalled that the club was prepared to deepen cuts to the existing supply deal
  • Data showing that the Chinese manufacturing sector growth jumped unexpectedly in November, although the see-saw messages regarding a potential US-China trade deal continue to cloud the market… especially given recent US legislation to sanction China for its policies in Hong Kong and against its own Uighur community
  • The discussion in Vienna by the OPEC nations and the wider OPEC+ club revolved around adherence and implementation of the current supply deal, focusing on cajoling errant members – ie. Russia – into meeting their quotas, in exchange for a deeper cut to prop up prices
  • This resulted in a decision to cut output by a further 500,000 b/d in Q1 2020 – formalising the supply reductions already in place and subject to all members of OPEC+ implementing all of their pledged curbs; further details on the new plan are expected to be released
  • OPEC’s outlook on the crude market in 2020 has changed slightly, as it expects that the US shale revolution will slow down considerably in the next two years; however, it also warns of additional output coming from non-OPEC members, including Norway and Brazil, the latter being a possible new OPEC member
  • Meanwhile, in the US, the chronic decline in the active rig count continues, with the Baker Hughes index falling by a net 1 last week – the loss of 3 gas rigs offset by the gain of two gas rigs – the 13th decrease in the past 15 weeks, with the active count down 274 y-o-y
  • The decision spinning out of OPEC’s Vienna meeting is broadly positive – not a great shot in the arm, but not detrimental to the current market; as such we see crude prices trading in their current range of US$62-64/b for Brent and US$57-60/b for WTI


Headlines of the week

Upstream

  • Norway’s Equinor has announced that it will scale back exploration activities in frontier areas in the Barents Sea, shedding risk to focus on drilling near existing discoveries such as Johan Castberg and Wisting, and therefore decreasing the chance of discovering a new Arctic oil region
  • Cairn Energy will be exiting Norway as it sells its entire stake in Capricorn Norge AS to Solveig Gas Norway AS for US$100 million
  • Libya’s El Feel – a key field operated by Eni and Libya’s National Oil Corp near the giant Sharara field – has restarted production at 74,000 b/d after clashing between rival fighting factions forced it to shut down
  • Woodside’s development plan for Phase 1 of the offshore Sangomar field in Senegal – targeting production of 100,000 b/d via FPSO – has been submitted to the Senegalese government, paving the way for FID
  • Spurred on by success, ExxonMobil is adding a fifth drillship in Guyana as it probes a new ultra-deepwater prospect just north of the Stabroek block
  • Equatorial Guinea’s latest licensing round was a boon to Lukoil, which walked away with the prime EG-27 block containing the Fortuna gas discovery, while US player Vaalco Energy won 4 blocks in the onshore Rio Muni basin

Midstream/Downstream

  • Pertamina has purchased US crude for the first time in a long while, inking a shipment for 950,000 barrels of US WTI crude with Total to be delivered over 1H 2020 to the Cilacap refinery, pivoting away from Middle East grades
  • Trafigura is looking to sell off its fuel station network in Australia – operated through its retail arm Puma Energy – as continued losses in the space since it entered the market in 2013 for US$850 million pile up
  • Construction on BASF’s giant US$10 billion integrated petrochemicals project in Zhanjiang, Guangdong has begun, with the first phase to be launched in 2022 as the first wholly foreign-owned chemicals complex in China
  • Equatorial Guinea has announced plans to build two new oil refineries – each with a processing capacity of 30-40,000 b/d using local Zafiro crude – along with other projects including a methanol-to-gasoline plant and LNG expansion
  • Bosnia’s sole refinery – the 25,000 b/d Brod site – should be operational by mid-2020, following a major overhaul that began in January 2019

Natural Gas/LNG

  • Algerian piped natural gas exports to Europe have been squeezed out by boosted supply of LNG from Australia and the US, as well as piped gas from Russia, which has forced Sonatrach to turn more of its gas into LNG sold by spot
  • Gunvor has agreed to market LNG from the Commonwealth LNG project in Louisiana internationally, as well as double its own purchases from the project to as much as 3 million tpa once the project begins operations in 2024
  • Norway’s BW Offshore insist that its Kudu natural gas project in Namibia is ‘alive and well’, with talks ongoing with the government two years after the FPSO specialist acquired a 56% stake in the license from NAMCOR
  • ExxonMobil is reportedly looking to sell its 50% stake in the Neptun Deep gas project in the Black Sea offshore Romania – the location of its major Domino discovery – for some US$250 million as it continues on a major asset sale
  • Petronas is sending its second FLNG unit – the PFLNG Dua – to the Rotan gas field in Sabah, beginning liquefaction operations there by February
December, 06 2019