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Last Updated: May 7, 2019
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Power plants in Saudi Arabia burned an average 0.4 million barrels per day (b/d) of crude oil in 2018 directly for power generation, the lowest amount since at least 2009, the earliest year that data are available from the Joint Organizations Data Initiative (JODI, Figure 1). According to the JODI data, compared with all other countries, Saudi Arabia burns by far the largest amount of crude oil directly for power generation. Between 2015 and 2017, Iraq used the second-largest amount of crude oil for power generation (over 150,000 b/d on average), but has significantly reduced its direct crude burn since then.

Figure 1. Saudi Arabia direct use of crude oil for power generation (2014 - 2018)

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

Despite continued, steady increases in both population and electricity consumption, Saudi Arabia managed to reduce 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. In recent years, however, nonassociated natural gas production has increased. The Wasit gas plant reached its full operating capacity of 2.5 billion cubic feet per day (Bcf/d) in 2016. The plant was built to process nonassociated gas, which it is currently processing from the Hasbah and Arabiyah offshore gas fields, both of which began production in 2016. Saudi Arabia is investing in more natural gas processing capacity, including the construction of the Fadhili gas plant, which will be able to process nonassociated natural gas from both on- and offshore fields. The Fadhili gas plant is expected to be completed by the end of 2019 with a capacity of 2.5 Bcf/d. Consumption of natural gas in Saudi Arabia has steadily increased, averaging 10.6 Bcf/d in 2017, the latest year for which data are available (Figure 2).

Figure 2. Saudi Arabi natural gas and fuel oil consumption

In addition to natural gas, Saudi Arabia has also been using fuel oil as a partial replacement of crude oil in power generation. High-sulfur fuel oil is a relatively cheap petroleum product that can be used to fuel marine vessels and can also be used for power generation. However, because of environmental concerns and competition with other fuels, fuel oil consumption has been generally declining in most regions in the world. In Saudi Arabia, however, fuel oil consumption rose 25% between 2015 and 2018 to 0.5 million b/d on average, according to JODI data. Some trade press reports indicate 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.

With less crude oil directly being used for power generation, more crude oil is available for domestic refining and exports. For many years, Saudi Arabia has been working to increase its domestic refinery capacity. Saudi Arabia is able to process 2.9 million b/d of crude oil domestically, which will rise further after the startup of the 400,000-b/d Jazan refinery, which may come online in 2019. Because of its refinery additions, Saudi Arabia has been able to process more of its crude oil domestically. Crude oil refinery runs averaged roughly 1.8 million b/d in 2009 and subsequently rose to an average of 2.6 million b/d by 2018, according to JODI data (Figure 3).

Figure 3. Saudi Arabi crude oil refinery intake and petroleum product exports

As a result of increased refinery runs, Saudi Arabia was also able to increase the amount of petroleum products it could export. Exports of petroleum products more than quadrupled between 2009 and 2018, from 0.4 million b/d to 2.0 million b/d. Saudi Arabia exports more diesel than any other petroleum product, averaging 0.8 million b/d in 2018. Gasoline and fuel oil were the next two most exported petroleum products in 2018 at 0.4 million b/d and 0.3 million b/d, respectively. Saudi Arabia also imports petroleum products; however, over the past several years, Saudi Arabia has generally become a net exporter of most products, according to JODI data.

In addition to refining more crude oil domestically, using less crude oil in power generation can enable Saudi Arabia to increase crude oil exports, if needed. However, in late 2016 and in late 2018, Saudi Arabia, along with other members of the Organization of the Petroleum Exporting Countries (OPEC) and some non-OPEC countries, agreed to voluntarily cut crude oil production in order to prevent further declines in crude oil prices. These agreements resulted in lower production of crude oil in Saudi Arabia, which is a more significant factor in how much crude oil the country has available to export throughout the year (Figure 4).

Figure 4. Saudi Arabi crude oil production and exports

Furthermore, Saudi Arabia has been cutting production beyond its agreed-upon target, meaning that as Saudi Arabia’s crude oil production falls, production of associated natural gas will also decline. Declines in associated natural gas production could result in an increased need for crude oil used for power generation.

U.S. average regular gasoline and diesel prices increase

The U.S. average regular gasoline retail price rose nearly 5 cents from the previous week to $2.89 per gallon on April 29, 4 cents higher than the same time last year. The Rocky Mountain price rose over 8 cents to $2.84 per gallon, the East Coast and Gulf Coast prices both increased nearly 5 cents to $2.78 per gallon and $2.58 per gallon, respectively, and the Midwest and West Coast prices each rose over 4 cents to $2.77 per gallon and $3.67 per gallon, respectively.

The U.S. average diesel fuel price increased more than 2 cents to $3.17 per gallon on April 29, 1 cent higher than a year ago. The Rocky Mountain price increased 4 cents to $3.18 per gallon, the West Coast price increased more than 3 cents to $3.73 per gallon, the Gulf Coast and East Coast prices increased 2 cents to $2.94 per gallon and $ 3.19 per gallon, respectively, and the Midwest price increased nearly 2 cents to $3.06 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.2 million barrels last week to 58.9 million barrels as of April 26, 2019, 10.3 million barrels (21.1%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest, Rocky Mountain/West Coast, and East Coast inventories increased by 0.9 million barrels, 0.2 million barrels, and 0.1 million barrels, respectively, and Gulf Coast inventories increased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 9.6% of total propane/propylene inventories.

electricity electricity generating fuel mix international liquid fuels natural gas oil petroleum OPEC Saudi Arabia
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Venezuelan crude oil production falls to lowest level since January 2003

monthly venezueal crude oil production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.

monthly venezuela crude oil rig count

Source: U.S. Energy Information Administration, based on Baker Hughes

Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.

EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.

Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.

India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.

monthly venezuela crude oil exports by destinatoin

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.

A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.

If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.

EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.

May, 21 2019
Your Weekly Update: 13 - 17 May 2019

Market Watch

Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b

  • Crude oil prices are holding their ground, despite the markets showing nervousness over the escalating trade dispute between the USA and China, as well as brewing tensions in the Middle East over the Iranian situation
  • China retaliated against President Trump’s decision to raise tariffs from 10% to 25% on US$200 billion worth of Chinese imports by raising its own tariffs; crucially, China has also slapped taxes on US LNG imports at a time when American export LNG projects banking on Chinese demand are coming online
  • In the Middle East, Saudi Arabia reported that two of its oil tankers were attacked in the Persian Gulf, with the ‘sabotage attack’ near the UAE speculated to be related to Iran; with the US increasing its military presence in the area, the risk of military action has escalated
  • The non-extension of US waiver on Iranian crude is biting hard on Iran, with its leaders calling it ‘unprecedented pressure’, setting the stage for a contentious OPEC meeting in Vienna
  • In a move that is sure to be opposed by Iran, Saudi Arabia has said it is willing to meet ‘all orders’ from former Iranian buyers through June at least; Saudi Aramco is also responding to requests by Asian buyers to provide extra oil
  • The see-saw trend in US drilling activity continues; after a huge gain two weeks ago, the active US rig count declined for a second consecutive rig, with the loss of two oil rigs bringing the total site count to 988, below the equivalent number of 1,045 last year
  • There is considerably more upside to crude prices at the moment, with jitters over the health of the global economy and a delicate situation in the Middle East likely to keep Brent higher at US$71-73/b and WTI at US$62-64/b


Headlines of the week

Upstream

  • Occidental Petroleum and Warren Buffet have triumphed, as Chevron bowed out of a bidding war for Anadarko Petroleum; Occidental will now acquire Anadarko for US$57 billion, up significantly from Chevron’s US$33 billion bid
  • The deal means that Occidental’s agreement to sell Anadarko’s African assets to Total for US$8.8 billion will also go through, covering the Hassi Berkine, Ourhoud and El Merk fields in Algeria, the Jubilee and TEN fields in Ghana, the Area 1 LNG project in Mozambiuqe and E&P licences in South Africa
  • BP has sanctioned the Thunder Horse South Expansion Phase 2 deepwater project in the US Gulf of Mexico, which is expected to add 50,000 boe/d of production at the Thunder Horse platform beginning 2021
  • Africa is proving to be very fruitful for Eni, as it announced a new gas and condensate discovery offshore Ghana; the CTP-Block 4 in the Akoma prospect is estimated to hold some 550-650 bcf of gas and 18-20 mmbl of condensate
  • In an atypical development, South Africa has signed a deal for the B2 oil block in South Sudan, as part of efforts to boost output there to 350,000 b/d
  • Shell expects to drill its first deepwater well in Mexico by December 2019 after walking away with nine Mexican deepwater blocks last year

Midstream & Downstream

  • China’s domestic crude imports surged to a record 10.64 mmb/d in April, as refiners stocked up on an Iranian crude bonanza due to uncertainty over US policy, which has been confirmed as crude waivers were not renewed
  • Having had to close the Druzhba pipeline and Ust-Luga port for contaminated crude, Russia says it will fully restore compliant crude by end May shipments, including cargoes to Poland and the Czech Republic
  • Mexico’s attempt to open up its refining sector has seemingly failed, with Pemex taking over the new 340 kb/d refinery as private players balked at the US$8 billion price tag and 3-year construction deadline
  • Ahead of India’s move to Euro VI fuels in April 2020, CPCL is partially shutting down its 210 kb/d Manali refinery for a desulfurisation revamp
  • China’s Hengli Petrochemical is reportedly now stocking up on Saudi Arabian crude imports as it prepares to ramp up production at its new 400 kb/d Dalian refinery alongside its 175 kb/d site in Brunei
  • South Korea’s Lotte Chemical Corp expects its ethane cracker in Louisiana to start up by end May, adding 1 mtpa of ethylene capacity to its portfolio
  • Due to water shortage, India’s MRPL will be operating its 300 kb/d refinery in Katipalla at 50% as drought causes a severe water shortage in the area

Natural Gas/LNG

  • Partners in the US$30 billion Rovuma LNG project in Mozambique now expect to sanction FID by July, even after a recent devastating cyclone
  • Also in Mozambioque, Anadarko is set to announce FID on its Mozambique LNG project on June 18, calling it a ‘historic day’
  • After talks of a joint LNG export complex to develop gas resources in Tanzania, Shell and Equinor now appear to be planning separate projects
  • Gazprom has abandoned plans to build an LNG plant in West Siberia to compete with Novatek, focusing instead on an LNG complex is Ust-Luga
  • First LNG has begun to flow at Sempra Energy’s 13.5 mtpa Cameron LNG project in Louisiana, with exports expected to begin by Q319
May, 17 2019
Shell Eclipses ExxonMobil Once Again

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

  • ExxonMobil – Revenue (US$63.6 million, down 6.7% y-o-y), Net profit (US$2.35 billion, down 49.5% y-o-y)
  • Shell - Revenue (US$85.66 billion, down 5.9% y-o-y), Net profit (US$5.3 billion, down 2% y-o-y)
  • Chevron – Revenue (US$35.19 billion, down 5% y-o-y), Net profit (US$2.65 billion, down 27.2% y-o-y)
  • BP - Revenue (US$67.4 billion, down 2.51% y-o-y), Net profit (US$2.36 billion, down 9.2% y-o-y)
  • Total - Revenue (US$51.2billion, up 3.2% y-o-y), Net profit (US$2.8 billion, down 4.0% y-o-y)
May, 15 2019