In March 2019, Venezuela's crude oil production (excluding condensate) averaged 840,000 barrels per day (b/d), down from 1.1 million b/d in February, according to estimates in the U.S. Energy Information Administration's (EIA) April 2019 Short-Term Energy Outlook(STEO, Figure 1). This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought Venezuela's state oil company, Petróleos de Venezuela, S.A.'s (PdVSA), operations 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. Venezuela's production decreased by an average of 33,000 b/d each month in 2018, and the rate of decline accelerated 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 production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years, with average 2018 imports the lowest since 1989. However, there may be upward pressure on the prices of other crude oils imported into the United States.

Venezuela's production is expected to continue decreasing in 2019 and declines may accelerate as sanctions-related deadlines approach. These deadlines include provisions that third-party entities that use the U.S. financial system must cease 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 will likely contribute to a further step-level decrease in production.

Additionally, U.S. sanctions, as outlined in the January 25, 2019, Executive Order 13857, immediately banned exporting petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—from the United States to Venezuela and required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. The imposition of these sanctions has already affected oil trade between the United States and Venezuela in both directions. 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 take Venezuela's crude oil, according to data published by ClipperData Inc., while the destinations of some vessels carrying Venezuelan crude oil remain unknown (Figure 2). Venezuela is likely keeping some crude oil cargoes intended for exports in floating storage until it finds buyers for the cargoes.

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 produced using complex processing units, or upgraders, to upgrade the crude oil before it is sent via pipeline to domestic refineries or export terminals. These upgraders were shut down in March during the power outages. If the crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, the 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.

In 2019, Venezuela's crude oil production decline has resulted from a combination of disruptions and lost capacity. EIA differentiates among voluntary production reductions; unplanned production outages, or disruptions; and expected declines in production. For the Organization of the Petroleum Exporting Countries (OPEC), voluntary cutbacks count toward spare capacity. EIA defines spare crude oil production capacity as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices.

For all countries, involuntary disruptions do not count as spare capacity. Events that could cause a disruption include, but are not limited to, sanctions, armed conflict, labor actions, natural disasters, or unplanned maintenance. In contrast, EIA considers production capacity declines that result from irreparable damage to be lost capacity and not a disruption. EIA no longer counts the lost production because it is very unlikely that it could return within one year and add to global supplies.

Because the power outages in Venezuela resulted from a lack of maintenance of the electricity grid, associated crude oil production declines are considered lost production capacity resulting from mismanagement. As of the April 2019 STEO, EIA includes the portion of Venezuela's production decline that resulted from U.S. sanctions—approximately 100,000 b/d beginning in February—as a disruption (Figure 3). If sanctions persist, the country will likely be unable to restart the disrupted portion of production and the 100,000 b/d will become lost capacity. Although EIA does not forecast unplanned production outages, its forecast for OPEC production totals will reflect declines in Venezuelan production.

As Venezuelan crude oil has come off the global market and as other countries—including the United States—have produced more light, sweet crude oil, the price discount of heavy, sour crudes has narrowed. U.S. refineries are among the most complex in the world, making them well-suited for the physical properties of Venezuelan crude oil (with high sulfur content and heavier API gravity). Heavier, more sour crude oil is typically priced lower than other crude oils because of differences in crude oil quality. Mars—a medium, sour crude oil produced in the U.S. Federal Offshore Gulf of Mexico—traded at a five-year (2014–18) average discount to Light Louisiana Sweet (LLS) of $3.94 per barrel (b). The Mars-LLS discount has narrowed in 2019, averaging $0.62/b in March, and even reached parity on March 27 (Figure 4).

Venezuela's crude oil production is forecasted to continue to fall through at least the end of 2020, reflecting an expectation of 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 is currently included would change this forecast.

U.S. average regular gasoline and diesel fuel prices increase

The U.S. average regular gasoline retail price increased more than 1 cent from a week ago to $2.84 per gallon on April 22, more than 4 cents higher than the same time last year. The Rocky Mountain price increased nearly 12 cents to $2.76 per gallon, the West Coast price rose 5 cents to $3.63 per gallon, and the East Coast price increased nearly 2 cents to $2.73 per gallon. The Midwest price decreased more than 1 cent to $2.72 per gallon, and the Gulf Coast price fell slightly, remaining virtually unchanged at $2.54 per gallon.

The U.S. average diesel fuel price increased nearly 3 cents to $3.15 per gallon on April 22, more than 1 cent higher than the same time last year. The Rocky Mountain price increased 6 cents to $3.14 per gallon, the West Coast price increased nearly 5 cents to $3.70 per gallon, the Midwest price increased more than 3 cents to $3.04 per gallon, and the East Coast and Gulf Coast prices increased 2 cents to $3.17 per gallon and $2.92 per gallon, respectively.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.0 million barrels last week to 57.8 million barrels as of April 19, 2019, 10.6 million barrels (22.5%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest inventories increased by 0.6 million barrels, while East Coast and Gulf Coast inventories each increased by 0.3 million barrels. Rocky Mountain/West Coast inventories decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 10.4% of total propane/propylene inventories.

A tremor ran through the oil & gas industry last week. It wasn’t a by-product of fracking activity, but it is certainly linked. Supermajor Chevron agreed to purchase US independent Anadarko Petroleum for US$33 billion, a 39% premium to Anadarko’s last traded price. It’s the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. That deal catapulted Shell to become the world’s largest LNG trader, expanding its reach in the fast-evolving industry. Chevron will be looking to do the same.

The purchase of Anadarko gets Chevron into two prolific areas: the Permian Basin in the US and LNG. Chevron is already one of the largest supermajors operating in the Permian, with 2.3 million acres in the area. In this respect, the purchase is strategic. Combined with Anadarko’s assets, Chevron would now have a 120 sq.km corridor in the sweet spot of the shale basin –  Delaware, which straddles the Texas-New Mexico border. It’s a major salvo fired and a great boost to Chevron’s ambitions, which named investment in the Permian as its major focus last year. But more than just extracting oil, the purchase plugs a hole in Chevron’s portfolio. Through Anadarko, Chevron will gain major US midstream space, including a 55% stake in the Western Midstream Partners whose pipelines crosses all over Texas, linking the Permian to the processing and exporting base on the Gulf.

Internationally, the acquisition also boosts Chevron’s presence in LNG, which had recently  lagged behind other supermajors like Shell, ExxonMobil and Total. Anadarko’s Mozambique LNG project is neck-in-neck to become the African nation’s first LNG project with ExxonMobil. Drawing on Mozambique’s prolific Rovuma basin, the LNG export project has a nameplate capacity of 12.88 mtpa, of which 8.5 mtpa has already been committed through sales and purchase agreements. With FID scheduled for this year and operations expected in the 2023/24 timeframe, it complements Chevron’s current LNG portfolio – including the massive projects in Western Australia – nicely.

Together with recent investments in the upper echelon of energy companies, it seems the moniker supermajor may not be enough. Within the supermajor category, there was already a hierarchy, with ExxonMobil and Shell outpacing the rest. With this Anadarko apurchase, Chevron leaps into that tier, which analysts are calling ultramajors. That is, if there isn’t a spanner in the works. Occidental Petroleum, which is also focused on the Permian, had previously made a US$70 per share bid for Anadarko. It is now considering a counter proposal. The battle for Anadarko will go on, but we expect that Chevron will prevail, seeing how Anadarko’s operations fit so neatly into its own portfolio.

But more than just Chevron, could this be a preview of the future? The US shale revolution was kickstarted by plucky companies and ambitious independents, while the majors lost out. With this Chevron deal – along with ExxonMobil’s expansion and BP’s recent purchase of BHP assets – this could kick off another round of industry consolidation, centred around buying the way into the Permian and other shale basins. This might be a major purchase that shakes up the status quo, but if the signs are correct, there is more of this to come.

Infographic: The Chevron-Anadarko deal

• US$33 billion 25% cash- 75% stock deal
• Chevron to acquire Anadarko shares for US$65 per share
• Chevron will assume net debt of US$15 billion
• Chevron will sell some US$15 billion of assets to offset the purchase

Market Watch

Headline crude prices for the week beginning 15 April 2019 – Brent: US$71/b; WTI: US$63/b

• Crude oil futures could be on the verge of snapping its longest weekly rally since 2016, as the market continues to balance managed crude supply from the OPEC+ nations with accelerating American output
• Analysts are predicting that things could be coming to a head, which might see OPEC+ abandon its plans to stabilise supply and prices for an intense battle for market share with American shale producers instead
• This seems to be echoed by comments from Saudi Arabia, hinting at a U-turn in OPEC+’s dedication to extending the current supply quota agreement
• Russian Premier Vladimir Putin also chimed in, saying that he was ‘keeping his options open’ on the cuts and that he does not support an ‘uncontrollable’ increase in oil prices
• Ongoing concerns in Libya, Venezuela and Iran are giving other OPEC nations some room to breathe in their supply deal, with the organisation reporting that its output plunged in March to 758,000 b/d below the expected Q2 average
• After Japan reported it would hold back on resuming Iranian crude imports, India is now doing the same until clarification of American waivers on the sanctions is received
• The International Energy Agency reports that it sees global oil markets tightening, warning that this could lower actual demand and forecasts
• After a large 19 rig gain last week, the US reversed gear to lose 3 rigs, adding two oil sites while dropping five gas rigs, bringing the total active count to 1022
• Rumbles of a shale slowdown in the US could keep crude prices on a gentle upward curve, with Brent likely to trade at US$71-72/b and WTI and US$63-64/b

Headlines of the week

Upstream

• Shell has sold its 22.45% non-operating interest in the US Gulf of Mexico Caeser-Tonga asset to the Delek Group for some US$965 million in cash
• US President Donald Trump is aiming to limit state powers over cross-border pipeline to promote projects stalled by state regulators over permit and environmental concerns through the issuance of Executive Orders
• CNOOC has signed a new PSC with Smart Oil Investment for the Bohai 09/17 block in the shallow-water Qikou area of the Bohai Bay Basin in China
• Also in the Bohai Bay, CNOOC and ConocoPhillips are planning to double production from the Penglai 19-3 field over the next few years
• Shell has partnered with Sinopec in a maiden exploration of China’s shale oil potential, targeting the Dongying trough in Shengli in eastern China
• Shell has also announced an ambitious drilling programme in Brazil, targeting the Argonauta pre-salt areas in the Santos Basin
• Petrobras and the Brazilian government have settled a deepwater contract dispute for US$9.06 billion, paving the way for Petrobras and its partners to begin development of the crude deposits under the 2010 Transfer of Rights

Midstream & Downstream

• Continuing on its diversification strategy, Saudi Aramco is now looking to double its global refining network to some 10 mmb/d by 2030 as a means of locking in buyers for its crude amidst intense competition, which would see Aramco to continue investing in key global refining centres
• Shell is aiming to complete the overhaul of its RCCU at the 218 kb/d Norco refinery in Louisiana by May, ahead the US summer driving gasoline demand
• Sinopec reports that its Jinling refinery in Jiangsu has sold its first 4,200-ton cargo of low-sulfur marine fuel ahdad of the new IMO standards kicking in
• Saudi Aramco has signed an agreement with Poland’s PKN Orlen to trade Arabian-grade crude to the refiner in exchanges for high-sulfur fuel oil

Natural Gas/LNG

• Total has been awarded an exploration licence for Block 12 in Oman, with the onshore 10,000 sq.km asset near the gas-rich Greater Barik area that is expected to hold ‘significant prospective gas resources’
• Saudi Aramco is planning to move into LNG for first time ever, offering to supply Pakistan with cargos on a spot or short-term basis, even though it does not produce LNG and has only just begun developing an LNG trading desk
• First feed gas has begun to flow at Sempra Energy’s Cameron LNG Train 1 in Louisiana, the final commissioning phase for the project
• Keppel Gas in Singapore has imported its first 160,000 cbm cargo of US LNG under the country’s Spot Import Policy, its first from outside Southeast Asia and the first trickle in an exported flood of American LNG into the region

Corporate

• Saudi Aramco has issued its first global bond, raising US$100 billion from the sale, above and beyond the initial expectations of US$10-15 billion
• Abu Dhabi’s Mubadala Investment Company has sold a ‘significant minority interest’ of 30-40% in Spanish energy firm Cepsa to investment group The Carlyle Group, but will retain majority shareholder
• Canadian player Africa Oil has acquired 18.8% of fellow Canadian upstream firm Eco (Atlantic) Oil and Gas, but stressed that the acquisition was for investment purposes with no intention of exercising control