Last week in world oil
-International crude prices started the year off a bit weaker than in its ended in December, with prices hovering around the US$52-53/b on the New Year, as the US dollar rallied to its highest levels against major currencies since 2002. January is when OPEC members are expected to make major cuts to their collective supply, and the oil markets will be hoping that the quotas will stick to lift prices.
Upstream & Midstream
-BP and Azerbaijans Socar have agreed to terms governing the developing of the giant Azeri-Chirag-Gunashi (ACG) field in the Caspian Sea through 2050. BP is the lead in the AIOC consortium that comprises international presence in ACG, with other partners being Chevron, Inpex, Statoil, Itochu, ONGC Videsh and ExxonMobil. The super-giant ACG currently produces 620 kb/d of oil equivalent, beginning in 1997 with estimated recoverable reserves of 5-6 billion, with more gas reserves yet untapped.
-Peruvian President Pedro Pablo Kuczynski is threatening to terminate the US$5 billion Southern Peruvian Natural Gas Pipeline if evidence of bribery surfaced. News that Brazilian builder Odebrecht had admitted to bribing officials in Peru from 2005 to 2014 triggered the investigation, with some US$29 million allegedly distributed to gain access to Peruvian energy projects. Under the graft investigation, Odebrecht is required to divest its 55% stake inproject, with Brookfield Asset Management a likely buyer. Chinas CNPC has also been named as a possible contender.
-The US rig count might have ended just under the year-end rig count for 2015, but it is up significantly since mid-2016, with signs that the count will improve further over the first half of 2017. The final week of 2016 saw only 2 new rigs being added both oil during the quietest period of the year, bringing the total to 525, just under 536 on December 30, 2015. Since May 2016, American drillers have started/restarted over 209 oil and gas rigs domestically as prices improved over the second half of 2016.
-After being idled in 2012 by Valero, the 225 kb/d refinery in Aruba will be restarted in 2017. The process will take over 18 months, with Citgo appointing a consortium of Frances Technip, Venezuelas Tecnoconsult and Y&V Group to refurbish the site in a US$700 million project. The would give Venezuelas PDVSA a continued presence in the Caribbean through its US subsidiaryCitgo,after the Curacao refinery now appears to be in Chinese hands.
Natural Gas & LNG
-Malaysias Petronas is aiming to move ahead with its US$27 billion LNG project in western Canada by identifying a new site that would reduce cost and quell local opposition, which had dogged the Pacific Northwest LNG project previously. The processing site will remain on Lelu Island, but the docking facilities moved to theneighbouringRidley Island, eliminating the need for an expensive suspension bridge that was part of the original plan that cut through an environmentally sensitive area.
Last week in Asian oil:
Upstream & Midstream
-Iran has named 29 companies from over a dozen countries that will be allowed to bid for oil and gas projects under its new Iran Petroleum Contract (IPC) model. Though not exhaustive, the pre-qualification list includes Shell, Total, Eni, Petronas,Gazpromand Lukoil, but not BP, which opted out of participating out of fears of renewed American hostility when Donald Trump enters the White House.
-In a move that acknowledges that domestic Chinese upstream production is hitting a wall,Petrochinawill slash capital spending at the Daqing field the countrys largest by 20% in 2017. The aim is to now keep output steady instead of boosting production, keeping output steady at 40 million tons of oil and gas by 2019, in line with 2015 figures.
Downstream & Shipping
-Australian grocery retailer Woolsworth is selling its national fuel station network to BP for A$1.8 billion, claiming that it didnt understand the fuel business. The deal marks BPs second major foray back into downstream in the last two months, after agreeing to partner with Reliance in India.Woolworthsfuel stations are currently being supplied by CaltexAustralia,and will be transitioned to be part of the BP network gradually.
-Chinas Sinopec has begun supplying Beijing Six grade gasoline and diesel to the capital, as the city battles the persistent smog that blankets Beijing. Beijing Six is a stricter standard than even the National Five (equivalent to Euro V) that will be rolled out across China over 2017, with the same 10ppmsulphurlimit and a lower nitrogen oxide and olefins spec. All 562 of Sinopec fuel stations in Beijing will sell the new standard, supplied mainly by SinopecsCangzhou, Yangshan and Qilu refineries.
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Headline crude prices for the week beginning 20 May 2019 – Brent: US$73/b; WTI: US$63/b
Headlines of the week
Midstream & Downstream
At first, it seemed like a done deal. Chevron made a US$33 billion offer to take over US-based upstream independent Anadarko Petroleum. It was a 39% premium to Anadarko’s last traded price at the time and would have been the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. The deal would have given Chevron significant and synergistic acreage in the Permian Basin along with new potential in US midstream, as well as Anadarko’s high potential projects in Africa. Then Occidental Petroleum swooped in at the eleventh hour, making the delicious new bid and pulling the carpet out from under Chevron.
We can thank Warren Buffet for this. Occidental Petroleum, or Oxy, had previously made several quiet approaches to purchase Anadarko. These were rebuffed in favour of Chevron’s. Then Oxy’s CEO Vicki Hollub took the company jet to meet with Buffet. Playing to his reported desire to buy into shale, Hollub returned with a US$10 billion cash infusion from Buffet’s Berkshire Hathaway – which was contingent on Oxy’s successful purchase of Anadarko. Hollub also secured a US$8.8 billion commitment from France’s Total to sell off Anadarko’s African assets. With these aces, she then re-approached Anadarko with a new deal – for US$38 billion.
This could have sparked off a price war. After all, the Chevron-Anadarko deal made a lot of sense – securing premium spots in the prolific Permian, creating a 120 sq.km corridor in the sweet spot of the shale basin, the Delaware. But the risk-adverse appetite of Chevron’s CEO Michael Wirth returned, and Chevron declined to increase its offer. By bowing out of the bid, Wirth said ‘Cost and capital discipline always matters…. winning in any environment doesn’t mean winning at any cost… for the sake for doing a deal.” Chevron walks away with a termination fee of US$1 billion and the scuppered dreams of matching ExxonMobil in size.
And so Oxy was victorious, capping off a two-year pursuit by Hollub for Anadarko – which only went public after the Chevron bid. This new ‘global energy leader’ has a combined 1.3 mmb/d boe production, but instead of leveraging Anadarko’s more international spread of operations, Oxy is looking for a future that is significantly more domestic.
The Oxy-Anadarko marriage will make Occidental the undisputed top producer in the Permian Basin, the hottest of all current oil and gas hotspots. Oxy was once a more international player, under former CEO Armand Hammer, who took Occidental to Libya, Peru, Venezuela, Bolivia, the Congo and other developing markets. A downturn in the 1990s led to a refocusing of operations on the US, with Oxy being one of the first companies to research extracting shale oil. And so, as the deal was done, Anadarko’s promising projects in Africa – Area 1 and the Mozambique LNG project, as well as interest in Ghana, Algeria and South Africa – go to Total, which has plenty of synergies to exploit. The retreat back to the US makes sense; Anadarko’s 600,000 acres in the Permian are reportedly the most ‘potentially profitable’ and it also has a major presence in Gulf of Mexico deepwater. Occidental has already identified 10,000 drilling locations in Anadarko areas that are near existing Oxy operations.
While Chevron licks its wounds, it can comfort itself with the fact that it is still the largest current supermajor presence in the Permian, with output there surging 70% in 2018 y-o-y. There could be other targets for acquisitions – Pioneer Natural Resources, Concho Resources or Diamondback Energy – but Chevron’s hunger for takeover seems to have diminished. And with it, the promises of an M&A bonanza in the Permian over 2019.
The Occidental-Anadarko deal:
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.
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.
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.