In a double blow to Indonesia’s attempt to boost its natural gas production, supermajor ExxonMobil and Thailand’s national oil company, PTTEP have both pulled out of the East Natuna project within days of each other last week. This leaves state oil firm Pertamina as the only player left in Southeast Asia’s largest undeveloped gas resource; a role that it cannot afford to undertake alone.
In a statement, PTTEP said that ‘under current production sharing contract terms and market conditions, commercialising the hydrocarbon resources in this area would be difficult,’ as it confirmed its pullout after the results of a Technology and Market Review (TMR). ExxonMobil’s statement was more terse – stating in a letter to the Indonesian authorities that East Natuna was ‘uneconomical for the company under current terms.’
There are two ways reading into those statements. The first is the market conditions are tough. East Natuna is located on the southern edge of the South China Sea, where the border between Malaysia and Indonesia kinks upwards unexpectedly. Not only is this area isolated (and claimed by China), it is also far away from any existing infrastructure – requiring either a floating production unit or long pipelines, both of which will be expensive. The payoff was once worth it – reserves at East Natuna are estimated at 222 tcf, of which at least 46 tcf is recoverable. But high carbon dioxide content (exceeding 70%) requires expensive processing that needs significant capex. With an estimated price tag of at least US$40 billion, East Natuna needs LNG prices of US$10-15/mmBtu to break even – and that’s hard to justify when Asian spot prices are now languishing at US$6/mmBtu.
The second is more pointed – the ‘current production sharing contract terms.’ Under the current Indonesian PSC structure, natural gas producers have to meet a Domestic Market Obligation (DMO) – that at least 25% of the production must be supplied to the local market. There is leeway for the government to demand more if the need arises. That is a huge chunk of output taken away from any project. Upstream producers in Indonesia have long championed reform to the DMO, arguing that it stifles investment. But Indonesia needs the DMO as well – its domestic consumption is growing and its argument is that Indonesian resources should also stay in Indonesia instead of being exported; at subsided prices, of course.
The first can change, depending on market conditions, but money is on LNG prices in Asia to remain below the range required by East Natuna, with the tsunami of Australian, American and Canadian LNG on its way. The second is tougher – the Indonesian government has tried for years to streamline its PSC structure to balance both domestic requirements and stimulating investment. But it will have to, sooner of later, if it wants to reverse the chronic decline in Indonesia upstream output. In the meantime, the long-running East Natuna project has claimed two other victims. Discovered in 1973, the first PSC to develop it was formed by Pertamina and pre-merger Exxon. Over the next four decades, Petronas and Total would be involved in various other attempts to commercialise the discovery, with ExxonMobil and PTTEP now giving up as well. ExxonMobil did offer an olive branch, stating that it would help with technology and technical assistance if needed. Indonesia replied that it might make a ‘special incentive’ to keep the project viable. That would have to be a very special incentive indeed; but given projected market conditions, possibly still far from enough to keep the project alive. East Natuna remains a pipe dream, for now.
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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.