In 2005, the tiny Persian Gulf nation of Qatar declared a moratorium on production at its North Field. Natural gas from this giant field, part of a larger reservoir that straddles Qatari and Iranian borders, had helped Qatar ramp up production, eight years after it exported its first cargo of LNG to Spain in 1997. The halt came as a bit of a surprise back then, seen as limiting, but in hindsight was a great move. Existing projects with partners ExxonMobil, Shell and Total were more than enough to vault Qatar to become the largest LNG exporter in the world, and there were technically challenging projects like the Pearl and Oryx Gas-to-Liquids (GTL) refineries that demanded attention.
The logic, then, was to prevent overexploitation of the precious North Field, particularly since it was shared with Iran, where it is known as South Pars. Detailed studies on the structure of the field have estimated that, at current production rates, Qatar still has about 135 years of gas reserves underground. With most of the giant Qatari projects now complete, the country can afford to exploit a little more. So 12 years later, the moratorium has been lifted.
Qatar Petroleum (QP), the state oil firm, intends new development to be confined to the southernmost part of the North Field, running almost onshore, contributing a 10% increase – or 2 bcf/d or 400,000 barrels of oil equivalent in national production. It comes after QP merged its two gas subsidiaries – RasGas and Qatargas – into a single entity called Qatargas in December 2016, streamlining the business structure of its gas operations. Together with partners ExxonMobil, Total, Shell and ConocoPhillips, the new Qatargas will operate all Qatari LNG production, while the newly-established Ocean LNG will manage the international marketing of all Qatari LNG.
Put all of those announcements together and the picture is clear; Qatar is moving aggressively to retain its crown as the world’s top LNG exporter, fending off Australia, the USA and Russia as they ramp up their respective output. The flurry of LNG production has resulted in global installed LNG capacity of over 300 million tonnes a year, while only around 268 million tonnes of LNG were traded in 2016, Thomson Reuters data shows. That has helped pull down Asian spot LNG prices LNG-AS by more than 70 percent from their 2014 peaks to $5.65 per million British thermal units (mmBtu).
With LNG prices already waning due to the existing and growing glut, what good will it do for Qatar to add more to the mix?
Qatar's decision to lift the moratorium is indicative that the country will not just do nothing while other large producers pick-up more customers in a growing market. For one thing, Qatari costs are low. Qatari LNG is already one of the cheapest to produce in the world, and any new North Field output can be tapped back into infrastructure already in place – allowing Qatar to better weather low LNG prices than say Australia, where Chevron has had to deal with massive ramp-ups in costs for the Gorgon and Wheatstone.
Secondly, the QP announcement pointedly did not mention whether the new gas will become LNG. Which means Qatargas is looking at other options. More GTL and Gas-to-Petrochemical projects, perhaps? Or perhaps feeding the natural gas demand of its Gulf neighbours? The UAE, Bahrain, Oman, Kuwait and Saudi Arabia are short on natural gas, so a trans-Arabian Peninsula pipeline might be just what is needed. QP Chief Executive Saad al-Kaabi told reporters at Qatar Petroleum's headquarters in Doha, "What we are doing today is something completely new and we will in future of course share information on this with them (Iran)."
The lifting of the North Field moratorium also comes just in time since Qatar’s domestic oil and gas production is plateauing, kicking off the next phase of Qatari growth. And when that next phase begins to end, well, Qatar still has a whole lot more of the North Field to tap into. Saad al-Kaabi continued to say that "For oil there are people who see peak demand in 2030, others in 2042, but for gas, demand is always growing."
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
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.