The first official glimpse of Saudi Aramco’s financial performance confirms the state-run oil giant can generate profit like no other company on Earth: net income last year was $111.1 billion, easily outstripping U.S. behemoths including Apple Inc. and Exxon Mobil Corp.
But accounts published before the firm’s debut in the international bond market also show Aramco -- an organization that produces about 10 percent of the world’s crude -- doesn’t generate as much cash per barrel as other leading oil companies like Royal Dutch Shell Plc because of a heavy tax burden.
The bond sale, being pitched to investors this week in a global roadshow, has forced Aramco to reveal secrets held close since the company’s nationalization in the late 1970s, casting a light on the relationship between the kingdom and its most important asset. Both Fitch Ratings and Moody’s Investors Service assigned Aramco the fifth-highest investment grade, the same as Saudi sovereign debt, but lower than oil majors Exxon, Shell and Chevron Corp.
The company is preparing to raise debt in part to pay for the acquisition of a majority stake in domestic petrochemical group Sabic, worth about $69 billion. The deal is a Plan B to generate money for Saudi Arabia’s economic agenda after an IPO of Aramco was postponed. In effect, Crown Prince Mohammed bin Salman is using the firm’s pristine balance sheet to finance his ambitions.
Aramco will pay 50 percent of the Sabic acquisition cost when the deal closes and the rest over the subsequent two years, according to a person who saw a presentation made to potential investors on Monday. Aramco declined to comment.
The 470-page bond prospectus, filed with the London Stock Exchange, detailed a litany of risks for prospective investors, including missiles falling on Aramco’s installations, the impact of proposed U.S. antitrust laws on OPEC, the fight against climate change, and even the risk that Saudi Arabia will break the peg between its currency, the riyal, and the U.S dollar. It also revealed the Saudi oil giant was the victim of a "successful" cyber attack in 2012 that forced the company to move some operations into "manual" mode.
While the prospectus revealed the richest company on the planet, it also showed how reliant Aramco is on high oil and natural gas prices. In 2016, when the price of Brent crude plunged to average $45 a barrel and OPEC cut production, the company struggled to break even. Net income for the full year was just $13 billion and free cash flow a tiny $2 billion.
The kingdom’s dependence on the company to finance social and military spending, as well as the lavish lifestyles of hundreds of princes, places a heavy burden on Aramco’scash flow. Aramco pays 50 percent of its profit on income tax, plus a sliding royalty scale that starts at 20 percent of the company’s revenue and rises to as much as 50 percent with the price of oil.
Aramco reported cash flow from operations of $121 billion and $35.1 billion in capital spending, and paid $58.2 billion in dividends to the Saudi government in 2018, according to Moody’s. In a presentation to potential bondholders, the company said its "ordinary dividend" last year was $52 billion. There wasn’t an immediate explanation about the gap between the two figures.
Fitch said its A+ rating reflects the “strong links” between the company and the kingdom, and the influence the state has on Aramco through regulating the level of production, taxation and dividends.
“Over time, a low oil price environment could cause a sustained fiscal deficit for Saudi Arabia that could result in changes down the line for Aramco’s fiscal regime,” said Neil Beveridge, an energy analyst with Sanford C. Bernstein & Co. in Hong Kong. “You can’t disassociate the sovereign government from Aramco given the very close relationship and the contribution Aramco makes to the overall funding for Saudi Arabia.”
Aramco reported funds flow from operations -- a measure closely watched by investors and similar to cash flow from operations -- of $26 abarrel equivalent of oil last year, according to Fitch. That’s below what Big Oil companies such as Shell and Total SA enjoy, at $38 and $31 per barrel, respectively.
“Funds from operations, which is operation cash flows before working capital changes, is the best measure to compare oil companies’ profitability, since Ebitda does not take into account taxation,” Dmitry Marinchenko, senior director at Fitch in London, said in an interview.
Aramco told potential bondholders it generated operating cash flow of $121 billion in 2018. Although that’s significantly higher than oil majors produce, the difference isn’t a large as the Ebitda or the net income. Shell, for example, reported cash flow of $53 billion, despite a significantly lower oil and gas production than Aramco. Exxon reported cash flow last year of $36 billion.
Fitch’s A+ rating for Aramco is one level below the AA- for both Shell and Total. The Moody’s rating is well behind Exxon’s top Aaa level.
The oil giant has mandated banks to hold a roadshow for dollar-denominated notes from April 1, potentially including tranches from three to 30 years, according to a person familiar with the matter. Fitch said that Aramco planned to pay for the 70 percent stake in Sabic “in installments over 2019-21.”
The company will hold meetings with investors in coming days in cities including London, New York, Boston, Singapore, Hong Kong, Tokyo, Los Angeles and Chicago. Aramco picked banks including JPMorgan Chase & Co. and Morgan Stanley to manage the debt offering.
The bond plan, credit rating and the publication of the first extracts of Aramco’s accounts are all part of the ambitions of Prince Mohammed, who controls most of the levers of power in the kingdom and wants to pursue an IPO as part of his plans to ready the country for the post-oil age. Yet his ambition to secure a $2 trillion valuation has faced pushback from global investors, prompting a delay in the IPO.
For all the shock and awe in Aramco’s big reveal, the published numbers appear to leave that valuation a long way off, implying a dividend yield about half of what Shell pays.
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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.