It does not seem that long ago when Saudi Arabia’s crown jewel, Saudi Aramco was about to make a huge splash by listing (a tiny portion of itself) publicly for the first time. Although that was less than a year ago, many of the details then have now been glazed over. Over the final quarter of 2019, the IPO timeline was in considerable flux, reportedly because the Saudi Crown Prince was determined to engineer a US$2 trillion debut valuation. It did not. At least not immediately, starting at US$1.88 trillion before briefly hitting target after. Several months later, a global pandemic has significantly reduced that valuation. Not only that, Saudi Aramco no longer has claim to the title of the world’s most valued company. That belongs to Apple.
But that’s besides the point now. What matters is Aramco’s commitments in the lead-up to its valuation. In order to generate the maximum amount of interest, mainly from the ruling and connected Saudi families, Aramco promised to hand out over US$75 billion in annual dividends through 2025. Even in better times, that’s a huge promise. But now that the oil price situation has upended, it seems unsustainable.
For another company, public-listed or private, the solution would be simple. Scale back announced dividend payouts, or stop them completely. That’s what companies like Shell, BP and Total have done. In an economic crisis, most investors would understand. But what if the major shareholder is a government? Aramco is still 98% owned by the Saudi government, and the federal coffers, which run everything from the national airline to plans to open up for official tourism are dependent on the dividends that Aramco pays. Adjusting the dividend payouts is not an option, particularly since the government is already far from balancing its budget even with the current fiscal structure. The blurred line between Saudi Arabia and Saudi Aramco is a double-edged sword; and it is now a liability for a company that finds its hands shackled and its flexibility to manoeuvre cemented down due to its commitments.
This need to prioritise dividends means that Saudi Aramco has a reckoning to face. Its valuation and, indeed, business plan was driven by a diversification strategy that was meant to move Aramco from an upstream-focused titan to an integrated behemoth. Aramco had invested in key refining nodes throughout Asia and the world that ensure captive demand for its crude in key markets. It bought SABIC in a pricey deal that was part of a petrochemicals-heavy downstream dive. It set up an LNG trading desk in Singapore before it even produced a single drop of liquefied natural gas. With dry season in the oil and gas world setting in, some of these projects must now wither so that the rest of Saudi Aramco can survive.
A spate of cancellations and deferments have been announced. The planned US$20 billion crude-to-chemicals plan in Yanbu is likely to be cancelled outright. The decision to purchase 25% of Sempra Energy’s Port Arthur LNG project in Texas is being reviewed. A US$6.6 billion plan to add new petrochemicals capacity at the Motiva refinery on the US Gulf Coast is on pause. Downstream plans linked to greenfield refinery investments in Pakistan, India and China have been delayed. CEO Amin Nasser has slashed CAPEX for 2020 from US$40 billion to US$25 billion, and the March 2020 plans to boost crude output capacity within the Kingdom (to 13 mmb/d from a current 12 mmb/d) have been deferred by a year.
But, as dire as this sounds, this is more of a refocusing rather than a reckoning. There is a certain trend here, where outright cancellations are linked to eliminating risk of excess capacity, while delays are linked to new projects and expansions. In petrochemicals, for example, Aramco’s SABIC purchase means it already has a large surplus of production capacity. Adding to that right now, with the global economy expected to be weak for years, is not good business. But Aramco is also committed to expanding its natural gas/LNG offerings and securing long-term demand nodes through refining for its crude. It is just admitting that now is not the best time to focus on those.
It is then instructive to look at what projects have not been affected by the slash in funding. It remains in talks to acquire a stake in India’s Reliance and an integrated downstream site in China’s Zhoushan. The Yanbu plans are expected to be repackaged as incremental upgrades to existing sites, a move to focus on upgraded brownfield sites over building greenfield ones. And drilling still continues, with Aramco announcing the discovery of two new oil and gas assets near the Kingdom’s border with Iraq, with the Hadabat Al-Hajara and Abraq at-Tulul fields offering a mixture of light crude, condensates and natural gas to the market.
Saudi Aramco is not retreating because it wants to. It is retreating because it has to. All indications now appear to show that Aramco is committed to following the strategy roadmap it has outlined previously. At least in the future, Aramco will become more diversified and in line with industry expectations. The current dividend situation has made Aramco less nimble. Admitting its challenges maybe out of character for Saudi Aramco. But the one thing that all can admit right now is that a pause is necessary in order to figure out the best way forward.
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The constant domestic fighting in Libya – a civil war, to call a spade a spade, has taken a toll on the once-prolific oil production in the North African country. After nearly a decade of turmoil, it appears now that the violent clash between the UN-recognised government in Tripoli and the upstart insurgent Libyan National Army (LNA) forces could be ameliorating into something less destructive with the announcement of a pact between the two sides that would to some normalisation of oil production and exports.
A quick recap. Since the 2011 uprising that ended the rule of dictator Muammar Gaddafi, Libya has been in a state of perpetual turmoil. Led by General Khalifa Haftar and the remnants of loyalists that fought under Gaddafi’s full-green flag, the Libyan National Army stands in direct opposition to the UN-backed Government of National Accord (GNA) that was formed in 2015. Caught between the two sides are the Libyan people and Libya’s oilfields. Access to key oilfields and key port facilities has changed hands constantly over the past few years, resulting in a start-stop rhythm that has sapped productivity and, more than once, forced Libya’s National Oil Corporation (NOC) to issue force majeure on its exports. Libya’s largest producing field, El Sharara, has had to stop production because of Haftar’s militia aggression no fewer than four times in the past four years. At one point, all seven of Libya’s oil ports – including Zawiyah (350 kb/d), Es Sider (360 kb/d) and Ras Lanuf (230 kb/d) were blockaded as pipelines ran dry. For a country that used to produce an average of 1.2 mmb/d of crude oil, currently output stands at only 80,000 b/d and exports considerably less. Gaddafi might have been an abhorrent strongman, but political stability can have its pros.
This mutually-destructive impasse, economically, at least might be lifted, at least partially, if the GNA and LNA follow through with their agreement to let Libyan oil flow again. The deal, brokered in Moscow between the warlord Haftar and Vice President of the Libyan Presidential Council Ahmed Maiteeq calls for the ‘unrestrained’ resumption of crude oil production that has been at a near standstill since January 2020. The caveat because there always is one, is that Haftar demanded that oil revenues be ‘distributed fairly’ in order to lift the blockade he has initiated across most of the country’s upstream infrastructure.
Shortly after the announcement of the deal, the NOC announced that it would kick off restarting oil production and exports, lifting an 8-month force majeure situation, but only at ‘secure terminals and facilities’. ‘Secure’ in this cases means facilities and fields where NOC has full control, but will exclude areas and assets that the LNA rebels still have control. That’s a significant limitation, since the LNA, which includes support from local tribal groups and Russian mercenaries still controls key oilfields and terminals. But it is also a softening from the NOC, which had previously stated that it would only return to operations when all rebels had left all facilities, citing safety of its staff.
If the deal moves forward, it would certainly be an improvement to the major economic crisis faced by Libya, where cash flow has dried up and basic utilities face severe cutbacks. But it is still an ‘if’. Many within the GNA sphere are critical of the deal struck by Maiteeq, claiming that it did not involve the consultation or input of his allies. The current GNA leader, Prime Minister Fayyaz al Sarraj is also stepping down at the end of October, ushering in another political sea change that could affect the deal. Haftar is a mercurial beast, so predictions are difficult, but what is certain is that depriving a country of its chief moneymaker is a recipe for disaster on all sides. Which is why the deal will probably go ahead.
Which is bad news for the OPEC+ club. Because of its precarious situation, Libya has been exempt for the current OPEC+ supply deal. Even the best case scenarios within OPEC+ had factored out Libya, given the severe uncertainty of the situation there. But if the deal goes through and holds, it could potentially add a significant amount of restored crude supply to global markets at a time when OPEC+ itself is struggling to manage the quotas within its own, from recalcitrant members like Iraq to surprising flouters like the UAE.
Mathematically at least, the ceiling for restored Libyan production is likely in the 300-400,000 b/d range, given that Haftar is still in control of the main fields and ports. That does not seem like much, but it will give cause for dissent within OPEC on the exemption of Libya from the supply deal. Libya will resist being roped into the supply deal, and it has justification to do so. But freeing those Libyan volumes into a world market that is already suffering from oversupply and weak prices will be undermining in nature. The equation has changed, and the Libyan situation can no longer be taken for granted.
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According to 2018 data from the U.S. Energy Information Administration (EIA) for newly constructed utility-scale electric generators in the United States, annual capacity-weighted average construction costs for solar photovoltaic systems and onshore wind turbines have continued to decrease. Natural gas generator costs also decreased slightly in 2018.
From 2013 to 2018, costs for solar fell 50%, costs for wind fell 27%, and costs for natural gas fell 13%. Together, these three generation technologies accounted for more than 98% of total capacity added to the electricity grid in the United States in 2018. Investment in U.S. electric-generating capacity in 2018 increased by 9.3% from 2017, driven by natural gas capacity additions.
The average construction cost for solar photovoltaic generators is higher than wind and natural gas generators on a dollar-per-kilowatt basis, although the gap is narrowing as the cost of solar falls rapidly. From 2017 to 2018, the average construction cost of solar in the United States fell 21% to $1,848 per kilowatt (kW). The decrease was driven by falling costs for crystalline silicon fixed-tilt panels, which were at their lowest average construction cost of $1,767 per kW in 2018.
Crystalline silicon fixed-tilt panels—which accounted for more than one-third of the solar capacity added in the United States in 2018, at 1.7 gigawatts (GW)—had the second-highest share of solar capacity additions by technology. Crystalline silicon axis-based tracking panels had the highest share, with 2.0 GW (41% of total solar capacity additions) of added generating capacity at an average cost of $1,834 per kW.
Total U.S. wind capacity additions increased 18% from 2017 to 2018 as the average construction cost for wind turbines dropped 16% to $1,382 per kW. All wind farm size classes had lower average construction costs in 2018. The largest decreases were at wind farms with 1 megawatt (MW) to 25 MW of capacity; construction costs at these farms decreased by 22.6% to $1,790 per kW.
Compared with other generation technologies, natural gas technologies received the highest U.S. investment in 2018, accounting for 46% of total capacity additions for all energy sources. Growth in natural gas electric-generating capacity was led by significant additions in new capacity from combined-cycle facilities, which almost doubled the previous year’s additions for that technology. Combined-cycle technology construction costs dropped by 4% in 2018 to $858 per kW.
Fossil fuels, or energy sources formed in the Earth’s crust from decayed organic material, including petroleum, natural gas, and coal, continue to account for the largest share of energy production and consumption in the United States. In 2019, 80% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.
The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production and imports) to disposition (consumption, exports, and net stock additions). In this diagram, losses that take place when primary energy sources are converted into electricity are allocated proportionally to the end-use sectors. The result is a visualization that associates the primary energy consumed to generate electricity with the end-use sectors of the retail electricity sales customers, even though the amount of electric energy end users directly consumed was significantly less.
Source: U.S. Energy Information Administration, Monthly Energy Review
The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but production has also risen for non-fossil fuel sources such as nuclear power and renewables. As a result, fossil fuels have accounted for about 80% of U.S. energy production in the past decade.
Since 2008, U.S. production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 15 quadrillion British thermal units (quads), 14 quads, and 4 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 10 quads since its peak in 2008.
Source: U.S. Energy Information Administration, Monthly Energy Review
In 2019, U.S. energy production exceeded energy consumption for the first time since 1957, and U.S. energy exports exceeded energy imports for the first time since 1952. U.S. energy net imports as a share of consumption peaked in 2005 at 30%. Although energy net imports fell below zero in 2019, many regions of the United States still import significant amounts of energy.
Most U.S. energy trade is from petroleum (crude oil and petroleum products), which accounted for 69% of energy exports and 86% of energy imports in 2019. Much of the imported crude oil is processed by U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 42% of total U.S. energy exports in 2019.
Source: U.S. Energy Information Administration, Monthly Energy Review
The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2019. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption has decreased by 11 quads. In 2019, renewable energy consumption in the United States surpassed coal consumption for the first time. The decrease in coal consumption, along with a 3-quad decrease in petroleum consumption, more than offset an 8-quad increase in natural gas consumption.
EIA previously published articles explaining the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.
Principal contributor: Bill Sanchez