Are Inverted Yield Curves A Harbinger Of Lower Oil Prices?

---

The first quarter of 2019 was lovely for oil bulls as Brent increased 27% while WTI climbed 33%. With Brent now trading near the $69 mark and WTI above $60, there are a fair number of prominent analysts who see OPEC+ tightening and unplanned outages in Iran and Venezuela push oil higher by at least another $10 or perhaps even $20 per barrel. We concur that fundamentals are improving and see potential for supply/demand balances to tighten further as US waiver deadlines on Iranian crude are revisited in May while Venezuela and its oil sector descends further into chaos.

Unfortunately, there is also a black macroeconomic cloud over commodity markets in the form of deeply depressed global bond yields which have recently flipped inverted across some parts of the maturity curve. Fixed income markets are screaming that the global growth picture is unimpressive and to us this lack of confidence continues to suggest that the easy money for crude oil bulls has already been made. While there is reasonable hope for upward momentum this spring- do not expect to see similar returns on oil in Q2 to what we saw in Q1.

So where are these global interest rates trading and why should oil markets care? Government bonds have rallied substantially since the fall as expected global growth rates have decelerated and central banks have taken dovish measures to prop-up economic performance. In the US, the 10yr yield has dropped from 3.2% to 2.4% in the last six months and the yield on the 3-month T-Bill briefly traded above the yield on the 10yr- an inversion which many believe forecasts recession. In Japan 10yr JGB has dropped from 0.15% to -0.86%. In Germany the 10yr Bund yield has decreased from 0.6% to -0.07% and in Italy it’s moved from 3.6% to 2.5%. On one hand, lower rates should boost consumption and weaken currencies. On the other, more sinister hand, low global rates can have a negative impact on market sentiment adding to the nonstop flow of ‘demand concern’ headlines which are already cutting into oil prices. Bond traders and central bankers are clearly concerned with the current global economic picture and our view is t
hat this will spill into commodity markets and dampen rallies for oil in 2Q.

To confirm, we aren’t arguing that the global economy will dip into recession in 2Q 2019 and historical data doesn’t insure that weak economic performance leads to low oil prices (see chart of oil prices in 2009 and 2010.) However, we are firm believers in the idea that the constant thumping of headlines bemoaning the sicknesses of the global economy will weaken sentiment and limit the ability of oil to rally to the $90 mark which some analysts are now predicting.

Where could our analysis go wrong? April could prove to be an important month for the global economy in 2019 with reasonably high odds of including a US/China trade deal. While our concern has been and still is the event will illustrate the ‘buy the rumor, sell the news’ theory, there are obviously non-zero odds that it will boost economic confidence. Our first economic data point of the month was the release of China’s manufacturing PMI for March on Monday which soundly beat forecasts by moving back in to expansion territory. We’ll need much more of this type of news to move significantly higher in Q2.

Quick Hits

- China’s manufacturing PMI screamed higher in March printing 50.5- well above expectations. The index has averaged 50.6 over the last twelve months but just 49.8- slightly in contraction territory- over the previous six months. The print was widely interpreted as a green light to buy risk assets leading to YTD highs for global stocks and crude oil.

- China’s data was such a story early this week it seems to have overshadowed early estimates of OPEC’s March production was also very much noteworthy. Bloomberg estimated the cartel’s output at 30.385m bpd representing a 4yr low and a m/m decline of about 300k bpd. Saudi Arabia was to thank for most of the cut with a m/m decline of about 280k bpd to 9.82m bpd. Iran’s production was estimated to be down 30k bpd to 2.71m bpd. Iraqi output fell 780k bpd to 4.55m bpd and Venezuelan output fell 180k bpd to 890k bpd. Libya registered by far the largest gain with a 200k bpd m/m increase to 1.1m bpd due to the restart of its Sharara field.

- WTI settled above its 200-day moving average this week for the first time since October. In our judgment crude oil flat price still looks technically strong. It would be very hard to look at charts and argue the market looks bearish.

- In equity markets the S&P 500 traded over 2,865 this week marking a 15% gain for the year. The Shanghai Composite traded near 3,175 representing a 29% YTD gain.

- Crude oil spread markets also moved higher this week with Brent’s prompt 6-month spread reaching +1.85 representing a 5-month high. WTI spreads have also flipped comfortably into backwardation with the WTI June/December spread trading +75 cents.

- Iran’s oil minister stated he expects OPEC+ to extend their current deal beyond June following a meeting with Russia’s energy minister. Russia’s crude production in March is currently estimated near 11.3m bpd which is slightly above its target production level in the current agreement.

- Chinese President Xi offered a cooperative tone regarding the US in comments from Beijing this week noting that the two countries should develop relations based on consultation and stability.

- US gasoline spreads continue to forecast reasonably strong fundamentals this summer as the June contract traded at a 24-cent per gallon premium to the December contract.

DOE Wrap Up

- US crude inventories increased 2.8m bbls last week with help from a decrease in demand and a decline in exports.

- Overall crude stocks are higher y/y by 4% over the last four weeks and 1% below their seasonal 5yr average.

- The US has 27.6 days of crude oil supply on hand and is higher y/y by about 7% over the last four weeks. Days of supply is ½ day below its seasonal 5yr average for late March/early April.

- US crude production continued to plod along at its all-time high print of 12.1m bpd.

- Cushing stocks increased by more than 500k bbls to 46.9m bbls.

- US crude imports fell to 6.5m bpd and are averaging 7m bpd so far in 2019 after averaging 7.8m bpd in 2018. Exports fell from 3.4m bpd to 2.9m bpd and are averaging 2.7m bpd after averaging 1.96m bpd in 2018.

- US refiner demand continues to disappoint printing 15.8m bpd last week for a 400k bpd w/w decline. Overall inputs are averaging 16.36m bpd which is lower by 80k bpd versus 2018. US refining margins also fell this week with the WTI 321 crack moving from $22/bbl to $20/bbl.

- On a more bullish note, US gasoline inventories continue to fall and decreased by 2.9m bbls last week to 239m bbls. Total US gasoline stocks are flat y/y.

- Inventories declined despite stubbornly lower US gasoline demand + exports which printed 9.82m bpd last week. Demand has averaged 9.98m bpd over the last four weeks which is lower by about 200k bpd y/y. Overall demand is averaging 9.78m bpd so far in YTD in 2019 which is lower y/y by 65k bpd.

- US distillate inventories fell 2m bbls w/w to 130m bbls and are higher y/y by 1% over the last four weeks

Global Intelligence Report - 3rd April 2019

---

Sources

- Aramco insider (current high-level Aramco staff)
- Former Aramco executive
- Turkish investigative journalists in Ankara and Istanbul

Every Reason to Be Alarmed About Aramco

Inside the corridors of Saudi Aramco, there is panic. While media report on the brilliant $69-billion takeover of SABIC petrochemical company by Aramco - particularly emphasizing alleged cost savings for both--the truth of the matter is that this is a disaster for the Saudi oil giant. As we speak to our sources inside Aramco in the wake of the SABIC deal and the $10-billion bond sale, the mood is one of defeat.

Despite the best efforts of Aramco’s top brass to subvert Mohammed bin Salman’s cash grab from its long-siloed balance sheet, the young prince has emerged victorious. The deal will essentially see almost $70 billion transferred from Aramco to the Public Investment Fund (PIF - the Saudi sovereign wealth fund), which Prince Mohammed controls completely.

Aramco executives opposed the deal because it didn’t make economic sense, especially at the high valuation it was ordered to accept - but the fears run even deeper.

For a decade, Aramco has operated as a quiet economic advisory office for the royal family: It is regularly sent details of non-oil deals for analysis by highly trained staff. Those sane economists and analysts, together with their bosses, fear Prince Mohammed will sink huge amounts of the new funds into investments that are highly unlikely to address the country’s pressing economic reform needs.

One example is the massive NEOM real estate project that is proving to be a grandiose megaproject in the tradition of similar efforts by King Abdullah and Hosni Mubarak. Another example would be investments similar to the $40 billion sent to the Vision Fund. In fact, Softbank is raising a new fund and PIF could again be a major contributor.

In the best case, such investments would bring a modest return and even that might be farfetched considering the depth of talent on the fund’s staff. Even so, this will not likely move the dial on the 2030 plan to kick the country’s addiction to oil revenues and high subsidies. Alarm bells are ringing at Aramco - not for its own future, but for the future of the country as a whole.

And in the meantime, Aramco has had to divulge one of its best-kept secrets: The exact size of its Ghawar oilfield, the largest conventional oilfield in the world. The cat was let out of the bag on Monday when Aramco had to publicly report its profit for the first time in its history. Investors had been foaming at the mouth over this field for years, speculating that it topped 5 million bpd. But now everyone knows it doesn’t - instead, it’s officially 3.8 million bpd. That makes Aramco’s future “valuation” even more tenuous. However you look at it, MBS is killing Aramco, and Aramco feels the dilution keenly.

What Erdogan’s Local Election Loss Really Means

Cracks are showing in Erdogan’s power base in Turkey. In local elections held on Sunday, Erdogan’s ruling Justice and Development Party (AKP) appears to be losing popular support. But it is important to put this into perspective. Based on the election results, the AKP has just over 40% of popular support. But they can combine this with their nationalist allies, the MHP, to maintain the majority. Despite Erdogan’s victory speech on March 31, the reality is that the AKP lost almost all the provinces along Turkey’s western and southern coasts, and much of the heartland, including the capital province of Ankara. The AKP even lost Istanbul, the most important mayoral seat, though the margin was slim and Erdogan is claiming irregularities and vowing to contest it.

The bigger picture is that the elections show that the economy remains the most important factor for voters. Opposition parties took advantage of the ongoing economic downturn and the devaluation of the Turkish lira by forming clever provincial alliances that ultimately led to the AKP’s major setback. This is a massive achievement considering that Erdogan completely controls the media. Right now, Erdogan is worried, but he also has time on his side. There won’t be any more elections until 2023 and he will carefully deal with these losses until then.

Game Over for Algerian Strongman

Over the past couple of weeks we have stressed the pending climax of seething political unrest in Algeria, which has officially reached its peak with the resignation on Tuesday of President Bouteflika. The military kingmakers gave him no choice in the matter. But from an investor standpoint, a phase of high-level political uncertainty now begins for the gas-rich country, and deals will continue to be put on hold. On Wednesday (3 April), Algeria’s Constitutional Council will convene and the president of the upper house of parliament will become the interim leader for up to 90 days while elections are organized. But this in itself could be highly contentious as the interim leader, based on the constitution, is a Bouteflika ally. Investor concerns are not to be taken lightly, either: This is a dangerous venue to have such a massive political vacuum. It borders Libya and the Sahel, and one can be sure that Islamist radicals are already plotting how they can take advantage of the destabilization. Destabilization in 1988 led to massive riots, unrest and a civil war against radical Islamist forces who are still circling and preparing to strike. In 2013, they attacked and took control of a natural gas facility and took its workers hostage in an incident that the oil and gas world will not likely soon forget.

On the sanctions front ...

Japanese refiners last week put a halt to further imports of Iranian crude, with Japan having failed to obtain a waiver extension from Washington. Japanese refiners are concerned about concluding all insurance-related and financial transactions on the 15 million barrels of Iranian crude cargo they have already loaded before the waiver expires in May. This early cut-off benefits the Middle East and Russia, which will be filling the gap left by Iranian crude. There is considerable infighting right now in Washington over sanction waivers; while this round appears to have been won by the Bolton-crew, which has been pushing for an end to waivers and a harder line on Iran, detractors have been concerned about giving key allies extensions. However, a statement coming out of the White House on Friday suggested that the waiver period is over - until Trump feels that sufficient leverage has been gained for another extension.

In the meantime, the sanctions regime against Venezuela is attempting to tighten the noose, with Washington up in arms over traders and refiners who continue to deal with what is still the Maduro regime’s crude oil. While the Venezuelan oil industry is under sanctions already, traders and refiners in Russia, India and Europe continue to supply Venezuela with fuel. Where this gets complicated is that not all of these transactions are in violation of sanctions already implemented. So, essentially, Washington is now threatening traders with new sanctions if they continue to deal with fuel going into Venezuela even if it is not in explicit violation. There is absolutely no legal precedent for Washington’s demand in this case. Traders are not violating sanctions if they are not using the US financial system for trades or barters, so this is quite simply a squeeze that is not backed by law.

Production

- Iran’s giant South Pars natural gas field has increased production by 12 percent over last year, according to official data. South Pars has 14 trillion cubic meters of natural gas and 19 billion barrels of gas condensate--a figure that represents half of the country's overall reserves (8% of the world’s total reserves).

- While Alberta has continued to reduce production via government mandate, Alberta’s crude inventories rose again in February thanks to rail shipment bottlenecks that have rendered it uneconomical. According to official data, by the end of February, Alberta had 72 million barrels of oil in its inventory--up by 3.9 million barrels from a month prior.

- For March, OPEC production was at its lowest level in four years, with combined OPEC production at 30.4 million bpd--280,000 bpd lower than February.

- French oil giant Total has now commenced crude production at the second half of its Angola Kaombo project, doubling overall capacity to 230,000 bpd at the floating production storage and offloading facility. This is a significant achievement that effectively represents 15% of the country’s entire oil production.

The deal book

- US private-equity firm Carlyle Group LP has secured a 50-year lease in a Texas land deal for its $1-billion Corpus Christi oil export terminal project. The 200-acre plot will be the site of the terminal and docks designed to load US crude for global markets. That is the second piece of good news for Carlyle in as many weeks: Last week, a Texas court lifted a temporary injunction preventing Corpus Christi officials from entering into the contract.

- There have been some interesting LNG developments in Equatorial Guinea this week, with new deals related to Noble Energy and Marathon Oil Corp. Offshore in this venue, Noble Energy has natural gas Blocks, while Marathon Oil has the PUnta Europa LNG plant. The government has agreed to a deal for the Alen Unit JV project which will construct a 950-million-cubic-feet-capacity pipeline from the Noble Energy platform to Marathon’s LNG plant, where it will be processed for export. This is a massive 70-kilometer pipeline and first gas is slated to start flowing in Q1 2021.

- Also on the LNG scene, Sempra Energy’s Mexican subsidiary (Energia Costa Azul, ECA) has received two LNG authorizations from the US DOE for exporting natural gas produced in the US to Mexico, and for re-exporting LNG to non-FTA countries. Sempra is keen to let investors know that the timing here is significant as it is scheduled to meet with customers and partners in Shanghai this week.

- A major merger between Japan’s Idemitsu Kosan Co. and Showa Shell Sekiyu K.K. on Monday has effectively led to the creation of a new national oil giant that will dominate Japan’s wholesale petroleum scene. Idemitsu is the second-largest oil wholesaler in Japan, and Showa Shell is the fourth-ranked in the country.

- The $1.7-billion merger between Denbury Resources and Penn Virginia Corp. is now defunct. Both sides have agreed to terminate Denbury’s acquisition of Penn, citing opposition from Penn shareholders along with difficult market conditions. For Denbury, the acquisition of Penn was about gaining a strong foothold in the Eagle Ford.

ConocoPhillips in focus ...

ConocoPhillips is our chosen company in focus this week due to a number of developments and upcoming events. First, there have been indications this week that there is specific interest in the company’s North Sea assets (mature fields) coming from Chrysaor Holdings Ltd. After an earlier failed attempt to divest these assets for $3 billion failed, Conoco relaunched bidding again in January. Overall, the company is trying to divest all assets that are not related to US shale exploration, but has hit hurdles. Chrysaor, while it has not officially confirmed its interest, is rumored to be considering the Conoco North Sea assets. Cutting a deal on this sale would be good timing for Conoco. The company will be announcing its quarterly earnings on April 25, and analyst forecast consensus estimates are at about $0.78 per share. Also weighing in on shares will be a recent victory (even it was following a major defeat) when an arbitral tribunal awarded it $8.7 billion in compensation for the expropriation of its Venezuelan assets.

The politics of permitting…

There have been two major developments this week on the US regulatory front that should be high on investor radar. First, Trump has signed a presidential permit for the highly controversial construction of TransCanada’s Keystone XL pipeline. The permit runs the full spectrum for TransCanada, approved construction, connection, operation and maintenance of the US-Canada pipeline. In November the original March 2017 permit for the pipeline was invalidated by the federal judge in Montana. From a legal perspective, it is still possible that even with this presidential permit, another environmental review will still need to be conducted and approved by a court, though the White House is clearly hoping to bypass this process.

The second development concerns Alaska drilling: While we saw an April 2017 executive order from Trump reverse an Obama-era ban on Arctic and Atlantic drilling, an Alaska judge has now blocked Trump on both fronts, saying that the president had exceeded his authority in April. The April 2017 executive order has now been restored. It can still be revoked by Congress, and the federal judge’s ruling can also be sent to the Ninth Circuit Court of Appeals. But we caution that this is really a red herring for investors. Buried evidence about a much-talked-about oil well drilled in the Alaskan Arctic four decades ago suggests there was nothing much to write home about. This move is largely political and not economic.

Who Replaces Venezuela’s Lost Barrels?

---

The heavy-light imbalance in the global crude market continues to rock tenets that were previously thought immutable. Behind most of the disequilibrium one finds the United States – in the past 5-6 years most of the accretion in global crude production was a result of the US expansion of light sweet shale crude, amidst which the Trump Administration initiated a sanctioning fiesta that saw more than 1mbpd of Iranian medium sour oil scraped off the supplier market and another 1mbpd eliminated from Venezuela’s export portfolio. Ironically, the much-reduced heavy supply hurt primarily USGC refiners, who, with an aggregate heavy crude refining capacity of 2.8mbpd, are best suited to refine Latin American and Middle Eastern heavy barrels. Is there a way out from this for the Gulf Coast?

In the calendar year of 2018, Mexico was the largest supplier of heavy barrels to the United States, exporting some 670 000 barrels per day on an annual average basis (predominantly the 22° API and 3.3 percent Sulphur-containing Maya). Venezuela was second with 0.45mbpd on an annual average basis, spread across a variety of grades that range from the most popular DCO, Zuata, Hamaca to the less frequent Merey and Boscan. Should the United States quit importing Venezuelan crude altogether, for the American national books that would mean a gaping hole of 165 million barrels per year (out of the total 730 million barrels of heavy crude US refiners bought, i.e. almost the quarter) which need to be replaced with something.

There already emerged a rule of thumb which says that whenever OPEC cuts production, it is going to be heavy or medium sour output that is being curtailed. One can see that in the physical movements around the globe in general and the Middle East in particular, one can discern it in the collapse of the Brent-Dubai spread (which traditionally hovered around 3-4 USD per barrel yet dropped as low as some 30-40 cents in January 2019 and only reached 1.5 USD per barrel, i.e. half of the traditional premium, on April 01). As the Vienna Alliance is still keeping a production cut in vigor, it would be logical to assume that if the United States is to procure sufficient volumes of heavy sour crude, OPEC member countries (or OPEC+ participants) would be out of question. Let’s take a closer look.

Mexico

Even though Mexico is the largest seaborne supplier of heavy crudes to the United States, most of its crude is actually heading to Asia and to a lesser degree Europe, under long-term contracts, which renders the task of increasing Mexican imports quite complex. Moreover, Mexico’s production peaked in 2004 at 3.8mbpd and has fallen since then precipitously, reaching a 40-year low at 1.7mbpd in December 2018. Albeit politically somewhat difficult under current circumstances, there might be a way out to the benefit of both Mexico and the US – crude swaps, whereby some crude destined to be refined in PEMEX’s refineries in Mexico, would be swapped for US light sweet.

This would solve Mexico’s perennial headache, massive fuel oil yields in its refining system, whilst also providing complex USGC refineries with a Venezuelan-lookalike, the Mexican Maya. Yet the chances to see this happen are low – they would be much higher if the United States had a national oil company and not a plethora of firms with varying interests. In the long term, as PEMEX’s long-term contracts with Asian buyers run out and its crude production witnesses some sort of a rebound after 2021, it is fully conceivable that some of those volumes would be reoriented towards the USGC. However, in the short-to-mid-term, US firms must seek for viable solutions elsewhere.

Colombia

Behind Mexico and Venezuela, Colombia was the third largest seaborne supplier of heavy crude to the United States in 2018, exporting some 62 million barrels (0.17mbpd). Being less contract-bound than Mexico in terms of volume distribution, Colombian grades such as Castilla and Vasconia did manifest a palpable increase in Q1 2019, especially in March when Colombian exports to the US averaged 0.31mbpd. Chevron took in a substantial amount at its Pascagoula refinery, however the geographic spread of Colombian crude was as wide as possible – from New York and Philadelphia to Lake Charles, LA. Yet as with Mexico above, there is a clear limit to which Colombian exports to the US can go – and it is dictated by dropping production in the Latin American country. It simply cannot export more heavy volumes than the 17-18 million barrels (0.5mbpd) it already does.

Angola

Angolan exports to the United States did witness a minor renaissance, yet its impact is quite limited. American buyers have been buying two VLCCs per month of heavy sweet Pazflor and Dalia in February and March, most likely the same situation will take place in April. This equates to some 60kbpd per month which pales in comparison to the 0.55mbpd US imported from Venezuela in the pre-sanctions period. Moreover, Angolan crudes are a staple diet of Chinese refiners and this level of demand amidst falling production levels has resulted in grades like Dalia (23.7°API and 0.48 percent Sulphur) appreciating to unseen levels – it traded at a hefty 1.20 USD per barrel premium to Dated Brent as of April 02.

Source: OilPrice data.

This brings us to the following bottom line – US refiners can increase their supplies from Colombia or Angola, yet they cannot overpower the declining production trends there. Moreover, they also have to be ready to outbid Chinese, Indian and other Asia Pacific refining powerhouses that have found themselves in a similar situation. Consequently, their best chance is also the most evident one – turn to Canada, an allied country that already is the United States’ largest crude supplier. Canada is pretty much the only heavy crude-producing nation whose production is on the increase and is being administratively curtailed due to pipeline constraints. Apart from the ever-obvious geographical proximity issue, there is a subtler dimension to the United States opting for more Canadian heavy barrels.

Traditional suppliers of heavy barrels to the American market – PEMEX, PDVSA, Ecopetrol and others – are state-owned national oil companies with little American involvement around. Canada, on the other hand, has no national oil company and its producers are oftentimes very intricately linked to US energy interests (take Imperial Oil, the fifth largest Canadian producer, of which ExxonMobil owns 69.6 percent). Moreover, as Canada matters more and more to US refiners, it would not be hard to imagine US oil and gas majors buying up the most profitable companies in a mirror version of Saudi Aramco buys Asian refiners to whom intends to supply with its own crude.

Source: EIA.

The above also sheds a different light on President Trump intensifying pressure to have the 830kbpd Keystone XL pipeline construction launched as soon as possible. Last week he issued a new permit for the oil pipeline that would connect Hardisty, Alberta with Steele City, Nebraska, erasing any references to environmental reviews. The previous presidential permit has been in limbo for quite some time after a federal judge in Montana found the State Department’s environmental impact assessment not appropriate to the scale of undertaking. Despite President Trump’s renewed push, things will not be easy for Transcanada, the operator of the pipeline, as it still has an array of court hearings to win, most notably on water quality and route suitability. Yet oddly enough in a world that is increasingly environmentally conscious, fast-tracking Canadian pipeline projects seems the best-suited strategy for the long-term stability of US refining.

The Hydrogen Economy – A Bonanza For Natural Gas

---

The hydrogen economy might be on its way, but it won’t be arriving any time soon, not until after 2030 at least. If and when it does make an appearance, it is likely to be somewhat different to the image of popular imagination because a hydrogen economy will run primarily on natural gas.

Parts of the hydrogen economy are falling into place, notably significant gains in electrolysing power. Polymer Electrolyte Membrane (PEM) electrolysers now come as complete operating units the size of an ISO container, offering MWs rather than kWs of power and the production of hydrogen is sufficiently pressurised without the need for a compressor for vehicle fuelling or methanation.

A gradual roll out of infrastructure is taking place, but fuel cell vehicle sales lag far behind EVs. Europe, which to some extent is developing hydrogen transit corridors, has less than a 100 hydrogen refuelling stations in operation. Japan has about half that number and the US even less.

Scaling up

PEM technology is being tested at scale at Shell’s Rhineland refinery in Germany, where an electrolyser with peak capacity of 10 MW will be installed by 2020.

“If powered by renewable electricity, the green hydrogen will help reduce the carbon intensity of the site,” says Shell. It may well be powered by renewable electricity and as such is a valuable way of reducing refinery emissions, which is no easy task as emissions from refinery processes tend to be spread over multiple, fairly small sources making capture difficult and expensive.

However, though large-scale for an electrolyser, it is still small-scale in terms of hydrogen production. The refinery requires 180,000 tons of hydrogen a year, while the 10 MW electrolyser will produce just 1,300 tons for an investment of €20 million ($22.6 million), implying that just under 1.4 GW of electrolyser capacity would be needed to meet the refinery’s total hydrogen requirements.

Space would be required to house the electrolysers, although perhaps not as much as might be expected as they could be stacked. The cost would also be substantial, although gains would be made from the scaling up of electrolyser production.

‘Surplus’ power

Apart from scale, the second problem is Shell’s ‘if’ with regard to the use of renewable energy to produce the hydrogen.

Power-to-gas concepts, which have been most widely tested in Germany, offer many attractions, but all are based essentially on what is considered ‘surplus’ renewable electricity. A study published by DNV GL in March, Hydrogen in the electricity value chain argued that renewable hydrogen will be competitive with natural gas by 2035, but the primary source of energy to produce the hydrogen – an energy carrier not an energy source – will still come from cheap surplus renewable electricity.

National energy systems with a high penetration of renewables can and do produce temporary electricity surpluses already. More common is renewable energy curtailment as a result of localised grid congestion.

Power-to-gas concepts use this low (sometimes negative) cost electricity to generate hydrogen and drop it directly into the gas grid. It is an elegant solution in may ways and gas grids can absorb a lot of hydrogen – somewhere in the region of 5-15% by volume, depending on the type of end-use equipment and the nature of the natural gas, regulations allowing.

However, hydrogen producers will not be the only callers on cheap surplus electricity, and they are unlikely to be the most cost effective over the next decade, owing to the efficiency penalties of first electrolysis and then combustion. Batteries or pumped hydro where possible will compete, as will grid development and reinforcement to export surplus electricity to other regions.

Electricity surpluses are not intentional and there are financial incentives to eradicate them; electricity generators are not in the business of providing free electricity. When surpluses reduce, prices rise, and the electricity is no longer cheap.

Power-to-gas implies a deliberate strategy of surplus creation. This is not impossible, but few countries have 100% renewable targets for electricity generation by 2050, let alone the 100% plus which would be needed to meet power demand and also making inroads into heat and transport via hydrogen production.

As hydrogen production is scaled up, there may even be water use implications. PEM electrolysers require much higher water purity than alkaline electrolysers, but in neither is the water recoverable. Water is abundant, but potable water much less so with increasingly large parts of the world suffering from water stress.

Leveraging the benefits

A Japanese study on hydrogen production published in February suggested solar photovoltaics in combination with a battery assisted electrolyser could produce hydrogen in a range of $1.92-$3.00/kg, the lower end being below the US Department of Energy’s target of reducing the levelized cost of hydrogen production to $2.30/kg by 2020.

However, this is only theoretical at present based on future technological advancement. Also, the problem of scale remains, given that solar, despite expanding rapidly, is struggling to make a big dent in the electricity mix because of its low capacity factor.

This is not to undermine the benefits of hydrogen. Its attractions are many. It is easy to distribute up to certain limits with existing infrastructure. It can be produced at any point on an electricity grid, as well as acting as a means of storage for off-grid locations, where renewable energy sources are available. It has the potential to play a key role in the decarbonisation of heat, an area in which progress lags behind the power sector and where the technological options appear much more limited. In transport, fuel cell vehicles eradicate emissions at the point of use.

These advantages suggest that the technologies required to develop a hydrogen economy will continue to attract research and development in an attempt to reduce costs. But this will take time. It also suggests that in rolling out the hydrogen economy, hydrogen use will grow quicker than the ability to produce fully decarbonised hydrogen.

Steam reforming

The fallback position is to steam reform natural gas, a process which produces carbon dioxide and one that is likely to remain cheaper than other means of hydrogen production well into the 2030s, suggesting steam reformation will prove much more than a transitional arrangement.

The hydrogen economy is likely to evolve based on natural gas and LNG in the first instance. This will deliver the benefit of single, large site rather than small, multiple-point carbon dioxide emissions, facilitating capture and storage.

The deep decarbonisation required by the targets promulgated by the EU for 2050 require an ‘all of the above’ strategy in which hydrogen cannot be ignored. Even in areas like shipping, deep decarbonisation targets to hit 2050 targets set by the International Maritime Organisation assume growth in hydrogen as a shipping fuel post-2030 – yet another call on the nascent industry.

Steam reforming natural gas can provide the volume of hydrogen production required to develop and deploy hydrogen’s end-use applications. However, it also means that Carbon Capture and Storage (CCS) becomes a critical enabling technology for the hydrogen economy, making real environmentalists’ fears not that CCS locks fossil fuels into the system long term, but that the pursuit of the hydrogen economy does - a situation in which CCS could not be allowed to fail.

Higher Oil Prices Are In The Pipeline

---

Things are getting interesting again on the crude market, with Donald Trump relaunching his Twitter attacks on OPEC, albeit in much more diplomatic wording now, amid US-China trade talk prospects brightening after several weeks of market skepticism. Against the background of crude oil prices rising, President Trump also took issue with the OPEC production cuts rendering crude prices too high and threatened the blackout-stricken Venezuela with another round of sanctions. This plethora of geopolitical factors easily prevailed over the American Petroleum Institute and EIA both of which confirmed a crude inventory build.



Thus, for the first time in almost six months, the global crude benchmark Brent edged very close to 70 USD per barrel, pulling off a solid four consecutive days of growth. On Wednesday afternoon the Western hemisphere benchmark WTI traded at around 62.5-62.8 USD per barrel.

1. Saudi Aramco Publishes Financial Results for First Time Ever

- Just as Saudi Aramco announced its intent to but 70 percent of Saudi petchem holding Sabic, the Saudi national oil company disclosed its 2018 financial results, for the first time ever.
- The Saudi NOC’s revenues exceeded $356 billion last year, still mostly generated by crude sales which accounted for 56.4 percent of the total (down exactly 30 percent from 2016).
- Saudi Aramco reported a ground-breaking $111 billion net income in 2018, surpassing past results of $76 billion in 2017 and $13 billion in 2016.
- Saudi Aramco’s crude production averaged 10.3mbpd last year, with total production reaching 13.6mbpd of oil equivalent on an annualized basis.
- Saudi Aramco’s proven reserves as of 2017 year-end were assessed at 260 billion barrels of oil equivalent, giving the Gulf nation a 55 years worth of reserve bounty.
- At the same time, Fitch and Moody’s have assigned a first-ever credit rating to Saudi Aramco, with the former assessing it as an A+ investment, whilst the latter gave it an A1 grade.

2. ExxonMobil Seeking a Nigeria Exit



- According to market rumours, ExxonMobil is seeking to sell its upstream assets in Nigeria as part of its promised $15 billion divestment programme.
- This is the second known instance of Exxon’s divestment drive, concurrently seeking to sell the totality of its Azerbaijani assets.
- The US firm’s Nigerian portfolio is among the most prolific in Africa, yet it is declining for some time already, hitting 0.21mbpd last year from the peak of 0.4mbpd in 2007.
- ExxonMobil would not be the first Western major to decrease its Nigerian exposure after Chevron, Shell and Total, however might be the first to leave the country altogether if it maneges to find a suitable buyer (previously it was NNPC buying majors’ shares).
- This does not mean ExxonMobil will not be looking at new projects in Africa – as recently as March the US major was holding top-level talks with the Algerian Sonatrach to enter the Algerian market.

3. Brazilian Buzios Makes Its Way to China

- As the heat intensifies over those heavy volumes that are still available on the global market, Chinese refiners have been buying up Brazil’s latest addition to its export portfolio, Buzios.
- Buzios is very similar in quality to Brazil’s flagship export grade Lula (28° API) – it has an API density of 28.4° API and contains 0.3 percent Sulphur.
- Buzios is traded at a 20-30 cent per barrel discount to Lula as its calcium content is higher, requiring refinery pre-treatment.
- Brazil has benefited greatly from China’s appetite for heavy barrels, with its exports to China rising 37 percent y-o-y in 2018 to 635kbpd (edging even higher this year, to 966kbpd so far).
- More than half of Brazilian exports to China go to the Shandong province where the overwhelming majority of teapots is currently located.
- Petrobras launched the P-76 platform on February 19 and the P-77 platform on March 18, eventually paving the way for the Buzios field’s first-phase peak production capacity of 150kbpd.
- Total Buzios production might even go as far as 750kbpd by 2021, as Petrobras intends to bring in additional four production platforms.

4. Concurrently, US Cargoes to China on the Rise

- For the first time since September 2018, China’s largest refiner Sinopec started buying US crudes for its refining system via its trading subsidiary Unipec.
- We have already covered the Chinese independent refiners’ restart of US imports earlier this year, notably that of Shandong-based Hongrun which bought a cargo of Eagle Ford.
- The fact that state-owned companies are now back at it again after a prolonged hiatus marks a significant shift in the Chinese oil market.
- Unipec has chartered the 1.2MMbbl MT Maran Artemis early March already, however only now did the company’s involvement become known.
- Unipec is also bringing over a 2MMbbl WTI-laden MT Noble, destined for the port of Zhanjiang.
- According to official Chinese government data, China did not buy any US crude between October 2018 and January 2019, however some Eagle Ford and WTI volumes did reach it indirectly via South Korea.

5. Algeria Lowers April-Loading Saharan Blend OSPs

- Algerian state oil company Sonatrach has cut its April-loading official selling prices (OSP) for its flagship Saharan Blend crude from a 30 US cent per barrel premium against Brent to parity with it.
- The news comes amid Sonatrach selling out its April volumes and already trading May-loading ones at a Brent Dated parity or a 10 cent per barrel premium to it.
- Before stepping down President Bouteflika revamped the governing cabinet of ministers, with Energy Minister Mustapha Guitouni being reshuffled for Mohamed Arkab, head of the Algerian gas company Sonelgaz.
- Europe is following the Algerian developments very attentively as Algeria is a key natural gas supplier, meeting 10 percent of the continent’s demand.
- The mild winter of 2019 has resulted in Sonatrach seeing its oil and gas revenues drop 7.5 percent in January-February, on the back of a 23-percent fall in pipeline gas exports.

6. ADNOC OSPs Witness a Modest Dubai Differential Cut

- United Arab Emirates’ national oil company ADNOC has increased the retroactive official selling prices for all of its four crude grades for March-loading cargoes, at the same time narrowing their differentials against Platts Dubai monthly average.
- ADNOC’s flagship grades – Murban, Das and Upper Zakum – have witnessed a 11 cent per barrel, 1 cent per barrel and 6 cent per barrel month-on-month decrease against the Dubai benchmark.
- ADNOC set the retroactive March OSP for Murban at 68.60 USD per barrel, whilst Das was fixed at 68 USD per barrel.
- The only ADNOC crude which saw its Dubai differential increase as compared to February was the recent addition Umm Lulu, whose March OSP was se tat 68.55 USD per barrel.
- Thus, the Umm Lulu premium to Dubai rose 9 cents per barrel month-on-month to 1.62 USD per barrel, also narrowing the gap between Umm Lulu and Murban to just 5 cents.

7. Gabon Licensing Round Runs Off the Rails

- Last year Gabon promised to wrap up the nation’s 12th shallow and deepwater licensing round by the end of June 2019, yet things have not budged an inch since then.
- Apparently the 34 blocks in question ought to be awarded by September (initially set for April, then June), however there is no legal certainty this deadline will not be moved again.
- Availing themselves of President Ali Bongo’s illness-induced absence, a host of military officers claimed they have taken over the country in January 2019, yet were quickly quashed by the Gabonese military.
- The subsequent halt on all development projects comes as a blow to Gabon, whose proposed state ownership conditions (15 percent carried interest and a 10-percent stake in fields) seem to be much more favorable than that of African peers.
- The Gabonese government also promised to rewrite the hydrocarbon code, eliminating the 35-percent corporate income tax to lure foreign investors, a promise that is already five months overdue.