Can The World Avoid A Global Oil Supply Crunch?

The European gas crunch has been hogging headlines for months now, and with good reason – the continent is still struggling to secure enough energy for its winter needs. But there may be a worse crunch looming over the world, and that would be an oil crunch.

The signs are there for everyone to see should they bother to look: OPEC’s spare capacity is dwindling, new discoveries are at historic lows, and banks are growing increasingly reluctant to engage with the oil and gas industry because of the rise of ESG investing.

Meanwhile, supermajors are curbing their output as they focus on growing their low-carbon business.

A capacity crisis?

“Shrinking global spare capacity underscores the need for increased investments to meet demand further down the road,” the International Energy Agency said in its October 2021 Oil Market Report, after noting that as OPEC ramped up production under its return-to-normal deal, its spare production capacity will fall considerably, potentially reaching just 4 million bpd by the fourth quarter of this year. That would be down by more than half from 9 million bpd at the start of 2021.

Spare capacity is an important indicator of production flexibility in the oil world. The IEA defines it as production that can be launched within 90 days and sustained over an extended period of time. The U.S. Department of Energy defines spare capacity as production that can be tapped within 30 days and sustained for 90 days. According to the EIA, OPEC’s spare capacity could fall to 5.11 million bpd by the end of this year.

The IEA does not seem to be sure what it wants – more investments in oil or more investments in renewable energy. It called for both on different occasions last year. But based on oil price developments, it seems the shrinking spare capacity of the world’s oil cartel is indeed a cause for concern despite the planned shift to low-carbon energy.

What fuels this concern even further is that some members of the extended cartel OPEC+ are nearing the limit of their spare capacity, and Russia is among them. One of the world’s top producers, according to reports, is finding it difficult to return production to pre-pandemic levels at a time when other OPEC+ members are dealing with the same problem. This means that even if demand continues to grow at the current solid rate, supply may not be as quick to catch up.

Wanted: new oil discoveries

New oil and gas discoveries may have hit their lowest level in 75 years, Norwegian energy consultancy said in a December report. Total newly discovered resources last year stood at some 4.7 billion barrels of oil equivalent, which was down from 12.5 billion barrels of oil equivalent discovered during the first pandemic year.

At the same time, European supermajors are deliberately reducing their oil production in line with the strategy to move toward renewable energy under pressure from shareholders, activists, and governments. So, on the one hand, we have less money being spent on new supply and on the other, we have a deliberate reduction in existing supply.

The low level of discoveries means that reserve replacement rates have fallen, too, and low reserve replacement rates in the oil and gas industry are bad news for future supply. Saudi Arabia warned last year that underinvestment in new oil production could lead to an energy crisis, but since everyone expects Saudi Arabia to say something like that, not a lot of attention was paid to the warning. And even if it was, boosting the rate of new oil discoveries is not as easy as it once was.

Banks on an ESG rampage

The rise of the ESG investor has made quite a splash in the financial industry. Returns are still a priority, but it is no longer the single ultimate priority. These days, investors want to know that their money is being used in a responsible way, for the good of the planet. And this means that they are increasingly reluctant to see this money going to the oil industry.

Because of this trend, banks and asset managers are rethinking their own business strategies. Asset managers are requiring their clients to make emission reduction commitments, threatening to drop them otherwise. Banks are refusing to lend to the oil industry and also threatening to drop clients that generate a lot of carbon dioxide emissions.

It isn’t just pressure from shareholders that is guiding lenders’ hands. Regulators are also turning up the heat on banks, requiring new risk assessments based on climate change scenarios and tightening capital requirements accordingly. To avoid being hamstrung by regulations, lenders are cutting their exposure to the apocalypse-bringing oil and gas industry.

Meanwhile, demand for oil appears to be as healthy as ever, and oil price forecasts are pointing to a solid upward potential. The thing that oil bears who cite the energy transition as the reason for their bearishness seem to be forgetting is that it will take a lot more than a couple of years.

It will also be tough, as Oil Price Information Service’s Tom Cloza wrote in an opinion piece for CNN. 

“Once we really start moving away from fossil fuels, it will be expensive and painful. To deny that expense is as disingenuous as denying climate change,” Cloza wrote. To argue with this and with the fact that we will continue needing millions upon millions of barrels of oil for the observable future would be a waste of time.

Oilprice by Irina Slav, January 18, 2022

Why The Bears Completely Missed The Mark On Oil Demand

In 2020, as the coronavirus locked down country after country, many energy industry observers and even participants floated the argument that this was the end of the oil era. Demand, these commentators said, had peaked. From now on, it will be a downward spiral for it, they said. These predictions did not age well.

Just a year into the pandemic, economies were reopening, growing, and unsurprisingly for many, consuming more crude oil. Last September, Bloomberg reported that some of the world’s biggest economies had seen a rebound in oil demand to pre-pandemic levels and even further growth on top of these levels.

Now, two years into the pandemic and with hopes it could be the last one for infection waves, oil demand is still going strong despite the fresh scare of the Omicron variant. Analysts are predicting higher oil prices still, citing limited capacity, insufficient investment in new production, and the strength of demand.

The International Energy Agency this week expressed its surprise with this demand strength. The IEA, it seems, had assumed that for some reason or another, oil demand growth would slow down. Perhaps the assumption had something to do with the agency’s own energy forecasts that see massive growth in wind and solar power generation capacity and a strong increase in EV adoption, with the latter directly affecting oil demand. Yet its assumption proved to be quite wrong.

“Demand dynamics are stronger than many of the market observers had thought, mainly due to the milder Omicron expectations,” the IEA’s chief, Fatih Birol, said this week. Translated, this statement means that the IEA expected more national lockdowns to prevent the spread of the new coronavirus variant. Yet more severe lockdowns were quite unlikely this time around—even the wealthiest economies would find it hard to cope with another shutdown of their economies, so they are approaching this Omicron wave more carefully than previous ones.

“We see some of the key producers including Nigeria, Libya and also Ecuador that have serious supply disruptions,” Birol also said, echoing concern by analysts that the supply side of the global oil equation is as problematic as the demand side. Ecuador is already restoring production after it repaired two important pipelines. Libya continues to be a wild card, and Nigeria is struggling but determined to boost its oil production.

This is the present state of oil fundamentals. The future may look different. For one thing, the underinvestment problem is becoming increasingly grave. Both OPEC and the IEA—the latter which has rebranded itself as a champion of the energy transition—have warned that the world needs more new oil discoveries.

The only reason for this could be that demand is not dying as fast as hoped by all the champions of the energy transition. Yet Big Oil is curbing its oil output because of transition pressure, and this would mean not just fewer new discoveries because of lower investment in exploration but also lower output from some of the biggest producers out there. This would swing the burden of supply more to OPEC+ whose spare capacity is shrinking, just like European Big Oil’s output.

The oil demand outlook appears to be so bullish that even U.S. shale drillers have begun boosting their production despite a pandemic-induced rearrangement of priorities that saw them focus on returning cash to shareholders and forego production growth. With oil exports last year hitting record highs, failing to take advantage of the opportunity to supply a higher portion of the oil an energy-hungry world needs would have been a little odd.

“The consumption of oil and gas has to diminish, demand has to decline,” the IEA’s Birol said earlier this month in comments on a Canada-focused report. “There is no way out. But I wanted to make clear that a declining demand doesn’t mean tomorrow they will be zero.”

The statement echoes one made by President Biden when he was criticized for asking OPEC to pump more oil while at the same time pushing a green transition-heavy agenda at home. Biden argued the two were not mutually exclusive because the transition took time.

“On the surface, it seems like an irony,” Biden said earlier this month, referring to his call on OPEC+ to add more oil production while heading for COP26 to discuss the reduction of global emissions. “But the truth of the matter is … everyone knows that idea that we’re going to be able to move to renewable energy overnight … it’s just not rational.”

Indeed, despite calls from some more radical environmentalist groups to do exactly that, oil and gas production cannot be stopped overnight to ensure a clear path towards the 2050 net-zero goals. But even the decline that the IEA’s Birol correctly sees as essential for the achievement of the Paris Agreement goals might prove a tough nut to crack. Unless, of course, governments resort to a series of bans and mandates to point their citizens in the right direction. Come to think of it, some are already doing just that.

Oilprice by Irina Slav, January 18, 2022

Independent ARA gasoline, gasoil stocks rise (week 2 – 2022)

Independently-held gasoline and gasoil inventories in the Amsterdam-Rotterdam-Antwerp (ARA) area rose in the week, but overall stocks fell, according to the latest data from consultancy Insights Global.

A fall in gasoline demand from the US — a key outlet for gasoline produced in ARA — brought regional inventories to their highest since June. The fall in exports has also reduced demand within the ARA area for barges moving finished-grade material and components around the region. Lower demand for barges and a rise in Rhine water levels has caused barge freight rates in ARA and the Rhine to fall heavily in the first weeks of this year, after they reached multi-year highs in fourth quarter of 2021.

Gasoil barges bookings from the ARA area to destinations along the river Rhine rose during the week, albeit from a very low base as many operators were still off in the first weeks of January. There was no rush to take advantage of the heavy fall in barge freight rates, as backwardation in the gasoil market structure gave traders little incentive to refill their inland storage tanks. Seagoing tankers arrived in ARA from Finland and Russia, and departed for France, Spain and the UK.

Stocks of all other surveyed products fell. Naphtha inventories fell, with a rise in flows to regional petrochemical sites more than offsetting the arrival of cargoes into the region from Norway, Russia, Spain and the UK.

Jet fuel stocks fell, staying broadly steady on the week with one cargo arriving from Spain and one departing for the UK. Fewer jet fuel cargoes are reaching Europe from the Middle East, as demand improves east of Suez, particularly in Dubai. Some vessels originally bound for ARA have diverted across the Atlantic to the US, cutting further into European supply.

Fuel oil stocks fell heavily, dropping by 11pc to reach their lowest since early November 2021, with cargoes departing for the Caribbean, the Mediterranean and the US. Cargoes arrived from Germany, Russia, Sweden and the UK.

Reporter: Thomas Warner

Look Beyond Oil for Clues Into $447 Billion Saudi Currency Stash

For investors closely watching a key indicator of Saudi Arabia’s financial health, deciphering the ups and downs of its $447 billion foreign-currency reserves has become more about dividends than crude prices.

Sharp increases in the central bank’s net foreign assets now coincide with payouts from state-controlled oil producer Saudi Aramco. Disbursements of the company’s $18.75 billion quarterly dividend, almost all of which goes to the Saudi government, mean the reserves reflect less frequent but larger transfers of cash from the Dhahran-based firm.

Bloomberg by Vivian Nereim, January 13, 2022

China Secures Foothold In This Strategic Middle East Oil State

The recent talks between Oman’s Assistant to the Chief of Staff for Operations and Planning, Brigadier Abdulaziz Abdullah al-Manthri, and the Chief of Staff of Iranian Armed Forces, Major-General Mohammad Bagheri, may mark a new phase in the already deep and broad relationship between Oman and Iran, and in the Sultanate’s drift into the Iran-China axis.

“The two countries [Iran and Oman] have conducted several joint naval drills in recent years, within the scope of securing the waterway from the Persian Gulf through to the Gulf of Oman from smuggling and other threats, including terrorism, but these [recent] talks were concerned with expanding that cooperation both in terms of the armed services involved beyond just the navy and the scope of their joint activities beyond anti-smuggling and dealing with terrorist threats,” an Iranian source who works closely the Petroleum Ministry told OilPrice.com last week. 

The basic catch-22 for Oman that has expedited its move towards the Iran-China power axis is that it lacks the scale of natural resources to generate the financing required to keep its economy ticking over without any further industry but the industry that it is looking to diversify its economy with – petrochemicals – requires a lot of upfront financing before it pays off.

Consequently, with only around five billion barrels of estimated proved oil reserves (barely the 22nd largest in the world) and minimal natural gas reserves – Oman explored many options to bridge this financing gap but its budget problems were dramatically worsened by the Saudi Arabia-instigated Oil Price Wars of 2014-2016 and 2020. Even before the 2020 attempt by Saudi to severely disable the U.S.’s shale oil sector by using exactly the same strategy that had failed in 2014-2016 and had destroyed the budgets of its OPEC brothers as well, as analyzed in-depth in my new book on the global oil markets, Oman had been facing a budget deficit for that year alone of at least 18 percent of GDP and budget deficits averaging at least 15 percent per year over the next five years. 

In order to give it time to develop its answer to many of its financial problems – the rollout of the perennially-delayed but potentially game-changing Duqm Refinery Project and its corollary projects of a product export terminal in Duqm Port and Duqm refinery-dedicated crude storage tanks in Ras Markaz – Oman tried several options to raise money.

So determined was Oman to keep its fiscal deficit within manageable proportions that not only did it implement measures (including lower expenditure on wages and benefits, subsidies, defense, and capital investment by civil ministries) that reduced expenditure (in 2016 by around 8 percent of GDP) but also moved to rein-in hydrocarbons-related spending as well. In this context, the Sultanate’s Financial Affairs and Energy Resources Council formed a specialized working group to study public spending and the means by which to reduce it.

At the same time, it was made clear that the Omani government would apply zero-based budgeting in the ninth five-year plan of approving allocations for development projects only after all feasibility studies and real cost analysis of each of them had been completed. The Council also underlined that it aimed to avoid having any additional requests for funding from developers after any project had been started. 

However, Oman’s problems relating to the Duqm Refinery Project became worse in 2016 when the UAE’s International Petroleum Investment Company (IPIC) said that the Duqm project no longer fitted its overall investment strategy, in light of the impending merger at the time of IPIC with the Mubadala Development Company, and withdrew from the project.

Although this was followed in November by the signing of a memorandum of understanding between the Oman Oil Company (OOC) and the Kuwait Petroleum Corporation (KPC) for co-operation on the construction of the refinery, OilPrice.com understands that this was not even half of the then-estimated cost of US$6 billion.

Given the negative international credit ratings outlook, and ratings downgrades in previous years, Oman’s options to raise money through conventional bond offerings remained constrained, and so did the appetite of international investors to buy into any part-privatization of any of Oman’s state-owned companies, even the once much-fancied Oman Oil Refineries and Petroleum Industries Company’s (ORPIC).  

It was at this point that China saw its chance to expand its foothold in Oman, which is a key land and maritime hub in Beijing’s multi-generational power-grab project, ‘One Belt, One Road’ (OBOR). Specifically, at around the same time as IPIC withdrew from the project, the refinery operator – the Duqm Refinery & Petrochemical Industries Company (DRPIC) – in tandem with the OOC, appointed a number of global banks, led by regional heavyweight Credit Agricole, to advise on the optimal methods to obtain the funding for the project.

These overtures found particular favor with China, which as part of a broad-based investment into Oman pledged the required funding to cover the completion of the Duqm Refinery. However, it came with the usual Chinese caveats of it being allowed to build massive far-reaching infrastructure projects. 

Already accounting for around 90 percent of Oman’s oil exports and the vast majority of its petrochemicals exports, China was quick to leverage this by further pledging US$10 billion immediately for investment into the Duqm Refinery Project’s adjunct oil refinery – just after the implementation of the nuclear deal with Iran at the beginning of 2016.

At that point, Oman announced that the budget for the Duqm Refinery Project was being increased from the longstanding figure of US$6 billion to a combined US$18 billion for all elements of the Project. This, Oman’s government announced, would enable downstream production to increase from its current 15 million tonnes to 24 million tonnes by 2030, while the commodity sales volumes would nearly double from 21 million tonnes to 40 million tonnes by the same date.

Although further investment from China was geared towards completing the Duqm Refinery – including the export terminal in Duqm Port and the crude storage tanks of the Ras Markaz Oil Storage Park – Chinese money was also funneled towards the construction and building out of an 11.72 square kilometer industrial park in Duqm in three areas – heavy industrial, light industrial, and mixed-use. This has enabled China to secure deeply strategic areas of land in the geopolitically vital Sultanate vitally important Oman, which has long coastlines along the Gulf of Oman and along the Arabian Sea, away from the extremely politically sensitive Strait of Hormuz.

It also offers largely unfettered access to the markets of South Asia, West Asia, and Africa, as well as to those of its neighbors in the Middle East. Following the usual Chinese template of investment, it has also given China the opportunity to populate these areas its own people, from project managers to security personnel.

In line with these developments, the addition of Oman to its Middle East territorial acquisitions means that Beijing can fast-track the transport routes between Iran and Oman.  A long-mooted adjunct to China’s direct plans in this context has been the utilization by Iran of Oman’s unused liquefied natural gas (LNG) capacity.

This plan, long talked about between Tehran and Muscat, is part of Iran’s plans to become an LNG superpower based on its massive South Pars and North Pars non-associated gas fields. Oman for its part would allow Iran to use 25 percent of the Sultanate’s total 1.5 million tons per year LNG production capacity at the Qalhat plant. This could be done as part of a broader plan to build a 192-kilometer section of 36-inch pipeline running along the bed of the Oman Sea at depths of up to 1,340 meters from Mobarak Mount in Iran’s southern Hormuzgan province to Sohar Port in Oman for gas exports.

This, in turn, would re-open the possibilities for further pipeline routes running from Iran to Oman and then into Pakistan and then into China, and the other way around, all under the security protection of China, irrespective of any plans that the U.S. might have in the southern part of the Shia crescent of power in the region, as also analyzed in-depth in my new book.

Oilprice by Simon Watkins, January 11, 2022

Pemex Looks to Double Refinery Throughput, Take Business from Gulf Coast Refiners

The National oil company of Mexico, Pemex, is exporting ~1mb/d of crude oil, with ~60% flowing to the US and gulf-coast refineries, but the current CEO wants to change that.

At a press conference in Mexico City yesterday, CEO Octavio Romero shared plans to cut exports to ~430kb/d in 2022 and eliminate them entirely by 2023, as Pemex refineries ramp up to consume the domestic crude.

The Dos Bocas refinery, a 340kb/d plant currently under construction, will be fully operational in 2023 and account for ~1/3 of increased domestic crude consumption.

The Pemex downstream system processed ~1.2mb/d from 2010-2014 before utilization dropped to as low as 690kb/d in 2020.

Currently processing ~800kb/d, the Pemex system could increase runs ~400kb/d by simply returning existing refineries to historic utilization rates.

Cutting exports by the full 1mb/d appears to be a challenge, as running the legacy system at rates not seen in half a decade, and running the new Dos Bocas refinery at capacity would only reduce exports by ~780kb/d.

Nevertheless, 780kb/d of increase in oil production in Mexico and the Gulf region would cut into share for US Gulf Coast refiners like Valero (NYSE:VLO), Phillips (NYSE:PSX) and Marathon (NYSE:MPC), as well as reducing margins for integrated companies like Exxon (NYSE:XOM) and Chevron (NYSE:CVX).

In addition to cutting into market share, reduced Mexican exports would reduce the supply of heavy crude oil to the Gulf Coast system, leaving US refiners in search of additional heavy barrels from Canada, Venezuela and the Middle East.

Seeking Alpha by Nathan Allen, January 11, 2022

China’s Reliance on Middle East Oil, Gas to Rise Sharply

China has long relied on the Middle East to secure much of the oil needed to fuel its rapid economic development. Now Chinese President Xi Jinping wishes to create an “ecological civilization” that relies less on fossil fuels and more on renewable energy.

As the world’s largest oil importer seeks to become greener and more self-reliant, one might expect a shift in its attention and capital. The reality, however, is not that simple. 

A growing interdependence 

Since China became a net importer of oil in 1993, the Middle East has emerged as an increasingly important source of this critical commodity. By the time China surpassed the US as the largest importer of crude oil in 2017, almost half its supply originated from this troubled region.

Despite China’s years-long efforts to ramp up local production and diversify its acquisition, its dependency on the Middle East for crude oil remains intact. In 2020, China imported crude oil that totaled roughly US$176 billion. Almost half (47%) of these official imports came from Middle Eastern countries. 

Notably, Saudi Arabia emerged as China’s largest crude oil supplier and was still maintaining its leading position as of October 2021. The $28.1 billion worth of oil exported from the Kingdom to China in 2020 accounted for 15.9% of China’s total crude oil imports.

Iraq found itself in third place, shipping $19.2 billion (10.9%) worth to the mainland over 2020. Oman, the United Arab Emirates and Kuwait were also among China’s top 10 suppliers, exporting $12,8 billion (7.3%), $9.7billion (5.5%), and $9 billion (5.1%), respectively.

China’s thirst for Middle Eastern oil is perhaps best exemplified by the case of Iran. During 2020 and into early 2021, Iran had reportedly exported almost 17.8 million tonnes (306,000 barrels per day) of crude oil to China in the face of US sanctions on the Islamic Republic. 

Besides oil, the Middle East also provides another vital resource to China – natural gas. As one of the world’s largest exporters of Liquefied Natural Gas (LNG), Qatar records the second-highest export volume of 106.1 billion cubic meters in 2020.

That year, China received 8 million metric tonnes of LNG from Qatar, accounting for 20% of its total LNG imports. With China’s demand for gas set to remain relatively strong over the next several years, Qatar continues to be part of this important equation.

China’s dependence on the Middle East for oil and gas has elevated the region’s strategic significance to Beijing. China has accordingly sought to expand cooperation beyond the energy sector from maritime and railway infrastructure projects within the framework of its Belt and Road Initiative to investments in advanced technologies such as 5G networks, artificial intelligence and nuclear energy.

According to the American Enterprise Institute’s China Global Investment Tracker, more than $123 billion flowed from China into BRI-related investments across the region between 2013 and 2019. The resulting economic entanglement has created an interdependence that has established China as a major player in the region.

Uncomfortable realities 

Geopolitical instability in the Middle East remains a significant energy security concern for Beijing. The attack on Saudi Aramco’s oil facilities by Houthi insurgents in September 2019, which caused oil prices to surge 15%, serves but one telling example.

That crude oil and LNG traveling from the Middle East to China moves through some of the most unstable regions of the world, only compounds the challenge for Beijing. 

Tankers leaving the Middle East and North Africa first transit the Strait of Hormuz or Bab el-Mandeb strait, two maritime chokepoints that straddle regions fraught with conflict. From there, they move south past the port of Gwadar in Pakistan’s troubled Balochistan province and towards Myanmar, where one of the longest-running civil wars is threatening China’s $1.5 billion natural gas and oil pipeline links to the Indian ocean.

Traversing through the narrow Strait of Malacca, ships then move north through the contested waterways of the South China Sea and Taiwan Strait before discharging at Chinese ports.  Chinese oil supply chain network under Belt & Road Initiative Source: Sarker, Md Nazirul Islam, et al (2018)  Adapted by SIGNAL

To secure these waterways and ensure the steady flow of energy to the mainland, China deployed its first modern battle-ready warships to the region as part of a naval task force to conduct escorts and patrols in the pirate-infested Gulf of Aden in 2008.

While pirate activity has primarily shifted to other regions – like the Gulf of Guinea – since 2012, the People’s Liberation Army Navy (PLAN) remains active in the Gulf of Aden. This has led some pundits to raise questions about China’s intentions.

A 2016 report by the French Institute For International Relations posits that China’s anti-piracy missions “have evolved from protecting Chinese shipping interest” into a “strategic forward deployment, contributing to the rise of Chinese sea power in the Indian Ocean.”

The authors’ assessment seems congruent with China’s 2015 military strategy, which states “the security of overseas interests concerning energy and resources, strategic sea lines of communication, as well as institutions, personnel and assets abroad, has become an imminent issue.” 

Beijing has sought to bolster the capacity of its deployment of military assets by establishing forward operating bases – such as the opening of the first Chinese overseas naval base in Djibouti in 2017.

Notably, on December 14 at the Sixth Annual Conference on Israel’s China Policy, Israel’s former Mossad Chief Efraim Halevy pointed out that China had recently constructed a pier large enough to accommodate an aircraft carrier at the naval base in the eastern African nation.

More recently, an attempt by China to construct a secret military facility in Abu Dhabi’s Khalifa port that was halted due to US pressure serves as another example of China’s determination to enhance its power projection capabilities in the region.

While the true intent of the project remains unclear at present, China’s development of commercial ports in outposts around the world has been described by US officials as a “clear effort to develop footholds for military access.” 

From the Chinese perspective, Beijing needs this power. Besides threats stemming from piracy and political instability along its energy supply chain, the narrow straits through which most of China’s oil and gas transits pose another geopolitical conundrum for Beijing: the US Navy and its allies could interdict shipments of energy supplies and hence threaten China’s energy security.

Considering China’s dependence on foreign suppliers for oil remains in excess of 70%, Chinese fears of such disruptions to the energy supply chain will only grow. 

While many analysts have called into question the viability and sustainability of executing such a blockade, there is no doubt that the possibility occupies an important place in Chinese strategic thinking.

As Richard Ghiasy, Fei Su, and Lora Saalman explain in a 2018 report on the 21st Century Maritime Silk Road, “the CPC mindset [is] to prepare for the worst and to alleviate sources of vulnerability, rather than hope for the best.” 

Evidence of this can be found in China’s efforts to develop the China-Myanmar oil and gas pipelines that run from Kyaukpyu port to Kunming, the China-Central Asia pipeline, and its plans to construct a China-Pakistan-Iran-Turkey (CPIT) energy corridor – to transport oil and natural gas primarily from Iran overland through Pakistan to China.

These projects are all designed to reduce the country’s heavy reliance on critical maritime chokepoints, through which roughly 83% of China’s oil imports transit. 

In addition to the construction of new overland routes, China has developed a significant strategic reserve of oil, which according to the Oxford Energy Institute, is “estimated to contain 40 days’ supply.”

Meanwhile, Chinese national oil companies – CNPC, CNOOC and Sinopec – are planning to boost spending and are expected to drill 118,000 wells over the next five years at a projected cost of $123 billion. However, considering that only 2.4% of global proven oil reserves are located in China, the scope for increasing domestic production remains limited.

Energy in transition 

China’s 14th five-year plan, the blueprint that will guide China’s development through 2025, places a significant emphasis on energy security and climate change. The Five-Year Plan commits the government in very broad terms to “formulate an action plan for peaking carbon emissions before 2030” and to “anchor efforts to achieve carbon neutrality by 2060.” 

The world’s second-largest economy had already embraced green energy production prior to this plan, including wind, solar, hydro and nuclear, as well as the electrification of the energy and transportation systems.

China has come to dominate many of the vital global renewable energy supply chains of the 21st century and is the biggest producer of batteries, electric vehicles, solar panels, power control systems and wind turbines.

China today controls roughly 60% of the solar market and has maintained its position as the top investor in renewable energy for 10 years in a row. In 2019 alone, China invested a staggering $83.4 billion in the clean energy sector.    Investment in clean energy globally in 2019, by select country (in billion US dollars) 

Over the last decade, China added 36% of the world’s total new renewable generation capacity. By 2060 China aims to transform its power generation mix from roughly 70% from fossil fuels today to 90% from renewable sources.

As international energy expert Edward C Chow explains: “China does this partly but not solely because it recognizes its overdependence on oil and gas imports and the security vulnerability this causes.” 

Not so fast; and not so simple 

However, the transition towards a greener, more sustainable world will take time and is likely to be both a messy and costly process. According to Zang Xiaohui, dean of economics at Tsinghua University’s PBC School of Finance, China will need to invest as much as $46.6 trillion by 2060 to meet this goal. 

Deputy Secretary-General of the National Development and Reform Commission, Su Wei, has emphasized that despite the country’s ambitious plans to go green, economic growth remains a top priority.

Considering the stability that traditional power sources have provided China’s industrialization efforts compared to the “intermittent and unstable” renewable sources, Su Wei points out that China has little choice but to rely on energy sources such as oil, gas and coal power while “transiting.”  

The power cuts and blackouts that recently rippled across China, causing factories to slow production or close entirely, illustrated the extent to which the country relies on non-renewable sources to maintain economic growth. 

Despite its ideals to transit towards green and clean energy, China’s dependence on oil and gas imports is projected to grow to 80% by 2030. According to a parametric review of data from the US Energy Information Administration (EIA) by Emeritus Chair in Strategy at Center for Strategic and International Studies Anthony H Cordesman: “China and Asia will have a sharply growing dependence on MENA and Gulf petroleum exports that may well extend through 2050.”

Cordesman points out that “China will depend – as will the rest of Asia – on energy exporters like Algeria, Libya, Egypt and Syria, as well as the states of the Arab/Persian Gulf – Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, the UAE, and Yemen.” 

Against the backdrop of escalating tensions between China and the US, such reliance only lends further impetus for China to expand its influence and secure its interests in the region.

Through 2060, China will need to protect the sea lines of communication to ensure the integrity of its oil and gas supply chains. This reality increases the possibility that Beijing will seek to establish more military outposts to enhance its naval power projection capabilities. 

Meanwhile, Middle Eastern countries are not standing by idly as the world transitions to a greener future and are increasingly looking to Beijing to assist them in constructing their very own clean energy ecosystems.

As these ecosystems mature and the world begins to rely less on the region’s oil, Beijing’s dominance of the renewable energy supply chain promises to turn the geopolitical status quo on its head and may leave the Middle East uncomfortably dependent on China in the green economy. 

ASIA TIMES by Dale Aluf, January 11, 2022

Asset Sales to Dominate Nigeria’s Oil Sector, Says Analyst

Nigeria is likely to contend with a gale of divestments by international oil companies to reduce operating, security challenges and the huge costs of battling with the COVID-19 pandemic, industry officials and analysts told S&P Global Platts.

According to the global provider of energy information, 2022 poses to be a very challenging year for Nigeria, Africa’s largest oil producer, with the country facing a race against time to implement reforms needed to bolster exploration and check declining oil production as it fights a wave of divestments from IOCs.

It reported that the signing into law of the long-delayed Petroleum Industry Act, previously known as the Petroleum Industry Bill, in August this year is not expected to bring the much-needed succour to the oil sector.

The landmark PIA was signed into law on August 16 and was expected to turn the Nigerian National Petroleum Corporation to a private company within six months in order to make it easier for the struggling company to raise funds for oil exploration and production. But the impact of this bill has so far been barely felt.

The PIA could be hugely beneficial, but government officials have lacked professionalism in putting it into place, S&P Global Platts quoted the Chief Executive Officer, Degeconek, Abiodun Adesanya, as saying.

He said, “The fact is that this Petroleum Industry Act is coming a little too late as it has been delayed for too long.

“Those who were rightly placed to pioneer the implementation are not the people in government now. So, I expect to see more divestment by oil majors from selected assets because things are not working as they should be.”

Many oil majors are starting to divest legacy oil and gas assets in Africa as they target net-zero carbon emissions while hanging onto their most efficient and often largest oil projects.

According to the report, Nigeria could be the worst hit as Shell, Chevron, and ExxonMobil are close to selling their onshore assets in the West African country.

Nigeria is under pressure to implement the PIA as soon as possible, according to Mike Sangster, managing director of TotalEnergies in Nigeria.

“The window for investments into fossil fuels is narrowing. Very few years would remain for access to urgent funds to develop the Nigerian petroleum industry,” he said at a recent industry event.

This all comes at a time when Nigerian is struggling to produce at even two-thirds of its total capabilities.

Nigeria has the capacity to pump around 2.2 million barrels per day of crude and condensate, but in 2021 output has been languishing near 1.55 million bpd due to a slew of operational and technical issues.

The Nigerian government is aiming to attract much-needed investment to bolster oil exploration and production and increase reserves and output to 40 billion barrels and 3 million bpd, respectively, by the mid-2020s, but these targets are starting to look unattainable.

The pandemic and the acceleration of the energy transition away from fossils fuels does not bode well for Nigeria, which is desperate to kick-start its exploration and production programs.

Projects like Shell’s Bonga Southwest/Aparo, TotalEnergies’ Preowei and Exxon’s Bosi are all at risk of never being developed. These fields have the potential to add a total of around 400,000 bpd to Nigerian oil production.

“Investment decisions are billed to be taken on these landmark projects around next year to arrest Nigeria’s sagging oil production volumes,” an official from the Nigerian Upstream Petroleum Regulatory Commission told S&P Global Platts. “But there are dark clouds hovering around sanctioning these projects now due to the emergence of the new COVID-19 variant.”

Ongoing field and pipeline issues, fiscal stress and insecurity in the Niger Delta are likely to continue to threaten the growth outlook for Nigerian oil output, according to S&P Global Platts Analytics.

Bonny Light, Escravos and Forcados have all faced production issues in 2021, while the output of other key grades, such as Qua Iboe, Brass River, Agbami, Akpo, and Egina, has also remained consistently low this year.

Nigerian oil supply will grow to 1.7 million bpd by April 2022, down from levels of 1.9 million bpd in April 2020, Platts Analytics said in its recent forecast.

By PUNCH, January 6, 2022

ARA oil product stocks rise (week 1 – 2022)

Independently-held oil product stocks in the Amsterdam-Rotterdam-Antwerp (ARA) hub rose over the past week, supported by a fall in gasoline exports.

Rising gasoline inventories in the US are reducing the demand for imported European cargoes, and in turn supporting inventories in the ARA area.

Data from consultancy Insights Global show ARA gasoline stocks increased in the week to 5 January, with no cargoes departing for the US and several tankers of finished-grade material and components arriving in the region from Ireland, Italy, Russia, Sweden and the UK.

Rising gasoline supply in northwest Europe has reduced naphtha demand from regional gasoline blenders in ARA, boosting naphtha stocks in the area on the week.

As well as the lack of blending demand, inventories were supported by the arrival of naphtha cargoes from the US Gulf coast, Russia and Spain. Northwest European naphtha refining margins rose to six-year highs during December, drawing in cargoes from outside the region.

Stocks of all other surveyed oil product groups were broadly steady. The amount of gasoil moving up the river Rhine on barges fell on the week, helping stocks tick up.

Barge freight costs on the Rhine and in the ARA area slumped, as rising Rhine water levels meant fewer barges. Some of the excess barge supply was able to move north into the ARA area, easing the congestion and loading delays that was seen in previous weeks.

Tankers carrying gasoil arrived in ARA from Finland, Russia and Qatar, and departed for Argentina, Spain and the UK.

ARA jet fuel stocks edged down on the week, with regional supply and demand appearing to be well-balanced. No tankers arrived or departed ARA carrying jet fuel.

Fuel oil stocks were also steady, rising, with cargoes arriving from France, Germany, Italy, Spain, Russia and the UK, and departing for the Mediterranean and west Africa.

Reporter: Thomas Warner

The Lone Star State May Host The World’s Next Big Hydrogen Hub

It is widely thought that a future low-carbon hydrogen industry will arise in industrial clusters.

The emphasis is on ports, where concentrations of basic industries, pipelines, and shipping will support large scale production and efficient supply. Plans for major industrial ports in Europe, such as Antwerp and Rotterdam, are enhanced with the possibility of offshore storage of carbon dioxide.  In the US, the region that appears best equipped for widespread adoption of clean H2 is the Texas Gulf Coast centered on Houston. The Houston region’s industrial sector comprises approximately 30% of US refining capacity and more than 40% of US petrochemical capacity. Its industrial sector accounts for 40% of the state of Texas’ industrial emissions. 

This vast industrial landscape of refining, petrochemicals, and related industries already consumes one-third of current US hydrogen production, almost all of which is produced from natural gas by the steam methane reforming (SMR) process. Nearly 50 SMR facilities, operated by major merchant producers such as Air Liquide, Air Products, and Praxair, exist along the Gulf coast. They connect to over 900 miles of dedicated hydrogen pipelines, which account for more than half of the US’s hydrogen pipelines and close to an astonishing one-third of H2 pipelines worldwide. 

This large existing market for industrial hydrogen lays over a regional geology that should support storage: salt caverns for temporary storage of hydrogen gas; and undersea caverns for the perpetual storage of carbon dioxide beneath the Gulf of Mexico.

These favorable attributes have spurred serious consideration of how a ‘hydrogen hub’ might emerge. The possibility of assembling all of the pieces required for a clean H2 system, linked to local industries as well as national and global export markets, has appeared. 

But all of the pieces required for a functioning system remain for now separate pieces, most of them in very early stages of development. The possibility of turning Houston’s gray hydrogen into blue or green hydrogen will depend on effective public policy being put into place. 

CCS ‘Innovation Zone’

ExxonMobil Corp. is thinking seriously about a hub concept for Houston, where the company has a major corporate campus, large refinery complex, and more than 12,000 employees. 

The oil major announced its intention to explore the viability of carbon capture and storage (CCS) in the Houston area last spring. Then, in September, it was joined by a working group of ten more companies that expressed interest in working together to support large-scale CCS infrastructure.

It’s an impressive list, including Calpine, Chevron, Dow, INEOS, Linde, LyondellBasell, Marathon Petroleum, NRG Energy, Phillips 66 and Valero Energy Corp. According to ExxonMobil, the 11 companies represent nearly 75% of Houston’s industrial and power generation CO2 emissions. 

While no formal structure has been created, their discussions continue and the 11 companies intend to have more announcements in the first quarter of ’22. 

A likely leader will be ExxonMobil Low Carbon Solutions, a subsidiary business launched in early 2021 to initially focus on CCS projects worldwide, with projects and partnerships in nearly a dozen countries. For the Gulf project, it is focusing on an effort to capture emissions from industries along the Houston Ship Channel that comes miles inland from Galveston Bay. 

The company’s proposal would be the world’s largest CCS project, storing 50-100 billion tons of carbon dioxide annually by the year 2040 in old oil and gas formations beneath the sea floor of the Gulf of Mexico. 

It might seem improbable that huge quantities of carbon dioxide could be carried by pipeline to reservoirs thousands of feet below the sea floor, beneath impermeable rock, but technically it’s feasible. Indeed, the U.S. Department of Energy (DOE) has estimated that storage capacity along the U.S. Gulf Coast is enough to hold 500 billion metric tons of CO2. It is more than 100 years of total industrial and power generation emissions in the US. 

The challenge is to finance it. ExxonMobil thinks the project will require $100 billion. The company envisions something of a collective effort, with government and industry collaborating on an ‘Innovation Zone’ approach. 

“We envision a ‘zone’ approach, similar to other public-private initiatives established to facilitate economic growth or tackle other broad societal challenges,” says Joe Blommaert who is president of ExxonMobil Low Carbon Solutions. 

Such a collaborative effort will be no easy matter to build. ExxonMobil asserts that funding must be a mix of public and private, with public sector subsidies and incentives combined with support from across industries. Appropriate regulatory and legal frameworks must be established to enable investment. 

But the lever to put it all together, ExxonMobil acknowledges, may well require some form of carbon tax. The company has stated publically that it is in favor of establishing a market price on carbon in order to drive investment in large-scale CCS.

Getting H2 going in the Texas Triangle

Another perspective on Houston’s huge hydrogen potential appears in an influential new report entitled ‘Houston Region: Becoming a Global Hydrogen Hub.’ Produced by the civic group Center for Houston’s Future, the report lays out a tentative pathway to deploying the many elements of Houston’s industrial complex to build a viable low-carbon hydrogen economy. 

Nearly all of the Gulf coast’s widespread hydrogen apparatus was built for the region’s refining and petrochemical industry. To extend production into clean hydrogen and to get it into the energy system, the Hydrogen Hub report looks at the problem in a phased way, separate from the ExxonMobil project.  

“To begin, we can start small, just to get hydrogen into the system and leverage that,” says Andy Steinhubl, who is Chair of the Center for Houston’s Future and a board member of GHI (Green Hydrogen International). 

He explains that an initiative to activate clean H2 must occur in a sector where the cost of hydrogen can compete with existing fuels now or in the near future. The Hydrogen Hub report asserts that comparative economics strongly favor heavy trucking for an activation phase. 

“Trucking is the ‘killer app,’” says Steinhubl. “It (hydrogen) competes favorably with diesel fuel on price, the infrastructure is largely in place, and the truck technology is almost there,” he adds.  

He points out that the underlying technology is quickly emerging, as vehicle manufacturers such as Hyundai, Toyota and Nikola continue work on fuel cell electrified trucks that can match diesel engine torque and horsepower. They intend to supply heavy trucks to shippers who will increasingly seek to curb emissions.  

To get this early H2 market going in Texas, Steinhubl is looking at the I-45 Houston-Dallas corridor.  

“We could literally start a system tomorrow,” he says, “with a refueling station in the Houston port, another in the Dallas warehouse district, and trucks making the non-stop 3.5 hour trip between them on Interstate 45.” 

In fact he sees a hydrogen truck triangle becoming feasible. I-45 would be the first leg or side of the triangle. The service could add I-35 from Dallas to San Antonio, and I-10 from San Antonio to Houston. The distances are all similar and would not require the trucks to stop for fuel between them. Local service would also be feasible in the dense cluster of industries, refineries and privately-owned ports along the Houston Ship Channel.  

All of this could start with pilot projects requiring modest initial investment.  

“A few refueling stations, a few trucks, extend a pipeline or repurpose an H2 delivery truck and off we go,” says Steinhubl. 

Still it will require significant coordination and value chain development. 

“We will need to build a coalition of relevant players across the value chain – shippers, logistics companies, a hydrogen producer, a fuel station operator (possibly Shell), a truck manufacturer, a local port and government. 

“We will need to identify pilot locations and scope – how many trucks, point of refueling, where fuel is coming from and arriving at, etc.,” he says. “Then, secure funding and execute.”

This nascent market would likely begin with gray hydrogen, already in abundant supply in the region, produced with inexpensive natural gas from the Permian Basin of West Texas. Indeed, the size of the Houston area’s existing H2 system is so vast that a hydrogen trucking pilot would add little additional carbon emissions. 

Steinhubl is quite certain that such fuel powering fuel cell trucks could compete with diesel. 

“The reason why trucking is a ‘killer app’ is there isn’t a cost of supply vs alternative fuel issue. Nor availability of supply. Just need to get downstream pieces lined up,” he says. 

“On trucking ‘supply’ the infrastructure is nearly already there. And H2 trucking tech is in place. We just need to make the trucks, which requires a customer.

“So it requires creating a new chain, a whole new end to end set of interrelationships. No piece moves without the others – we need to incent them all to move together.”

Of course, in addition to deploying hydrogen in trucks, extending production into clean hydrogen will require carbon capture, utilization and storage (CCUS). That too will require dedicated financial support and incentives to become part of the value chain. 

The Texas-based energy company Denbury Inc., which specializes in carbon capture for enhanced oil recovery, manages an extensive CO2 pipeline network east of the city of Houston. This Denbury system could play a critical role. 

Global hydrogen hub 

While a heavy truck pilot could be launched relatively quickly with the region’s existing hydrogen infrastructure, a broader application of clean hydrogen will require much more work. Among the oft-listed potential hydrogen markets, such industrial heat, power production, or building heating, no clear winner emerges now. The costs are still too high. 

Steinhubl points out the difficulties for an industry such as steel making. The hydrogen molecule is so small that the metallurgy of current processes is not compatible; a conversion to hydrogen fuel will require redesigning the plants.  

What’s needed now is more public support. DOE has earmarked $8 billion for four hydrogen hubs and Houston intends to be selected as one of these in 2022. There is also the 45Q tax credit that companies and utilities can apply for carbon capture projects, but proponents say it needs to be expanded. 

There is a lack of clean fuels incentives in Texas, where proponents of large-scale hydrogen projects can only hope for the kind of support seen in the EU and the UK, with their carbon taxes and direct subsidies, or in California with its Low-Carbon Fuel Standard. 

Nevertheless, Texas enjoys important advantages that will help. An important example for a trucking pilot is the Port of Los Angeles, which now has 10 hydrogen fuel cell trucks deployed into service, with three refueling stations to be open in ’22. Such a pilot project would likely require fewer incentives to get up and running in Houston, given its hydrogen advantages and dense patterns of heavy trucking. 

A fairly rapid start-up of green hydrogen pilot projects may also be feasible. Here Texas has at least one unique advantage, given the significant power consumption requirements for electrolysis. Texas is the largest wind power producing state in the US and has a rapidly growing solar fleet. The state’s power market enjoys many hours of low-priced excess power due to its generation mix heavy in wind power. 

This advantage for green H2 should grow as renewable power penetration increases in the state, while electrolysis costs and production efficiencies improve. For example, an early market opportunity for green H2 could be found in programs to decarbonize bus transportation. 

Meanwhile, a rising supply of low-cost renewable electricity can only be to the advantage of pilot projects for seasonal power storage, given the region’s great potential for long-term hydrogen storage. Its advantageous geography enables the presence of several geologically unique salt caverns that may be deployed for H2 storage. There are local companies already in the business of creating such salt caverns. 

These pilot projects could lay the basis for an expansion phase, with more pipelines extending from the Gulf Coast to the Permian, sending CO2 and receiving low-cost natural gas. This would help foster the production of larger amounts of blue H2 for export markets. A likely candidate would be to meet growing demand in California, where public policy will require ever greater amounts of it. 

And, with a major US port right there, growing demand in Europe will come into play. And locally, Houston could seek to develop new industries that need nearby hydrogen, such as a low-carbon steel industry on the Gulf Coast. 

Steinhubl foresees an integrated blue-green hydrogen system, with more application of green hydrogen over time. But none of this will come cheaply. The Hydrogen Hub report recommends four key initiatives to launch blue and green H2 (see report, page 9):

· A heavy trucking pilot;

· A seasonal storage pilot using H2 caverns and low-price power;

· Connection of the existing SMR system to CCUS to create blue H2;

· Additional long-duration hydrogen storage opportunities across the Texas grid.

The report estimates that $565 million in incentives and expenditures will be required over 10 years for these pilots and initiatives. 

What happens in Houston…

The DOE’s new Earthshot initiative, launched in ’21 with its first component ‘Hydrogen Shot,’ seeks to reduce the cost of clean hydrogen by 80% to $1/kg by the early 2030s. 

What occurs in Houston, with its significant hydrogen-related resources, will no doubt factor importantly into this effort. Such a positive price trend will produce positive feedback, enabling the expansion of its hydrogen economy with great potential for export earnings, which in turn will open new opportunities for local economic development.  

This, no doubt, is what is motivating Houston’s business and civic leaders to look seriously at low-carbon hydrogen. The pilot projects of the Hydrogen Hub report, coming into play simultaneously with the enormous CCS project of the 11-company consortium, could help transform the old oil city’s economy in a post-carbon age.  

“Now we’re looking to 2050,” says Steinhubl.  

Oilprice by Alan Mammoser, January 4, 2022