Category: Nieuws

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

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 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

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

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

Some in the oil industry fear that oil prices may again return to the $100 mark, with President Joe Biden’s anti-fossil fuel stance and aggressive green agenda threatening the supply of oil and gas in the foreseeable future. 

President Biden’s energy agenda has been a puzzling one, but it didn’t start off that way. At the very start of his term, President Biden was quick to cancel the Keystone XL pipeline. He suspended oil and gas leasing on federal lands, and sent a clear signal to the oil and gas industry: your days are numbered. 

Now those policies may push oil prices back up to $100, as oil production in the United States is still lagging pre-pandemic levels by nearly 2 million bpd, while demand continues to tick upwards. 

It’s not that oil production in the United States is stagnating. Hardly. But the slow recovery—impeded in part by Hurricane Ida—could tip the market into a shortage rather than a surplus. 

Demand is already outpacing U.S. production. In 2021, U.S. crude oil inventories have shed nearly 70 million barrels. 

It would be one thing if U.S. policy were pro-oil and gas. As oil prices rise, oil and gas investments would flood in, and the market would do what the market does—regulate itself. But oil investors and banks—even Big Oil companies—are desperately trying to tiptoe through the new environment. Shareholders are now spattered with activist shareholders demanding more accountability with regard to the environment. Banks are eager to display their green prowess by shunning new oil and gas projects. Oil and gas companies are leery of sinking too much money into new drills too fast in an environment that may or may not be hospitable to them in the future.

Now, the lack of investment and sluggish return of U.S. oil production could send oil prices spiking.

That’s not to say that all are on board with this call for $100 oil. Some contend that OPEC+ has its finger on the pulse of the oil industry so that oil won’t have a chance to go that high. Others, however, question how much spare capacity OPEC+ has at the ready to respond to additional demand surges. 

The U.S. Energy Information Administration sees OPEC+ spare capacity reaching 5.11 million bpd in the fourth quarter of next year. 

Goldman thinks $100 oil by 2023 shouldn’t be ruled out, as supply additions are expected to be simply too slow to keep up with demand—precisely the scenario we saw in 2021. Goldman’s base forecast is still $85 Brent in 2022 and 2023. But it isn’t ruling out the possibility for $100 oil, made possible by higher cost inflation for drillers or a significant supply shortfall.

Saudi Arabia warned that this underinvestment could be dangerous.

No matter where the exact call for oil prices lands, one common theme exists in most oil forecasts today: there is simply not enough supply while demand is robust. And oil prices will need to go even higher if significant investments are to be made to the extent where supply can keep up with demand. How high? Well, that will depend on the policies in place to support the industry—and those policies today aren’t looking to congenial.

Oilprice.com by Julianne Geiger, January 4, 2022

Exxon Mobil Corporation(NYSE: XOM) expects to post an annual profit in 2021 on the back of operating gains of up to $1.9 billion, per the company’s regulatory filing.

Notably, the expected gain exceeds the one-time charges driven by strong oil and gas prices.

Expectations 

Per the filing, the largest U.S. oil producer expects sequentially higher profit from oil and gas production in the fourth quarter of 2021. Additionally, refining and chemicals operating profits are likely to be flat to lower on a sequential basis. 

The regulatory filing indicated that one-time charges associated with asset impairments and contractual costs are anticipated to reduce oil and gas earnings by up to $1.2 billion. No details regarding the production assets were provided. 

According to ExxonMobil, expected lower margins in chemicals might decrease profits by $600 million to $800 million, compared to $2.14 billion recorded in the prior quarter. Additionally, Refining margins are anticipated to be flat or drop by $200 million on a sequential basis. 

On a positive note, ExxonMobil indicated mark-to-market gains of up to $1.1 billion for oil and gas and refined products. Proceeds from asset sales, including the company’s U.K. North Sea assets are likely to be $500 million. 

Based on current expectations, the company plans to spend $20 billion to $25 billion per year on new projects through 2027, including $2.5 billion per year on carbon reductions. Markedly, the company expects to double its pre-pandemic annual profit by 2025. 

Wall Street’s Take 

On December 15, RBC Capital analyst Biraj Borkhataria maintained a Sell rating and a price target of $70 (14.5% upside potential) on the stock. 

Overall, the stock has a Hold consensus rating based on six Buys, six Holds, and three Sells. The average ExxonMobil price target of $72.33 implies 18.3% upside potential from current levels.

ExxonMobil’s upcoming earnings report for the fourth quarter of 2021 is likely to be released on February 1, 2022.  

Smart Score 

According to TipRanks’ Smart Score system, ExxonMobil gets a 6 out of 10, which indicates that the stock is likely to perform in line with market averages.

By Nasdaq, January 4, 2022

The African Refiners and Distributors Association (ARDA) has said that the continent needs to deliver the “refineries of the future”, to be able to meet the growing energy needs of its population.

Executive Secretary of ARDA, Anibor Kragha, in a presentation at the Africa Energy Futures Forum held during the 23rd World Petroleum Congress in Houston, USA, noted that the existing refineries will need to be upgraded to produce AFRI-6 or less sulphur fuels in line with the organisation’s roadmap.

With only 20 countries in Africa having refining operations and capacity utilisation down to 55 per cent on the average, Kragha advocated that new refineries, like the Dangote Refinery in Nigeria and the ERC Refinery in Egypt, should be designed to produce cleaner fuels.

He lamented that the current situation whereby only six African nations have Liquefied Petroleum Gas (LPG) storage capacity above 50,000 metric tons (MTs) was leading to uneconomic cargoes and increased landed costs.

“This overall situation has resulted in Africa petroleum products shortfall growing significantly over the years which poses significant concerns for Africa’s energy security as the continent remains heavily reliant on imports,” he argued.

Kragha stated that significant investments are required in integrated refining and petrochemicals plants to meet growing demand and reduce imports as well as in large-scale LPG infrastructure to effectively promote replacement of biomass with LPG as clean cooking alternative across Africa.

He noted that Africa’s future refineries must be flexible and efficient, stressing that policies that would provide an enabling environment for investments, including clarity in regulatory frameworks and compliance requirements would help the continent to attract much-needed capital for future world-class refinery projects.

He further called for an accompanying financing plan, which will promote investments in world-class, integrated refinery and petrochemicals complexes as well as critical LPG storage and distribution infrastructure.

In addition, the ES explained that digitalisation, machine learning, decarbonisation, safety and reliability, efficiency and funding were key to the proposed future refineries.

In an earlier forum, ARDA had noted that about $15.7 billion would be needed to upgrade the existing 36 refineries on the continent, maintaining that the challenge will be to ensure that these refineries are converted into efficient centres of excellence.

“Complex, inefficient supply chains and intra-African trade challenges are currently impeding implementation of cost-effective clean energy solutions, but the African Continental Free Trade Agreement (AfCFTA) presents opportunity for the African Union and the respective Regional Economic Commissions to implement a harmonised energy transition plan,” he explained.

Consequently, Kragha said that future refineries will need to minimise production of fuels and instead focus on converting crude oil directly to petrochemicals via modern alternative technology and delivering higher capital efficiency through a lower overall environmental footprint

By economicconfidential, December 27, 2021