Category: Nieuws

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

The head of corporate planning of National Iranian Oil Refining and Distribution Company (NIORDC), Ali Reza Arman-Moqaddam says Iran will have to opt for petro-refineries in order to develop its refining industry.

Although a 300,000-b/d petro-refining facility with crude oil feedstock would require $10 billion in investment, incentives are expected to draw in both local and foreign investors.

Arman-Moqaddam told “Iran Petroleum” that petro-refineries would aim to diversify petrochemical feedstock and generate more revenue from Iran’s oil resources, not to mention profits from the conversion of crude oil and gas condensate to valuable products.

Here is the full text of the interview Arman-Moqaddam gave to “Iran Petroleum”:

What are the development scenarios of Iran’s refining industry, considering the energy intensity in the country, as well as plans to enhance crude oil refining capacity?

In the development of the refining industry, several issues are considered as key requirements, such as prioritization based on available resources, balancing export and domestic production programs to prevent the sales of raw materials and promote production of higher value products and sustainable supply of fuel needed by the country. In addition, how to implement consumption management programs is also of particular importance. In the case of gasoline, the current balance of production and consumption is positive, but if consumption keeps growing, in the near future, this balance will become negative and in other words, we will become gasoline importer. According to the documents and regulations of the High Energy Council, the consumption of energy carriers in the country should be managed in accordance with the requirements of efficient use. To that effect, the transport sector’s energy supply document up to horizon 2041 has been drawn up so as to take into consideration the fundamentals of energy efficiency and upgrading energy output, and hybrid fuel and electricity would constitute a 6% share of the transport mix by then. The gasoline consumption is expected to reach 94 ml/d by that time. Constructing petro-refineries is expected to meet such objective.

For instance, should we fail to find a reasonable solution to contain the gasoline consumption now, the gasoline consumption would reach 160-170 ml/d by 2041, in which case petro-refinery construction would make no sense and all refineries in Iran would have to run at full capacity for supplying gasoline and no feedstock would remain for petrochemical plants. Therefore, now, based on the assumption that energy efficiency policies would be implemented in coming years, construction of petro-refineries in Iran is economically viable. If we fail to exercise efficient energy use, development of the refining industry would be exclusively based on fuel supply. In the near future, petro-refineries would be no longer economically viable in terms of energy supply priority.

Now that all eyes are fixed upon renewable energies, while the future of investment in fossil energies is faced with buts and ifs, is it economically viable to invest in petro-refineries?

The extensive petroleum products and petrochemical markets, the facility of exporting such products compared to crude oil and its immunity to sanctions are among the advantages of development of the refining and petro-refining capacity in the country and leaving behind selling raw materials. Building petro-refineries is not merely an economically viable project with job creation advantages; rather, it is a strategic solution for blunting the impact of sanctions. Many nations have already planned to increase the share of renewables in the energy mix and therefore fossil resources are directed to development of petrochemical products with a burgeoning market. Under these conditions, competitive markets will take shape and the cost price of products will be the key decision-making element in the competitive market. Integrating refineries and petrochemical plants would enable us to reduce expenses. Therefore, petro-refineries would diversify products of higher value-added, reduce the cost price of products, boost output and profitability and reduce energy consumption. That is why they are considered a suitable strategy for economic development. Despite the economic viability of petrochemical megaprojects, the main challenge for implementing these projects would be financial restrictions, as is the case with any other megaproject.

How are we going to build a petro-refinery under the present circumstances?

Establishing a petro-refinery as a megaproject, worth billions of dollars, would require a large number of fundamentals. One of these requirements is protective law to facilitate the process of implementation of the project. In this regard, the Law on Protecting Crude Oil and Gas Condensate Downstream Industry with Public Investment, adopted in 2019 by the Iranian parliament, and the amendment to this law along with its executive bylaws provide good support to such projects. Using the incentive of feedstock supply would guarantee reimbursement of facilities throughout construction, which is unique. As far as the process of using the facilities of this law is concerned, I have to recall its history.

In 2019, Iran’s Petroleum Ministry called for the establishment of refinery. A total of 74 companies bade for this project, 42 of which uploaded their documents on the NIORDC website. Following the implementation of formal, technical and financial assessments, finally 19 projects including 8 new refineries and 11 qualitative upgrade projects in current refineries were approved. Another key requirement for implementing this project under the present circumstances is precise and expert planning for financing through diverse resources including equity provision, absorbing resources from the capital market as well as banking facilities. Of course, we recommend that those applying for these projects set up syndicates and unions under the present circumstances to integrate their capital for projects of higher priority.  

Are any refineries expected to be repurposed to petro-refineries?

Some of existing refineries, after undergoing quality upgrading, would be able to supply products which could serve as feedstock for petrochemical plants. However, as the main processes are fuel-based, they would be still known as refinery. Regarding new projects, although the initial permit has been given to most of them under the title of refinery, the main projects are in the process of changing their license to petro-refinery owing to the feedstock supply incentive enshrined in the law. It seems that of 8 new projects, 6 would be looking for license for petro-refinery.

How much is needed for building a petro-refinery?

To build a 300,000-b/d petro-refinery with a 35% conversion ratio of petrochemical products, $10-11 billion investment would be needed. Such figure is big enough when compared to normal projects under way in the country. But attracting such investment would be possible during a four-year period. That is why we have recommended that applicants integrate their investment with a view to providing more suitable conditions for implementing a full project. Meantime, changing the processing paradigm by reducing the ratio would reduce investment needs.

How much do we need for building the eight refineries whose licenses have been granted?

In case applicants look for building refineries based on the initial licenses, totally $40 billion would be needed, inclusive of financing expenses. If we assume that some of these projects would shift to petro-refineries, more than $60 billion in investment would be needed.

Is this industry attractive enough to draw in foreign investors?

Given the fact that the economic incentive of feedstock supply, which guarantees investment return, has been implemented as a supporting solution for reimbursement of investments, sufficient attraction has been created for both local and foreign investors from an economic standpoint. However, in addition to economic attraction, absorbing foreign investment would largely depend on Iran’s external political and economic relations with the financial and commercial bodies of other nations. In terms of investment viability in the petro-refining sector, we have to take into account its processing pattern, too. For instance, one of the major crude oil fractions is naphtha which is widely used at refineries for producing gasoline. That is while at petro-refining plants, the bulk of naphtha is used for producing aromatic petrochemicals and olefin. In light of the significant price difference between gasoline and petrochemicals, creating significant profitability, the burgeoning petrochemical market, particularly in regional and global markets, would create the necessary incentive for investment under normal international circumstances.

Are you currently focused on building petro-refineries?

As undeniable fact, development of the refining industry in Iran is inevitable. This industry is required to be developed by prioritizing the qualitative upgrade of current refineries. As part of the Ministry of Petroleum’s strategy to increase the refining capacity, construction of petro-refineries is on the agenda. Therefore, the focus of NIORDC, as the administrator of development in the refining industry, lies on preparing the ground for implementing projects to upgrade quality of the current refineries and enhance the refining capacity through developing petro-refineries with sufficient financing in the mid-term and long-term. Meantime, development planning in this industry mainly relies on financial and management capabilities of the private sector.

Where does Iran’s refining industry stand currently?

Currently, 10 refineries are operating in Iran with a total crude oil and gas condensate refining capacity of 2.2 mb/d. In case there is no abnormal consumption of fuel in the country, the refining industry could ensure the country’s fuel need supply and even facilitate petroleum product exports. Iran’s ten refineries are producing 105 ml/d of gasoline and 110 ml/d of gasoil. In addition to that, over the past two years, due to restrictions caused by the coronavirus and long lockdowns, gasoline consumption rate had declined to some extent. But as soon as the vaccination campaign accelerated, gasoline production in Iran has been increasing. Under such circumstances, the key point is the risk of growing consumption in various sectors for various reasons including inefficient use of energy commodities due to low-cost fuels and non-application of effective mechanisms in management, in which case, the production-consumption balance would face a challenge.

How many refining projects are currently under operation?

We’re currently witnessing new projects in all refineries across the country. In the Persian Gulf Star refinery, operational debottlenecking for enhancing capacity is in its final stages, while in the nine other refineries, mainly quality upgrade projects are under way in different phases. For instance, at the Abadan refinery, capacity development and stabilization project is under way in addition to the renovation of older sections and upgrading the quality of products. It has been financed by China. At Shiraz, Isfahan and Tehran refineries, there are also quality upgrade projects under way at various stages. In other refineries, there are also projects under way aimed at upgrading the quality of heavy products. 

How are they financed?

The projects under way in current refineries are divided into two categories in terms of necessary investment. The first category consists of projects pertaining to optimization and quality upgrade of light and middle distillate products, which are financed by domestic resources of refineries, as well as financing instruments based on the capital market. Examples are gasoline manufacturing or gasoil hydrotreating projects. The second category includes refinery projects pertaining to the quality upgrade of heavy products, which would require much higher investment due to the technologies needed in them and the necessity of using a large number of processing units and sophisticated equipment. 

Regarding these projects, a combination of the financial resources portfolio, including the investor’s income, domestic banking facilities, capital market capacity and financing, is used. Of course, financing is faced with challenges now. As for new refining and petro-refining projects, the necessary investment depends on the capacity and the process of the project. For instance, the capital needed for a crude oil petro-refinery of 300,000 b/d is about $12 billion. For these projects, due to the high volume of investment needed for them, a portfolio similar to what was described is used for financing.

Have you held any negotiations for attracting foreign investment?

Before this new phase of sanctions became operational, in 2015 and 2016, financing of most quality projects at current refineries had become nearly finalized. For instance, we had reached good agreements with Japan for financing and technology at two refineries and we had made good progress in technical and contractual issues, but after the US unilaterally pulled out of the JCPOA (the 2015 Iran nuclear deal with six world powers), our talks came to a halt and we lost the chance of development. We had also struck preliminary agreements with South Korea, which were halted, too. Even for financing new projects at Jask and Siraf, Japanese and Korean consortiums were expected to provide necessary finance. At that time, we needed about $15 billion in investment for quality upgrade projects at five operating refineries. Implementation of those projects could practically boost the quality of all products in the country, while helping convert fuel oil to high-value products such as gasoline and gasoil. But that did not happen due to the US pullout of the JCPOA.

Have you halted development projects?

No, we haven’t. We have redesigned the refinery development projects by making some modifications in the processing patterns with the help of local contractors. Currently, some of them are close to operation. For instance, after we failed to go ahead with the Japanese the project envisaged at the Bandar Abbas oil refinery, we considered a new method for development. We reached agreement with the Research Institute of Petroleum Industry (RIPI) for technical savvy provision. The design phase has made very good progress. After this phase, we will go into the investment phase. Based on a new project for the Bandar Abbas oil refinery, we would need $1.3-1.5 billion in investment. If we wanted to go ahead with the Japanese, we would have needed $4 billion in investment.

How many refineries are expected to be built under new development projects?

A relatively high number of licenses have been issued for building refineries, 11 of which are being pursued more seriously. It is noteworthy that for the purpose of making investment attractive for the construction of refineries and petro-refineries, the Iranian parliament adopted a law on feedstock supply. Of the said 11 projects, 8 have been defined within the framework of this law. These projects include five running on crude oil with a total capacity of 1.22 mb/d are under way in southern coasts. Moreover, three refining projects with condensate feedstock are under construction in the Siraf area with a total capacity of 240,000 b/d.   

Is it clear which of them would become integrated refinery and petrochemical plant?

The initial license for most of these projects, except for two, pertains to refining. But recently, most of these projects are expected to become petro-refinery in a bid to benefit from the incentive provided for in the parliamentary law and financing advantages.

Once these projects have been implemented, how much would be Iran’s refining capacity?

Currently, Iran’s crude oil and gas condensate refineries treat about 2.2 mb/d. Regarding enhanced capacity through new projects it is clear that due to the high volume of investment, implementing all these projects simultaneously would not be possible. However, with the assumption of setting a timeframe for the implementation of these projects and the startup of a total of 11 refining projects, Iran’s refining capacity would have increased by more than 1.7 mb/d, but as I mentioned before, it is not possible under the present circumstances. However, if the projects are prioritized and with the assumption of creation of suitable conditions in the international and economic sectors, increasing the refining capacity by about 750,000 b/d would be possible.

Where does the refining renovation stand now?

All sectors of the petroleum industry need improvement and reconstruction on a regular basis. That is done in refineries, like similar industries, through technical inspection monitoring and decrepit parts are handled through overhauls and some installations are practically renovated. It is noteworthy that in the economic feasibility phase, the useful life of a refinery is considered between 25 and 30 years, but the real life of refineries in Iran and other nations is much higher due to overhauls and implementation of numerous improvement and reconstruction projects. For example, the Abadan oil refinery was initially built more than a century ago. The useful life of the Tehran refinery is more than 50 years and that of Isfahan refinery is more than 40 years. Regarding the Abadan refinery, we have defined a development project, which is currently under way by the Chinese. Coincidentally, this is one of the projects that had been planned when the JCPOA was effective. The first phase of this project would come online during the first half of next calendar year.

How much was the average gasoline production and consumption recently? To what extent did covid-19 affect Iran’s gasoline consumption?

Iran’s gasoline production recently averaged 95 ml/d and its consumption reached 85 ml/d on average. Regarding the impact of the coronavirus outbreak on the gasoline consumption, it was affected by covid-imposed lockdowns last calendar year, which reduced it to 75 ml/d, down from 90 ml/d year-on-year. For the current calendar year, if we divide it into pre-vaccination and post-vaccination periods, we can clearly see the impact of eased restrictions on the gasoline consumption. Vaccination accelerated in September. Before that, the gasoline consumption had averaged 83 ml/d. In September, it was up 7% to 89 ml/d.

How can we control the growing trend of gasoline consumption now so that we would not have to import in coming years?

An important issue in the energy sector is sustainable fuel supply all over the country. This issue is being pursued through developing refineries. However, in my view, the more important part would be to implement consumption management plans. In case the objectives of efficient energy use, reduced energy intensity do not materialize, in the near future, we would experience the negative production-consumption balance even if the refining capacity is developed constantly. Planning and implementing consumption management plans would entirely depend on coordination between all legislative and executive organs and collective cooperation. That is only in such case that development of petro-refineries would make sense and instead of fuel production, part of products may be directed to valuable petrochemicals.

By Shana.ir, December 26, 2021

The energy revolution, accelerated by the pandemic, is changing the DNA of the oil and gas industry at its core.

In a recent interview Glynn Williams, CEO of Silixa — a company that provides fiber optic-powered data solutions for the oil and gas sector (as well as several others) — reveals something of the emerging recognition that the oil and gas industry can make a strong contribution to the renewables sector:

“Many people and entire states depend on the prosperity and well-being of independent oil and gas companies (IOCs) and their suppliers, but they are still being cast unfairly as the villains of climate change and the renewables revolution. In reality, they have been fully engaged in the huge undertaking of transitioning their businesses and practices toward the renewables sector. So, far from being its enemies, they are increasingly its facilitators.”

What is your view on the current state of the oil and gas market in the wake of a pandemic and what are the prospects for the future?

We are currently seeing a big bounce-back in activity despite continued disruption being foreseen for the remainder of the year. Moreover, in the medium term the fundamentals look strong with pre-pandemic demand levels returning at the end of 2022. There has been significant underinvestment during the COVID period and that will, I feel, lead to a return of increased spending in 2022.

For us, oil and gas will remain an attractive segment in which to operate as our customers in the OPEC Middle East, the big water offshore and the U.S. shale sectors will all make improved levels of investment, which will then lead to further opportunities for Silixa.

Other opportunities will arise out of operators’ need to meet their ESG requirements. A feature we have seen this year has been reducing scope-one emissions.

We have recently launched an intervention system with the time in the well acquiring data significantly reduced to a matter of hours versus conventional techniques. So, our scope-one emissions are reduced because we don’t require generating plants at surface operations for days but only hours at a time. If we are dealing with issues of fugitive emissions through well integrity problems, they can be quickly resolved by identifying the source of the leak, enabling the customer to do their mediation quickly.

What we are also seeing is an acceleration of digitalization allowing, for example, supervision of well-side operations without the need to fly specialists around the world. The advance of digital technology and solutions established during the pandemic will be a strong platform for growth for some of the faster-moving service providers.

How much does public image reflect the actual direction of travel of IOCs and their suppliers?

Although oil & gas companies and their suppliers are branding themselves as green through mission statements, logos and corporate color choices, rebranding can be pointless where it doesn’t express and underline real commitment.

However, oil & gas company branding increasingly reflects fundamental changes in philosophy and business practices. For example, BP has repositioned with solid renewable energy targets and a defined roadmap to decarbonization. Another example is Total, which has undergone a complete rebranding becoming TotalEnergies, highlighting the company as a broad energy supplier rather than just oil and gas.

In many ways IOCs have embraced the energy transition, and companies like ExxonMobil have identified multiple carbon capture usage (CCU) projects. Some may have been slow in adopting energy transition, but are now accelerating the dialogue, making very strong commitments to carbon capture and storage hubs.

This year we have noticed a greater sense of purpose among the major IOCs, reflecting a response to shareholder pressures and what’s happening in the wider world.

Decarbonization, renewables and transferable skills

Investment that was going into exploration work previously is now going into renewables markets, largely by acquiring licenses and the transition from off-shore gas to off-shore wind, but mainly in operating in new areas. Some large companies have been paying premiums to access renewables markets, I hope it works out for them.

How to access the subsurface is very well known in the oil & gas industries: how to drill wells, how to make sure they are secure, how to monitor them. All of that is very transferable into CO2 capture and storage. The offshore wind energy sector will be able to exploit the practices of the technologies and competencies of the subsea providers.

However, it will be challenging for those in the offshore supply sector who are offering generic products because there will be fewer wells completed and progressively less intervention over time. So some of the generic providers will struggle if they don’t have anything that stands out and is considered best-in-class.

As for Silixa, we are well-positioned. Roughly half of our sales are now being generated outside of oil & gas. We are finding that our oil & gas solutions are now being rapidly adopted for use in mining, carbon capture & storage and geothermal sectors with little investment or actuation on our part. So I am very optimistic about what is playing out in new areas.

How does Silixa fit into the new energy normal?

It has been a broadly-based business for some while. Some identify with us as an oil & gas services business, but we have a lot of relationships outside that with a very broad offering. We are fortunate in having a multi-disciplinary team that already speaks the language of the emerging sectors.

We have five business units, three of them facing oil & gas and two of which are facing respectively mining and the broader area of environmental infrastructure. Within those, we have an alternative energy group, and an earth science group addressing the emerging pressures on the world, such as climate change and increasing populations. 

Our knowledge of the subsurface domain will be key to the safe and economic storage of CO2 and success of complex geothermal systems. This understanding of the subsurface domain and application of the technology over many years has resulted in all parts of our business well populated with experienced geophysicists and geotechnical staff.

A case in point relating to our carbon storage and geothermal knowledge and transferable technologies is in the company’s optically distributed fiber optic sensing. This is unique in that the technology can make measurements of what we call the far-field, which enables it to track the movements of fluids within the system and in the near-field. This enables us to understand when the system is in optimum conditions.

Can you give any specific examples of transference in this area?

Transferable technology, like people’s transferable skills, can be applied quickly and appropriately. One of the successes that gives us confidence looking forward is the success we have already enjoyed in transferring some of our oil and gas flow metering solutions to the mining sector where we can help our customers understand flow and movement within large networks and help achieve their ESG objectives avoiding water and energy use.

As a result of considerable early success, we are making a significant investment in building an international team as we believe our proven technologies will assist in overcoming ESG and technical challenges in the provision of base metals such as copper and nickel, which are vital in the energy transition picture. So, there are many elements to our technology that are very special, particularly our ability to quickly apply proven techniques to the challenges of energy transition that are now so urgently needed to combat global warming.

Forbes by Robert Rapier, December 24, 2021

The U.S. government has authorized Petroleos Mexicanos’ bid to take over Royal Dutch Shell Plc’s Deer Park refinery, according to Mexico President Andres Manuel Lopez Obrador.

It’s something historic,” the president, broadly known as AMLO, told reporters Wednesday.

Pemex has been awaiting approval from the U.S. Treasury Department to acquire Shell’s stake in the Texas plant, a move that would expand its refining capacity and secure critical fuel supplies for the state oil producer. The purchase comes as AMLO seeks to increase state control of the country’s energy markets, refine all of its own oil, and reverse more than a decade of production declines.

A Treasury Department representative declined to comment.

The acquisition will cost $1.2 billion, AMLO said at a press conference, more than twice the price the company announced in May. Pemex will pay off the refinery’s debt to complete the purchase, tapping Mexico’s National Infrastructure Fund, Pemex Chief Executive Officer Octavio Romero said Wednesday.

Bloomberg previously reported that Pemex could spend about $1.6 billion on the takeover, using the infrastructure fund and a bridge loan from commercial banks to pay off the refinery’s debts, a part of the deal that wasn’t clear when it was first announced.

Pemex Refinery Deal May Cost $1 Billion More Than Announced

Pemex is making the acquisition even as its finances are so dismal the government is injecting billions of dollars into the company as debt has soared to $113 billion, the most of any oil company in the world.

Mexico’s Foreign Affairs Minister Marcelo Ebrard said the Committee on Foreign Investment in the United States approved the sale in a letter. There were no pending issues of national security, and the review of the sale was concluded, Ebrard said, citing the letter.

CFIUS is responsible for reviewing sales of critical U.S. infrastructure to foreign buyers for national security.

Shell previously said the deal was expected to close early next year, subject to regulatory approvals.

The sale has sparked controversy, with critics claiming that it could affect national energy security in the U.S., due to rising gasoline costs and concerns that Pemex lacks the funds and expertise to run a U.S. refinery.

Last week, two New York businessmen filed a lawsuit in a U.S. District Court in Houston, alleging that the sale would increase gasoline prices and impact their business’s energy costs. In June, U.S. Representative Brian Babin published a letter to CFIUS opposing the deal because he claimed that Pemex didn’t have a record of operating refineries to international standards.

Pemex owns and operates six refineries in Mexico, but due to a lack of investment they are operating at less than half of their capacity, and Mexico imports almost 80% of the gasoline consumed in the country. Pemex is also constructing a new, 240,000-barrel-a-day refinery in AMLO’s home state of Tabasco that has gone over budget after the government’s initial estimate of $8 billion.

Bloomberg by Amy Stillman, December 23, 2021

President Joe Biden’s energy chief extended an olive branch to the oil industry Tuesday, telling executives a crude export ban is not under consideration, while assuring them that the administration was “not a bogeyman.”

Energy Secretary Jennifer Granholm made the virtual remarks Tuesday to an outside advisory group with members including executives from such companies as Exxon Mobil Corp. and Royal Dutch Shell Plc. Her conciliatory tone comes as the administration’s policies on energy production, which included a temporary halt to oil leasing on federal lands and the termination of a permit for the Keystone XL pipeline, have drawn the ire of industry. 

“I do not want to fight with any of you,” Granholm told the National Petroleum Council. “I do think it’s much more productive to work together on future facing solutions.” 

The administration, Granholm said, is not considering reinstating a ban on the export of crude oil — a tool the Biden White House had previously been considering as it sought ways to address gasoline prices that hovered around a seven-year high, setting off political alarm bells.

Granholm’s comments represent the administration’s most definitive statement regarding the export ban, which had the potential to upend oil markets while discouraging domestic oil production.

“I heard you loud and clear and so has the White House,” Granholm said in her remarks. “We wanted to put that rumor to rest.” 

Granholm’s address to the council follows finger pointing over the issue of high gasoline and oil prices. The industry was also angry with the administration’s decision to dramatically reduce access to oil and gas development, followed by complaints domestic producers weren’t ramping up production amid increasing energy demand as the worst of the pandemic ended. 

The Biden administration has since sold oil and gas drilling rights in the Gulf of Mexico after a federal district judge in June ruled against the moratorium. 

Granholm, in her comments, asked the industry to ramp up oil and gas production, while repeating previous complaints about unused permits and leases. 

“While I understand you may disagree with some of our policies, it doesn’t mean the Biden administration is standing in the way of your efforts to help meet current demand,” Granholm said, while asking the industry to help partner in the administration’s battle against climate change. “I firmly believe those that embrace the change rather than fighting it will be rewarded on the other side.”

Bloomberg by Ari Natter, December 21, 2021