Category: Nieuws

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

Market levels are expected to remain at current levels, with medium sour grades seeing support from the heightened pace of buying. Crude oil eased early in the week as traders weighed the potential near-term oil demand impacts of rising coronavirus cases around the world amid concerns about the effectiveness of vaccines against its omicron variant that weighed on market sentiment.

The World Health Organization said omicron poses a very high global risk. A strengthening in the US dollar also weighed on oil prices. Pfizer and BioNTech pharmaceutical companies said preliminary laboratory studies demonstrate that three doses of the Pfizer-BioNTech COVID-19 vaccine neutralize the omicron variant while two doses show indications of a significant increase in protection.

Crude oil prices averaged about 2 percent higher, despite persistent market volatility and an uncertain demand outlook amid concerns about omicron. Going forward, the market structure will depend heavily on the demand part of the equation, while a weaker oil market structure will probably weigh on market sentiment in the near term.

China’s announcement that it would cap overall emissions rather than restrict energy consumption to meet its climate goals could be a positive boost to the oil market.

However, oil prices came under further pressure after the International Energy Agency showed lower global oil demand growth forecasts for 2021 and 2022. Crude oil prices settled slightly higher, reversing earlier losses after the EIA’s weekly data showed the largest US crude draw last week since September, exceeding market expectation. Oil prices were supported with higher equity markets, as investors weighed the US Fed’s decision to tighten monetary policy to slow rising inflation.

While crude production growth outside of the OPEC+ remained just 90,000 barrels per day, industry reports suggest the figure to rise to 1.5 million bpd in 2022 and 0.9 million bpd in 2023. The reports said most growth will come from the US and its Strategic Petroleum Reserve release could add an additional 400,000 bpd to the global oil supply pool.

The IEA’s latest market outlook had a more bearish outlook for global oil balances in the first half of 2022. It now sees a surplus of 1.7 million bpd materializing in the first quarter of 2022 and a surplus of 2 million bpd in the second quarter of 2022.

December and January balances could tighten further as a major pipeline outage in Ecuador has forced crude production shut-ins which we estimate will take about 120,000 bpd of supply off the market on average in December and could potentially negatively impact January output too. Moreover, Russia’s crude and condensate production growth has slowed down recently because the country is running out of spare production capacity.

However, from January 2022, global crude balances are expected to be in surplus.

On the other hand, global prices of liquefied natural gas are trading at record highs. Prices will only fall from spring if Nord Stream 2 is commissioned but the world must get ready for another bumpy year ahead.

ArabNews by Mohammed Al-Shatti, December 20, 2021

France’s TotalEnergies (TTEF.PA), Royal Dutch Shell (RDSa.L), Malaysia’s Petronas and Qatar Energy on Friday scooped up big offshore fields in Brazil together with state-owned Petrobras, paying nearly $2 billion to its cash-strapped government.

While TotalEnergies (28%), Qatar Energy (21%) and Petronas (21%) made the top offer for Sepia field, Petrobras, formally Petroleo Brasileiro SA (PETR4.SA), later entered the consortium by exercising preference rights to take a 30% stake.

Petrobras (52.5%), Shell (25%) and Total (22.5%) secured the nearby Atapu field.

Officials, who had been keen to attract major foreign players, deemed the auction a success, and analysts said the offers agreed to were relatively rich.

The selloff was widely seen as a test of Brazil’s investment climate and of large oil producers’ willingness to keep spending big on traditional oil assets, despite increasing pressure over climate change and toward energy transition.

TotalEnergies, which snapped up a stake in both blocks, said the investment will bring output with “costs well below $20 per barrel of oil equivalent” and with carbon emissions rates below industry levels.

“These are unique opportunities to access giant low-cost and low emissions oil reserves,” CEO Patrick Pouyanné said in a statement.

Signing bonuses were fixed in reais at the equivalent of $1.3 billion for Sepia and $740,000 for Atapu. Companies bid for a percentage of the production they were willing to share with the government, winning the highest: 37.43% for Sepia and 31.68% for Atapu.

Petrobras, TotalEergies and Shell shares fell on Friday, following a 2.60% decrease in Brent prices.

Brazil attempted to auction both fields in 2019, but neither received offers, even from Petrobras. At the time, complex legal issues and rich signing bonuses kept oil majors away.

This time, the bidding terms were considered more attractive, several industry sources told Reuters, largely due to big cuts in both signing bonuses and minimum profit oil.

Government moves to streamline rules and lower fees “drew bids well above the minimums for both assets,” said Andre Fangundes, vice president of consultancy Welligence.

“Companies were more aggressive than we expected,” said Marcelo de Assis, head of Latin America upstream research at Wood Mackenzie.

Eleven companies signed up for the chance to bid on Friday. Exxon Mobil Corp (XOM.N)made final arrangements to bid together with Petrobras and a subsidiary of Portugal’s Galp Energia SGPS SA (GALP.LS), people close to the negotiations said, but never presented a final offer.

Oil majors will be able to add production to their portfolios in the short term. Petrobras is ramping up production at Sepia to 180,000 bpd and has reached the 160,000 bpd maximum capacity at Atapu. A second platform is planned for each field.

Cementing Brazil’s status as Latin Americas biggest oil producer, the two fields could boost the country’s production by 12% over the next six years, adding 700,000 bpd, and bringing in almost $40 billion in investment, its energy ministry said after the auction. Petrobras is set to receive $6.2 billion for past investments in the two fields.

Reuters by Gram Slattery, December 20, 2021

Oil supermajor Shell is facing some big changes in its future as stakeholders approve the long-talked-about move from the Netherlands to the U.K. This follows months of controversy over its scheduled North Sea Cambo oilfield project, resulting in Shell’s withdrawal from the development, and its huge drive to invest in renewables over the next decade. These are just a few of the major shifts in Shell’s energy strategy that suggest the company will undergo a substantial transition in the coming years. 

Last week, 99.8 percent of Royal Dutch Shell stakeholders approved the company’s move to London, which it hopes will help simplify its dual tax structure and make it more competitive. This could lead to a transformation like that seen by Total’s name change to TotalEnergies earlier this year, as Shell drops the ‘Royal Dutch’ to become Shell PLC.

The move is likely linked to a legal case loss earlier in 2021 when a Dutch court ruled that Shell must decrease its carbon emissions by 45 percent by 2030, in line with national aims to decarbonize the economy. Shell has already announced a net-zero carbon emissions target for 2050 and aims to reduce its emissions by 45 percent by 2035, five years behind the ruling. 

But Shell insists that the move will merely simplify its complicated dual-class share system, currently incorporated in the U.K. but with Dutch tax residence. Nick Stansbury, head of climate solutions at Legal and General Investment Management, a major Shell shareholder, explains, “We think this is actually a relatively routine bit of corporate simplification, a kind of corporate tidying up exercise to deal with a complex bit of historical legacy that is simply no longer needed in the world that Shell now lives and operates in.”

Shell stocks have dropped slightly since the announcement, from $44.14 on Friday 10th December to $42.83 the following Wednesday. However, uncertainty around the latest wave of Covid-19 infections and the worldwide implementation of greater restrictions have hit several oil and gas stocks hard in recent weeks. Shell believes the move will ultimately be positive for its stakeholders, as well as for its planned projects in both fossil fuels and renewables. 

Shell’s Chair, Sir Andrew Mackenzie stated of the proposal last month, “The simplification will normalize our share structure under the tax and legal jurisdictions of a single country and make us more competitive. As a result, Shell will be better positioned to seize opportunities and play a leading role in the energy transition.”

The company has already promised major changes to its portfolio following the dip in oil and gas demand during the pandemic, as well as in response to international pressure to decarbonize operations. Much like other oil majors, Shell is doubling down on its investments in renewables, earmarking between $5 and $6 billion a year for green energy. Representatives have previously stated that oil production most likely peaked in 2019 and now is the time to get ahead of the game when it comes to alternative energy development. 

Its objective is to sell around 560 terawatt-hours annually by 2030, twice its current electricity sales. Building upon its current hydrogen operations, Shell hopes to develop integrated hydrogen hubs to serve both industry and heavy-duty transportation, expecting to achieve a double-digit share of the world’s clean energy sales. 

In the mid-term, Shell announced a $565 million investment for renewable energy projects in Brazil through 2025, earlier this year. Developments include largescale solar fields and a natural gas-fired thermal plant, which could start generating energy as early as 2022. 

However, the oil major was repeatedly criticized this year for its ongoing interest in the development of the Cambo oilfield in the North Sea, particularly following the COP26 climate summit that took place in Glasgow this November. Until this December, Shell was pursuing the further exploration and development of Cambo, seemingly contradicting its pledge to move away from fossil fuels and decarbonize operations. But following mounting public pressure, Shell ultimately withdrew from the Cambo oilfield development last week, forcing Siccar Point Energy to put the project on hold. 

Siccar Point’s CEO, Jonathan Roger, expressed disappointment in Shell’s decision to exit the project. He still believes that “Cambo is a robust project that can play an important part of the UK’s energy security, providing homegrown energy supply and reducing carbon-intensive imports, whilst supporting a just transition.”

So, the jury is out on how dedicated Shell is to reducing its carbon emissions by 45 percent by 2030, as ruled in the Netherlands earlier this year, especially following its recent decision to move to the U.K. However, its recent withdrawal from Cambo, as well as a significant increase in its renewable energy investments over the last year, suggest that Shell is open to diversifying its portfolio, as it aims to get ahead of the competition in several green energy areas.

OilPrice by Felicity Bradstock, December 17, 2021