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When Saudi Arabia’s Energy Minister Prince Abdulaziz bin Salman announced that Saudi Arabia was no longer an oil-producing country, he likely didn’t mean literally

“Saudi Arabia is no longer an oil country, it’s an energy-producing country,” the Energy Minister told S&P Global Platts this week.

Saudi Arabia has high green ambitions that include gas production, renewables, and hydrogen.

“I urge the world to accept this as a reality. We are going to be winners of all these activities.

Saudi Arabia will surely benefit from the green transition. While the Exxons, Chevrons, and Shells of the world are busy doing climate activists’ bidding in the boardroom and courtroom, NOCs–particularly in various OPEC nations–are all-too-eager to take advantage of what will surely be increased oil prices.

Already Saudi Arabia has raised its official selling price for the month of July to Asia.

But that doesn’t stop Saudi Arabia from pursuing its green ambitions–the Saudi Green Initiative–while funding those green ambitions through oil sales. Saudi Arabia plans to generate 50% of its energy from renewables by 2030, in part to reduce its dependence on oil. In 2017, renewables made up just 0.02% of the overall energy share in Saudi Arabia.

But that doesn’t mean Saudi Arabia is planning on producing any fewer barrels of oil. And it doesn’t mean that Saudi Arabia is planning on halting funding for all new oil and gas projects, as the recent IEA bombshell report has suggested the world must do to reach net-zero by 2050. Saudi Arabia has long maintained that oil will remain a dominant energy source for decades.

Saudi Arabia’s Energy Minister said that the IEA’s net-zero pathway spelled out in its most recent report was like a sequel to La La Land. In fact, several oil-producing and oil-consuming nations have dismissed the report.

Saudi Arabia’s oil revenues–which will fund any green aspirations the country may undertake–have dwindled over the last year and a half, and state-run oil giant Aramco had to hold bond sales just to pay its hefty dividend to the state.

Nevertheless, the world’s largest exporter of crude claiming it is no longer an oil-producing country is noteworthy indeed.

OilPrice, by Julianne Geiger, June 17, 2021

The events of May 26, 2021 look like a defining moment for the oil and gas industry.

In the space of a few hours, three decisions crystallised trends that had been building for years at the large international oil companies, showing the pressure they are under to address climate change and the energy transition.

In the US, 61% of the votes at Chevron’s annual meeting were cast in favour of a proposal that the company should “substantially reduce” the greenhouse gas emissions created by its products in the medium- to long-term.

Shortly afterwards, shareholders at ExxonMobil elected three directors nominated by the hedge fund Engine #1, despite opposition from the company’s board.

Meanwhile in the Netherlands, environmental campaigners won a court battle against Royal Dutch Shell, which was ordered to cut its worldwide carbon emissions by 45% by 2030.

These events raise five key issues that are worth bearing in mind.

The nature of stakeholder pressure is fundamentally changing

Shareholder resolutions and legal challenges at big oil companies relating to climate change are nothing new. The difference with the latest round of challenges is that they were successful.

The votes at Chevron and ExxonMobil reflected a significant increase in support for shareholder proposals and directors that were opposed by the companies’ boards. This change is largely being driven by institutional investors, which have become much more active on climate-related issues in recent years. These new stances are not about environmental activism, but reflect their assessments of investment risk.

Similarly, the successful case against Shell reflects a new approach to litigation. The campaign group made their case on the basis of human rights law, and succeeded where shareholder resolution in 2018 had failed.

The bar is being raised for decarbonisation

It is worth noting that all three companies already had targets in place for cutting carbon emissions, but shareholders and campaign groups judged these to be insufficient. For Shell, the 45% reduction in absolute emissions ordered by the court is considerably deeper than the 20% the company previously had in place. Chevron shareholders voted for the company to commit to substantial reductions in its Scope 3 emissions, created when its products are used. That is a clear signal that the bar is being raised for all publicly-traded companies in terms of their decarbonisation strategies.

The impact will be felt throughout the industry

At the moment, stakeholder pressure is mainly focused on Big Oil. For the independents, there is more likely to be a steady ratcheting up of pressure, rather than a step change. However, regulatory changes driven by social and political pressure will affect the whole industry. National oil companies do not generally face the same pressures from shareholders and governments, but still need to be commercially competitive. Carbon border adjustment mechanisms that tax imports according to their associated emissions — already under discussion in the EU, Canada and the US — could leave state-owned oil and gas companies locked out of key markets if they fail to address decarbonisation.

Decarbonisation creates higher risks for supply and prices

In Wood Mackenzie’s base-case forecast, as much oil is needed overall in 2050 as is being produced in 2021. Uncertainty over the pace of decarbonisation creates the possibility of unintended consequences for prices. If stakeholder pressure has the effect of constraining investment and restricting exploration and demand remains high, the result could be tight markets and rising prices over the medium-term.

Addressing Scope 3 emissions is a huge challenge for the industry

In the near-term, most oil and gas companies are focused on their Scope 1 and 2 emissions, created by their own operations and their purchases of energy. Significant reductions in Scope 3 emissions are likely to require fundamental structural changes to business models, with companies moving from Big Oil to Big Energy.

The alternative, cutting emissions while remaining focused on hydrocarbons, relies heavily on carbon capture, utilisation and storage (CCUS), for both producers and their customers. However, there are significant barriers: the costs for CCUS are still high relative to prevailing carbon prices in most parts of the world, and reaching the necessary scale could take a long time.

Indian Oil Corp., or IOC, has unveiled refinery diversification plans that will witness the start of a hydrogen dispensing facility at its Gujarat refinery and more downstream products, as it aims to prepare for a future catering to growing demand for both oil and cleaner forms of energy.

The move is part of the state-owned company’s wider initiative to embark on a strategic growth path that will aim to maintain focus on its core refining and fuel marketing businesses, while making bigger inroads into petrochemicals, hydrogen and electric mobility in the next 10 years.

IOC said the hydrogen dispensing facility will aim to fuel hydrogen buses plying between Vadodara and Kevadia, as well as Sabarmati Ashram.

The comments from IOC come after Indian Prime Minister Narendra Modi’s announcement over the weekend that a project is underway to develop Kevadia in the western state of Gujarat as an electric vehicle city.

“There is a fresh momentum for scaling up hydrogen use across sectors globally. Our refineries already have hydrogen generation units, and in fact, refineries present a very attractive case for acting as the hydrogen production and supply centers,” IOC chairman S.M. Vaidya told S&P Global Platts.

Wider products footprint

Vaidya recently said IOC was carving out its expansion path keeping in mind the anticipated slowdown in transportation fuels demand that would come in a decade or two.

“The high demand growth trajectory for Indian petrochemicals demand coupled with the high and growing imports of petrochemicals further strengthen the case for this in the Indian context,” Vaidya said.

Earlier in the week started June 6, IOC signed an agreement with the Gujarat state government to set up a petrochemicals and lubricants integration project as well as an acrylics and oxo alcohols project at IOC’s Gujarat refinery.

The projects will strengthen IOC’s readiness for venturing into petrochemical projects like PVC, styrene, acrylonitrile, polymethyl methacrylate and ethylene oxide in future, the company said.

“There is consensus across the board that petrochemicals integration is the way forward for the refining sector. Current refinery expansions and new capacity additions are expected to improve petrochemical feedstock availability in future,” Vaidya said.

The other infrastructure project planned under the agreement with the Gujarat government is a new flare system at the Gujarat refinery.

“Today, Gujarat is charting a new path of prosperity. To power that journey, IOC’s Gujarat refinery is now poised to grow to 18 million mt/year capacity,” Vaidya said.

Vaidya said the pandemic would not alter India’s robust long-term energy demand fundamentals despite creating short-term hurdles, making it imperative to pursue refining expansion as well as an expand footprint in CNG, LNG, biodiesel and ethanol.

Crude-to-chemicals

IOC is also looking at crude-to-chemicals, which is a technology frontier to capture the potential in petrochemicals demand, although it comes with high capital expenditures, Vaidya said.

In addition, IOC has undertaken a series of initiatives in the hydrogen sector.

“Hydrogen is the fuel of the future. IOC plans to set up several hydrogen production units on pilot basis,” Vaidya said.

Last year, IOC inaugurated its hydrogen-spiked CNG, or H-CNG, plant in the Indian capital while the Petroleum Ministry launched trial runs of buses using H-CNG as fuel.

To produce H-CNG, the entire CNG of a station passes through this new reforming unit and part of the methane gets converted into hydrogen, with the outlet product having 17%-18% hydrogen. IOC officials said emission levels would come down substantially for vehicles using H-CNG as fuel.

H-CNG blends can be produced directly from CNG, bypassing the energy-intensive electrolysis process and high-pressure blending costs. The flexible process allows the production of H-CNG on-site, in less severe conditions and under low pressure, IOC said, adding that the cost of H-CNG production by the above process would be about 22% cheaper than conventional physical blending.

Within liquid fuels, Vaidya expects that IOC will be playing a big role in blending of biofuels like ethanol and biodiesel.

India has brought forward its target of blending gasoline with 20% ethanol by five years in efforts to accelerate the push toward renewables and a cleaner energy basket. Prime Minister Modi said the country will now aim to achieve the target of 20% blending by 2025, instead of 2030.

“To achieve a target of 20% ethanol blending, India will be required to increase the current pace of ethanol capacity addition by 3.5 times, which could be a challenge. However, raw material aggregation and timely investment would be key factors to be monitored,” said Vivek Sharma, senior director at CRISIL, a separately managed unit of S&P Global.

S&P Global Platts, by Sambit Mohanty, June 14, 2021

It’s not just BP Plc and Royal Dutch Shell Plc that are having to prepare for a world that’s less hungry for oil and gas.

The world’s biggest independent oil storage company Royal Vopak NV is partnering with battery startup Elestor BV to develop a battery that they think could to be one of the cheapest ways to store electricity in large quantities.

It’s a role currently dominated by hydrocarbons, something that needs to change if the world is to curb its emissions.

“Developing large-scale and low-cost electricity storage will become increasingly important,” said Marcel van de Kar, Vopak’s global director of new energies. “With this promising technology of Elestor, electricity can be stored in molecules on a large scale.”

It’s a sign of how the rest of oil industry — beyond the headline grabbing supermajors — is planning for the existential threat a greener future represents. BNEF expects oil demand to peak in 2035, meaning everyone from extractors to storage firms needs to prepare for a world that uses less.

Elestor’s battery uses two tanks of hydrogen and dissolved bromine to store energy, both of which are cheap and plentiful compared to the rare metals lithium ion cells rely on. Because it is a flow battery, capacity can be boosted by simply increasing the size of the vessels, making it ideal for mass storage of electricity.

That could be key to allowing the broad switch to renewable energy that’s needed to meet the Paris Climate goals. Energy firm Wartsila Oyj estimates 2,594 gigawatts of battery capacity is needed in G-20 nations to balance them, since wind and solar only work intermittently. That’s more than five times current nuclear capacity worldwide — another option to provide baseload supply.

While Elestor’s batteries are currently still small, the joint venture plans to scale them to 3000 Kilowatt hours — enough to power around 30 homes for a day — before growing them further.

The grid battery space is dominated by lithium ion cells, thanks to the pre-existing industry which builds and maintains them. Other competitors include vanadium flow batteries, recently selected by California to help stabilize its grid, as well as zinc-based stationary batteries developed by Eos Energy Enterprises Inc. That company last year went public via a special purpose acquisition company.

Bloomberg, by Eddie Spence, June 14, 2021

Iraq plans to boost the production capacity of West Qurna 1 by 40% to more than 700,000 b/d over the next five years at a time when operator ExxonMobil seeks to exit one of the world’s largest oil fields with expected recoverable reserves of over 20 billion barrels.

Iraq’s state-run Basrah Oil Co. signed a contract with ExxonMobil and Schlumberger to boost the field’s production capacity by 200,000 b/d by drilling 96 wells, the oil ministry said in a statement June 17.

Currently West Qurna 1 is producing 380,000 b/d out of a production capacity exceeding 500,000 b/d, Karim Hattab, a deputy oil minister said in the statement. The field also produces around 150 MMcf/d of associated gas, he added.

Iraq is in talks with ExxonMobil to take over its 32.7% stake in West Qurna 1, the country’s oil minister Ihsan Ismaael said May 3.

Ismaael had previously said Iraq was in talks with potential unnamed US energy companies to take over ExxonMobil’s stake. Other partners in West Qurna 1, where ExxonMobil is the main operator, are PetroChina (32.7%), Japan’s Itochu (19.6%), Indonesia’s Pertamina (10%) and Iraq’s Oil Exploration Co. (5%).

Iraq awarded the contract to develop West Qurna 1 to ExxonMobil, Shell and Oil Exploration Co. in 2010. In 2018, Shell sold its 19.6% stake to Itochu and exited the giant Majnoon oil field.

ExxonMobil’s exit from the southern West Qurna 1 field may be similar to Shell’s 2018 divestment of its stake in Majnoon, whose operations are now managed by Basrah Oil Co., the minister said May 3.

S&P Global, by Dania Saadi, June 12, 2021

Romanian state-controlled gas producer Romgaz (SNG) has entered exclusive negotiations with US oil group ExxonMobil for its stake in the Neptun Deep offshore gas project in the Black Sea.

The exclusivity agreement is valid for four months, until October 15, 2021, Romgaz said in a note to investors.

If the two sides reach an agreement, this could be the biggest transaction ever carried out by a Romania company. ExxonMobil has invested some USD 750 million (EUR 615 mln) in the Neptun Deep project so far. The American group holds a 50% stake in the project.

ExxonMobil’s partner in the project is Romanian oil and gas group OMV Petrom, which holds the other 50%. OMV Petrom will take over the project’s management if Romgaz buys Exxon’s stake, according to a previous announcement of the two companies.

In 2008, OMV Petrom and ExxonMobil launched a joint venture for the exploration of the Neptun Block in the deepwater sector of the Black Sea. The block covers an area of approximately 7,500 square kilometers in water depths ranging from 100-1,700 meters.

The two companies invested over USD 1.5 billion between 2008 and 2016 in exploration and appraisal activities in the Neptun Deep block.

In 2012, Domino-1, the first deepwater exploration well in Romania, confirmed the existence of a natural gas reservoir. The gas reserves were estimated at between 40 and 80 billion cubic meters, or three to six times Romania’s annual gas consumption at that time.

The two partners were supposed to decide on starting the commercial exploitation of the perimeter by 2018. However, they delayed their decision after Romania’s Parliament changed the offshore law and introduced conditions that made the investment less attractive.

Romania’s Liberal Government that came to power in late 2019 promised to change the offshore law and sweeten some of its clauses. However, the debate has been postponed and the new draft law hasn’t been discussed yet.

Romgaz’s shares were not immediately influenced by the announcement, which came two hours into the trading session. The SNG stock ended the day 0.5% lower than Thursday.

By Romania-Insider, June 12, 2021

An under-the-radar hearing on the way shippers will contract volumes on Canada’s key crude oil export pipeline began last month in what could turn out to be the most important battle for control of Canadian oil resources. 

The more than a month-long hearing at the Canada Energy Regulator (CER)—planned to end on June 25—is expected to end up with the regulator determining how Canadian oil firms and U.S. refiners will pay to ship crude on Enbridge’s Mainline system over the next decade. Mainline, with the capacity to ship nearly 3 million barrels per day (bpd) of oil, is Canada’s biggest transporter of oil, carrying crude from oil-rich Alberta to markets in eastern Canada and the U.S. Midwest.  

The current pipeline contracting system expires on June 30, 2021. Mainline’s operator Enbridge has been operating the pipeline for decades under the so-called “common carrier” system, in which all of the huge capacity has been available for short-term shipments of volumes that shippers can change every month. This has given Canadian oil producers the flexibility to contract short-term volumes without having to commit to long-term obligations to ship crude on the pipeline. 

Mainline Operator Enbridge Looks To Secure Long-Term Shipments

Now Enbridge wants to change that. Mainline’s operator seeks to convert the contracting terms to ones where 90 percent of the available capacity would be reserved for long-term access to its network. Canada Energy Regulator’s Commission is set to decide, after the hearing ends at end-June, whether the proposal is fair for all parties. 

Enbridge’s rationale for the new tolling framework is to ensure certainty for shippers in the long term, it says. But it also has a purely business reason to seek long-term firm contracts for Mainline—to reduce its long-term volume risk, because competing pipelines already offer shippers the ability to contract for firm service on a long-term basis. The new proposed system will “provide Enbridge with the tools to compete on a level playing field,” the company said in its proposal. 

For example, the Trans Mountain expansion project already has contracts in place that commit the majority of its capacity to firm service on a long-term basis. In this case, if Enbridge continues as a “common carrier”, it could lose much more than the firm long-term contract pipelines where shippers pay for volumes anyway, regardless of how much they would actually ship one month or next.  

While Enbridge’s application to convert Mainline to firm long-term contracting may be just protecting its business in the long term, it could mean that Canada may give control to its most important pipeline to U.S. refiners, which favor the proposed new contracting system, Samir Kayande, an independent energy business strategy consultant, writes in Financial Post. 

CER Hearing “is about who effectively controls Canadian resources” 

Since refiners typically want low crude oil prices, if they are given their way in the new contracting system, their bargaining power would grow, at the expense of Canada’s exploration and production companies which usually would like to see higher oil prices, Kayande argues.  

“The toll hearing at the CER is about who effectively controls Canadian resources,” Kayande notes. 

According to Enbridge’s evidence, companies that ship over 75 percent of the volumes on the Mainline have said the proposed terms and tolls are “fair, balanced, and productive.”  

“Producers have generally not shipped on the Mainline, with the exception of those that hold capacity on connecting downstream pipelines. It could well be that, if Mainline Contracting is approved, it is primarily parties with refining interests and parties (including producers) that have downstream pipeline capacity that will contract for service on the Mainline,” Enbridge argues. 

“But this would not be a “redistribution of the pie”. This would be entirely consistent with the current and past usage of the Mainline under the 100% uncommitted service structure,” the pipeline operator says.  

Canadian Oil Producers Vs U.S. Refiners

However, most Canadian oil producers, especially those without downstream capacity in Canada and the United States, beg to differ. 

The Explorers and Producers Association of Canada (EPAC), which includes 170 producers, said, “Ensuring that the crude oil and liquids produced and exported from Western Canada realize the highest possible market value is of critical importance to the citizens of the provinces that own the resource, to the oil producers of the WCSB and their investors, to the communities who depend on that investment and to the municipal, provincial and federal governments who rely on the taxes and royalties paid by the upstream oil and gas industry.” 

“These public interests also far outweigh the objectives of the small group of mostly US based refining and allied interests that support the Application, that seek to acquire control for the next two decades over 90% of the transportation capacity on the Mainline thus giving them ability to lower the price that WCSB producers receive for their crude oil,” EPAC noted.

The association also slammed Enbridge’s “fear of competing pipelines” as “self-serving and opportunistic.”  

The Canadian Shippers Group, consisting of Canadian Natural Resources, MEG Energy Corp, Shell Canada, and Total E&P Canada, said that “The Application is the result of an egregious attempt by Enbridge to exert its market power to its own advantage, which would come to the detriment of Canadian based producers, aggregators and refiners.”  

Roland Priddle, the former chair and board member of the National Energy Board between 1986 and 1997, also slammed Enbridge’s proposal in his evidence on behalf of the Canadian Shippers Group. 

“The support that Enbridge has marshalled for the Application does not represent the Canadian public interest: it is biased in favour of U.S. refiners and against Canadian crude oil producing interests, which had previously been the only or the dominant counterparty in settlement negotiations,” Priddle said. 

The ongoing hearing about the changes to Mainline’s operation has turned into a battle about who will control the future of Canadian oil and its prices. 

Oilprice , by Tsvetana Paraskova, June