In this episode of the Platts Future Energy podcast, Varaleka Pant and Arsalan Syed discuss with Deb Ryan the importance of evaluating the carbon intensity for crude and some of the major global crude grades, and explain the need for standards in this space to ensure consistency in low carbon crude trading.
More listening options:
Hello, and welcome to the Platts Future Energy podcast from S&P Global Commodity Insights, where today, we'll be talking about: why understanding carbon intensity of crude production is so important; what S&P Global Commodity Insights is doing to ensure transparent analysis; how carbon prices play into the cost of offsetting emissions; and what market trends we're seeing as we start publishing crude grade carbon intensities.
My name is Deb Ryan, and I'm the Head of Low Carbon Commodities here at S&P Global Commodity Insights. And today, I'm joined by Varaleka Pant, one of our low carbon markets analysts; and Arsalan Syed, Lead of low carbon commodities. And today, we're going to talk about low carbon crude.
Varaleka, I want to start with you today. What is the carbon intensity for crude? And why is this so relevant in the changing energy landscape?
The energy markets have been in a tailspin in the last 2 years, seeing a dramatic demand drop due to the pandemic followed by supply chain shocks from the pandemic recovery that very recently has seen the prices skyrocket with this very valid question around energy security due to the Russia invasion of Ukraine.
Finally, we're also seeing developing countries really struggle to keep their economies afloat and many households being pushed back into poverty. With these clouds of possible recession looming over global markets, providing affordable energy is now the #1 priority for most of the governments.
The series of events in the backdrop of grim IPCC warnings and aggressive climate commitments have really strengthened the argument that oil and gas would continue to be the part of our energy mix for the coming years. But for that to be the case and for the energy to be affordable, we would have to produce crude at the cost of lower emissions. Hence, it is very critical for countries and operators to quantify the emissions associated with the crude production and chart out feasible emission reduction strategies. And this is where knowing the carbon intensity for a certain crude being traded in the market becomes so important.
At S&P Global Commodity Insights, we have defined carbon intensity as a collective emissions from upstream crude production, that is: emissions from production and extraction of crude; maintenance activities happening in the field; wellhead flaring; fugitive emissions; emissions from transportation of this crude to a loading port; and any emissions from processing of the crude before it can be sold off to a refiner.
Thanks for that overview, Varaleka. So you started talking about some of the things we're including in the carbon intensity, but can you talk about how S&P Global Commodity Insights is defining these carbon intensities for the different crude fields that we're looking at and the different types of production?
So we have adopted a bottoms-up approach towards estimating the carbon intensity associated with a barrel of crude. We have divided the very complicated value chain of crude into 3 parts, which is the upstream, midstream and the downstream.
The upstream carbon intensity has emissions associated with crude production and extraction, maintenance, wellhead flaring, any fugitive emissions, methane slippage and emissions associated with crude and associated gas processing before it can be sold off to a refiner, which purchases that crude.
The midstream carbon intensity includes emissions from transportation of that crude from a field to a likely refinery so it can be either using a pipeline or a crude tanker. But we assume that shipping for crude happens using AFRAMAX vessel, which is around 600,000 barrels on it and the vessel is fueled using a low-sulfur fuel oil.
The downstream carbon intensity would include the emission footprint associated with various refined products and petrochemicals. And we get to publish those numbers to the market.
So bringing Arsalan into the conversation, there are associated price premiums that we're also publishing along with our carbon intensity values. What do these price premiums represent?
Yes, that's a really good question. Just to take a step back and talk about the voluntary carbon market. So through these price premiums, we've really shown that marriage between the carbon intensity of crude and what we're seeing with the voluntary carbon market itself.
So we've heard a lot about the voluntary carbon market over the past 2 years, but it's not a new market in any way, right? It emerged in the early 2000s as a way to mitigate those greenhouse gas emissions. But what we've seen in the last 2 years is this real approach where people are looking, companies and countries alike are looking at the voluntary carbon market as this viable solution.
So what we've done on the pricing side is -- Varaleka just described the carbon intensity that we published for over 100 fields. For each one of those fields, we publish a price premium as well. That's a dollar per barrel indication of what it costs to offset the emissions for that field.
So just to talk about an example. If you were to take the crude field [ 2P ], which has a carbon intensity of around 17 kilograms, if you were to look at the price premium, that would be $0.35 per barrel using a removal-based credit. So just to kind of put things into perspective, as that carbon intensity gets higher, the cost to offset those emissions or the cost to use the voluntary carbon market increases.
The same thing is true for depending on how expensive those credits are. So what we saw at the beginning of last year is voluntary carbon prices were going through the roof. And the reason that is, is because of this resurgence in demand. Some of the prices that we publish here at Platts, like the Platts CEC, which is the CORSIA-eligible credit. When we started assessing this price, it was $0.80 per metric ton, and it got as high as $9 per metric ton.
We've seen carbon prices cool off a bit at the start of this year, just that the market has really adopted this risk-off sentiment that we've seen in the equity markets and then the voluntary carbon markets alike. So as those prices have shifted, we've seen that price premium or the cost to offset go down as well as we've seen that downward pressure in the voluntary carbon market.
Thanks for that background, Arsalan. In June this year, we actually started publishing carbon intensities and price premiums for crude grades. Can you talk about why this is important for the market, especially as it relates to trading of crude?
Yes. And we've really turned our focus to grades based on feedback from the market itself, right? So as Varaleka mentioned, we started off by looking at the fields, which was a logical first step when you look at the supply chain of the barrel, right? But when things are trading, they're trading based on the grade itself.
So for example, a crude like WTI Midland is making its way into Europe, into Rotterdam. And what the market wants to know is the carbon intensity of that grade, not necessarily of that field. The field is really good from an operator standpoint, from a refinery standpoint as well. But at the end of the day, what's actually getting on to the ships and making its way into the refinery is the grade, which is why we've turned our focus to the grade and looking at the grade as part of the evolution of the entire supply chain.
And Varaleka, we've been publishing our field carbon intensities in kilograms of CO2 equivalent per barrel of oil equivalent. However, we're publishing the grades, as Arsalan just talked about in kilograms of CO2 equivalent per barrel. Can you explain what the difference is between these 2 assessments?
Yes, sure. So when we look at a field, you have multiple production of commodities coming out. So you have oil, the crude oil coming out, you have associated gas, which can then be upgraded and be used as LNG. And you also have some condensate coming out.
So when you look at the carbon intensity for the fields, that is what we define per barrel equivalent, which would be the entire production from that field. But when we start looking at the grades, it's actually the crude, which is being traded on the market per barrels. And that is why it's important to represent the carbon intensity for the crude cargo per barrels.
Arsalan, can you talk about when we've seen different trades of low carbon crude or offset crude around the world, we've seen some differences in how these trades are currently being done. Can you talk around why it's so important for standards and the need for standards as it relates to carbon intensity and the cost of offset and price premiums for these crudes?
Sure thing, Deb. First off, this is a very, very nascent market, right? The crude market has been around for 100 years, but this component is something that people are just starting to look at. So there's going to be a need for the industry to really come together on a standard, on what that means. And I think we're still figuring that out a little bit.
You mentioned the need for standardization when it comes to offsetting some of the cargoes as well. So there's big differences in what we see. For example, one of the differences that we see are the type of credits that are being used. So there's a certain reputational risk as well that is there if you use credits that are older vintages. So there's something that needs to be standardized there.
The second part that needs to be standardized is the type of credits, right? Depending on what your preferences are as a company and the price of the credit themselves, there's different projects that are underlying those credits and there needs to be some standardization there.
The last thing that really needs to be standardization on when it comes to looking at the offset is the life cycle that you're looking at. So we've seen offset trades over the last 24 months, really 2021 and 2022, where they've taken into account the full life cycle of emissions. So looking at from the production of that commodity all the way to their end use. But then there's been cases that where companies are just looking at the upstream.
So for example, from the wellhead to short-term storage. So there's a need for standardization there as well. The other thing that Varaleka talked about is there are different ways that companies are looking at this value of carbon intensity in the crude space. There's kilograms of CO2 equivalent per barrel of oil equivalent.
So the way that we're seeing is it's not necessary that one way is true or one way is correct, but it's depending on how you slice that pie, right, depending on where you draw those boundaries on where you see that emissions, that number can differ as well. So it's not about us finding the correct way to measure this, but it's about the market coming together to set the standard on what this will look like so there can be an apples-to-apples comparison from field and from grades.
Like Varaleka mentioned, depending on the units that you use, you can see a different carbon intensity. So even though we're at the start, really, the past 12 months, we've seen a lot of acceleration into the market. I have no doubt that the industry itself will come to a standard, and these are sort of just the growing pains that we're seeing as the market tries to calculate what their true carbon intensity is.
Thanks for that, Arsalan. Varaleka, one of the things that we've looked at when we addressed the different carbon intensity through the supply chain and particularly focusing on the upstream is that we're looking at all these different fields and types of production around the world. Can you explain how we do assess the different emissions and looking particularly that upstream supply chain calculations that we're looking at?
So when we assess these carbon intensity for these fields, we basically use the OPGEE version 2 model, which is a model created by Stanford University. And using that model and our own data, we quantify what are the emissions associated with production and extraction, maintenance, what kind of fugitive emissions we are seeing on the field, and what kind of emissions are coming from processing of the crude before it can be sold off to the market.
But we also utilize the satellite model. So we have a partnership, and we sort of use the data coming out of the VIIRS satellite. And essentially, what the satellites help us figure out is what kind of flaring are we seeing over these oil and gas facilities.
And using the heat map, we can actually convert it to the actual flat volumes seen over those fields. And this really helps us to sort of put into the context of what are the sources of emissions for different fields. And based on the analysis that we've done for 100-plus crude fields, we have found that every field is unique in terms of its operation and on-site emission management.
So in general, we can categorize upstream emissions into broadly 2 buckets. One would be the easy-to-abate emissions such as wellhead flaring, [ routine ] venting, methane slippage, which are easy to abate and actually account for 50% to 60% of upstream emissions. These omissions can actually be brought down by investments in flare gas recovery systems and phasing out [ routine ] process venting.
And to reduce these emissions, we're actually seeing operators take on multiple steps. We see them undertaking frequent site monitoring to check for leaks, investing in new equipment such as valves and seals, and organize regular training for plant operators to ensure that there's a heightened awareness around preventable methane slippage and any operator malpractices that can cause pressure relief flaring.
The second bucket of emissions is what we call the hard-to-abate emissions, such as those associated with moving the crude in pipelines and tankers, crude processing emissions, emissions associated with production and extraction of crude. The quantity of these emissions totally depend on the type of field you're looking at.
So for example, if you look at a Canadian field that has a bitumen grade oil. The processing emissions would be higher due to the usage of steam and upgradation of bitumen that is required. But for an aging field such as [indiscernible] and Qatar, which has depleted 80% of its recoverable oil, higher emissions would be associated with the advanced crude recovery procedures that are being employed to maintain a healthy field output.
And this is where we have seen different operators bring different solutions to the table. We've heard from operators in the Middle East and Canada look into electrification and fuel substitution in their facilities and really looking at nuclear energy utilization or using hydrogen for the same. Whereas, if you look at the Nordic operators, they are utilizing the abundant hydro energy available onshore.
While reducing these emissions at the source is key, we have also seen operators being interested in technology such as CCUS and participating in the voluntary carbon markets to really get their hands on removals and avoiding space credit to offset these hard-to-abate emissions.
So Varaleka just talked about a couple of the different types of carbon credits that are available in the market. S&P Global Commodity Insights publishes a lot of different daily carbon price assessments. Arsalan, can you talk a little bit about some of the difference in these prices? And why are we actually using the CRC or the removals credit price in our assessment of carbon intensity?
When we really went out to the market, the main feedback that we got was the need for the use of high-quality credits, right? The market wanted to see what this calculation look like for removal credit specifically because those are the ones that the market wants to use. They might not use them all the time when it comes to the economics of them, and I'll talk about the pricing of these credits a little bit, but that end goal is using removal-based credits.
Companies like Microsoft and Amazon have come out and said that when they're looking at this space, when they're using the voluntary carbon market to offset their emissions, they're only going to look at removal-based credit. And that's kind of the approach that others have taken as well.
The way that we assess the Platts CRC or the price of the removal-based credits is it's a basket assessment, looking at 2 different prices. So one is the price of tech-based carbon capture and then the other is the price of natural carbon capture.
The lowest price out of those 2 is what sets that Platts CRC price. Currently, there's a wide price disparity between those 2 prices. So tech-based carbon capture mid-June was trading around $130 per metric ton, whereas natural carbon capture hovers around $16 per metric ton.
So as you can see, because that wide price disparity between those 2 prices, it's going to be the natural carbon capture for the time being that's setting the Platts CRC assessment. That's not to say that it will always be like that.
When you look at the road map to net zero for different companies, for different countries, you see that tech-based carbon capture is going to make up a bigger piece of that pie. As more investment dollars go into that space, right, here in our backyard in Texas, we see that there is a lot of plans for tech-based carbon capture in the Permian Basin as well as the industrial processes in Houston as well. So as more of those credits hit the market and supply goes up, at that point, based on market fundamentals, you'd expect the price of the tech-based carbon capture to go down.
There's other industries that are looking very, very close at tech-based carbon capture credits, such as the ethanol industry where ethanol producers are trying to get in on what that looks like for them. There's different industries from an industrial process that are looking at a similar thing, whether it's the metals industry, the petrochemicals industry, so on and so forth. So as more people look at the tech-based carbon capture space, it's going to be interesting to see what happens with the price component.
There's different prices that we publish in the voluntary carbon market. I just talked specifically about the Platts CRC, but then there's people out there that want to use avoidance credits, right? And we publish a price for that as well that hovers around $13 per metric ton.
We see a lot of these credits being used to offset emissions in places like South America where about 75% of their voluntary carbon market is actually made up of avoidance credits, places like Brazil, when you look at the Amazon rainforest, places like Peru and Colombia. So it's not necessary that everybody is using these removal credits, but that's really the type of credit that people want to use. In the absence of that, they are using credits that they have access to.
So Arsalan, just starting to wrap up, from a pricing side, how do you think we'll see carbon-accounted crude really evolving in the future and in the market?
So when we've talked to the market, we've really heard the sentiment of an attribute approach. So similar to where you have API with crude, where you have things like sulfur that affect the price, we're hearing a similar thing with carbon intensity.
Right now, we're really at the forefront of the market where market participants are still trying to wrap their head around what carbon intensity means, how it could affect the value of their barrel or the barrels of crude that they're buying. But eventually, what we're going to see is carbon intensity being attribute related to the crude and some price differentiation based on that CI number.
So barrels that have a low CI will warrant some sort of premium and vice versa is true for barrels that have a higher CI. Even though we think about this as the norm maybe some years away, we've already seen market participants try to extract value from lower carbon intensity.
So based on our carbon-accounted crude MOC guidelines that we published in or with the market itself, we see that based on a lower carbon intensity, people want to publish that in an offer and extract as much value as they can for that lower carbon intensity. We've seen an interest not only from the supply side, but from an end use side as well, where refiners actually want to take a hard look at the slate of crude that's going into the refinery and being able to identify the carbon intensity for each one of those.
All of this is currently voluntary. So there's no regulation out there that says that you have to buy crude that has a lower carbon intensity. But in the eventuality that this happens, as people really start to tighten the screws on ESG and a focus on the environment, if that comes down the pipe, then we can expect to see that CI will inherently just be an attribute related to the crude rather than having to wait for the market to really adopt that.
And I'll say that we're at the start, but we're already seeing carbon intensity being part of this conversation as we talk about things like API and sulfur. So it's really, really exciting to see.
And Varaleka, when we look at the upstream carbon intensity, how do we see the traditional upstream oil and gas sector evolving in the coming years?
Yes, I think this is a very interesting area to watch. We expect the traditional upstream oil and gas industry to truly evolve in every front. We have already seen oil majors diversify their asset portfolios and remarket themselves as energy companies rather than traditional oil and gas providers.
The European and Middle Eastern majors are investing in hydrogen, renewable energy and CCUS facilities. And mid-June this year, Chevron announced that it would be spending $2.5 billion to develop its hydrogen business line.
And on the other hand, we've also seen oil majors spend around 14% of their CapEx on the low carbon initiatives this year. While there is an interest in the low carbon investments, the majors are also cleaning the emissions of the books with asset sell-offs. So majors are exiting from high carbon-intensive assets in Latin America and the North Sea. And in the U.S. alone, we have seen around $77 billion in asset sales to smaller companies with less oversight and [ decommissioned ] targets.
There's an obvious movement in the clean energy space, but the bread and butter of these companies still remains selling oil and gas. And that's why we are seeing operators making announcements to invest in advanced crude recovery methods to lift their field production and integrate upstream and downstream business lines.
There's also a growing interest to invest in petrochemicals and circular plastics. While most of these investment activities right now are influenced by the investor pressures, in the long run, it would really be the policy development like Arsalan mentioned that would reshape the traditional commodity markets.
I mean there are separate proposals around emission reporting and accounting by the SEC in the U.S. and the EU ETS, which actually have the potential to reshape the market. But I think in the coming years, we anticipate a whole new trading ecosystem to develop where carbon accounted commodities can be traded effectively. And this is only possible with standards around carbon accounting and international trade consensus.
I want to thank both Varaleka and Arsalan for joining me today. This is a fascinating topic. And like they both talked about, we're really excited to see how this evolves, both in terms of how we're looking at carbon intensity fields, but also how carbon pricing and the concept of how carbon intends to become an attribute of crude going forward in the future. So thanks both for joining me today.
Stay ahead for the evolution of energy and navigate the pathways to a low-carbon global economy with the Platts Atlas of Energy Transition, your map to the sustainable commodity markets of the future. Explore the Atlas by visiting spglobal.com/atlas.