Devin McDermott: So I wanted to ask about the Permian. You’ve had strong results so far this year and in the slides you had some interesting charts and some of the advantages you see versus peers and how you develop the asset. I was wondering if you could dive into a little bit more detail on that. When you think about some of the specific drivers that allow you to get such better MPV versus other cube development in the basin, what are those in your view? And as part of that, could you address the resource recovery trends you’re seeing and the improvement there and any room for further up-side on that?
Darren Woods: Yes, sure. Al, I guess maybe start by going back to the approach we outlined 2018-2019 timeframe where we said ExxonMobil can bring a different game to the unconventional space and really bring to bear and leverage the capabilities that we have versus many others who are competing in that space. And key amongst those was taking advantage of our scale and balance sheet to develop this asset at scale. And so, you may recall, we talked about the cube development, which was really focusing on how you maximize overall recovery and not near term production. That wasn’t a particularly well received approach back in 2018-2019 timeframe, but I think with time, it’s demonstrated its value and it’s actually manifesting itself in the results that you see today, which is, we’re focused on making sure that as we develop the resources and all the benches in that resources, particularly the ones that are connected, that we do that in an optimum way, that develops and maximizes the recovery versus initial production rates.
And so that’s really important. That cube development, we continue to evolve that. I think we’ve gotten to a stage now where we feel really good about how we’re executing that development. We focused on capital efficiency. And I would tell you today, we are setting records for the length of our lateral wells, which, again, lowers the cost associated with accessing the resource. And importantly, as you drill longer wells, it’s critical that the productivity of each foot of that well remains constant. And so, we’ve done a lot of work to make sure that the productivity of each foot is consistent as we drill longer and longer. So that’s driving capital costs down pretty significantly. And then I would say, we’ve got a lot of technologies that we’re trialing, ones that I won’t go into specific detail on to try to match some eyes recovery.
And we’ve got those technologies deployed in the field. We’ve got some early results that are quite encouraging, but they aren’t at the scale today to manifest themselves completely in our results. So, I think all those things together continue to give us a lot of confidence that not only have we moved to the front of the pack and demonstrated industry leadership with what we’ve got today that we see a lot of upside to that as we move forward and I don’t think we’ve reached the end of the optimization process yet.
Devin McDermott: Great. Thanks Darren.
Darren Woods: You bet.
Operator: Moving next to Sam Margolin with Wolfe Research.
Sam Margolin: Good morning. Thank you.
Darren Woods: Good morning, Sam.
Sam Margolin: This question is about EOR. Hopefully, you don’t find it too far afield. But because you are [Technical Difficulty]
Jennifer Driscoll: Devin, you are kind of breaking up on us. Sam, are you available? Operator, let’s try another question and come back to Sam.
Operator: Okay. We’ll go next to John Royall with JPMorgan.
John Royall: Hi, good morning. Thanks for taking my question. So I’m just looking at your bridge for energy products and you have over $2 billion of negative margin, it’s right in line with the number out of your 8-K, so no surprises there, but definitely a bigger decline on a relative basis than we’re seeing from your couple of peers that have reported so far. So, just looking for any additional color on the drivers of that margin decline? Maybe there’s something to call out around regional mix or crude slates that are a bit more unique to Exxon?
