 So good morning and welcome. Whoa, good morning and welcome. Let me start off with a quick administrative safety moment for you all. Since we're on the ground floor, this'll actually be pretty easy. There's two access egress routes going out of this room. If you go directly to the back and follow signs to your left, the exit signs will drop you in the alley on the side of the building. It takes you out to M Street South. If you walk through the front, which is probably the easier way, because that's the way you came in. You go through the foyer out onto Rhode Island Avenue and we congregate in the park across the street to the right of the Beacon Hotel, okay? We don't expect anything to happen, although we did have Secretary Jewell here a week and a half, two weeks ago, and there had been a gas leak on M Street a couple of blocks away. And she announced to the crowd that there was a gas leak in the building. And everyone sitting in the back of the room quickly got up and left. So I'm just putting you on notice for that. For those of you that don't know me, I'm Frank Verascio. I'm Senior Vice President here at the Center. I'm also the Schlesinger Chair for Energy and Geopolitics, and it's really my pleasure this morning to welcome you to this discussion because we've been talking about this for quite a long time to be able to combine refining and crude exports because that's where the rubber hits the road, right? We started working back in 2008 on the shale gas revolution in part because we had worked on the NPC study, Hard Truths, and there was a white paper in the NPC study that talked about unconventionals. And we thought, huh, this is interesting. So let's get a handle on that and see where it goes. So our first natural gas event was done in 2008 in the subsequent six or seven years. We've worked on exports, high prices, low prices, productivity, infrastructure, the policy issues attendant to this revolution. So the SPR, size, composition, disposition of the Strategic Reserve, the Jones Act, things that people don't normally wanna talk about, issues related to transportation modalities, whether it's rail or pipe, refining infrastructure. And this is one of the things that actually has struck me for quite a long time that in this town, people talk about volumes and they don't talk about quality of crude oil. And with the exception, if you think of large scale crude burn, most of the oil goes to refineries. So you have to bring that in the conversation. And the quality part of the refining is actually an interesting, more interesting conversation. So we'll get into that with the speakers we have this morning. If you'll indulge me a little bit, I actually do have some setup slides, but since this is throwback Thursday, I'm gonna take a personal moment. This is my forest pump moment. So when I started in the industry, one of my first jobs was with TOSCO and the acronym stood for TOSCO, the Oil Shale Company. And I was director of crude supply and refining. So I did mostly downstream, but there was an arm of TOSCO that was dedicated to research. And the research part of that was to identify sources of crude oil that would produce a light oil that would fuel their refineries where they needed a high gasoline yield. And we decided that shale was the way to go. And they hooked up after a variety of experiments with Exxon at the time and developed a oil shale project that was actually pretty harsh on the environment and involved retorting high cost. As we led up to that period, so this is coming out of the embargo, coming out of the Iran-Erech War, the Iranian Revolution, price decontrol, prices were skyrocketing at the time, all relative, where people thought if you could get access to this light sweet crude and make a lot of gasoline before cafe standards kicked in, you could make a lot of money. And then we hit a price downturn. Sound a little bit familiar? And a lot of this research went away. And then it took 30 years for this to come back. So the good news side of that story is when I left Tosco, I went to Penn's Oil, and my first project in the upstream was fracking the Marcellus. These were shallow vertical wells, but we thought that there was a lot of gas there. It would just take time for prices to bring that forward. So it's actually been an interesting ride, but as you go through this, you've seen some of this before, but there was three lessons I learned in that, and I think they're all applicable to today. So the first one is that all shales are not alike, and we're seeing they're not homogeneous. The productivity that we see getting to know the rocks is really important, and one of the downsides of the price decline is that the research wells really aren't being drilled anymore. And that really helped us when prices were rising to better know the reservoir dynamics, right? Second part is that all crude oils are not created equal, and beauty is in the eye of the refiners, and I think you'll hear that theme echoed today. People talk about light and heavy, but they're sweet and sour. There's nephrenic crudes that are good for gasoline. There's paraffinic crudes that are good for motor oils and lubricants, because wax and acid content, you don't want, because it's corrosive to your refining, to your process. And these are expensive pieces of equipment, right? And then the third piece is economics really matter, and I think this is one of the themes you'll see as well, is that it's not only the inputs, low-cost inputs, but it's to maximize the value of the outputs by getting high-margin products. So when you think through this about where light oil goes and where heavy oil is refined, putting in both the domestic and global perspective is really important. So if you'll indulge me here, I've got a couple of quick little slides, and then we'll move on to our panel, because I think this is actually part of the conversation that people haven't had. As prices rose and we started looking at the U.S. supply chain, hydrocarbons are a continuum, gas condensates are liquids, and then the oil piece of it. And when you get to that piece, I'm sorry. The gas side is really important. On the refining side, gas is a feedstock. It's a blend stock component, and it's a source of hydrogen. So it's a process fuel and also a feedstock. And so we will continue to have the benefit of low-cost natural gas, but that's important. As prices rose, and you started seeing this on the production side, people that were producing gas looked for condensates because condensates were closer to crude oil, almost had the price of crude oil, and they moved to liquids-rich plays. On the crude oil side, if you add the condensates and split them off, especially from light oil, it could actually increase the value of your crude oil or decrease it, depending on what the refineries were. But the crux of the matter is on the crude oil side. And the rise in light oil on the crude oil side has just been phenomenal from the U.S. perspective. So much so that it's displaced most of our imports of similar light oil, and it's now is substituting for other oils. But that takes investment to accommodate that. We're actually back to levels that we haven't seen in 30 years. I think the February numbers for EIA were 9.2 million barrels a day in production. That's actually pretty phenomenal. On characteristics, the quality characteristics make this discussion more interesting than just simple volume substitution. So when I talk about beauty being in the eyes of the refiner, I think it's important. Crude oils are classified and priced by density, by sulfur content, by acidity, and those discounts reflect the desirability to certain refiners and also the availability. So if you have something people want, they will pay for it. If there's a lot of it out there, price goes down. But then there's other quality characteristics too. And Lynn and Joanne, I think we'll talk about this in a broader context. Inputs and outputs. So typically, light oils produce a certain slate of products. Heavier oils produce a different slate. When you look at the value of the crude oil going into the front end, you want to maximize the yields of high value products at the back end. You can upgrade some of those heavier oils, but that takes process equipment to do that. And you'll see when you start looking at the discussion of what oils and how they're priced that these economics enter both on an individual refining basis, but also on a global refining context. Crude oil quality, I'll leave this because it's great minds. When I talked to Lynn about this, he has an identical slide. So I'll let him explain it. What's kind of important lower right hand side, you can see that Eagle Ford and Bakken don't sit with the normal refining mix. They're at the light end of the scale. And then the final point is that economics matter, like in any business. So you want to optimize refinery operations both at the front end and the back end. And that involves integrating a wide array of feedstocks, typically 80 to 100 different feedstocks to produce a slate of maybe 20 or 25 products that have high value on the back end. So the trick throughout this process is to find the right combination of inputs and outputs, operating rates and the parameters that you operate those refinery to deliver the most profitable outcome. And then the final point is that the issue of new investment. If people know that they have a secure supply of low cost feedstock and they can afford to make that investment and recoup those costs, they will do that. In the current climate, when you look at the new production that we expect to come from the Gulf of Mexico, for example, over the next three years, some of that may feed into Gulf Coast refineries more easily than a lot of new light oil. The price of light oil will change relative to where we're selling it and what the demand for it is. And all these new investments trigger new source review, in most cases, from an environmental and regulatory standpoint. So it's a little bit more complex, but it actually is still a good story. For our speakers today, and these were all chosen because of their expertise, and I would argue, with the exception of Joanne, that we have over a hundred years of experience here. A hundred and two. A hundred and two. He's got 80. Wow, it's a tough crowd. But they were all chosen after talking to a variety of people and I want to thank Bob Slaughter and Tom O'Connor and Kurt Barrow, folks that we talked to, Marshall and John Guy at the Petroleum Council, because they really helped us think through this. This is a complex issue and we wanted to make it digestible but also informative. So Lynn Westfall is our first speaker. Lynn serves as Director of Energy Markets and Financial Analysis for the Energy Information Administration. But in addition to his government credentials, he formerly served as Senior VP at Tesoro and he was Vice-Chair of the Western States Petroleum Association. Ah, so his 37-year career, now we're up to 250, in the refining industry included operational assignments in refining, processing, crude purchasing, wholesale and retail marketing and asset acquisition. So pretty broad spectrum. Joanne Shore, Joanne carries the title of Chief Industry Analyst for the American Fuel and Petrochemical Manufacturers, where she focuses on regulatory and policy issues related to refining and processing. Many of you know Joanne from her tenure at EIA and also in DOE's Department of Policy, but before that she handled competitive analysis and planning for the downstream specter of Gulf Oil, for those of you old enough to remember Gulf Oil. Martin Tallett, Martin is the President and Founder of ENSYS Energy. He's a well-known advisor to both industry and government. He developed a decision support software and services and we went around looking for the number of companies that could speak authoritatively on global refining trends and investment. Martin consistently comes out at the top of that list. Prior to his consulting work, Martin too worked for Exxon and for Amaco, so this is just a terrific panel. I would urge you to pay special attention to these discussions and then we're gonna move on to the export panel immediately following this and we will show you how they tie together. So thank you all for coming. I'm gonna start with Mr. Poti. Yeah, so where do my slides? Let me bring them up. I control this from here. You see them in my hands. I know my slides are there somewhere. There we go. Got it. Okay, we got it. All right, well thanks Frank. Good morning and welcome everyone. Now the task I was assigned as a member of this panel is to review refining processes in order to try and explain exactly what it is that refineries do. As Frank so kindly put it, I've been in the business for a long time. I've probably been giving these refining presentations for 20 to 30 years, but the one thing I've never been able to do is to make this subject matter exciting. The best I can hope for is that I can make it informative and I hope you find that to be true in the next 20 minutes or so. Okay, well to begin with, as Frank has said, really in order to understand refineries, you have to understand their major feedstock, which is crude oil. And the reason for that is that refineries are designed around certain crude qualities. The type of refinery you have, the size of the units, what the units do, depend on the qualities of the crude oil and the two major determinants of crude quality are first of all, it's gravity, it's density. The reason that's important is that the lighter or the less dense the crude oil is, the more it naturally contains the size of the molecules that we want it to have. If you think about it, refineries take a very heavy dense material called crude, they turn it into a very light material, gasoline. So the more that light material is already in the crude to begin with, the less work a refinery has to do and the less sophisticated refineries are needed to process it. We measure gravity or density in units called degrees API. That is simply a scale of density that is set up so that the API of water is exactly 10. It's just a scale that's set up that way. So we designate the three types of crudes that Frank told about, light, crude, medium and heavy. Now you notice I have different unit numbers here. I say that light crude starts at 35, Frank said 34, medium at 27, Frank said 24. There's no ruled per se in the industry on what makes light heavy and crude. Everybody's got slightly different numbers, the point being that they are generally classified in one of three categories, like medium or heavy. Just to give you a feel for these gravity numbers, tar. You may have noticed that there are a few repairs going on on the roads in DC. Well that tar that they're spreading out on the cracks has a gravity of about eight. And motor oil, if you've ever added motor oil to your car, has a gravity of about 40. So that's just again to give you a feel for the numbers that we're talking about here. The second major quality of crude that's used in designing refineries is the crude sulfur content. Frank gone over this a little bit. The reason that's important is number one, sulfur is a poison to the catalyst that are used in the refining process. If you design a refinery to take out to run a very low sulfur crude, you don't have a lot of ability to take all the sulfur out if you try and put a high sulfur crude in it. And if you can't take the sulfur out, you'll poison all the catalysts in your refinery and you'll end up not having a refinery anymore. The second reason that refineries take out sulfur and you have to design around how much sulfur there is is that when you burn sulfur, it forms sulfur dioxide. Sulfur dioxide combines with water to make sulfuric acid. Sulfuric acid will corrode your engine. It'll corrode your refinery. And for those of you that remember long enough ago, it's a major cause of acid rain. We measure sulfur just in terms of weight percent. Again, Frank showed you the cutoff point between sweet and sour is being 0.7%. I've got 1%, no hard and fast rule. Again, just two categories of sulfur content. Matter of fact, I will tell you the short story behind why we came up with sweet and sour is the names. In the very beginning of the refining industry, and no, I was not around at this point. The only product that came out of refineries was kerosene, lamp oil. And it competed at that time with whale oil. Both of them are clear substances and the only way a consumer could decide which one they were getting was actually put a drop on their tongue. Whale oil is sweet. It comes from fat. And kerosene still has sulfur in it, so it tastes sour. And that's how we came up with the terms all those years ago to differentiate sulfur content between sweet and sour. Now for completeness sake, I'm gonna show you a couple of other qualities of crude oil. These are not so important when you design it. It certainly is important when you buy crude oil and in pricing it. There are other things that poison catalysts. There are some metals, nickel and vanadium being two that act as catalyst poison, so you will discount the price of crews that contain high number of that. Frank alluded to this. If you ever hear of high tan crude, tan stands for total acid number. Obviously the acid content can lead to equipment corrosion and as a matter of fact, if you try and run a crew that has high enough tan content, you actually have to have a special metal in parts of your refinery in order to run it without crowding your refinery. And then there are some terms like naphthenic and paraffinic. These are really just different chemical compounds that give you an idea of how much or how little of less desirable products they yield. Well, on a worldwide basis, looking at the two primary characteristics, gravity and sulfur, you see a wide spectrum, all the way from very light, very sweet crudes, such as Eagle Ford, as well as some that come from places like Malaysia and Algeria, all the way up to very heavy, sour crudes, like a crew that comes from Mexico called Maya, and then you have every combination in between. Very roughly speaking, very general rule of thumb that doesn't always hold true is that as crudes get heavier, they also get more sour. You can kind of see a line going up from lower right to upper left. In general, that's true. It's not always true, but in general, heavier crudes tend to have more sulfur. Now, when you look at the gravity of a crude, its density, it gives you a very good indication of the size and distribution of hydrocarbon molecules. And quite frankly, if you remember anything from my presentation, this is the one slide to remember. After this, I'm gonna get a little more complicated and you can go out and get some coffee, something like that, but this is I think the one slide that will help you remember what refineries do. What I've shown here are four different crude oils. I've got Eagle Ford in green, I think that's green, Bakken in orange, Alaska North Slope in dark blue, and then Canadian oil sands in the black. What this is is, this is a chart of the percent, volume percent in these crudes that boil off at individual temperatures. That's important because the temperature at which a component boils off is directly related to the size of the molecules, the number of carbon atoms that are there. So for example, if you look at the green line, you can see that a large portion of Eagle Ford boils off at about 200 degrees. And going down to the next scale, that means that a large portion of Eagle Ford condensate has molecules that have seven to eight carbon atoms. And the number of carbon atoms determine what refinery products are in the crude itself. Gaslings made up of compounds that range from about four carbon atoms to 12 carbon atoms. And refinery processes are largely built around making gasoline. So what refineries do chemically, if you wanna think of gasoline as being the Goldilocks zone, that's the zone or the size of molecules that we want. What refineries do is, for the molecules that are too small, they have chemical processes that combine them together, make them bigger so they'll fit into the Goldilocks zone. And then for the molecules that are too big to fit into the Goldilocks zone, they have chemical processes that break them up. And that in essence is what refineries do. Now you'll notice that there are a lot less small molecules to combine than there are big molecules to break up. And I'm about to show you when I get into the more detail of the processes, that's the reason why we have a lot more processes in refineries that break up big molecules than we have processes that combine small molecules to make them bigger. But I think it's easy to see here how if you designed a refinery to run, let's pick the extreme example of Canadian bitumen and the unit you'd have to put in to break up those molecules, that refinery is substantially different than a refinery that's built to run Eagle Ford Condensate, for instance, which already has a lot of the right molecules. And that's the reason why you can't run heavy crude and a light crude refinery and you can't run light crude and a heavy crude refinery because of this different distribution of the molecules. And again, you're trying to get everything into one zone between C4 and C12, let's say. Okay, with that in mind, I'm gonna get a little more complicated here. This is a diagram of what you'd call a complex refinery and all of its various processing units. Now, in general, these units fall into one of three categories. Either distillation, which is the separation of molecules, conversion, which is actually chemically changing the molecules, or desulfurization, which is removing the sulfur. So I'm gonna go over these one at a time. Let's look first at distillation. Distillation, and you may recall from high school chemistry, is simply separating components by differences in their boiling point. It does not change the chemical nature. It is the very first process in refining because the first thing you have to do is separate crude into large groups of molecule sizes to then send them to the right unit to either break them up or combine them. And it's also used throughout the refining process for purification. Chemical processes don't make 100% of what you're looking for. You always get a byproduct to sort of purify it. You use distillation to separate them out by their boiling points. As an example, what I'm showing here is a scale of carbon atoms from one to 10. I'll also show you the names in case you're interested. You can amaze your friends by knowing that C10 is called decane. And to the other side is their relative boiling points. Roughly speaking, every carbon atom you add adds about 60 degrees to this boiling point. And if you think of a nice summer day when the temperature is, let's say, 90 degrees, what this means is that everything with four carbon atoms and above would be in a vapor stage because 90 degrees is above its boiling point and everything with five carbon atoms and higher would be in the liquid stage because it hasn't reached yet its boiling point. So this is the very first process in refining. It's distillation. We separate crude into broad categories of molecular sizes and then we give them names that no one can understand. We call them things like naphtha and gas oil and those sorts of things. Now the next process that we're gonna talk about are the conversion processes. And these are the processes that move the molecules into that Goldilocks zone. These are processes that change the chemical nature. They generally require a catalyst and they are generally directed at producing gasoline. The reason for that is that jet and diesel fuel occur naturally in the crude oil and all we really have to do is separate them out. We don't have to chemically change them. Gasoline on the other hand is a blended product. Gasoline is the result of anywhere from three to eight different components that come from various units. There is no unit in a refinery that is the gasoline unit. You can't point to one and say, the units make a component of gasoline and then you blend it together at the end. And of course as we said earlier, all your processes and conversion are either making heavy components lighter, lighter components heavier or changing and improving their quality, such as octane. So the first of these, making heavy components lighter, there are three refinery units that primarily do that. There's coking that's done in a unit called coaker. They use a very high temperature to break up the very heaviest components, the biggest molecules in crude. You then have a hydrocracker that uses high pressure hydrogen to break up the next heaviest size components that are about the size of diesel molecules. And then finally you have a fluid catalytic cracker or an FCC that breaks up the next size molecules to get them into the Goldilocks zone. So we're gonna add these three to our diagram and they fit in right here. And again, going from breaking up the very heaviest to breaking up medium size molecules. Now for taking light components and making them heavier, there's really only one process in the refinery. It's called alkylation. As I said before, as the crude all comes in, it really doesn't have a lot of light components. So it doesn't pay you, there's not a whole lot of volume there. So it doesn't pay you to take those light components and combine them together. But in a catcracker, an FCC unit, the one that breaks up the lightest of the heavy molecules, if I can ruin the English language that much. Those molecules are so close to the Goldilocks zone anyway that catcrackers have a habit of over cracking and making some of the molecules actually too small. So an alkylation unit is attached onto a catcracker to take that portion that has been over cracked, combine those smaller molecules together and make a larger molecule out of them. There's an older process. If you ever visit a refinery that's got an older process called polymerization, you're in about a 1930s or 1940s era refinery and I would leave if I were you. I'd just say that for completeness. Okay, so here's where the alkylation process is added. As I said at the tail end of a catcracker. Now the last conversion process, and this is one I haven't really talked about before, is you do have some molecules included that naturally occur in the Goldilocks zone. The problem with them is they tend to have very low octane. That's because they are straight chains. They are carbon atoms just in a row that are lined up and for reasons I can't possibly go into, take my word for it, it has low octane when it has this shape of a molecule. So we've got two processes in refineries that don't change the number of carbon molecules. They don't break it up. They change the shape of it. The first of them is called a reformer. What a reformer does is it takes that molecule, it attaches the two end carbon atoms together and it forms a chain. That improves its octane considerably. So that's what a reforming unit does. Second process is called isomerization. And what this does is it takes that long chain molecule, it breaks a piece off the end and it reattaches it in the middle to form a branch. And again, those two shapes of molecules have much higher octane than the straight chains that come in with crude oil. So with that, you'll be glad to know we have built a refinery. You now have all the units you need to make the components, the blend gasoline, you've got your jet fuel and your diesel. Now lastly, for anyone who still remembers when I started my talk, I said there were three processes in refineries, distillation, conversion and desulfurization. And I've shown you distillation and conversion, I haven't shown you desulfurization. The reason for that is desulfurization occurs throughout the refinery. There are desulfurization units in front of every conversion unit because you have to take the sulfur out or else it'll poison the catalyst. In general, you design desulfurization units based on how severe, how much sulfur you want to remove. So if you want to only take sulfur down to 500 parts a million, you don't make it very high pressure, medium pressure and then very, very high pressures in desulfurization units can take it almost down to nothing about five parts per million. With that, I am done with my part of the talk and I will get to sit down now and I think Joanne's gonna come up next. Thank you. Thank you. Oh, it was above, it was above, sorry. There, all right, all right. Okay. I'd like to thank Frank and Sarah and CSIS for having this get together today. Let me see if I can go back one more. I'm gonna follow up on what Lynn started but I'm going to jump to the 60,000 foot level so you won't need to remember as many details but I hope you'll appreciate some of the complexity behind some of the things that I'm going to bring up. I'm gonna focus on the strategic shifts in refining that have occurred and I'm gonna start with a little history. Before we get to the light-tight oils, I'm gonna look backwards at a strategic shift in moving to the heavy crudes that this industry went through and then I'm going to talk about a second strategic shift that's a little more recent that's a demand-driven shift. Then we'll move to the light-tight oil shifts that are going on now. So starting with the heavy oil picture. Going back into the 80s, we had a lot of heavy crude production coming from Venezuela, Mexico, and the Middle East and with arrangements with Gulf Coast refiners, changes were made in our refining system to process more and more heavy oil from those parts of the world. And as Lynn pointed out, that measurement of gravity that says how heavy you are, the average gravity for US crudes began to go down. Then we had the oil sentence from Canada come on and refiners in the Midwest began processing that. And again, we kept going down in terms of what was happening to our crude oil slate. But of course, the light-tight oil production began to increase and we had a little turnaround in the gravity there, but we'll get to that in a minute. What refiners did to process this heavy crude is they invested in units called cokers that Lynn mentioned. These are brute force cracking units. They break those molecules apart. They create streams from those units that can then be put into other processing units in the refinery to create more gasoline and distillate. They're very expensive. We're talking about a billion dollars with a B for one of those units within a refinery. But you can see there was a lot of investment that almost tripled in capacity there from 1980 to where we are today. Now I'm gonna talk about another strategic change. Again, the demand change. As many of you know, up until 2007, we had been experiencing growth in petroleum in this country. This is a graph of the change in consumption between 1987 and 2007, that 20-year period, growth in petroleum in total, growth in gasoline, growth in distillate, which is diesel heating oil. But looking ahead from 2007 to 2027, we're looking at a declining demand in the United States for total petroleum driven to a large degree by gasoline cafe standards. And we have an increase still in distillate. So two things going on, a loss of total petroleum and a change in product slates. Well, we've had a recent loss in petroleum, mainly due to the recession, and our refiners have dealt with that by exporting product. We've gone from being a net importer product to a net exporter product. So the refineries are still continuing to run at fairly good levels as a result of doing more in the international markets. The more interesting change is the shift in product slate to needing less gasoline and more diesel. And this is true worldwide, not just in the United States. So refiners have been adding something called a hydrocracker to their facilities. These hydrocrackers that are being added now are to get more diesel and less gasoline. Valero, Marathon, Motiva are very good examples. They put in very large hydrocrackers in their facilities that also export product. These hydrocrackers are also very expensive. Valero quoted for a single grassroots hydrocracker, 1.6 billion with a B. So both of these investments, coking, hydrocracking, very large investments, ones you have to consider carefully and consider the risks involved with those investments, but they're being made. Now we'll turn to the light tide oil situation. One of the first challenges with light tide oil is getting the crude oil to refiners. And I think a lot of people in this room have already seen the many changes that have gone on in pipelines, rail, and so on to have that happen. Once that oil gets to the refiners, the first no-brainer is to back out lookalike imports. Then they start to adjust the crude mix. Sometimes that involves investment and more so as we go down the road. Interestingly enough, what we're seeing is the largest dollars being spent, the largest amount of capital dollars being spent by the refining industry. Not the midstream, the refining industry is transportation, getting that crude oil to them. They are investing in rail cars, in terminals, in pipelines, and so far, the biggest dollars are on that side of things. This is a little look at those imports. Lynn mentioned this and it's a visual that shows between 2007 before the increase in light tide oil production, that little orange area on the top. That is the quality of crude where a lot of this light tide oil resides. We're calling that super light on this particular slide. That's almost totally backed out now. In addition, we've seen a reduction in light crude oil, which is the next gray area below it. And we've seen some reduction in medium crude, but heavy crude continues. Two things have come out with people looking at this. One is we've gotten rid of the easy imports. Refiners now have major changes they have to make to be able to deal with these crudes. The second is all of this light crude is coming to the Gulf Coast where they process heavy crude and they process heavy crude, therefore they can't use the light crude. Both of these are incorrect. This is an old example and I pulled this up purposely as an old example. This is a mixed example. This goes back to 2003 and 2004. At that point, the imports were much higher and eight, sorry, there were nine refineries that were picked for this slide that their full slate was imports. So you're seeing the full slate of crude coming into these refineries. At that time, these refineries represented 1.8 million barrels a day on the Gulf Coast. They run a mix of crude oils. They were running about 35% heavy crude, but they also run light, they also run medium. They run sweet and they run sour. They run mixes and optimize those mixes. The other interesting point about this slide was what was going on at the time. This was devised because China's demand had just jumped and everyone was concerned about refineries ability to meet demand. The incremental crude coming on the market was heavy. Some folks were saying refiners can't handle the additional heavy crude. Their cocas are full. They can't run anymore. We can't meet demand. Well, this was an example of what they were doing. They were not investing at this point. These refiners had no new investments. They went from 35% to 40% heavy crude and they shifted some of their other crude to be able to do that. Now, there are limits to these shifts. That is absolutely correct. You can't shift forever. So you do have to make investments and we're gonna talk about that now. When a refiner is looking at investments, they look outside the refinery. They look at what's going on in the marketplace for crude, what's going on in the marketplace for products, what future regulations might be, their own competitive position. Inside the refinery, they look at their feedstock. If they make an investment, what can they do to better their feedstock situation, lower the feedstock costs, what happens to their operating costs and what kind of yield shifts do they get that will affect their revenues. And this is a little example. This was put together when prices were higher. It's an example that I'm going to give you and you're gonna see in a minute of a cracking refinery running Mars crude, which is a medium heavy crude, that then adds a cocker. And you'll see the shifts that go on just with that simple example. First thing you need are prices. Prices for the feedstocks, prices for the products. Now, when this refiner, a 100,000 barrel a day refiner is running this crude oil, the yields for the products are right below it. You see it's 41% yield for gasoline, 31% yield for distillates, 24% yield residual fuel. That's a boiler fuel. Look at the price of that residual fuel, $100 a barrel. The crude cost for this one was $112 a barrel. That's a cash losing product. But still, that refiner has product revenue coming in in total of $123 a barrel, 114 feedstock costs, operating costs, $3.24, with a margin of 558 cash margin put towards a return on their investment. Now they look at adding a coking unit. And remember today, coking units of billion dollars, these are big investments. What do they get for that coking unit? Well, look at their gasoline. They get more gasoline yield coming out of that barrel of crude oil. They get more distillate yield, 38%. The residual yield is almost gone, down to 3.5% and they get some petroleum coke, which is also not a high value added product. But in the end, their product revenue is higher. Their feedstock costs are a little higher because they're making more gasoline. They need a little more butane up there. Operating costs are higher. It costs more to run with the coker unit, coking unit. Their margin is $2 a barrel higher. Is that enough to get an adequate return on that coking unit? We don't have an answer to that, but that's the question they're trying to answer. If they had to put a billion dollars into that coking unit, are they going to get enough margin to justify that? And normally they wouldn't be running the same crude. They'd be actually going for cheaper crudes that have a little higher operating costs, probably not as good yields and they're hoping that with the drop in feedstock costs, they'll get an even better return on it. So that gives you a flavor for the kinds of detail that people start to look at and there's many, many combinations there. When it comes to the light-tide oil, there are several investment areas that refiners are making and they vary all over the place. Refiners are very, very different in terms of what they need to do to handle these additional light molecules that are coming in from the light-tide oil. One of the things they do is before it even gets to the crude unit, they put in equipment that will take off some of the light material to help get a material coming into the crude unit that doesn't have quite as much light material. Another thing they do is expand that crude unit to be able to handle more of that light material coming in. Another thing they do is what they call these overhead systems. The stuff that comes out of the top of the crude unit, the gases and the other light material sometimes needs to be adjusted and expanded to handle the additional light stuff coming in from this crude oil. And units downstream. This happens to be an example of a naphtha treating capacity situation here. Naphtha is a gasoline component, one of those light things that comes out of that light crude. You may have to expand some capacity there. But the bottom line is the cost of these kinds of investments run from 10 to 100 million with an M. These are small investments compared to what they were investing in for coking units, for hydrocrackers, and a lot of these investments are being made. We did a little survey last fall. It was about 60% of the industry capacity-wise. It showed that at the very top bar, these are market shares of their crude mix. They are increasing their supply of that super light in their runs. And looking ahead to 2016, they plan to continue increasing it. The interesting thing about this bar chart is in the future of 15 and 16, they're gonna cut a lot more into the medium than they have historically, and that gets back to some of the investments that are being made. Volume-wise, the increase in their plans represented over 730,000 barrels a day increase from 2014 to 2016. So the bottom line here is in the short term, the refiners are prepared to deal with this light crude. Yes, there are challenges. Yes, there are investments, but they're happening. And I think we're gonna wait with questions until the tail end. So, Martin. So good morning. Just while the slides are coming up, much appreciate the opportunity to be here this morning. And I came down from Boston, so I feel a bit like a gnome that's been let out into the sunlight. And you have some very strange things here that are kind of orange and yellow and purple along the side of the road. I think they're called flowers. And so it's actually nice to be somewhere relatively warm for once anyway. So, two super introductions by Lin and Joanne. And so I don't really need to say anything about refining now. That's the good news. The bad news is, you probably didn't know there's a test on this before you leave. But what I'd like to do is to take what they have said and really focus in on what do we see as some of the international implications of either not or going ahead with open crude oil exports from the U.S. Just first of all, ends this energy. And as Frank said, for about 30 years now, we specialized in assessing the developments at this sort of international scale and doing so in an integrated way. We try as much as we can to stay out of the politics and to try to assess by building bottom-up views of how the industry is likely to react going forward in time as things change and also under particular scenarios, a lot of what-if questions, it could be logistics, regulatory and so on. And that's really why this very wide range of clients has tended to come to us over time because they have this common theme of being interested in developments at the national and international scale. And not surprisingly, in recent years, we've become very heavily involved in U.S. and Canadian developments in logistics. Three studies alone on Keystone XL actually is really four. And I think that is testament in its own right to the kind of issues that we are facing at the moment. And a lot of work on logistics developments, which we track monthly in a service that we offer. And particularly, I want to draw as well on the study we did last year in conjunction with ICF on the impacts of allowing crude oil exports. So the first thing is that you can't export crude unless you've got the infrastructure to export crude oil. And as of a few years ago, that infrastructure didn't exist in the U.S. It was built to bring crude oils in to the heartland of the U.S. and not take crude oils out. But as we've seen, they have this amazing dynamism here in the U.S. And a friend of mine from Europe said, only in America could this happen. And so now we have a situation where we have several million barrels a day of at least a nameplate capacity of both pipeline and rail ability to take crude's two coastal markets. The Gulf Coast, not surprisingly. The primary target there. Where are we? Over six million barrels a day potentially total by the end of this year. And a lot of capacity to get that over the dock and onto the water as well. Not necessarily the biggest tankers, but it's feasible to do so. But also we should not forget that we have a lot of capacity that's now built that takes crude oil to East Coast and West Coast destinations. And some of that as well could be used to take crude out of the country. Those are the direct routes. And in addition, there's potential at least for indirect routes, such as particularly back and crude getting on to the Enbridge Line 9 that's being reversed and potentially onto Energy East Pipeline, very large project if it goes ahead eventually 1.1 million barrels a day that would take crude out to the Maritime provinces of Canada and then to the water. So this whole question about ability to absorb U.S. light tied oil that Lynn and Joanne have been building up to. And thank goodness Lynn explained API gravity, so I don't need to explain that anymore. And this chart shows what's going on in simplified terms. I mean, roughly we're saying that we have about five million barrels a day of light tied oil that's come onto the scene since 2008. And on average, if you include the Eagle Ford condensates and so on, it's about 45 API on average. And if you don't allow any crude oil exports, what you're trying to do or you're setting the refiners, the task to do is to accept or kind of stuff all of that into a system that typically processes about 15 million barrels a day. But as Joanne showed, has historically had a lot of investment to process heavier crudes. And so it processes typically about 31 degrees API overall crude slate. And that really is not a very good fit. And it's non-optimal, as Joanne said. You have to invest to de-bottom the crude units. And if you accept a lighter crude slate, you're also probably non-optimal in that you're not filling up your big upgrading units, cat-crackers, hydrocrackers, cocas, which are the units that give you the primary value added in the refinery. So there's a lot of issues there. And so what we're seeing is having backed out the look-alike light crudes. We now have a situation where there's incentives, of course, to get rid of the crudes some other way. So significant volumes going into Canada is basically the only non-US market currently available. And a series of what one might call get-arounds. So light or minimal processing of condensates so that they can be exported. And I think if we continue to see discounts of US crude oils versus international markers, then you have a continuing incentive to invest potentially in, say, simple splitters that will create two streams that can then be exported. Offsetting against that, though, of course, and again, going back to Joanne's comment about investment, is the mere prospect that crude oil exports could go open is of itself a deterrent to US refiners to invest. It could end up with stranded investment. So that's sort of a quick look at the US situation. But let's say, and this is now drawing on the studies that we've done, we've found that about 2.5 million barrels a day is an appropriate volume to be exported. So roughly half of that 5 million of light-tight oil production. And one of the questions is, well, can international markets absorb that? And the answer is really yes. It's a lot easier to take about 2.5 million barrels a day on average quality crude oil and to distribute that across international markets. Because looking ahead to 2020, the world will be processing of the order of 85 million barrels a day, about 15 of that in the US, which leaves about 70 in other world regions. Now, some of those regions are not going to be candidates for US crude oil. I don't think we're going to be exporting much crude oil to the Middle East, to Africa, and to Russia or the Caspian. So you put those to one side. You're still left with about 50 million barrels a day of crude being processed in several regions. And in general, with refineries that are somewhat simpler than those in the US and have typically somewhat lighter crude slates than the US. So taking those one by one, we're already sending about half million barrels a day to Canada. But as I mentioned before, the way we see it in our projections is if you allow open US exports that pressure to send everything to Canada would arguably diminish. And so you could have a reduction in the volumes actually going to Canada. But then Latin America is another potential market that we see. There, they typically have a heavier crude slate from their domestic production. But that's an opportunity for the light-tight oil to actually complement and blend up to a lighter level the heavier crude oils that they have. And very interestingly, just yesterday, Mexico announced firmer plans to engage in a swap, 100,000 barrels a day where they would send heavy crude to the US and the US would send light crude to them. And we also see this, we did a study recently for Mexico on their ICA marine fuels application. And crude trade was not the main objective of the study, but we could see the same kind of thing happening longer term. The US sends light crude very short distance down the road to Mexico that helps them produce lighter products. It also helps them avoid investment in upgrading capacity. And it seems like a very logical fit and potentially possibly to other Latin American countries as well. And then at Europe, declining petroleum product demand, declining refining throughputs, a severe product imbalance between gasoline and diesel. But nonetheless, what you have is also declining North Sea production. And much of the production that is remaining and even growing in the future is of heavier crude oils, often less than 30 degrees API. And so sending in a light tight oil is against an opportunity to kind of blend up to something that looks more like a traditional Brent or Forty's crude oil. And so there's a logic there. But one thing we note in our projections is if Canada is able to build out, particularly the big lines going east, then we end up with competition with Canadian light sweet and medium sourcruits, which are good fits for European refineries and maybe some heavy crude as well, actually moving to Europe and maybe nabbing some of that market. And then there's Asia, the massive refining system, really a combination of regions if you will, but processing in 2020 may be close to 30 million barrels a day of crude. A need to import that crude from all over the place. A lot of variety ability to accept different crude oils. They take in quite a lot of condensate partly because of naphtha use as a petrochemical feedstock. And so again, particularly with Panama Canal being expanded and allowing better economics from moving crude from the Gulf Coast. We see that in our projections as being a logical route, also potentially some movements possible off the US West Coast to Asia. So taking another look at this, looking at it a different way, what we're seeing in these projections is that if you allow US crude exports, you don't have to bring so much of that US crude into US refineries. So that volume to left-hand chart that drops. Also we see less crude going to Canada and then more to these other regions, Latin America, Europe and Asia. But this is not a one-way street. What we see is that US refinery through puts don't change very much. So what you're actually enabling is kind of a swap trade by getting rid of that really light crude from US refineries. You're enabling some of the more traditional imports to come in and to better fit the typical US crude slate. And so some increases back in from a little bit from a Canadian crude imports but also Latin America, Africa, Middle East. And this is not so much the light crude. It's the medium, some medium sweet but a lot of it's a medium and heavy sour crude oils. So again, swap trade is effectively what is likely to occur and that's what we project. Also less investment in US refineries. You don't need to make the kind of investments that Jo-Anne was referring to and you can operate US refineries more optimally. But again, for US refiners you need to have certainty in terms of whether crude oil can be exported or not. So looking at the crude slate and the left-hand chart here is the average API of what the US crude slate has been over many years and stating back to well before Lynn was born. And so we can see that again, the long down-term trend which has been replaced somewhat by a little bit of an uptrend in recent years. But the right-hand chart shows what our projection would be. The red line is if you allow crude exports you still got some lightning of the US crude slate. The blue line is what happens if you block any additional exports and you'd have a kind of severe uptrend in US average crude oil API. And that doesn't look like a whole lot but 40 degree API shifts spread across all US refineries on average with pad three refineries being the worst hit is a very major change. If you look at EIA statistics on subgroups of refineries, the API of the crude slate doesn't change that much from month to month. It only changes maybe plus or minus one or two degrees API as they shift crude slates around but over time they're all very stable. So you avoid that issue if you allow open crude exports. Again, in terms of the types of crude exported and we would see the first ones to get out of the US is much of the condensate type crudes because they're the least best fit. And so Eagle Ford condensate kind of number one on the list partly because it's proximity to the coast Corpus Christi and so on. Possibly some other condensates. And then the light sweet crude. So again, Eagle Ford crude, some Permian Basin could be a back-end crude as well in some near Barara crudes. Again, the light sweet crudes potentially also some of the sort of light medium sour crude and there ANS could be a candidate especially with a build-up in capacity to deliver crudes to West Coast refineries and possibly even some Gulf of Mexico offshore crude oil as well. It's difficult to look at this situation. Now I've been talking about the US but to look at it and without talking about Canada. And the really, it's almost one logistic system these days. And so looking at Canada and what situation could obtain there is one of the things we've consistently seen first of all is a potential for a lot of crude to go off Western Canada to Asia. Over a million barrels per day provided the logistics can be built which really comes down to trans-mountain pipeline expansion and to Northern Gateway, both of which have problems in terms of acceptance. But we could also see similar volumes again if energy is built and particularly if there's some constraints on the Western pipelines to go to Europe. And I mentioned this before. And so that's another situation. And again, that could be competition potentially for US crude oils. And so the movements to the US from Canada could end up playing more of a balancing role depending on which of these big pipelines out of Canada is or is not built. One thing I would mention here though is that I think there's been a kind of lack of limited discussion in the strategic debate. One might call it the NATO debate, USA, Canada, Europe on what the strategic incentives could be to supply refineries to Europe with Canadian and US crude oils, recognizing that anyway Russia is sending more crude now east because of the expansion of its ESPO pipeline system and recognizing to the issues in Europe at the moment centered around the Ukraine. So in summary then, yes, today we have the infrastructure to export crude oil in volume. Quality is really the big driver. If we were talking about this incremental crude oil being medium and heavy crude oils today, we would not be here in this seminar. It's because it's light crude, really light crude. And another thing that's key here is allowing exports enable to the market to operate more efficiently both in the US and globally. Okay, there's some winners and some losers but overall it operates more efficiently. And I think as I study with ICF and the other studies that have been done point out by putting more crude oil onto international markets you tend to get a reduction in global crude prices, depending on OPEC reaction and after the last few months boy is that some reaction. But there's a second component to this as well which is that enabling refiners to operate more optimally actually cuts the manufacturing costs. And so you can operate more efficiently your incremental costs for producing gasoline or diesel over and above crude tends to narrow. And so that also benefits the supply costs and ultimately consumers. And yes, the non US refining system is much bigger than the US refining system and can readily absorb the volumes that would make a big difference here if they were exported. And finally, as I mentioned before that we have to in this discussion really include Canada as well as the US because the two systems interact and operate so closely and it would be good to see some collaboration here. Okay, thank you for your time. So thank you all. You've managed to make this entertaining and you kept the bulk of the crowd. So that's a two for one of the things that strikes me and I think this is, I have two questions and I'll start them off in a second. But one of the things that strikes me is there's been a lot of discussion here about energy independence. We have argued against that. We think that there's a global market and there's benefits to that from all of your presentations it would seem that we will continue to import and export. So while net imports go down, the gross amount of traffic as we select the crudes, that's probably a good thing for global markets. And I think we're all kind of in agreement on that. The rhetoric sometimes gets overblown but the two questions I have, so I'll start with you Martin. It strikes me then in the global presentation you used DIA's high resource estimate and since it was done in 2014, a lot of it, I'm assuming it was kind of higher prices. In a lower priced, lower demand environment where we've displaced other lights, Angolan, Algerian, Nigerian, Crude Oil, Libyan Crude Oil even though it didn't come to the United States, if those were to come back on at lower prices those countries would I think compete more vigorously in Asian markets or European markets where they would be willing to discount because $50 versus $47, pretty easy choice to make in terms of losing a barrel. So when you talk about the volume of US exports that would move in this current market, it would have to be a lot less than the two and a half, three million barrels a day just finding a home. Yes, I think that's right. We all sit here with baited breath at the moment, I think waiting to see how much and how rapidly US production levels off because of these lower prices. And certainly that effect, difficult to quantify right now but it's going to take some of the pressure off exporting and as you say it could be that some of this offline crude that's in Libya and so on comes back on stream and that would add to the competition. Another thing that clearly is going to happen is that demand is going to go up for petroleum products, maybe not hugely but it should go up modestly at least and so that would create more of an opportunity in the refined products market which could in turn benefit US refiners. Okay, great. And then you can chime in on this too but for Lynn and Joanne primarily, when you look at the investments and the question about Joanne you all just finished a study about how much more light oil domestic refineries could absorb and then the question Lynn you raised about how much with the exception of December, January and February where gasoline demand looks to be going up, how much more gasoline do we sell and then you add in Mexico, the Gulf Coast, maybe blending with Canadian or a post-Maduro of Venezuelan oil, what's the incentive to make investments? Are refiners stuck at this point trying to figure out how they maximize profit? Joanne? Yeah, I'll take a first stab at it and one of the things I wanna clarify here because it's something that frequently gets confused in the discussion and that's short term and long term and there is no doubt when we go out longer term in a world where we continue to have this increase in light production that things become less optimal. The discussion of where a lot of the discussion is today is are we at that point or where is it? And I think Martin was talking about their study looking out as this production increases and I was talking short term the next few years. These investments are investments that are relatively low risk investments getting to Frank's discussion. These refiners at this point are not backing down any of the heavy crude that they're using. They're still using the heavy crude coming down from Canada, stuff coming in from Mexico and so on. So there's a period of time here when the investments that are being made are probably relatively profitable and still able to use this crude without having to make big decisions. We're talking about investments that in many cases if the advantaged crude discount will call it here in the United States from an equivalent international crude was $2 a barrel, they're making adequate return on the investment that they've got in there. So again, we're not in the realm today of making risky investments. But as refiners plan these investments and other investments are 20 year investments, 30 year investments, so they are looking ahead. They're looking ahead in the uncertainty of will we have crude exports, and many of the other regulations that may possibly change. And some of these investments are being done in conjunction with other investments in the refinery too, and it does impact their decisions. So regulatory uncertainty, uncertainty about what may happen to crude exports is important for that world. But a lot of what's being done in terms of getting access to and using more of this light oil today are not hugely risky investments. Yeah, I mean, you know, refinery investments are on a scale, of course, price versus return. And one of the interesting things that the AAPM study showed was in the next couple of years, I think it was an increment of 600,000 barrels or so to run like crude. Over 700. 700. And refineries are amazingly good at doing small things. We call it refinery creep. To small little projects, but when you spread it across 150 refineries. It's a big number. It's a big number, but you don't see it. What you see are the announced big projects, what you'll never see are these smaller things that can move you down the spectrum a little ways. I don't think we're at the point right now where someone's gonna invest $500 million in a big while. And I don't think we've gotten to the point yet where they're looking at the really large hundreds of million dollars investment. But as we progress down the line, the economics may be there. I think what you'll see though with the regulatory uncertainty, meaning I make this investment and then you allow crude exports and some of my economics change. I think what you'll see is refineries shifting some of that risk to the producers. Signing a long-term contract with them saying you will give me a discount off Brent of $8 a barrel. So I'll put this investment in and then they've shifted some of the risk. They're not gonna take all the risk for a $500 million project. And it'll be to both parties' benefits, really, to do that sort of thing. So I think that may be the next phase you get into if we get to the point where we need larger investments as a sharing of the risk. And on the policy side, and I know Ted's gonna discuss this in the second panel, but this whole idea of in the absence of crude oil moving on condensates the fact that we may make some stranded investments in the field, that we may not need when we eventually get to the crude oil export phase. We've done that before. We do that all the time. Yes. You always wanna be the first. You don't wanna be the last. So we're gonna open this up for comments and questions from the audience. We have a couple of simple rules. Wait for a microphone. If you can identify yourself and your affiliation. And while you're allowed to make comment, if you could ask your question in the form of a question, we really do appreciate that. So let's go ahead and we'll start here. And Mariah's got a microphone for you. Thank you very much. Diana Negroponte from the Woodrow Wilson Institute. I'm a Mexican expert, not a crude oil. Two short questions. One for Joanne. For the non-energy expert, would you please clarify back out imports of lookalike crudes? Short question for Martin, please, as a Mexico expert. The Mexican government has resisted the construction of a third refinery in Hidalgo based on costs. Now that this swap agreement is created, is there now an incentive for Mexico to construct? This would be private investment. A new refinery for Light Suite. Thank you. Yes, I apologize for some of the short terminology. What I should have said is reduce the imports of crudes that are of the same quality as the light tight oil that's coming from the US. And by quality we've talked about some of that, like for example the API gravity, the sulfur and some of these other properties. So that was the lookalike crude and back out, I should have said reduce. I mean those crudes are going to be coming, we're coming in from, a lot of them from Africa, North Africa, West Africa, and so on, the traditional kind of Light Suite crudes. And so in terms of Mexico, obviously an interesting situation with the energy reform could change a lot of things there. Pemex recently also announced delays or cancellations on essentially all of their projects though, because of budget cuts due to low crude oil prices. So I guess particularly in that context, with a kind of chronic deficit of gasoline and also diesel, and it's logical that they would want to take additional Light Suite crude under a swap arrangement, taking it initially into existing refineries. And again, 100,000 barrels a day, I would think may well be the first tranche. I think that may grow over time, certainly the numbers we came up with looking ahead. It was a long way, but 2030 were a lot higher than that. The potential that U.S. crude, if there's a lot of it, could be exported to Mexico. So I think overall the effect would be to defer investments or reduce the need, especially for upgrading investments in Mexico, whether that would have the effect of eliminating or adding the need for a new refinery is open to question. And I think as Lynn recently pointed to, nobody would be investing in any major new capacity, whether it's existing refinery revamping or whether it's a brand new refinery, unless those crude supplies are guaranteed very long term. I mean, you need something like a 20 year contract for that. So again, that brings you back to U.S. production and the ability to supply that crude oil over a very long time. You didn't ask me about my answer anyway. There are a lot of non-economic reasons to build a refinery, technology transfer, it creates jobs, et cetera. But it has almost always been the case in the petroleum industry that if you have restricted funds, you get a much better return on the upstream by producing crude. You're pulling something out of the ground and it's pick your number, between $50 and $100 a barrel. And as Joanne showed, if you put that same money into refinery, your increment is $5 a barrel. So in a constrained capital world has always made sense to invest in the upstream, particularly when you look at, Mexico has a very, very friendly neighbor that has a lot of products. It's called the United States. It could fill their product needs quite nicely. So again, I hate to put logic onto a political system that sometimes doesn't work that way. But even in a high oil price case, it would make more sense for them to invest in the upstream than in the downstream. John Keneese, Heart Energy Stratus Advisors. First a comment and then a question. The comment is, I think this should be a mandatory one-on-one seminar for about 535 people a mile and a half east of here. That's how they make it. I know. The question is this. Can't really talk about crude and crude quality without talking about refined products. Lynn, you just started down that path looking at the increased production U.S. and the slate going into the refining. Do you, the comment is, or a question is about declining product demand domestically here, especially gasoline. Is that gonna be a driver for refiners to export and find markets more and more? I think it already is. The last time I looked, about 15% of Gulf Coast capacity to produce gasoline is going into the export market. So that's certainly, in economics terms, becoming the price-setting mechanism. Right, in the Gulf Coast, so the driving force is there, but then you get into economics. Where can we really compete in the world with gasoline? Well, of course we can compete in Latin America. That's our home market. We have easy shipping. We're very close to it. We can probably compete in, for the same reasons, in Western Africa to provide gasoline. But at the end of the day, if you go out and you get a lot of excess capacity in the United States, the only place you can absorb that is in Asia. And that's where it's gonna be very tough for us to compete with Indian refineries, Middle East refineries. So it would take a different set of economics than we see today to hope that Asia can become a great sinkhole for American production of gasoline if it comes to that point where we can't, where we saturated Latin America and our natural markets in Western Africa, I think. I was just gonna say, and that's why we've been very happy to see some increases in gasoline demand this year. Certainly, yes, if you look at the longer-term trend, CAFE standards and so on, potentially bringing down US gasoline demand, and you ally that to a lightning in the US crude slade. One thing to think about on the exports of products is that they are really in a sense the small difference between two large numbers, the two large numbers being domestic demand and refinery production. And so relatively limited shifts in the total numbers can lead to more significant shifts in the exports. And certainly what we tend to see is a shifting in that export pattern as US crude slades become lighter, especially with no crude exports allowed or limited. And you end up with more natural gas liquids. There's been big increases in the very light streams being exported, more gasoline, and then frankly less distillate because you've just got less distillate available in the crude pool. And this is where the geopolitical implications start getting involved too, right? So if the United States, because of our competitive advantage on natural gas and crude oil, allows Latin American countries to defer investments, we become the supplier for Latin America that offsets certain things. I have the same concerns about China. If the Chinese were concerned about the US cutting off crude oil supplies from the Persian Gulf, I'm not sure how dependent they're gonna be on US light oil or US product. The same thing if we undermine European refineries because of the competitive economics that's a source of light crude purchasing, right? But it's also a NATO ally. And so we're gonna have to work through these things, Canada, Mexico, India, China, Russia, and Europe. And it gets a little more complicated, but actually that's one of the projects Sarah's taking on in this coming year. So I know we'll be in good shape going forward. Other questions? So, right here. Thanks. I'm Varun Sivaram, I'm a fellow at the Council on Foreign Relations. Lynn, you just said in an effort to offload some of the risk from doing these hundred, 500 million dollar investments to process more light, sweet oil, refineries may enter into long-term contracts with producers to lock in a discount. Seems to me that may erode some of the projected benefit from liberalizing exports because kind of the point of liberalizing exports is to close the divergence between domestic and international crude prices. How do you see that playing out in terms of stimulating continued US production? And is it a reason to liberalize exports sooner rather than later? Well, it's a matter of degrees, of course. If a, I'll pick a number. If a refinerial project requires a $7 discount on crude, a $7 discount off a $100 price, still leaves a producer a whole lot of incentive to continue his production. A $7 discount off of a $30 price might be something that would cause him to not produce the crude in the first place. So it's a matter where you think overall prices are gonna be in the future. Certainly anytime you remove regulatory uncertainty, you have a more efficient world in terms of investments. I will leave it to the politicians and those who talk about geopolitics on the potential of that happening. Certainly if you remove, as long as you have uncertainty, your investments will be very lumpy, if you will. You'll have to go through a crisis. By crisis, I mean a very large discount on crude so that someone will make an investment which will bring it down. Then you'll have to wait for your next crisis to bring it down rather than having a certain path of investment that you might have if you remove any kind of regulatory uncertainty. I'm going to make a comment here too. And I think it's an example of the kinds of dynamics that come into play and that are in play right now as we're dealing with this. And it's what makes it very difficult to model and project. You can get general ideas of things, but you're not gonna capture all the dynamics that are going on, including the international dynamics that are going on. And indeed those kinds of dynamics, and that's why I use that old example in my slide when people were worried about constraints that people were bumping into, that says there's usually a margin of error here where there's a little more cushion in time and whatnot as these dynamics come into play than people are expecting. And given the circumstances right now with the lower prices and the lower production going on, we have a period of years here to take care of this debate. It's an important debate and it has a lot of aspects to it. It's not a simple no-brainer issue in terms of the parties that are affected and indeed this dynamic you're talking about is one of the many that help in the process as it goes forward. Okay, we wanna move on to the second panel. So let me, while we've got Lynn here, I wanna ask one question. So Lynn's group, your office is also responsible for EIA's much-anticipated export study without putting you totally on the spot, but while you're kind of cuffed to the chair. Can you give us some insights on that study effort, kind of what we could look for, how you're evaluating, how you're looking at this? Well, I'm gonna back up a minute and say by, I think the middle of this summer we'll have completed about a year-long project to look at a variety of aspects of the question of crude oil exports. Last May and this coming May, we issue and will issue our forecast of US crude production by type, which hopefully from this presentation you realize that the type of crude that's coming out and how much is very important to your analysis. So that's coming out. Last September after BIS issued their ruling that allowed, a private ruling that allowed something called Processed Condensate to be exported, we started receiving a number of phone calls where people asking, that's great, what does condensate? So we had a condensate workshop to cover that. In October of last year, we issued two pricing reports, again, which you can find on our website by the way, one on the relationship between US gasoline prices and crude prices, and the report pretty well showed very directly that historically, US gasoline prices have been much more related to international crude prices than to domestic because of course one of the big issues in the export debate is everyone agrees pretty much that if you allow crude exports, domestic US prices will go up because they're selling it at a discount because they're trapped, but will that cause gasoline prices to go up? We also issued a report then on the relationship between gasoline prices and different markets. So that's kind of where we are at the moment. Next week sometime, we will issue a report on the technical options for refiners to process more like crude. What things they could do, Joanne covered some of this, what they can do to process more crude. By the, I'm gonna say April May timeframe, we'll take the next step and issue a study that says what they are likely to do in certain scenarios to accommodate more light tight oil in the United States. And then finally, I think our more broad study on all of the implications of allowing crude exports, I'm gonna target for mid-summer. The second panel, if we wanna keep kind of continuity here, if you wanna grab a cup of coffee, do a restroom break as we change out the panel as you're welcome to do that. But please join me in thanking these panelists. Thank you. Thank you.