So, thanks very much for coming. You braved both the weather and the Occupy DC crowd, so you get kudos for that and we have extra coffee in the back, so that's our reward for you all. I'm really excited about this session we've had today. We've been talking about doing something on tide oil and shales for quite a while. We did a lot on the gas shales over the last two and a half years. The story on oil I think is actually a phenomenal one that probably hasn't gotten the play that it should have gotten. As we go forward into 2012, in think tank land here, since we're responsible for dealing with nonpartisan or bipartisan bases, we deal with political people of all stripes. As we get into the election season, a lot of people would argue we're already there, that we do a lot in the way of fact checking, but we also try to do some things in the way of public education. We find this story to be one of the most compelling. It's not without challenges. It's important that we get this right, but we have to figure out how to frame it. As we go forward into next year, we've decided we're going to do a series on building blocks for solutions. The oil story I think is one of the most compelling and that's probably where we're going to start. I've got to tell you that this series really came together.  Back in September, we started discussing the Bakken, the Neobrara, Eagleford, Bakken-like structures, how many there were in the United States, and we thought maybe there was a half a dozen. The NPC study and Jim Sorenson's here, who did the white paper on this, thought that there was a lot more than that, and as we started playing this out, we started looking at 15, 18, 20, and when you look at the four or five big fields by 2020, their cumulative production can equal what we have in the offshore. This is a big, big deal, but it's also in places that haven't seen a lot of this production before, and so you're going to hear from some of the folks from North Dakota on what the community impacts have been on some of these areas. The influx of people, the amount of truck traffic, the water concerns, the building out of infrastructure you've heard about flaring in the Bakken. Well, the gas will be taken care of over time as pipelines and infrastructure get permitted, but this happens on a universal basis. It just takes time to get it right. So the whole concept here is to try to get a dialogue going for next year. We found that in the city, the sides are too far apart and they seem to be dug in. We're trying to find some common sense pragmatic solutions for the way going forward. When we did the tidal oil session in the oil market study group, Guy Caruso put it together for us back in September. So as kind of my colleague and co-conspirator, I'm going to turn the program over to him today, but this is a great panel. We're going to talk about the Yulfur, the Bakken, and U.S. production going forward and why we don't think it's going to make us necessarily energy independent. It's huge for energy security and companies have to be smarter and safer and more environmentally benign in their practices and I think we're getting there. So let me turn it over to Guy and thank you all for coming and enjoy the program. Thanks. Thank you very much, Frank. And I like to add my welcome and appreciation of you all being here given the circumstances today and fortunately don't seem to be too many problems getting into the building. So yeah, I think if you think of the first decade of this century and look at what are some of the big energy developments that took place, you'd have to say shale gas has got the rank right up there. And so you had the people giving sort of a nickname, shale revolution, shale gale. So now I think this decade may well be the decade for tide oil or whatever you want to nickname it. So maybe we'll have a contest, Frank, to come up with what do we call this decade. But tide oil clearly, as Frank said, is one of the real profound developments for U.S. energy and potentially certainly North American energy for sure given the results of the NPC study resource estimates that Andrew Slaughter from Shells who chaired that group within the National Petroleum Council talk about resource availability, resource recoverability. Frank mentioned energy security, it's certainly going to, I think, be recognized as important there. Biggie will be infrastructure development. I think every one of the speakers this morning will talk about the impact of tide oil development on infrastructure. And having looked at all of their slides, I think challenges are mentioned in there just about everyone's. It's clearly a challenge whether it's Bakken, and we've seen it already with Marcellus on the shale gas. Danny Brown from, and Darko's going to talk about challenges and other developments that they're facing in Eagle Ford. So I think we also have seen already in Pennsylvania and New York and a number of other states that are trying to deal with this development and on the gas side, regulatory challenges. And we have Daryl Ducart from Dunn County in North Dakota who's going to really give us an underground experience of what it takes to be a regulator in this very exciting new development. The NPC study, which is now out about two months, really, I think, made a lot of this very promising, how promising this tide oil and in addition to the shale gas will be for us here in the United States and North America, and we're lucky to have Jim Sorensen from the Energy and Environment Center in Bismarck, North Dakota to speak to us about the detailed work that was done in the white paper there. So I think we really got an outstanding group of presenters who can frame this issue and get, I think, off to a real good start on this series that Frank has said that we will be undertaking here at CSIS. It's been a true technologically innovative development that has brought us to where we are now, and I think we're just really at the beginning here, starting with Bakken and as Jim and Andrew will mentioned, it's only the beginning because during the NPC study identified a large number of other plays in addition to Bakken that are very promising. I think my recollection is something like at least 18 to 20, one of which is Eagle Fort, and that's right now the one that's really moving out the fastest after Bakken, and as I mentioned, Danny Brown will talk about that. So without delaying, I just want to really wrap this up by three o'clock, we'll go in the order that you have in your program, and you have detailed biographies of all of them, so I won't go into any great detail. We'll start off with Andrew Slaughter, who's a senior upstream person in the U.S. Shell Americas in Houston, followed by Jim Sorensen from, as I mentioned, Energy and Environment Center in Bismarck, author of the white paper for the NPC. Then Ben Montalbano has done some outstanding work along with his colleague Trisha Curtis at the Energy Policy Research Center, EPRINC. He's going to go into some of these infrastructure challenges at Bakken, and then be followed by Daryl Ducardo. I said, we'll give us an on-the-ground regulator's view as a commissioner in Dunn County, North Dakota, where it's really been maybe the center. Maybe I'm overstating it, but I think Dunn County has been the center of the Bakken development, and here's some very interesting experiences from Daryl, and then we'll wrap it up with Danny Brown, who'll remind us that this is going to go far beyond Bakken with the Eagle Ford work that Anadarko has already done. They're the leader in that development, and they've experienced in a number of other unconventional gas and oil plays. So we're very fortunate to have Danny with us today. He's general manager of the Anadarko project. And then finally, when you think about where do we go from here, as we saw in the shale gas, there's great potential that this may well go beyond North America, and EIA recently published a report on the potential shale gas reserves beyond North America, and I think that's another area where there'll be some fruitful work to be done by researchers in and out of inside government as well as others. So without further ado, I'm very pleased to have my friend and colleague, Andrew Slaughter, to be here to present the work that he cheered at the National Petroleum Council Center. Thank you, Andrew. Thank you, Guy. Thank you, Frank, and thanks to everybody at CSIS for putting this session together. I think it's going to be very interesting, and I'm certainly hoping to learn a lot this afternoon. I think the reason I am leading off this panel is we've just finished, as Guy mentioned, we've just finished about two years of work on the National Petroleum Council, where we looked at the whole framework of hydrocarbon potential, supply potential, and development strategies for hydrocarbons in North America. And so I think it's important before we do the deep dive into tight oil to try and consider where does it fit into this bigger picture of hydrocarbons in North America. Just to remind you that the National Petroleum Council study was North America, it was a focus on US and Canada, and it really was a focus on natural gas and oil. It didn't really need to consider other energy types, other things in the energy mix. It was an opportunity for us, the industry, government, and academics to consider where we are in the hydrocarbon supply picture and what it could look like going forward. We looked at the key roles of technology in unlocking new resources and driving supply potential going forward. We looked at the potential supply mix. We looked at ranges of possible supply, depending on the conditions of development that stem from regulatory policy, fiscal policy, access, technology development, and economic conditions. And we looked at the impact on the demand side, particularly for natural gas. And we looked at that because it's very important in terms of assessing whether natural gas can change the trajectory of greenhouse gas emissions and other emissions. We didn't look so much on the demand side for oil, because oil demand depends so much on transportation. And there's a parallel study with the National Petroleum Council, which is looking at transportation fuels, the different options, and the future way that will play out. And so all this comes together in terms of what are the impacts for the big national imperatives of economic development and economic prosperity, environmental management, environmental integrity, and, of course, energy security. And in many ways, this is at the heart of hydrocarbon development. There's a lot of potential there. But we have to do it in a way which is responsible and beneficial and visibly beneficial to both the communities where we operate and the national benefit in a wider sense. So I'm going to jump straight to oil, because this is not a natural gas panel. As we looked at natural gas and oil over the last two years, the shale gas revolution, however you want to call it, was already a good way along. So most of our participants and most of our stakeholders were reasonably well aware that something dramatic had changed in the natural gas supply business. They weren't so aware that oil also had a huge potential and oil resources were actually abundant. The mental models that people tend to have is that the US is an oil consumer and it's an oil importer. We don't think of ourselves necessarily as a huge oil producer. But the fact is, we are a world-class producing basins here and now in North America. If you think of the Gulf of Mexico, the deep water, if you think of the Alberta oil sands, if you think of the Alaska North slope, these are world-scale producing basins.  And this gives a great platform for moving forward if it's done in a responsible way. And in fact, if you look at the top oil producers around the world, if you add the US and Canada together, that's number one. And so it's right up there with Russia and Saudi Arabia, who we traditionally think of as the oil-supplied giants of the world. But North America is in that category. And it's not only volumetrically that we think about that. It's also this is the arena where key global technologies have been developed. Arctic development in the Alaska North slope, first done here. Deep water development, first done here in the Gulf of Mexico. Unconventional gas development with shale gas and tight gas, first done here in North America. So this is a tremendous platform for not only developing the industry and the supply here, but also rolling this out to other opportunities around the world. And so bringing American technology and value added to many basins around the world. And it's a great platform to take supply in this region to the next level over the next 20 to 25 years. So on the oil supply, this is how we segmented our analysis for the NPC study. We looked at these big buckets of types of supply in the US and Canada. And today we're going to focus really in on the unconventional, and particularly on the tide oil. But the conventional story, I have to say, is very compelling as well if you look at potential in the Arctic and new potential offshore, particularly if you go to offshore regions which haven't yet been developed. There's very considerable potential there. This next slide categorizes the ranges of supply potential for these various segments that I've just shown you. The left-hand bar on this chart has 2010 production from the US and Canada, just shy of 10 million barrels a day in total. And now the mental model, as I said, is that we're a consuming nation. Oil supply is kind of declining long-term. People remember Hubbard's Peak with US oil production peaking in the 70s. And that's where we think we are. Well, we could. These two bars on the right-hand side are ranges of where we could be in 25 years' time. So this middle bar is limited potential if we decide not to develop a lot of this resource, if we decide to restrict new exploration in the Arctic, if we decide to not to go new places in the offshore, if we decide to put in or maintain restrictive leasing practices in some areas, we could continue that gentle decline and be a major oil importer for, again, decades to come. However, the right-hand side is the potential if things go well in all these supply segments. Pretty much all of them that you see have the potential to grow. And this applies to the existing producing areas like the Gulf of Mexico and the Alberta oil sands, as well as emerging and new supply segments like tight oil and like new offshore areas and new exploration in the Arctic. I've highlighted the unconventional pieces of this supply picture here. And you can see that in both scenarios, both limited development and high potential development, the unconventional piece of that is gaining share, is likely to be a more important part of the future supply in any kind of world. And tight oil is right in that mix. I think tight oil is that kind of dark, maroonish, brown wedge in the middle of the bar there. Oil sands is the page one. So the differences between these supply outlooks really depend on choices, choices of policy in terms of leasing policy, access policy and fiscal policy, as well as the pace and success of technology development in improving recovery and economic recovery for these resources. If we home in on the pieces of the unconventional supply, and again, this is all material that was in the National Petroleum Council study. So here for each of these major components of unconventional oil, we see what it was in 2010 in the light blue, and then the range of potential outcomes, 25 years down the road in 2035. And by the way, we picked 2035 because it's a date specified in our study request, but much of this growth potential can and probably should continue beyond 2035. And to towards the mid decade. So you can see the oil sands, likely to grow in any type of case they've got a reasonably amenable access and development policy in Alberta, but between three to six million barrels a day is what we're looking at for the oil sands. The other big one is tight oil and Jim will go into this in more detail, but as we went through the study, our tight oil estimates, as we started to find out more, our tight oil estimates were actually ratcheted up going forward as there was more development literally happening day by day as we were doing the study and we were finding out more positive results and more positive stories. So tight oil, if there's really draconian restrictions on the deployment of technology and development, yes, there's a world in which it might not grow very much, but the hydrocarbons are there. And so if we hold it back now, then surely it will come later on, but if we actually do go for it and have responsible development in those tight oil areas, then you're looking at something like in the three million barrels a day range by 2035 and that actually, my personal feeling is that could be earlier than 2035 that we get to that kind of number given the pace of development that we're seeing in places like the back and increasingly in other arenas. And here's another map which shows, gives you an idea. This map covers both shale gas and oil from shale and so it gives you an idea of the tremendous geographical diversity across the continent of these resources. This has implications for clearly robustness and security of supply. The more places you've got, the better off you are, but it also has some challenges around particularly infrastructure. If you want to develop a play faster than the infrastructure can keep pace and that to some extent has been the early experiences in places like the back and where a lot of oil is railed out and that's rather more costly than moving by pipeline. So what do we mean by tight oil? You know, it was quite interesting the process of how we came up with the tight oil name. It's an analogous to tight gas. It's molecules produced from very low porosity, low permeability rock, but you see other terminology out there. You see shale oil, you see shale liquids, you see oil from shale. Many of the companies talk about LTO, light tight oil. These molecules, it's typically light crude because the oil molecules are bigger than gas molecules so it has to be quite light to actually move through the system and be produced. It's unlikely you'll get much heavy oil, much below low 20s API in this space. So it comes from tight, poor space and that's the main reason we picked that term and the other driver for that was to differentiate it from oil shale which people had been talking about for several years and which is the kerogen based oil which you find in Colorado which is a bit further down, a bit further away in terms of development. And the reason we've been able to access this resource in recent years is the application of similar technology to that which we developed for shale gas. Horizontal drilling, hydraulic factoring, pad drilling, improving the economics, improving the contact with the reservoir and the hydrocarbons and getting flows from multiple places in the source rock. So this really makes it both accessible and economic and quite honestly similar to shale gas, it seems to be that the more things you try, the more things work out quite well and so production is increasing as well as ultimate potential increasing on a fairly consistent basis. It started in the back end and I'm guessing when we began the study a couple of years ago, we really only had the back end in our sites but we'll hear this afternoon that there are other places where tide oil, however you want to call it, is becoming important. This is the map, Jim will probably show the same map, it's his map, it shows the plays we identified within the NPC study where you could potentially have economically recoverable tide oil resources. Now the difference between the blue dots and the red dots are the blue dots, there is already production there but probably at different intervals, probably more conventional oil at higher intervals in the play and the tide oil will be deeper but it does mean you have some supply chain in place, it does mean you have some infrastructure in place so those areas will probably relatively easier to develop. The red dots are the ones that require more new development from scratch but you can see like the map we just saw very geographically diverse and many more opportunities identified than we actually have gone after yet in terms of development. So like shale gas five years ago, we're in the early stages of this and we try and use our crystal ball and see how much it can develop but really you could be, there's a big window of uncertainty in terms of the potential additional upside if you look at the numbers associated with these plays just from what we know today. Some challenges and enablers.  It does the similar types of discussion do apply to tide oil development as are applied to shale gas development and some of the similar issues are there. So I think it's very encouraging that in these forums and in these reports and in these studies I see the industry really stepping out there and being committed to transparency, best practices, recycling water, minimizing impacts, minimizing environmental risk going way beyond what you see reported in the public domain and I think that's a very, very healthy thing and we actually need to do that in terms of maintaining public confidence and getting the license to operate and building this resource out. Infrastructure, I've got out there. Yeah, you'll hear a little bit more about that this afternoon but typically in any new development and whether it's large-scale infrastructure to move gas or oil to market or local infrastructure in water management or gathering gas which might go to flares in the early stages, you need time to build the scale in any play to get the infrastructure in place and so it's gonna be higher cost, it's gonna be more disruptive probably in the early stages of a place development and we're seeing that particularly in the back and in some of these other areas. Enablers, I expect continued improvement in technology, I expect recovery factors to improve. I expect more areas to be accessed. I think we're at the beginning of this technology story. It won't be, don't necessarily look for breakthroughs in technology but continuous improvement and better management of the hydrocarbon systems and more recovery, I think we're likely to see that over the next 10, 15, 20 years or so. And then of course the regulatory system, the access systems. If we prove this that we can do this right and well and effectively, cost effectively bringing economic benefits, I think we'll get the license to operate. I think the regulatory capacity will grow which we need it to do. We need that to be in step with industry and I think the benign conditions for development could happen. So that's a very quick run through, very high level, happy to take questions on both this part of the NPC study or any other part at the end. And I'll hand it over to my good colleague Jim who did the real work on tight oil that you see in detail in the study. Thank you Andrew for setting the stage by going through the NPC study. And I wanna start by thanking CSIS for inviting me to participate in this panel discussion. Really looking forward to really enjoying putting this together. As you mentioned, I'm gonna be talking about some of the work that I did as part of the NPC study to look at sort of quantify the title of resources that are out there in North America. That's what I'm gonna be talking about today. And I'm gonna start by giving a little bit of background. This is the Occupy North Dakota movement. And as you can see, they've been there for quite a while and they had a tendency to snarl up traffic as the Occupy movements tend to do. But in the last few years, we've seen some real true traffic jams that have occurred in some of the small towns. And so I'm gonna talk about are these title resources and this is the ultimate goal here is this kind of economic activity in some of these areas. So as Andrew kind of went through a definition of tight oil, I'm gonna cover a little bit of ground here but when people ask me, so what is tight oil? Well, what we're talking about are reservoir rocks that have extremely low permeability. And for those who may not have a background in the technical side of this, by low permeability we mean the ability of a fluid to flow through the rock system. And these are very low permeability or tight reservoirs and that impedes the ability of the oil to flow freely through the rock to the wellbore. The tight oil resources are typically found in rock formations that are associated with what we call organically rich shales. These are shales of extremely high organic content, carriage and rich, that ultimately got sort of cooked if you will and produced a lot of oil. The oil is expelled. Filling up those, even though the formations are tight they do have some porosity and that's been filled with oil and in some cases migrated to other formations. In particular some, while many of the oil plays that you'll hear about, the oil formations, if you will, people will talk about them as shale oils or oil shales. Actually a lot of the resources are produced from low permeability silt stones, sand stones, carbonate rocks such as limestones. So it's not always a shale that results in a tight oil resource but we can get some other rock types too but they're all characterized by extremely low permeability, that tight aspect. And it's that tight aspect that for decades made them uneconomic to produce. The resources were known about in most cases but they just weren't able to produce those until recent advancements in technology came along that allowed access to those resources and in particular we're looking at horizontal drilling and completion technologies and what this enabled the producer to do was to, you got your vertical well, you get down, you hit your formation, you turn, you go horizontally into it and that allows the well board to actually access more of the formation which facilitates producing more oil. So these, the laterals in the Bakken range from 5,000 to 10,000 feet. All the different well plays, tight well plays will have similar size, similar length lateral, some as low as maybe 2,000 feet, going up to 10, sometimes even 15,000 foot laterals. The other part of the change in technology that enabled these resources to be accessed was hydraulic fracturing. And of course that's been a big topic in the news lately and by fracking we're talking about a mixture of fluids and propents. For those who don't know, propents are very small pieces of whether there was sand or in some cases ceramic beads that are put down, pumped down with the frack fluid and to kind of give a little primer here on hydraulic fracturing, it's essentially a mixture of water, chemicals which are typically polymers and propents that are pumped at high pressure into the reservoir rock formation which forces those fractures to open along the well bore. Fracking will typically, at least in North Dakota in the case of the Bakken, will require anywhere from one to five million gallons of fresh water per frack job per well. A percentage of that frack water will return to the surface in a controlled manner through the case in where it's either recovered where it's recovered and either recycled or properly disposed of. The propents, those small grains of sand or ceramic beads, they actually become stuck in the fractures that are created by the fracking operation and therefore they prop open the formation which in turn increases the overall permeability of the formation and the vicinity of the well bore and allows that oil to flow more freely into the well bore making it an economically viable well. So kind of a lot of people talking about the Bakken here, it's kind of geographically oriented to what we're talking about. It's sort of in the central part of North America in the Williston Basin which straddles the Canadian US border. It's a very deep rock unit in the Williston Basin. It's the average depth in North Dakota is around 10,000 feet. When we get to the flanks of the basin, it gets as shallow as 5,000 feet. One of the important things with respect to the Bakken is that it does not outcrop anywhere. So it was discovered in the 1950s during drilling activities in North Dakota. And when I say discovered, that means not only was the rock formation itself discovered, but the oil resources that are associated with it were also discovered in the 1950s. So this vast resource of oil has been known about for over 50 years. But it's really only been in the last few years in the 2000s that prolific and sustained production has occurred as a result of the improvements in those technologies that I just mentioned. And currently oil in the Bakken is produced in North Dakota, Montana, Saskatchewan and Manitoba with North Dakota being sort of at this point the largest producer of the four in the Bakken. And this map is from the EIA, it's from I believe 2010. And really the dots, each green dot represents an oil well and that has grown almost exponentially since then. I mean, it's really continues to be an active drilling opportunity for a lot of companies and production continues and is gonna be continuing for a long time to come. This is the same map that Andrew had, so I don't wanna dwell on it too much, except to say I think the key point here is the geographic distribution of these different kinds of formations that are known to hold tight oil resources. I mean, they really cover from the West Coast to the East Coast, from way up in Northern Canada, Northern British Columbia on down to Mexico, we were able to find rock formations that contain tight oil resources. Now, for the NPC study, probably the main thing that I was asked to do was answer the question of, so what are the technically recoverable resources, the tight oil resources in North America? And to do that, let me just step back before I kinda show some of the results here. What I was working with was looking at peer reviewed journals in Society of Petroleum Engineering, American Association of Petroleum Geologists, things of that nature, they're peer reviewed journals that may have discussed technically recoverable resources for tight oil formations. I also looked at some of the USGS studies that have been done looking at some of the tight oil resources and then looked at a lot of the oil and gas regulatory agencies that have these formations in their jurisdiction and tried to get a handle on just how much oil is being produced from these different tight oil resources that you saw on the continental map there. And what we came up with were technically recoverable resource values for approximately a dozen tight oil plays in North America with the Bakken being by far the biggest at about four million barrels, as he estimated, technically recoverable resource, the Eagleford shale on around 900 million barrels, large resources in California and the Monterey shale, also the Cardium in Alberta. I mean, the take home message here there's quite a bit of oil that we found. We found anywhere, it's depending on the range as Andrew kind of said, we looked at different constraints on production, but you're talking anywhere from six to 10 billion barrels of technically recoverable resources just from these plays. And I emphasize that phrase just from these particular formations because as that previous map shows, there's actually quite a few other formations that we know have tidal resources and we know currently have production. That's something Andrew alluded to. When we started this in 2010, this is kind of the primary list, but as we looked at it more and more we found, I did come across sort of anecdotal evidence of production from the other resources, but the actual data to back that up and develop sort of an estimate of total technically recoverable oil just wasn't there, especially in the Eastern states. And it really kind of boils down to how a lot of the regulatory agencies handle their data and how they manage their data. North Dakota in particular is really good about sort of parsing out what formation any given barrel of oil is coming from. So that made it real easy. And this is, so I think the take home message here is really this is just a portion of the tight oil resource that we know to be readily available in North America. The other thing that we wanted to look at in the NPC study was to sort of project out and I also want to mention that the numbers I show here are based on the work really from 2010. And as Andrew mentioned, I think the numbers are actually, the true numbers should actually be higher than what I'm presenting. But what we saw was that by 2012 in the Williston Basin and by that we mean Montana, North Dakota, Saskatchewan and Manitoba, tidal oil production is going to be over 500,000 barrels per day. In Eagleford it's going to be over 100,000 barrels a day. So just in those two tidal oil formations alone we've got 600,000 barrels a day being produced. And when you throw in the production from the Nile Brara and many of the other resources that I showed on the past map and then the previous map it's probably going to be actually approaching anywhere from 700,000 to perhaps a million barrels a day already within just the next couple of years. When we look out at 2020, we're looking at tidal oil production of over 2 million barrels a day. And again, I think that's actually very conservative and that's based on just those tidal resources that I was able to get those technically recoverable reserves. I think when you bring in the other resources that just don't have the data yet, I think you are going to reach that number that Andrew was talking about, three to three and a half million barrels a day coming from tidal or resources in North America. And then I think what I find to be really interesting is that this resource is going to be sustainable for many decades to come. And it's a function not only of the number of formations in North America that contain tidal resources and our ability to get at them, but it also comes into something that we refer to that we've talked about is recovery factor. And that gets to the question sort of so how much oil can we really get out of these different formations? This is a bubble chart that shows where we sort of took what we called from the literature just focus on the Bakken. These are total oil in place reserve estimates. And for those who aren't familiar with the oil and gas sort of the technical terminology, there's a big difference between oil in place reserves and technically recoverable reserves. As I mentioned, back in the 50s and 60s, the North Dakota Industrial Commission knew that there was a lot of oil in the Bakken formation. Those are oil in place reserves, but they weren't, they didn't have the technology to go produce them economically. So they're technically recoverable reserves or very, very small. Now, as time has gone on, different workers have gone in. They've looked at that the Bakken, they've more wells are drilled in the Wilson Basin which gives the workers better data, more information on just how much oil is in the Bakken, how widespread is the Bakken, how widespread is the oil in the Bakken. And you had all the way up to Lee Price in the USGS in the late 90s, he estimated anywhere from 270 billion barrels to over 500 billion barrels of oil just in the Bakken alone. The other workers have got estimates around 300 billion barrels, maybe 32 billion barrels old, but the key point is, these are huge, huge numbers just for the Bakken. And then you look at that orange dot there and that is the technically recoverable reserve estimate from the USGS. And you see it's much smaller, it's 3.65 billion barrels. Now the North Dakota Geological Survey, their estimates say about four billion, but that's the order of magnitude you look at. You're looking at order of magnitude difference between the technically recoverable and the oil in place. And so right now the recovery factor for the Bakken is only about one to two percent. And if we look at that magnitude research, so even with one or two percent, we've got four billion barrels. If we can just improve that by one or two percent, you're doubling the technically recoverable resource, you're again adding billions of barrels to the resource estimates for the United States. And so the information, the projections that we put together for the NPC really didn't look at EOR because nobody's really done EOR. Nobody's really done enhanced oil recovery on these tight oil resources. Enhanced oil recovery techniques are certainly going to have to be different for tight oil than what they are for conventional oil. But if anything, history has taught us that technologies do improve and I have confidence they will improve and enhanced oil recovery techniques will be applied to things like the Bakken. And in particular I think CO2 could possibly be a game changer in a tight oil formation such as the Bakken. So I think there's a lot of ways that we can improve that recovery factor and bump that resource up. And that's what really allows us to say, yeah, I think this is gonna be a viable source and a sustainable source of oil for many decades to come. Now with any of these kinds of resources, of course there are challenges. I've kind of broken up this first slide here in environmental challenges. As I mentioned, these fracking operations can require millions of gallons of water. That can have a variety of stresses put to the local system. The frack fluids may contain chemicals that have become a subject of public concern. We've certainly heard a lot about that. And then flaring has also been a source of criticism in the last year or so. There's a lot of flaring that's been associated with the Bakken development. I don't like to put challenge slides up without offering some kind of solutions. And some of the things that we've seen in North Dakota are the development application of frack fluid recycling. That can be something that can kind of help alleviate some of those water related issues. The reformulation of frack fluids, I know of at least one service company that's working very hard, spending a lot of money trying to figure out how they can come up with more environmentally friendly frack fluid formulations. And then utilization of the flare gas. Again, I know that industry is working very hard to come up with two ways to utilize or improve the infrastructure to bring that flaring down a little bit. Other challenges, I think I sort of put in the category of public perception issues. Anytime you've got the construction of thousands of well pads and truck traffic that goes along with the drilling and the fracking operations, you're gonna get wear and tear on the roads and highways. You're gonna get traffic jams and communities that previously have never seen a traffic jam, communities that maybe only have a single intersection that even has a stop sign.  And these are all things that come up at public forums as we go out and talk about these things. Again, some of the solutions, I know that industry is working very hard to apply technologies that allow them to drill multiple wells from a single well pad, which in turn reduces the overall footprint of those operations. The construction of truck routes, the state is looking at constructing truck routes around some of the more impacted communities. And I know the industry is working to develop and apply a variety of dust control measures to take care of some of those issues. Finally, I wanna touch on some of the economic impacts that we've seen in North Dakota and the information we're presenting in the next two slides comes directly from Mr. Lynn Helms, who's the director of the North Dakota Department of Mineral Resources, which is the agency responsible for regulating oil and gas in North Dakota. And according to a study that he did, he says by 2012, there's gonna be, the Bakken activity is gonna equate to anywhere from 12,000 to nearly 20,000 jobs. And if we look at a 10 to 20 year lifespan for the Bakken play, which I think is a very reasonable estimate, that's gonna equate anywhere from 3,000 to 3,500 long term jobs. Those are good long term jobs. Those are sort of white collar, gold collar, high paying types of jobs, long term in North Dakota. When you talk about a state that's population is around 650,000, that's a big chunk of our employment sector. Lynn also looked at what a single well could do over its lifetime. And that single well is projected to produce more than 500,000 barrels of oil, generate over $20 million in net profit, pay approximately $4.2 million in taxes, pay royalties of nearly $7 million to mineral owners, pay salaries and wages of over $1.5 million and operating expenses of nearly $2 million. So a tremendous amount of impact just from a single well. And when you consider that North Dakota is currently on pace to be drilling about 2,000 wells a year, we're talking about a huge economic impact for that state. And as Andrew mentioned, a lot of this information is presented in the NPC report and that's there. And with that, I thank you for your attention and we'll certainly be willing to take any questions when we get into the panel discussion. Thank you. Thank you, Ben Montobano from Eprink. Good afternoon and thank you all for coming out today. As Guy mentioned, a colleague of mine, Trisha Curtis, has been doing most of the, has been leading our research on the Bakken and the shale play. So please send any complaints to her. All right, you've already seen this several times, but as a quick look at the U.S. shale oil plays. Couple things worth noting are the area shaded in yellow and other colors are federal and state lands. And essentially all the shale development, shale oil and oil developments in the U.S. are happening on private lands where access is more readily available. And it's also worth noting that how some of these other plays such as Eagle Forward and Utica Transpire will have connotations for where Bakken crude ends up. I want to talk a bit about Bakken production reserve estimates, transportation, infrastructure issues, and flaring. So just for example, if Eagle Forward comes on and is producing two, three, 400,000 barrels in a few years, there might be less of a market for Bakken crude down in the Gulf. This purple line shows Wilson Basin production and the blue area chart shows Bakken, well it shows North Dakota production, most of that being Bakken. And this goes through September of this year and you can see they just crossed 450,000 barrels per day. And that accounts for about 8% of U.S. production. There's still some legacy production in the Wilson Basin from Montana and other parts of North Dakota. There's a history of reserve estimates, technically recoverable for the most part. 2008 USGS put out an estimate of 4.3 billion barrels. The North Dakota Industrial Commission added 1.9 to that because they realized that the three forks, which is the layer that sits below the three Bakken layers, is serving as a source rock and essentially providing crude into the middle Bakken, which is generally the layer being drilled into and fracked. State officials with this rise in production put their estimate at about 11 billion barrels. Harold Ham from Continental Resources, who's a big player up there throughout 20 billion. And the USGS was hesitant to do another update because they said we just did one in 2008. Why do you guys need another one? But they saw the way production had exploded and acknowledged that another one was needed. So I'm guessing you'll see 10 billion barrels, but it's hard to say until that comes out, which I think is next year. These are two forecasts from the North Dakota Petroleum Authority. They both, the base case or case two plateaus, about a million barrels later this decade and 1.2 in a high base case, in a high case. And that depends on rig counts, drilling times, availability of completions, prices. But if you look at the plans for pipeline and other takeaway capacity, they support those production figures. One problem facing producers has been lack of transportation access and therefore a lower price received for their crude. So many of you are probably aware of the spread between Brent, which has historically been the European price for crude, but really lately has become the world price for crude and WTI, which has been basically the price of crude in the Midwest around Cushing, Oklahoma. And North Dakota Light Suite, which is actually a superior quality crude to WTI. It's lighter than API gravity in the 40s. Has been selling at a $10 discount to WTI, which itself has been selling at anywhere, 20 to $30 discount to Brent. So that's certainly put hurt on producers and revenues in the state. And that's largely because North Dakota is not located near any major refining centers or major crude transit points. And it hasn't had the infrastructure in place yet to get it to those. This chart shows the North American supply of crude by source, so the blue part of the pie is U.S. supply. Green shows Canadian imports, so blue and green are essentially North American supply crudes, and red shows non-Canadian foreign imports, which are mostly waterborne crudes. Now historically, most U.S. production had come from West Texas, and then we'd receive a lot of imports through the Gulf, and the infrastructure has sort of been designed to take that crude up to Cushing, so South to North. Canada is now our largest supplier of crude. We get about two to two and a half million barrels per day from them, add in about another half a million barrels from the Williston Basin. We got almost three million barrels of crude that really wasn't foreseen five or 10 years ago, and the infrastructure struggled to keep up. So we've had a bottleneck in the Cushing area, and it's not all bad. It's not such a bad thing that a huge slice of the country is being supplied by North American crude, but it has thrown prices into whack a little bit. And it's worth noting that the East Coast, Pad 1, is being served almost entirely by waterborne imports, and it's actually a natural market for Bakken crude. It's not just waterborne imports, where they get over half their imports are light, sweet crews from West Africa, and Pad 1 does not have the heavy refining capability that other refining centers in the country, such as Pad 2 in the Midwest and the Gulf Coast have, so they don't have the ability to switch their crude based on a light heavy spread. They basically have to take light crude, and because that's all waterborne, they're stuck paying Brent prices, and they're stuck paying Brent prices. They're facing large volumes of gasoline imports from Europe, where dieselization is left, refiner's there with lots of extra gasoline, so those are being dumped in the Atlantic, and there are companies that would like to build a pipeline to Pad 2, to Albany, or Buffalo, I'm sorry, to Pad 1 to bring Bakken crude from North Dakota to New York. I just, they're concerned that there might not be any refiner's left by the time that pipeline gets built, so. This is the current look at export shipments from North Dakota, so shipments of crude outside of the state. Most crude being produced right now is almost entirely being produced on site and stored in tanks on site, and then being trucked away, so that's creating lots of truck traffic, and then from there, you got about 350,000 barrels going into two pipelines, mostly into two pipelines that I'll show you in a second. Tesoro has a 58,000 barrel per day refiner that's almost being solely filled with Bakken crude. Another 100,000 or so being sent by rail, mostly to St. James in Louisiana, where companies can get light Louisiana sweet prices for their crude, which actually sell a slight premium to Brent, and even with transportation costs of probably $10 or $15 per barrel down there with a $30, $40 discount to Brent more than makes itself worthwhile, and another 25,000 barrels or so are being trucked, mostly north to Canada, to be put in pipelines to be re-imported into the United States. And the other interesting rail story is that there have recently been a few shipments of Bakken crude by rail to Albany, New York, because those refineries again are paying Brent prices, and there it's a little bit more expensive, $15, $20, but where the spread has been and even the discounted WTI, it's made it worthwhile. So the two major pipelines taking crude out of North Dakota, the Enbridge line in purple at the top, so it looks like maroon from here, and that takes it to Clearbrook, Minnesota, where it's sort of distributed mostly to pad two refineries, and then the Butte line in the southwest corner there, which is taking it out to two pad four refineries in the Rocky Mountain area. These are planned rail and pipeline capacity expansions. This has, by 2013, you'd have about 1.6 million barrels combined of takeaway capacity, half that being rail, according to these plans, but it's unlikely you'll see 800,000 barrels per day of rail takeaway capacity, it's just not, there will always be probably 100,000 barrels for so of rail takeaway, but it's not gonna be economic on a large scale like that. And Keystone would have brought 100,000 barrels per day down and brought it straight to Cushing, so it's unclear if that will be built at this point, but there's still, if you look at a plan by, plan by project by project chart, there's still about another 700,000 barrels of pipeline capacity, mostly going to Cushing, which is the US's central storage and transit point for crude, hope there is that producers will be able to capture more of that rent-priced action. These you can look at later, but it's just more detail on the plans. I'm gonna talk about flaring. There've been some pretty dire stories on flaring, and I'm not trying to belittle it, but sort of proposes that your 2012 doomedave scenario might come from flaring. But it's a situation that's improving with this recent spike in crude oil production. There has been an increased amount of flaring, but if you take a look at the amount of gas that's being captured, it's almost doubled since 2008, and although flaring's increased, which is basically the difference between the produced and sold on the top left chart, it is a situation that's improved, and it's just taking time to build capacity to collect that gas and process it. On a BTU basis, over 90% of the energy being produced from buck and wells in terms of combined oil and gas BTUs is being captured. About 8% of that's being flared right now. It's a problem for both residents who have to look at flares and producers who are losing the value of their gas, and it's not just dry gas or methane, but it's wet gas with a high liquids cut, which in those liquids sell closer to the price of crude oil in some cases, and it's a lot of loss of value, and it's not a situation they have any incentives to maintain. Because gas for the most part must be transported by pipeline, and you have a lot of independent companies there, there's a lot of coordination and manpower and permitting that need to come together to get the gas processing and takeaway capacity together. And the weather up there limits the construction season and it's hard to build pipelines and gathering systems and blizzards. The size and maturity of the play, it does span a fairly large area, and again with many companies, many smaller companies, so it's hard to coordinate that over such a large area, but it's being done, and so far there's been about $3 billion of investment that have gone into capturing that gas. This is just one example of compression and of gas takeaway and processing from One Oak, and by the end of 2012, they will have increased takeaway capacity by about 260,000 MCF per day, and they're currently flaring about 200,000 MCF, so, again, if this was spread and spread across the play properly, it would be more than enough, and there are other companies that plan, so eventually you're gonna see processing capacity takeover or at least be enough to meet the amount of gas that's being flared. Just one other way to look at it is the amount of gas that's being produced is enough to serve to heat these number of homes, and you can see how quickly that's increased as produced in captured gas has essentially doubled over the past few years, so that's the end of my presentation. I'll be happy to go into more detail about some of these things during the Q&A period. Thank you. Thank you very much. Daryl Ducart, who's been on the ground as commissioner in Dunn County. We'll share some of his experience with us. Good afternoon. Thank you, CSIS. It is a great honor as a farmer rancher from Dunn County, North Dakota, and just a county commissioner, a young county commissioner if I could call myself that, because as of last year on December 2nd was my first inauguration as being a county commissioner, and I'm up in front of you here today. It is my honor to serve with the four panelists as well, and I've been involved in this buck and shale thing since the Git go back in 1995 when it come to Dunn County, and I kind of spearheaded a couple of organizations and been trying to get the public involved in this, and one thing that I wanna make you kind of aware of that probably many are not aware of is as you see in my bio, I own 1,766 acres of land, and I'm a severed mineral owner. I don't own any minerals whatsoever. It's all producing oil, and I would say 60 to 70% of the people in Dunn County that own surface land are in the same situation I am. So with that, I'm gonna start you into a little bit about what Dunn County is. We are 2,080 square miles. We have a estimated population right now of about 3,800 people, basic farm to ranch community. Buck and shale development started in what we thought was an extreme development phase in 2006, and then it really got started in 2009. You can see Dunn County here on this map in the western side. I want to kind of draw your attention to McKinsey, Montrail, and Williams. The northern half of Dunn County, the east half of McKinsey, the south half of Montrail, and the east half of Williams County are the main producing Bakken areas right now. These are our big towns. They got laughed at in our pre-meeting a little bit. We have the big population of 750 in Kilder, which holds our public school system. We have the my hometown of 100. We have Helladay, and you can see the rest of it there as we move on, not a big area. Here's what I done to put this together as I was asked to talk about local government impacts. I spent three days at our courthouse taking time to get my department heads to sit down and talk to me, and we put together information from each one of these departments and then broke it down into one or two slides and made it very brief as we need to try and cover this in a limited amount of time. I'm gonna start off with our auditor's office, which is always the most important part. In 2007, you can see where we had 50 full-time employees. Today, we're at 80 full-time employees with a plan to add three more full-time employees at the beginning of 2012. Our payroll moved from 1.1 million to 2.3 million in 2010, and we're projecting that by 2013 to be the 3.5, 3.7 million. Emails, telephone calls have been tremendous impacts to this office because you have so many people that have no knowledge of where to get information that is needed in this county. So this is where they end up at in the auditor's office. Technology from the outside country is way ahead of us, so these people are more comfortable than the general public is using emails, and that was a big change for a lot of our employees. County commissioner-wise, we moved from three county commissioners last year to five this year. We had normally one regular meeting a month. We now have two regular meetings a month that start at nine o'clock in the morning, never get over before six, and we have three to five special meetings every month as well that deal with one or two issues. Our budget expenditures back in 2007 was about 4 million. 2011, we're looking at 35.7 million. Tax department, we're seeing a high ratio of splitting of properties because of development. We're seeing increased valuation of properties. We're seeing $50,000 homes in 2006 that now are selling for 175,000. Big difference, housing is just not available. Property valuations have increased by 19.4% from 2010. That's one year, one year. And later on, and I'll show you some of the developments. Increased recording because of the sales and splits, numerous requests for valuation of land use, these changes. Creation of subdivisions have increased workload. We had one subdivision in the county at the beginning of 2010. We now have four subdivisions in the county. Higher requests for determination of land ownership. Outside developers, investors are coming in, looking for properties to start building and helping out the community really. And they're hard stretched because a lot of these properties are leased in rental properties that landowners have left the state. So a lot of this responsibility falls back onto the tax department of tracking the systems. In this last year, in fact, it was just approved about three months ago. We finally bought a service agreement with GIS so we can do all of this tracking of land properties that are being transferred into Electrical. It was all being done manual before. And the workload was, the department said, we can't put any more overtime in. And when I seen the budget, I realized they couldn't put any more overtime in. Huge demands on property for housing and industry. It's just unbelievable. Clerk of court. These are some of the things that people don't realize that happens. You can see the changes there. I'm not gonna go through them all because it can get very lengthy. But I think the thing that really stands out to me is the records office collection, recorders office, excuse me, collection was 147,000 back in 2006, grew by 340% to 2010. So that tells you where the impacts fall onto that are hidden impacts that the industry does not see. Planning and zoning. We added a full-time code administrator. Our past code administrator was only 20% time and it was actually part of our tax department is what it was. Now we have a full-time person in here. Normal hearings were every three months we would have a hearing for planning and zoning and we'd have one or two proposals on the table. Now we hold two times, or we meet two times a month and we have 15 to 20 proposals on the table. And it goes from housing, which is non-traditional, non-city, non-rural business. Truck parking is a big one, industrial and business development, temporary housing, RV parks, and then crew camps are just starting to move into our area. Development of a new revised comprehensive land use plan has now passed our commission. We are into the phase of passing the ordinance that will regulate this land use plan. The last one they done was written in 1968. So there was a tremendous amount of updating that needed to be done there. Crew camp applications I touch on that. That new building there that being designed that is a three quarter mile from my residency in the little town of Dunn Center and Marathon Oil is establishing that and will hold 78 offices in that building plus their crew that will work the field in their area which is pretty much the Dunn Center part of Dunn County. Roads and traffic, we haven't changed things a lot. We still got 1200 miles of road. We still got only 25 miles of paved road. We had two miles destroyed so bad that we just turned it back in the gravel. The impacts to the roads back in 2006 were very little because of truck traffic. We just didn't have a lot of truck traffic. Today we have 330 miles that are heavily impacted and when I say heavily impacted, every mile of road probably handles anywhere from 250 to 400 trucks a day of howling oil, production water, aggregate for well pad sites, concrete water for fracking wells, et cetera. Your main routes get impacted and you can't help that. You just, it's part of it. One thing that has had to change and you can see there the general road maintenance was two to three operations per year. We have had to change that. We have had to do a lot of different things. We have experimented with a lot of different things that have been unsuccessful. Cost, we done a study this year. We've done 16 miles of heavily impacted road, trying to maintain it on a regular basis, put fresh aggregate on top of it and it was 24,000 miles to maintain that road for a year. So you, we are looking at any other options because we can't sustain them type of impacts. The other thing that's been becoming very interesting is we're running out of surface aggregates and not the fact that we're running out of total supply, the industry has come and is paying three to five times the premium that the county can afford to pay for the aggregate using it in the industry themselves for their roads and their pads. An example would be the county is trying to establish themselves at $3 a yard from the surface owner right now for the gravel industries in their pay and anywhere from $7 to $14 a yard and our tax base doesn't allow us to come compete on this. So we struggle with this issue and I don't know where we're gonna go with it. Sheriff's Department, you can see where we were at in 2006, you can see where we're at in 2010 and I think that totally reflects what you've seen in the clerk accords report to me. The budget has increased over 200% there. It's just been a tremendous force upon us and they're very, very busy people. Volunteer, our ambulance, fire departments and our rescue squads are all volunteer people. The small communities put money together over years, we're volunteer people and now we have these huge impacts where we really struggle and we're looking for help any place we can get help. You can see right now today we have 34 rigs drilling in Dunn County, roughly 80 to 120 personnel occupy each one of them rigs on a daily basis. So we have about 4,080 employees which roughly over 2,200 of them are driving into that county every day to go to work. This does not count the trucks that go through the county, this is just rig employees, people that work on rigs. 9-1-1 calls, the message there is from that department that many of these 9-1-1 calls are coming on out of state numbers and all them funds are left in another state. These are cell phones from people that are working in the industry in our community and we're expected to service them. The other issue we have is the lack of addressing. We have, as the statement down below says, we have people living in the middle of fields, agriculture fields on vacant farmsteads that they made an agreement with another farmer or rancher to park their RV trailers there. And this is a true instance. We had a situation this fall where we had a 9-1-1 call, they said you need to go to XO Farmer, this is where we're at. Well we went, the ambulance squad went to XO Farmer, the young man that was at this, I shouldn't say young man, middle-aged man, was having a heart attack. And we went to XO Farmer, but he forgot to tell us that he was on the farmer's rented place. Our ambulance crew actually drove right past him and it took another four and a half minutes before we got the ambulance turned around and back to him and it was too late. So, them are the things that are going on up there. We have the two squads, Kilder and Halliday, they cover 1140 square miles. If you put that in relationship with the 2080 square miles, we have services out of Stark County, which is to the south of us, and Mercer County that also come in and help tender some of the ambulance duties in our county. EMS services, just stressed overall, travel concerns because of road conditions, we can't, they can't make good time. Most of our roads are designed for 45 miles an hour. The heavy impacted roads, very few of them are in good enough condition to drive 35 miles an hour with any kind of a vehicle.  The other roads in the county, most of them will still sustain 45 miles an hour. Our two highways, which are two main arteries in Dunn County and our only arteries, are so impacted with truck traffic and employment traffic that you'll get onto that and at 65 mile an hour speed limit, most of the time you'll have to expect yourself to be driving between 45 and 55, just waiting for people to turn off and allow you to get by or whatever. It's different. Challenges, different types of accidents. This crew told me this a hundred times. We're seeing way different things from oil rig accidents to vehicle accidents, more semi-truck accidents, which are greater impacts to us than what we were normally used to. We need to update equipment. We don't have enough money. We can't find the monies to do it and we're searching hard to continue to do that. And then the county operators, again, our totaled volunteers and most of them live and serve this community. State's attorney office, again, probably reflects a lot of what happened in the clerk of courts, has seen a substantial increase in child abuse and neglect, domestic violence, violent crimes, alcohol-related offenses and illegal drugs. And trafficking and alcohol are probably the largest ones right now that we have, but we're seeing a steady increase in the domestic violence area and child abuse area. And my visitation with him was it's, always seems to have some relationship to alcohol and illegal drugs when it gets into the criminal court. Most of the increase in the caseloads, which is not surprising because this is the way it is, it involves individuals who have recently reclocated to Western North Dakota. Economical Development Office, and I think the top statement says a lot. A few years ago, I know the young lady that worked in here, when I was talking about running for county commissioner, she kept telling me, she says, if we don't change, she says, something's gotta go, my office has gotta go or something, we can't keep going. She says, I'm just begging people to come. And when I stopped the visit with her, she says, I would like the big people not to show up right now. So it was interesting. And her clientele from one or two a week has grown through 15 to 20 a day that come to her office and ask for some kind of assistance, direction. Who do I go see? What do I need to do? The procedures and the policies needed to follow too, to get you to the next step. So that department has really been challenged. Social Service, a department most of us don't think about when we talk about the energy industry and oil development, tight oil development especially. Elderly and handicapped are scared to travel and move around because of the influx of new people to the community. They hate waiting lines, they hate for food and gas and personal items. They don't have the personal relationship with the person across the counter anymore. Two years ago, you knew everybody across the counter that waited on you. And this is a self experience of my own and many of you will chuckle over this. I drove up to the grab and go, our gas, local gas station, quick service in September. And I stepped out to put gas in our expedition. Pump went run. And an African-American man, very polite, come out and he said, sir? He said, you need the prepay. That was such a shock to me that I had the prepay for my gas. But it's all over. Killed her.  Everything's prepay just because nobody knows who anybody is anymore. It just made it simpler. Applications coming in monthly for individuals and these are people looking for new jobs in the area. They're told by other areas, go to North Dakota. There's all kinds of work. Yes, we have all kinds of work but there's not a lot of places to live. We have people living in cars. We have people living in trucks. We have people living in tents. We have people living in little RVs. This morning, we were two above zero. So it's not been comfortable. Not been comfortable. Fuel assistance is climbing steadily. Many local residents are scared and say let's go back to the way it was before we had oil development. This is a slide that I kinda wanna elaborate a little bit on because some of our panelists already have talked about this in a certain extent. And I just wanna call your attention to a couple things. If you can kinda follow, in this is the middle of Dunn County and the way our development stands as of 2010, you can see the southern half of the Dunn County doesn't have a lot yet at this time. But the small little dots that kinda run across there in vertical lines, they are the early production wells that were put in 2006 to about 2008. All the big ones are wells that were done after that. And the difference is the fracking method. They were all open hole fracks back then. Now they're stage fracking. Anywhere from 12 up to 64 stage fracking. That's the big difference in the production of oil in that formation. So I think that lends back to some of the recovery. This here is a hundred, and I just took a small part of this. This is 160 acres of land that a developer stepped forward, a local land owner stepped forward and said, I'm willing to work with you guys, let's do something. We have now 26 oil field businesses built on here. On March 1st of 2011, there was nothing here. It was still a pasture. Today it's got 26 businesses on it. Two RV sites, seven office buildings. That's the change in one year, and we have more coming. Buck and Shale Development, the positives, created many job opportunities. We're not ashamed of that. It's been very good to us in that aspect. Really changed the salary levels in Western North Dakota and especially in Dunn County. Brought additional money to farm and ranchers because of lease monies and some farm and ranchers that have royalties. Creation of many new businesses in the area, that has really changed, and then we have the increased sales of local business or past businesses which instructs cars and farm equipment. The negatives, I tried to be fairly brief on this. Again, we have the 2,200 outside workers that are estimated coming in all the time. We have an overload of patrons at every business that we go to. We have a lack of employees in every business we have. Everybody's looking for employees and all of Western North Dakota is like that. I shared in our little briefing this morning, there are many places in Western North Dakota that McDonald's is offering anywhere from $15 to $17 an hour to start. So tremendous, tremendous change for Western North Dakota. Deterioration of roads as far as a county official is a big issue for us. Traffic everywhere is a big issue for our sheriff's department. We have going every direction. There is no such thing as North, South, East, West is just going all over and some of it goes just in circles. Total stress on all county departments, we were seeing a tremendous amount of overtime being put in by people before we started putting in some extra positions to try and elevate the stress of working extra hours. These are high stress jobs because the public is demanding and the people, they just need to get out of there at times and back off a little bit. County workforce, stress as we talked about, we're experiencing frustration overload and burnout, retaining current employees is getting to be a big issue because the oil field is offering a little bit more than what county is willing to pay. Communities are seeing a lack of contractors to get a house built. I heard the other day you're probably talking two to three years out as well. You could plan right now because we don't have the contractors in there. Fixing of streets and roads, them crews can't keep up and maintain anymore. Shortage of city workers, teachers, daycare, skilled labor forces and adequate and the law enforcement, energy response, public health, social service, public works, medical services is all growing so fast, nobody can keep up. We never, in our local medical clinic, we never had the weight to go in to see our local practitioner. I need to have my annual physical and I gotta wait until February. I didn't even think about it. The difficulties. Couple things that aren't on slides that I wanna share with you. Water is a concern of ours because we totally survive off of groundwater and surface water. We have no infrastructure water development that can give us drinkable water for the whole county yet. We have it developing and moving along but it's not there. We have aquifers that we're using water out of. They're regulated by the state and as soon as they go down to a certain level, the state shuts off that use. So this is hindering some of the fracking that should be going on. The other thing is, is our state's been very loyal to us. They give us 142 million for over a two year period to be used in road development and road maintenance. Dunne County was fortunate enough to get 13.6 million of that. The balance of it went to the other 16 counties and then they set up an impact oil trust fund that put a hundred million dollars out of the tax money that the oil's companies pay and that money is then used through a matching grant system for large cities, real small towns, and counties, county developments, schools, EMS services and they apply for that through a grant system and it's approved through a grant committee. So these were kind of the blessings that kind of come from some of this. So there is some help out there and the last thing I wanna touch on is we have a good working relationship with the oil companies in Dunne County. We are starting to seize by through conversation, talking to them one on one, they are coming in and doing some in kind work for the county. Little hard to get this done because of some of the regulations and the laws and liabilities, but we are seeing this. They are helping repair roads. They are helping give large sums of money to the ambulance squad fire department. They are good working relationships with them and we leave that door open for greater conversation as this thing, excuse me, as this thing continues to develop. In closing, we are two years behind in our infrastructure and if the development keeps moving along the way it is, we're a few years ahead before we're gonna be on an equal balance. With that, thank you. Thank you. Deanny Brown is the general manager of Anadarko's project and producing in Eagle Ford, Texas. Deanny, thank you for being here. I'd like to start off by thanking CSIS for having me here today. I'm really pleased to be here to talk a bit about what Anadarko has going on in Southwest Texas and we can draw some parallels and contrast between ourselves and the Bakken development that's going on in North Dakota. Before I begin the presentation, I may make some forward-looking statements as I go through this and so the attorneys like me to include this kind of slide in there as we make these types of presentations so if anyone has any questions about our specific operations or risk, please go to our website. I think it's at the top of the page and look at our latest 10Q and 10K filings and with that out of the way, we'll sort of start the presentation. I know that some of you in the room may be a little less familiar with Anadarko as opposed to some of the bigger integrated companies so I wanted to tell you a little bit about ourselves. We are a top U.S. independent E&P company. We employ about 4,700 people worldwide. Those individuals are tasked with producing, with developing and with otherwise commercializing the about 11 billion barrels and net risk captured resource we have as an organization so that's proven reserves, probable and possible resource. We think we've got a really deep portfolio and as part of that portfolio, we are active players in many of the shale basins across North America today. We're here to talk about Eagleford but we also have pretty good operations in Marcellus. We have operations at Hainesville and we have announced positions in both Utica and in Nibrera and we're very excited about the potential that those plays offer for us. But we're not only a shale developer, we have extensive experience through a whole line of E&P, exploration and production activities really around the globe. That breadth of our portfolio can be seen a little bit on the bottom of the slide here. You can see the four planks of our strategy at the top of the page. We think that's provided us a very balanced portfolio with production operations really anchored in North America but also in Algeria and China. We're very pleased with our development off the west coast of Africa and on top of that we've got a lot of exploration opportunities again with some of the North American unconventional gas and oil opportunities as well as announced discoveries and appraisal successes recently off of Brazil and the eastern coast of Mozambique. We're very excited about those opportunities as well. So that's a little about Anadarko but we're here today to talk about shale. So let's do that. You've seen different versions of this map throughout the course of the day. This is sort of the known shale base and distribution across the United States. As we can see, it's pretty diverse. The shale is broadly distributed across the country and depending upon whose resource assessment you used, I used the US Geologic Society's resource assessment, you can see that there's about 65 billion barrels of oil equivalent believed to exist, recoverable within these shale basins across the United States. So from an E&P company standpoint, that's very attractive to us because as we search to replace our production, as we search to regrow our reserve base, we realize that we have a homegrown resource base that we can go develop should the economics be favorable and the development concepts be favorable for us to do that. So we're very excited about this opportunity and we certainly have had a great success in several of our early endeavors into this type of formation. But I should note that not all shales are created equal and there's a tremendous amount of variation between the results that you'll see from different shale plays. So when you look at all of the different elements that are necessary to have success in a shale play, they can broadly be categorized in sort of two different tranches. One is the subsurface elements that must be in place for this to be successful. So as petrotechnical people, as geoscientists, as petroleum engineers, we have classically focused on the things on the left-hand side of the page. Do you technically have what's there to be successful with the shale play? So this is things like thermal maturity, is it oil or gas? Has the carrage in actually cracked to create hydrocarbons in the first place? Do you have the porosity? Do you have the permeability? All of these technical aspects to find out, do you have something there? But in addition to that, that's not sufficient. You also have to have these surface or above ground elements also in your favor. And so that's things like access. Can we get the leases that we need in order to develop these areas are the personnel available? We've talked about some of the challenges that these developments in the substantial rampant activity in the United States has presented. And some of that is finding qualified and experienced personnel in order to help us develop these opportunities. So you have all of these different subsurface and surface elements that have to be in your favor in order to have a successful play. And as a result of that, it should be no surprise that there is a tremendous amount of variability in the results delivered by different shale plays. And so conveniently for this forum, this Jeffery's chart shows that the Eagleford and the Bakken are at the sort of better side of this graph showing higher profitability associated with those two and higher prospectivity associated with those two opportunities. And it should really be of no surprise, and this comes because of one of those elements that we've talked about that was on the left-hand side of that earlier page, and that really has to do with thermal maturity or the type of hydrocarbon that is available through these two resource opportunities. And that's the fact that these are liquid rich. And so when we talk about energy equivalency, oil and gas, as many of you know, from an energy standpoint, it's usually, it's about a six to one ratio, about 6,000 standard cubic feet of gas per barrel of oil is equivalent on an energy standpoint, but from a pricing standpoint, they traded about 20 to one. And so the opportunity, as we see opportunities in liquid rich shale resource basins, it makes sense to us economically, and there's a profit motivation to look after those kind of developments. So it's good to see that forms like this are being put together because I think as opportunities for shale oil or tight oil exist, there will certainly be an investment desire to pursue those type of plays. So we know that Eagleford is profitable, but I want to tell you a little bit about the details of it. Eagleford is a massive shale development, probably not as massive as Bakken, but big in its own right. It's got about 15,000 square miles worth of a developable area. We think that's gonna ultimately require about 120,000 wells in order to develop this area. And so that's just a tremendous well count in order to really realize the full potential of this play. We're running about 211 rigs in the play currently. And to put that into perspective, there's about 2,000 rigs working total in the United States currently. So over 10% of the entire US rigs are working down in Eagleford. It's been an amazing ramp for us, and what's really interesting about that is if you look at the bottom page, the bottom portion of the page, you can see that this ramp has occurred very, very recently. And it just goes to show that if you have all of these elements I discussed earlier in your favor, the pace of activity and the scale of activity can get big very, very quickly. That can also be illustrated by the slide on the screen. Now, 2007 through 2009, you can see there's very little development going on in Eagleford. People were drilling wells. They were testing the results of those wells. And once those results, we got those results in. We internalized them. We understood the potential that was out there. You saw a flurry of activity start in 2010. That flurry has continued through today. And so just an amazing ramp in activity. We're on pace as an industry to produce about 50 million barrels of oil equivalent through the Eagleford formation this year. So really impressive ramp. That ramp that we've seen from an industry standpoint, Anadarko has also experienced, and perhaps even more so. We think we've got a fantastic acreage position down here. We're right against the Mexican border. And we stretched a couple of about 70 miles eastward and head into LaSalle County. We've got 400,000 acres. And we're right in the condensate and volatile oil window. Why is that important? It's important for a couple of reasons. One, if you look at the production breakdown at the bottom of the page, you can see about 70% of our production is associated with liquids. This is really important for the economic benefit I talked about earlier. But the gas component is also important because it provides the reservoir energy necessary to help get the oil and gas out of the formation. And so that balance that we have within our acreage position is very nice. And it's one of the unique things about the Eagleford in that there is this transition window. And a lot of the activity associated with Eagleford is right there in this transition zone. So we're really happy with that acreage position. We think we're going to run about 11 rigs there next year. And with 4,000 locations, you're talking at least 16 years to develop this play and get the full development. I think that 4,000 locations is likely to grow over time. And so you're talking perhaps a couple of decades for us to fully develop this field. The point behind that is that this investment will be there for a while. We're pouring over $1 billion gross a year into the area with all of the economic impact that that provides. We talked earlier about the different conditions that have to be present for you to have a successful shale play. And those are necessary preconditions to have success. But if you really want to drive value, you need to focus on these three things. You've got to focus on the technology. You have to understand what you have. You have to understand where the sweet spots within the formation are. You have to understand from a three-dimensional standpoint what the reservoir looks like. So you have to put a lot of effort into the technology. You also have to have a long-term commercial vision. So you have to be willing to commit on a multi-year basis to put the contracts in place that are necessary to secure the services. You have to be willing to put the infrastructure in place in order to allow you to produce the field to its full potential. And you have to have operational efficiencies. And so those operational efficiencies, we think we've done a very good job of that at Anadarko. This is, as mentioned earlier, and like most shale plays, a horizontally developed field. So we drill this through horizontal wells. We drill down to about 6,300 feet. And we call that our kickoff point. We get down to about 7,000 feet as we turn until we're in a sort of fully horizontal position. We then drill for about 6,000 feet. And that concludes the well. Back in the second quarter of 2009, we were drilling these wells at about 3,500 feet. And it was taking us about 22 days to do that. Over the quarter on quarter, we have seen our lateral link that horizontal zone increase until now we're drilling over 6,000 feet. And we have seen the time that it takes us to do that decrease. And so now we're drilling these at over 6,000 feet in about 12 days. What that has meant is an incredible increase in capital intensity. We have ramped up rig activity. We have increased the number of wells per year that we're able to bring online. And the capital intensity has increased as a result of that. And so that has meant more jobs in the field, more steel being ordered from suppliers, all that sort of stuff. So we even liked it because it's been able to increase our production. And I think that we've had some beneficial impact from that increase in capital intensity as well. This has also been mirrored on the completion side of things and that our completion activity has really increased as well in order to keep pace with all the drilling activity. And what that has led to is a situation where if you look at state records because of our focus on Eagleford and because of this increased operational efficiency in the capital intensity that we put into this field, by state records it shows that we are one of the number one, if not the number one operator down in Eagleford by well count and by production. It's something that we're pretty proud of. We're really thankful to have this in our portfolio. And it certainly provides a lot of value, not only to us, but also to the community in which we work through the economic impact that we provide. But we've been helped. And so this is a picture of the regional infrastructure down in Eagleford. And I'd like to contrast this a little bit with some of the things that Ben and others have talked about on the panel. The Eagleford, because of the position in Southwest Texas, has really benefited from a lot of the legacy infrastructure that's in place through historic oil and gas developments. And so on the top left-hand side of the screen, you can see the natural gas pipeline network across the United States. And while the Eagleford doesn't exist right within the middle of that pipeline network, it's awfully close to it. And so what that has done is it's really improved the overall economics force in order to tie our systems into these type of lines to get our product to market. And so that has really enabled us to plant the activity at the pace that we have. That's been augmented, as well, by our proximity to the Gulf Coast refining industry. And so not only have we been able to get the gas to market, but we've had a place to go with our oil, as well. You can contrast that with the buck and where they haven't had some of the similar infrastructure benefits that we've had down in Eagleford and see perhaps why we've been able to increase so rapidly and haven't faced some of the same challenges they have. That's not to say this has been easy. We've put over 280 miles of pipeline in the field ourselves. We've added about 90,000 barrels of crude oil storage and set 40,000 horsepower and compression. But there was all things that were manageable that we were able to do really because this legacy oil and gas infrastructure exists in the area. But there are similarities between us and the Bakken, as well. And some of that has to do with the fact that this development is really being pursued in an area that's fairly remote. And so on the screen, you can see a population density map of Texas. The area of Anadarko is the heart of our operations. It's really centered around Dimmitt County. Dimmitt County has a population of something less than 10,000 people. As we have looked through, what is the personnel and jobs impact of having our rigs in the field? After a lot of investigation, we've determined it's about 500 people per rig. So for running 10 to 11 rigs in 2012, that would tell you we've got between 5,000 and 6,000 people down there working in the field. Well, the entire county has got about 9,700 people in it in 2008. And we're just one operator. So many of the community issues that Darrell talked about a little earlier, we face some of those similar challenges. And I think a poignant example of that is housing. Some of our, as we have worked to try and make sure that our contractors and employees have appropriate housing for them and for their families and have the access to the infrastructure that they need, we have found that they've been moving further and further from our center of operations to find homes. And we're at a point now where many of our employees are living 50, 60, 70 miles away just to find the homes and commuting in every day. This is something that it certainly has been a challenge. Anadarko has now working with developers down in the area to try and get housing solutions in place. We're engaging the local officials, similar to what Darrell mentioned, to try and work through road issues, work through school issues, and those type of things. So the development and the pace of activity certainly offers its challenges. But there's also fantastic benefit to this as well. There's been reports by the UTSA that have come out to say that they think about 70,000 people within the next few years will be employed developing the Eagleford Shale. And those are local jobs. That's not the overall job impact. Those are local jobs. So just a tremendous amount of opportunity with respect to employment being coming about as a result of this development. So I just wanna close by sort of summarizing a few key points I think that we feel about shale development. One is that the shale development is going to continue to be a major source of production and reserves in the coming decades. It's something that we're very excited about. But in order to do that, the development environment, it needs to be competitive and it needs to be predictable. We need to understand the rules of the game going in. It's also important to note that not all shales are created equal. And because of all of these varying elements that we've talked about both from a surface standpoint and a subsurface standpoint, the results that you're going to see from a shale play are going to differ. And I think it's also always important to keep in mind that these developments have to be carried out in a safe manner. They've gotta be carried out in a prudent manner and they've gotta be carried out in an environmentally responsible manner. And it's incumbent upon us to make sure that that happens. Along with that, there's going to come a lot of resource intensity. It's gonna take a lot of people to do this. It's gonna take a lot of capital to do this. It's gonna take a lot of infrastructure and it's gonna take a lot of equipment in order to make these things successful. But if we do it right, then the benefits are great as well. A recent IHS report came out that showed that over 600,000 people are currently employed by shale development. And that's only increasing over the over time. They expect over 25 years that there'll be about $900 billion, billion dollars in local revenue and state and federal revenue associated with these type of developments. So we're excited about the opportunity as EMP companies. I think the local communities can be excited about the opportunities it's gonna provide to their local economies and from a state national level. It certainly does good things. Both from an economic standpoint and from a domestic energy standpoint. And with that, I thank everybody for their time. Happy to answer any questions afterwards. Well, we're running a bit late, but let's get right into the Q and A because I know there's been a lot of information put out there today and so let's wait for a microphone and identify yourself when you ask your question. John Meyers in the back there. This is for the county commissioner. You said in your start that I sense over half the people are severed owners. In other words, they don't have the landowners like yourself don't have an interest in the minerals. What's the view of those of your community, the severed owners about this overall development? That's a very good question. I would say that 20 to 30% have showed some resistance to allowing development to continue, but the majority are willing to work with the industry and allow it to succeed. Yeah, thank you. Yes, sir. In the middle of, thanks, Claire. Oh yeah, Chris Ellsner, Department of Energy. Mr. Brown, I was just wondering, I guess maybe in the Eagle Ford in particular, those efficiencies that you've realized in the past years, is that very much by producer and the correlated investment that'll come into Eagle Ford, are you starting to experience a lot of cost inflation? I think that does vary quite substantially by producer and a lot of it comes from one of the elements I discussed earlier is that multi-year investment approach. And so we went out early on and we made long-term commitments on contracts for service companies from a rig standpoint, from a completion crew standpoint. And we also put a lot of investment time and capital investment into building the infrastructure necessary for us to expand. And so not everyone is in the same situation. So consequently, their ramp in activity has been affected by that. We have seen some cost inflation overall within the Eagle Ford as the activity has ramped up. But again, because we put these long-term contracts in place, we've been somewhat protected by that. Yes, ma'am. Mr. Dukert, thank you. For Mr. Dukert, the development that's occurred, you talked to mention multiple times that it's what a strain these new services are on county funds. What does the county actually get out of this development? Does the county directly get any royalties? Does it get increased property taxes? What are your new sources of funds there? Yes, there is a, first of all, you have your oil production tax that's taken by the state. And then the only county that that's delivered from, that oil is produced at, a percentage of that comes back. And that returning percentage, I'm not sure exactly on that percentage number, but I believe it's about 6% of that growth that comes back in. And then as I explained, we have these extra funds that were brought into our system. There's also gonna be, and we have not realized this yet, as I showed you, the property growth. In the next year to two to five years, we're gonna see the property tax level really increase because of this extreme growth. So there will be property tax monies coming back in. Let me acknowledge David Bardeen for the next question. And David is the person that at least brought to my attention the significance of Bakken about six or seven years ago, and to many others as well. So thank you, David, for recognizing the importance of this very important national resource. Thank you, Guy, and thank you CSIS for this conference. I have a question for Commissioner Duckert and a question for Mr. Brown. On the property taxes, does the county levy a property tax on the mineral owner in the case of the severed estate? And for Mr. Brown, the question's gonna be, what is the recovery factor in current development in the Eagle Ford? But I'll ask the commissioner for you. No tax levied whatsoever. Is that because you're not allowed to, or because that hasn't been considered yet? Correct, we're not allowed to. We have been considering it, though. So you need the legislature and Bismarck to do something for you? Yes, we do. Good luck. Seems like a good approach. And it deals with my interest in recovery factors because what the mineral owner owns in the case of, say, the Bakken example that Mr. Sorensen gave us, maybe a one percent or a little more recovery factor, he doesn't own only the recoverable resource, the technically recoverable resources, he owns the entire resource in place and that's got some present value. From an Eagle Ford perspective on the recovery factors, that's a source of great debate. And it really depends on where we're unsure how much of the reservoir is feeding in to our former and to the well-born. So we realize that we're gonna get about between 400,000 and 500,000 barrels of oil equivalent per well that we drill. But when you do recovery factors, it depends on all of your inputs and the degree of variation in the inputs can be substantial. How big is the H? How big of the formation is actually contributing? We're not sure on those things. I think it's something higher than the one two percent that Bakken's doing just because we've got some substantial reservoir energy helping the drive. But certainly nothing like a conventional reservoir which would be in the order of 30% or higher. So somewhere between the two. But you don't wanna narrow that down. No, I don't. As I say, it's a source of a lot of debate. Well, Mr. Sorenson, if you know, what kind of gas oil ratios are they getting in the Bakken now? When I studied it a few years ago, it was roughly one to one. It was very low gas ratio compared to say with what happened to the Texas Gulf Coast during and after World War II, which would use the huge amounts of gas flaring before the interstate pipelines were built that people probably have forgotten about down in Texas. Yeah, and I don't know exactly what the gas oil ratio is right now, but it is considered low. It's more in line with what you're talking about. And it's one of the reasons why the infrastructure to collect the gas has been sort of slow to develop is it just doesn't seem to have the gas resource that other plays have. Oh, Michael. Michael Roster from CRS, Congressional Research Service. Hi, my question is, I guess, geared towards Mr. Slaughter and Mr. Brown. As we've talked about, I mean, the focus here has been on tight oil and here in Washington a lot of the debate revolves around fracturing issues. Do you see that the debate changing here in Washington as more and more of the production is shifting towards oil versus gas? And as I think Mr. Brown pointed out, the value of oil, you know, a lot greater than the value of gas, and as more of our production of oil comes from these sources, will it impact the debate around fracturing? I'll have a stab for that first. I mean, not being based on Washington, I'm not in day-to-day contact with the debate here, but I think you're talking about trading off the energy security and supply benefits of increased liquids production. Which is a somewhat different animal from the shale gas development because of the huge trade imbalance that the US has in terms of oil, which could narrow. So the economic benefits, the balance of trade benefits are of a different nature than the shale gas development. I think some of the more detailed operational issues around land use, around water cycle, around fracturing are similar because it's a similar type of technology that's being deployed and it's being deployed in areas which traditionally haven't had a lot of activity. So I think there will be a way of working through the discussions and the operations in terms of fracturing and water cycle that will be fairly similar between shale gas development and tight oil development. I'll just echo that. I think it was very well said. I would imagine along the same lines of what Mr. Slaughter said, the technology is essentially very, very similar, although some of the benefits provided do differ. So from that perspective, it may change the debate somewhat, but the underlying technology is very similar between the two. Eric. Eric Rasmussen, ex energy information administration employee. I have a question. I'm not sure for which of you, whichever is appropriate, and refineries, what's the outlook for new refineries in the upper Midwest and how helpful would that be in the infrastructure issue overall? Let's change this for a good product. I've seen one or two proprietary studies of refineries in North Dakota. One was for basically a 30,000 barrel per day topping plant. Another was for a larger, more complex refinery and neither were economic. So I wouldn't expect to see any refineries built up there, but I do understand, actually Trisha Curtis was on a call with, was actually on a radio show up in North Dakota and there were a lot of people calling in saying, we have all this crude oil up here, but we're facing gasoline and diesel shortages and that's sort of what Daryl spoke to. So there are people who would like one built up there, but it's hard to make economic sense. We're looking at minimum $500 million investment for one. Well, there's a difference between local use as well. I mean, if you get into product pipelines versus crude pipelines, you have batching and content problems as well. So you may actually make the problem worse initially. Other questions? So I have one quick question. So Daryl, I'm actually bent for you as well. When you talked about the situation on balance, pluses and minuses, is it more the perception of a timing situation that because development occurred so fast that infrastructure resources, that things will come similar to pipeline permitting and the experience that we've seen in Eagleford and other places, or do you think you're gonna be playing catch up for a long, long time? Well, that's a tough question. Looking through the past, I'm gonna guess we're gonna balance out. I live through one of the Bakken, or not the Bakken, one of the developments that was mostly developed in the Dupro formation worked in that area for a few years. And it took about four years after that initial play had happened to the economy to stabilize and the infrastructure to stabilize. So I don't think we're gonna see it happen quite as fast. I think it's gonna take a little longer because this is a whole different play. It's a whole larger impact of people. And the big thing about it is, is the volume oil is way greater than it was back then. So I'm gonna guess it's gonna do the same, but it's gonna take a period of more years to get to that balance. And is it gonna be five or 10? I don't have that answer. Any other comments? Jim. I was gonna say along with what Daryl said, I think the fracking is another aspect of it that makes it different from previous plays as far as how long it'll take for society to come back to equilibrium. The fracking, you've got the water issues that you didn't have with more conventional plays. You've got all the truck traffic, all those things. And I hadn't even realized that the competition for resources between other industries, I mean it's gonna be difficult for other industries to come in. And we've got a fledgling wind power industry in North Dakota. Well, if they're all competing for the same kind of resources, construction companies, et cetera, and those kinds of impacts are things that are gonna probably take a few years to work through. Trade off imbalances. Go ahead. You got a microphone, go ahead. Great, that's being done. Question, from a community impact standpoint, what of the oil companies do you think done right and maybe what are some of the things they've done wrong? I think, as I stated in our conference pre-meeting, that we were told back in probably about 2000 that North Dakota Industrial Commission and the oil and gas division in North Dakota kind of gummed to us with the knowledge from the oil industry already that there's a major play here. Start tying your shoes and then tying double knots because you're gonna get impacted. Politically, they were very correct, but our sub-political divisions, county governments, city governments, all kind of have experienced the past impacts and didn't realize and didn't understand the magnitude of this one. I think that's probably what's the key point to this. Oil companies, what could have they done different or better? I don't know if they really could have done a whole lot except just tried to pound more education into us. The direction was given, but we didn't know how to receive it. Yes, I think following up a bit on that question, if one goes back in the history, back in the early part of the 20th century and the development of oil towns, certainly in Texas, but also places like California, the oil companies became the core and the center of the growth of those communities with a long-term commitment, basically, that they were gonna be there as long as the cities or towns. Do you hear that kind of commitment coming from companies saying, we're gonna be here for 30 years, we're gonna train all our workers here? Would that make a difference if they did it? Yes, you're correct and it is happening. And my example will be my home small town. I live, the city of Dunn Center, if you remember, I had a population of 100 with the development of a Utah investor that's come in there and putting up a 58 complex housing unit and the Marathon Oil Company, putting in their 78 offices and businesses there.  Is it right or wrong? I don't know, I will learn to live with it, I can tell you that much. There's community, the elderly in the community that are quite resistant, but that is expected and the younger generation is moving with the roles and doesn't seem to impact Mahola. If I could add to that, you talk about history, historically you mentioned early 20th century companies would come in, almost a company town. I think where it's a little bit different and certainly Marathon is stepping up and doing that in North Dakota and has to stepped up and doing that in North Dakota, but a lot of areas of the Bakken are being developed by smaller independent companies and especially what we've seen in the last few years, those smaller independents get bought up, they one buys another and so that I think that commitment from a smaller company to a community isn't quite as long term as what you've had historically or what you're gonna expect from a Marathon or a Hesse. So my takeaways from this afternoon have been a couple. This homegrown world class resource that we now have out there just strikes me that in a post-McCondo, post-Fukushima, post-Euro crisis, you name it, world that we're in now, the energy landscape has changed and it's really time for a new policy rethink. And a lot of the situations Andrew as we talked before about the economics and the environment and the energy security pieces all come together and the trade offs within those areas are something we really have to concentrate on. But going forward, I think it's a great opportunity, it gives us some breathing space to figure this out. I wanna thank Molly and Lee for helping to put this together and I really enjoyed this panel discussion.  This has just been a terrific, it's an extensive perception of what's going on, kind of a deep dive. I hope this helped the education and we look forward to more of these kind of discussions. So thank you so much.