Plunging Crude Prices: Effects of Increased U.S. Oil Production

February 11, 2015

Mine Kuban Yücel shares data on U.S. oil production, focusing on the nation’s three most productive oil fields in South Dakota and Texas. She notes how increased production from these wells—due to tapping shale deposits, more efficient rigs and new horizontal drilling techniques—has increased oil output to the point where the U.S. no longer imports light sweet crude. Overall, the U.S. now produces more oil than it imports but, by law, the U.S. cannot export crude oil. Yücel explains how this affects oil-exporting countries’ economies, global oil prices, and drilling and refining activity in the U.S.

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Mine Kuban Yucel: Okay, so we've given you some background on what may have caused that price plunge in the second half of 2014. So now I'm going to talk a little bit about how that has impacted the oil industry in the U.S. and what that means for the U.S. economy.

So here you see oil and gas production in the U.S. This is annual data going back to 1920, and those little dots are, since it's annual it's the January estimates for U.S. oil and gas production. And in January of this year we produced 9.2 million barrels per day. That's huge and it's not quite our record. It's about equal to what we were producing before the plunge in 1986. And before 1986 it's about equal to what we were producing in 1974. So our record is 10 million barrels per day in 1970. So we're getting pretty close to that record.

You can see over there and I'm not going to try to fiddle with this but from 2010 on is when—the blue line is oil—when that oil output started going up and it's of course from the shales. And from 2010 to current, the U.S. added about 3.8 million barrels per day. And just that increase is more than the output of any country aside from Saudi Arabia, Russia, and China. So in just four years we added that much output.

Our record for gas was in 1970 also, but since 2010 every year has been a record for gas. In 2010 we were producing about 22.6 TCFs, trillion cubic feet, and right now we're at 28.6 TCFs. So it's a lot of natural gas coming out of the shales.

So where is it coming from? Well it's from shale, the majority of it. And a lot of states produce oil from shale. You see on this left hand side the smaller producers: Oklahoma, New Mexico, Wyoming, and Colorado are the larger of the smaller producers, but the bulk of it comes from North Dakota and from Texas. And you see in North Dakota, for example, output tripled from 2010 to 2014. North Dakota is producing about 1.2 million barrels per day. In Texas, again, tripled output since 2010 and Texas is producing 3.4 million barrels per day. That's a lot of output. And you know in Texas we like to say if we were a country Texas would be the seventh largest producer in the world. So that's quite a big player. It would have been, or is a pretty big player in the global oil market.

So one point to make here is that the oil that's being produced from the shales is very light oil. So it's called light sweet and it has very little sulfur and it has what we say high API gravity, which says that it's not very dense. That's why it's called light. And so oils with high API gravities are preferred by refiners and they're more costly; they cost more. And so the oil that you see here is the oil from the Eagle Ford, which is one of the producing regions in south Texas. And it's sort of shows you what the breakdown is between the light and the heavy oils that is coming out of Eagle Ford. But the Bakken is pretty similar too, so the shale oils are quite light. So 80 percent of Eagle Ford oil is greater than 35 degrees API. So that is when you start sort of saying it's light versus not light. So 80 percent is light. More than half is greater than 40 and about 15 is called ultra-light and that's called condensate also.

As I said, North Dakota's Bakken is very similar to this. Now why is this important? Well it's because as we have produced more and more oil from shale we have reduced our imports of light sweet crude, and you can see in the picture, 2010 we were importing about 2.1 million barrels per day of crude greater than 35 API. And in 2014 we only had about half a million barrels of light being imported. So we backed out all these light sweet crudes that we were buying from Angola, Nigeria, Algeria, and in fact I think something just came out from the Energy Information Administration. It's actually zero now, the amount of light sweet crude that we import has come down to zero because of all the production from the shales.

So the problem though is, so this continues to increase as we produce more and so we have nothing that we can back out now, and so that puts downward pressure on prices of light sweet crude in the U.S. Plus there's a mismatch between refinery capacity and the amount of oil that's coming out, the light sweet crude that's coming out or rather refinery capacity that could handle the light sweet crude. Because you see here a lot of our exports or imports rather were heavy oil. So this is the oil that we get from Venezuela and from Mexico. And so what happens is in the 2000s the refineries were reconfigured to be able to handle this heavy crude. Well now we're getting much less of it. We have all this light crude. It's not that they can't refine it. It's just not as efficient for them to do that, so refineries are running at really high utilization rates to be able to handle this. On the Gulf Coast in January it was about 96 percent utilization. Came down a little bit in February but still it's quite high.

And of course we're producing all this. You may remember, so this here you see production. That's the red. And imports are the blue. And these are annual numbers so you may remember the days when U.S. oil production had fallen to less than 50 percent of our imports and there was this huge uproar when we passed that 50 percent mark.

Well, the situation has changed pretty drastically. This is again annual so it doesn't show you the latest but the 2014 data that's an estimate are in the dots, and you can see that we are now producing more than our imports. And in fact January numbers were 9.2 million barrels per day of production versus 7.3 million barrels per day of imports. So it sort of has changed. The shale production has changed.

Now one point to make here is we can't export crude. We were looking at what that law was called and it's the 1975 Energy Policy and Conservation Act. I don't know if you remember that but it came about after the 1973 oil embargo, and so we said we are not going to be exporting. We are going to keep our crude to ourselves; we're not going to export any. So you can't export any crude but you can export refined product. So what happens is all this crude that's coming in, we make it into refined products and so we export gasoline and diesel and you can see the increase in our exports of gasoline and diesel in the picture. In fact since 2010 I have a number here. Diesel exports have nearly tripled and gasoline exports have more than doubled since the beginning of that shale boom. They did decline a little bit last year and it's a function partly of the weakness of our trading partners' economies and partly the strength of the dollar.

So given the decline in oil prices the rig counts have started to decline. So what you see here is North Dakota, which is the blue. Texas is red, and the green is U.S. minus Texas and North Dakota. And they have started to decline quite precipitously. The U.S. is down just in January by 355 rigs. That's about 20 percent decline, and more than half of that came from Texas, so Texas was down by about 186. North Dakota was down about 22 but again all of them in the 20 percent range. In Texas the largest decline was in the Permian basin. So the Permian basin and the Eagle Ford are the two main shale-producing regions for oil anyway.

But the interesting thing is it was not in the horizontal wells but it was in the old traditional vertical wells. And the reason for that is the horizontal wells are a lot more productive and so it's more efficient and they're cheaper per barrel than the vertical. So we have not seen a decline in horizontal wells yet. It's all vertical wells in Texas anyway.

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