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Pure Energy

Critiquing the SPR Swap Plan

This morning, I read an interesting editorial in the Wall Street Journal:

Obama Has a Plan To Manage Our Oil Reserve

The editorial was written by John Shages, a former deputy assistant secretary for petroleum reserves at the Department of Energy. The editorial essentially argues that the composition of the Strategic Petroleum Reserve (SPR) is lighter than the composition of oil that most refineries run. Since lighter crude is also more expensive than heavier crude, Shages is suggesting that we sell some of the light crude and buy back some of the heavy crude. His argument – echoing the argument from Obama and various other government officials – is that this would generate cash and help drive down oil prices.

Some excerpts from the editorial:

Sen. Barack Obama is proposing a simple maneuver — called an exchange, or swap — that will help lower the price of oil for consumers, increase the amount of oil in the SPR, increase energy security, and leave taxpayers better off by about $1 billion. His proposal deserves to be adopted.

Today, with historically high oil prices, it is time to debate using the SPR. Some argue that the reserve should only be used in emergencies. Others say that we should use all the tools at our disposal to help consumers.

OK, let’s debate. Regular readers know that I strongly object to using the SPR in an attempt to influence prices. That is not what it is for. High prices – which are incidentally well off of their highs – do not constitute an emergency. Further, that line about taxpayers being better off by $1 billion misses a very large point. I could also trade in my house for a mobile home, and be better off by a few hundred thousand dollars. But that few hundred thousand has costs associated with it: Less home, a home that isn’t as safe in bad weather conditions, and a home that has less value when I wish to sell it. Likewise, there are costs associated with downgrading the quality of the SPR.

Mr. Shages continues:

The oil in the reserve now is all light crude, which is easier and cheaper to refine into gasoline, a reflection of refining capability at the time the SPR was created. Over the past three decades, however, U.S. refining capacity has become increasingly sophisticated and complex, because the world’s oil is increasingly heavy and harder to refine. Today, about 40% of our refining capacity is configured to handle heavier crude oil.

We now confront a mismatch between U.S. refining capacity and the oil mix in the SPR. In a 2007 report, the Government Accountability Office (GAO) found that in an emergency this mismatch could reduce U.S. refinery capacity by 5% or over 735,000 barrels per day in total as some refineries scale back production to accommodate the SPR oil. The GAO recommended that the Energy Department change the reserve’s oil mix to at least 10% heavy oil, roughly 70 million barrels.

It struck me as very odd that having oil that is too light could reduce refinery capacity. After all, light oil is much simpler to process – as is alluded to above. Yields are also higher. Yet the claim is that we would be better off with heavier oil in the SPR? This didn’t add up, so I dug up that GAO report that was referenced:

Improving the Cost-Effectiveness of Filling the Reserve

Some excerpts from that report:

Our analysis of DOE’s Energy Information Administration (EIA) data shows that, of the approximately 5.6 billion barrels of oil that U.S. refiners accepted in 2006, approximately 40 percent was heavier than that stored in the SPR.10 Refineries that process heavy oil cannot operate at normal capacity if they run lighter oils. For instance, DOE’s December 2005 found that the types of oil currently stored in the SPR would not be fully compatible with 36 of the 74 refineries considered vulnerable to supply disruptions. DOE estimated that if these 36 refineries had to use SPR oil, U.S. refining throughput would decrease by 735,000 barrels per day, or 5 percent, substantially reducing the effectiveness of the SPR during an oil disruption, especially if the disruption involved heavy oil.

If you know what the assays look like for heavy oil versus light oil (See The Assay Essay), this looks like a very improbable claim. I suppose if you didn’t try to optimize your refinery for light oil, then that might be a true statement. But refiners optimize their refineries on a daily basis. I used to work in a heavy oil refinery. We could run heavy oil through, or we could run light oil through. If we don’t change the refinery settings at all, and run light oil through, then the above argument may be correct. But we would never do that. The overall yields are in fact higher with the lighter crudes, but you have to make the necessary adjustments. You may end up shutting down some units – like cokers – that are designed to handle heavy crudes.

But there is a more significant factor that seems to be overlooked. Refiners are configured to run heavy crudes because they are cheaper. Why are they cheaper? One, because they are more readily available. What does that suggest? That it is much less likely that there would be a disruption of heavy crude supplies. Thus, Mr. Shages (and Obama’s) argument is based solely on what refiners typically run, and ignores the question of typical availability of supply.

In conclusion, a heavy oil refinery can run light crudes with some adjustments. A light oil refinery can’t run heavy oils without severely impacting yields. Further, a light oil refinery is much more likely to see supply disruptions because there is simply less light oil available. This is why swapping heavy oil for light oil is a bad idea. It is a misguided attempt to influence oil prices, and that is not the purpose of the SPR. If it is allowed to be used for this purpose, then all we are doing is speculating with the reserve.

Footnote: Headed back to Europe today; offline for a couple of days.

September 8, 2008 Posted by | assays, Barack Obama, oil prices, oil refineries, refining, SPR | 60 Comments

Refining 101: The Assay Essay

When a refinery purchases crude oil, the key piece of information they need to know about that crude, besides price, is what the crude oil assay looks like. There has been a lot of discussion at The Oil Drum at various times about “light sweet”, or “heavy sour”, and how these qualifiers affect the ability of a refiner to turn these crudes into products. So, I thought it would be good to devote an essay to this subject, and discuss how different types of crude can affect a refiner’s bottom line.

Below are results from two different assays:

Liquid Volume % Generic Light Sweet Generic Heavy Sour
Gas (Initial Boiling Point to 99°F) 4.40 3.40
Straight Run (99 to 210°F) 6.50 4.10
Naphtha (210 to 380°F) 18.60 9.10
Kerosene (380 to 510°F) 13.80 9.20
Distillate (510 to 725°F) 32.40 19.30
Gas Oil (725 to 1050°F) 19.60 26.50
1050+ Residuals 4.70 28.40
Sulfur % 0.30 4.90
API 34.80 22.00

Table 1. Comparison Between Assays of Light and Heavy Crudes

Note that for this essay we are only concerned with a portion of the assay. The full assay would have information on metals concentration, salt concentration, vapor pressure, etc. What the two assays above tell us is that one is light (the higher the API gravity – a measure of density – the lighter the crude) and one is heavy. It also tells us that one is sweet (low sulfur %) and one is sour. Now, to be clear, a heavy crude can be sweet and a light crude can be sour. But refiners that are equipped to handle heavy crudes are generally also equipped to handle sour crudes, so that’s what they buy. Heavy sour is cheaper than light sweet, and there is more money to be made with heavy sour crudes as long as a refinery is configured to handle them. Gasoline doesn’t care whether it came from cheap heavy sour or more expensive light sweet; the product price will be the same in either case.

Now, back to the assay, and what the various categories mean. The way the assay is done is that the crude oil is boiled, and the amount boiled off at various temperatures is measured. This defines the various products, or cuts. When 99°F has been reached, the gases have been boiled off. This is the dissolved methane, ethane, propane, some butane, and some trace higher gases. This cut can end up being purified for sales, or it can end up as fuel gas to help satisfy a refinery’s need for steam.

The next cut is straight run, or natural gasoline. Gasoline is a mixture of hydrocarbons that are characterized by the boiling point, and the gasoline you purchase at the gas station will contain many different blending components. One of these will usually be light straight run gasoline. This cut will contain things like butane, octane, and every manner of branched and cyclic hydrocarbon that boils in a specific range. Most gasoline has been subject to additional processing (more on that later). The straight run gasoline is what can be expected to be distilled from the crude oil with no additional processing. Typically, straight run gasoline is not a highly desirable gasoline blending component, because the octane is usually pretty low. Nevertheless, the straight run gasoline does get blended into the gasoline pool.

The next cut is naphtha. You can do a couple of things with naphtha. You can blend it into gasoline, but the octane is even worse than for light straight run. Therefore, you are seriously limited on how much can be blended. More commonly, naphtha is fed to a catalytic reformer, which processes the naphtha and boosts the octane from less than 40 to greater than 90.

We then come to kerosene (also called “jet”), which starts to get into the range of diesel components. This cut also has more energy content per gallon than the earlier cuts, but is too heavy (less volatile) to be blended into gasoline. The sulfur components start to become more concentrated in these heavier cuts, so kerosene is typically subject to hydrotreating. In this step, hydrogen is added to the kerosene in a reactor to convert sulfur components into hydrogen sulfide, which is then removed. Kerosene has a number of uses. It is used as fuel for jet engines, and it is also blended into diesel. It is also used in some portable heating and lighting applications.

The next cut is distillate (specifically, No. 2 Distillate; kerosene is sometimes called No. 1 Distillate). Like kerosene, this cut contains sulfur and must be treated (as do all the heavier cuts). Distillate has two major end uses: as diesel fuel and as home heating oil. In fact, as seen in the assays above, a substantial portion of a barrel of oil ends up as heavy distillate. For the light sweet crude assay above, 32.4% ended up as distillate, and for the heavy sour crude 19.3% ended up as distillate.

We then come to gas oil, which is also known as fuel oil or heavy gas oil (distillate also being known as light gas oil). This cut is typically processed in a catalytic cracker to make cracked gasoline. By the name, you might guess that cracking involves breaking these heavy, long-chain hydrocarbons down into shorter hydrocarbons that boil in the gasoline range. The cracked gas is then blended into the gasoline pool.

The final cut, residuals, or just plain “resid”, is the cut of greatest interest when we talk about the economics of heavy crudes versus light crudes. Note in the assay above, that less than 5% of the barrel of light crude ends up as resid. However, the heavy crude yields over 28% resid. Resid is sold as asphalt and roofing tar, and is not a very desirable end product. Therefore, more and more refiners are installing cokers to further process the resid. A coker can take that resid and turn it into additional gasoline, diesel, and gas oils. The economics of doing this are typically very attractive, given the historical price spread between light oil and heavy oil. A coker can turn over 80% of the resid into valuable products.

Examples (For Illustrative Purposes Only)

Let’s compare two hypothetical refineries. Refinery A has no coker, and thus is restricted to either buying light crude, or buying heavy crude and selling a lot of low-value asphalt and roofing tar. So let’s say that Refinery A pays $55 a barrel for West Texas Intermediate. They will turn that barrel into 0.909 barrels of liquid fuel product (per the light assay above, 4.4% ends up as gas and 4.7% ends up as resid), which let’s say has a value of $80/bbl. They therefore grossed $80*0.909 – $55, or $17.72 a barrel before we consider the value of the asphalt and the gases. Historically, the value of asphalt has been very low – less than $0.10/lb. Given that our barrel of crude weighed around 300 lbs, and we got a 4.7% asphalt yield, the barrel yielded 300*0.047 = 14.1 lbs of asphalt worth $1.40. Let’s value our gases at the value of propane (about $0.14/lb on the spot market), and we get a value of 300*.044*$0.14 = $1.85 for the propane. Our gross profit (before operating costs, taxes, etc. are considered) is then $17.72 + $1.40 + $1.85, or $20.97 per barrel for the light crude.

Now consider Refinery B. Instead of buying WTI at $55/bbl, it buys a heavy Canadian crude for $38/bbl (this is an actual current price). Again, their barrel of oil weighs some 300 lbs, and as we can see from the assay above their resid yield may be in the range of 28%. So, of the 300 lbs, 84 lbs ends up as resid. But with our coker, we turn 80% of that into high-value products, and only 20% (16.8 lbs) ends up as low-value coke (a coal substitute). Therefore, the overall yield from the heavy crude amounts to the sum of the cuts up to resid (71.6%), plus the resid that was turned into products (80% of 28%, or 22.4%) minus the gas cut (3.4%) for a total of 90.6%. The overall liquid yield is almost the same as for the light crude, and yet we paid much less for the crude. So, our economics look like this: For the liquid fuels, we grossed $80*0.906 – $38 = $34.48 a barrel. This is almost double what we profited from with the light crude. We have slightly less propane yield than in our previous example. The value of propane is $1.43. Finally, we end up with 16.8 lbs of coke, which is worth only $0.015/lb (about $0.25 total). Our total gross profit then is $34.48 + $1.43 + $0.25 = $36.16.

This explains why so many refiners are rushing to install cokers. This is also why I don’t get too excited when someone comments that the build in crude inventories could be a build in “undesirable” heavy sour. Refiners don’t buy what they don’t need, so if heavy sour inventories are increasing then this is primarily coming from refiners that can process heavy sour.

As light sweet supplies continue to deplete, refiners will increasingly turn to heavy sour crude. But not enough refiners yet have a demand for heavy sour, so it trades at a significant discount to light sweet. This will of course change as more cokers are installed. There will be a higher demand for heavy crudes, and the asphalt market will become more lucrative as the asphalt supply gets rerouted to cokers.

Of course the caveat is that a coker is a major capital expense (hundreds of millions of dollars), and it is only part of the equation. I have focused here on processing heavy crudes, but not at all on sour crudes. The story is similar to that for the heavy crudes. Sour crudes trade at a significant discount to sweet crudes, and the refiners need additional processing equipment to handle them. But the economics currently favor installing the cokers and hydrotreaters to handle the heavy sour crudes, and will continue to do so as long as they trade at a substantial discount to light sweet crudes.

As always, comments, corrections, and questions are encouraged. Do note that while the examples above are approximate, they are not exact. There is more to the economics than what I have presented, but for the purposes of understanding some basic refining economics, this should suffice.

Additional Reading

Refining 101 at Tesoro
Basic Refining Overview
Petroleum Refining and Processing from the EIA
What is the difference between gasoline, kerosene, diesel fuel, etc.?
How Oil Refining Works

January 12, 2007 Posted by | assays, crude oil, economics, refining | 7 Comments

Refining 101: The Assay Essay

When a refinery purchases crude oil, the key piece of information they need to know about that crude, besides price, is what the crude oil assay looks like. There has been a lot of discussion at The Oil Drum at various times about “light sweet”, or “heavy sour”, and how these qualifiers affect the ability of a refiner to turn these crudes into products. So, I thought it would be good to devote an essay to this subject, and discuss how different types of crude can affect a refiner’s bottom line.

Below are results from two different assays:

Liquid Volume % Generic Light Sweet Generic Heavy Sour
Gas (Initial Boiling Point to 99°F) 4.40 3.40
Straight Run (99 to 210°F) 6.50 4.10
Naphtha (210 to 380°F) 18.60 9.10
Kerosene (380 to 510°F) 13.80 9.20
Distillate (510 to 725°F) 32.40 19.30
Gas Oil (725 to 1050°F) 19.60 26.50
1050+ Residuals 4.70 28.40
Sulfur % 0.30 4.90
API 34.80 22.00

Table 1. Comparison Between Assays of Light and Heavy Crudes

Note that for this essay we are only concerned with a portion of the assay. The full assay would have information on metals concentration, salt concentration, vapor pressure, etc. What the two assays above tell us is that one is light (the higher the API gravity – a measure of density – the lighter the crude) and one is heavy. It also tells us that one is sweet (low sulfur %) and one is sour. Now, to be clear, a heavy crude can be sweet and a light crude can be sour. But refiners that are equipped to handle heavy crudes are generally also equipped to handle sour crudes, so that’s what they buy. Heavy sour is cheaper than light sweet, and there is more money to be made with heavy sour crudes as long as a refinery is configured to handle them. Gasoline doesn’t care whether it came from cheap heavy sour or more expensive light sweet; the product price will be the same in either case.

Now, back to the assay, and what the various categories mean. The way the assay is done is that the crude oil is boiled, and the amount boiled off at various temperatures is measured. This defines the various products, or cuts. When 99°F has been reached, the gases have been boiled off. This is the dissolved methane, ethane, propane, some butane, and some trace higher gases. This cut can end up being purified for sales, or it can end up as fuel gas to help satisfy a refinery’s need for steam.

The next cut is straight run, or natural gasoline. Gasoline is a mixture of hydrocarbons that are characterized by the boiling point, and the gasoline you purchase at the gas station will contain many different blending components. One of these will usually be light straight run gasoline. This cut will contain things like butane, octane, and every manner of branched and cyclic hydrocarbon that boils in a specific range. Most gasoline has been subject to additional processing (more on that later). The straight run gasoline is what can be expected to be distilled from the crude oil with no additional processing. Typically, straight run gasoline is not a highly desirable gasoline blending component, because the octane is usually pretty low. Nevertheless, the straight run gasoline does get blended into the gasoline pool.

The next cut is naphtha. You can do a couple of things with naphtha. You can blend it into gasoline, but the octane is even worse than for light straight run. Therefore, you are seriously limited on how much can be blended. More commonly, naphtha is fed to a catalytic reformer, which processes the naphtha and boosts the octane from less than 40 to greater than 90.

We then come to kerosene (also called “jet”), which starts to get into the range of diesel components. This cut also has more energy content per gallon than the earlier cuts, but is too heavy (less volatile) to be blended into gasoline. The sulfur components start to become more concentrated in these heavier cuts, so kerosene is typically subject to hydrotreating. In this step, hydrogen is added to the kerosene in a reactor to convert sulfur components into hydrogen sulfide, which is then removed. Kerosene has a number of uses. It is used as fuel for jet engines, and it is also blended into diesel. It is also used in some portable heating and lighting applications.

The next cut is distillate (specifically, No. 2 Distillate; kerosene is sometimes called No. 1 Distillate). Like kerosene, this cut contains sulfur and must be treated (as do all the heavier cuts). Distillate has two major end uses: as diesel fuel and as home heating oil. In fact, as seen in the assays above, a substantial portion of a barrel of oil ends up as heavy distillate. For the light sweet crude assay above, 32.4% ended up as distillate, and for the heavy sour crude 19.3% ended up as distillate.

We then come to gas oil, which is also known as fuel oil or heavy gas oil (distillate also being known as light gas oil). This cut is typically processed in a catalytic cracker to make cracked gasoline. By the name, you might guess that cracking involves breaking these heavy, long-chain hydrocarbons down into shorter hydrocarbons that boil in the gasoline range. The cracked gas is then blended into the gasoline pool.

The final cut, residuals, or just plain “resid”, is the cut of greatest interest when we talk about the economics of heavy crudes versus light crudes. Note in the assay above, that less than 5% of the barrel of light crude ends up as resid. However, the heavy crude yields over 28% resid. Resid is sold as asphalt and roofing tar, and is not a very desirable end product. Therefore, more and more refiners are installing cokers to further process the resid. A coker can take that resid and turn it into additional gasoline, diesel, and gas oils. The economics of doing this are typically very attractive, given the historical price spread between light oil and heavy oil. A coker can turn over 80% of the resid into valuable products.

Examples (For Illustrative Purposes Only)

Let’s compare two hypothetical refineries. Refinery A has no coker, and thus is restricted to either buying light crude, or buying heavy crude and selling a lot of low-value asphalt and roofing tar. So let’s say that Refinery A pays $55 a barrel for West Texas Intermediate. They will turn that barrel into 0.909 barrels of liquid fuel product (per the light assay above, 4.4% ends up as gas and 4.7% ends up as resid), which let’s say has a value of $80/bbl. They therefore grossed $80*0.909 – $55, or $17.72 a barrel before we consider the value of the asphalt and the gases. Historically, the value of asphalt has been very low – less than $0.10/lb. Given that our barrel of crude weighed around 300 lbs, and we got a 4.7% asphalt yield, the barrel yielded 300*0.047 = 14.1 lbs of asphalt worth $1.40. Let’s value our gases at the value of propane (about $0.14/lb on the spot market), and we get a value of 300*.044*$0.14 = $1.85 for the propane. Our gross profit (before operating costs, taxes, etc. are considered) is then $17.72 + $1.40 + $1.85, or $20.97 per barrel for the light crude.

Now consider Refinery B. Instead of buying WTI at $55/bbl, it buys a heavy Canadian crude for $38/bbl (this is an actual current price). Again, their barrel of oil weighs some 300 lbs, and as we can see from the assay above their resid yield may be in the range of 28%. So, of the 300 lbs, 84 lbs ends up as resid. But with our coker, we turn 80% of that into high-value products, and only 20% (16.8 lbs) ends up as low-value coke (a coal substitute). Therefore, the overall yield from the heavy crude amounts to the sum of the cuts up to resid (71.6%), plus the resid that was turned into products (80% of 28%, or 22.4%) minus the gas cut (3.4%) for a total of 90.6%. The overall liquid yield is almost the same as for the light crude, and yet we paid much less for the crude. So, our economics look like this: For the liquid fuels, we grossed $80*0.906 – $38 = $34.48 a barrel. This is almost double what we profited from with the light crude. We have slightly less propane yield than in our previous example. The value of propane is $1.43. Finally, we end up with 16.8 lbs of coke, which is worth only $0.015/lb (about $0.25 total). Our total gross profit then is $34.48 + $1.43 + $0.25 = $36.16.

This explains why so many refiners are rushing to install cokers. This is also why I don’t get too excited when someone comments that the build in crude inventories could be a build in “undesirable” heavy sour. Refiners don’t buy what they don’t need, so if heavy sour inventories are increasing then this is primarily coming from refiners that can process heavy sour.

As light sweet supplies continue to deplete, refiners will increasingly turn to heavy sour crude. But not enough refiners yet have a demand for heavy sour, so it trades at a significant discount to light sweet. This will of course change as more cokers are installed. There will be a higher demand for heavy crudes, and the asphalt market will become more lucrative as the asphalt supply gets rerouted to cokers.

Of course the caveat is that a coker is a major capital expense (hundreds of millions of dollars), and it is only part of the equation. I have focused here on processing heavy crudes, but not at all on sour crudes. The story is similar to that for the heavy crudes. Sour crudes trade at a significant discount to sweet crudes, and the refiners need additional processing equipment to handle them. But the economics currently favor installing the cokers and hydrotreaters to handle the heavy sour crudes, and will continue to do so as long as they trade at a substantial discount to light sweet crudes.

As always, comments, corrections, and questions are encouraged. Do note that while the examples above are approximate, they are not exact. There is more to the economics than what I have presented, but for the purposes of understanding some basic refining economics, this should suffice.

Additional Reading

Refining 101 at Tesoro
Basic Refining Overview
Petroleum Refining and Processing from the EIA
What is the difference between gasoline, kerosene, diesel fuel, etc.?
How Oil Refining Works

January 12, 2007 Posted by | assays, crude oil, economics, refining | 17 Comments