Fuel for America's transport needs

When groups such as OPEC try to predict the future demand for oil and petroleum products, one of the significant factors in that analysis lies in the demands of the US transportation sector. I have intermittently tracked those numbers, through the Vehicle Miles Travelled plot which the FHWA publishes each month, and here is the latest plot, which includes figures through last November. Bear in mind that this is a rolling 12-month total of miles travelled.

12 month rolling total of vehicle miles travelled in the USA (FHWA )

It is becoming increasingly evident that the plot has returned to a steady increase that has now been sustained at about the same rate as being maintained up to the earlier peak.

The question now comes, as evidenced by the remarks of London’s Mayor, as to how much higher the price of gasoline/diesel fuel will rise before it, once again, has an impact on overall growth. Overall growth was around 1.1% in November, up more than the annual average increase of 0.7%.

Driving is, to an extent, seasonally controlled, as this plot of the last three years driving, by month illustrates.

Travel on US Urban Highways by Month (FHWA)

Thus the bitter cold and poor driving conditions of the last couple of months may have had a negative impact on the overall totals, moving forward from the end of the plot, yet overall the recovery seems to be being well maintained.

This return to a higher level of demand is the subject of the front page comment on This Week in Petroleum which the EIA issued today (Wednesday). They note that transportation accounts for 72% of US petroleum consumption, at 12.9 mbd out of the current national total demand of 18 mbd. In the latest Energy Outlook the EIA has projected that GDP will grow steadily at 2.7% over the next 25 years, including a steady growth in transportation fuel use.

DOE projections for energy distribution (Energy Outlook )

As an aside it is interesting to note the EIA comment:

Although the situation is uncertain, EIA’s present view of the projected rates of technology development and market penetration of cellulosic biofuel technologies suggests that available quantities of cellulosic biofuels will be insufficient to meet the RFS targets for cellulosic biofuels before 2022, triggering both waivers and a modification of applicable volumes, as provided in Section 211(o) of the Clean Air Act as amended in EISA2007. The modification of volumes reduces the overall target in 2022 from 36.0 billion gallons to 25.7 billion gallons in the AEO2011 Reference case, equal to the AEO2010 Reference case.5

Well I don't think that is much of a surprise. In regard to more conventional ethanol production, it appears to have reached a current plateau at 0.9 mbd.

Turning to the more usual look at the charts, the anticipated decline in demand over the quarter has led to a drop in refinery activity.

Refinery inputs (EIA)

However the production of crude dropped even faster:

US crude oil production (EIA)

The difference has come from increasing imports. We will see whether this is a transient or more permanent change.



Retail gas prices now average $3.11 per gallon in the US (locally we are still hovering around $3.00), still a fair way below the $7.75 of the UK, but one wonders whether the steady ramp up in price will continue for another year or so, and if it does, what the consequences will be.

OGPSS - Venezuela, heavy crudes, API gravity and refinery gains

Because the world market is increasingly having to accommodate crudes that are heavier and less easy to refine into desirable, profitable products I thought I would revisit my discussion from earlier in the series about the limitation on global oil production, due to the need for suitable refineries to process the oil that is produced, before it can reach and be used by the ultimate customer.

I have covered the operations of refineries in the past, but this time I thought I would dwell a little more on some of the factors that relate to the type of oil that is being refined. It is perhaps timely to do so, given that China is moving forward with plans to construct a refinery that will process the heavy Venezuelan crude that, until now, has largely been sent to specialized refineries in the United States that are designed to handle it. In 2008 Venezuela exported 120 kbd of oil to China (out of a total of 1.89 mbd, of which the USA imported 1.19 mbd). This past year the flow to China is reported to have increased to 362 kbd. It might be noted that the recent diplomatic leaks known as the Wikileaks saga has revealed cables that suggest that China was getting some of this oil for $5 a barrel, and then selling it for more on the open market, including possibly to the USA. This could be quite possible since it is also reported that while Venezuela said it exported 460 kbd to China, Chinese figures put the volume this year at 132 kbd.

The largest supply of oil remaining in Venezuela is that in the Orinoco Belt, which the USGS has estimated holds a reserve of some 513 billion barrels. (Which, for reference is about twice the size of the Saudi Arabian reported reserve.) The problem with the oil is that it has an API of 9 degrees. Which is where I need to digress a little and explain to those not familiar with the term, what API gravity is, and the significance of a value below 10 degrees.

In the following explanation I am going to use a couple of examples taken from “Petroleum Refining in Non-Technical Language” by William Leffler, which has some clear descriptions that I cannot hope to improve on, in explaining some of these issues.

As I had mentioned in the earlier post, the crude that comes from the ground is a mixture of compounds of carbon and hydrogen with the compounds individually having roughly twice as many hydrogen atoms as carbon, and with the higher numbered compounds being heavier. As a way of characterizing the crude at this point, the American Petroleum Institute developed a measure known as the API gravity. The API gravity, which is expressed in degrees, is obtained from the equation:


If you recognize that the specific gravity of a fluid is the relative density of the fluid when compared with water (at 60 deg F in this case), then you will see that with an S.G. of 1, water has an API gravity of 10 degrees. Fluids, such as the Orinoco crude, with an API gravity of 9 degrees, are thus denser than water, and the scale is inversely related to density, so that the higher density fluids such as asphalt, have a lower API gravity (in this case 11 degrees) than lighter fluids such as light crude (36 degrees) and gasoline (60 degrees).

The initial separation of the different compounds in the crude is achieved by heating the crude to about 750 degrees F, and feeding the result into a distillation column, where the volatized fractions of the mix can be condensed back out and separated out on trays at different temperature levels. The hydrocarbon content can thus be characterized by the relative levels of fluid that condense out at different temperatures, and the product is known as a Distillation Curve for that crude. For example these are the basic curves for some of the heavy crudes from South America.

(Original Source OGJ Nov 18, 2002) I have added the temperature ranges in which the different fractions of the crude would settle out.

You can see that, there is not, initially, a lot of the lighter fractions available in these crudes., which are also because of this, more viscous and difficult to move around the plant.

To produce those higher fractions the refinery will first remove the lighter fractions, as described above, but then will further heat the remaining crude to the point that the heavier hydrocarbons break down into smaller molecules. Consider the case of the C16H34 Cetane molecule, which will break down into a combination of C8H18 octane molecules; C6H12 hexene molecules and C2H4 (ethylene) molecules roughly in the ratio of 50:38:12. When this happens the volume of the product will also increase. (I am taking this example, and the numbers from Leffler’s text).

The density of the original fluid was 7.2 lb/gal, it now breaks down into the smaller molecule hydrocarbons.

If we consider the original volume weighed 7.2 lb (1 gal) then 50% of that would become C8H18, which would weigh 3.6 lb. However octane is a lighter hydrocarbon that only weighs 5.9 lb/gallon, so that the resulting volume would occupy (3.6/5.9) 0.61 gallons.

In the same way the 38% of the original 7.2 lb would break down into the same weight of C6H12, some 2.7 lb, but hexene has a density of 5.6 lb/gallon. The resulting volume would thus occupy (2.7/5.6) 0.48 gallons.

And the third fraction would be the 12% that turns to ethylene, some 0.9 lb that would, at the new density (3.1 lb/gallon) occupy 0.29 gallons.

If one adds up the three “cracked” volumes the total is now 1.38 gallons, rather than the original 1 gallon, and this is how “refinery gains” are developed (illustratively) within the refinery. To keep the temperatures down during the cracking process it is generally carried out at a lower pressure than atmospheric, since this allows the fluid to boil at a lower temperature.

The heavier the crude then the more complex, and expensive the process of refining becomes. Often even to produce the original crude to the point that it can be pumped long distances, it must first be upgraded to a synthetic crude in an upgrader, located on site. It is this process that the Canadians have found a way to work around, though this is not yet the case with Veneuela. As a result as the different blocks of the Orinoco Basin are being developed, they only come into full production when upgraders have been constructed to handle the flow.

Given the need for considerable processing of the Venezuelan crude, which can also contain other contaminants such as vanadium., it is important to note that about the same time as the USGS was upgrading its figures for the Venezuelan reserve, that country and China were approving a $6-billion joint venture to build a 400 kbd refinery in China to handle that crude. Whether the crude is processed into a syncrude before shipping to China is not clear, but this is all part of the effort by Venezuela to increase exports. (The crude will come from Junin Block 4.)

Veneuela has contracted with a number of other country partners for production from other parts of the Orinoco Basin. Petrovietnam will help develop Junin Block 2, which is slated to have a production capacity of 200 kbd by the end of this year; Italy’s ENI has a target of 240 kbd starting to come on line in 2013 from Junin Block 5, though the refinery to process this into diesel for Europe won’t be built until 2016; Russia will partner in Junin Block 6 to develop 450 kbd at some unspecified date. In addition a combination of partners are to develop blocks in the Carabobo region, with a total production of 800 lbd, with the production to be on stream by 2013, though upgraders for the crude won’t be ready until 2017. The Chinese involvement has now been approved, with a performance period of 25 years, and further the Chinese have agreed to develop Junin 1 and Junin 8 at 200 kbd each, for a grand total of 800 kbd, which will require a $40 billion investment. Should all the investments that Venezuela envisages come to pass, then they anticipate that the country could be producing 7 mbd by 2021.

It is worth noting that the Junin 1 block was supposed initially to be developed by Belarus, but that fell through. However, in a four-party deal, Venezuela has agreed that it would send some of its crude to the USA, if Azerbaijan agreed to send an equivalent amount of its oil to Belarus. Azerbaijan is increasing production and has just reached the 1 mbd mark.

Whether Venezuela will reach the levels of production anticipated, or at the rate anticipated, is still, of course some matter of debate, but it does explain where some of the more Cornucopian projections acquire some of their statistics.

This week's TWIP and record world demand for oil

Te EIA released their “This Week in Petroleum” today, with an article on American demand over the past year plotted by month. I had not seen the data presented that way before, and since you may not have, either, here it is:

Change in overall demand in the USA (EIA )

It is spread over two years so that you can see that demand bottomed out in May 2009, and has been rising ever since. As they point out, a growth of almost 1 mbd over last year is a very significant increase in demand, which just about offsets the similar sized drop in demand back a couple of years ago as the crisis began to develop.

If one notes that the plot ends in September, and then goes to the refinery input plot for this past week, that too is kicking up significantly, though at only about half the earlier gain y-o-y.

UPDATE: Because of these evidences of continued rising demand, the IEA has just raised its forecast of demand for next year by another 260,000 bd to 88.8 mbd.

Though in the period between these two points the input reverted to close to being the same as last year.


Gasoline demand does not show as high an increase, with most of the increase in production going into distillates.




That steady increase is a little odd, except that is being used to keep stocks up, given that demand has suddenly dropped off:

(The above figures are from today’s TWIP

At the same time ethanol production has steaily continued to climb to the point where it has now set a new record at 0.939 mbd.


Elsewhere in the world Wood Mackenzie is noting that we appeared to have returned to consumption levels from before the recession. In fact a new record has been reached:

Worldwide oil demand for this year’s third quarter will set a record at 88.3 million b/d, said Wood Mackenzie Ltd., Edinburgh, in its latest analysis. 

According to the report, provisional data shows that global oil demand for the recent quarter will almost certainly exceed the previous highest quarter—the fourth quarter of 2007—when demand averaged 88 million b/d.



Just 3 years from the onset of the great recession, global oil demand has recovered to the pre-recession peak seen in 2007, the report said.

The IEA is predicting that this new level will be close to the average demand for the whole of 2011 but it may be that those predictions are already behind the times.

Assuming that this is the case, then the talk of seeing crude over $100/bbl in the near future is likely to become more true than less. Not that this will cause much concern among the OPEC ministers soon to meet in Ecuador, and certainly it is not going to be a concern if, as Lybia’s minister predicts, oil reaches the $100 figure. Should that occur it might be that quotas get loosened a little, but that is unlikely to occur before the next meeting next June. Which might suggest that the projection of $100 oil may be exceeded quite a bit sooner than most people think. There is, after all, only so much oil still stored around the world in tankers.

OGPSS - Some limits to oil fungibility

This is the second in a series I am just starting on oil production and consumption around the world. While it is going to focus more on individual nations and oil fields, over time, there are some general remarks that I want to use to preface the series and this is one of those. (OGPSS – Oil and Gas Production Sunday Series).

One of the first things that I was told when I started looking into whether there was a coming crisis in oil supply was that oil is fungible. What that meant was that if, for the sake of discussion, the Saudi Arabian government cut off oil supply to the West, then the West could turn around and buy an equivalent amount from somewhere else (it turned out to be the North Slope and the North Sea) and the world could continue on its merry way. In fact if you go to Merriam Webster oil is cited as an example of a fungible commodity.

being of such a nature that one part or quantity may be replaced by another equal part or quantity in the satisfaction of an obligation:- oil, wheat and lumber are fungible commodities.

But that assumption is not totally true, and in the world where matching production to demand is becoming a somewhat more difficult and expensive operation the limits to the fungibility of oil may soon become more evident.

One of the reasons for this is that, with some increasingly rare exceptions, one cannot drive up to an oilwell and fill the tank with the flow out of the ground, and then drive happily off. Crude oil is a mixture of different hydrocarbons. (Morgan Downey explains this is more detail in “Oil 101”, and I will refer to that book a number of times as this series progresses, it sits on my desk.) Hydrocarbons are a combination of hydrogen and carbon atoms in different combinations, but with very approximately, twice as many hydrogen atoms as carbon. As the number of carbon atoms increases one moves from the simple light compounds such as methane (CH4) to the more complex heavier fluids that get down to residual oils ( 29 to 70 carbons) and bitumens (above 70). Because the different components of the oil have different uses, the different fractions of the oil are separated out for individual use at a refinery. The quality of the crude is generally expressed by the API gravity, of which more in a later post.

Typical crude oil fractions

Because the different oilfields of the world produce oil with different combinations of hydrocarbon compounds, and with varying levels of other contaminants, such as, for example, sulfur, it is not always easy to switch the oil supply coming into a refinery from one field to that from another. The EIA has plotted the increase in sulfur content coming into US refineries. As the crude becomes heavier and contains higher sulfur content, so the refining process becomes more complex and expensive.


For many years, for example, the heavy, high sulfur, crudes produced in Venezuela were shipped to refineries in the United States that were designed to refine the oil to the desired products. Other refineries, geared to refining lighter sweeter (i.e. lower sulfur) crudes cannot accept very much of the Venezuelan oil and blend it into their process streams, since even to get to an intermediate crude they would need to include a higher quality (and more expensive) lighter crude in the blend. Thus when there was a strike in Venezuela in 2002, and the world lost 3 mbd of oil production, there was only a limited flexibility in the way that the affected refineries in the United States were able to resolve their supply shortfall. (And in those days it was possible to increase Mexican supply to help out).

Venezuela is one of two countries (Canada being the other) with a significant production of synthetic crude from the heavy oil sands in that country. These are a more extreme case of the need for special refineries, since in both the Canadian and Venezuelan case the heavy oil must first be treated at the site to upgrade it to the quality of a conventional crude, before it can be sent to a conventional refinery. (I briefly discusses that refining in an earlier Tech Talk). This established a secondary limit on how much oil can be produced from those deposits at one time. Some time ago I visited the Oil Sand operations in Alberta, and was there on the day that the new Upgrader facility was shut down because of the escape of some of the gases from the process. I could smell a faint odor of “cat pee”, but nothing near the smells from many other processing plants of varying nature that I have visited over the decades. Nevertheless the new section of the plant was shut down for months until the problem was solved, removing over 100,000 bd from the market.

More recently the difference in price between heavy crude and light has reduced, to the point that the Canadians are no longer going to increase the size of the upgraders in the Fort McMurray area, but will instead be shipping the bitumen to eager customers. This does require some additional technology:

Under the new timeline, which was disclosed yesterday, Syncrude will lift production to 425,000 barrels through debottlenecking, and add a further 115,000 per day of bitumen production. Both expansions are expected by 2020.

(With additions to its mining operations, Syncrude actually plans to extract 600,000 barrels a day of bitumen by 2020, but barrels that go through its upgrading process actually shrink in size, resulting in a total output of 540,000.) Bitumen on its own is too thick to flow through a pipeline: at room temperature, it has the consistency of old molasses. But Syncrude plans to employ a new system that uses a solvent to remove what Ms. Fisekci called the "nasty" part of the bitumen. That system, which Syncrude operator Imperial Oil also intends to use at its Kearl oil sands mine, will allow the bitumen to flow without needing to be upgraded.

This will reduce the current bottleneck in production, which lies with the upgrader capacity, since it is only after the crude has passed through them, that it is able to flow easily through the pipelines to the conventional refineries. That change is not yet being considered in Venezuela, where the syncrude is now counted, by the EIA at least, as part of overall production.


The graph from the EIA highlights another consideration as I move to discuss the global trade in oil. That is the rising consumption within the country, a phenomenon that Jeffrey Brown (Westexas) introduced us to as the Export Land Model back in January 2006, since, with declining production it accelerates the reduction in net exports, as the Venezuelan case now illustrates.

I’ll close today with one last point on the limits of fungibility. There are certain oilfields where the contamination of the crude is such that special refineries are needed to process the oil. The most outstanding of these is the oilfield at Manifa in Saudi Arabia, a subject I have been writing about for over five years. The problem with that production, which was initially slated to be in production next year comes from the need for special refineries to process the oil (an extreme case of the earlier condition I described). The plan was that two refineries would be built in Saudi Arabia to handle the initially 1 mbd of planned production, which by last March had dropped to 900,000 bd. One of these is being built by Total at Jubail, though it is interesting to note that the refinery is now scheduled – in its 400,000 bd capacity – to also receive oil from the more conventional field at Safaniya. It is now anticipated to open in 2013. A second refinery at Yanbu will also take 400,000 bd. Aramco will then build a new refinery at Jazan, with a capacity of 400,000 bd starting in 2013. But until those refineries come on line, unless the Saudi’s and Chinese work out a deal (not beyond the bounds of possibility) that oil will stay in the ground.

The above is intended to show is that there are constraints outside of just having oil in the ground, and a ready customer, that preclude immediate sales and satisfaction. As this series develops I will be highlighting some others.

More on refining

Last week I pointed out that the crude oil that comes out of the ground is not made up of a single hydrocarbon, but rather is a mix of different hydrocarbons that have to be separated. And oils from different parts of the world are formed as different combinations of these, and even those from the same country have different properties. Today I would like to go a little further and talk about distillation curves, and because the world supply is changing to heavier crudes then go on to explain a little bit about what is involved in cracking a crude. It is a little more immediately relevant than some posts given that researchers at Purdue have just come out with a suggestion for an improved refining sequence that they claim could improve efficiency by between 6% and 48% depending on how the process sequences in the refinery are re-ordered. And the crude doesn’t have to come out of the ground. NIST have even tested some made from pig manure, with video.

For those new to the site this is where, on weekends, I post a small technical talk, explaining some of the aspects of the fossil fuel business, so as to help understanding of some of the topics on the site. It is a very simple explanation, because of space, and those who wish to ask or expound a bit more are invited to do so through the comments.

When you first get a sample of a new oil, then you will gradually heat it to known temperature levels, generally following a standard method or something more advanced. As the sample is heated, the lighter fractions boil off first, and by plotting the volumes emitted within known temperature ranges, a basic sense of the make-up of that particular oil can be achieved.



Example of two distillation curves from different types of oil

For example, of one looks at the blue line in the above graph, this shows a typical light oil composition, and might well yield, on passing through the first distillation column of a refinery, the sort of separation that I showed in the plot last time.

Distillation products from light oils (Source EIA)

However, as is slowly becoming apparent, we are seeing less of these light oils on the market, and increasingly the world is having to accept a greater proportion of heavier crudes. To understand the difference that this makes, consider the red line in the above graph.

You can see that there is no fraction boiled off until the temperature has passed 250 deg. Which means that, in its untreated state, there is no natural gasoline in the oil. Likely it was too close to the surface and those fractions evaporated away over the millennia (as is the case with the heavy oils in Alberta for eg, though this example is from somewhere else). So how do we change this mix into something more useful?

The answer, not only for this crude, but also for the heavier fractions of the light crude, since in both cases we would like to end up with about 45% gasoline, requires that we crack (or split) the higher carbon molecules into lighter or lower carbon ones. For example say we have a molecule of Cetane (16 carbon and 34 hydrogen atoms or C16H34) if we heat this to a high enough temperature, then we can break it down into some Octane (C8H18), some Hexane (C6H12) and some Ethylene (C2H4). But, obviously, what we would like to do is to control what it is that we break these heavier molecules into, and how much of each we produce.

And so we get into the world of Cracking Oil. After the crude oil has been separated into the different fractions, the gas-oil fraction is then fed to a second heating process, where the fluid is brought back up to a high temperature (perhaps around 735 deg C 1400 deg F) and mixed with a finely powdered catalyst (hence the "cat"). Steam is also added to help with the movement of the mix, and the combined mix is fed up a pipe (called a riser) into a tank and as it flows up and into the tank the gas-oil breaks down into the lower carbon molecules. This happens very quickly, so that by the time the mix is in the tank, the heavy molecules have broken down, and so can be drawn off.

However the catalyst has first to be removed, which happens by passing the flow through cyclones that spins the flow and separates the heavy catalyst, which is collected and fed down a pipe back to be reclaimed and re-used. It needs to be processed since, in part, the process is not perfect and carbon will be deposited on the particles of catalyst, blocking its action. (It can be burned off - providing some of the heat for the process). The catalyst can then be re-used. One operation might use the catalyst at a flow rate of some 55 tons/minute.

The hydrocarbons that flow out of the cracking process are then separated into different fractions, depending on the season more gasoline or distillate might be desired, but the process might yield about 8% coke, 55% gasoline, and 12% light gas oil with about 10% of the flow being a sufficiently heavy product that it is sent back to be run through the process again. Light gas oil becomes diesel and furnace fuel oil. The lighter gas products are usually sent to alkylation, or reforming where the lighter molecules can be combined to give products that can be blended into a gasoline or another desired product.

Different crudes have different mixes of hydrocarbons, and will need different sizes of processing sections that convert these different fractions to usable and desirable products. Refineries have been built to usually handle only a given range of crudes, and thus have to be considerably modified if that mix should change. Sometimes the crude can be even heavier, the sands in Alberta contain an oil which is more conventionally called a bitumen, since it has less volatile material that the heavy oil example I used. That oil must therefore go through an additional step to produce the lighter synthetic oil that can then be distilled and cracked more conventionally. Some of the new processes involved in mining and processing the ore are described in a pdf file by Herron. It also includes the distillation curves for the original crude and that obtained when the THAI process is used.

Distillation curves from the Athabasca Oil Sands (after Herron)

There are also contaminants such as sulfur that can be found in the oil. If the content is higher than 2.5% then the oil is called "sour"; this sulfur must be removed, and while at one time it was used as fuel in the refinery that has been stopped and now it is recovered. That also requires a treatment circuit that must be installed if the mix to the refinery changes.

This is part of an ongoing weekend series on technical aspects of oil and natural gas production, among other things. As ever, if this is not clear, or if there is disagreement then please feel free to post, and I will try and respond.

Some new vehicle travel numbers

As I sit waiting for “This Week in Petroleum” to update I wandered over to the Federal Highway Administration to see if the latest Traffic Volume data was available. And it is, with the numbers for December 2008 just having been posted. The reason for the interest can be seen in the plot of miles driven, that they provide, and this is the new one:

Source FHWA

It actually looks a little more fearsome than it is.
UPDATE: The TWIP information has been added.

The data plotted above is a 12-month rolling average, and when you look at the individual month data, and use the urban highways plot as representative (the argument also holds for the rural and total) you can see that driving started to drop last December relative to 2006. Through all of last year it has been down relative to 2007, but with the December figures we are starting to stabilize, and come closer to the previous years figures.

Source FHWA

In fact if you look at the regional plot, the Northeast is slightly up on last year, and most of the other regions are not down much (relative to the previous drops of around 5%).

Source FHWA

So this may mean that for most of us the situation may be stabilizing (sorry West Coast, not you yet). Now this data is still a couple of months old, and it shows that the drop is still going on, but demand for fuel may be leveling off.

Added: A little late today, the TWIP now is up, let me add the two plots from this week that I have been looking for. The first is the demand curve. Now we know from the second figure that driving started its dive last December, so the comparison is with what was already turning into a drop, but if you look at this week’s gasoline demand:
Source EIA TWIP

Then you can see that current demand, which equated to the same number as this time last year last week, has just risen above it this week based on four-week averaging. However if you look at the tabulated numbers the week saw a drop of 100,000 bd on average, which is down 200,000 bd on a year ago.

Source EIA TWIP

Which takes up back to see what is going into the refineries, and this is still paralleling the drop of last year. It is currently about 300,000 bd below last year’s figure.
Source EIA TWIP

Gas prices have now been rising for 3 weeks, while home heating oil prices have been falling for five weeks. But even as refinery input bottomed out at this time last year, so it appears to be doing the same again this year, although we may have to wait a week or two to see a clearer trend.




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