Paper presented at the 2nd International Chemical Downstream Conference

Mumbai, 29-30 January 2015

Paper presented at the 2nd International Chemical Downstream ConferenceMumbai, 29-30 January 2015

Let us start by looking at the factors determining the price of crude oil. This slide uses the economist’s approach of comparing supply and demand curves. The horizontal axis indicates increasing volumes of crude oil in the world.

The supply curve S shows the increasing amounts of crude oil that would be supplied as prices rise. Much of the oil in the Middle East can be extracted at a cost of $20 per barrel or less, covering exploration, production, processing and transportation. OPEC countries outside the Middle East generally have higher extraction costs. The spotlight recently has been on US production costs of non-conventional oil. Supplies from fracking can vary between $40/bbl and $90/bbl depending on location and the nature of the rock strata. Production from tar sands, as in Canada, can require more than $100/bbl to cover all costs, including processing and transportation (though new in situ steam injection technology might bring the cost down to $65/bbl).

The demand curve D shows that more and more oil will be consumed as prices fall. Some industries, such as the chemical industry, are so dependent on petroleum that very high prices could be entertained if necessary. Other uses can flourish only with lower prices (gasoline, heating) given competition from other energy sources. When prices get low enough, oil can compete with other energy sources, for example coal or natural gas for electricity generation.

The Figure is a stylised representation, showing step changes rather than a continuum of costs and prices. This helps to understand that the curves can change with time. As sources expand or contract, the horizontal lines can lengthen or shorten. As costs change, the vertical lines can shorten or lengthen. The horizontal line marked “U.S.CHEAP” has clearly become longer in the last few years as oil from fracking in the USA has expanded.

The market is equilibrated where the supply and demand curves cross. As this point the price is equal to the marginal cost of production, that is, the cost of supplying the last, highest cost barrel of oil. It is also equal to the marginal benefit of consuming oil. The last barrel confers benefits that just barely cover the cost of acquiring it, compared with switching to another energy source.

The Figure indicates that the market should equilibrate at around $65/bbl, being a level intermediate between low cost and high cost of production in the USA. This is a position that should apply over the next few years. But remember that the horizontal and vertical lines can expand or contract depending on technology changes and new discoveries (affecting the vertical lines), but also as a result of conscious decisions to restrict supply or to encourage non-conventional oil (affecting the horizontal lines).

[Tecnon Orbichem thanks Fred Peterson of Probe Economics for this and the next three Figures.]

But why are we talking of crude oil at $65/bbl longer term (and seeing still lower prices in practice recently), when for much of the period from early 2011 to late 2014 crude oil prices were around $100-110/bbl? What has changed?

One factor is that demand has been contracting (or growing less than had been planned for) with slow or zero economic growth in Europe and Japan, and a slowdown in growth in China and the other BRICs. So the steps in line D have been shifting to the left. For some time this has been balanced by a shift of the S line steps to the left, in particular through the “Adjustment of Production” that has been undertaken by Saudi Arabia to stabilise world markets. The Figure shows the position over 2011-late 2014 when such adjustment enabled prices to hold at about $100/bbl.

Then, at the OPEC meeting in November, Saudi Arabia decided it would no longer cut back its own production to try to stabilise the market, since it was getting no support from other OPEC members or other oil producing nations. Saudi Arabia decided to defend its market share rather than the world price, meaning that the market would be allowed to find its own level freely. Reasons for Saudi Arabia to take this stance (in addition to frustration at lack of support from other producers) include:

• Forcing high cost US producers to curb production (contraction of theU.S.EXPENSIVE line in the Figure)

• Punishing Iran, which needs a very high crude oil price to balance the nationalbudget, for its support of Shia insurgencies

• Punishing Russia, which also needs a high crude oil price, for its support ofPresident Assad of Syria

• Concentrating the minds of other OPEC producers on the need for productioncuts.

It can also be mentioned that its availability of huge currency reserves will enable Saudi Arabia to endure low oil prices and a negative state budget for several years if necessary.

The effect is seen in the Figure. Falling world demand (the D line steps moving to the left) has not been compensated for the moment by any shift of the S line to the left. Consequently the cross-over point has moved down to about $50-55/bbl. (The Figure is stylised: the actual glut is smaller than shown.)

However, there are signs that the first of the objectives of Saudi Arabia listed above is being achieved. New fracking well drilling in the USA is set for contraction in 2015. The U.S. land rig count fell by 250 rigs, or about 15 percent, between mid November and mid January. The oilfield services company Schlumberger announced that it will cut 9,000 jobs, or about 8% of its workforce, and similarly Baker Hughes and Halliburton plan to cut thousands of jobs. Meanwhile the oil majors have announced substantial curtailing of capital expenditure for this year ---Conoco (by 33%), Occidental (by 33%), Chevron (by 13%), Shell (by $9bn), ExxonMobil (by $5.5bn), and Total ($4bn). The effect of these cutbacks in expenditure on exploration and production could well be to raise crude oil prices to around $75/bbl during the course of the next 2-3 years.

The factors mentioned in conjunction with the previous Figure will take many months to take effect, but decisions to cut or expand the flow of oil by producers can have a more rapid effect. The Figure above illustrates that short term demand D is not likely to change much during the space of a few weeks or months. Automobile drivers will be thankful for the fall in gasoline prices from $4 to $2 per US gallon, but they are unlikely to start driving for longer distances, at least not short term. However, as a result of Saudi Arabia deciding to increase supply, moving the supply curve from S-1 to S-2, the crude oil prices collapsed, touching a low of $45/bbl (Brent), as shown by the red arrows. A reverse action, by a change in policy of some leading OPEC members, could send prices shooting back up to $100/bbl, though this does look extremely unlikely for the present.

Later on we shall be examining the effect of the fall in crude oil prices -- a move to the left along scale C -- on ethylene and propylene production, but this effect gets transmitted through the medium of naphtha or ethane. The Figure illustrates the inter-relation between pricing of these feedstocks. Naphtha, crude oil and heavy fuel oil prices tend to follow each other, such that a vertical line crossing scales A, B and C will give a fairly accurate indication of market prices of the three at a given moment. However markets do not necessarily always have the same balance and there can at times be some deviation from the usual correlation that a vertical line would indicate. As regards heavy fuel oil and natural gas, there is correlation between scales B and D is some parts of the world, including Europe and Asia, by decisions to price natural gas at its $/mmBtu equivalent to heavy fuel oil, but in other parts of the world, especially the USA and the Middle East, there is no correlation at all. As regards ethane, its pricing shown in scale E has at times been in line with the $/mmBtu pricing of natural gas, from which it is derived, but as we shall see, the pricing of the two can deviate widely at times. As regards propane, its price tends to track naphtha on scale A but with a small discount as shown by scale F in Europe and Asia (but a big discount in the USA and Middle East) so is normally not correlated with scale D for natural gas. In summary, a vertical line in the Figure can be helpful in correlating the prices of different feedstocks as crude oil prices change, but one has to be aware of the exceptions and deviations that occur.

This Figure illustrates the cash production cost of ethylene generated for a model of a medium sized naphtha cracker, according to the prevailing cost of naphtha on scale A. Clearly this is an idealised representation, since the vertical position and the slope of the line depend on many variables, but a single line will serve our purposes for the moment. One variable we should mention is the value of the propylene co-product. For the present we assume that the propylene price accorded by the market is equal to the ethylene price.

Next, however, we allow for the fact that the propylene and ethylene prices may not be equal. The Figure shows the effect on ethylene production costs of the value of the propylene co-product. If the market price of propylene is only 0.7 times that of ethylene (as used to be the case 20 years ago), then ethylene costs are as shown by the top sloping line. If the propylene to ethylene price ratio rises, the ethylene cost falls. If the propylene price were to rise to 1.3 times that of ethylene, the cost of ethylene production comes down to levels represented by the lowest sloping line.

In this Figure we have taken the model naphtha cracker used in Slide 6 and represented the situation in May 2014, before crude oil prices started sliding. At that time crude oil prices (Brent) were around $110/bbl and naphtha prices in Europe and Asia were in the range $945-980 per ton, as shown by the column. Ethylene production costs were therefore at a level represented by the black dot, slightly higher in Asia where propylene prices were slightly lower than in Europe. The horizontal line indicates that the spot ethylene import prices into North-east Asia at that time were around $1440/ton, so were barely covering cash costs of production. (In practice a range of prices were to be found, with contract prices in Europe higher and spot pipeline sales lower. We will base the arguments on the spot import price of liquid ethylene in North-east Asia as being the most transparent.)

Now we look at the situation in December 2014, when crude oil prices had fallen to an average of $65/bbl for Brent (actually around $75/bbl at the beginning of the month but down to about $55/bbl by the end of the month). The naphtha price averaged $550/ton and is represented by the column in the Figure (but again started the month higher and ended the month lower, the Figure shows just the mid-month position). The black dot shows that the spot price for liquid ethylene imports into North-east Asia was somewhat higher than the production cost of ethylene for our model medium sized naphtha cracker.

Now we look at the cost of production of ethylene from ethane. The lower line shows the cost of production according to the price of ethane as shown in scale E. In May 2014 the price of ethane in the USA was 29 c/gal or $215 per ton. The vertical double-headed arrow shows what a huge advantage ethane-based producers had over naphtha based producers, in the USA or elsewhere, at that time. The solid bar indicates the range of ethane prices that applied over March to July 2014 and throughout this period production costs of ethylene from ethane were some US$1,000/ton lower than costs from naphtha. Scale E has been set so as to be equivalent to scale D if ethane is priced at its heat value in $ per mmBtu. But is this how ethane is priced? Not necessarily, as we shall see in the next slide.

This Figure compares the price of ethane and natural gas in the USA, both expressed in $/mmBtu. There have been times when ethane has had the same price as the natural gas from which it is derived, including the mid-2014 period considered in Slide 10. At those times ethane has been in surplus and could command no more that its heat value on the market. In contrast there have been times when the ethane price has been far higher than its heat value, for example in 2011. In that year ethane prices were for the most part around $12/mmBtu or 78 c/gal or $580/ton. A glance at Slide 10 shows that ethane-based ethylene was still cheaper to make than naphtha-based ethylene based on $1000/ton naphtha, as it was at that time.Today ethane is being sold at below its natural gas equivalent heat value, to the point that serious consideration is being given to use it in gas turbines for electricity generation. The reason is the need to remove much of the ethane content of wet gas to bring the natural gas within its specification for pipeline transport. There is an over supply in the USA at present of natural gas produced from fracking, and a still greater over-supply of ethane as a result. Much of the natural gas being produced is a side product of fracking wells drilled for the sake of shale oil, so tends to be wet gas.This situation will persist for some time, as the next Slide illustrates.

This Figure compares the capacity to produce ethane with the capacity to consume in the USA. The capacity to produce ethane is shown by the black line, which takes account of the many projects that have been announced to extract ethane from the mounting supplies of wet gas coming from fracking operations. The left column for each year shows the ethylene capacity based on ethane in the USA, allowing for the nine projects that have been announced, while the right hand column is the corresponding capacity to consume ethane. It is seen that the capacity to produce was barely sufficient to cover the capacity to consume in 2012, which accounts for the tight supply and high prices for ethane in 2011-2012 that we have seen in Slide 11. Conversely from 2013 onwards there is an increasing surplus of ethane, which is reflected in the very low price for ethane being seen at present, which is likely to persist for some years. The surplus is sufficient for a number of projects to have emerged to export ethane, and several companies around the world have signed up for long term ethane supplies from the USA, including Ineos, Sabic, Borealis and Reliance.All these projects were announced before the collapse in crude oil prices and the resulting reduction in competitivity of ethane compared to naphtha. However ethane retains an advantage, albeit reduced, and most of these projects are likely to go ahead, as the next Slide indicates.

The Figure illustrates the situation in December 2014 but can be used to represent the situation for many months to come, if crude oil prices remain not too distant from $60/bbl. Natural gas prices in the USA are likely to be in the range $4 – 5 per mmBtu (they are currently much lower) with ample supplies from fracking operations. The Figure shows that, if ethane is priced at its heat value of $4 – 5/mmBtu, then the production cost of ethylene from ethane crackers will be in the range $300-400 per ton in the USA.Ethane will be exported from the USA to cracker operations in Europe and Asia. If the ethane is exported at a price of $4 - 5/mmBtu fob its cost at destination crackers overseas is likely to be in the range $7.00 –8.50/mmBtu. The corresponding cost of production of ethylene in those overseas crackers will be in the range $500-600/ton. The Figure shows that, if naphtha is at $550/ton, corresponding to crude oil at $60/bbl, the overseas ethane crackers will still have lower production costs of ethylene to the extent of $200/ton or more compared to naphtha crackers.Of course ethane prices could become detached from natural gas prices in the USA, and the Figure shows that if they were to rise to $12/mmBtu the ethane crackers would lose their advantage over the naphtha crackers, both producing ethylene at a cost of $800/ton. Whilst this is not impossible, it is very unlikely, as Slide 12 has shown that ethane prices are likely to remain in line with natural gas prices for years to come.

The last few Slides have shown a single line to represent the production cost of ethylene, but Slide 7 reminds us that the slope of this line depends on the propylene to ethylene price ratio. What is the likely range of values for this ratio?The Figure compares propylene and ethylene prices in Asia, actually the contract prices in Taiwan. In the period 1999-2001 the ratio was about 0.7, a reflection of the traditional view at that time that propylene had by-product status. But that changed in subsequent years, such that from 2002 onwards the propylene price has been little lower than ethylene price and often equal to it. Indeed for most of 2011 propylene prices were higher, giving an average propylene to ethylene price ratio of about 1.05 for that year, but by 2013 the ratio had come down again to 1.00 and in 2014 it was once again below 1.00. It has been widely predicted that world propylene markets will become tighter than ethylene, because of the switch in production in the USA (and later elsewhere) of ethylene towards ethane crackers (with virtually no propylene co-product) and away from naphtha cracking (the main source of propylene). In that case the ratio would probably go back above 1.00. However the recent fall in crude oil and hence naphtha prices may mean that such a prediction is no longer credible.

This Figure is a return to Slide 13 but now allowing for the effect of propylene co-product value on ethylene costs. The commentary to that slide, where the propylene to ethylene price ratio has been taken as 0.93, stated that if “ethane prices ….. were to rise to $12/mmBtu the ethane crackers would lose their advantage over the naphtha crackers”. The present Figure shows that this conclusion must be modified if a different ratio applies. Indeed if the ratio were to rise to 1.3 (a rather unlikely scenario) the ethylene production cost comes down to not much above $600/ton and ethane can not cost more that $10/mmBtu without losing competitivity with naphtha. This is a rather extreme example, but it does illustrate that naphtha crackers in Europe and Asia can reduce their disadvantage compared to local ethane-based crackers using imported ethane by maximising the price of propylene relative to ethylene that the market will bear.

Naphtha crackers are the main source of propylene, but there has been increasing interest in propane dehydrogenation as an alternative source. On international markets propane prices have been priced at about 10% below naphtha when expressed in a $/mmBtu basis in recent years. This explains the interest in building propane dehydrogenation units in Asia. In the USA propane prices have become de-linked with naphtha prices for the last three years, averaging around $10/mmBtu until a few months ago, so there has been a still greater interest in propane dehydrogenation, with seven projects under way in the USA and one in Canada. The much lower price of propane in the USA compared to international prices results from its ready availability from wet natural gas from fracking operations.

This Figure represents the basic scheme of a propane dehydrogenation unit. The off gases are utilised in plant and provide most of the heat (steam) required. The hydrogen by-product can be recovered to obtain a credit.

The Figure compares the market price of one ton propylene in Asia, taking Taiwan as the example, with the cost of the 1.20 tons of propane required to make it in a dehydrogenation unit (somewhat less than 1.20 tons is claimed by technology providers). The gap between the two is examined in the next Slide.

This Figure plots the price of one ton of propylene and 1.20 tons of propane in Taiwan over the past 13 years. The gap between them is plotted as the black line. The cost of dehydrogenation, in addition to that of the 1.20 tons of propane, is about $150 per ton of propylene, as represented by the horizontal line. All times when the black line lies above the horizontal line would have signalled when a propane dehydrogenation unit would have shown positive cash flow. Although there have been moments when cash flow would have been negative, on average over the past ten years such a unit would have generated around $200 of positive cash flow per ton of propylene, or about a 13% EBITDA. Expectations until recently were that the gap was due to expand. The next two slides analyse this expectation.

The situation for propane dehydrogenation in Europe or Asia before the recent crude oil collapse is illustrated in the Figure. The vertical column indicates the price of naphtha as read off scale A and at the same time the price of propane read off scale F. The Figure represents prices as they were in May 2014 but are fairly representative of prices in the previous two-three years. Propane prices in Europe and Asia were about 90% of naphtha prices at that time and have generally been in that relation over the past four years, as we saw in Slide 16. The black sloping line indicates the cost of production of propylene from propane, whose price is assumed to be at 90% of that of naphtha.The Figure indicates that under the conditions of May 2014 (and previously), propylene could be produced about $150/ton more cheaply via propane dehydrogenation than from a naphtha cracker, and generate a cash flow of around $200+ per ton for spot sales in Asia. The expectation at that time was that these margins would continue into the future, and indeed improve. The reality is shown in the next Slide.

In this Figure we see the situation in December 2014, after the collapse in oil prices, which, however, had still not reached bottom. Now we see that propane dehydrogenation has lost its advantage over naphtha cracking. Indeed spot prices of propylene at that time had plummeted to below the cash costs of either route. However December 2014 was a very volatile month for propylene pricing and the cost of naphtha and propane had sunk further by the end of the month, so the apparent loss was maybe not so severe as indicated.This and the previous Slide represent the position in Europe and Asia. The situation in the USA is quite different, with much lower prices for propane (about $420/ton in December 2014), but the conclusion is the same, namely that the gap between propane dehydrogenation costs and naphtha cracking costs for propylene has narrowed drastically. Propane dehydrogenation is still viable in the USA, but no longer for the moment in Asia and probably the projects there that have not got off the ground yet are unlikely to be realised.

Returning to ethylene, there has been much discussion recently about the use of ethylene generated from ethanol from bio-sources, to make sustainable polyethylene and ethylene glycol. This Figure indicates that, while bio-ethylene could be produced more cheaply from certain bio-materials (i.e. sugar) in certain countries (e.g. Brazil, India) than petro-materials before the crude oil collapse, by December 2014 that advantage had been lost. It could take several years before crude oil prices have recovered to the point that bio-ethylene becomes economically viable --except for applications where a premium price for ethylene derivatives is acceptable.

We now examine how low crude oil prices will affect the inter-competitivity of various petro-based and other materials. First we compare HDPE and PVC. The Figure illustrates that HDPE production cash costs escalate more rapidly with rising crude oil prices than do PVC cash costs. This is partly explained by the fact that only half the VCM molecule consists of hydrocarbon. The straight lines shown for VCM and PVC costs represent a considerable simplification, in that it is assumed that the cost of chlorine is 1/2.1 or 47% of the cost of production of the Electrochemical Unit (ECU). In practice, while this division of costs by mass balance is often used for internal accounting by integrated companies, the market price for chlorine can vary widely from this calculation. Nevertheless market behaviour indicates the validity of this approach, as seen in the next two Slides.

This Figure traces the prices of HDPE and PVC in North-east Asia over the past 15 years. During the years of very low crude oil prices at the beginning of this period, the gap between the two was almost zero, as the previous slide would lead us to expect. Since then a gap has developed between the two prices, which in the next slide we see can be roughly correlated with expectations from Slide 23.

In this Figure we have plotted the gap in price between HDPE and PVC in North-east Asia month by month, against the crude oil price prevailing in the same month. The correlation between the gap and the crude oil price may be rather rough, but there is a clear trend for the gap to widen with higher crude oil prices, as Slide 23 predicts. To be sure there is a large degree of scatter, not surprisingly given the approximation that had to be used for the cost of chlorine in Slide 23.

Now we proceed to a different comparison of competitive materials, this time fibre intermediates. First we build a correlation between caprolactam prices in Asia and crude oil prices, month by moth over the past 15 years. The straight line shows there is a reasonable correlation, though there is quite a bit of scatter. A major cause of scatter is the supply demand situation for a given month, which we shall be examining later.

In this Figure we repeat the exercise for polyester raw materials, namely the sum of the prices of 0.865 tons of PTA and 0.35 tons of MEG. The correlation with the crude oil price is rather better in this case.

Here with compare the two straight line summaries from the previous two Slides. The raw material costs for nylon 6, namely the caprolactam cost, is always higher than the polyester raw materials costs. However the disparity reduces as the crude oil price falls. If crude oil prices in 2015 average $55/bbl, then caprolactam (and hence nylon 6) will be less disadvantaged compared to polyester than during the past few years. Nylon 6 has lost some market share to polyester in recent years, but probably this will stop for the next few years (there are many other factors determining the competitivity between these two fibres).

Polyester fibre also competes with cotton. This Figure compares the idealised market prices compared with crude oil, but this time of polyester polymer (PET) with nylon 6 (PA6) and also with raw cotton (all three need further processing before becoming yarns). Whilst PET and raw cotton were comparable in price until recently, after the crude oil collapse we can expect PET prices in 2015 to be well below those of raw cotton. Some moves to a higher content of polyester staple in blends with cotton in certain fabrics are thus likely to take place.

In Slide 26 we noted quite a lot of scatter in the correlation between monthly prices for caprolactam and the crude oil price for the same month. A major contribution to that scatter comes from the cash margin above production cost for a given month, which is large when markets are tight and becomes small or zero (or even negative) when markets are over-supplied. In this and the next few Slides we try to correlate the cash flow with the tightness or looseness of the market.The present Figure shows as the top black line the cash cost of production of caprolactam depending on the crude oil price (Brent). The cost has been built up of various elements, which are identified. There are the energy dependent items, principally cyclohexane (which depends on benzene and hydrogen costs), ammonia and steam. Then there are the items which are independent of energy costs to a first approximation, namely the fixed costs, of both the caprolactam plant itself and of the raw material plants (cyclohexane and ammonia). It may seem strange to divide the costs of production of cyclohexane etc. between energy dependent and energy independent, but it helps to group all the fixed costs at the top of the wedge shown in the Figure, as there are times when prices do not cover total costs, but still make a contribution to fixed costs. Finally there are some other non energy dependent costs, for example costs associated with delivery of the caprolactam to the customer, which is usually in flake form in Asia.

The plots show the monthly prices of caprolactam in Asia, with months numbered 1 to 12. The data start in January 2009, for which month the cash flow was slightly negative according to the model, but there was a progressive improvement during 2009, which continued in 2010, until very good cash flow was registered for nearly all months of 2011. Cash flow then deteriorated in 2012, and by the end of the year was again in negative figures. The next Slide looks at the following years.

The situation then became grim in 2013, with every month registering negative cash flow in the model. This can be attributed to the spree of building of new caprolactam plants in China, which took the whole world into a gross over-supply. Things continued in the same vein in the first half of 2014. Then, in the second half of 2014, crude oil prices started falling, with increasing speed. Caprolactam prices also came down, but the Figure illustrates that caprolactam prices did not totally reflect the reduction in energy costs and indeed cash flow actually improved in the latter months of 2014.It should be remembered that the model used is that of an average sized caprolactam plant in Asia, so the cash flow performance of any one plant may have been better or poorer than represented by the model. Also, the build-up shown in the Figure is idealised and in practice there can be deviations from linearity at any of the stages in the supply chain between crude oil and caprolactam.

We now try to correlate the price recorded in a given month not only with the crude oil price but also with the tightness prevailing in the market for that month. For this we use the concept of a tightness index for the market, defined as:

Tightness Index = log10[Capacity/(Capacity – Production)]If we think of the gap between Capacity and Production as the Buffer which is available to meet above-normal requests for supply, the above definition can be rewritten:

Tightness Index = log10[Capacity/Buffer]Experience shows that when the Tightness Index is 1.00 (meaning that the Buffer is one tenth of total capacity and remembering that log10[10] equals 1.00), markets are generally balanced. When the Tightness Index is 1.4 the Buffer is 1/25th of capacity, in other words plant utilisation is 96%, which results in a very tight market. Conversely when the Tightness Index is 0.6 the Buffer is one quarter of the capacity, meaning a utilisation rate of 75%, which indicates a very over-supplied market.In the Figure we have set a sloping scale for the prices to be plotted, such that the vertical scale corresponds roughly to the Tightness Index that we judge applied for the month in question. The methodology is empirical but this Figure does provide a reasonable correlation between three parameters, the caprolactam price, the crude oil price, and the caprolactam Tightness Index for a given month.

The Capacity and the Production that we have used in the calculations of the Tightness Indices are those of the whole world. For chemical products that are readily transportable experience shows that it is the world balance that affects market tightness for all regions.

The previous Slide can be used to forecast caprolactam prices. This Figure shows an example. The situation of the caprolactam market in November 2014 was as shown in this Figure as regards the crude oil price (vertical column) and Tightness Index (horizontal bar). The cross-over, designated by the black box, indicates the price to be expected, and indeed prices in December 2014 were within the range indicated by the box.

This Figure was drawn up early in January 2015 to predict prices for the month. The parameters of the crude oil price and Tightness Index were as shown, with the black box indicating the expected price. Final agreements for January eventually emerged at close to the range indicated by the box.

Trying to look far into the future, by 2020-2022 maybe crude oil prices will have been restored to $100/bbl, and maybe the caprolactam surplus will have totally disappeared as world demand expands and closes up to the level of capacity, resulting in a very tight market. If both these conditions appear at the same time, the caprolactam price should be in the range indicated by the black box.

This Table pulls together the conclusions reached in the earlier Slides, plus a few more judgements.Basically chemicals made from naphtha have moved into a more favourable position compared with the situation before the crude oil collapse, while chemicals made from ethane no longer have the crushing advantage of previously, though they are still very competitive.

This Table shows in a nutshell the winners and losers from the narrowing in pricing between ethane and naphtha.

Paper presented at the 2nd International Chemical Downstream ConferenceMumbai, 29-30 January 2015