1. Supply and Demand
2. EIA inventory reports – why aren’t they bearish anymore? Over the past 2 weeks, demand is outstripping supply by 25 BCF/week, and the infamous NG glut would disappear in 16 weeks at that rate.
3. Supply: rig counts. Rig counts continue to fall. Since supply continues to fall even after rig counts start to grow again, we can be assured that supply will continue to fall for at least another three or four months.
4. Demand: If the recession has in fact bottomed, then we can expect natural gas demand to boomerang higher, as economy wide production levels are currently below economy wide consumption levels, and inventories are down 10% YOY. Inventory/sales ratio is still higher than it was in 2006-2008, so industrial demand may remain weak in the short term.
5. Previous examples of rig lay downs, their duration, scope, and the related price action. There are two cases where the number of rigs decreased by 40-45% (1999 and 2002). They were both in similar periods of excess gas storage and the correlated low price. In our current situation, the number of rigs has decreased by 59%(‼)There is a gap between where a company will lay down a rig and start one up again. It requires a significant move higher in price before companies will increase the rig count. If a company will lay down a rig at $4, they won’t necessarily put it back into operation until $5 or even higher. In previous examples, prices moved by 50-75% off their lows within 2 months.
6. Technical price support for a bullish conclusion
7. Conclusion
Wednesday, July 22, 2009
1. Supply and Demand
On Thursday every week, the Energy Information Agency (Note that all the data presented in this report are taken from the EIA unless otherwise noted) releases national storage data for natural gas. This report is an important data piece for traders and economists who are looking for clues to the supply/demand disposition of natural gas. The inventory follows a similar pattern every year, whereby inventories build from late March to mid November, and then draw down quickly during the cold winter months (Figure 1).
Figure 1 Natural Gas Storage (Source EIA)
Note the cyclical nature of gas inventories. Since the spring and fall has neither excessive heat nor excessive cold, these periods are called the shoulder months and have the least demand for natural gas. Demand is elevated in the summer due to air conditioning, but inventories still grow in the summer, just at a slower pace. Since the expected number of degree days is different in every calendar week, the most meaningful comparisons of natural gas disposition are achieved by comparing the same week in different years. Additionally, other factors affecting demand (holidays and scheduled industrial furloughs) generally fall in the same calendar week and are neutralized by comparing year over year data.
While comparing the same week on a YOY basis can provide “first-order” estimation for changes in supply and demand (footnote 2: When speaking of supply and demand in this paper I do so informally; I intend to mean quantity supplied (excluding changes in inventory) and quantity demanded. Thus if I say “supply exceeds demand by 20 BCF” the reader can take it to mean that, ceteris paribus, the quantity supplied is 20 BCF greater than the quantity demanded, and that difference is made up by inventory levels) , it will only give an accurate depiction averaged over many weeks of data. This is because one finds that even in the same calendar week the weather can vary greatly from one year to the next. Therefore, a more sophisticated approach must account for changes in weather between the two years. This is done by constructing a regression using weather data as explanatory variables and inventory changes as the dependant variable. Once you know the predicted effects of changes in heating and cooling demand, you can then back out a decent estimate for the year over year change in supply and demand disposition.
Figure 1 Natural Gas Storage (Source EIA)
Note the cyclical nature of gas inventories. Since the spring and fall has neither excessive heat nor excessive cold, these periods are called the shoulder months and have the least demand for natural gas. Demand is elevated in the summer due to air conditioning, but inventories still grow in the summer, just at a slower pace. Since the expected number of degree days is different in every calendar week, the most meaningful comparisons of natural gas disposition are achieved by comparing the same week in different years. Additionally, other factors affecting demand (holidays and scheduled industrial furloughs) generally fall in the same calendar week and are neutralized by comparing year over year data.
While comparing the same week on a YOY basis can provide “first-order” estimation for changes in supply and demand (footnote 2: When speaking of supply and demand in this paper I do so informally; I intend to mean quantity supplied (excluding changes in inventory) and quantity demanded. Thus if I say “supply exceeds demand by 20 BCF” the reader can take it to mean that, ceteris paribus, the quantity supplied is 20 BCF greater than the quantity demanded, and that difference is made up by inventory levels) , it will only give an accurate depiction averaged over many weeks of data. This is because one finds that even in the same calendar week the weather can vary greatly from one year to the next. Therefore, a more sophisticated approach must account for changes in weather between the two years. This is done by constructing a regression using weather data as explanatory variables and inventory changes as the dependant variable. Once you know the predicted effects of changes in heating and cooling demand, you can then back out a decent estimate for the year over year change in supply and demand disposition.
2. Why The EIA reports aren’t bearish anymore
First two weeks of July 2009 (i.e. the last two inventory reports)
Average cooling degree days for the past two weeks=62
Average inventory fill for the past two weeks=82.5
First two weeks of July (2006-2008)
Average cooling degree days for the first two weeks= 75
Average inventory fill=85.5
Look at the difference in cooling degree days between this year and the average over the past 3 years (62 versus 75). How big of a difference could that make in cooling demand?
That big of a difference in CDDs is good for about 25 BCF less use per week,
(Footnote 3
I ran a least squares regression using the difference between changes in inventory in two consecutive years as the dependant variable and changes in heating degree and cooling degree days as the independent (or explanatory) variables. I use terms for the differences in the square of the CDDs and HDDs as well to allow for a non-linear relationship (for example, if 10% of the population uses an air conditioner at 80° F, but 50% use an air conditioner at 90° F, then a linear specification won’t give us as accurate of a specification). The equation generated by the least squares regressions to explain inventory changes based on differences in degree days is the following:
d(dINV)= -2+0.97*d(HDD)+0.79*d(CDD)+0.0013*d(HDD^2)+0.0096*d(CDD^2)
where:
dINV=change in EIA natural gas inventory from one week to the next
d(dINV)= difference in dINV for a given week, between year x and year (x+1).
d(HDD)=difference in Heating Degree Days for a given week, between year x and year (x+1).
d(CDD)=difference in Cooling Degree Days for a given week, between year x and year (x+1).
D(HDD^2)= difference in the square of the HDD for given week, between year x and year (x+1).
D(CDD^2)= difference in the square of the HDD for given week, between year x and year (x+1).
The fact that the constant term at the beginning of the equation is -2 instead of 0 reflects the fact that we have had a YOY inventory build of approximately 100 BCF per year over the past three years. In the long run this constant term will equal 0! end footnote)
so based on simple weather YOY comparisons, we would have predicted fills in the 110 range over the past two weeks. Instead we got 82.5, a fact that signifies less gas was put in storage than what is predicted based on the regression.
Based on the past two weeks of data, and assuming the regression is roughly accurate, demand is outstripping supply by 25 BCF/week or almost 4 BCF a day! Normally this level of discrepancy would create an absolute panic in the market. However, because the stock of natural gas is currently 450 BCF above average, the market reaction was muted. Still, the price has moved up 10% since before the release of the July 3rd inventory report.
One way to think of the current situation is to parse the bearish or bullish reality in terms of stock versus flow.
The stock:
Stock of natural gas is 450 BCF above normal. VERY BEARISH
1st derivative (The flow):
After accounting for changes in weather and other exogenous factors, I estimate that demand has outstripped supply by 25 BCF/ week for the past two weeks. Over the past 4 weeks, demand outstripped supply by 21 BCF/week. While four weeks is a small sample size, this level of discrepancy is statistically significant. Future inventory reports will continue to confirm, deny, or accelerate this apparent disparity between supply and demand. BULLISH
2nd derivative (change in the flow):
In 2009Q1, the supply demand disparity was the opposite: supply outstripped demand by 40 BCF/week. Thus, in one quarter, the market went from a 40 BCF/week surplus to a 25 BCF/week deficiency. Obviously, this implies the second derivative of the stock (change in the change of the stock) is negative and steeply so. Why this is and whether it will continue will be the focus of my discussion in sections 3 and 4. BULLISH
In summary, if a trader were to focus only on the stock of natural gas, they will see a 450 BCF glut. Examples of natural gas prices getting driven into the ground during the fall shoulder months abound (and under much less extreme storage gluts then the current one). However, if the trader considers the flow (1st derivative) and change in flow (2nd derivative) a different perspective emerges. Assuming the previous calculations are accurate we are currently running 25 BCF/week below expectations, at which rate the entire storage glut would be gone in 18 weeks. If the 2nd derivative (change in flow) is negative, then the glut could disappear even faster. How can we estimate which effect will dominate prices in the near future? Well, this is not the first time the market has been in this scenario: we had a natural gas glut in both 1999 and 2002, and history can be our guide. In section 5, we look for possible rhymes in these previous instances to divine the probable outcome of our current situation.
Average cooling degree days for the past two weeks=62
Average inventory fill for the past two weeks=82.5
First two weeks of July (2006-2008)
Average cooling degree days for the first two weeks= 75
Average inventory fill=85.5
Look at the difference in cooling degree days between this year and the average over the past 3 years (62 versus 75). How big of a difference could that make in cooling demand?
That big of a difference in CDDs is good for about 25 BCF less use per week,
(Footnote 3
I ran a least squares regression using the difference between changes in inventory in two consecutive years as the dependant variable and changes in heating degree and cooling degree days as the independent (or explanatory) variables. I use terms for the differences in the square of the CDDs and HDDs as well to allow for a non-linear relationship (for example, if 10% of the population uses an air conditioner at 80° F, but 50% use an air conditioner at 90° F, then a linear specification won’t give us as accurate of a specification). The equation generated by the least squares regressions to explain inventory changes based on differences in degree days is the following:
d(dINV)= -2+0.97*d(HDD)+0.79*d(CDD)+0.0013*d(HDD^2)+0.0096*d(CDD^2)
where:
dINV=change in EIA natural gas inventory from one week to the next
d(dINV)= difference in dINV for a given week, between year x and year (x+1).
d(HDD)=difference in Heating Degree Days for a given week, between year x and year (x+1).
d(CDD)=difference in Cooling Degree Days for a given week, between year x and year (x+1).
D(HDD^2)= difference in the square of the HDD for given week, between year x and year (x+1).
D(CDD^2)= difference in the square of the HDD for given week, between year x and year (x+1).
The fact that the constant term at the beginning of the equation is -2 instead of 0 reflects the fact that we have had a YOY inventory build of approximately 100 BCF per year over the past three years. In the long run this constant term will equal 0! end footnote)
so based on simple weather YOY comparisons, we would have predicted fills in the 110 range over the past two weeks. Instead we got 82.5, a fact that signifies less gas was put in storage than what is predicted based on the regression.
Based on the past two weeks of data, and assuming the regression is roughly accurate, demand is outstripping supply by 25 BCF/week or almost 4 BCF a day! Normally this level of discrepancy would create an absolute panic in the market. However, because the stock of natural gas is currently 450 BCF above average, the market reaction was muted. Still, the price has moved up 10% since before the release of the July 3rd inventory report.
One way to think of the current situation is to parse the bearish or bullish reality in terms of stock versus flow.
The stock:
Stock of natural gas is 450 BCF above normal. VERY BEARISH
1st derivative (The flow):
After accounting for changes in weather and other exogenous factors, I estimate that demand has outstripped supply by 25 BCF/ week for the past two weeks. Over the past 4 weeks, demand outstripped supply by 21 BCF/week. While four weeks is a small sample size, this level of discrepancy is statistically significant. Future inventory reports will continue to confirm, deny, or accelerate this apparent disparity between supply and demand. BULLISH
2nd derivative (change in the flow):
In 2009Q1, the supply demand disparity was the opposite: supply outstripped demand by 40 BCF/week. Thus, in one quarter, the market went from a 40 BCF/week surplus to a 25 BCF/week deficiency. Obviously, this implies the second derivative of the stock (change in the change of the stock) is negative and steeply so. Why this is and whether it will continue will be the focus of my discussion in sections 3 and 4. BULLISH
In summary, if a trader were to focus only on the stock of natural gas, they will see a 450 BCF glut. Examples of natural gas prices getting driven into the ground during the fall shoulder months abound (and under much less extreme storage gluts then the current one). However, if the trader considers the flow (1st derivative) and change in flow (2nd derivative) a different perspective emerges. Assuming the previous calculations are accurate we are currently running 25 BCF/week below expectations, at which rate the entire storage glut would be gone in 18 weeks. If the 2nd derivative (change in flow) is negative, then the glut could disappear even faster. How can we estimate which effect will dominate prices in the near future? Well, this is not the first time the market has been in this scenario: we had a natural gas glut in both 1999 and 2002, and history can be our guide. In section 5, we look for possible rhymes in these previous instances to divine the probable outcome of our current situation.
3. Rig Counts
Every week, Baker Hughes publishes the number of active gas rigs operating in the world and in the United States. This rig count data correlates with the number of new gas wells that can be expected to be drilled in any given week. In order to simply maintain supply, a certain number of rigs need to operate. The necessary number depends on the initial flow rate of new wells, and the depletion rate of the existing resource. If the number of new drilled wells goes above this number, then supply well increase, and vice-versa. One of the important metrics to know is what the average depletion rate is in existing wells. Unfortunately, that piece of data is extremely difficult to calculate because there are so many types of wells in different types of rock and the overall distribution of quality and type is constantly changing. What we do know is that
1. Depletion rates steadily increased between 1980-2006 (see http://www.eia.doe.gov/oiaf/servicerpt/depletion/pdf/app_g.pdf and
http://gswindell.com/tx-depl.htm)
2. Average flow rates have been decreasing over the past 30 years (Figure 2)
3. Initial flow rates for shale gas are impressively high (anecdotal)
4. Depletion in shale wells is very high, particularly in the first few months of operation (Also anecdotal)
Figure 2
The only two years in the past decade when production per well increased were 1999 and 2007. These years featured relatively low prices in natural gas, so the increase in per well production may be due to producers:
1. Only drilling their best prospects that year
2. Reducing the number of existing wells since the low price did not justify the existence of marginal wells.
It is also clear that 1998-1999 represented a turning point in the production per well. This could be due to a number of different factors:
1. A decrease in the quality of available resource
2. A shift in the type of well being drilled (conventional versus unconventional)
3. An increase in the rate of drilling after 1999. Starting in 1999, there was an explosion in the rig count and the number of new wells drilled. The acceleration of drilling would more quickly change the demographic of total wells toward lesser quality or unconventional wells.
This is consistent with data on the number of operating drill rigs. Glancing at a graph of drill rigs, it is clear that there was a noticeable increase in rigs starting in 1999 (Figure 3).
Figure 3 (Source: Baker Hughes)
While supply stayed more or less constant from 1998, the number of existing wells increased dramatically, and the rig count exploded. This trend continued through 2007 when shale natural gas wells started changing the dynamics of the market.
Take a close look at Figure 3 and you will see that there have been 3 dramatic falls in rig counts in the past ten years: 1997-1999, 2001-2002, and 2008-current. These drops in drilling activity correspond to very low prices for natural gas (as the famous quip goes: low prices are the cure for low prices). In section 5 the rig drops in 1998 and 2001 are examined and used to model what might be expected in 2009. Speaking generally, as drilling activity slows, there is a point at which depletion of the total existing supply exceeds new marginal supply, and total supply starts to fall. Because the rig count falls below the maintenance level, supply continues to fall even after the rig count starts to climb. This is because it takes a period of time to activate the number of rigs necessary just to drill at the level necessary to maintain supply. In Figure 4, there is a graphical estimation to prove the point.
Figure 4 Rig count starts at exactly the level necessary to maintain supply. We assume an annual depletion rate of 25% and also assume a 40% decline in drill rigs from peak to trough that declines linearly over a period of 40 weeks. Finally we assume that once the rig count has bottomed, the rig count then has a linear increase back to the initial rig level in 25 weeks.
This figure gives a first approximation for how supply responds to decreased rig counts. In order to try to model the 2006-2009 period a little bit more accurately, some assumptions need to be made. First, it is pretty clear that we were expanding supply from 2006-2008 at a meaningful (some would say blistering) pace. Therefore, the drill level was above the level necessary to maintain supply, and this is confirmed by the increase in supply during 2008. Furthermore, the increase in rigs during this time period was particularly marked for horizontal rigs in shale deposits (footnote 5:The emergence of horizontal drilling for shale natural gas is probably the most significant development in the energy sector over the past 3 decades. Some market participants have noted the extremely fast depletion rates of shale natural gas wells. While a fast depletion rate will present a challenge after the supply of shale gas peaks, it actually makes the resource more flexible and responsive so long as the resource is increasing. While this paper generally holds the view that natural gas prices could spike in the next 12 months, shale natural gas and its high depletion rate will actually act as a damper on this price increase. Since initial flow rates are so high and a larger percentage of a shale well’s production occurs in the first few months, this decreases the amount of time necessary to increase supply by significant quantities) : the number of these rigs expanded by more than 100%. When the total number of drill rigs peaked in late 2008, producers could very well have been drilling 50% more wells then was necessary to maintain then-current levels of supply. That will be the baseline assumption in the estimate that follows.(footnote 6:Other assumptions include: horizontal rigs are modeled to drill twice as much gas per rig as other types of rigs to reflect the elevated initial flow rate of shale gas. Depletion rates are assumed: horizontal wells deplete at 70-80% per annum, and other wells deplete at 40-50% per annum. I am not suggesting that Figure 5 is a completely accurate depiction of reality; for one thing, it does not account for supply that was lost during Hurricanes Katrina, Rita, Gustav, and Ike. It also aggregates different types of wells, and makes assumptions about depletion rates that may or may not be accurate. But it will give a better broad view of supply then what is suggested in Figure 4. The red curve at the end of the graph reflects an estimate of what future supply would look like if rig counts started increasing next week and increased linearly at a rate of 30 rigs a week.)
Figure 5 Rig Data from Baker Hughes. Curve depends on depletion rates estimated by author
This figure is meant to illustrate the concept that supply will continue to fall even after rig counts start to recover. This is because we have now overshot the number of rigs necessary to maintain supply, and so supply will fall until we return to that number of rigs.
In conclusion, by comparing to past instances where rig counts fell below the level necessary to maintain supply, we can expect that supply will continue to fall for at least another month or two. If rig counts stay at current levels (or continue to fall) then the nadir in supply will be pushed out that much further. To relate this back to section 2, an expected reduction in supply would cause, everything else equal, the second derivative of natural gas storage (that is, the change in the flow rate) to be negative
1. Depletion rates steadily increased between 1980-2006 (see http://www.eia.doe.gov/oiaf/servicerpt/depletion/pdf/app_g.pdf and
http://gswindell.com/tx-depl.htm)
2. Average flow rates have been decreasing over the past 30 years (Figure 2)
3. Initial flow rates for shale gas are impressively high (anecdotal)
4. Depletion in shale wells is very high, particularly in the first few months of operation (Also anecdotal)
Figure 2
The only two years in the past decade when production per well increased were 1999 and 2007. These years featured relatively low prices in natural gas, so the increase in per well production may be due to producers:
1. Only drilling their best prospects that year
2. Reducing the number of existing wells since the low price did not justify the existence of marginal wells.
It is also clear that 1998-1999 represented a turning point in the production per well. This could be due to a number of different factors:
1. A decrease in the quality of available resource
2. A shift in the type of well being drilled (conventional versus unconventional)
3. An increase in the rate of drilling after 1999. Starting in 1999, there was an explosion in the rig count and the number of new wells drilled. The acceleration of drilling would more quickly change the demographic of total wells toward lesser quality or unconventional wells.
This is consistent with data on the number of operating drill rigs. Glancing at a graph of drill rigs, it is clear that there was a noticeable increase in rigs starting in 1999 (Figure 3).
Figure 3 (Source: Baker Hughes)
While supply stayed more or less constant from 1998, the number of existing wells increased dramatically, and the rig count exploded. This trend continued through 2007 when shale natural gas wells started changing the dynamics of the market.
Take a close look at Figure 3 and you will see that there have been 3 dramatic falls in rig counts in the past ten years: 1997-1999, 2001-2002, and 2008-current. These drops in drilling activity correspond to very low prices for natural gas (as the famous quip goes: low prices are the cure for low prices). In section 5 the rig drops in 1998 and 2001 are examined and used to model what might be expected in 2009. Speaking generally, as drilling activity slows, there is a point at which depletion of the total existing supply exceeds new marginal supply, and total supply starts to fall. Because the rig count falls below the maintenance level, supply continues to fall even after the rig count starts to climb. This is because it takes a period of time to activate the number of rigs necessary just to drill at the level necessary to maintain supply. In Figure 4, there is a graphical estimation to prove the point.
Figure 4 Rig count starts at exactly the level necessary to maintain supply. We assume an annual depletion rate of 25% and also assume a 40% decline in drill rigs from peak to trough that declines linearly over a period of 40 weeks. Finally we assume that once the rig count has bottomed, the rig count then has a linear increase back to the initial rig level in 25 weeks.
This figure gives a first approximation for how supply responds to decreased rig counts. In order to try to model the 2006-2009 period a little bit more accurately, some assumptions need to be made. First, it is pretty clear that we were expanding supply from 2006-2008 at a meaningful (some would say blistering) pace. Therefore, the drill level was above the level necessary to maintain supply, and this is confirmed by the increase in supply during 2008. Furthermore, the increase in rigs during this time period was particularly marked for horizontal rigs in shale deposits (footnote 5:The emergence of horizontal drilling for shale natural gas is probably the most significant development in the energy sector over the past 3 decades. Some market participants have noted the extremely fast depletion rates of shale natural gas wells. While a fast depletion rate will present a challenge after the supply of shale gas peaks, it actually makes the resource more flexible and responsive so long as the resource is increasing. While this paper generally holds the view that natural gas prices could spike in the next 12 months, shale natural gas and its high depletion rate will actually act as a damper on this price increase. Since initial flow rates are so high and a larger percentage of a shale well’s production occurs in the first few months, this decreases the amount of time necessary to increase supply by significant quantities) : the number of these rigs expanded by more than 100%. When the total number of drill rigs peaked in late 2008, producers could very well have been drilling 50% more wells then was necessary to maintain then-current levels of supply. That will be the baseline assumption in the estimate that follows.(footnote 6:Other assumptions include: horizontal rigs are modeled to drill twice as much gas per rig as other types of rigs to reflect the elevated initial flow rate of shale gas. Depletion rates are assumed: horizontal wells deplete at 70-80% per annum, and other wells deplete at 40-50% per annum. I am not suggesting that Figure 5 is a completely accurate depiction of reality; for one thing, it does not account for supply that was lost during Hurricanes Katrina, Rita, Gustav, and Ike. It also aggregates different types of wells, and makes assumptions about depletion rates that may or may not be accurate. But it will give a better broad view of supply then what is suggested in Figure 4. The red curve at the end of the graph reflects an estimate of what future supply would look like if rig counts started increasing next week and increased linearly at a rate of 30 rigs a week.)
Figure 5 Rig Data from Baker Hughes. Curve depends on depletion rates estimated by author
This figure is meant to illustrate the concept that supply will continue to fall even after rig counts start to recover. This is because we have now overshot the number of rigs necessary to maintain supply, and so supply will fall until we return to that number of rigs.
In conclusion, by comparing to past instances where rig counts fell below the level necessary to maintain supply, we can expect that supply will continue to fall for at least another month or two. If rig counts stay at current levels (or continue to fall) then the nadir in supply will be pushed out that much further. To relate this back to section 2, an expected reduction in supply would cause, everything else equal, the second derivative of natural gas storage (that is, the change in the flow rate) to be negative
4. Demand
Evidence is starting to accumulate that production of goods is stabilizing. Consumption data also appears to have stabilized. According to the most recent Census report, sales did not drop between March and May. While inventories are still dropping, the underlying production levels seem to have stopped declining, and are at a level slightly below consumption levels. Again we are faced with a stock versus flow situation. The stock of goods is too high, but the flow is now negative (that is, the production of goods is lower than consumption of goods.) Unless consumption drops further, we can expect production to come up at least to the level of current sales. This point is fleshed out with a particular focus on natural gas by an investor and trader named Rob and with a tag of Robry825. For those interested in looking in more detail at the demand for natural gas, I recommend reading his weekly blog post at http://robry825.blogspot.com, and also his near-daily postings at the Investor Village CWEI message board :(http://www.investorvillage.com/smbd.asp?mb=2234&pt=m&clear=1) for detailed and disaggregated data on demand for natural gas.
A quick comment on weather: one of the big stories in the natural gas market this summer has been the bearish weather. With the exception of several weeks of hot weather in Texas, this summer has been remarkably cool, and there has not even been the threat of tropical storms in the Gulf of Mexico. As of mid-July, we have predictions of continued unseasonably cool weather across most of the CONUS. The psychological effect of weeks and weeks of cool weather may be leading market participants to overemphasize the importance of bearish weather. Weather forecasts are only accurate to 14 days, so we could very easily have a bullish switch in weather, such as a hot August or a cool October.
In conclusion, I think that the demand side for natural gas is uncertain. There exists the possibility that goods consumption and natural gas demand will fall still further, particularly if our fate is to plunge into a deflationary depression. Barring such a worse-case scenario however, we might expect industrial demand to pick up soon, since current industrial production is below current consumption levels. This again points to a flat or negative second derivative for natural gas storage levels.
A quick comment on weather: one of the big stories in the natural gas market this summer has been the bearish weather. With the exception of several weeks of hot weather in Texas, this summer has been remarkably cool, and there has not even been the threat of tropical storms in the Gulf of Mexico. As of mid-July, we have predictions of continued unseasonably cool weather across most of the CONUS. The psychological effect of weeks and weeks of cool weather may be leading market participants to overemphasize the importance of bearish weather. Weather forecasts are only accurate to 14 days, so we could very easily have a bullish switch in weather, such as a hot August or a cool October.
In conclusion, I think that the demand side for natural gas is uncertain. There exists the possibility that goods consumption and natural gas demand will fall still further, particularly if our fate is to plunge into a deflationary depression. Barring such a worse-case scenario however, we might expect industrial demand to pick up soon, since current industrial production is below current consumption levels. This again points to a flat or negative second derivative for natural gas storage levels.
5. What History Tells Us: Previous Examples of Rig Lay Downs
Summarizing to this point, the bearish and bullish factors affecting the natural gas market are:
BEARISH
1. incredibly high storage levels
2. consistently bearish weather since February
3. emergence of a new resource (shale gas) with lower costs and high initial flow rates
BULLISH
A. low price (which is below the marginal cost of all but the most cherry new wells)
B. the past few weeks of EIA inventory data
C. the change in the supply and demand disposition over the past 4 months
One might think that the battlefield is level at this point, and the incredible price volatility over the past 2 weeks affirms that market participants are even more uncertain than usual about price. However, previous examples of supply gluts and rig lay downs point to a decidedly bullish outcome.
In Figure 6, we model the last three instances of major rig lay downs.
Figure 6
The first thing to note about Figure 6 is that the percentage of rig lay downs is greater in our current episode than in the previous two episodes (roughly 60% vs. 45%). Therefore, even if drill rates in late 2008 were substantially greater than what was necessary to maintain supply, we have now certainly fallen to a drill rate that will not maintain supply.
In the next two figures the thing to note - and this is crucial - is that in both 1999 and 2002 rig counts continued to fall even after the price had reached its nadir (Figures 9 and 10).
Figure 7
Figure 8
The fact that rig counts did not start rising until 8-12 weeks after the price nadir has serious implications for the current volatility of natural gas prices. If market prices don’t start rising until storage flow is clearly negative (that is quantity supplied is obviously less than quantity demanded), and if rig counts fall even after prices start rising, then the market is set up for a potentially serious shortage. I don’t think it is a coincidence that in both cases (1999 and 2002), prices spiked by more than 500% within 20 months after the rig cont low. Extreme volatility in input prices has been shown to create a drag on the economy.
{(footnote 7: Among others, see Bernanke, 1983; Irreversibility, uncertainty, and cyclical investments. Authors comment: The problem of volatility has no obvious solution and without the futures market, the volatility would likely be greater (and the chances of shortages higher.) As much demonizing as there has been of speculators in the past year, this is clearly a place where speculators can improve Pareto Optimality of the economy. By taking a risk to buy at market bottoms, speculators can smooth what would be an even greater disruption of the natural gas market. It is also true in both cases that rig counts did not start falling until prices had fallen significantly from their peaks, so speculators have a function in both rising and falling markets.)}
To examine the two cases in Figures 7 and 8, it appears that in 1998-1999 producers reduced rig use so long as prices were below $2.50. In the second case (2001-2002), producers reduced rig counts so long as prices were below $3.25. In both cases, these were approximately the same price that producers started to reduce rig counts. The significance of this can be seen by looking at the current situation (Figure 11). Rig counts started to fall in late 2008 after prices had fallen from $13.75 to approximately $8. However, prices have now fallen on top of that by more than 50%! This suggests that prices might have to rise substantially (perhaps greater than 100%) before rig counts start to increase.
Figure 9
Once again, to balance the argument, we must consider shale natural gas. If the shale natural gas resource is large enough, the industry will be able to offset the depletion in the entire resource base by only adding more shale wells. If the marginal cost to drill these wells is significantly below $8 and they can be brought on fast enough, then it is less likely that we would see $8 in the immediate future.
To conclude this section, in previous episodes of natural gas gluts that resulted in laying down a substantial portion of rigs, the rig count did not start to increase until 8-12 weeks after price had reached its ultimate nadir. Since breaking contracts is very expensive, gas producers will operate at a loss (selling gas for less than the cost to produce it) so long as it is less than the substantial loss incurred by capping a well or not using already leased equipment. This retards the rate at which they would otherwise lay up their rigs. On the opposite side, a company will not take a rig out of storage until they are sure the project is profitable. Therefore there is a gap in the price between which companies have neither incentive to lay down nor start up rigs. This is what leads me to predict that supply could continue to decrease for at least another 4 months (2 months until rig counts to start to increase, and another 2 months until supply stops falling.) It is worthwhile to note that in each of the previous episodes, rig counts did not start to rise until prices had achieved the level where rig counts had started to fall. While shale gas could certainly alter the dynamics, this suggests that rig counts may not start increasing until prices reach $8.
BEARISH
1. incredibly high storage levels
2. consistently bearish weather since February
3. emergence of a new resource (shale gas) with lower costs and high initial flow rates
BULLISH
A. low price (which is below the marginal cost of all but the most cherry new wells)
B. the past few weeks of EIA inventory data
C. the change in the supply and demand disposition over the past 4 months
One might think that the battlefield is level at this point, and the incredible price volatility over the past 2 weeks affirms that market participants are even more uncertain than usual about price. However, previous examples of supply gluts and rig lay downs point to a decidedly bullish outcome.
In Figure 6, we model the last three instances of major rig lay downs.
Figure 6
The first thing to note about Figure 6 is that the percentage of rig lay downs is greater in our current episode than in the previous two episodes (roughly 60% vs. 45%). Therefore, even if drill rates in late 2008 were substantially greater than what was necessary to maintain supply, we have now certainly fallen to a drill rate that will not maintain supply.
In the next two figures the thing to note - and this is crucial - is that in both 1999 and 2002 rig counts continued to fall even after the price had reached its nadir (Figures 9 and 10).
Figure 7
Figure 8
The fact that rig counts did not start rising until 8-12 weeks after the price nadir has serious implications for the current volatility of natural gas prices. If market prices don’t start rising until storage flow is clearly negative (that is quantity supplied is obviously less than quantity demanded), and if rig counts fall even after prices start rising, then the market is set up for a potentially serious shortage. I don’t think it is a coincidence that in both cases (1999 and 2002), prices spiked by more than 500% within 20 months after the rig cont low. Extreme volatility in input prices has been shown to create a drag on the economy.
{(footnote 7: Among others, see Bernanke, 1983; Irreversibility, uncertainty, and cyclical investments. Authors comment: The problem of volatility has no obvious solution and without the futures market, the volatility would likely be greater (and the chances of shortages higher.) As much demonizing as there has been of speculators in the past year, this is clearly a place where speculators can improve Pareto Optimality of the economy. By taking a risk to buy at market bottoms, speculators can smooth what would be an even greater disruption of the natural gas market. It is also true in both cases that rig counts did not start falling until prices had fallen significantly from their peaks, so speculators have a function in both rising and falling markets.)}
To examine the two cases in Figures 7 and 8, it appears that in 1998-1999 producers reduced rig use so long as prices were below $2.50. In the second case (2001-2002), producers reduced rig counts so long as prices were below $3.25. In both cases, these were approximately the same price that producers started to reduce rig counts. The significance of this can be seen by looking at the current situation (Figure 11). Rig counts started to fall in late 2008 after prices had fallen from $13.75 to approximately $8. However, prices have now fallen on top of that by more than 50%! This suggests that prices might have to rise substantially (perhaps greater than 100%) before rig counts start to increase.
Figure 9
Once again, to balance the argument, we must consider shale natural gas. If the shale natural gas resource is large enough, the industry will be able to offset the depletion in the entire resource base by only adding more shale wells. If the marginal cost to drill these wells is significantly below $8 and they can be brought on fast enough, then it is less likely that we would see $8 in the immediate future.
To conclude this section, in previous episodes of natural gas gluts that resulted in laying down a substantial portion of rigs, the rig count did not start to increase until 8-12 weeks after price had reached its ultimate nadir. Since breaking contracts is very expensive, gas producers will operate at a loss (selling gas for less than the cost to produce it) so long as it is less than the substantial loss incurred by capping a well or not using already leased equipment. This retards the rate at which they would otherwise lay up their rigs. On the opposite side, a company will not take a rig out of storage until they are sure the project is profitable. Therefore there is a gap in the price between which companies have neither incentive to lay down nor start up rigs. This is what leads me to predict that supply could continue to decrease for at least another 4 months (2 months until rig counts to start to increase, and another 2 months until supply stops falling.) It is worthwhile to note that in each of the previous episodes, rig counts did not start to rise until prices had achieved the level where rig counts had started to fall. While shale gas could certainly alter the dynamics, this suggests that rig counts may not start increasing until prices reach $8.
6. Technical Price Support for a Bullish Conclusion
So far this paper has looked exclusively at fundamentals. It concludes with a quick glance at technical price considerations in the natural gas market. Natural gas has been in a price range between $3 and $4.5 for the past 5 months (Figure 10).
When a market trades in a range like it has for the past 5 months, it is because there are large market participants on both sides of the trade. To date, it appears that producers are not willing to produce below $3.5 and will aggressively buy futures below this level. Producers hedge a percentage of their production: to do this they sell futures contracts with the intent to deliver the product at some agreed upon month in the future. Once the futures contract has been sold, a producer still has the option to buy the contract back. If they buy the contract back at a price lower then they sold it they will immediately pocket the difference. They then have the choice of either:
• Selling the (originally hedged) gas on the spot market
• Capping wells, or not drilling them in the first place
It appears that producers have been buying back future contracts when the price is below $3.50. On the other side of the coin, there appears to be a segment of market participants who are willing to short large quantities of gas when prices rise above $4. This segment is most likely large speculators (I say this based on Commitment of Trader Reports), who have been short natural gas for the past 12 months. It also could be large end users (industrial, electric generation plants, utilities) but it seems unlikely they would choose to un-hedge future deliveries at $4 when they have gotten used to $7+ gas over the past 5 years!
Just last week, prices once again tested the sub-$3.5 region and once again this price range was rejected by some market player (most likely natural gas producers). The fact that prices did not break the April low can be seen as bullish. However, sometimes a break to new lows is necessary to create a capitulation in the market. If prices were to break below $3.15 we would likely see a capitulation; prices would probably fall for an additional week or two in this scenario, but then turn around quickly. However, since prices did not break to new lows, it suggests that the most likely outcome is that medium term or even permanent lows have now been made in this (historic) bear market.
Zooming in our time frame to the past few weeks (Figure 11), we can see that Wednesday’s selling last week was vehemently rejected by buying after the Thursday inventory report. While it is dangerous to read too much into an isolated price movement, the current formation is at least consistent with the beginning of a powerful rally.
When a market trades in a range like it has for the past 5 months, it is because there are large market participants on both sides of the trade. To date, it appears that producers are not willing to produce below $3.5 and will aggressively buy futures below this level. Producers hedge a percentage of their production: to do this they sell futures contracts with the intent to deliver the product at some agreed upon month in the future. Once the futures contract has been sold, a producer still has the option to buy the contract back. If they buy the contract back at a price lower then they sold it they will immediately pocket the difference. They then have the choice of either:
• Selling the (originally hedged) gas on the spot market
• Capping wells, or not drilling them in the first place
It appears that producers have been buying back future contracts when the price is below $3.50. On the other side of the coin, there appears to be a segment of market participants who are willing to short large quantities of gas when prices rise above $4. This segment is most likely large speculators (I say this based on Commitment of Trader Reports), who have been short natural gas for the past 12 months. It also could be large end users (industrial, electric generation plants, utilities) but it seems unlikely they would choose to un-hedge future deliveries at $4 when they have gotten used to $7+ gas over the past 5 years!
Just last week, prices once again tested the sub-$3.5 region and once again this price range was rejected by some market player (most likely natural gas producers). The fact that prices did not break the April low can be seen as bullish. However, sometimes a break to new lows is necessary to create a capitulation in the market. If prices were to break below $3.15 we would likely see a capitulation; prices would probably fall for an additional week or two in this scenario, but then turn around quickly. However, since prices did not break to new lows, it suggests that the most likely outcome is that medium term or even permanent lows have now been made in this (historic) bear market.
Zooming in our time frame to the past few weeks (Figure 11), we can see that Wednesday’s selling last week was vehemently rejected by buying after the Thursday inventory report. While it is dangerous to read too much into an isolated price movement, the current formation is at least consistent with the beginning of a powerful rally.
7. CONCLUSION
As Peter Bernstein was famous for saying, “we simply do not know what the future holds.” For me, the art of investing and trading is a constant reminder that I can only guess at what the future holds and that I am always reliant to a large degree on chance (or something greater) for my trade ideas to work. However, to quote another famous man “in the fields of observation, chance favors only the prepared mind.” While Louis Pasteur was speaking about microbiology, I believe the same principle applies to investing. While there is no guarantee that the natural gas prices will rise in the next few months, I have laid out a case for why they might, and I stand ready to profit if I get my chance.
All Bulled Up on Natural Gas
The Bullish Case for Natural Gas Prices
1. Supply and Demand
2. EIA inventory reports – why aren’t they bearish anymore? Over the past 2 weeks, demand is outstripping supply by 25 BCF/week, and the infamous NG glut would disappear in 16 weeks at that rate.
3. Supply: rig counts. Rig counts continue to fall. Since supply continues to fall even after rig counts start to grow again, we can be assured that supply will continue to fall for at least half a year.
4. Demand: If the recession has in fact bottomed, then we can expect natural gas demand to boomerang higher, as economy wide production levels are currently below economy wide consumption levels, and inventories are down 10% YOY. Inventory/sales ratio is still higher than it was in 2006-2008, so industrial demand may remain weak in the short term.
5. Previous examples of rig lay downs, their duration, scope, and the related price action. There are two cases where the number of rigs decreased by 40-45% (1999 and 2002). They were both in similar periods of excess gas storage and the correlated low price. In our current situation, the number of rigs has decreased by 59%(‼)There is a gap between where a company will lay down a rig and start one up again. It requires a significant move higher in price before companies will increase the rig count. If a company will lay down a rig at $4, they won’t necessarily put it back into operation until $5 or even higher. In previous examples, prices moved by 50-75% off their lows within 2 months.
6. Technical price support for a bullish conclusion
7. Conclusion
1. Supply and Demand
2. EIA inventory reports – why aren’t they bearish anymore? Over the past 2 weeks, demand is outstripping supply by 25 BCF/week, and the infamous NG glut would disappear in 16 weeks at that rate.
3. Supply: rig counts. Rig counts continue to fall. Since supply continues to fall even after rig counts start to grow again, we can be assured that supply will continue to fall for at least half a year.
4. Demand: If the recession has in fact bottomed, then we can expect natural gas demand to boomerang higher, as economy wide production levels are currently below economy wide consumption levels, and inventories are down 10% YOY. Inventory/sales ratio is still higher than it was in 2006-2008, so industrial demand may remain weak in the short term.
5. Previous examples of rig lay downs, their duration, scope, and the related price action. There are two cases where the number of rigs decreased by 40-45% (1999 and 2002). They were both in similar periods of excess gas storage and the correlated low price. In our current situation, the number of rigs has decreased by 59%(‼)There is a gap between where a company will lay down a rig and start one up again. It requires a significant move higher in price before companies will increase the rig count. If a company will lay down a rig at $4, they won’t necessarily put it back into operation until $5 or even higher. In previous examples, prices moved by 50-75% off their lows within 2 months.
6. Technical price support for a bullish conclusion
7. Conclusion
Thursday, July 16, 2009
Informal thoughts on China forex and US/China situation
China forex above 2 trillion now; up 180 bill in the three months to June.
All back of napkin estimates but let's parse that a little.
Trade surplus for those three months~$33 Billion. Interest payments on US, EURO, and Japanese bonds~$6-10 billion.
Valuation effects on Euro, Japan, and other assets due to the (on average) 7.5% appreciation of Yen, Euro, etc: $45 billion.
Which leaves us roughly $95 billion of "hot" money; multinationals trading their dollars in for yuan to invest or build capital in China, plus some investors who manage to slip through the cracks.
In other posts I've talked about how asset preference shifts are a major determinant in exchange rates, and this is a wonderful example. As risk aversion subsided, dollars sought opportunities on foreign shores (in this case China) and I'm sure this was responsible for part of the drop in the dollar, in spite of China's currency peg.
So the US is damned if we do damned if we don't. Either we have a strong currency paired with risk aversion, or we have an improving economy paired with a falling dollar. No way around it.
People like to compare US/China situation to Britain/US 100 years ago. They point out that the dollar didn't become reserve currency for 25 years after US became dominant economic player. This comparison leaves much to be desired though. For one thing, US is roughly same land mass as China, is natural resource rich. That would argue that China will not overtake the US as the world leading economic power, much less depose our currency.
We still have the best universities and a tradition like none other of risk taking (which definitely correlates with high economic activity).
On the OTHER hand, we are definitely in a funk, particularly K-12 education; we are in much worse fiscal/debt shape then UK was at the same time; we have a fiat currency; and face potentially serious resource constraints. FWIW, I think all of this research coming out (SF FED for example) pointing to a lower d(potential GDP) is nothing more than a REFLECTION of resource constraints experienced between 2005-2008 (expensive oil as exhibit 1). As usual, the standard interpretation puts the cart in front of the horse and says that the recession is leading to a lower potential GDP. Hogwash. I'm not saying that it isn't an integral part of the mechanism, and I'm sure the granger causality tests are rejected, but it is still putting the cart in front of the horse. The REASON we had the downturn in the first place, and the REASON people switched to feeling quite pessimistic about things stem from resource constraints. Same goes for the credit crisis IMHO, but that is harder to show.
For those that want evidence that the resource constraint could have been responsible for the great recession (with credit channel intermediaries acting only as a delivery mechanism) check out my paper on oil at http://outsidetheboxecon.blogspot.com/ or any of Hamilton's papers on the same subject. Fits the data very well: much better in fact than the monetary theories.
Any way, I have kind of wandered away from my initial point.
My point is that the US/China situation does not have a good comparison. The US is an awesome country. However, we are hamstrung by debt, and that could create an out-sized setback to our economy if the world experiences meaningful resource constraints over the next decade.
All back of napkin estimates but let's parse that a little.
Trade surplus for those three months~$33 Billion. Interest payments on US, EURO, and Japanese bonds~$6-10 billion.
Valuation effects on Euro, Japan, and other assets due to the (on average) 7.5% appreciation of Yen, Euro, etc: $45 billion.
Which leaves us roughly $95 billion of "hot" money; multinationals trading their dollars in for yuan to invest or build capital in China, plus some investors who manage to slip through the cracks.
In other posts I've talked about how asset preference shifts are a major determinant in exchange rates, and this is a wonderful example. As risk aversion subsided, dollars sought opportunities on foreign shores (in this case China) and I'm sure this was responsible for part of the drop in the dollar, in spite of China's currency peg.
So the US is damned if we do damned if we don't. Either we have a strong currency paired with risk aversion, or we have an improving economy paired with a falling dollar. No way around it.
People like to compare US/China situation to Britain/US 100 years ago. They point out that the dollar didn't become reserve currency for 25 years after US became dominant economic player. This comparison leaves much to be desired though. For one thing, US is roughly same land mass as China, is natural resource rich. That would argue that China will not overtake the US as the world leading economic power, much less depose our currency.
We still have the best universities and a tradition like none other of risk taking (which definitely correlates with high economic activity).
On the OTHER hand, we are definitely in a funk, particularly K-12 education; we are in much worse fiscal/debt shape then UK was at the same time; we have a fiat currency; and face potentially serious resource constraints. FWIW, I think all of this research coming out (SF FED for example) pointing to a lower d(potential GDP) is nothing more than a REFLECTION of resource constraints experienced between 2005-2008 (expensive oil as exhibit 1). As usual, the standard interpretation puts the cart in front of the horse and says that the recession is leading to a lower potential GDP. Hogwash. I'm not saying that it isn't an integral part of the mechanism, and I'm sure the granger causality tests are rejected, but it is still putting the cart in front of the horse. The REASON we had the downturn in the first place, and the REASON people switched to feeling quite pessimistic about things stem from resource constraints. Same goes for the credit crisis IMHO, but that is harder to show.
For those that want evidence that the resource constraint could have been responsible for the great recession (with credit channel intermediaries acting only as a delivery mechanism) check out my paper on oil at http://outsidetheboxecon.blogspot.com/ or any of Hamilton's papers on the same subject. Fits the data very well: much better in fact than the monetary theories.
Any way, I have kind of wandered away from my initial point.
My point is that the US/China situation does not have a good comparison. The US is an awesome country. However, we are hamstrung by debt, and that could create an out-sized setback to our economy if the world experiences meaningful resource constraints over the next decade.
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