April 23, 2015 § 1 Comment
The price of oil is going to look like saw teeth for some time to come. For purposes of simplicity I will stick to using Brent, the benchmark price for the rest of the world. As I have opined before, if the US lifts the ban on export of our oil, WTI price will rise to Brent levels. These two benchmarks were in lock step for years and then began diverging in 2011 when shale oil seriously hit the market. While on the face of it simply a correlative point, I believe it is causal. When condensate exports began being allowed in 2014 the spread narrowed. I believe that when exports are permitted the spread will disappear altogether.
The graph shows Brent pricing up to late February 2015. Of interest is the fact that while the original drop was massive, nearly halving the price, the recent excursion is 25% off a new floor. True demand alteration is hardly ever that sudden. This is likely a result of real or perceived change in supply. Around that time Libya, which had fairly suddenly come on stream with 700,000 barrels per day (bpd) in late 2014, dropped to 200,000 bpd following sabotage and ISIS sourced violence.
On a go forward basis, the reason for price excursions will be real changes in shale oil production together with speculative beliefs in this regard. I have asserted in previous posts that the US has unwittingly become the swing producer, meaning when it sneezes world oil catches a cold. The Saudis used to have this status together with OPEC determinism of oil supply. Recently Boone Pickens shared a stage with former EPA head Carol Browner and ex-secretary of energy, Steve Chu, discussing the environmental safety of shale oil and gas production; no doubt the debate was entertaining. Associated with this occasion Pickens stated to the press that the US was responsible for the oil price crash, not the Saudis. While this is not exactly news to at least readers of my posts, I cannot recollect a causal link being suggested by any person vested with expertise. Most of the press has been on why the Saudis did it, rather than whether they did it. Damaging US shale oil production and hurting the economy of Iran and weakening Syria’s Assad (the latter through impoverishing financier Russia) were the principal theories advanced. Assuming the validity of Pickens’ assertion, one can conclude that if US production brought the price of oil down, then reduction in the same would send it back up. One theory of Saudi motivation would be supported.
Were the US production in question from conventional resources such as offshore development, one would not expect discontinuities. Conventional production has long latencies: many years to get going and it is not economically viable to turn off and on. Shale oil on the contrary is relatively easy in this regard. Producing wells can be “shut in” with relative ease, especially gas wells. Since these wells tend to decline rapidly in production, mere maintenance of rates in any given area requires drilling new ones. Simply not drilling new wells will have the net effect of reducing US production, which will in turn result in a rise in the price of oil. When the price is high enough they will begin drilling again. A new well can go on stream as soon as ten days after commencement. That period is even shorter for the over 3000 wells that reportedly are in “fracklog” bucket. This is a backlog of wells which have been completed all but for the final fracture stimulation step. Speculators are aware of this. They will drive price up when storage levels drop and the price has achieved a bottom of sorts. This cycle of price increase, new production then depressing the price, followed by reduction in drilling and production will repeat. The visual effect on a graph such as the one above is that of a saw tooth pattern.
Predicting the price of oil at any time is an exercise in futility. But my best guess at this time, based on continued weakness in China’s GDP growth, is that Brent pricing will fluctuate in the range $45 to $60 in the saw tooth pattern mentioned above. Whether OPEC can or will intercede in any way to affect this is not known. But it is unlikely that they will curtail production to raise prices. All that will achieve is more US shale oil production. I think the saw teeth are here for a while.
March 31, 2015 § Leave a comment
Not my usual blog. Just letting folks know that the site was down since March 16 due to a technical glitch. Even now you may get “certification warning”. Switch to Firefox or Bing or Explorer from whichever one gives the warning. Don’t ask why; I barely get by understanding these gremlins. Going to Firefox from Explorer did it for me. Sorry for the snafu.
February 24, 2015 § 4 Comments
My 2012 post High Octane has consistently had very high readership to this day. This merited a revisit. It is also a fitting topic on the heels of my last post regarding alternatives to petroleum based fuels being hurt by low oil prices. This price crash did more damage to that cause than just the already extended sojourn to the depths. It raised a specter that has always been in the psyche of oil old timers: the price can crash any time and it has in the past. In the recent past the dogma has shifted to volatility only north of about $90 per barrel. This was based in large measure on OPEC providing a floor and the juggernaut represented by the growing economies of China and India keeping demand pumped up. This last was bolstered by the well-known relationship between per capita GDP and car ownership.
Then the economic growth rates of China and India faltered. Furthermore, China started making a concerted push to use coal derived methanol as a gasoline substitute. India is experimenting with ultra-small cars such as the Tata Nano (70 mpg). Indian Prime Minister Modi recently lifted the restraints on genetically modified (GM) oil seeds. Rape seed oil (a variant is more conservatively named Canola) is expected to be an early beneficiary. Canola oil, ordinarily used for cooking, can be processed very simply into diesel with a process known as transesterification. In fact it is so simple that a garage operation would be quite economical. Also to be noted is that India consumes nearly three times as much diesel as it does gasoline, so oil seed conversion is advantaged.
But my favorite is Jatropha, which is indigenous to India, much of East Asia and Florida, for that matter. As I mentioned in a post two years ago, the time is right, and even more so now than when I wrote that piece. Jatropha created a lot of excitement in India and other places a decade ago because it was not a food crop and was drought resistant. The problem was that wild type jatropha was too variable in yield and other economically important parameters. Now with the plummeting in the costs of DNA sequencing, high throughput screening and associated data analytics a GM jatropha with great qualities need not be far away.
In some ways the foregoing discussion is something of a distraction from the premise of the original High Octane. There I suggested that ethanol, the legislative favorite displacer of gasoline, was not being properly utilized. Today Congress is seriously considering revising the flawed Renewable Fuel Standard. The principal flaw is the insistence on cellulosic ethanol, which has proved economically intractable. In today’s gasoline pricing scenario it is even more so. Technology simply has not kept up with congressional wishes and is unlikely to do so.
The biggest problem, however, is not that at all. It is the fundamental problem of trying to fit a round peg into a square hole. The two most viable gasoline substitutes, ethanol and methanol, will deliver 33% and 50% fewer miles to the gallon, respectively, in today’s conventional engines. These engines have been optimized for gasoline for a hundred years, which is why they have compression ratios of around 9. Higher compression ratios deliver more energy per gallon but cannot be tolerated by 87 octane gasoline. However, ethanol and methanol respectively have octane ratings of 113 and 117. A high compression engine will operate effectively with these fuel blends and give back much of the intrinsic energy penalty.
This is essentially a repeat of what I said in the last post. Now I have more ammunition to enable the substitutes. Both ethanol and methanol have one more very useful attribute that allows even higher compression ratios. They have high latent heats of evaporation. When injected into the cylinder the evaporative cooling effect reduces the temperature. This is a key because at high compressions the problem is temperature rise causing premature ignition of the fuel, also known as knocking. This cooling effect will enable very high compressions.
Now to the final point: is it asking too much of the automotive industry to modify the engines for higher compression? First of all race cars have high compression. But a more mass produced example just appeared a couple of years ago. Mazda introduced the Skyactiv engine which operated at a compression ratio of 13 with regular gasoline. The key step appears to be dual injection of the gasoline, the second one coming in response to temperature sensing and presumably producing evaporative cooling. This car is rated at about 35% higher highway mileage than the regular counterpart. One of the technology advances along the way has been to measure cylinder temperature and react to it. So they can do it if they want to.
Now consider the following facts. The cooling from injecting ethanol vapor would be about 2.6 times that from gasoline. A blend would be somewhere between and Mazda likely are getting a bit of that benefit with the 10% ethanol in most gasoline. And here is the kicker. With methanol that number is 3.7 times. So, even a 20% blend ought to give heck of a boost. Higher blends are completely feasible and China is piloting these, albeit in conventional engines. And methanol from inexpensive natural gas is more affordable than ethanol. Aside from the higher efficiencies, a cooler running engine produces less NOx. Also, a high compression engine delivers more torque. Such vehicles will be fuel efficient in the extreme, use less petroleum products, have vastly reduced tail pipe emissions compared to all but electric vehicles, and drive like muscle cars. They should move off the lot.
February 21, 2015 § 4 Comments
Sustained low cost oil will certainly damage the substitution of petroleum products in transportation. For the purposes of this discussion we will operate with the scenario that oil will hang around in the range $40 to $60 per barrel. But the answer to the question is more nuanced because oil is not oil. Different types of oil have differing carbon footprints and production costs. On the one hand, more cheap oil will inevitably lead to greater consumption and hence more associated carbon release. But what if the carbon footprint of the crude oil goes down, what then may be the net impact? We will discuss these matters below.
My position on oil substitution is essentially that of Ann Korin and Gal Luft in their book Turning Oil into Salt, substituting to the point that oil ceases to be a strategic commodity, and merely a useful one with alternatives. Prior to this oil price crash we were on our way albeit haltingly.
Status of Substitutes:
One entire class of substitutes was driven by arbitrage between gas and oil driven by per unit of energy price differential. This did not exist until about 2005 because both commodities were in lock step. In our assumed scenario the gap is still there, just closer to a factor of two than four in the US. The obvious casualties are natural gas conversion to diesel or gasoline. Sasol has already indefinitely postponed the Louisiana GTL plant. They would have struggled to be profitable at $90 oil. At half that they are in deep strife. Also, at a relatively constant $50 oil price US shale oil is essentially the swing producer, meaning ups and downs in this sector take the world price with them. In this scenario OPEC is essentially toothless and cannot be relied upon to be a stabilizing force on price. Nothing hurts a costly GTL plant with long amortization schedules more than uncertainty. With cheap shale gas in the US Sasol likely thought they had that licked. Then oil became low and uncertain and the wheels came off.
Less impacted will be gas to other liquids such as methanol and dimethyl ether. These are raw materials for a lot of chemicals and have world prices in their own right. Also, China is on a big push to substitute gasoline with methanol. Since that was driven largely by tailpipe emissions especially in urban areas, the reduction in the price of oil may not have as much effect. That could put a floor on the world price of methanol. Dimethyl ether is a seamless blend with LPG, a common fuel in countries such as India. Not yet commonly done, the lower hydrocarbon prices could slow down that thrust.
Direct combustion of natural gas in vehicles has had a lot of traction in the form of CNG in short haul and LNG in long haul applications. The narrowing of the oil/gas price will certainly reduce the economic merit of this action and consequently slow the momentum except in non-attainment areas and the like. The struggling passenger vehicle program will more than ever need technological advances in higher density and low pressure storage systems allowing economical charging in homes.
The challenge faced by widespread adoption of electric vehicles remains the same: battery prices south of $200 per Kwh are necessary. The next most important factor is reasonable night time pricing of electricity in all states. Gasoline prices matter, but not as much as the other two factors. The fact that electric vehicles (EV’s) are 60% more efficient well to wheel, and hence lower emitters of GHG (at power plants in their case) than conventional engines, ought to be recognized in policy setting. CAFÉ standard do not adequately take into account EV’s. At this early stage that is fair enough but a standard explicitly targeting emission reduction ought to recognize the unique EV advantage. The common challenge to EV’s is that they are only as clean as the electricity producing plant. The increased efficiency noted above means they simply use less energy no matter where it is produced. Furthermore, we are well on our way to at least solar power being cost competitive with alternatives in many markets without subsidies. Taken together with coal substitution by gas we can expect a gradual greening of electricity, certainly in the time frame that EV’s could reasonably be a double digit percentage of the market.
Consistently lower diesel and aviation fuel prices will reduce costs in the delivery of goods and of people. If this cost advantage is passed on it will increase commerce. Passenger vehicles will be driven more with low gasoline and diesel prices. CAFÉ standards will be harder to meet because the US public always switches to SUV’s and pickups when fuel prices drop. All of this and sheer increased commerce will add to the carbon burden.
What of the oil types and their carbon footprint? Canadian heavy oil is famously considered “dirty” by the folks opposed to the Keystone XL pipeline, meaning, that it has a high carbon footprint. This comes about in two ways. One is that this oil is intrinsically carbon rich compared to the hydrogen content. When refined it has a residue of carbonaceous material known as petroleum coke which is essentially coal with some differences. This can amount to up to 18% of the original oil. The second is that getting it out of the ground requires more energy than for recovering conventional oil. This energy use produces CO2. There is one other piece. Refining it requires a lot of heat to break down the big molecules. Considering all these factors it is a bit surprising that scholarly studies estimate only about 16% more carbon intensity when considering the “well to wheel” full cycle analysis. Part of the reason may be that so much of the emission is in the final combustion process no matter the source. One study has it as low as 6%. In any case it is more.
Prior to shale oil bursting on the scene, the marginal barrel of oil was getting progressively heavier. Even the more recent Saudi Arabian oil field Manifa is relatively heavy in character. The continued growth in oil consumption equated to more carbon release. Then came shale oil which is the polar opposite: very light and low carbon to hydrogen ratio comparatively. When shale oil is refined there is no need for high temperature molecule breaking processes.
Oil priced near $50, our scenario, results in a shift away from Canadian heavy oil provided enough of the light oil is available and can be produced sustainably. Canadian oil sands are exploited in one of two ways: Open pit mining and treatment of the oily sand and in-situ heating with steam to make it flow (SAGD). New mining operations break even at about $90 and are unlikely to be pursued. Paradoxically, already constructed mines are relatively cheap to operate if you don’t count amortization, in the vicinity of $25 per barrel operating cost, so current plants will continue to produce. SAGD breaks even around $65. Almost all future growth plans as far as I am aware are for SAGD, and this was even before the crash. Technology development continues to reduce the steam to oil ratios, which will help costs and carbon footprint.
Shale oil breaks even somewhere between $40 and $70. In our scenario the higher cost ones and those with restrictive financing will drop eventually. But the key point is this. These are early days in shale oil exploitation and technology to reduce costs is certain, it is only a question of timing. So, if the reserves are in fact there, North America will shift to a higher fraction of light oil and hence lower carbon footprint. But the original objective of chipping away at the oil monopoly of transport fuel still stands, while somewhat compromised by the low price on what it is substituting.
February 12, 2015 § Leave a comment
This is a Guest Post by Daniel Kauffman
Everyone has noticed that the price of gasoline is down significantly in 2015, with average prices in the range of $2.00-$2.20 per gallon compared to $3.40-$3.70 per gallon last summer. This 40% decrease makes sense given the 50% decrease in the price of a barrel of oil, which has dropped to $45-55 per barrel of West Texas Intermediate in 2015 compared to $95-$105 last summer. What has largely been overlooked is that though our gasoline bill is way down, our natural gas bill is not.
Last summer I was paying $0.93 per therm (about one hundred cubic feet) for natural gas, and now I am paying $0.89 per therm, only 4% less. How is it that we are seeing less money leave our pocket for gasoline but not for natural gas? Is there no downward natural gas shock to mirror the recent downward oil shock? Domestic wholesale natural gas prices have fallen, but not by as much as oil has. Henry Hub wholesale natural gas spot prices saw one million Btu (MMBTU) of natural gas (about 10 therms) trade in the $4.00-$4.50 range last summer, and are now trading in the range of $2.60-$3.00 (note: a million Btu is about 10 therms, so that is a drop from ~$0.42 to ~$0.28 per therm). The first thing to notice is that the wholesale natural gas price drop of ~1/3, though significant, is not as large as the 50% oil price drop. The second thing to notice is that the price pass-through to the consumer is much higher for oil: around 70-80% of the price decrease in oil is being passed through to the pump in its refined derivatives of gasoline and diesel, whereas we are only seeing a scant 4¢ cent/therm retail price cut on natural gas from a 10-15¢ cent/therm wholesale price drop, a less than 50% pass-through. The natural gas I am using to heat my home seems to be more expensive than it ought to be.
Let’s take these two issues separately: first the smaller wholesale natural gas price decrease, then the smaller pass-through reduction.
Two Years of Wholesale Oil and Natural Gas Prices
One explanation for the smaller wholesale natural gas price decrease is that domestic wholesale gas was already very cheap. Natural gas in the U.S. is, to a large extent, a waste bi-product of the highly profitable oil production industry, and in many cases the low prices simply did not justify the expenditure on natural gas gathering infrastructure to bring the product to market. The ratio of oil price in $/barrel to natural gas price in $/million Btu has dropped from ~24 last summer to ~18 now, but even 18 is very high by historic standards – it wasn’t until about 2009 that a long term range of 6 to 12 was exceeded (worth noting is that a barrel of oil has about six times the energy content of a million Btu of natural gas, so at a multiple of 18 we still value oil three times more than natural gas on an energy content basis). To some extent an oil/natural gas ratio drop from 24 to 18 is really just a small regression towards the long-term mean.
Paradoxically, the oil price drop may in some places cause natural gas prices to increase. This is because oil production will be deferred or new wells not drilled at all, thereby decreasing the quantity of natural gas coming to market. Less extra natural gas will put less downward pressure on wholesale natural gas prices at locations where there is spare capacity to bring that natural gas to market. Ironically, this also means that if oil prices go up again, natural gas prices may hold steady for the exact same reasons why they were already low to being with.
International LNG prices have recently come down dramatically. LNG contract prices in Japan, the world’s biggest LNG importer, have dropped from $16 to $10 per million BTU from last year to this, and spot LNG prices are less than $7 (in case anyone wants to redirect an in-transit LNG tanker), the lowest level in five years. Why has this precipitous drop not had a bigger impact on domestic prices? The simple reason is that the U.S. is not (yet) tied in to the global LNG trade, and so domestic supply and demand considerations will dictate prices with minimal international influence. For LNG importers such as Japan and South Korea, natural gas can be substituted with oil or coal as a power generation input source depending on commodity prices. Here in the U.S. though natural gas is still a growth fuel for power generation as decommissioning of old coal plants continue. A substitution hedge to another fuel in the short term is not really in the cards and given low domestic natural gas prices is not at all necessary.
Does a precipitous fall in global natural gas prices threaten America’s competitiveness in natural gas-intensive industries? Not really, and certainly not enough to move the needle on domestic wholesale natural gas prices. There has been a move over the past five or so years to expand natural gas intensive industries in the U.S., which produce outputs such as methanol, chemicals, fertilizers and glass. Such factories are long lead-time assets and once built prefer to run at capacity. There have been no major announcements of postponements of projects because the energy economics are suddenly more favorable elsewhere in the world (note: postponements and cancellations may occur because of corporate capital allocation considerations, but that’s a different issue). Foreign corporate owners might shift marginal capacity between their global factories based on relative regional input costs, but this is a very small short-term effect that would barely be noticed in the domestic wholesale natural gas markets. For the time being much of the world’s wholesale natural gas will still have prices linked to oil, and most natural gas in Europe will retain the “brought to you by Putin’s Russia” brand. Unless there is an assurance of long-term low natural gas prices somewhere else, corporations investing in America in part because of a competitive advantage in natural gas will have no reason to change plans.
In summary, here in the U.S. we have steady supply and captive long-term demand for natural gas, and a wholesale natural gas market detached from the far more globally fungible commodity of oil. It makes sense that natural gas prices simply won’t drop as much here as oil will in a downward oil price shock.
As for the second issue, the smaller pass-through discount, consider the difference in industries between gasoline and natural gas distribution and retailing. Gasoline is a refined commodity with multiple suppliers, delivered via tanker trucks in a highly competitive transportation industry, and sold to us by mom and pop gasoline retailers at very narrow retail margins. Everywhere in this supply chain, assets are substitutable and margins are squeezed by competitive pressure. Natural gas on the other hand more closely resembles the electric utility industry. Retail natural gas utilities such as PSNC Energy and Piedmont Natural Gas procure bulk natural gas in long-term contracts, distribute through a capital intensive distribution pipeline network, have no retail competition, and are by extension regulated utility monopolies within their territories. It would take a new distribution pipeline, such as the proposed Atlantic Coast Pipeline, to put a long-term dent in local retail natural gas prices. The competitive pressure in the two industries couldn’t be more different.
Personally, I’m going to enjoy the low gasoline prices while they last, which might not be for very long. Though I would have liked to see lower heating bills this winter, I take comfort in the certainty that they will still be relatively low for many winters to come.
Daniel Kauffman, President of TerraCel Energy
February 5, 2015 § 1 Comment
Much reporting has been devoted to the hypothesis that Saudi Arabia held the line on not reducing production in the face of plummeting prices in order to drive US shale oil production into retreat. If history repeats shale oil may actually become stronger, but not right away.
Hard to argue is the fact that the US has been placed in the position of becoming the swing producer. In other words US production surges and declines will directly influence the world price of oil. The Saudi’s used to be in that position and this was the primary basis for the OPEC cartel being the determinant of pricing. The US added a million barrels per day (bpd) to the market each year for the last three years. Until late last year this merely made up for declines in other parts of the world. Then Libya added 700,000 bpd late last year and supply went into imbalance with demand. This was particularly the case because China dropped into an unaccustomed single digit growth of their GDP, after a decade and more of double digit growth. That drop in demand in China and elsewhere (India’s growth rate also ratcheted down) combined with US production and Saudi inaction led to a halving of oil price in the matter of a couple of months.
Most oil companies have responded with projected reductions in spending. This will slowly have a depressing effect on production. Shale oil has breakeven pricing between $40 and $65. The higher cost prospects and those with restrictive financing conditions will drop out. Also dropping out will be the so-called stripper wells, loosely defined as wells producing less than 100 bpd. That’s right, shale oil wells produce as little as that. In fact the vast majority are well under 700 bpd. This compares to offshore wells producing 50 to a 100 times that. Also, flat production in shale oil requires continuous drilling, due to high rates of decline in production in a given well. The reported plummeting in rig count is therefore more of an indicator of future production decline than it would have been in conventional production. All of this means that shale oil production can be expected to start declining in a matter of months. This will put upward pressure on the price of oil. A new normal may well settle in around $60 by the end of the year.
But the purpose of this essay is not to predict the future on oil pricing. I am suggesting that a sustained low price of oil is likely to stimulate innovation. In the decade comprising about 1985 to 1995, the price of oil had sunk and rig counts went from 2400 in 1985 to a flat 700 or so in the early nineties. Forced to profit in a low oil price market (oil companies affected) and low rig count market (service companies impacted), industry, and the service companies in particular, responded with a basket of technologies that forced down the cost to produce. For interest, the technologies were 3D subsurface imaging brought to the desk top, horizontal drilling and key enablers known respectively as steerable systems and measurement while drilling (MWD). I was directly involved in the development and launch of the last mentioned, so know the period well. The figure below shows the change in cost to produce over that period (undiscounted). Service company profits were high because value pricing was available for that sort of gain. The company in which I worked had revenue increases in the period 1987 to 1994 of about 7 times, and EBITDA increases with an even higher multiplier.
Will history repeat? The reason to respond in the affirmative is in part that the industry has been living on borrowed time in this sector. In some ways the industry has been fortunate to profit while employing essentially brute force techniques. Many in the public believe that shale oil and gas spawned horizontal wells and hydraulic fracturing. Not so. Horizontal wells hit the ground running in the period mentioned above and fracturing had been going on for decades prior to that. In point of fact the technologies are being deployed in a very inefficient manner except for significant efficiency gains in the drilling process through pad drilling (closely spaced wells on a small footprint with rigs moving quickly on rails). In particular, the reservoir is not being well managed. Up to 50% of fracturing zones can be non-productive. Only about 5% of the oil in place is currently being recovered. New wells decline in production up to 70% in the first year. All of these can be attacked with a high likelihood of success. Again, the most likely players in this are the service companies in part because the vast majority of shale oil and gas is being produced by small players with little or no research capability. This is my first mention of gas. Shale gas will also profit directly from technology gains in the areas mentioned.
If history does repeat we could expect the breakeven price for shale oil to drop to $30 and below. If that comes to pass, and industry responds predictably, and the reserves are in fact there, the world will be awash in oil again. Market forces of supply and demand will control and OPEC will cease to be important.
December 1, 2014 § 1 Comment
The November 24, 2014 issue of the Wall Street Journal has a point counterpoint piece on this issue. Tyson Slocum of Public Citizen speaks against the notion of lifting the oil export ban and Jason Bordhoff of Columbia University is in support. They both discuss the popular issues: effect on gasoline price to the consumer, national energy security and the environmental threat of continued shale oil production.
Source: Energy Information Administration
The Domestic Oil Glut: Good for Us?
Slocum raises an issue that is new to me, that the glut is beneficial. He recognizes that keeping the export ban and thereby keeping US oil out of the world marketplace is a factor in West Texas Intermediate (WTI) oil price running below Brent, the benchmark for the rest of the world. The differential has been as much as $20 per barrel. It was not always so. Looking back the last five years, the split is coincident with the run up in production in Eagle Ford in 2011 and then later the Bakken. One could comfortably conclude that the differential was caused by US shale oil production and the inability to put it out on the world market. Of further interest is the fact that Bakken crude fetched a price lower than WTI for much the same period (late 2010 until the present). This was occasioned by the fact that the shale oil has a light sweet (sulfur less than 0.4 %) character. While seemingly a reason to rejoice for refiners, this presents a vexatious problem for them. They spent enormous capital on equipment to process heavy and mostly sour crude from Canada, Venezuela and Mexico. They also can buy this crude at a significant discount to WTI because of the relatively high proportion of carbon that cannot be converted to a useful fuel or chemical. Now they were being asked to substitute this discounted imported crude utilizing their expensive capital with domestic crude at WTI price that would idle said equipment. They responded by offering a lower price than WTI. This sort of market based pricing is normal. However, in this instance the market is being manipulated by the export restriction. US producers are not in a position to spurn the US refineries and sell for higher prices elsewhere.
Slocum argues that this is good for the country. He maintains that the resulting glut in US supplies “helps insulate the American economy from the uncertainty caused by oil supply disruptions abroad. Opening exports would remove that protection, which would be disastrous.” In other words he thinks maintenance of a supply glut in perpetuity through a policy action is a good remedy for the occasional burps in world supply. The national Strategic Petroleum Reserve (SPR) was created for just this scenario and no further policy action is needed in support. 30 million barrels of the reserve was released in 2011 in response to the Arab Spring related disruption. I have also opined elsewhere that the SPR could be drawn down quite a bit in recognition of the fact that shale oil can be brought on stream very rapidly. Proof for this assertion is that US shale oil production has increased by 1 million barrels per day (bpd) over each of the last two calendar years.
Effect upon Gasoline Pricing.
Both Slocum and Bordoff address this issue. The public in general appears to be in Slocum’s court in believing that exports would cause the gasoline price at the pumps to go up. Bordoff argues, in my opinion correctly, that gasoline is a world commodity and that prices are generally set by Brent pricing. He ascribes this to a finding by the US Energy Information Administration (EIA). I also agree with his view that allowing US crude on the world market is likely to have some downward pressure on Brent pricing, and hence gasoline. Of note, though, is that US crude would add light oil to the market increasingly dominated by heavier crude. So the main destinations would be “simple” refineries not the complex ones such as those that spurned it in the US. So a factor would be the number and locations of these. It is known that several such refineries have been mothballed in Europe. Incidentally, at least two small simple refineries previously shut down have now been reopened in Texas. One new one has been permitted in the Bakken, the first new refinery permit in decades.
Curiously, neither of the two authors speaks to the effect of the policy to allow export of refined products, including gasoline. These account for 3.5 million bpd. In my view, the fact that gasoline can, and is, exported, is a factor in gasoline prices remaining high simply by supply and demand arguments. In theory, however, a simple refinery located close to oil production could produce gasoline relatively cheaply and pass on the savings to the consumer locally. But this is not likely to be a large effect. Each of these refineries is less than 20,000 bpd, compared to world scale ones up to and over a million bpd. So their cumulative impact is relatively small. But if the trend takes a hold, and in my view it ought to, much of our oil could be processed in these highly distributed small refineries. Pipelines would be minimized, with a positive environmental footprint as a result. Today the Bakken is moving a million bpd crude oil in largely unregulated trains already shown to be prone to derailment and attendant damage. Local refining would be a welcome alternative.