January 27, 2016 § 1 Comment
With Electric vehicles are at in interesting inflection point. Car makers are finally getting serious about traversing the main hurdle: battery cost. When the Nissan Leaf first emerged, and for that matter also the Chevy Volt hybrid, lithium cells cost over $450 per kWh (kilowatt hour). As a rule of thumb, each mile driven uses 0.25 kWh. A hundred mile range will require 25 kWh in principle. But it is impractical to drain down to zero and a useful figure is likely 80 or 85%. In other words, 100 mile range likely needs a battery pack with about 30 kWh.
Many of us have posited the notion that cost had to drop below $200, preferably $150 for any sort of widespread use. At $150 per kWh, a 30 kWh battery would cost about $5500, accounting also for the ancillary costs for the pack beyond that of the cells. That is a reasonable fraction of a selling price of $25,000, a useful target for an economy 5 seating car. An all-electric car has no internal combustion engine, no transmission, possibly no differential (if 4 motors are used), all of which reduces cost. But a 100 mile range may not sell broadly (witness the muted enthusiasm for the current Nissan Leaf). At 200 miles, we are talking the battery pack costing $11,000. That probably takes the pre-rebate price up to $36,000. Is that too pricey for most?
A Prius type of hybrid has many of the good features of EV’s: regenerative braking, engine stops when stationary, electric drive for start and low speed, where IC engines are less efficient, to name the principal features. All of these combined will typically add 40% or so to the gas mileage in city driving. I mention city driving for two reasons: one is that it shows off the hybrids the most and two because the all-electrics such as the Leaf are impractical for distance driving at this time. These cost 2 to 4K more than the base model. 200 mile range all-electrics eventually ought to cost about 6K more (after realizing gains on lower cost mechanicals).
Tesla is making things interesting. Their luxury Model S is priced not much more than regular luxury models. The 60 kWh battery is about to be replaced with a 70 kWh pack. They flirted with a 40 kWh pack and it never really left the blocks because of perceived customer reaction. It shows in buying behavior as shown in the 2015 statistics for large luxury cars. It seems that the same luxury for about the same price with zero tailpipe emissions makes it an easy decision.
The buying habits of this cohort may not comport with those of economy car buyers. So the $36K (before rebates) crossover may not have the same reaction. GM is betting on the forthcoming Bolt (great name by the way, reflective of the fast start possible with electric drive). Priced at $37,500, it will have 200 mile range (which, with a 60 kWh battery, is consistent with our computation above and so is believable) and seat 5. It will have plenty of pep: 200 HP (150 kW) and 206 foot pounds of torque. With the heavy batteries on the bottom of the cabin compartment, the center of gravity is in the middle and low. So in addition to being peppy it ought to handle well. GM can do this because they claim to be getting the batteries for $145 per kWh and much as Tesla has claimed, expect that to drop to $100 by 2020. These prices ought to translate to Nissan as well. So expect a bigger battery Leaf model.
Low gasoline prices, likely for a couple of years, affects some of the decisions. But it comes down to this: a hybrid five seat vehicle can deliver 45 mpg in the city. An all-electric will give about 105 to 110 mpg (computed on the basis of a gallon of gasoline containing 34 kWh of energy). It will cost more but maintenance will be much less, and so on. And there is the environmental benefit. Provided the big guns go forward with their intent the consumer will have choice.
December 14, 2015 § 1 Comment
Crude oil prices reached $36 per barrel this week. I had opined in a previous post in April that oil prices would fluctuate in a saw tooth pattern. Well, that has come to pass after a fashion, but not quite in the way I thought it would. First the facts, as shown in the figure below.
There is an oscillation. But it is modest and not driven by the assumptions of my model. Those had been premised upon two key factors. One was that OPEC would cease to be deterministic on price and that normal supply and demand conditions would be in play. That has happened. My other view was that when prices dropped sufficiently, demand would pick up, and in turn drive more shale drilling. Months after that kicked in, the new production would dampen price and so on.
Two major macro events have conspired to vitiate the theory, at least for now. China is practically in a recession, at least as compared to their explosive growth of the previous decade. The consumption drop, both real and perceived, is limiting oil demand. India, while not in the same state per se, has simply not delivered on the growth promise of Prime Minister Modi. This is in part because his party does not control the upper house (sort of like the Senate in the US) and in part because his mandate is being severely tested by a huge loss by his party in the populous state of Bihar. Business friendly changes will be slow to come. On balance, the two countries expected to produce increased demand are not showing up.
The other factor has been the so-called Fracklog. This is the inventory of wells that have been drilled but not yet fractured. The impetus for this approach was in part that this differed about two thirds of the cost until prices improved. The other reason to do it this way is to perform like tasks, in this case drilling and casing of the wells, all together. This improves efficiency in the logistics of materials supply and the like. Offshore platforms routinely operate in this way and a variant is known as batch drilling wherein even the drilling portion is done in batches (a single well is not drilled from top to bottom and then the next).
In the case of shale oil the next step, the fracturing, simply has not occurred for a number of wells waiting for better prices. That count is believed to be around 5000 wells. It was a scant 1200 or so early in the year. Assuming initial production from each well in the vicinity of 500 barrels per day (bpd), the effect would be a potential 2.5 MM bpd if unleashed all at once. That is logistically impossible even though each well could begin producing within a week of equipment arriving. But even an additional couple of hundred thousand bpd would move the price needle down measurably. Possibly speculators are concerned that cash strapped owners will do just that at some point. This bearish thinking may be a factor in the price staying down.
Another curiosity as of today (December 14, 2015) is that WTI almost has price parity with Brent. This is unprecedented going back at least 4 years. The spread has been about 10% until recently. It all began when shale oil really took off in volume and export restrictions limited its market. The figure below shows the trends.
My hypothesis is that the speculators are assuming that the export restrictions will be lifted. There has been a lot of press on Congressional action being imminent. Mind you, the horse trading to achieve that legislation is of the type that often stalls near the finish line. Nevertheless that is the only argument that makes any sense of the spread disappearing.
At this point I feel that the saw tooth behavior is still likely but at lower numbers until true demand creation and some destruction of the fracklog. Some smaller oil companies will fail but the properties will be snapped up by the better heeled independents; the majors will not participate much in this. They in turn will eschew the ultra-high cost developments such as the Arctic, which is all to the good. Their forays to date have been unproductive and in my opinion the environmental risk is not worth the reward.
June 2, 2015 § 2 Comments
A century or so ago Tesla and Westinghouse beat Edison in the war of electricity transmission and AC became our way of life. In an odd modern twist, the first, and most famous electric car is named after Tesla, but runs on DC current. Most electronics run on DC, but AC continues as the transmission medium, dooming us to the ubiquitous “brick” converting to DC for our phone charging, computers and so on. The DC worm is turning. In some measure this is due to fact that the output of solar panels is in the DC mode, as is that of back up batteries. Organizations such as the EMerge Alliance are making some inroads in commercial buildings with a proposed 24 V wiring standard. But curiously the lead for the resurgence of DC usage in homes may well be from India.
wtih apologies to the Australian rock group
Power shortages are a way of life in most developing nations. Consumers who can afford it have back up devices which are inherently inefficient. The rest simply do without for several hours at a time often each day. Most governments respond with more power plants, which in many countries are coal fired, with attendant effects on public health and climate change. The Indian Institute of Technology, Madras (IITM), has initiated the Uninterrupted DC (UDC) program. This is an innovative scheme to provide continuous power even during the intervals of shortage. This is accomplished through some changes in the grid system at a sub-station level, combined with households using energy-efficient DC devices. Widespread acceptance of this concept will require some equipment to be redesigned. But many other common devices such as computers and cell phone chargers, as well as energy efficient LED lights already operate on DC. DC powered fans are already available. Large scale adoption will improve consumer experience through uninterrupted service and reduced costs and have a net positive impact on the environment.
India is poised for rapid economic growth. This growth brings with it increased requirement for electric power at the industrial and consumer levels. Chronic power shortages especially at peak intervals have to be managed. Industrial consumers rely on diesel powered back up power, which has its own issues with particulate matter emissions. Private consumers have two choices. Those that can afford to install inverters in each home which charge batteries for use during the outage. AC power is converted to DC for storage and then reverted to AC for running devices. Each of these steps has an associated loss. Furthermore, when the power comes back on, each of these systems charges up for the next time, creating a surge on the grid. The UDC system is targeted at providing limited service continuously while at the same time reducing the overall energy consumption. In essence this is an aspect of Demand Side Management. It fits with the overall direction from the International Energy Agency that any reasonable carbon emission targets in 2050 can only be met by using 50% less. India and China are routinely cited as major contributors to atmospheric carbon due in part to reliance on coal for power. Program such as UDC could lead the way to mitigating the environmental impact of coal for power. Uninterrupted DC (UDC) technology is so named by its inventors, to emphasize that it delivers a useful quantity of power in uninterrupted (24×7) mode, and in DC form, incentivizing use of efficient DC appliances. Devices powered by DC can be 50% or more efficient than their AC counterparts. Use of such devices and the systems to enable these are central to the concept of UDC. In low to moderate income households the critical devices for continuous operations are lights, fans and either cell phone chargers or LED televisions. A home that typically uses 1 kW of AC peak power, could get by with 100 W of DC with somewhat reduced functionality.
The UDPM is a new device at the spot of the current meter and is the heart of the UDC system. It incorporates the existing AC meter and adds capability to split the incoming power into a DC 48 V line and a conventional AC 230 V line. The house is rewired to accommodate a few low voltage lines to run the low voltage devices. In a peak demand period the sub-station will send 10% of the normal electricity to each home instead of turning it off, as is the current practice. The UDPM at the home will utilize it solely for the 48 V service. During the period of the brownout the sub-station steps down the power to 4.2 kV from the normal 11 kV. The UDPM detects this voltage drop, cuts the AC output, and limits the 48V DC output to, say, 100W. This robust signaling is another innovative feature of the system. Importantly, during normal operation, both home circuits are in use, but the DC output is always limited to the brownout level of 100W. This allows for the utilization of the low power DC devices all the time and not solely during the brownouts. The consequential lowering in the power bill is a positive for the homeowner, and the continuous use incentivizes the manufacturer.
Fit with Solar Energy: While the initial focus of UDC is reasonably moderate income homeowners, the middle and upper-middle class segment could also be addressed through the addition of solar energy. This source is DC power to begin with and is artificially converted to AC for conventional appliances. This can still be allowed while a significant portion could be used in the DC mode. Typical solar outputs are 12 V and four together add up to 48 V. Perhaps this is why IITM chose that particular voltage, not to mention that 48V has been the standard DC voltage for telecom equipment worldwide. 12 V is also the output of standard lead-acid storage batteries. Ultimately one could expect even compressors for refrigerators to go the DC mode. Air conditioning would be next, but for the drier parts of India air coolers using water function quite well and those components are DC amenable.
Conclusions: UDC is an elegant addition to the Demand Side Management arsenal. It generally falls in the category of technology solutions although a small element of behavioral change exists. Utilities will undoubtedly welcome this development. Since the changes have to be at the sub-station level, the conversion could be staged community by community. IITM reports that pilots have already found word of mouth spread of the demand. An innovative business model may be necessary to pay for the modifications in the homes. Widespread use of this technology is certain to reduce the overall national burden on the power sector. Countries could justifiably claim advances in GHG mitigation.
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.
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.
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.
October 8, 2014 § 7 Comments
There is that movie soundtrack by Paul McCartney which goes “Live and let die”. If the current drop in oil prices (see figure below) is sustained for any significant length of time, the effect on countries will be highly variable. A sustained Brent oil price below $90 per barrel will do potentially grievous harm to the Russian economy with or without the financial burden of aggression in the Ukraine. The latest Russian budget was premised upon oil at $100, and given that over 40% of treasury coffers are filled with oil and gas revenue, a sustained price below $90 would be very difficult to swallow. Some reports have it that every $1 drop in Brent results in a $2.1 billion annual drop in revenue. In fact in an earlier blog I had mused on the option of release of the Strategic Petroleum Reserve (no longer needed in the US due to burgeoning domestic oil production), to drive down prices, or the mere threat to do so, to influence Russian aggression.
The US on the other hand will broadly be unaffected. A steady Brent price between $80 and $90 (if there is such a thing as steady oil pricing) could dampen some of the shale oil ardor. Shale oil prospects are highly variable with respect to breakeven price, but the vast majority of them make good returns at $80 per barrel pricing. Particularly if oil export were to be permitted, the net effect would be minimal. This is because US shale oil currently sells at a discount to Brent of well over $10, and export would afford it full Brent pricing. Allowing exports would markedly improve the resiliency of US shale oil production relative to softness in world oil pricing.
Many oil producing countries could be placed in an untenable situation were the Brent prices to stay below $90 for extended periods of time. The Gulf monarchies have spent lavishly on their populations especially following the Arab Spring. Good numbers are hard to come by, but Saudi Arabia is believed to need a $90 price as a minimum to sustain the social benefits. That number is higher in some of the other OPEC members such as Venezuela and Algeria, as also in Iran.
The drops in oil price do not appear to be any country’s doing. As we previously reported, world oil production dropped by 2 MM bpd over the last two years and was entirely made up by new US production from shale deposits. But more recently supply has also picked up elsewhere, especially Libya. Demand on the other hand has reduced, especially in the US. The trend towards demand reduction will continue at least in the US, where methane and ethane will displace oil in transportation and as the feedstock for chemicals such as olefins. Although unintended, a sustained drop in oil prices will serve the political interests of US and its allies vis a vis containing Russian aggression in the Ukraine. A sustained loss of oil and gas export related revenue, in conjunction with economic sanctions, would make military expenditures in the Ukraine affair essentially infeasible. The most related aspect of the sanctions is that with loss of revenue the Russian oil firms would need to borrow and foreign capital would simply not be available.
This is somewhat ironic because Russia has threatened to use curtailment of gas supplies to Europe as an imposition of political will. I have maintained in these pages that energy is a much more powerful weapon than armies for exacting pain for behavior seen as detrimental to the interests of a producing country, in this case Russia. In other words they would be living by the sword of energy. It seems now that there is a risk of dying (thrown into a deep recession) by that very sword, even if it was wielded unintentionally and by no one in particular.
September 18, 2014 § 2 Comments
The oil export ban is an anachronism and needs to be lifted. The original energy security beliefs no longer hold water. We are fast approaching the point at which domestic production augmented with that of the near neighbors Canada and Mexico will serve the bulk of our oil needs. Combine this with the fact that an overabundance of natural gas will inexorably displace oil in many sectors, beginning with key chemicals such as ethylene and derivatives.
The most compelling argument until recently was the nature of the oil that we produce. It is light (API gravity greater than 40) and sweet (less than 0.4% sulfur), making it highly desirable to all but the US refineries. This anomalous situation comes about from the fact that most US refineries are outfitted with expensive process equipment to handle heavy crude (API gravity less than 20) often with high sulfur and heavy metals. Heavy crude sells for a discount of 15 – 30% to the benchmark West Texas Intermediate (WTI). So they are loath to pay full WTI price for crude that does not effectively utilize their expensive equipment. The result is that oil from the Bakken has sold in 2014 for a discount to WTI ranging from $5 to $15 per barrel. WTI in turn is selling at a discount to the North Sea benchmark Brent price. In 2014 that spread was between $5 and $12. US refiners love this spread because their raw material is cheaper. They also love the shale oil to sell at a discount to WTI. They are the principal opponents to lifting the crude export ban.
A segment of the public believes that oil exports will lead to higher gasoline prices. Since oil is fungible, with a world price, this argument is not viable. However, one could argue that export ban mediated lower cost oil would allow US refiners to produce gasoline for less and pass on that reduction to the consumer. The fly in that particular ointment is that gasoline exports are permitted by law. So refiners will necessarily sell to the highest bidder. In fact, export of US diesel to Europe is believed to be in part responsible for the shutdown of refineries there.
This last point brings us to the second reason to consider lifting the ban: possible oil diplomacy. Europe currently imports over 3 million barrels per day (bpd) from Russia, in addition to 14.7 billion cubic feet per day (bcfd). Retaliation for sanctions is likely to come in the form of energy supply tightening. US oil exports to Europe will have two positive outcomes. One is just the gesture of coming to their aid and the corollary benefit that this quality oil is well suited to “simple” refineries, especially in Eastern Europe. The other benefit is to the US GDP. This oil will sell for Brent price, which as we noted before is $10 to $27 over what Bakken oil sells for today. Even at just a million bpd, that results in additional revenue to US producers of up to $10 billion per year. Keep in mind also that US shale oil production has been seeing annual increases of a million bpd for the last two years. The figure reproduced below from Platts is striking.
Over the period February 2012 to May 2014 US production increase has single handedly made up for a net drop of 2 million bpd from the rest of the world. While this US production rate is expected to slow in 2014 to closer to 0.75 million bpd, the contribution will continue to be large, and the bulk of this is not suited to US refineries. So the domestic glut of light sweet crude is likely to continue. Exporting oil is good for the economy and a potentially important political gesture at a time when European allies are needed to combat the latest threat in the Middle East.
May 30, 2014 § Leave a comment
A recent report by Gal Luft suggests many measures for Europe to be less dependent on Russia for their natural gas. An intriguing one is that the International Energy Agency (IEA) creates and manages a strategic reserve of a liquid fuel that could be run in gas turbines in times of shortage. In effect it would be a strategic gas reserve in that it would guard against disruptions in the supply of gas. He suggests the liquid be an alcohol such as methanol.
Short term storage of methanol
The concept of methanol as a storage medium for subsequent combustion to generate electricity is not new. But these have all been for short term storage; the methanol to be consumed at the location it was generated. One elegant concept is tied to the “clean coal” technique of power generation known as Integrated Gasification Combined Cycle (IGCC). Here coal is reacted with water to produce synthesis gas or syngas, which is a mixture of carbon monoxide and hydrogen. Typically this is further “shifted” to produce hydrogen and carbon dioxide. The CO2 is destined to be sequestered in some way and the hydrogen is burned for power.
All coal and nuclear plants face the problem that electricity generated at night is of little value and that during the day there can be peak demand periods in excess of 25% over baseline. Yet they cannot be turned on and off. IGCC plants offer the option to convert much of the syngas in the slack period to methanol. This is a simple chemical process. The crude “fuel grade” methanol could be stored and then burned in the specially modified gas turbines at any time. Peak load periods could be served running the stored methanol. The additional cost to convert syngas to methanol would be about USD 6 per million BTU (MMBTU), not much more than would have been to “shift” to hydrogen. However, this portion of the electricity generation would produce CO2 and in that way vitiate an objective of the IGCC. On the other hand this would be a clean burn not that different from natural gas.
Strategic storage of methanol
A strategic reserve of methanol in Europe, as suggested by Luft, would have somewhat different economic considerations than the example given above. In the case of the IGCC the plant would only have to consider the cost of production, not the market price. Also, they were using the higher cost fuel only during peak periods, when the electricity sales prices are high and can sustain a somewhat costlier fuel.
A strategic methanol reserve in Europe would have the following characteristics. The methanol could be raw methanol straight out of the reactor with impurities such as DME. The market price for methanol could be expected to be in the neighborhood of USD 25 per MMBTU. The cost would be lower for an impure product, likely discounting USD 4. This would compare against a nominal natural gas price of around USD 10 per MMBTU. But two other considerations could narrow the gap. Strategic reserves are owned by country governments. These entities could collectively own methanol production facilities that then delivered the fuel on a cost plus basis to each reserve. With USD 4 natural gas, this cost plus number could be expected to be in the vicinity of USD 14. It would be even lower when sourced from Qatar or Iran. The price on release could depend upon the situation. In any case releases would take place only in the event of a severe dip in supply, politically or otherwise driven. In that situation the actual market price would be higher than the nominal USD 10, thus narrowing the gap. Besides, the national energy security benefit and the correlated issues of keeping the traditional suppliers such as Russia in line, have value.
Having the IEA take the lead on a strategic gas reserve has precedent. All 28 member countries of the IEA are required by agreement to hold in reserve oil to the tune of 90 days of consumption in the previous year. Net exporting nations such as Norway are exempt from the requirement. Some countries by treaty support each other, such as the US commitment to support Israel with the US Strategic Petroleum Reserve (SPR). The term “petroleum” is interesting because only oil is being stored and yet the term technically applies to all hydrocarbons ranging from oil to natural gas liquids (NGL’s) to methane. This is because the foregoing is part of a continuum in the conversion of organic matter to hydrocarbons. This is why one finds gas associated with oil (much of it being logistically stranded and hence flared) and liquids associated with gas. In the parlance, though, petroleum has become synonymous with oil. This does not prevent oil import/export statistics from counting NGL’s in the figures!
As we have discussed elsewhere, the concept of the SPR for the US is less compelling now. Domestic production is on a rapid rise and new shale oil wells can be drilled and produced in a matter of weeks. In a sense, the shale reservoirs are our reserve. Consequently, the US could offer arrangements to other countries similar to that with Israel. India is a possibility; their current reserve covers only two weeks of consumption. The US has a diplomatic hole to dig out of with the presumed new Prime Minister, having denied him a visa some time back. This could help.
A strategic reserve to guard against gas supply disruptions in Europe certainly has merit. Methanol appears to be the most viable fluid to keep in the reserve. While the storage mechanism is very straightforward compared to storing oil, the economics need to be worked out considering in particular the externalities.
March 31, 2014 § 3 Comments
George Soros was recently quoted as suggesting that the US use the Strategic Petroleum Reserve (SPR) as a deterrent to Russian aggression in the Ukraine. No details were given but I thought we could examine the validity of the premise. Certainly it was more promising than the knee jerk suggestion by others that we export LNG to the Ukraine, which too we will debate.
The SPR was created following the Arab Oil Embargo in the early seventies. It is currently near capacity at about 700 million barrels. The intent had been primarily to guard against a disruption of imports. In some ways shale oil has changed much of that. Domestic production has catapulted in the last few years, with the prospect for much more. These are relatively shallow wells drilled quickly compared to offshore wells. A supply disruption would require SPR help for a much shorter period than was envisioned back when the capacity was designed. The country is also using significantly less oil now. Finally, cheap shale gas is going to steadily displace oil.
All of the above argues for the release of the SPR if a national imperative dictates. It could be drawn down significantly without affecting the original mission. One such imperative could be to dampen the expansionist ardor of Russia. Oil represents more than half of all Russian budget revenues and 30% of the GDP. If we were to release 1 million barrels per day for a month, that 30 million barrel deficit would be wiped out by new production (in addition to the current rate) from the Bakken and Eagle Ford in pretty short order. This is, of course, if we want to top up the SPR. In my view that is not necessary. Also, the SPR was filled up at an average cost of a bit under $30 per barrel. A little profit will be made as well by the Treasury. History has shown that a million barrels a day will cause a serious drop in the price of oil. The size of the SPR backing up the threat would also be a factor. The result would be a dramatic impact on the economy of Russia, hopefully just in the short term to change behavior.
This action could not be taken without the active cooperation of the Saudis. Their buffer capacity could make it up in no time. US relationship with the Saudis is at ebb right now due to the Syrian situation. However, in their eyes Russia is a worse actor in Syria than are we. So they may just go along. Also the mere threat may be enough. But it has to be credible. Release for a week may be necessary, much as Russia did in cutting off gas through the Ukraine in 2009 for ten days.
Now for the knee jerk suggestions regarding exporting LNG to the Ukraine to help out. First, could LNG ships navigate the Bosporus Strait? The answer is probably a reluctant yes from Turkey. But LNG goes wherever there is the best price. US sourced LNG would likely go to Asia. Admittedly, however, any US sourced LNG going to Asia now releases Middle East LNG for the Ukraine. The clincher on this whole argument is that any new permits would take at least two years to start export and even that only if the permit was given to an existing LNG import terminal. A brand new terminal would take four to five years. So if curbing Russian aggression in the short term is the intent LNG makes absolutely no sense, even as sabre rattling.
A scant five years ago who would have thought that the US may be in a position to use hydrocarbons as a weapon of political will? Shale oil and gas achieved that single handedly. This is another reason why we have a duty to produce it responsibly.