Green Energy

Even those who are skeptical of extreme climate change would mostly agree that we can’t indefinitely keep pumping CO2 into the atmosphere. The conclusion is that we need to move to alternative sources of energy which do not use carbon fuel.

The cleanest are solar and wind, ignoring pollution due to fabrication and installation, which can be amortized. It seems clear that the developed world is moving to these at a really surprising and significant pace, especially considering the complexity and interdependency of any energy infrastructure.

The pace doesn’t seem satisfactory to those who are convinced of impending doom. However, intermittency is a huge problem. Energy from solar and wind is by its nature highly intermittent. Our ancestors for most of human history had to deal with the intermittency of sun and wind, but it would be a major adjustment for the modern economy.

If you can’t tolerate intermittency, the math is pretty simple. You either have a duplicate energy infrastructure capable of supplying full power when intermittent sources are not functional, or you must double the capacity of the infrastructure so as to top up batteries or other energy storage devices for use in the off hours. Either way, you need to build and maintain infrastructure capable of double the current power, which is economically problematic, because you are still supplying the same end amount of power, and therefore only using half capacity.

If you want to maintain a backup infrastructure which is not solar/wind, it will have to be turned off whenever solar/wind are producing. That will make it impossible to amortize. The renewables will seriously reduce any chance of running the backup during peak hours. The only economic alternative is to double the price charged the consumer.

It is sometimes suggested that a new national power transmission line infrastructure could be used to balance supply over hundreds of miles. However, there is NIMBY resistance to power lines, which seems more defensible after the recent disastrous California fires. Also, there is only a 3-hour time zone difference between the US coasts, so it hard to see how solar balancing would make enough of a difference.

The US uses about 400,000 MWh of electricity per night hour, so 12 hours of backup storage would be just under 5,000 GWh of storage. For comparison, the state of California currently has about 150,000 MWh of energy storage, mostly pumped hydro (see Appendix). That is only about 3% of the storage required nationally, and the true backup requirement is much larger, since I am talking here about only solar; if some of the renewable source is wind, and the wind doesn’t blow, demand will have to be served from backup even during peak daylight hours.

As noted before, generation capacity must be great enough to both supply daytime use and to top up storage; in other words, renewable generation capacity must be about double the instantaneous capacity required by a source that is available around the clock. Worst case, it must cover winter nights at high latitudes, which means up to 16 hours at the latitude of Seattle. There you would need triple the current instantaneous generation capacity.

Battery cost projections are enormous, even though great progress is being made in reducing those costs. Today, a Tesla PowerWall stores 14 kWh and costs around $10k installed. At that price, the current California storage capacity of 150,000 MWh would cost over $100 billion, and as we saw that is only 3% of the total needed nationally, so the total would exceed $3 trillion. Worse, batteries degrade over time and a useful lifetime of 10 years is considered quite good for lithium-ion technology.

According to Bloomberg, battery prices are projected to read $58 per kilowatt-hour in 2030 and $44 in 2035. At that latter price, the California storage capacity of 150 GWh would cost “only” $6.6b, and the national total only $220b.

Of course the US defense budget is about $690b, so some funding could be freed up if we truly believe it is a crisis, and that renewables plus batteries are the only answer. Having to replace those batteries every few years remains a problem, not to mention pollution and toxic waste from production and disposal.

The other problem with intermittency is that when sun and wind are producing, they may well be producing too much. In the absence of adequate battery backup to absorb that power, you have to either shut down or dump energy. So now you are paying for expensive generation facilities, plus backup, with double or even triple the output capacity of the existing infrastructure, and then you are sometimes shutting it down! Insane.

If you really think doom is impending, there are only two alternatives. One is to go immediately and completely to sun and wind, regardless of energy storage capacity. This implies intermittent supply, with a radical impact on modern life and business; essentially, going back to the way of life prior to fossil fuels, when the rhythm of life and commerce was driven by the capricious availability of sun and wind.

Worse, given such intermittency, many households and business will be incentivized to generate their own backup power using fossil-fuel generators. For instance, many owners of electric vehicles plug them in to recharge overnight – what are they to do? Are we going to use governmental force against them?

The other option is nuclear. It is the only non-fossil energy source that can handle the full energy needs of the economy without intermittency. If the alternative is doom, even toxic disposal and meltdown risks have to be considered tolerable.

If someone says to me that AGW is now a crisis, I expect them to also step up to one of these alternatives. Intermittency or nuclear. Anything less says to me they either don’t really think it’s a crisis, or they can’t do math.

A Good Word for Wind and Sun

Let me add a proviso. My argument so far has been focused on replacement of existing infrastructure in countries like the US, where virtually the entire population has its foreseeable energy needs met already, and where intermittency would be loudly resisted. However, the US only accounts for about 14% of global energy usage, and much of mankind still lives in places where intermittent energy is an accepted fact of life, and additional usable energy, from whatever source and however unreliable, would be welcome.

Much of the increase in pollution in coming years is projected to occur due to energy development in such countries. Therefore, for such countries, the economic argument is not the same as it is for the US and other developed nations. There is a ample reason for them to concentrate on renewables, and the benefits could be big.

Other Energy Storage Options

Although the electrochemical battery is currently by far the most researched and developed energy storage option, it is not the only one. Energy can be stored in mechanical devices, gravitational fields and fluids under pressure. However, there are serious practical drawbacks and scaling issues associated with all these options too.

The most basic issue is physics. The electromagnetic force is far more powerful than gravity, and is also utilized far more efficiently by chemical battery action than any other known process.

For example, if you want to use gravity by pumping water uphill, then releasing it to drive a turbine generator, you will quickly realize that an immense amount of water needs to be stored at the higher gravitational potential in order to match quite modest electrochemical battery energy storage capacity.

Several attempts have been made to commercialize energy storage in high speed flywheels. Unfortunately, as cool as they may look, these devices suffer from friction and fragility. Unless mounted on superconducting bearing designs, they lose energy rapidly, and a device spinning at high rpm requires substantial safety measures to guard against damage or injury from disintegration.

Carbon Capture

For the developed world, there might actually be a third alternative (instead of nuclear or intermittency): continue using fossil fuel power generation, but with carbon capture and sequestration (CCS) or reuse. This technology is very much in the early stages, but if you are absolutely against nuclear, and can’t tolerate intermittency, it may be the only game left.

One problem with CCS is the 2nd Law of Thermodynamics. Captured carbon is in a relatively low entropy state compared to free atmospheric molecules. This implies that carbon capture can’t be achieved without a concomitant increase in global entropy, for example, by generating energy to power the capture process. And that raises the question of where that energy comes from, and how much pollution is released as a side effect of generation. Things need to be measured very carefully to be sure that there is a net reduction.

Natural Gas

If natural gas is burned, it produces CO2, but if it is released without burning, methane is a far worse greenhouse gas than CO2 (greater cross section for infrared absorption). There are several major problem areas:

  1. Free methane release due to agriculture and landfills: there are some promising approaches to using so-called trash gas, primarily by collecting it, cleaning it, and injecting it into existing pipelines.
  2. Methane leakage: there is substantial leakage from existing pipelines and last mile delivery systems. The current approach seems to be to identify and cap all leaks. That is kind of like Whack-a-Mole.
  3. Flaring of gas from oil wells: all oil wells produce some gas, and often in quantities which are uneconomic i.e. not worth the expense of connecting to a pipeline. Commonly such gas is flared off – just burned. This is better than releasing free methane but still undesirable, as it puts CO2 into the atmosphere.

Wellhead Processing

A better approach might be to generate electrical power at the wellhead, so there is by definition no chance of a downstream leak. To scale this solution would require amendment of PURPA (the Public Utility Regulatory Policies Act of 1978) which disallows small local generators unless they use renewables.

If that restriction can be overcome, such local electrical generation would also allow the possibility of pumping the CO2 combustion product right back into the ground, resulting in a dramatic reduction in carbon emissions.

Other possibilities exist:

  • Natural gas might be used to charge NG fuel cells at the wellhead; this obviates the risk of downstream leakage.
  • Hydrogen might be produced by reforming of natural gas at the wellhead. There are technical problems with feeding hydrogen to existing pipelines, because the corrosion and leakage risks are greater, although hydrogen is not a greenhouse gas. However, such hydrogen could be used to charge hydrogen fuel cells directly at the wellhead.

Electric Vehicles

Consider further the effect of the accelerating transition to all-electric vehicles i.e. purely battery powered, as opposed to hybrids. Human beings will likely continue to be diurnal creatures, so the night-time demand for electricity, to recharge these vehicles, will do nothing but increase. Intermittency, with mostly nocturnal power outages, will not be an option.

Personal vehicles could be recharged opportunistically during daytime hours, as they are not typically in continual use. This is not so for long-haul truck and rail transport. Air transport is also concentrated in daytime, for many reasons, including safety; not to mention that non-fossil-fuel long-haul air would require truly revolutionary advances in battery technology.

There is fundamental problem here. Absent nuclear power, fossil fuel power generation will continue to be a major source, and the transition to electric vehicles may paradoxically increase demand for it. At least, centralized power generation may be more amenable to carbon capture. Another advantage is that electric motors are more efficient than internal combustion motors, so, even with carbon-burning electrical power generation, there still may be a net reduction in pollution.

New Designs for Nuclear Power

There are promising developments in this area. The rap on nuclear among Green advocates has gone from safety concerns to expense. Perhaps it became clear that nuclear accidents are very rare and very much over-reported. Far more people have died from the effects of air pollution caused by fossil fuels than have died in nuclear accidents; fear of nuclear power is a great example of the effect of “fake news”.

So the argument has now become that nuclear power doesn’t pencil out economically (even Rocky Mountain Institute, which I generally support, takes this tack). In the US, there is some truth to this, much of it due to lack of design standardization, and to a contentious licensing process. Before discussing a couple of new solutions, I might refer back to the previous calculation showing the immense cost of moving to dependence on renewables; if climate change must be abated at any cost, this is the alternative, and nuclear power is hardly more costly.

NuScale is a company in Portland OR which has developed (originally with funding from the US DOE) a modular, compact design – the Small Modular Reactor, or SMR. The SMR is built in a factory, rather than on-site, allowing for savings from production efficiency. If you want more power, you chain together multiple modules, making it scalable and again saving on production cost. A 12-module plant developing a net 683 MW has initial costs under $3 billion, and cost would likely go down with mass production. 400,000 MW, the target figure for the entire US, would then cost a maximum $1.75 trillion, compared to $2.5 trillion for a battery storage system alone – and the battery system still needs generation capacity to top it up.

The SMR also incorporates new safety features: for instance, if the power grid completely fails, the control rods drop by gravity into the core, shutting it down.

TerraPower, funded by Bill Gates, has developed a design for what is called the Traveling Wave Reactor (TWR). This reactor design uses a small core of fissile material to seed a reaction in depleted uranium, enriching U238 into Pu239 in-situ. The depleted uranium is currently waste material which presents a long-term storage problem, so the TWR solves that. It also solves the problem of enriching uranium in a prior process, which presents security and non-proliferation issues.

Unlike NuScale, TerraPower is still in the R&D phase. Cost estimates are not available, though it is promising that its primary fuel is material currently viewed as only waste.

Appendix: California Dreaming

by James Temple, MIT Technology Review July 27, 2018

There are issues California can’t afford to ignore for long. The state is already on track to get 50 percent of its electricity from clean sources by 2020, and in August 2018 the legislature passed a bill that would require it to reach 100 percent by 2045. To complicate things, regulators also voted in January of that year to close the state’s last nuclear plant, a carbon-free source that provides 24 percent of PG&E’s energy [note: according to another source, that is 9% of the total California energy mix]. That will leave California heavily reliant on renewable sources to meet its goals.

The Clean Air Task Force, a Boston-based energy policy think tank, found that reaching the 80 percent mark for renewables in California would mean massive amounts of surplus generation during the summer months, requiring 9.6 million megawatt-hours of energy storage. Achieving 100 percent would require 36.3 million.

The state currently has 150,000 megawatt-hours of energy storage in total. (That’s mainly pumped hydroelectric storage, with a small share of batteries.)

Building the level of renewable generation and storage necessary to reach the state’s goals would drive up costs exponentially, from $49 per megawatt-hour of generation at 50 percent to $1,612 at 100 percent.

And that’s assuming lithium-ion batteries will cost roughly a third what they do now.

Similarly, a 2018 study in Energy & Environmental Science found that meeting 80 percent of US electricity demand with wind and solar would require either a nationwide high-speed transmission system, which can balance renewable generation over hundreds of miles, or 12 hours of electricity storage for the whole system (see “Relying on renewables alone significantly inflates the cost of overhauling energy”).

At current prices, a battery storage system of that size would cost more than $2.5 trillion.

Posted in Uncategorized | Comments Off on Green Energy

Tax Breaks for Oil

There is a lot of smoke being generated these days about the supposedly unfair “tax breaks” for the oil industry. A lot of this discussion is a textbook example of “spin”. And a lot of it depends for its effect on the presumed ignorance of its audience regarding the oil and gas business.

It is worth looking at the facts. Here is a summary from Associated Press, as published in the Thursday, May 12, 2011 Seattle Times:

The tax breaks at a glance

A look at the main tax breaks and how they benefit the oil-and-gas industry:

The biggest is called the domestic manufacturing deduction, a 2004 tax change meant to encourage companies to manufacture in the United States. Companies of almost any type are allowed to deduct from taxable income up to 9 percent of profits from domestic manufacturing. Oil-and-gas companies were classified as manufacturers, but their deduction was capped at 6 percent. This provision is expected to save the oil-and-gas industry $18.2 billion over 10 years.

Another subsidy, established in 1913 to encourage domestic drilling, allows oil companies to deduct more quickly all of the so-called intangible costs of preparing a site for drilling. To accountants, intangible costs are for things that have no salvage value when the well runs dry, i.e. clearing land and pouring concrete. A business ordinarily would deduct these costs over the life of the drilling site. Instead, small, independent drillers can deduct all these expenses in the first year; major, so-called integrated companies such as Exxon Mobil can deduct 70 percent in the first year. The break is worth $12.5 billion over 10 years.

A 1926 rule that establishes how oil companies can depreciate the value of their wells allows drillers to deduct 15 percent of the well’s revenue from taxable income. The cost of an oil or gas well would be depreciated over the well’s life under a more traditional depreciation scheme. The tax break was created in part to simplify accounting, so companies wouldn’t have to guess how long an oil or gas field would produce. It can be a boon: Total deductions over the life of the well sometimes can be bigger than what the company spent. This provision was eliminated for major oil companies in 1975, but it continues for independent producers. The break is worth $11 billion over 10 years

This is one of the clearest statements I have read regarding these tax rules.

First, note that the domestic manufacturing deduction, the biggest deduction of all, is not specific to the oil and gas business; in fact, the benefit to the oil business is capped at a lower rate than that for other manufacturers!

How can that be called an unfair break, unless it is actually unfair to the oil business? To call this deduction a break for the oil business is spin of the purest sort, the kind of thing which should be held up as a bad example in high school debating class.

Another key point is generally ignored in the public debate over tax breaks for the oil industry.

In both the cases of depletion and expensing of intangible drilling costs, the tax  incentives are provided for independent (i.e. not integrated) oil producers. For the major oil companies such as ExxonMobil, these incentives are not available or are capped. This point is rarely mentioned, since most consumer anger is directed at the majors. Wherever you see the phrase “integrated oil and gas producers”, read “major oil companies”.

Therefore, eliminating these “tax breaks” would hurt smaller, independent domestic producers, who produce about 1 million barrels a day, but have almost no impact on the other 19 million or so barrels of domestic US consumption.

Lastly, and most important, these tax deductions were not cooked up out of stone soup; they represent standard accounting practices as applied to mineral production.


Now, before going any farther, it is worth making a point which is easily missed in the glib discussion of how many billion dollars these “breaks” are worth, and in most discussion of the oil & gas business.

The oil business is highly uncertain.

When you drill a well, you just don’t know beforehand if it is going to produce or not. Of course, there is geological data leading you to be optimistic, or you wouldn’t be drilling at all, but the reality is that up to 90% of new wells are dry. In my own company’s experience over the last decade, about half of the wells in which we have invested have come up dry, and that is in spite of a lot of factors pushing the success rate up: for example, the large number of reentries, where the odds are as good as they get. (In a reentry, you already know going in what the original driller found; there have been a lot of potential reentries in recent years, because the barrel price was so low in the 1990s that many low-producing wells were not economically viable and had to be abandoned).

Another thing you don’t know is whether the market price will be adequate to allow you to profit. Sure, these are good times now. But in the 1990s, when the barrel price was around $10, it still cost domestic producers $30-$40 to produce that barrel. There is a reason why an entire generation left the oil business.

So a lot of the criticism of oil business “tax breaks” ignores the elephant in the room – all those failed drilling attempts and all those wells which produced but were not economic at low barrel prices. It is a classic example of the “fan-in” fallacy, better known as “20/20 hindsight”. The oil business survivors have done very well indeed, but a balanced discussion must also recall those who lost everything when the market was down and/or their geological data proved incorrect.

Intangible Drilling Costs

Expensing of intangible drilling cost (IDC) is derived from the generally-accepted accounting principle that mandates an immediate write-down of costs of a failed enterprise. In the case of a dry hole, to demand anything other than immediate expensing of all unrecoverable costs (IDC) would fly in the face of such an accounting principle. That’s why IDC is often called “dry hole cost”.

I don’t know exactly how the Associated Press calculated its figures for the worth of each kind of deduction. I assume that the reporter obtained Treasury data regarding the total national amount for each type of deduction. If the data simply totalled all IDC deductions, without regard to whether the well in question produced or not, then the actual revenue which could be recovered by repeal of the IDC deduction  would be a small fraction of the amount claimed.

And even successful producing wells can and often do go dry unexpectedly. This is especially true of small, marginal reservoirs. Once a well went dry, all its costs would have to be expensed.

So, yes, it would be technically possible to demand that IDC be written down over time, as opposed to expensed immediately; large, integrated producers are required to do so. However, the number of exceptions would be large and the complexity of the accounting would be daunting.

Making the accounting even more complicated is the possibility of secondary and tertiary recovery. These are technologies, such as water and CO2 flooding, and hydraulic fracturing (“fracking”), which allow additional production from a well which would otherwise have run dry.

Percentage Depletion

Let’s look at percentage depletion. When any company, oil or otherwise, pays for an asset with a useful life extending over a number of years, standard accounting practice is to write down a fraction of the cost of that asset each year. This is termed depreciation. Depletion is akin to depreciation, but applied to natural resources (the term of art is “wasting assets”).

Integrated producers (the ExxonMobils of the world) are required to use cost depletion, writing down a fraction of the original acquisition, exploration, and production cost every year, until the full original cost is written down. Independent producers are allowed to deduct 15% of revenue for production up to 1,000 barrels a day; this allowance continues indefinitely.

If such a well is operating at breakeven, it will recover its costs in approximately 7 years. Therefore, it is possible, if prices are high and a well produces for a longer time, for the producer to receive more in deductions than paid out in original costs. Sounds like a great deal, doesn’t it? Well, there are few problems.

Even if a well produces, you really don’t know how long it will produce. You also don’t know when you will need to employ secondary and tertiary recovery techniques to extend the productive life of the well. 7 years is actually a pretty good run for a small well.

And, needless to say, you don’t know what will happen to oil prices in that time.

Again, I do not know the calculation technique used in the AP report. However, it is clear that the value of the percentage depletion allowance is highly dependent on the current market price per barrel of oil and on the average lifetime of small wells. Furthermore, general accounting principles would mandate some form of cost recovery in any case. Therefore, the estimate for the amount of tax revenue which could be recovered by elimination of percentage depletion must be highly speculative.

If you mandate cost depletion for all wells, then drillers of small wells, which are more likely to go dry quickly, face a difficult business decision if well production falls before the original cost has been fully amortized. If the original costs were significant, there might be a perverse incentive to plug and abandon (“P & A”) wells which could otherwise continue to produce under secondary recovery.

There is no question that percentage depletion is a great incentive to produce marginal wells in a boom time, when the barrel  price is high. In some such cases, the value of the tax deduction may be greater than the original capital cost. However, the producer is still taxed each year based on 85% of revenue, and in a down year for barrel prices, or with a well which goes dry in less than 7 years, the  cost recovery may be less than the full original cost. It’s a risky business.


I hope that I have shown that the apparent “tax breaks” for the oil industry are neither as pervasive nor as arbitrary as critics have claimed. They are not as beneficial to the major oil companies as they are to small independent producers, and their replacement by different accounting methods would unquestionably increase the complexity of tax preparation and auditing, and reduce incentives for the large fraction of domestic production which comes from independent oil companies, while providing an uncertain increase in tax revenues.

Appendix: CBO Report

The following quote is from the Congressional Budget Office (CBO) 1986 Report on Reducing the Deficit (Spending and Revenue Options). Italics below are mine.

Percentage depletion allows firms to deduct a certain percentage of the gross income from a property as depletion, regardless of the firm’s actual capitalized costs. For example, nonintegrated oil and gas companies are allowed to deduct 15 percent of their gross revenue from their first 1,000 barrels per day of oil and gas production each year, regardless of their capitalized costs. (Integrated oil and gas producers are required to use cost depletion for recovering capitalized costs.)

Mine development costs and oil and gas drilling costs are also immediately deductible, except in the case of integrated producers. Under the Deficit Reduction Act of 1984, the Congress limited expensing of producing wells for integrated oil and gas producers to 80 percent of intangible drilling costs, with the remaining 20 percent deducted over a 36- month period.

The current tax treatment of mineral properties has been criticized because many of the preproduction expenses of mineral properties can be deducted faster than the value of the assets they “produce” declines. For example, drilling expenditures by oil companies produce assets (that is, producing wells) that gradually decline in value as oil reserves are depleted. The tax code, however, allows firms to deduct most of these costs in the year incurred. Moreover, percentage depletion often allows firms deductions in excess of their original investment. In some cases, percentage depletion (in present-value terms) is even more generous than immediate expensing of all depletable costs.

The result of these provisions is that mineral producers face effective tax rates that are lower than statutory tax rates and, for many producers, lower than effective tax rates on other industries. This tax advantage could be mostly eliminated by replacing the current set of provisions for mineral capital costs with a new system of cost recovery that required all expenditures on mineral rights, exploration, development, and drilling to be capitalized. Under this proposal, all producers would be allowed the option of recovering these costs through the current provisions for cost depletion or amortizing them over 10 years (using the 250 percent declining balance method, switching to straight-line depreciation after six years). Expenditures on dry holes, unproductive mines, or worthless mineral rights would, however, still be expensed.

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U.S. Suit Sees Manipulation of Oil Trades in 2008

Another discouraging bit of political football around energy in the NY Times, May 24, 2011. Every time the price of oil goes up, some people seem to reflexively think it must be a conspiracy by evil speculators. Funny, this group doesn’t seem to have an explanation for why the price sometimes goes down, nor any apparent curiosity about what happens to “speculators” who are long in oil when that happens.

On Tuesday, federal commodities regulators filed a civil lawsuit against two obscure traders in Australia and California and three American and international firms. The suit says that in early 2008 they tried to hoard nearly two-thirds of the available supply of a crucial American market for crude oil, then abruptly dumped it and improperly pocketed $50 million.

So the accused “tried to hoard nearly two-thirds of the available supply of a crucial American market for crude oil”, then “improperly pocketed $50 million”. Pretty alarming, isn’t it?

Here are some basic facts:

  • The average daily trade volume in the American market is 20 million barrels, give or take.
  • The US Strategic Petroleum Supply, the largest storage capacity in the world, can hold about 700 million barrels, or only about 30 days’ volume on the US market.
  • The average daily dollar volume on the American market, at $100/bbl, is $2 billion; the world volume, about $8 billion.

Does it seem plausible that any individuals could privately hoard “two-thirds” of the US supply? Or, if they could somehow do so, only make $50 million on the deal? Or, even if they could somehow make that “improper” profit, that it could have any measurable effect on the market price? I think the regulators’ argument depends for its plausibility on the supposed reader’s lack of basic numerical skills.

Well, let’s give the regulators the benefit of doubt, and read further.

In the case filed Tuesday, the defendants — James T. Dyer of Australia, Nicholas J. Wildgoose of Rancho Santa Fe, Calif., and three related companies, Parnon Energy of California, Arcadia Petroleum of Britain and Arcadia Energy, a Swiss company — have told regulators they deny they manipulated the market.

Aha! Now I get it. It’s a Wildgoose chase. Am I reading The Onion, not the New York Times?

In a matter of a few weeks in January 2008, the defendants built up large positions in the oil futures market on exchanges in New York and London, according to the suit, filed in the Federal Court in the Southern District of New York.

Now, a futures position could be either long or short – the article doesn’t say. My guess is, they were going short on the futures, as a hedge against their current purchases. Thus the future positions were actually a bet that the market price would fall. This is a fairly standard investment approach.

At the same time, they bought millions of barrels of physical crude oil at Cushing, Okla., one of the main delivery sites for West Texas Intermediate, the benchmark for American oil, the suit says. They bought the oil even though they had no commercial need for it, giving the market the impression of a shortage, the complaint says.

Here we get to the meat of it. The usual attack on “speculators” centers on this very point: they have “no commercial need”. And “the market” got a (presumably false) “impression of a shortage”. Surely, the reasoning goes, this can’t be good.

However, that oil did not sit around indefinitely. It was most assuredly sold (within weeks or days) to people who did have a “commercial need”, and were glad to have it, and it was sold at the spot price prevailing on the day of sale. If that price turned out to be higher than the price at which the so-called speculators bought it, then they would make a profit; if not, they wouldn’t.

Now, what about that impression of a shortage?

At one point they had such a dominant position that they owned about 4.6 million barrels of crude oil, estimating that this represented two-thirds of the seven million barrels of excess oil then available at Cushing, according to lawsuits.

So now we have gone from “nearly two-thirds of the available supply” to “two-thirds of the seven million barrels of excess oil”. Hmmm…

The capacity of the tank farm at Cushing is 46.3 million barrels. So the defendants owned about 10% of that, which just doesn’t seem too alarming. I am not at all sure what the article means by “excess oil” – does that refer to oil which is in storage but not immediately spoken for, or perhaps to unused storage capacity available at the beginning of the supposed escapade? It sounds a lot like “excess profit”, something which exists very much in the eye of the beholder.

The traders repeated the buying and selling in March 2008, and were preparing to do it again in April but stopped when investigators contacted them for information, the suit says.

Between January and April, average gas prices rose roughly to $3.50 a gallon, from $3. It was not until later in 2008, after the defendants had ceased their reported actions, that oil prices soared higher — reaching $145 that July. By the
end of the year, prices had fallen back to around $44. The Texas oil is now around $100.

After reading this, I downloaded the average monthly price history for the year in question (easily available from

Cushing, OK WTI Spot Price FOB (Dollars per Barrel)














2008 92.97 95.39 105.45 112.58 125.40 133.88 133.37 116.67 104.11 76.61 57.31 41.12

Note that, from January to March, the period during which Mr Wildgoose and friends were supposedly goosing the market for improper gains, the price did indeed rise from just under $93/bbl to just over $105, about a $12 increase. However, after they stopped, in the ensuing two months the price rose to over $125, a $20 increase! And it jumped another $8 the next month! Wouldn’t such data lead a reasonable person to doubt the speculation theory?

Over this 90-day period from January through March, about 1.8 billion barrels traded on the US oil market, for a dollar volume of about $180 billion.

According to the government, the Wildgoose cohort bought and held 4.6 million barrels. Neglecting storage costs (which must surely have been sizable), that is an investment of about $460 million. On this, they made $50 million, a little over 10% of their investment. That is hardly an outrageous profit – the average profit for all US manufacturers in 2010 (not a particularly great year, if you don’t recall) was 8.5%. So Wildgoose went to a lot of trouble, and ran the risk of attracting unfavorable government attention, in order to make quite a mediocre profit.

Relative to the total market volume over the period in question, the Wildgoose cohort owned at the most a quarter of a percent of the oil traded, and their profit was less than one thirtieth of the dollar volume. The reported profit of $50 million is only about 2.5% of the daily US dollar volume, and a little over half a percent of the world oil trade daily dollar volume.

To summarize, the government theory is that Wildgoose and friends drove the price up by buying, and were then able to profit by selling. However, as I have shown, the amount of oil they purchased was miniscule by comparison with any measure of sales volume or storage capacity. Furthermore, the oil price went up more after they stopped than it had while they were active.

The most humorous thing of all is this: looking at the price history over the full course of 2008, if the government hadn’t intervened, and Wildgoose and friends had kept playing the oil market until later in the year, they most likely would have taken big losses, much larger than the relatively small profit they actually cleared.

So the truth is that the government, by stopping them, locked in their profits! Who should be investigated now?


Posted in Speculation | Comments Off on U.S. Suit Sees Manipulation of Oil Trades in 2008

Big Whine from Big Oil

The discussion of the so-called oil tax breaks is too often just an exercise in spin. Here is an example quoted in an article in the NY Times May 15, 2011:

“Or take prices at the pump. In a memorandum to Senate Democratic leaders on Wednesday, the nonpartisan Congressional Research Service said that eliminating the tax benefits would have virtually no effect on the price of gasoline. The impact on industry profits — the Big Five earned a robust $35 billion in the first quarter of this year alone — would be trivial.”

My thoughts:

  1. So exactly why are these tax breaks being blamed for the high price of gasoline?
  2. The profits of the Big Five oil companies should not be confused with those of smaller domestic independent producers, who would be seriously harmed by the elimination of these tax provisions.
  3. The current profits accruing to the oil industry should not be confused with average long-term profits, which are in the middle of the pack for US business. The oil business is exceptionally cyclical, a basic fact which seems to be completely ignored in this discussion. When prices are high, the business does well. When prices are low, as for instance from 1980-2002, the business struggles, but nobody seems to pay any attention.

“The report also addressed one more industry claim: that ending the tax breaks for the oil companies alone would be discriminatory. Most of the breaks — deductions for well depletion, intangible drilling costs and the like — are unique to the industry.”

These two tax provisions are two out of four under discussion; by my math, that is half, not “most”. And these two provisions are not unique to the oil industry. First, they are shared with all mineral producers. Second, they are based on accounting principles which are shared with all industrial businesses:

  1. Depletion is analogous for the mining industry to depreciation of a capital asset. Percentage depletion exists because straight-line depreciation is an accounting nightmare for an asset which might be renewed (by secondary recovery or drilling).
  2. Expensing of intangible drilling costs is not unique either. Any business is allowed to expense the costs of a failed project – one which does not produce revenue. The oil business is allowed to expense intangible drilling costs because 1) most wells are dry (average: about 90%), and 2) even wells which do produce can run dry unexpectedly, so trying to track which intangibles could be expensed would result in another accounting nightmare.

“The exception is a deduction for domestic production, designed to encourage all manufacturing companies to invest in this country. But as the research service pointed out, industry is not going to stop drilling on American territory as long as the oil is there and yielding big dollars.”

This rather blithe statement shows a basic misunderstanding of domestic production. Smaller independent producers account for about 1m bbl/day of total domestic production of 7m bbl/day. However, 1) the production cost of domestic onshore oil is far higher than that of Middle Eastern and offshore production; an estimate (based on personal experience with deal flow) would be in the range of $35/bbl versus $10/bbl. Therefore 2) the major oil companies have largely abandoned domestic exploration; most new domestic oil is found and produced by small independent companies, who would be seriously affected by the loss of these tax provisions.

Seattle Times, May 12, 2011

“Given profits of $35 billion in just the first quarter alone, it’s hard to find evidence that repealing these subsidies would cut domestic production or cause layoffs,” Senate Finance Committee Chairman Max Baucus, D-Mont., told the oilmen.

This remark shows the same ignorance as the previously-cited one. Big Oil, whose profits are cited, has already stopped drilling on American territory, at least the onshore part of it. The tax breaks being argued over have little impact on Big Oil, but do have a disproportionate impact on smaller, independent domestic producers, who are the ones actually drilling on US soil.

Consider by comparison that Microsoft made $5b on 1st-quarter revenue of $16b. That is about 31%, a far higher profit percentage than the 9% received by Big Oil, and Microsoft is not particularly even a darling of tech investors anymore!

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Obama’s Oil Speech

Unfortunately, President Obama’s “Oil Speech” of April 22, 2011 was a rehash of the usual tired stuff:

  1. Every time, going back decades, that the gas price has risen to a relatively high level, a government task force has been appointed to investigate speculative fraud. There have been some dozen such investigations. They have never discovered anything actionable outside of a few mom and pop service-station operations. Nothing that would have any real effect on prices. The answer is simple: speculators can’t speculate on thin air. Without supply shortages, demand increases, or fears of such, prices just don’t increase. If speculation were risk-free, everyone would do it.
    (Since there is no way for an individual investor to store large enough amounts of oil to seriously affect world supply, I would like to hear some plausible scenario for how the speculators are actually making money!)
  2. When you think about it, and when all the rhetoric is stripped away, the only way alternative energy will ever be viable is if the price of oil stays high. Otherwise, people will continue to consume cheap fossil fuel energy. So lowering the oil price will have the effect of wiping out all those alternatives that Obama is supposedly trying to support. If you look at the history of alternative energy in the US since the 1970s, this is exactly what has happened. Obama is talking out of both sides of his mouth.
  3. The net profitability of the oil business in the US is 5.7% (2010), about average compared to all US business. It is way lower than pharmaceuticals, for instance, which earned 19.4%. When the oil business is losing money (such as 1980-2000), no one pays attention or cares. When prices rise, and the oil business is recouping some profit, everyone screams bloody murder.
  4. While the oil business does receive some tax breaks which could be questioned, it nevertheless pays tax at a rate higher than average for all US business – according to the Tax Foundation, “the average effective tax rate on the major integrated oil and gas industry is estimated to equal 38.3 percent. This exceeds the estimated average effective tax rate of 32.3 percent for the market as a whole”.
  5. The tax break which is usually cited is the percentage depletion allowance. However, while the use of a percentage calculation can be questioned, the accounting rationale for this is the same as that for any depreciation or amortization, and it’s hard to question that. Also, percentage depletion only applies to wells producing less that 1,000 bbl/day, so the major oil companies benefit relatively little from it.
  6. The other tax break usually cited is the writeoff of intangible drilling costs (“dry hole” costs). However, this represents cash spent, with quite possibly no return. Any business is allowed to write off a failed project. The only difference here is that the oil buiness gets the writeoff even for the 10% of wells which actually produce. So what’s the big deal?
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That ‘70s Energy Crisis

So you think you understand why the energy crisis of the 1970s occurred? That it was all due to the Iranian overthrow of the Shah?

Few people, even today, seem to understand some basic facts:

  • US domestic oil production peaked in 1971
  • US gasoline deliveries were subject to allocation controls which dated back to WW2. These controls favored farmers and rural areas over urban drivers, resulting in a situation where local shortages were likely to occur.
  • When drivers panicked and starting keeping their tanks topped off, the total amount of gasoline kept in those tanks increased dramatically, since in normal times people only keep their tanks about half full. This in itself exacerbated the situation – in other words, individual reactions to a feared shortage actually helped create the shortage.
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Cap and Dividend

Everyone who looks seriously at the energy issue recognizes that oil consumption will not decrease unless the price of oil is high enough that alternative energy sources are competitive. Whether you are worried about climate change or about America’s dependence on foreign oil, this question of price is inescapable. You can’t legislate economics away.

But allowing the oil price to float higher has serious consequences for businesses and individuals. The US economic infrastructure is very adapted to cheap oil, in the sprawl of our cities and the “just in time” scheduling of our businesses. Particularly hard-hit by price increases are the poor.

Several proposals have been made to introduce market incentives to reduce carbon pollution. “Cap and trade” is an approach to pollution control pioneered by Ronald Reagan and then George HW Bush, who directed its application to reduce the use of leaded gasoline and fluorocarbon refrigerants.

Under cap and trade, carbon permits are given out to historical polluters, who then can buy and sell them. Thus there is a strong incentive to reduce one’s own pollution since one can then sell permits at a profit (as well as an incentive to overstate one’s historical level of pollution!).

Cap and trade is attacked on these grounds: 1) it generates profits for polluters, and 2) it increases consumer prices, which is generally regressive. The first point is exactly correct – that’s the incentive without which the polluter would presumably not spend money to reduce pollution. The second point is also true, but it needs to be weighed that any pollution control action will have economic costs.

“Cap and dividend” is a relatively new and untested proposal, supported by several Democratic Senators, including Maria Cantwell of Washington state, whereby anyone who introduces carbon into the economy has to buy the right to do so, which means it is a levy on upstream producers and importers. There doesn’t appear to be any trading component, just an auction of the rights to produce. So it doesn’t really bear any resemblance to cap and trade.

Cap and dividend addresses the second objection to cap and trade by redistributing revenue from a permit auction to consumers, in the form of a dividend per person or household, thus offsetting the impact of higher prices. It addresses the first objection to cap and trade by not generating profits for polluters in the first place: they will have to spend to purchase permits, thus increasing their production costs.

Let’s do some numbers:

  • Carbon content of oil = 19.9 metric tons / TJ (terajoule)
  • Oil has 6.1 GJ / bbl, so about .12 mt / bbl = .13 short tons / bbl
  • Proposed C&D bid estimated at $200 / ton, so this would = $26 / bbl
  • Carbon content of NG = 14.4 mt / TJ
  • 1 cf of NG produces about 1,000 BTU, so
  • 1 mcf = 10e6 BTU, with 1,055 joules / BTU, so 1 mcf = 1.06 GJ
  • Carbon content of NG therefore = 0.017 tons / mcf or $3.34 / mcf at $200.

These figures would be very difficult for the domestic independent oil & gas industry to handle. The NG levy is almost equal to the current price. An additional $26 cost per bbl of oil would probably put the domestic oil breakeven above $60 per bbl.

It is then possible that the Saudis or other foreign producers could use cap & dividend to harm US independent oil production, since they could bid up the auction rights to a level that would eliminate any domestic industry profits yet still be profitable for them. The domestic independents break even at around $35-40 per bbl. Assume a barrel price of $80; then a C&D auction bid of $45 per bbl would suffice to drive domestic producers into the red. This corresponds to a carbon levy of $346 per short ton. The Saudis’ lifting cost is around $10 / bbl (transport costs are relatively insignificant) so they would still be making a $25 / bbl profit or about 60% gross margin.

The Saudis drove the Soviets to their knees in the 1980s by flooding the market with cheap oil. They no longer have the production headroom to do that again, but C&D would give them a different weapon.

Of course, much of this assumes that the cost is mostly borne by the producers. To the extent that producers push the cost downstream, it will reduce demand and increase the incentives for efficient use of derived products. This is all good from a carbon reduction perspective; in other words, you want the producers to push the cost increase downstream as much as possible, so that the entire supply chain has an incentive to reduce carbon use. The dividend reduces the price signal to end users; however, there is still an incentive for individuals to conserve, since the dividend is not usage-based.

The real devil is in the details. How would a cap and dividend system actually work in the energy business? A lot of oil exploration is highly speculative: even with modern analytic tools such as 3-D seismic, wildcat success rates are none too high (10% or so). A producer would have to project not only the future price of oil or gas, but the future auction price of permits. Of course, producers already need to get permits to drill, as well as filing with state oil and gas boards to assure all mineral rights are respected.

When a well is producing, the extra cost associated with C&D can, depending on demand, be pushed downstream. However, a wildcatter would need some kind of insurance that a permit would be available at a reasonable price should the well come in. Thus there would necessarily be a market in derivatives against the permit auction price. Otherwise the volatility of the oil market would only increase dramatically. That would not be a good outcome for anyone.

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