Research Triangle Energy Consortium

On Monday this week, traders paid to unload oil purchase contracts known as futures. The price of oil went negative. Story lines had titles about being paid to fill gas. But, sorry, you will not be paid to fill up your gas tank. You already knew that because business does not work that way. What may surprise you is that some gas station owners are commanding better margins right now than before. Some explanation for the conundrum follows*.

The real price of oil, the price folks actually using it are prepared to pay, never went negative.  This was an artifact of commodity trading. Traders buy oil for delivery sometime in the future. They never intend to take delivery. They are speculating on the price rising prior to the delivery date, netting a profit. When they are wrong, they sell the contract to someone at a loss. This one was a doozy of a loss. Because of the precipitate action of many traders on the same day, the price of oil plummeted, going to a negative USD 37 (see graph in the link). They paid someone to take that oil off their hands. To underline the transient aspect of this event (no matter the chicken little headlines), at this writing a scant few days from the plummet, the price is just over USD 17. Not munificent, but not negative.

Futures trading in oil in the US is different from that in Europe. In the US, oil delivery must be taken in Cushing, Oklahoma. Traders caught in the squeeze described above have the option of storing it in Cushing for a while. Not this time. No spare capacity was available. Brent oil futures take delivery at a port in Europe. Brent May futures dropped just 2 dollars. This Cushing pinch point feature, together with other bottlenecks in pipeline transport, are the reasons why West Texas Intermediate (WTI), the US benchmark, always is USD 2-5 below the Brent price. This despite the fact that the oil is sweeter (less sulfur) and lighter. 

The majority of US oil produced today is shale oil.  This is light and sweet and when distilled in a refinery, over 90% comprises useful transportation fuel gasoline, jet fuel and diesel. Only 5% is a residue known as fuel oil, which also can be burnt for heat. The problem today is that gasoline and jet fuel have plummeted in demand, but diesel has kept up reasonably because of farm use and increased truck traffic for deliveries. A refinery today can get crude oil for a very low price. It can sell much of the diesel fraction, but the gasoline fraction (usually more than the diesel fraction) has low demand. Yet, to produce diesel, gasoline is also produced. The result is that the gasoline is sold to the distributor at a very low price. But, according to some reports, some retailers are not passing on all the savings, with the result that their profit margins are higher than they were in normal times. That may be scant comfort with the low volumes. But in recent times, the convenience store associated with the pumps has been the profit maker, not the fuel, and that volume likely has not dropped. You will also notice that the spread between the pump price of gasoline and diesel has increased substantially.

Oil price is likely to remain low until the demand returns in some measure. Demand is estimated to have dropped by 27 million barrels per day (bpd) in April. OPEC + (OPEC plus Russia) agreed to a 9.7 million bpd reduction in output. The Texas Railroad Commission considered forcing a reduction of 1 million bpd and hoped to persuade other US jurisdictions to reduce another 3 million. After a critical meeting this week, two of the three commissioners voted it down. That leaves the supply/demand imbalance too high to put upward pressure on price. President Trump wants to top up the Strategic Petroleum Reserve (SPR) from the current 635 million barrels to 710 million. Congress is still to approve the cost to do that. The average cost of of oil in the SPR is USD 28. A top up at current prices would be a good deal. But the rate of fill cannot exceed 0.5 million bpd. So, it may not make a material difference. What will make a difference is wells being shut in. Companies will go bankrupt and be swallowed up for dimes on the dollar by the big ones, who have the deep pockets to hold on for better pricing.

Negatively priced oil was a mere curiosity. The over USD 50 price drop in a day was driven by trader behavior. That is unlikely to repeat. Many states are relaxing restrictions. Tracking already shows more people on the move. Schools are likely to open in some jurisdictions. Expect oil prices to hover in the low 20’s in the near future. That will not be enough for many producers, who will shut down their wells, which in turn will cause prices to firm. In other words, supply/demand drivers will return, and the aberrant negatively priced oil will be a story for the ages.

Vikram Rao

April 26, 2020

*this piece was driven by a request from three regular readers of this blog.

The combination of Covid 19 driven demand loss and the Russia/Saudi spat sent oil into negative pricing for a day in late April 2020. This was largely an anomaly driven by futures trader missteps. Now, there is the real, although still unlikely, scenario unfolding for negatively priced Liquefied Natural Gas (LNG). Spot pricing in Europe and Asia is at historic lows, approaching USD 2 per MM BTU, and dipping below that on one occasion. At that price it is tantamount to being negative because it is less than the cost to produce and deliver for most.

The cost of landed LNG anywhere may be broken down into two parts: liquefaction and transportation. Post landing, there is a re-gas cost. The first step is the costliest and is broken into capital cost amortization and operating cost. The capital component is the higher of the two. While location specific variants exist, very roughly speaking, liquefaction costs USD 2 – 3, transportation 0.4 – 1.1 (sometimes double that in times of scarcity of vessels) and re-gas O.4. The transportation costs are distance driven. Add to that the cost of the feed gas, which can be lower than the regional price due to long term contracts. Nevertheless, even if a low cost of USD 1.0 is ascribed to it, a useful total figure for the US would be USD 4. This makes the landed cost still higher than the spot pricing in evidence today.

LNG is the methane part of natural gas cooled to -161 ^oC. Most natural gas contains up to 10% larger molecules than methane. These are primarily ethane, propane, and butane. These must be removed prior to liquefaction. In the liquid state methane is 600 times denser than the gas from which it was derived. This property makes it amenable for long distance transport across oceans. But it must be kept at -161 ^oC. The most economical way to accomplish this is to allow some of it to evaporate, which cools the bulk liquid. An everyday example is the cooling action of sweat evaporating from one’s skin in a breeze. The gas is collected and used in the vessel engine or to make steam, which conserves it and prevents a greenhouse gas emission, but still constitutes loss of a saleable good.

As in the case of oil, when the demand is suddenly depressed, LNG gets stored. Limited capacity at the land locations leads to storage in the idled vessels. This week Qatar reportedly has 17 tankers idling off their coast. Each tanker carries up to 3 billion cubic feet of gas. Unlike in the case of oil, this storage has a cost beyond the lease of the vessel: the boil off gas has no use in a stationary vessel. It must be released from the tanks and will likely have to be flared.

Most LNG contracts have pricing pegged to the price of oil. The plummet in the price of oil in the last couple of months took with it the LNG price. In net importing nations, LNG sourced gas is the marginal cubic foot. Domestically sourced gas is used first. In India, for example, in normal times, the controlled price for domestically produced gas was complex, but around USD 4 per MM BTU. The LNG import price was around USD 11. Now things are different. After the Covid 19 depressed demand is met with regional gas, LNG demand is low, thus driving down the spot price. Incidentally, Indian renewable electricity has increased as a percentage of the total during the last few months.

LNG is to Qatar what oil is to Saudi Arabia: the primary source of income for the nation. It does not have the luxury of a cartel to control prices. Qatar, together with Russia and Iran, did attempt to form the Organization of Gas Exporting Countries (OGEC) in 2008. This was about the time that US shale gas was hitting its stride. Within a few years, US shale gas throttled the formation of the cartel because it was producing some of the lowest cost gas natural gas in the world, and lots of it. In very short order, the US went from plans to be a major importer of LNG (and therefore a client for the OGEC aspirants) to an exporter. Cheniere Energy, the US leader in LNG was forced to dump development plans for re-gas plants and to shift gears to become exporters. This reinvention did give them a cost advantage over competitors who joined the trend to take advantage of plentiful low-cost gas: existing facilities. The docking stations for the vessels and the shore storage existed and comprised nearly half of the cost, and half the time to commission, of that in greenfield operations.

Green field LNG liquefaction facilities and associated marine berths and storage cost about USD 4 billion, give or take some depending on details. 40-60% of this is labor, one reason why local governments find such plants attractive. But the high cost means long amortization periods. Add to that the fact that from start to finish they take up to 10 years to build. Uncertainty in pricing, the practice in this industry of long-term contracting notwithstanding, is daunting. That is precisely what Covid 19 has accomplished: created significant uncertainty in demand. Predictably, investors are balking. Worldwide, USD 50 billion worth of plants have been canceled or delayed.

Qatar faces the quandary of not being able to control prices, and yet needing a high market share: exactly what the Saudis faced with oil a couple of months ago and responded by offering discounts to get share increases. If Qatar were to do this, LNG price could briefly dive into negative territory. The US producers are likely to curtail production because it is unprofitable. Russia and Norway already are throttling back on gas sales. Qatar will most likely also drop production, no matter the fiscal pain, and spare us the drama of negative price lightning striking again *.

Vikram Rao

*”Lightning is striking again” in Lightnin’ Strikes, performed by Lou Christy (1966), written by Lou Christie and Twyla Herbert

Oil drilling leases will soon be available in the Arctic, according to a story in the New York Times. The Alaska National Wildlife Refuge (ANWR), a land-based portion of the Arctic, is cited. But the Arctic is cold, both figuratively and literally. When he took office in 2017, President Trump announced a roll back of a “permanent” ban on Arctic drilling that President Obama instituted as he was leaving the White House. I opined then that the roll back would have no net effect because interest from oil companies would be minimal. I also wrote at the time that President Obama’s action was also largely symbolic, and not material.

The principal reason for these conclusions is that the price of oil has been low since 2015, when US shale oil became the determinant of oil price in the world and the ability of the Organization of Petroleum Exporting Countries (OPEC) to prop up prices was deeply undercut. USD 120 per barrel highs became USD 70 highs. The Covid-19 pandemic has decimated shale oil company ranks, but it has also caused demand, and price, to plummet to historic levels. Accordingly, the crystal ball of future oil prices is murky. Murky crystal balls equate to uncertainty, which, added to the environmental risks, further equates to higher discount rates. Making matters worse on the investment side, any Alaska play has a long-term payout. First oil is likely a decade after the lease purchase. This involves forecasting the price of oil into the second half of the century.

All the indications are that oil demand will reduce significantly by 2040, largely through electric vehicle adoption. Certainly, the super-major oil company BP’s beliefs in this regard have translated into plans for a major replacement of oil revenue with revenue from renewable electricity. They recently announced that by 2030, their oil production will be reduced by 40%, concurrent with major investment in renewables, resulting in 50 GW electricity production. That production is up there with good size electric utilities. This decision also comes at a time when the dividend has been halved and properties divested to raise cash. It also is coincident with the divestiture of their pioneering Alaska North Slope holdings to privately held Hilcorp, during which transaction they sweetened the pot with a loan to ensure closure of the deal. This does not sound like a company that will invest in a US Arctic lease. I do not see any oil company headquartered in Europe doing it either.

Hydrogen is an important industrial commodity even not counting the possible use as electric vehicle fuel. US refineries purchase 2 billion cubic feet per day of hydrogen (in addition to using another 0.5 billion cubic feet produced internally). Virtually all of it is produced from natural gas. As we discussed in these pages earlier, hydrogen produced using surplus electricity during low demand periods is one of the most promising solutions for the problem of  intermittency of renewable electricity. Oil companies like BP, doubling down on renewables, are unlikely to miss this point. Also, if conversion to ammonia is more appropriate for storage and transport, who better positioned than an integrated major oil company? In its announcement, BP makes a vague reference to hydrogen. No mention is made of geothermal electricity, but it is highly unlikely they are not watching that space.

Returning to the issue of success of a lease sale in the ANWR, one of the primary challenges is the paucity of high-quality seismic data. These are subsurface images acquired by individual oil companies in proprietary shoots or by seismic operators speculatively shooting to then sell subscriptions to the data in “libraries”. The acquisition and interpretation of the data is the edge employed by oil companies in obtaining the winning bids without overpaying. Less data means more uncertainty. My take on the situation is that there will be fewer bids due to competing capital spend directions, the uncertainty in the price of oil, the environmental risks, and the delays likely due to litigation (case in point the litigation based delays in the Keystone XL oil pipeline construction). But whatever bids that materialize are likely to be low-balled. In that case, the revenue from the sale will be underwhelming. This assumes, of course, that the administration goes ahead with plans to auction the tracts. More than likely this is just another tempest in the Alaskan teapot.

Vikram Rao

August 20, 2020

This discussion is about fixing, as in solving, but it is also, and mostly, about fixing as in rendering immobile. The impact of the greenhouse gas CO₂ can be mitigated either by producing less or by capture and storage. A recent paper in the journal Nature triggered this piece. It discusses the feasibility of fixing CO₂ in the form of a stable carbonate or bicarbonate by reacting atmospheric CO₂ with minerals in the volcanic rock basalt, one of the most ubiquitous rocks on earth. Crushed basalt is to be distributed on farmland. The bicarbonate fraction is water soluble and run offs take it to the ocean, where the alkalinity mitigates ocean acidification. The reaction products are also a desirable soil amendment. This paper is mostly not about the technology. It studies scalability and the associated economics. The authors estimate the process can be accomplished at a cost ranging from USD 80 to 180 per tonne of CO₂. Putting that in perspective, the current US regulation has a 45Q Federal Tax Credit of USD 50 per tonne sequestered in this fashion. This lasts for another 12 years. While no business ought to be built on the promise of subsidies, the length of time allows cost reduction to occur. At USD 80, the lower end of the range noted by the authors, the cost is in an acceptable range.

The use of basalt to fix CO₂ is a part of the genre referred to as mineralization of CO₂. Divalent species, but principally Ca and Mg, are present in rocks. In low pH conditions they react with CO₂ to produce a carbonate (or bicarbonate). Olivine, another common mineral, often found in association with basalt, is a mixture of MgO.SiO₂ and FeO.SiO₂. The reaction product is MgCO₃ and SiO₂. For CO2 sequestration purposes this may be accomplished in situ or ex situ. The term sequestration most properly includes both capture and storage, but is often used just for the second step, and that is how we will use the term here.

A promising approach for in situ storage of CO₂ is injection into oceanic basalt deposits. Basalt is formed when the magma from volcanic eruption cools rapidly. When it cools slowly, it produces species such as granite, with large crystals and high hardness, a rock more suitable for structural applications. Basalt on the other hand is fine grained and weathers easily. This is good for reactivity. In oceanic deposits it is even more so the case when the rapid cooling in water results in “pillows”, which partially disintegrate to be permeable. They are often overlaid with later placements of magma sheets. These impermeable layers act as barriers to injected CO₂ escaping, affording time for mineralization. The mineralization is further accelerated if the injected CO₂ is in the supercritical state (achieved at greater than 31 ^oC and 1070 psi). All fluids in this state have properties of both gas and liquid. Here the supercritical CO₂ permeates the rock as if it were a gas and reacts with the mineral as if it were a liquid.

Ex situ fixing of CO₂ follows the same chemistry as in situ, at least in the aspect that the product is a carbonate. The raw material can be tailored to the need if cost permits. The CO₂ capture cost is the same in either case. However, an ex situ process has many advantages over in situ ones. The process kinetics can be advanced using higher rates of reaction using standard process engineering methods such as fluidized beds. Catalysis could also be employed. The products could also be expected to have value, such as in substitution of concrete ingredients. But, as in the case of fly ash from coal combustion, also a simple additive to concrete, the realization of that value can be elusive. Niche uses can be found, but monetization on the massive scales required to make a dent in climate change will require concerted effort.

The cost of production will still dominate the economics and the largest component of that is the acquisition of CO₂ from the industrial combustion process or air. Air capture is a relatively recent endeavor and targets production cost of USD 100 per tonne CO₂, at which point it becomes extremely interesting. The principal allure of this method is that it can be practiced anywhere. If located near a “sink”, the utilization spot, transport costs and logistics are eliminated. This underlines a key aspect of ex situ sequestration, the availability and cost of CO₂ in the form needed.

The original premise for this discussion, mineralization of CO₂ from the air, skips the CO₂ acquisition constraint. But the focus shifts to the procurement of massive quantities of rock and crushing into small particles. Two pieces of good news. One is that basalt is possibly the most abundant mineral on earth, although a lot of it is at ocean bottoms. The other is that basalt crushes relatively easily, especially if weathered (contrasted to its country cousin granite). But the elephant in that room is that procurement still involves open pit mining, anathema to environmental groups. In recognition of this, the authors of the cited Nature paper encourage a study of availability of tailings from mining operations as basalt substitutes for oxides of divalent ions. They opine there are vast hoards of such tailings from mining operations over the years. They also suggest the use of Ca rich slags from iron making. These are oxides of Ca and Si in the main, with some oxides of Al. Lest this idea be extrapolated to slags from other smelting operations, a caution: the slags from some processes could have heavy metals and other undesirables such as sulfur. On the plus side of that ledger, the processing of certain nickel ores entails a beneficiation step that results in a fine-grained discard rich in Mg silicates, which ought to be very reactive with atmospheric CO₂.

While the use of industrial waste for sequestering CO₂ is technically accurate, acquisition and use of alkaline earth rich oxides will have hurdles of location, ownership, and acceptability to farmers, to name just a few. I am also reminded of the fact that when “waste” products with no or negative value create value for someone else, the price will often be revised, upwards. But the method in the cited paper certainly is a useful addition to the arsenal of measures to mitigate global warming, provided field operations verify the predictions on rates of reaction. This battle will only be won with many different arrows in the quiver.

Vikram Rao

August 9, 2020

London Underground railway platforms have warnings to “mind the gap”. In those cases, the meaning is literal: curvature of the platform often creates a variable gap between the concrete and the first step on the train. In any Presidential election year news and views are sometimes difficult to separate. For this discussion I am ignoring the obvious disinformation promulgated by conspiracy theorists and the like. The gap we are minding is more along the lines of spin.

Spin has always been a permissible technique in society. These are facts presented in a light favorable to a point of view or cause. This year the main issue that will get spun is the economy. Had the pandemic not intruded, the argument would have been the causes of the Dow at 29000. The present administration handed a vibrant economy on a plate by Obama or Trumpian wizardry. Well, Covid-19 took care of that. Now, it will be about how the pandemic was managed to keep deaths to a minimum, while also minimizing damage to the economy caused by the shutdowns. On the one hand you have Australia and New Zealand, who took early decisive actions on distancing and now have remarkably low mortality. On the other end of the spectrum is Sweden, which conducted a massive experiment by relying almost solely on herd immunity. Every state in the Union is relaxing distancing differently. While only time will tell, the spin business is in high gear.

In the reporting of improvement in the economy, mind the gap in how percentages are used. Mind the denominator. Consider a commodity, say oil at USD 100 a barrel. A 50% drop (as happened in late 2015) would take it down to USD 50. Then a 50% gain at that point would take it to USD 75, still USD 25 short of where it started. Each a 50% change, but the denominator intrudes. A recent headline stated that air travel had surged 123% in just the last month. The comparison was with a period that had seen a drop of 96%. The 123% gain brought it up to a figure that was still 91% short. This is not to say that the increase was not welcome and noticeable; it is just that some reporting leaves that detail unsaid.

An interesting variant on dicey comparisons is a story in the NY Times on the price of oil. It reports that price was USD 31.82 on May 18, 2020. Then it goes on to say, “That may seem like a minor miracle given that the price is more than $60 above where it was about a month ago”. While not inaccurate, the fact is that the drop to negative USD 37 a month ago was anomalous and for one single day due to an oddity in trader behavior. The comment was in the context of prices at which oil production could be profitable. However, the producer never saw the negative price, just the traders. The true price at that time was the price a day later, about USD 17. Still a huge jump to USD 31.82, but not USD 60 and not in the miracle range, minor or otherwise.

Currently, possibly the biggest gap is in matters relating to ameliorating or avoiding Covid-19. Investigative papers are placed online before they have been peer reviewed. The intent is to get them out for use by other investigators, but an eager press does not always underline that fact. Vaccines get a spotlight. While understandable, in view of the promise of such things, the “we are nearly there” feeling underlies many of the stories. They even move markets, as did the recent success of Moderna’s vaccine in a very limited trial. Dueling well-intentioned experts add to the gap, the minding of which proves daunting for the general public.

Now, this last is for the many of us who are in baseball withdrawal. In the parlance, throwing a curve is not the same as putting spin. In baseball, a curve may have some spin, but so can a fast ball. And fielders must be ever vigilant in minding the gap. Else, a single could turn into a double or worse. Now I return you to regular programming.

Vikram Rao

May 23, 2020

A recent issue of the Economist has a piece predicting a peak in oil demand.  Until recently all the noise has been around the theory of peak oil production.  Much ink has been put on paper on this topic and it even has variants.  The version that I subscribe to is not peak oil in the sense of declining resources, but rather peak ability to produce.  While this may seem like hair splitting, the difference lies in what is available versus what is economically available.  Necessarily, therefore, these numbers depend heavily on a forecast of price.  The higher this is, the more viable certain resources.

This is why the discussion of that other peak, that of demand, is crucial.  If in fact that turns out to be the case, oil price may well remain at levels that are unprofitable for some resource bases such as the Arctic.  The Economist article even depicts oil as a dinosaur (reproduced above from the article).  Lovely imagery notwithstanding, dinosaurs were wiped out by a cataclysmic event.  Oil will be eroded away steadily and may never ever become extinct.

In our previous discussion on peak oil, we referred to the phenomenon as a plateau not a peak.  The two studies upon which we premised that blog, both came in with their plateaus in the low to mid nineties million barrels oil per day (bpd).  The lower number, that of the French Petroleum Institute, IFP was 92 million bpd.  Notably, and almost certainly coincidentally, the Economist citation of two studies is precisely that number, this time for demand.  The Twin Peaks, as it were, if they were to materialize, would produce immense price stability.  In the absence of a demand plateau we had theorized that a flattening of supply would lead to a continual rise in oil price.  This was a partial basis for our belief that the oil/gas spread would remain large, at least in North America.

Implications of a Demand Peak:  Worldwide about 60% of oil usage is for transportation.  That percentage is much higher in the US.  But the point is that the non-transportation uses are probably the most vulnerable to substitution by natural gas.  The largest two sectors are as a fuel (heating, electricity, other industrial processes) and in chemicals production.  The degree of substitution will be driven by the spread in oil/gas price and the longevity of the same.  Unlike in the past, the newer shale gas sources are abundant and forecasted to have predictably low prices for natural gas for decades.  If this forecast holds it will cement the substitution and thus lower the peak oil demand.

Easy to understand is the conclusion that the coincident peaks will put supply and demand in balance, thus stabilizing the price of oil.  In that case the price of natural gas alone will determine the spread.  Arguably all of the oil to gas substitution will put some upward pressure on natural gas price.  LNG notwithstanding, gas is dominantly a regional, not world, commodity.  The upward pressure will be less in North America, with shale gas resources that will unleash in response to demand.  Eventually other countries will have that capability, notably China and Argentina.  In the meantime higher local prices could slow some of the oil substitution.

Will a peak in demand cause a reduction in the ability of the Saudis to manipulate oil prices?  Probably not; if anything it could increase the urgency to prevent serious dips in price.  The cost of their social programs dictates the need for stable high prices.  But if reduced output is needed to prevent dips, this could have a net negative impact on their economy.  But in an odd twist, the current move to switch from oil to other means for electricity production could come under review.  If surplus oil were available due to export curtailment it could be burnt for power without a deleterious impact on revenues.  In any case, diversification away from oil as the dominant source of income will be a key.

We have in our columns here discussed the displacement of oil based products with natural gas sourced fuels and chemicals.  Certainly the displacement of coal by gas in electricity production has been at a high rate, almost single handedly lowering CO2 emissions to 1994 levels.  But this Economist article is the first I have seen that discusses energy efficiencies combined with substitution of oil to the point that demand plateaus.  Dinosaurs are cool.  But the accurate imagery is that of Luft and Korin, turning oil into salt.

Vikram Rao

A recent article by Bordoff (Columbia University) and Levi (Brookings Institution) makes some interesting observations with regard to a possible shift in the balance of oil power from the Middle East to the Western Hemisphere.  Of particular note is their discussion of the concept of spare capacity.  For a net exporting nation this would be defined as the ability to shut in or produce more at will.  They report that the Saudis have spare capacity of 3.5 million barrels per day (MMbpd) against total exports of 8.7 MMbpd.

This immense spare capacity allows the Saudis to be the moderating influence on oil prices. If prices rise steeply, with the risk of causing demand destruction, the Saudis can open the spigots. They could also respond to pressure from influential importing nations. No small wonder, therefore, that the US continues to have a comfortable relationship with the Kingdom despite major differences of opinion on issues such as women’s rights and the war on terrorism.

For net importing nations the concept of spare capacity scarcely applies. For the US, increased domestic production, which is proceeding in leaps and bounds, merely means decreased reliance on foreign oil. But here is the kicker. Our new found oil is all from tight formations and virtually all of it is sweet, light oil. It commands a higher price than the heavy oil from Canada, Mexico and Venezuela. Many of our refineries have invested heavily in coking equipment to deal with the heavy stuff. Their margins are less for the light crude. So, the displaced crude will be the light oil from Nigeria and some from the Middle East, which is increasingly turning heavier, despite the benchmark name Arabian Light.

All of this complication underlines a truism: oil is not just oil and refineries are very picky about what crude suits them.  The smartest move may be for us to export the light crude at high prices and continue to import the heavy crude at low prices (that differential can be as much as $30 per barrel).  That requires Presidential approval, I do believe.  For reasons best known to someone other than I, refined products can be exported at will but the raw oil or gas export requires approval, except to NAFTA countries.  Permitting oil exports at high prices has no downside to it especially if the resulting import is from friendlies such as Canada.  The question of Canadian oil being dirty can be debated elsewhere.  Suffice to say there are solutions if folks are prepared to be a wee bit innovative.  Unconstrained export of LNG will have a significantly net negative impact on the economy.  When you go to this link, go further to the report linked therein.
The authors of the cited article opine that the Saudis will continue to be the controlling factor on oil prices even if our dependence drops dramatically. This seems right because even if the US drops to zero oil from the Middle East, it will have an interest in keeping oil price moderated. In part this would be to keep our own imported oil price in check, and in part it could be to protect our allies. But this probably means that the dreams of a few of us, of ceasing the policing of the Strait of Hormuz, may well need to be relegated to the wishful thinking pile.

One important point missed by the authors is the potential impact of gas and gas derivatives reducing domestic demand for oil.  They recognize the oil/gas price spread and the arbitrage opportunity it brings in the chemicals industry.  But they don’t sufficiently recognize the significant movement in displacing diesel with compressed natural gas (CNG), liquefied natural gas (LNG), gas derived synthetic diesel and dimethyl ether (DME).  Technology is increasingly enabling this direction and it could have a material impact upon the demand for oil.  When added to the oil derived chemicals, such as nitrogen fertilizer, ethylene and propylene, as already noted by them, significant demand destruction of oil can be anticipated in the US.  This was noted recently be a Saudi prince (pictured above) in a warning to the Saudis to diversify.
One final argument relates to the previous point regarding the role of abundant and cheap natural gas in the US. To the extent that this affects demand destruction of oil, natural gas could be the spare capacity nobody is thinking about. It can be turned on in under a month when needed. Shutting in natural gas is more feasible than shutting in oil. In an odd twist the oil substitute natural gas could be our spare oil capacity.
Vikram Rao