Research Triangle Energy Consortium

The future of oil has been debated for ever since I can remember.  When I was an undergraduate in engineering in the early sixties, we were taught that the world would run out of oil in 30 years.  Such predictions continued with the concept of Peak Oil oft discussed.  But, with the recognition of immense heavy oil reserves, and more recently with the emergence of shale oil, the discussion has shifted to the demand side. 

For nearly a century all crystal ball gazing centered on sufficiency of a strategic commodity.  Over the last decade or so, oil is well on its way to turning into salt*.  Lest you conjure alchemical imagery, I hasten to explain that oil is merely going the way of salt. Salt used to be a strategic commodity. Canning, and later refrigeration turned it into a useful commodity, no longer strategic.  This was about the time that the era of oil began, with the discovery of Spindletop and the resultant decimation of the price of oil. The era was abetted by the demand created by mass production of economical cars by Ford, which incidentally killed the auto industry of the time: electric cars.  More on the revenge later.

But the demise of oil will be preceded by a protracted hospice stay.  Folks will predict X% electric cars by year Y.  But that will be for new vehicles.  Legacy vehicles will go a long time, especially in countries like India, a major developing market for automobiles.  The electric starter was first installed in a Cadillac in 1911.  I was still hand cranking our venerable Morris 8 sedan in India (with difficulty; I was 6) in 1950.  On the other side of the coin, India is more amenable to conversions to electric drive, in part due to low labor cost and in part due to a way of life that wrings out every drop of value in a capital asset.

The future of oil is now being discussed relative to demand, not so much supply.  Peak oil discussions are replaced by peak consumption ones. Shale oil put paid to the supply issue. Even before Covid-19 destroyed demand, a groundswell of movement was present towards oil alternatives for transportation fuel.  This was driven by climate change concerns, but also to a degree by emissions such as NOx and particulate matter.  But the projections on future demand depend on the tint of the glasses worn.  The Organization of Petroleum Exporting Countries (OPEC) is predicting return to pre-Covid levels of consumption by late next year.  Somewhat surprisingly, the US Energy Information Administration is also singing that tune as are some oil majors such as ExxonMobil. 

Most surprisingly, however, British Petroleum (BP) is very bearish.  Their projections, while being scenario based, are causing them to plan a 40% reduction in their oil output by 2030.  This is to be combined with a big uptick in renewable electricity production.  Shares rose on the announcement.  But BP has been contrarian before, along the same lines.  Over a dozen years ago they announced a pronounced shift away from oil, renaming BP to stand for Beyond Petroleum.  That did not go well.  Particularly unhelpful to their reputation for operating in difficult environments was the oil spill associated with the massive Macondo blow out.

The future of oil is not the future of natural gas.  Together they share the term petroleum, although it is imprecisely used in the parlance to stand simply for oil.  They were both formed in the same way, with natural gas being the most thermally mature state of the original organisms.  But in usage they are different.  Oil is mostly about transport fuel and natural gas is mostly about fuel for electricity generation and the manufacture of petrochemicals, especially plastics. 

The pandemic decimated transportation fuel but had much smaller effects on electricity and less again on plastics.  In the post pandemic world, natural gas will endure for long, while oil will be displaced steadily by liquids from natural gas and biogas, and ultimately by electricity.  This, of course, excludes aircraft, which will need jet fuel for the foreseeable future.  Biomass derived jet fuel will be a consideration, but not likely a big factor.

Electric vehicle batteries costing USD 100 per kWh will be the tipping point, and we are close.  At that level, the overall electric vehicle with modest range will cost about the same as a conventional one.  The battery and electric motors’ cost will be offset by the removal of the IC engine, gear box, transmission, exhaust systems and the like.  For a compact car, each 100 miles in range will add about USD 2500 to 3000 to the capital cost. Maintenance costs will plummet and the fuel cost per mile will be significantly less than with gasoline or diesel.  To top it off, the linear torque profile typical of electric motors enables high acceleration from a stop.  A progressive shift is inevitable. The revenge of the electric car.

The only debatable issue is the rate of change.  And this is where the opacity appears in the future of oil.  The main sticky bits are perceptions of range required (and the willingness to pay for more) and charging infrastructure.  The latter could be influenced by business model innovation, such as battery swapping rather than owning.  But oil is here to stay for decades.  Therefore, improvement in efficiency, to reduce emissions per mile, are paramount.  The industry appears to understand that.  When the US administration announced a drastic relaxation of mileage standards in 2025, four major companies voluntarily agreed to a standard close to the old one.  I suspect this was in part because they already had worked out the techno-economics to get there, and certainly the consumer would like the better mileage.  Could be also that they had projections of electric vehicle sales that allowed fleet averages to be met.  A compact electric vehicle has a gasoline equivalence mileage of about 120.  Quite an offset with even a modest fleet fraction.

The oil barrel has sprung a leak.  But it is likely a slow one.

Vikram Rao

October 22, 2020

*Turning Oil into Salt, Anne Korin and Gal Luft, 2009, Booksurge Publishing

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.

Vikram Rao

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

There is a lot of teeth gnashing about President Biden ordering a limited drawdown of the Strategic Petroleum Reserve (SPR) earlier this year. A New York Times piece warns that the SPR is at its lowest level in four decades (see chart). How relevant is that statistic?

Let’s go back to how it all began. In 1973 the US was importing 6.2 million barrels per day (MMbpd). Today, it is the largest oil producer and a net exporter by a small margin. But importantly, about half the imports are from Canada, with whom the US has a mutual dependency. Canada has heavy crude the bulk of which is refined in the US, with a resulting export of refined products. Viewed in North American terms, imports from other parts of the world are minor.

Back to 1973. The Arab Oil Embargo to countries such as the US and the UK caused a tripling of the price of oil. To avoid such disruption, the US decided in 1975 to create the SPR. Since then, the crises that drove the decision have not materialized. Drawdowns have been few and light (see chart). In other words, even before shale oil and the resulting North American self-sufficiency, strategic access has not been needed. And yet, pundits, such as those in the NY Times piece, keep maintaining that someday the reserve may be needed*. We discuss that premise here.

The SPR comprises four salt caverns, created by drilling into salt bodies and excavating using circulating water. These are ideal for storage of oil. In fact, salt has been an important impermeable stratum to trap oil in reservoirs. At its peak the reserve had about 719 MM barrels. It was filled over the years and has a low average purchase cost of USD 28 per barrel. While the President’s purpose was to ease the cost of gasoline at the pump for the populace, the sale of SPR oil is coincidentally generating a profit for the government at today’s prices.

Oil is not all the same. One reason the US imports oil from Canada and Mexico, while at the same time exporting domestic production is that US refineries prefer the heavy oil from those countries. They have expensive process equipment to refine such oil, which they get at a large discount because the cost to refine is higher for these crudes. To pay more for light shale oil, while at the same time idling the expensive kit, makes no economic sense. And unlike the European situation with Russian oil and gas, the imports are from friendly neighbors who need the US refineries.

Similarly, the oil in the SPR is not all the same. Over 60% of it is high in sulfur (designated sour) and has significantly lower value than the sweet oil.  The final withdrawals this year are 85% sweet, possibly because that is the mix most suited for purchasers. If, and when, shale oil is injected, it will improve the quality of the balance. But that ought not to be necessary. Here is why shale oil could directly address any shortfalls in supply.

First, there is a significant inventory of DUC wells. DUC stands for drilled and uncompleted and is pronounced duck. I will spare you duck hunting allusions. The hydraulic fracturing portion of the completion is the costly part of the operation. It was suspended for some wells during the low oil prices of a few years ago and the wells were mothballed. Such wells can come on stream in a matter of weeks. Second, even new reservoirs can be accessed and flow oil in a few months. Environmentalists are concerned that new wells will perpetuate fossil fuel production. Ordinarily they would be right for, say, deep water wells. But shale oil wells are burdened with high rates of reservoir depletion. Production from the first couple of years must justify the return on investment. The capital asset does not need years of production to provide the return, as it would for conventional plants such as refineries, or deep water wells, for that matter.

The drawdown executed by the US administration of about 1 MMbpd for 180 days is nearing the end, with 160 MM barrels already released. The reserve is at about 420 MM barrels and will drop to 400 MM barrels by the end of the year. In the unlikely event that the strategic purpose of the SPR is invoked, and it has not since its inception, that amount provides a cushion while additional shale oil is brought on stream.  Over the last few years, the shale oil industry has been more restrained than in the past, seeking better returns. If this were to be a national security issue, short term policy measures could overcome that hurdle.

Shale oil in the ground is our strategic petroleum reserve.

Vikram Rao

October 1, 2022

*’Cause someday never comes, from Someday Never Comes, Creedence Clearwater Revival (1972), written by John Fogerty.

Electricity prices in Europe are going through the proverbial roof, as reported in a NY Times piece. There but for fortune go you and I, is the song line*. Substitute “shale gas” for “fortune” and you have the United States today. Were it not for shale gas, we would be facing a dismal future in electricity pricing and carbon mitigation.

European electricity prices are being driven by high prices for natural gas. A scant two years ago, the price ranged from USD 5 to 8 per MMBTU (which is roughly equivalent to a thousand cubic feet).  At the time US prices would have been between USD 2 and 3. In the last ten months, European prices have fluctuated between USD 25 and 60, with a peak of USD 70 following the Russian invasion of Ukraine. These are unprecedented numbers. At the peak, natural gas was at a calorific equivalent of oil at USD 420 per barrel.

Even discounting the war related peak as unusual, even the pre-war price of USD 25 to 35 was extraordinarily high and appears to have been driven by LNG supply and demand imbalance. Reminding folks, Liquefied Natural Gas (LNG) chills the gas to -161 C, in so doing compresses the gas 600 times, and is the only realistic means for transoceanic transport of natural gas. The overall delivered cost per thousand cubic feet goes up between USD 3 and 4, depending on the distance of the destination.

When the crisis struck, Europe was getting a natural gas mix of domestic, Russian and LNG. LNG became the last cubic foot and therefore the determinant of price. Climate change related droughts in Asia led to shortfalls in hydroelectricity, thus raising LNG demand, which outstripped supply. Diverting supplies from these other destinations to Europe escalated the cost.

In the US, the norm since 2010 has been natural gas at a fraction of the oil price, except when oil took unusual dips, making gas both cleaner and more affordable. The significance of the year 2010 is that shale gas production hit its stride in 2009, causing natural gas prices to remain low, mostly under USD 5. But, prior to that the US was a net importer of gas and much of it was expected to arrive in the form of LNG, with 41 regasification terminals under consideration. In fact, Cheniere Energy’s Sabine Pass plant, with a regassification capacity of 4 billion cubic feet per day (bcfd) was commissioned in 2008 but by 2010 the decision was made to convert it to a liquefaction facility. Expensive facilities such as high draft vessel berthing and gas storage translated to the new mission. This bold move, betting on shale gas potential, gave them a lead and the model has been emulated by others.

With exports averaging 11.2 bcfd this year, the US went from being an important importer of LNG in 2006 to the largest exporter in 2022. It currently supplies nearly half of Europe’s LNG. Ironically, France, which banned hydraulic fracturing, was the largest recipient of shale gas derived LNG from the US in June.

Gas driven decline in coal power Courtesy US Energy Information Administration

Were it not for shale gas, the US certainly would not have been in a position to ameliorate the pain in Europe today. On the contrary, it would have been a major importer of LNG and there is every reason to believe that it would have been facing the same electricity pricing crisis being endured by Europe today. Furthermore, coal-based electricity would have seen a resurgence. Evidence for this is that in 2021, when natural gas prices nearly doubled, coal-based plant capacity factors increased by nearly 25% (see figure). This elasticity means that if the US had seen anything like the 5- and 6-fold natural gas price increases that Europe experienced pre-war, substantial shifts to coal would have been likely, with new capacity additions. This last would be because the shale gas-based decline in coal plants would not have occurred in the first place. Dismal, indeed, from an environmental standpoint.

There but for shale gas . . . .

Vikram Rao

August 29, 2022

*There but for Fortune, Joan Baez (1964), written by Phil Ochs

This is the story of a minority investor attempting to influence the direction of ExxonMobil to be more climate conscious while being even more profitable. Engine No. 1 (evoking childhood images of the Little Engine that Could) pulled off the improbable.  With less than 1% shareholding, they persuaded major players such as BlackRock and the California State Teachers Retirement System (a major pension fund) to go along.  Two of their slate of four nominees have been elected and another is possibly on the brink.  Management resistance had been acute; much money was spent in opposition.  This was seen as a defeat for the Chairman and CEO.

This is New York Times front page news.  ExxonMobil’s deteriorating earnings performance certainly helped the insurrection.  In a fireside chat with my economist son @justinrao, I was asked whether this would work.  Another NY Times piece opined it would not, and that 2 in 12 directors would simply not have the votes to accomplish anything.  This is simplistic thinking.  A board is not the US Senate (remember the days when senators were collegial and actually listened to opposing viewpoints; well, those days are gone).  Each member of any public board has a fiduciary duty to the shareholders.  They are on the same team.  Usually, important direction setting is given to a subcommittee to research and report on the matter.  The report is debated, and a board consensus is achieved.  If the new members command the respect of the others, and they are not too radical in their approach, change is possible.  The new members are “independent directors”.  For those not in the know, independent directors are defined as those not having a material association with the company.  Certainly not officers.  But also, not employees of the investment groups.  There are shades of gray, but independent directors are seen as not influenceable, hence the term.

All change will have to meet the conditions of duality of earnings growth and some other softer objective, in this case carbon mitigation.  These are early days in the battle for climate preservation.  Relatively low hanging fruit ought to be available.  Were I one of those new directors, I would request scenarios to be produced.  Scenarios are not predictions, they are more in the form of what-if exercises, and particularly useful when strategizing in an uncertain environment. These would be guides to at least a provisional strategic direction which yields good returns while meeting climate change objectives.  The latter would be seen as likely societal outcomes directing company behavior, not ideological. 

The future will almost certainly entail reduction in oil usage, with the only debate centering on rate of change.  Certainly, both Shell and BP are betting on that outcome.  While this is a carbon mitigation direction, from a board perspective it is a demand signal needing response.  In this example, the response would be to plan on oil production reduction while investing in electricity, which will be the “fuel” displacing oil.  ExxonMobil has stated that entering the renewables arenas is contraindicated because they have no edge in that space.  I agree with this view when it comes to production of solar energy.  Not so much on wind, where they could have an edge in the emerging application of deeper water production, for which floating platforms will be needed.  This last is where they have deep expertise.  California has a sea floor that drops off precipitately.  Floating production is very likely.

Rather than participating directly in the production of renewables, they could innovate in the space of filling a critical gap in renewables: the handling of diurnality and peaks and valleys.  Germany derives 40% of its electricity from renewables.  This is an average figure.  On a given day that number could be 15% or 75%.  A recent solar bid accepted in Los Angeles had a direct solar output price of about 2.3 cents per kWh.  But the battery back up added nearly 2 cents to that.  Enabling renewables requires a storage solution.  As evidenced by the LA figure, basic solar is becoming the low-cost standard.  In my view it is headed to commodity status.  The profit will lie in solving storage.  In that area, companies such as ExxonMobil are well stocked in science and engineering talent.  Production of electrolytic hydrogen during periods of excess is one of the candidates.  So, is ammonia. Both are staples of ExxonMobil downstream operations.  They could do this more profitably than most.  

My favorite renewable for oil companies to consider is geothermal energy.  It is fast reaching feasibility at scale.  It is also the only renewable of which I am aware, which is both base load scale and load following.  Load following essentially means tunable to demand.  No storage required.  Most importantly, for oil companies, the core competencies are the same as for oil production.  Furthermore, the personnel laid off due to reduction in oil production could simply be switched to geothermal.

There is profit in renewables, you simply must pick your spots.  The new directors could educate the rest on these points.  As for the CEO, sometimes a win follows a loss.  Sometimes you get thrown into the briar patch*.

Vikram Rao

*How Br’er Rabbit snatched victory from the jaws of defeat, literally the jaws of Br’er Fox. Br’er Rabbit and the Tar Baby, a Georgia folk tale.

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

Several of my readers asked me to comment on Michael Moore’s latest film, Planet of the Humans. One asked specifically for commentary on the contention in the film that progress in the use of renewables causes increased use of fossil fuels. I slogged through the one hour and forty minutes and did not find it said just that but could see how that could be inferred.

The film conducts an equal opportunity trashing of most darlings of clean energy: solar energy, wind energy, biofuels, electric vehicles (hydrogen and battery driven) and biomass energy.  Did note keep count, but the last probably gets burnt the most.  Prominent environmental organizations come in for lashings, either for supporting one or more of those listed above or for taking donations from folks who made money doing something deemed objectionable, such as logging.  The usual whipping boys, oil and gas, and even coal, are mostly spared.  In fact, the omissions are almost as interesting as the inclusions. 

The film title notwithstanding, the content is very US centric.  While externalities are discussed, such as tailings from mined minerals, the biggest atmospheric pollutant killer, particulate matter, does not get even a footnote.  This even though the bulk of this pollution is from biomass combustion.  They trash biomass but miss this connection seemingly because their messaging is on how wrong everybody (especially prominent environmental NGO’s) is on biomass being renewable. Even 100-minute documentaries have time limitations, I get that.  Particularly when essential minutes must be spent on two takes on an allegedly 500-year-old cactus being bulldozed for the Ivanpah solar thermal plant.  We were spared a prairie dog being brutalized.  But important minutes were spent on primates on a leaf denuded tree.

I will first address the issue of increased use of fossil fuels with further penetration of renewables. Solar energy is properly criticized for its diurnality requiring back up generation or storage. Footage is devoted to outdoor events powered by solar having backup generators or power from the grid. Event support people are interviewed in what is cast as an expose, sadly of a well-known issue. But even though fossil fuel is often used to level the load where solar is the main source, any use of solar displaces fossil fuel derived electricity.  I suppose one could argue that this shortcoming of solar will always keep fossil fuel in business.  But that ignores advances in storage which do not, or minimally, require fossil fuel. Also, and here is the US centric part, the over a billion folks without electricity can most advantageously be served by solar (many are in high solar intensity regions) combined with microgrids, potentially eliminating grids and the fossil fuel powered plants connected to them. Backup power can be with biomethane derived from animal waste.  This is by way of example only.  The point is that folks with nothing will settle for something, warts and all, when it comes to affordable energy.

Speaking of biomethane, this film does not parse the biofuels field.  It paints with a broad brush, using ethanol from sugarcane and corn as the whipping boys.  This is too easy.  Many, including I, consider ethanol from food crops to be a bad idea, even if it can be accomplished without accompanying deforestation and open field burning of residue (practices implied as commonplace in the film).  For fuel substitution in gasoline or diesel, methanol from a variety of sources, not the least animal and municipal waste, is far preferable.  This last is not mentioned, and I do not expect it. This film is about problems, and the wrong headed thinking by all but the narrator, not resolutions.

The broad-brush strokes are particularly evident in the very long critique of biomass combustion.  The contention is made that biomass is not a renewable resource. While, once again dealing in absolutes, they still managed to strike a bit of a chord with me.  The fundamental premise of biomass being renewable is that plants consume CO₂ and when they die, the CO₂ released is the same as if it is combusted.  The argument goes that one is better off burning for a use rather than letting it die.  And, if a new plant is grown in concert with the combustion, the biomass burnt is carbon neutral. By contrast, fossil fuel combusted has no offset regeneration.  Accordingly, biomass combustion is a net positive on carbon emissions.

Reality intrudes.  If trees hundreds of years old are used for this purpose, even if replanted, the time scale of regeneration is inadequate.  On the other hand, if fast growing trees are grown and harvested for this purpose and replanted on a planned basis, one is closer to neutrality.  The most benign, and unarguably sustainable source is slash.  This is the residue of tops, branches and leaves left after logging operations.  Add to that the woody waste from sawmills.  Finally, small diameter trees removed to encourage the growth of the more desirable forest species (or for reducing the impact of forest fires), are also a viable source.  We are left to conclude that many factors are involved in determining whether biomass combustion can be considered a net positive for carbon mitigation.  Declaring all woody biomass as renewable, as some jurisdictions have done, together with associated credits, is counterproductive.  It could, and likely does, encourage harvesting of forests without proper management. Policy in this area ought to be more nuanced.

The film is generally long on criticism and short on solutions. Were I a proper reporter, I would watch the film over again to confirm this abiding feeling.  But I simply do not have the stomach for it.

Vikram Rao

May 3, 2020

A recent story notes that natural gas drilling in 2018 has dropped by 87.7 %, from a peak in 2008.  Over the same period, natural gas production has increased by 58%.  Natural gas drilling is down to a whimper, but natural gas production continues to grow, year on year.  Had the gas production been from conventional offshore reservoirs, one could have hypothesized that a few large gas fields dominated production, despite fewer wells being drilled.  But most of the drilling for natural gas in this decadal period has been in shale, which does not produce high volumes, but each well is relatively inexpensive.  Before we launch into the explanation of the seeming anomaly, consider the impact of the result.

Natural gas production, largely from shale, was arguably the single biggest reason for lifting the US out of the last recession.  In the decade prior to the recession, US gas prices had fluctuated wildly from USD 2 per million BTU (MM BTU) to as much as USD 15 per MM BTU.  Nothing dampens the spirit of investors in capital driven industries more than unpredictability in the price of the key raw material.  Consequently, major industries, methanol producers for one, fled to countries with sustained low gas prices, such as Trinidad.  When shale gas went on the market in high volume, prices dropped, and stayed low, in the vicinity of USD 3 per MM BTU.  With predictions of sustained low prices, predictions which have held up now eight years later, industry returned to the US.  Liquified natural gas (LNG) imports were no longer necessary, and shortly thereafter, the US became an exporter of LNG.  For every citizen in the US, a lower fraction (sizable for many) of take-home pay went towards transportation and home heating and cooling.  The savings were spent on goods and services.  The recession was in retreat.

Shale oil picked up and became a major force by about 2013.  In 2015, the high production halved the world oil price and OPEC was marginalized.  The low oil price, together with the low natural gas price, contributed to the economic gains and a record stock market.  But gas prices stayed low despite steep reduction in gas exploitation, because gas supply continued to be high.  Curiously, and seemingly paradoxically, the reason is the steeply increasing oil production over the decade.  Over roughly the same period as the decline in gas drilling, oil production has increased from 5.0 MM bpd in 2008 to 11.6 MM bpd in 2018.  Now for the explanation as to why that caused gas production to rise.

Crude oil comprises of a mixture of molecules, with the bulk of them conforming to the formula C_nH_2n+2, where n is an integer.  Oil molecules break down over time in the host environment of high pressure and temperature.  The most thermally mature state is methane, with n=1.  Ethane, propane and butane, with n=2,3 and 4, respectively are the next more immature.  Shale oil is very light, as defined by API gravity.  Accordingly, the n’s are low numbers relative to heavier oils.  One could reasonably expect shale oil to be associated with some molecules at higher thermal maturities.  This is known as associated gas, and usually comprises methane in the main, together with the somewhat larger molecules with n=2-4 and more. Canadian heavy oil, on the other hand, could be expected to have little or no associated gas.  More shale oil production automatically means more shale gas production.

Recent data from the Permian, the hottest oil play in the US today, indicates that every MM Bpd of oil would have associated with it 2.2 billion cubic feet per day (bcfd) of gas.  If this statistic is taken to apply to all shale oil, as a first approximation, on would expect gas production to be 14.5 bcfd greater in 2018 than in 2008, from this source alone.  That translates into 5.3 tcf per year.  With no let up in shale oil production in sight, natural gas will continue to be produced.  Expect, therefore, for natural gas prices to remain at low to moderate levels, and a boon to the economy.  Shale gas drilling is, metaphorically speaking, dead, or at least a shadow of its formal self.  But natural gas remains the reigning monarch in assuring a healthy economy.

Vikram Rao