How Relevant is the Strategic Petroleum Reserve today?

October 1, 2022 § Leave a comment

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, over millennia, 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.

The Devil and the Deep Blue Sea

September 4, 2022 § Leave a comment

California’s recent decarbonization legislation includes extending the life of the Diablo Canyon nuclear reactors in the face of environmentalist opposition. Their concern has been for the marine creatures potentially killed during cooling water uptake from the ocean. The dilemma posed in the title, similar to between a rock and a hard place, applies to the Diablo Canyon decision. A recent paper from Stanford and MIT details the issues and lands in the extended life camp with some twists discussed later here.

Back to the dilemma. No form of energy, clean or otherwise, comes without baggage. So, it comes down to compromises. Wind has avian mortality and visual pollution. Solar may carry the least baggage, but recent events pose a unique twist. The price of natural gas going up 5 and 6-fold in Europe due to climate change and Russian aggression shows that reliance on a global supply chain could be fraught. In context, over 60% of solar panel components originate in China. Sabers are rattling in the Taiwan Strait. No telling what happens to solar panel costs if things escalate.

More dilemma: opponents of the decision want to simply build more solar and wind capacity. Even Senator Dianne Feinstein weighed in with the opinion that absent the Diablo decision there would be more natural gas usage. Exactly right, especially if the course of action proposed by opponents, more solar and wind, is followed. This is because solar and wind have low capacity utilization due to diurnal and seasonal gaps in output. At this time these gaps are dominantly filled by natural gas power generation. In other words, more solar and wind means more natural gas burned until carbon-free gap fillers, such as advanced geothermal systems and small modular (nuclear) reactors, hit their stride. And that will take a decade. In the meantime, Diablo Canyon 24/7 output notwithstanding, natural gas will continue to increasingly be used in step with addition of solar and wind capacity. A mitigative measure on the associated CO2 production would be carbon capture and storage attached to the natural gas power plants. The best-in-class technology achieves this for USD 40 per tonne CO2. One of the new California bills encourages this direction. It is opposed on the grounds that it encourages more fossil fuel production. True. But, as noted above, until carbon-free gap fillers are at scale, natural gas is the only practical alternative. Rock and a hard place.

The two plants at Diablo Canyon account for 9% of the electricity and 16% of the carbon-free electricity for the fifth largest economy in the world. Removing it would make already tough zero emission goals almost unattainable, certainly the 2030 ones. This state is currently in an epic heat wave causing power demand spikes. It is also the state most vulnerable to climate change driven forest fires. It can ill afford to take out any carbon-free capacity, especially if the concerns expressed on Diablo Canyon continuance can be met by other means.

Diablo Canyon nuclear facility at Avila Beach, CA. Source: NY Times. Credit: Michael Mariant/Associated Press

Enter the Stanford/MIT paper. It has explicit engineered solutions to minimize marine life extinction in the water procurement. It also has two other interesting suggestions to maximize the environmentally related value of Diablo Canyon. One is to use part of the output to desalinate seawater. The measures taken to protect marine life would apply here as well during the water acquisition. Since reverse osmosis produces a highly saline wastewater, the disposal in the ocean would need to follow means to minimize damage to sea bottom species. These are known methods and simply need adoption.

The other suggestion is to electrolyze water to produce hydrogen. This would be considered green hydrogen because the electricity was carbon-free. Power is employed in this way in Europe during periods of low demand. There they are piloting adding a 20% hydrogen cut to natural gas pipelines, to reduce fossil fuel use. A point of note is that the electrolytic process requires 9 kg fresh water for each kg hydrogen produced. While green electrolytic hydrogen is seductive, especially when using electricity during period of low demand, fresh water is in short supply in many areas, especially South/Central California. Could be a reason for the Stanford/MIT report suggestion regarding desalination at Diablo Canyon.

Aggressive decarbonization strategies will come with tough choices. An easy one is to target “carbon-free” rather than “renewable” energy. A harder one is to tolerate bridging methods, such as natural gas power with carbon capture and storage. The trick is to ensure that the bridges* are to definite targets. With sunset clauses.

Vikram Rao

September 4, 2022

*A bridge over troubled water, from Bridge Over Troubled Water, Simon and Garfunkle (1970)

There But for Shale Gas . . .

August 29, 2022 § 2 Comments

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 Time for Blue Hydrogen

August 11, 2022 § Leave a comment

For the longest time blue had been content as a pure spectrum color at a nominal wavelength of 450 nm. Then the hydrogen police said it was not green enough. This despite Kermit the Frog informing us that it was not easy being green. Apparently, Britain agrees with Kermit, as reported in an Economist story. Their hydrogen strategy is heavily loaded with blue.

First a reminder on definitions. When hydrogen is synthesized by reacting methane with water, the process known as steam methane reforming, it is classified as grey hydrogen. If the resultant CO2 is captured and stored, the color of the hydrogen turns blue. If the hydrogen is produced from splitting water electrolytically using green electricity, it is classified as green hydrogen. To confuse matters further, the Government of India has classified the blue hydrogen from methane reforming as green if the methane is biogas sourced.

Going back to the Economist story, Britain has called for hydrogen to be 4% of energy demand by 2030. Even at this relatively modest target, the green electricity required for this hydrogen to be green would be 126 TWh (terawatt hours). This compares to the total green electricity production in 2020 of 135 TWh, with many potential uses beyond electrolytic hydrogen. In fact, one of the uses planned is blending hydrogen to a 20% level in natural gas pipelines. Mainland Europe has been piloting this and there is a consensus that a 20% blend is tolerated by the pipelines and by the end use.

The British plan calls for production of blue hydrogen in two locations with industry such as ammonia and methanol production that already uses grey hydrogen. Carbon mitigation in industry takes two forms. One is to change the process by replacing the existing reactant, such as coke, with hydrogen, thus curbing or eliminating CO2 emissions. One such is ironmaking with the Direct Reduction Iron process, and the resulting steel would be considered green steel if the hydrogen were to be green. Steelmaking is specifically cited by the British plan.

The other approach is to not change the process, but simply substitute a zero-carbon hydrogen for the grey hydrogen. The British plan favors blue hydrogen as a pragmatic means to achieve carbon mitigation faster than may be possible with just green hydrogen. This plan relies on economical means for capturing and storing the CO2 from the methane reforming. This is increasingly a reasonable expectation, with technology already commercial and likely to be available at scale within a couple of years. Economical is defined as fully loaded cost lower than the carbon penalty in force at the time. This is variable and stands at about €85 at this writing (see figure). A leading carbon capture technology claims capture costs at USD 40 per tonne, with an expected reduction to USD 30 over time. Given that geologic storage costs about USD 10 per tonne, the combined figure is well below the carbon penalty.

Carbon pricing in the EU  Source: EU Carbon Permits – 2022 Data – 2005-2021 Historical – 2023 Forecast – Price – Quote (

The Good Before the Great

Few would dispute that the most desirable hydrogen is the green variety. Here too a relaxation must be sought for the strict definition. The electricity source ought to be expanded from renewable to carbon-free. The carbon mitigation purpose is served and scalable carbon-free sources such as geothermal energy and nuclear power are then comfortably included. As previously discussed, these are excellent fillers of the diurnal and seasonal gaps in solar and wind production.

But green electricity is in short supply compared to the demand. The primary reason is that the largest sources, solar and wind, have low capacity utilization. On the demand side, everybody wants some. The MIT spinout Boston Metals needs it to make electrolytic green steel. The other principal green steel method, DRI, needs electrolytic (green) hydrogen. Data centers supporting the cloud are energy hogs that are growing steeply. All the major players in that space want green electricity. Ditto for bitcoin that other fast growing energy intensive sector. In other words, relatively sparse green electricity has many calls on it.

Enter blue hydrogen. The case against it begins with the fact that only 90 to 95% of the CO2 is captured at the point source. Some is still released. The other knock on it is that natural gas production is implicitly encouraged. But the uncomfortable truth is that every new solar/wind emplacement already creates demand for natural gas to fill the longer duration gaps in output. Although coal and oil will continue to decline, natural gas will be needed as a gap filler till the zero-carbon alternatives hit their stride; and that is a decade or more away. That is plain and simple pragmatism. As is the need for blue hydrogen until green electricity becomes more easily available. It is the only viable near-zero-carbon hydrogen that can achieve scale swiftly.

The battle against climate change must be joined with the best weapons at hand. No active battlefront waits on the ultimate weapon. Blue ought to be the primary color of hydrogen until, again quoting Kermit*, being green is easier.

Vikram Rao

* It’s not easy bein’ green Kermit the Frog, written by Joe Raposo, sung by Jim Henson (1970)

How Realistic is a Carbon-free Power Grid?

July 21, 2022 § Leave a comment

There is a new sheriff in Energy Town. In much of the world, solar and wind are the lowest cost source of power, clean or otherwise. They are effectively the new base load to which all other sources of energy must fit. And fit is needed.

Navigating Dunkelflaute

Dunkelflaute is the German word for periods with no wind and no sunlight. A more fanciful definition is dark doldrums. Navigating doldrums has always been hard for sailing ships. So it is for electricity production in periods of Dunkelflaute, which are substantial year round, because solar and wind utilization peaks out at monthly averages of 25% and 40% respectively, with annual medians at lower figures. The figure shows capacity factors for wind-based generation in the US. Capacity factor is essentially the efficiency of utilization of the nameplate capacity (maximum rated output). Solar energy has similar characteristics in terms of seasonal variation, with annual median capacity factors closer to 20%.

The list is short for clean energy sources for navigating Dunkelflaute: geothermal energy, small modular (nuclear) reactors (SMRs) and innovative storage systems. Sure, pumped hydroelectricity and other forms of gap pluggers exist, and may even be cost effective where available, but they are not scalable.

Seasonal variability of wind in Texas 2001-2013

A feature desired for all gap fillers is the ability to load follow. This means ramping up or down in response to demand on a dynamic basis. Advanced geothermal systems, in late-stage development, can load follow without impairing operations. So can SMRs. One reason that the conventional means for gap filling, natural gas fired generators, are so effective is that gas turbines can spin up or down with minimal energy penalty.

Economics of Gap Filling

There are two types of gaps, diurnal and seasonal. Solar has more diurnal variability than wind, and the most well-known gap is the 4-6 hour one in the evenings. This is filled with batteries and this practice will likely continue. The cost for this in the vicinity of 2 cents per kWh, which effectively doubles the solar based cost in places like Los Angeles. A recent study of several grid systems in the US and Europe by the Rocky Mountain Institute1 has shown that batteries alone will be very costly for the last 50% or so of achieving 24/7 clean power. The numbers go well over 10 cents per kWh on the PJM grid in the northeast US. In estimating the cost of gap fillers, investigators and commentators must resist comparing costs with those of solar and wind. The comparison must be with the conventional gap fillers, and that means aiming for less than 15 cents, and possibly less than 10 cents per kWh.

A frame of reference for this choice is the cost of the most common gap filler, natural gas combined cycle (NGCC). With a relatively low capital cost contribution to the delivered cost (20% as a rough average), the cost of natural gas is the dominant factor. At natural gas cost of USD 5 per MMBTU (which is the energy content of roughly one thousand cubic feet of gas), the dispatched cost from the producer will be about 5 cents per kWh. I am using that figure for natural gas cost because I expect that number to not be exceeded (except in short upset conditions such as the Great Texas Freeze) because of abundant shale gas.

But for comparison with zero carbon power gap fillers, one needs to remove CO2 from the NGCC process. Technology available today, but not yet at scale, ought to remove 90% plus for USD 40 per tonne CO2, with another USD 10 for geologic storage. That adds about 2.4 cents to the NGCC tab, bringing it to 7.4 cents per kWh in the US example above. Note that gas price in Europe has always been over double that in the US, and today it is at 6 times, making the associated dispatched cost that much more expensive. The point is that a global figure for a true zero carbon gap filler could conservatively be 15 cents per kWh, with an aspiration target of 10 cents over time.

How realistic is that? Very, according to leading developers of advanced geothermal systems and SMRs. At least two of the geothermal folks, Fervo Energy and SAGE Geosystems, have near term plans for commercial installations, at a Google data center and Ellington Air Force base, respectively. At least in the case of Fervo, we will know by 2024 whether the claimed costs of well under 10 cents per kWh are realized. In SMRs, NuScale is also claiming numbers well below 10 cents, but the first installation will not be until 2029.

Role of Hydrogen

Load following has one shortcoming. When not needed, the utilization is lower. In Texas, for example, in the period 2012-2019, capacity factors for NGCC varied from 48% to 57% in response to solar and wind-based delivery shortfalls relative to demand. Over 80% of the cost of electricity from an NGCC is variable cost, dominated by the price of natural gas. Lower capacity factors are more tolerable than they would be for conventional nuclear power, where capex dominates the economics.

Both advanced geothermal and SMRs have relatively low fuel costs, especially geothermal. Load following though they may be, the capital is more effectively amortized if the electricity during the idle periods is utilized in some fashion. The obvious option is storage, but that awaits innovation for systems suitable for long periods.  

An option acquiring some currency is production of electrolytic hydrogen. Considered green hydrogen, the value would be high. But the onus of low capacity factors now shifts to the electrolyzer. Here there can be some relief, in that these units can be relatively small and considerable research is ongoing to reduce both capex and opex costs. The low capacity factor piper must be paid, but this seems like the most cost effective stopping point in the toppling dominoes. At scale, the problem of adequate clean water supply for electrolysis becomes an issue. But another variant on the use of idle gap fillers is for enabling desalination plants.

The hydrogen could certainly be stored and used to generate power as a gap filler. But there are higher value uses. One would be to blend into natural gas pipelines to reduce fossil fuel usage. Blends up to 20% are known to be pipeline and end use tolerant and are already being piloted in Europe. Another high value use is in the production of ammonia for several applications, fertilizer being the largest. Transporting ammonia is cheaper than transporting hydrogen, so the ammonia would most profitably be synthesized near the hydrogen production. Recent advances in cost-effective small-scale ammonia synthesis will enable this option.

Carbon-free power grids are certainly in our future. How many, how soon and to what degree, that will depend on technology, policy enablers and appetite for investment. But even this is just one skirmish in the battle against climate change*.

Vikram Rao

*All in all, you’re just another brick in the wall, from Another brick in the wall (1979), performed by Pink Floyd, written by Roger Waters. This is my interpretation of the lyrics, not the standard one.

1 Dyson, M, Shah, S, & Teplin, C, Clean Power by the Hour: Assessing the Costs and Emissions Impacts of Hourly Carbon-Free Energy Procurement Strategies, RMI, 2021,


November 28, 2021 § Leave a comment

Perhaps the question ought to be how well we are being allowed to manage the transition.  When President Biden attempted to put the arm on OPEC+ (Organization of Petroleum Exporting Countries plus Russia) to increase production to dampen oil prices, he was accused in some progressive circles of acting in opposition to his avowed climate change goals.  No matter that in a country beset by inflationary pressures, any relief for the consumer ought to be welcome.  The oil market is elastic.  Only increased supply, at constant demand, will reduce prices.  Unable to persuade OPEC+, President Biden took the unprecedented step of coordinating with several net importing nations in releasing oil from strategic reserves.  The US will release 50 million barrels, only about 8% of the reserve.  This too was criticized from many angles. 

The one criticism I found most interesting was that US refineries would not want the stuff because the release was from the more sour (high sulfur) crude containments.  The argument was that they would need hydrogen for desulfurizing (true) and that rising natural gas prices made the hydrogen (mostly derived from natural gas) prohibitive (not so true).  The US may be the one country not having a natural gas supply issue, provided producers choose to respond to the relatively high prices.  One factor in favor of so doing is that shale gas wells have a short payback period due to high decline rates (rate of drop in production).  Consequently, an investment in shale gas is not a bet on the long term prospects of the commodity.

Also, the LNG business will continue to grow to feed Europe, Japan, China, India, to name a few dependent on it.  The relative lack of it is why the prices are at unprecedented highs in those countries.  In other words, LNG will be an important customer for decades for new natural gas.  Another parenthetical point on what US refineries want: they do not want US shale oil because it is too light and too sweet(!), and they have expensive kit going idle if all they refine is shale oil.  This is one reason that the US imports 4 million barrels a day of heavy crude from Canada (and only 0.4 million from the Saudis).  The SPR release oil will blend in just fine.

The moral of this particular episode is that while long term carbon mitigation goals must be set, if they cause significant privation in the short term, the current public support for carbon mitigation could dwindle, making it harder for those goals to be bolstered with necessary policies.  Take the current explosion in natural gas prices worldwide, but mostly in the net importing nations.  European governments are scrambling to protect the public from crippling heating bills this winter.  In this scenario, investors shunning fossil fuels do not serve the common good.  The argument is made that investors are leery of taking positions in areas that are in decline.  Natural gas may be the one fossil fuel that will see growth in the short to medium term, and eventually take longer to decline than oil.  In part this is because over 90% of essential backup of renewables comes from natural gas.  As noted in a previous blog, this will continue until we solve the storage problem at scale.

An important consideration for investors is the payback period, and to a degree the allowable amortization period.  The latter is a policy matter for governments.  The US has a long-standing policy favorable to producers (essentially a subsidy), which is debatable in its merit because of the broad swath.  But were it to be used in targeted areas, the use of public funds could be supportable.  In any case, some mechanism must be found to incentivize investment in the bridging areas.  This applies also to vehicles.  We are a very long way from electric vehicles being in the majority.  The auto industry ought to continue to invest in innovation in the efficiency of IC engine based vehicles.

The concept of bridging to a greater goal must not only be tolerated, but ought to be considered essential.  Renewables have intermittencies, which will require fossil fuels to fill the gaps, for at least a decade and change. Today we are faced with the inescapable prospect that additional solar or wind places incremental demand on natural gas. This is an uncomfortable truth that must be faced until cost effective sustainable alternatives take a hold.

Vikram Rao

November 28, 2021


November 14, 2021 § Leave a comment

The family in the title is, of course, the scientific community.  As reported in many places, including the New York Times, Moderna and the National Institutes of Health (NIH) are feuding regarding patent rights and inventorship of the key patent applications covering the Moderna version of the mRNA vaccine for Covid 19.

Lightly discussed in the press, but mentioned as a further point of contention, is that the NIH has a seminal patent for enabling the action of mRNA based vaccines.  The Covid 19 virus (SARS-CoV-2) has a structure resembling a crown, hence the name corona virus (see figure).  Note the spikes jutting out beyond the main body. This is composed of the spike protein. When the mRNA is introduced into the body it produces the spike protein, mostly in the liver.  However, merely being produced is not enough, because what matters to the immune system is not just the sequence of the protein, but the shape. Left to their own devices the produced proteins wouldn’t fold into the signature spike shape, so tricks are needed to nudge them in the right direction.

SARS-CoV-2 transmission electron microscopy image, courtesy NIAID-RML

To achieve this, NIH and university collaborators arrived at a method of covalently stabilizing the produced protein using a divalent sulfide bond.  The resulting “closed structure” is sufficiently like the SARS-CoV-2 spike protein as to stimulate the production of antibodies providing immunity from the disease.   A more scientific discourse on what was done is in a recent Nature paper.

The technique described above applies to all corona viruses.  The patent US 10,960,070, which issued just in March this year, covers all viruses with spike proteins.  The importance of this is twofold.  Firstly, any variant of the mRNA approach for addressing Covid 19 appears to need this technology to be effective.  More on that later.  Secondly, one concern continues to be that more corona virus mediated diseases are likely, particularly if the animal to human transmission with SARS originally from civets in 2002, MERS reportedly from camels in 2012, and now Covid 19, likely from bats, broadens to other species.  Were this to happen, it appears we have the technology to quickly produce mRNA vaccines to combat them.  Even this time around, the time scale of vaccine production was unprecedentedly short.

Now, back to the main dispute between Moderna and the NIH.  Facts not in dispute are that the NIH funded Moderna to the tune of USD 1.4 billion (yes with a b) to develop the vaccine.  This was a company that had never commercialized any product previously. NIH also provided experienced collaborators.  Three of them, Drs. Graham, McLellan, and Corbett, were inventors on the technique described above, and Graham was the lead inventor (in the eyes of the law all inventors are equal, but it is customary to have the largest contributor be named first; accordingly, the patent is referred to as the Graham patent).  Also, seemingly not in dispute is that US 10,960,070 is vital to the efficacy of any mRNA-based coronavirus vaccine.  Certainly, the creators of the other mRNA vaccine, Pfizer-BioNTech, licensed the patent.  Curiously, Moderna did not, and yet nobody is arguing that they are not using the technology in their vaccine technology.  My not very expert read of the claims in the patent is that the claims are strong and hard to work around.

If Moderna is using US 10,960,070 and not licensing it, why has the NIH not taken infringement action?  One explanation could be that the four-year collaboration certainly commenced prior to the March 2021 issuance of the patent, and until early this year, there was no certainty of issuance.  But it did issue.  Ordinarily, that would lead to some legal resolution.  Muddying matters is that NIH scientists collaborated and quite possibly the “background” technology, comprising the technique underlying the NIH patent was offered for non-exclusive use. This is normal in collaboration, but often includes “normal and customary” royalties in the event of commercialization. Perhaps it did not in this case. 

Now to the essence of the dispute.  NIH claims that the three scientists mentioned above ought to be named inventors.  The Moderna spokesperson says, “the company was legally bound to exclude the agency from the core application, because “only Moderna’s scientists designed” the vaccine”.  On the face of it the legal aspect is correct.  Being a collaborator is not sufficient.  Inventorship has the higher bar of direct contribution to at least one of the claims in the patent. This is a fact issue.

In context, the Times story states that the patent office “role is simply to determine whether a patent is warranted”.  While that is the case at this stage, if the validity of the patent is placed in dispute, inventorship is something that plays an important role.  Leaving out (provably) legitimate inventors can render the patent unenforceable, although the bar for proof is high. These days, the lowest cost means to challenge a patent is to appeal to a federal body through the Inter Parte Review (IPR) process.  Aside from being cheaper than conventional litigation, to date the IPR process has been substantially more challenge friendly than the courts.

Inventorship does not automatically grant ownership rights to the employers of the named inventors.  But it is usual for the patent to be co-owned in these cases, especially when both entities have invested in the discovery.  US 10,960,070, for example is assigned to NIH, Scripps, and Dartmouth.  Yet, the reporting has it owned by the NIH.  As is usual in these situations, there must be a side agreement on respective rights.  Absent that, each co-owner has the legal right to do what they want to with the property, which gets to be a mess. 

There is a hint in the reporting that part of the impetus for the NIH asserting co-ownership in the recent Moderna patent application is the desire to make it available to poorer countries.  If it did so by licensing, there is the risk of the licensee improperly executing, thus bringing disrepute to Moderna’s offering.  I have faced this in my career and always required safeguards, which would not be possible if Moderna was not directly involved in the licensing. The better resolution to this dispute is a royalty share rather than rights to license by the NIH, and an agreement for Moderna to make the vaccine available at lower cost to those poorer countries.  AstraZeneca is reputed to have done that.  When the Gates Foundation invested in CureVac (Germany) they made such a provision a condition.  The NIH ought to have done so at the outset.  In all fairness, the civilian bosses at the time may not have felt that way.  Now that horse has all but bolted*.

A feel-good story has turned into a horror show.  The poster child for public-private partnerships has become Exhibit 1 in the short course on how not to conduct collaborative innovation.

Vikram Rao

November 14, 2021

*”I drove my Chevy to the levee, and the levee was dry” from American Pie written and performed by Don McLean (1971)


November 7, 2021 § 3 Comments

A recent New York Times story cautiously lauds a Russian effort in Siberia to provide heat to a seaside community from a floating nuclear reactor.  Two concepts are in play here.  One, which is common to all forms of electricity production, is the use of the relatively low-grade heat of the working fluid following turbine operation for electricity.  In some cases, this is known as combined cycle.  The energy in the heat can often be nearly as much as that in the generated electricity. This part is not new.  The relatively new bit is that the reactor is a small one on a barge and could reasonably fall in the classification of small modular reactors.

Small modular reactors (SMR’s) have been around for about two decades, but none are in commercial operation.  My first encounter with these was about twenty years ago.  A couple of scientists from the Los Alamos National Laboratory came to visit me at Halliburton.  They claimed to have an SMR with about 30 MW output of electricity.  The key features were that they were safe from runaway by the very nature of the nuclear design and that the whole unit could be placed underground in a chamber.  The fuel rods would need to be replaced only every 5 years, with a future target of 10 years.  The location of the reactor made it relatively immune to terrorism.  This was necessary in part because the intent was to distribute them in communities.  The modularity would enable mass production.  And unlike conventional nuclear installations, everything would be built in central locations and subassemblies would merely be put tother on location.

I wanted to use the concept in heavy oil recovery in Canada.  Steam is conventionally generated on site by combusting natural gas and is essential for inducing mobility to the viscous oil underground.  The steam plant is a big CO2 generator and is in large measure responsible for the high carbon footprint of heavy oil.  In my concept, the lower grade steam after power generation from the SMR had ample sensible heat for use downhole.  The Los Alamos concept became the company Hyperion, but simply did not get off the ground for our use. 

Now several players have the joined the fray, including large ones like Toshiba and Westinghouse.  A big issue will be societal acceptance.  Not in my back yard (NIMBY) will be replaced by NNIMBY, with the first two words being No Nuclear.  Education on the safety of these compared to the old ones at Chernobyl and Three Mile Island will be key.  It will still be a struggle in some countries.  Germany painted itself into a corner by banning all nuclear after the Fukushima Daiichi tsunami disaster. I imagine the ultra-low probability of tsunamis in Germany was not a consideration, just the reported intransigence of the Green Party holding sway. In the NY Times story town residents bathing in hot water from the reactor complex do worry about the source.  The explanation of fluid contact-less heat exchangers appears to be winning the day.

Here is an irony regarding the phobia for water from such a source.  Iceland gets much of its day-to-day use energy from hot water from geothermal sources.  Folks soak in the geothermal pools there and all over California, Nevada and Wyoming. Medicinal properties are attributed. The source?  That giant nuclear reactor at the center of our earth. OK, to be fair, there is a heat exchanger in play.  The heat is conducted through the mantle and only then contacts a water source, which is then transported to the surface via faults in the rock.

The current crisis with unprecedented natural gas prices has people wishing for more nuclear, and bemoaning policies such as those in Germany.  But conventional nuclear is costly compared to solar and wind, especially after the augmentation and storage issues are resolved.  Curiously, US Secretary of Energy Granholm announced at the COP26 meeting that the US believes in small modular reactors.  She plans “to make sure they are less expensive (than conventional reactors)”.  I think that goal is more likely in greenfield situations like India, where some savings would be from not having a grid.  The greatest savings will be from mass manufacture of the sub-assemblies in central locations, with just final assembly on the site.  In traditional nuclear power generation capital represents 74% of the levelized cost (compared to 22% for natural gas).  SMR’s are intended to directly address this cost.

Governments ought to consider enabling multiple emplacements of SMR’s through financing and fast permitting, thus speeding the road to mass manufacture, and steepening the glide path to low costs.  The Indian government did this with LED lighting and now has some of the lowest cost devices in the world.

Vikram Rao

November 7, 2021


November 3, 2021 § 2 Comments

A recent story in the Economistpoints out that fossil fuel is not retreating from the world energy stage any time soon.  Decreasing, yes, but not going away.  This is certainly truer for natural gas than for oil.  But even oil has circumstantially made a reprise appearance due to a complex scenario which we will discuss below.

The world has rushed into renewables without adequately solving the issue of swings in output of solar and wind.  Over 90% of augmentation during slow intervals (rainy and windless periods) is with natural gas fired power.  The battery back up that we hear about is mostly for the 4 to 6 hours in evenings.  Even that almost doubles the cost of solar in some cases.  Storage and augmentation are badly lagging solar and wind installations.  Ironically, therefore, the more we install, the greater the demand for natural gas.  Not helping is that . . . . .

Natural gas prices are at unprecedented highs in most of the world other than the US.  Even in the US, they have doubled in the last few months.  In many parts of the world, including Europe and Asia, prices have been over USD 20 per MMBTU, and as high as USD 30 last week.  In Europe, in June they were USD 8 and a year ago they were USD 4.  This extraordinary surge is attributed to a combination of events, but all underpinned by one characteristic of gas: it is a regional commodity.  Pipelines do not cross oceans.  The only means of transoceanic supply is through Liquefied Natural Gas (LNG).  New LNG supply takes 5 years to go on stream, so it is not the means for a short-term remedy.  The process of liquefaction, transport and re-gas adds between USD 3 and 5 to the original cost.  In net importing nations, LNG will be the marginal cubic foot, so it will set the price, creating something of a windfall for the domestic gas producers.  Look for European gas (and oil) companies to report record profits.  Shell’s shift from oil to gas is looking brilliant.

Europe gets a little over 40% of its natural gas from Russia.  The mere announcement of an intent to increase supply from Russia caused a drop from USD 30 to USD 20 in days.  Then, news of a hiccup increased the price over USD 2 in a day.  This underlines the power wielded by Russia.  We have discussed the use of energy as a weapon of political will in this column in the past.  Putin is unlikely to let this opportunity pass, especially if the winter is colder than usual.

Another odd dynamic is in play in oil.  Much of the crude oil produced in the world has undesirable quantities of sulfur.  In the refining process this is removed using hydrogen.  Also, heavier oils require hydrogen to be “cracked” down to useful transportation fuels.  Over 95% of hydrogen is produced from processing natural gas.  High natural gas prices mean that light, sweet oil is suddenly prized even more than usual because it will not incur those added costs (by and large).  US shale produces such an oil.  Look for shale oil to be in short supply.  We used to think that when this happened, producers would quickly ramp up.  That was before the carnage of the last couple of years, during which small producers sold out to large ones.  Large companies are more measured in their response, and the carnage has reduced investment appetite.  The table is being set for USD 90 per barrel oil.  Two years ago, it was under USD 20.

At current prices gas, on an energy equivalency basis, is much more expensive than oil.  Using a rule of thumb, at USD 25 per MMBTU, gas is more than twice as expensive as oil, which is at about USD 80 per barrel.  I do not recollect ever seeing that in my 40 odd years in the energy business.  In many parts of the world, dual fired electricity generation capacity is using oil instead of gas, thus increasing oil demand. At a time when oil majors Shell and BP have announced strategically planned production decreases and US shale oil interests will be slow to respond unless prodded by the government.  Such prodding, while pragmatic and a plus for the balance of trade, will certainly not play in progressive circles. If this game can be played while still emphasizing carbon mitigation, the US could be positioned to be the swing producer in both oil and gas.  Until oil goes away. Slowly.  Being a swing producer has political heft.  Just look at Russia in the European gas scene.

Governments having been doing much to subsidize and otherwise drive the use of renewables.  They should now put an even greater emphasis on the development of sustainable storage and augmentation means.  Otherwise, they run the risk of a public losing faith in at least the renewable energy arrow in the carbon mitigation quiver.

Vikram Rao

November 2, 2021


September 10, 2021 § 1 Comment

Low-cost energy lifts all boats of economic prosperity. Or on the other end of the spectrum, high-cost energy threatens to sink them, especially if prices rise suddenly. Nowhere is the positive scenario more evident than in Iceland. An otherwise resource poor country, cheap energy has elevated it to the third highest gross domestic product in the world. Unlike Norway, a country at a similar latitude, almost all produce is domestically derived. Greenhouses enabled by natural hot water operate for much of the year.

Iceland has the good fortune to be sitting on the Mid Atlantic ridge between the North Atlantic and Eurasian plates. Surrounded by volcanoes, the earth stresses are such that most eruptions are through fissures, unlike those in Hawaii and other places with typical conical protrusions with violent eruptions. Furthermore, with abundant subsurface water and high thermal gradients (subsurface temperatures that rise faster than normal with depth), hot water rises in the faults and emerges on the surface as geysers, or mere hot water lakes.  This hot water supplies heat for 90% of the homes.  It also is used to produce electricity, although in that case the water is from wells drilled a couple of kilometers. I estimate their cost to produce to be well under 2 US cents per kWh. They charge industry 5 cents and domestic users pay 13 cents. Clearly, tariffs are involved. But this compares to Netherlands and Germany at nearly 30 cents for domestic users.

A recent New York Times story reports a different scenario for the rest of Europe (yes, Iceland is in Europe) in that rising natural gas prices in Europe are slowing the post-pandemic economic recovery.  Natural gas prices are reported to have risen to USD 18 per MMBTU.  The pre-Covid 19 figures used to roughly fall out as follows: the US at USD 3, Europe at USD 9 and Japan at USD 17. The US is still low at USD 5, but that is the highest in nearly a decade. Abundant shale gas has kept the price down, but that industry has been battered by the pandemic, so is probably slow to respond to the surge. Remember also that shale gas driven low energy cost was the single biggest factor for US recovery from the recession of 2009.

What we can expect

On natural gas price, in one word: volatility*.  The USD 18 per MMBTU reported today as the spot price for Europe is probably aberrant.  The price was a third of that a few months ago. Also, most utilities operate on long term contract pricing. The high spot price is almost certainly driven by liquefied natural gas (LNG) import prices.  Drought conditions in countries such as China have reduced hydroelectric output and required augmentation with LNG powered electricity. Parenthetically, yet more evidence of impact of climate change. Usually, the spot price is determined by the price of the last cubic foot of gas imported.  For Europe, that is LNG. The winners here are the Russians with pipeline supplied gas, if the contracts allow escalators.

Again, most LNG contracts are long term and pegged to the price of oil.  In the US, most (all?) are based on the Henry Hub spot natural gas price.  It is multiplied by 1.2 and liquefaction cost of USD 2.50 is added to it. Today at USD 5 prices, LNG would be at USD 8.50, a far cry from the spot price in Europe of USD 18.  And so it goes in the commodity trading market.

I would expect US shale gas drilling to pick up in response to the price.  The smaller players, who are fewer yet after bankruptcies last year, will respond. Now that so many properties are in the hands of the major oil companies, expect their response to be more measured.  In any case, I expect US prices to stabilize and there is no serious risk of prices rising to the point where coal has a resurgence. Unlike in the case of oil, all gas pricing is regional. LNG is the only means of transport between regions and it adds a cost of somewhere between USD 3 and 4 to the produced gas price.

The experts are predicting a colder than normal winter.  If that transpires in Europe, the proverbial Katie will have to bar the door on natural gas prices.

Vikram Rao

September 9, 2021

*Everybody look what’s goin’ down from “For What It’s Worth” by Buffalo Springfield (1967), written by Steven Stills.

Where Am I?

You are currently browsing the Uncategorized category at Research Triangle Energy Consortium.

%d bloggers like this: