April 16, 2020 § Leave a comment

I used to think geothermal energy was a niche play.  And it was, until fairly recently.  Or, to be fair, I became aware recently that multiple approaches were being investigated, all of which were scalable, albeit to different degrees.  I define scalability to mean the ability to supply a material portion, and in the limit, a majority, of the electricity needs of the world at a price competitive with conventional alternatives.

The source of geothermal energy is the core of earth.  Essentially a nuclear reactor, where temperatures approach those at the surface of the sun.  The heat is conducted to the earth’s surface and eventually dissipates into our atmosphere.  Harnessing this heat is the essence of geothermal energy production.  Utility scale geothermal energy involves drilling a well, not unlike an oil well, pumping a fluid down, usually water, and then recovering the fluid heated by the subsurface rock to perform some work.  That work is usually the generation of electricity.  In short, we are mining for heat rather than oil or gas.  The operations to accomplish this, and the underlying technologies, are identical to those used to prospect for oil and gas, except for the final power generation bit. To the extent that step out technologies are needed, these too are in the general realm of oil industry capability.

Oil and gas companies have recognized the need to diversify and become energy companies.  Over a dozen years ago, BP’s CEO famously declared that BP stood for “beyond petroleum”. While premature, the sentiment still led to forays into solar and wind.  Except for offshore wind having some synergy with oil company core competencies, these areas were not good fits as portfolio components.  Accordingly, to this day, they comprise small portions of the companies.

Geothermal offerings fall into two buckets: those that operate in rock at 200 C plus and ones that require 300 C plus.  In the former category fall Engineered Geothermal Systems (EGS).  Because the heat content of the rock is relatively modest, inducements are needed for the heat to transfer to the fluid being circulated.  This is accomplished with standard hydraulic fracturing.  The twist is that existing natural fracture networks are utilized to advantage.  The energy required to open existing fractures is much less than that to create new ones.  Consequently, induced seismicity (the risk of creating an earthquake, and a concern that has been raised by observers) is very unlikely. 

Induced seismicity requires a high energy input into an active fault.  An active fault is roughly defined as a fault likely to move in response to an energy input.  A fault is a mismatch between two bodies of rock, often created due to a movement (known as slip) of one body relative to another adjoining one.  Continued movement in response to an energy input can create a seismic event, an earthquake.  The magnitude of the earthquake is directly proportional to the length of the fault.  As noted above, the energy from opening natural fractures (a common geological feature not to be confused with faults), is small.  Furthermore, EGS operations require a thorough knowledge of the earth stresses, and so detecting faults and their lengths is straightforward. Avoiding operating in proximity to long active faults would mitigate earthquake concerns.

The second bucket is that of hotter zones, exceeding 300 C, most preferably 350 C. High thermal pickups by the fluid in the well can be achieved with well architecture that maximizes contact with the rock, and no hydraulic fracturing is involved.  This would be a closed loop system, with the working fluid not entering the rock.  If the temperature exceeds 374 C and pressure 221 bar, any water present in the reservoir would be in the supercritical state.  This is a state in which it behaves like both a liquid and a gas.  When CO2 is sequestered in porous rock, it is in a supercritical state, taking advantage of this dual property.  A more mundane example is CO2 decaffeination of coffee beans: the supercritical state allows easy entry into the bean as a gas and dissolves the caffeine like a liquid.  Supercritical water will produce more power than would steam.

EGS operations can be executed with the latest current technology. The deeper stuff needs development.  The oil and gas industry is well positioned to do both.  In fact, an aspect of the development of deeper systems is an extension of recent advances by the industry in high temperature, high pressure systems.  One could argue that they are the only ones who could reasonably pull it off.

Now is the time.  The oil industry (especially including oil service companies) is positioned to put geothermal energy into high gear.  This would not have the appearance of greenwashing even to the most jaded.  The federal government ought to help, although in the midst of Covid 19 recovery efforts, that might be tough.  And yet, that pandemic is the reason (now that the Russia/Saudi spat is resolved) that the US oil and gas rig count has plummeted over 30% in just one month. Continued demand destruction could ensure a long-lived drop at some scale.  That then, would be the time, to put people to work doing something else productive.  If at the same time this work moves the needle on a renewable energy source the appeal is to both sides of the congressional aisle. 

For the oil and gas companies, a sizeable geothermal portfolio (eventually) provides optionality.  Since essentially the same crews can be used to drill for either oil or heat, portfolio shifts driven by market conditions are feasible.  Forecasting the speed of adoption of electric vehicles will no longer be important.  Good for the industry and good for the environment.  Large scale win wins are often mirages; not this one.

Vikram Rao

April 16, 2020


August 20, 2020 § 4 Comments

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

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

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

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

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

Vikram Rao

August 20, 2020


April 9, 2020 § 3 Comments

A webinar conducted by the Research Triangle Cleantech Cluster this week, in which I participated, triggered this piece. Some points made by the other three panelists Ivan Urlaub, Renee Peet and Gary Rackcliff are reflected here, but I take responsibility for this product.

For purposes of this discussion, energy falls largely into two buckets: electricity and oil and gas derivatives. In the last two months or so, the price of oil has halved.  Part of the driver was the Saudi/Russia spat, which is likely to end soon because neither can live with USD 23 (price at the writing) oil for long.  But the “shelter at home” policy in much of the world has slowed industrial output to a dull idle. Gasoline and jet fuel use has plummeted. Electricity usage has dropped.  Here we will discuss the likely longer-term implications, especially as relating to energy.  Some of the issues addressed arise from questions that were asked in the webinar mentioned above.  Here is a crack at a list of outcomes that I see as highly probable.  A modicum of support is also offered for the assertions.

  • Electricity from renewable sources will not take a hit, except for diminished access to capital due to federal loan paybacks and the availability of workers for production and installation. An uptick in this space is possible, in which case closer attention to storage will be required.
  • Distributed electricity production, with associated microgrids, will remain unaffected, except for capital constraints.  Non reliance on a grid makes this segment attractive for resiliency in the face of disasters such as forest fires and hurricanes, but that sort of resiliency is less applicable to this disaster. To the extent that current deployments are in underserved communities, especially in low- and middle-Income countries, oversupply is unlikely because the supply usually just barely keeps up with demand, or the potential demand of increased productivity.
  • Electricity suppliers with a heavier footprint in smart features, such as remote monitoring of home usage, are benefitting during this crisis because so much service can be provided without deploying personnel.  Post crisis enthusiasm for these features, leading to wider adoption, is likely.  This can only help with resiliency as well and ultimately with enterprise profitability. Compared to other power industry investment, the scale of this one is small.
  • Oil prices will hover in the range USD 30-50 per barrel, with possible excursions to USD 25, with considerable volatility.  For the first time in a Very Long time, Texas producers may agree to a cap on production.  The Texas Railroad Commission, which has had nothing to do with railroads since 2005, regulates the industry.  Prior to OPEC, they were the determinants of oil price.  Production controls, whether mediated by the TRC or not, are likely to return.  Were that to happen, and if Russia and the Saudis reciprocate with production cuts, oil price could well be in the upper reaches of the range noted above, once the economic recovery is in full swing.  The US government has also announced a purchase of 77 MM barrels of oil for the Strategic Petroleum Reserve (SPR).  Since the SPR is depleted by about that amount, this would top it up.  The average cost of the current reserve is USD 28.  If they go through with it (funding for it is in doubt) the new oil will likely be at a similar price.  I have blogged previously that the SPR is not really needed any more, that shale oil in the ground is the reserve, but this could help prop up the price at a bargain cost.
  • In not agreeing with OPEC on production restraint, Russian intent was to kill US shale oil.  Shale oil will be wounded, but not killed.  As in the last plummet in oil prices in 2015, highly leveraged players will declare bankruptcies.  The properties will be scooped up by the major oil companies for dimes on the dollar.  With deep pockets, the majors will simply keep shale as a portfolio item and unleash when profitable.
  • The short- to medium-term reduction in shale oil production will reduce associated gas production.  After the winter of 2020, natural gas prices will begin to firm.  This firming will not be enough to reverse the attrition in coal demand for power.
  • Electric vehicle (EV) adoption rate will not materially be affected by the drop in gasoline prices, no matter how sustained. The fully loaded cost of EV fuel is dominated by cost of amortization of the batteries.  At a battery cost of USD 100 per kWh, as forecast by Elon Musk for next year (he actually said 2020, but I will cut him some Queen Corona slack), a 200 mile range EV will have a fully loaded cost of about USD 1.50 per gallon equivalent.  This is based on a lot of assumptions, but the electricity “variable” cost is between 17% and 30% of that figure.  The main takeaway is that unless gasoline price drops to a sustained USD 1.50 or lower (unlikely in most of the US, very unlikely in California and incomprehensible for Europe), gasoline pricing will have little influence on EV adoption.  If a battery swapping model is adopted (where the consumer does not own the battery and swaps a charged one at each “fill”), the pay as you drive concept will be appealing, with lower car purchase cost and lower per mile cost.
  • EV adoption rate is on the upswing, but still hard to predict. Oil and gas companies would do well to diversify their portfolios into electricity, which has other markets as well.  This has indeed been happening for a while.  But wind and solar don’t fit the core competencies of these companies.  A relatively new entry is scalable geothermal energy.  The operations are not only a fit, but oil (and oil service) companies are uniquely positioned to speed up the entrée and scale.  Once in their portfolios, they can balance them based on the EV adoption rate, much as they currently do with their oil versus natural gas components.
  • Remote working will have some measure of sustained adoption post apocalypse. It is being “field tested” by outfits that may not have used the mechanism in the past.  Some may find that it is cost effective.  I remember when Shell Oil went to a 10-hour day, four days a week, in Houston to reduce commute miles and associated emissions.  Remote working is that on steroids.  During this emergency each company will have sorted out which functions (and persons) are suited to this approach.  They can take an informed view on adoption.
  • Virtual meetings will have an even greater adoption rate.  Technology has kept improving, but inertia or conservatism has kept adoption down.  Now, with the enforced testing regime, informed decisions will be made.  I see a strong uptick in this area.  Winners are IT connectivity companies.  Losers are airlines.  Business travelers are the most profitable passengers on a plane.
  • Both the above will reduce use of oil derived liquid fuel.  Depending on scale this demand destruction could materially affect the price of oil. Natural gas pricing will remain unaffected; different markets served.

One, somewhat off topic outcome is rise in public empathy, and possibly altruism. When behaviors such as these are entrenched for months, they are more likely to stick. This is good. The (positive) irony would be if the pandemic caused “a contagion of good example” to spread. From an entrepreneurial standpoint, innovations in enabling this trend could be effective.

Vikram Rao

April 9, 2020

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