October 8, 2014 § 7 Comments
There is that movie soundtrack by Paul McCartney which goes “Live and let die”. If the current drop in oil prices (see figure below) is sustained for any significant length of time, the effect on countries will be highly variable. A sustained Brent oil price below $90 per barrel will do potentially grievous harm to the Russian economy with or without the financial burden of aggression in the Ukraine. The latest Russian budget was premised upon oil at $100, and given that over 40% of treasury coffers are filled with oil and gas revenue, a sustained price below $90 would be very difficult to swallow. Some reports have it that every $1 drop in Brent results in a $2.1 billion annual drop in revenue. In fact in an earlier blog I had mused on the option of release of the Strategic Petroleum Reserve (no longer needed in the US due to burgeoning domestic oil production), to drive down prices, or the mere threat to do so, to influence Russian aggression.
The US on the other hand will broadly be unaffected. A steady Brent price between $80 and $90 (if there is such a thing as steady oil pricing) could dampen some of the shale oil ardor. Shale oil prospects are highly variable with respect to breakeven price, but the vast majority of them make good returns at $80 per barrel pricing. Particularly if oil export were to be permitted, the net effect would be minimal. This is because US shale oil currently sells at a discount to Brent of well over $10, and export would afford it full Brent pricing. Allowing exports would markedly improve the resiliency of US shale oil production relative to softness in world oil pricing.
Many oil producing countries could be placed in an untenable situation were the Brent prices to stay below $90 for extended periods of time. The Gulf monarchies have spent lavishly on their populations especially following the Arab Spring. Good numbers are hard to come by, but Saudi Arabia is believed to need a $90 price as a minimum to sustain the social benefits. That number is higher in some of the other OPEC members such as Venezuela and Algeria, as also in Iran.
The drops in oil price do not appear to be any country’s doing. As we previously reported, world oil production dropped by 2 MM bpd over the last two years and was entirely made up by new US production from shale deposits. But more recently supply has also picked up elsewhere, especially Libya. Demand on the other hand has reduced, especially in the US. The trend towards demand reduction will continue at least in the US, where methane and ethane will displace oil in transportation and as the feedstock for chemicals such as olefins. Although unintended, a sustained drop in oil prices will serve the political interests of US and its allies vis a vis containing Russian aggression in the Ukraine. A sustained loss of oil and gas export related revenue, in conjunction with economic sanctions, would make military expenditures in the Ukraine affair essentially infeasible. The most related aspect of the sanctions is that with loss of revenue the Russian oil firms would need to borrow and foreign capital would simply not be available.
This is somewhat ironic because Russia has threatened to use curtailment of gas supplies to Europe as an imposition of political will. I have maintained in these pages that energy is a much more powerful weapon than armies for exacting pain for behavior seen as detrimental to the interests of a producing country, in this case Russia. In other words they would be living by the sword of energy. It seems now that there is a risk of dying (thrown into a deep recession) by that very sword, even if it was wielded unintentionally and by no one in particular.
September 27, 2014 § 1 Comment
The White House Science advisor John Holdren is credited with suggesting that responding to the threat of climate change ought to be some mix of mitigation, adaptation and suffering, and all that remained to be determined was the mix. This statement implies the inevitability of climate change and that preparing for it must be a part of the response. I suspect this cheered the climate hawks more than the doves. The suffering part is right out of the playbook of economists, the dismal science folks. Bleak though it may be, it is recognition of a stark reality. The entire statement is an acknowledgement that doing nothing is in fact a choice for suffering. Accordingly, climate hawks must not take too much comfort in the statement.
Even those who consider that climate change is a reality do not necessarily agree that climate science is “settled”, a characterization that is common. Nobody doubts that adding carbon dioxide to the atmosphere has adverse consequences to global warming. But influential scientists such as Steve Koonin dispute the ability of our models to predict the balance between human and natural influences. Consequently, adaptation has to be an important part of the debate on response.
In discussing the Holdren utterance, David Roberts recently had some interesting takes. He suggests that the effect of mitigation is global while that of adaptation is local. He goes on to conclude that mitigation is altruistic and adaptation is “the opposite”, serving only a self-interest. We will now examine this very interesting point of view.
Mitigation is that great big grab bag comprising all the measures to reduce greenhouse gases. These range from carbon capture and storage to curbing fugitive methane to energy efficiency and conservation. Many of these have positive outcomes to society beyond the carbon mitigation objective including economic value created. Mitigation certainly has global impact. In fact the common complaint is that India and China are not doing their part and consequently exacerbating the problem. So in that sense a mitigation action is altruistic because it benefits distant faceless people unknown to us. But it is not that clear and simple. Mitigation measures include many that are technologies which can be sold to other parts of the world for a profit, neatly removing them from the altruism bucket. An example is small modular nuclear reactors which are well suited to the over a billion people with no access to power grids. This serves the purpose of mitigation through not using fossil fuel (in the case of villages it is usually subsidized diesel). But it is also adaptive because distributed power is inherently more resilient due to absence of grid infrastructure. It is easier to implement distributed power when there is no grid at all. Consequently this is a technology from the first world that is uniquely appropriate for the third world. Transferability could apply to a host of energy efficiency technologies. The execution of these measures in the west could well be viewed as altruistic but not the transfer to other parts of the world.
Roberts also contends that carbon mitigation is innately altruistic because the benefit accrues to people in the future. This would have a ring of authenticity were it not to be for the popular refrain that climate action makes the world better for “our grandchildren”. There goes altruism. Incidentally, there is a school of thought that privation well into the future ought to be discounted with a social discount rate (similar to a financial discount rate) of as much as 3%. But this is not the forum for that discourse.
Adaptation is even more opaque. Roberts suggests that adaptation is solely local and “benefits only those proximate to the spender”. While this is true of the measures taken to account for sea level rise (in fact he uses the example of sea walls), many other measures have immense transferability even without redistribution of wealth. An important example is sustainable food production in the face of climate change. Here we define climate change to be “alterations in climatic and weather conditions characterized by shifts in average conditions and in the frequency and severity of extreme conditions” as discussed in a 2012 report on adaptive food production methods. These approaches are in large measure transferable to the second and third worlds and in some cases explicitly so.
Some of us here at RTI have been mulling over the extent to which distributed production of fuels and chemicals may be seen as an adaptive defense against climate change. Distributed production is a relatively new concept of producing chemical plants fifty to a hundred times smaller than conventional and located closer to either the raw material source or the market. For purposes of this argument we will assume cost neutrality with respect to the alternative conventional large plants. Certainly this action would result in shortening of supply lines of raw material, finished goods, or both. Supply lines are notoriously disrupted in extreme weather. Fewer long distance pipelines would also result in a smaller environmental footprint. This issue merits study in part because to date the entire push for distributed production has been premised upon economics only and not the societal benefit.
September 18, 2014 § 2 Comments
The oil export ban is an anachronism and needs to be lifted. The original energy security beliefs no longer hold water. We are fast approaching the point at which domestic production augmented with that of the near neighbors Canada and Mexico will serve the bulk of our oil needs. Combine this with the fact that an overabundance of natural gas will inexorably displace oil in many sectors, beginning with key chemicals such as ethylene and derivatives.
The most compelling argument until recently was the nature of the oil that we produce. It is light (API gravity greater than 40) and sweet (less than 0.4% sulfur), making it highly desirable to all but the US refineries. This anomalous situation comes about from the fact that most US refineries are outfitted with expensive process equipment to handle heavy crude (API gravity less than 20) often with high sulfur and heavy metals. Heavy crude sells for a discount of 15 – 30% to the benchmark West Texas Intermediate (WTI). So they are loath to pay full WTI price for crude that does not effectively utilize their expensive equipment. The result is that oil from the Bakken has sold in 2014 for a discount to WTI ranging from $5 to $15 per barrel. WTI in turn is selling at a discount to the North Sea benchmark Brent price. In 2014 that spread was between $5 and $12. US refiners love this spread because their raw material is cheaper. They also love the shale oil to sell at a discount to WTI. They are the principal opponents to lifting the crude export ban.
A segment of the public believes that oil exports will lead to higher gasoline prices. Since oil is fungible, with a world price, this argument is not viable. However, one could argue that export ban mediated lower cost oil would allow US refiners to produce gasoline for less and pass on that reduction to the consumer. The fly in that particular ointment is that gasoline exports are permitted by law. So refiners will necessarily sell to the highest bidder. In fact, export of US diesel to Europe is believed to be in part responsible for the shutdown of refineries there.
This last point brings us to the second reason to consider lifting the ban: possible oil diplomacy. Europe currently imports over 3 million barrels per day (bpd) from Russia, in addition to 14.7 billion cubic feet per day (bcfd). Retaliation for sanctions is likely to come in the form of energy supply tightening. US oil exports to Europe will have two positive outcomes. One is just the gesture of coming to their aid and the corollary benefit that this quality oil is well suited to “simple” refineries, especially in Eastern Europe. The other benefit is to the US GDP. This oil will sell for Brent price, which as we noted before is $10 to $27 over what Bakken oil sells for today. Even at just a million bpd, that results in additional revenue to US producers of up to $10 billion per year. Keep in mind also that US shale oil production has been seeing annual increases of a million bpd for the last two years. The figure reproduced below from Platts is striking.
Over the period February 2012 to May 2014 US production increase has single handedly made up for a net drop of 2 million bpd from the rest of the world. While this US production rate is expected to slow in 2014 to closer to 0.75 million bpd, the contribution will continue to be large, and the bulk of this is not suited to US refineries. So the domestic glut of light sweet crude is likely to continue. Exporting oil is good for the economy and a potentially important political gesture at a time when European allies are needed to combat the latest threat in the Middle East.
August 31, 2014 § 2 Comments
A recent story in Forbes tells the tale of the rise, fall and rise of LyondellBasell, a Houston based chemical manufacturer. At first blush the story is a gripping tale of savvy investing, risk taking and two opposite bets by equally shrewd investors. But the true message is really none of that. It is entirely the plus side of the Ethane Dilemma that I discussed in my shale gas book two years ago. It is also a lesson in the possibility that behind every problem lurks an opportunity.
The tale unfolded in 2007 when Basell, a European chemical company bought struggling Lyondell Chemicals. By 2009, in part beset by the recession, the newly named LyondellBasell sought Chapter 11 bankruptcy. Apollo Global Management saw an opportunity and essentially purchased the company for about $2 billion. Meanwhile, billionaire Len Blavatnik, one of the principals in Basell also bought into positions in the restructured company after himself having lost serious money on the bankruptcy. The company took off and Apollo cashed in about $12 billion in 2013. Not a bad profit in five years. Blavatnik, with a similar proportional profit in hand, instead of cashing out, continued to buy and is reported to be sitting on $ 8 billion in largely unrealized profits. The Forbes story focuses on how savvy billionaire investors took different paths at this point.
Ethane Price as Compared to WTI
Figure courtesy of Dow Chemical Company
The Forbes story credits the shale gas revolution with the performance. In a sense that is true but the explanation is more nuanced than that. First is the fact that the bulk of LyondellBasell profits come from ethylene and derivatives. Second is that ethane prices started to drop relative to oil in 2009. By mid-2010 ethane was nearly half the price of oil on the basis of energy content (see figure above). Ethylene is conventionally produced from the oil derivative naphtha. Ethylene from $4 per MM BTU ethane is about $ 600 cheaper to make per tonne, and a tonne of ethylene sells from $1000 to $1500 (the price in 2014) depending on market conditions. This was the primary reason for LyondellBasell profitability coming strongly out of bankruptcy. In the Forbes story there is a quote: “Billionaire hedge fund manager Dan Loeb used more than half of his first-quarter letter to his investors wondering why Dow Chemical Co.–where returns have trailed LyondellBasell significantly over the last three years–wasn’t more like its rival”. In my shale gas book I mention that 33 of 36 US crackers are on the Gulf Coast, with just two in the mid-west and one small one in Kentucky. Those two just happen to belong to LyondellBasell and are very close to ethane supply. In recognition of this, the company quickly added capacity to these two. Result: enormous profits capitalizing on the low raw material prices and LyondellBasell was uniquely positioned with respect to competitors such as Dow. Besides, Dow, while a major ethylene producer, has a much broader portfolio than LyondellBasell.
In 2013, when Apollo cashed out and Blavatnik increased his stake, ethane pricing simply dropped through the floor (see figure above). In fact the spot price of ethane in the mid-west is even less than that shown in the figure. This explains why the company profits continued to climb and the stock stands at 50% over the figure when Blavatnik last purchased stock from Apollo. In the Forbes interview Blavatnik attributes the success of his strategy to luck and hopes the luck will continue. More likely is the possibility that he saw the trend, which started in 2012. The fundamentals underlying the trend, low natural gas price and high prices for propane and butane, will continue to cause wet gas to be produced preferentially. Half of that is ethane, with no value unless converted to a chemical. Consequently, ethane will continue to be a glut until crackers show up. But unlike expansions of LyondellBasell crackers, new ones take many more years, significant financing, and ethane pricing crystal balls extending twenty years. In late 2013 Shell postponed indefinitely a cracker destined for Pennsylvania. Small, distributed, crackers as suggested in previous posts could be a factor in this game. Cheap stranded ethane represents a business opportunity. LyondellBasell merely happened to be in the right place at the right time.
June 26, 2014 § 1 Comment
Fly ash has been in the news since the Dan River, NC contamination incident earlier this year. Much of the attention has been on remedying the current situation: ash in unlined pits, especially proximal to surface water. This is appropriate because future contamination events from existing disposal sites need to be prevented. Current proposals place the timing of resolution out in the fifteen year timeframe.
So, what happens to all the fly ash produced in the interim? It could go to lined pits. In this regard there is similarity with the measures for temporary storage of liquid drilling wastes. Neither has been classified as a hazardous waste by the EPA. But in current draft NC legislation, liquid drilling wastes will be required to be stored in double lined pits with sensors between the layers. The same could do the trick for fly ash in solid or liquid form. The former is vastly preferable. This is because fly ash is light and fluffy and comprises spherical particles. This material will stay suspended and not easily settle to the bottom as sludge for removal. Bottom ash, the other type of ash in a coal combustion unit, is more amenable for pond settling.
Beneficial Use of Ash:
All coal deposits contain a certain proportion of minerals associated with the coal. These are oxides of elements such as Silicon, Potassium, Iron and Calcium. Many of these are in the clay family. When the coal is combusted these oxides remain inert. They end up in the bottom of the retort (bottom ash) or fly out of the top (fly ash). Fly ash constituents have a unique character: they comprise small spheres. As a result the material is light and fluffy. Transportation could result in dusting.
Fly ash falls into two classifications: Class F and Class C. Both classes have oxides of the same elements noted above, but Type C will have substantially more lime (CaO). When blended with water the mixture of oxides will form a substance not unlike cement. To get the same cementing consistency with Type F one needs to add lime when completely replacing portland cement. But in either case the material can very usefully replace cement in part or whole in the preparation of concrete. Concrete is essentially sand and/or gravel bound together with cement. Displacing cement is good for the environment because the manufacture of cement is a major producer of carbon dioxide.
Concrete prepared with fly ash based cement is believed to have improved properties over the conventional material. In particular the cement flows better than portland cement in part because of the spherical character of the particles. Improved performance is also claimed for bricks made with fly ash, lime and gypsum. Over 10% of fly ash in India (20 million tons per year) is converted to this product with the strong backing of the World Bank.
Hurdles to Use
Why, then, does not all fly ash get used in this fashion as opposed to being placed in landfills or ponds? One reason is that the producer may not be located close to the potential user and the cost of transport of this low density material could be high. There is also the risk of dusting. Fly ash can have trace amounts of Arsenic, Vanadium and other heavy metals. The original coal is the source. While representing possible hazards in transport, in the use in concrete they are benign. These elements, more than likely in the form of oxides, can be expected to be trapped in the concrete. They will not be subject to leaching because they are in the concrete body. But even when the concrete is converted to rubble at the end of life, they ought to remain in a form not subject to leaching in large measure because they will not be water soluble.
The second, and more important, reason for limited use of fly ash is the carbon content in some ashes. When the EPA introduced laws to reduce oxides of nitrogen (NOx) in the flue gases, the result was more unburnt carbon in the fly ash. When this material exceeds about 6%, it is not acceptable as a cement substitute. Two distinct types of technologies exist to overcome this problem. One is to physically separate the unburnt carbon using for example froth floatation or electrostatic methods. In most such cases the carbon is recycled for use in the combustion process. The other is to perform a controlled burn of the carbon usually utilizing the heat in some way. One elegant technique is to use microwaves. The energy is absorbed only be the carbon and not the ash constituents. This is similar to the fact that in a microwave oven the food absorbs the energy (gets heated) while the ceramic container stays substantially cool. In fact the industrial process can use the same frequency as household ovens, thus making it inexpensive because those components are mass produced.
What North Carolina Ought to Do
According to published reports very little if any of the fly ash produced in North Carolina is being used in concrete manufacture. One manufacturer testified in a state senate hearing that he was importing fly ash from other states for his use. A cursory examination of the fly ash from Duke Energy plants indicates that the majority is Class F. It will need the addition of lime (unless blended with regular cement), but concrete manufacturers actually prefer Class F because Class C ash can harden up spontaneously when wet, whereas Class F can be controlled. The carbon removal will require expense and the resulting sale of the fly ash may not always prove profitable. Of note is that Wisconsin recycles on average 85% of the ash and the national average is over 40%. So the economics are likely not prohibitive in all instances. Policy support from Raleigh could help. Any fly ash not going to land fill is a good thing.
May 30, 2014 § Leave a comment
A recent report by Gal Luft suggests many measures for Europe to be less dependent on Russia for their natural gas. An intriguing one is that the International Energy Agency (IEA) creates and manages a strategic reserve of a liquid fuel that could be run in gas turbines in times of shortage. In effect it would be a strategic gas reserve in that it would guard against disruptions in the supply of gas. He suggests the liquid be an alcohol such as methanol.
Short term storage of methanol
The concept of methanol as a storage medium for subsequent combustion to generate electricity is not new. But these have all been for short term storage; the methanol to be consumed at the location it was generated. One elegant concept is tied to the “clean coal” technique of power generation known as Integrated Gasification Combined Cycle (IGCC). Here coal is reacted with water to produce synthesis gas or syngas, which is a mixture of carbon monoxide and hydrogen. Typically this is further “shifted” to produce hydrogen and carbon dioxide. The CO2 is destined to be sequestered in some way and the hydrogen is burned for power.
All coal and nuclear plants face the problem that electricity generated at night is of little value and that during the day there can be peak demand periods in excess of 25% over baseline. Yet they cannot be turned on and off. IGCC plants offer the option to convert much of the syngas in the slack period to methanol. This is a simple chemical process. The crude “fuel grade” methanol could be stored and then burned in the specially modified gas turbines at any time. Peak load periods could be served running the stored methanol. The additional cost to convert syngas to methanol would be about USD 6 per million BTU (MMBTU), not much more than would have been to “shift” to hydrogen. However, this portion of the electricity generation would produce CO2 and in that way vitiate an objective of the IGCC. On the other hand this would be a clean burn not that different from natural gas.
Strategic storage of methanol
A strategic reserve of methanol in Europe, as suggested by Luft, would have somewhat different economic considerations than the example given above. In the case of the IGCC the plant would only have to consider the cost of production, not the market price. Also, they were using the higher cost fuel only during peak periods, when the electricity sales prices are high and can sustain a somewhat costlier fuel.
A strategic methanol reserve in Europe would have the following characteristics. The methanol could be raw methanol straight out of the reactor with impurities such as DME. The market price for methanol could be expected to be in the neighborhood of USD 25 per MMBTU. The cost would be lower for an impure product, likely discounting USD 4. This would compare against a nominal natural gas price of around USD 10 per MMBTU. But two other considerations could narrow the gap. Strategic reserves are owned by country governments. These entities could collectively own methanol production facilities that then delivered the fuel on a cost plus basis to each reserve. With USD 4 natural gas, this cost plus number could be expected to be in the vicinity of USD 14. It would be even lower when sourced from Qatar or Iran. The price on release could depend upon the situation. In any case releases would take place only in the event of a severe dip in supply, politically or otherwise driven. In that situation the actual market price would be higher than the nominal USD 10, thus narrowing the gap. Besides, the national energy security benefit and the correlated issues of keeping the traditional suppliers such as Russia in line, have value.
Having the IEA take the lead on a strategic gas reserve has precedent. All 28 member countries of the IEA are required by agreement to hold in reserve oil to the tune of 90 days of consumption in the previous year. Net exporting nations such as Norway are exempt from the requirement. Some countries by treaty support each other, such as the US commitment to support Israel with the US Strategic Petroleum Reserve (SPR). The term “petroleum” is interesting because only oil is being stored and yet the term technically applies to all hydrocarbons ranging from oil to natural gas liquids (NGL’s) to methane. This is because the foregoing is part of a continuum in the conversion of organic matter to hydrocarbons. This is why one finds gas associated with oil (much of it being logistically stranded and hence flared) and liquids associated with gas. In the parlance, though, petroleum has become synonymous with oil. This does not prevent oil import/export statistics from counting NGL’s in the figures!
As we have discussed elsewhere, the concept of the SPR for the US is less compelling now. Domestic production is on a rapid rise and new shale oil wells can be drilled and produced in a matter of weeks. In a sense, the shale reservoirs are our reserve. Consequently, the US could offer arrangements to other countries similar to that with Israel. India is a possibility; their current reserve covers only two weeks of consumption. The US has a diplomatic hole to dig out of with the presumed new Prime Minister, having denied him a visa some time back. This could help.
A strategic reserve to guard against gas supply disruptions in Europe certainly has merit. Methanol appears to be the most viable fluid to keep in the reserve. While the storage mechanism is very straightforward compared to storing oil, the economics need to be worked out considering in particular the externalities.
April 21, 2014 § 4 Comments
In Vikram Rao’s March 31st post entitled “Bear Trap” he examines the potential influence of the U.S. over geopolitics in Eastern Europe if the U.S. were to leverage its Strategic Petroleum Reserve or theoretical LNG exports. If reducing Eastern Europe’s dependence on Russian gas is the objective, then it is worth considering the possibility of developing American-style shale gas and oil production in Poland and Ukraine, particularly as doing so could represent an opportunity to export American equipment, technology and know-how while simultaneously pursuing geopolitical objectives.
Both Poland and Ukraine have significant recoverable shale resources: Poland has 148 trillion cubic feet of shale gas and 1.8 billion barrels of shale oil, while Ukraine has 128 trillion cubic feet of shale gas and 1.2 billion barrels of shale oil (for frame of reference, this gives each country about 11-15% of U.S. shale gas reserves, and about 2-4% of U.S. shale oil reserves). Domestic shale gas would provide Ukraine with 65 years’ worth and Poland with over 250 years’ worth of gas at their current rates of consumption. This is a significant amount given that two-thirds’ of Ukraine’s consumed gas and about half of Poland’s consumed gas is imported from Russia.
At the recent American Association of Petroleum Geologists annual conference, I had the opportunity to discuss shale drilling and fracking (i.e. hydraulic fracturing) in Eastern Europe with members of the Polish Geological Institute. To date, about 60 wells have been drilled in Poland, about 20 of which have been fracked. All of these wells have been exploration wells, meaning that no gas is currently being produced commercially from shale reservoirs.
Though Poland has had some success exploring along the Baltic coast, results to date have mostly been disappointing. Companies attempting to hydraulically fracture shale reservoirs in Poland have not had the same success as they have had in the U.S. The most obvious reason why not is that the geology in Poland is simply more complicated; reservoirs are typically 3-5 km (~2-3 miles) deep rather than the 1-3 km depth of U.S. shale beds such as the Permian basin in west Texas and the Marcellus in Pennsylvania. The Polish basins are not only deeper, but they are also thinner, with pay zones often no more than 10 meters thick, as compared to the 50 meters or more that is often be found in U.S. shale basins.
As with most of Europe but unlike North America, mineral rights in Poland and Ukraine are by default owned by the state rather than the land owner. In Europe when farmland is drilled and gas is produced, instead of farmers getting royalty payments and local municipalities getting increased budgets, regional or federal bureaucrats would manage the royalty income from the energy companies. Such a structure is less conducive to farmers and communities inviting in drilling and production operations as happens in parts of the U.S. Though this appears to be an impediment to scaled shale gas production, there are other incentives that could mitigate the lack of mineral rights. For one, politicians in Poland are primarily interested in job creation (in this way they have a lot in common with our local politicians), and much influence in Eastern Europe is local in nature – a land owner whose land is drilled on will no doubt be able to secure good jobs for his extended family and friends given all of the construction, transportation, and service work required to drill and produce gas from the land. Though the state owns mineral rights, land lease agreements would still be required to drill and travel on private land, and so payments can be arranged through these agreements in lieu of America-style mineral leases. Also, a member of the Polish Geological Institute advised me not to underestimate the seriousness with which Poles take energy security and the collective desire to find a way to produce their own gas in order to reduce reliance on Russia. Here in the U.S. we talk about energy security as an abstract concept, but in Eastern Europe energy security is personal.
What seems to currently be lacking most in Eastern European shale gas exploration drilling is the intuition around how to best drill and complete the wells. So far, replicating American wells has not worked, but then again it took many years to improve U.S. shale drilling and fracking to the point of economic viability, and the process is far from perfected. Optimizing well drilling and completion of shale reservoirs is a process of trial and error that has not had a chance to play out yet in Eastern Europe.
Even if a drilling company cracks the code of Eastern European shale, Russia will still be able to influence whether commercially viable quantities are ever produced. Russia can easily drop gas prices below the economic break-even point for domestic producers and, if need be, is probably patient enough to do so for as long as it takes for the international oil companies to lose interest. It is also conceivable (or in a more cynical perspective, likely) that Russia could make life hard for any energy or oilfield services company involved in the production of European shale gas who also has ongoing business in Russia’s vast oil & gas sector, though this will certainly not deter small players who have no active business in Russia.
Given a concerted effort by Poland or Ukraine, it is only a matter of time, effort, money and thought before the drilling and oilfield services companies figure out the right combination of geological analysis, drilling, and well completion techniques required to economically produce gas from Eastern European shale. But that is a lot of “ifs”, and so there is no guarantee that Poland or Ukraine will ever produce geopolitically meaningful quantities of domestic gas.
Daniel Kauffman, President of TerraCel Energy