Tech Talk - Natural Gas, China and Russia in the post-Crimea time.

The recent takeover of Crimea by Russia has given China a strengthened hand as it continues to negotiate with Gazprom over the supplies of natural gas for the next few years.

It was not that long ago that Gazprom was riding high around the world, as it supplied large quantities of its own and Turkmen gas to Europe, and was negotiating to sell more into China and Asia in general. Then Turkmenistan and China arranged their own deal, and with the construction of a direct pipeline between the two countries, suddenly the market was no longer running entirely Gazprom’s way. They could no longer mandate that Turkmenistan take the price that they offered at the time that Russia controlled all the pipelines that carried the gas to market. And with that change, and the changing natural gas market, so Gazprom’s fortunes have started to teeter.

At the same time the anticipated Russian market in the United States, which would have been supplied from newly developed Russian Artic reserves such as those in the Shtokman field are no longer needed, as the American shale gases have come onto the market in increasing quantities. The world has, in short, become a somewhat less favorable place for Gazprom and the Chinese have hesitated to commit to a further order of natural gas, in part because they anticipate getting a better deal for the fuel than Gazprom would like them to pay.

Russia would like, and is anticipating, that the deal for some 38 billion cubic meters/year of natural gas, starting in 2018 will be signed when President Putin visits China in May. (In context Russia, which supplies about 26% of European natural gas, sends them around 162 bcm per year). Negotiations over the sale of the gas have dragged on for years, having first started in 2004 but the major disagreement continues to be over price. At a time when Norway is seeing a peak in production and Qatar is moving more of its sales to Asia, Russia had seen an increase in European sales, and has been able to move that gas at a price of $387 per 1,000 cubic meters (or $10.54 per kcf/MMBtu. The price of such gas in the US is quite a bit cheaper.

Figure 1. Natural gas prices in the United States. (EIA )

Russia would like to get a price of around $400 per kcm ($10.89 per kcf) with the slight extra going to pay for the pipeline and delivery costs. Whether the two countries can come to an agreement on the price may well now depend on how vulnerable Russia really is to any pressure on its markets from other sources of natural gas. Japan, for example, is now considering re-opening its nuclear power stations, as the costs for imported fuel are having significant consequences on their attempts at economic growth.

Similarly there is talk that the United States may become a significant player on the world stage by exporting LNG as it moves into greater surplus at home, thereby providing another threat to Russian sales. Part of the problem with that idea comes from the costs of producing the gas, relative to the existing price being obtained for it, and part on the amount of natural gas viably available. Consider that, at present, some of the earlier shale gas fields, such as the Barnett, Fayetteville and Haynesville are showing signs of having peaked.

Figure 2. Monthly natural gas production from shale fields (EIA)

While production from the Marcellus continues to rise, there is some question as to whether the Eagle Ford is reaching peak production although that discussion, at the moment relates more to oil production. However given that it is the liquid portion of the production that is the more profitable this still drives the question.

And in this regard, the rising costs of wells, against the more difficult to assure profits is beginning to have an impact on the willingness of companies in the United States to invest the large quantities of capital into new wells that is needed to sustain and grow production. A recent article in Rigzone took note that the major oil companies are rethinking their strategies of investment, with some reorganization of their plans in particular for investment in shale fields. This raises a question for the author:

Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?

Before investors put up the money for new LNG plants they need to be assured that there will be a financial return for that investment. Given that it takes time for such a market to evolve, and given the need that Russia has to sustain its market and potentially to increase it, the volumes that the US might put into play are likely to be small, with little other than political impact likely.

If Russia recognizes this, and feels relatively confident that Europe must continue to buy natural gas from Gazprom, particularly with the current move by Europe away from other sources of fuel such as coal, then they are likely to be more resistant to bringing the price down for their Chinese customers. On the other hand if China thinks that it might be able to get a better deal from Iran, were sanctions to ease, or from other MENA countries, then – thinking perhaps that Russia needs the sale more – they might toughen their position and the price debate may continue.

It will be interesting to see if it resolves within the next few weeks, and if so, at what a price.

Tech Talk - The IEA World Energy Outlook

It is the time of year again that different folk stare into their own versions of a crystal ball and project how much energy the world will need in the future, and where they think that it will come from. It is interesting to look at these various predictions as the global supply picture morphs under a changing reality.

One of the changes in reality that is likely to have significant impact in the near-term is the flow in the Alyeska pipeline. Long-time concerns over the decline in flow and the effect that heat loss has on the contents is leading to new work to change the pipe dynamics and possibly to remove the water before it is pumped, lowering the temperatures at which the line currently has to be maintained.

Figure 1. Historic and Projected flows through the Alaskan pipeline (Alyseka)

The precipitation of ice and water from the oil, within the pipeline will otherwise reach a point that flow will stop – potentially at around 300 kbd, at a date not too far into the future.

In their annual World Energy Outlook, the IEA continue to see, overall, a gain in US oil production through 2025, largely coming through the light tight oil of the sort being produced from North Dakota and West Texas.

Figure 2. IEA projections for global oil production growth in the years to 2035. (IEA)

However in the following years , out to 2035, that supply also declines so that by 2035 the US will likely be in the same sort of supply situation, relying heavily on imports, that it is today.

The IEA make the point that the only longer term places that can be relied on are Brazil, with the off-shore fields, and the Middle East. Looking first at Brazil, which continues to have some problems in bringing their fields on-line on-schedule, the IEA anticipates that the major production growth is likely to be in the next ten years, but will continue beyond that point.

Figure 3. Brazilian oil production through 2035. (IEA)

Because the IEA foresee that Brazil will continue to supply the largest portion of its energy from hydropower this means that the largest volume of the fuel can be exported, where it meets the continually growing demand from the rest of the world.

Figure 4. Anticipates sources of power for electricity generation in 2035 (IEA)

At the same time the IEA anticipate that primary energy demand will still focus heavily on fossil fuel sources through 2035, with renewable energy only slowly nibbling away at the totals so that, by 2035 fossil fuel will have dropped from contributing the current 82% down to 75% of the larger total.

Figure 5. Anticipated changes in the sources of primary global energy through 2035. (IEA)

Although, by that time the IEA foresee a change not only in the places where demand is highest, but also in the relative rankings. The major finding in this regard that they draw attention to is the anticipated greater growth rates in India than in China, as time passes.

Figure 6. Changed picture of global energy demand in the year 2035 (IEA)

Other than projecting the growth in demand there is the need to anticipate where the supply will come from, and in this regard the IEA projects that the largest growth will come from natural gas (Figure 5), although crude oil is still anticipated to grow, with refinery capacity increasing to about 104 mbd.

It is interesting that the IEA projections for oil production growth hang most heavily on increased production from the Middle East. It requires very little glance into their crystal ball to assume that this is likely based on the increased production from Iraq, an assumption that was, last year, a largely common assumption to all future projections. Unfortunately for those earlier projections in the interim the initial Iraqi targets have been cut back, with current targets being reduced below the “best case” scenario that the IEA had projected in their review of the country.

Taken with the possibility of a significant and sudden decline in production from Alaska, and the likelihood that the rate of drilling in the Bakken will decline, as prospects become more uneconomic suggests that it will be difficult to sustain the levels of crude output that the IEA are anticipating can be made available to meet their projected needs.

By the same token the growth in the global demand for natural gas is predicated on the reserves uncovered in the United States being exported, as needed, to the rest of the world. It is, however, also predicated on the price of natural gas remaining relatively stable in terms of current costs.

Figure 7. Anticipated components of the costs of US LNG when shipped to either Asia or Europe (IEA)

The underlying flaw in that assumption is that the costs of purchasing the natural gas in the United States are now starting to rise to a more realistic level relative to the costs of production from tight shales. This week's OGJ, for example has noted the EIA Short Term Energy and Winter Fuels outlook that notes that prices are expected to rise 13% this winter over last (on constant demand) to $3.62 per kcf. Given that the EIA is expecting the price to inch upwards towards $5.00 per kcf over the next year this makes the IEA report appear a little over-optimistic on costs and hence market share.

Figure 8. Natural Gas Prices in the United States (EIA)

This is likely to be particularly true as some of the older gas fields, such as the Haynesville, appear to be in decline even at prices in the $4 - $5 per kcf range.

Figure 9. Natural Gas Production from the Haynesville Shale (OGJ )

Increasing the price of natural gas will reduce its competitive advantage over coal and in consequence I would anticipate that power generating companies will continue to build boilers that can handle both coal and natural gas, and that the longer-term continued switch to natural gas will become more of an economic choice dependent on how much LNG finally comes onto the market from the United States and at what price. I am not convinced that this will be quite the bargain and cornucopia that it is anticipated to become. In other words I still find the IEA view of the future to be a somewhat optimistic one, given the realities that are now unfolding before us.

OGPSS - Global oil demand and Iranian production

One of the headlines this week has come from the IEA Report that suggests that the United States will be the top global oil producer in five years. Yet back in DeSoto Parish in Louisiana where the Haynesville Shale discovery in 2008 started the bonanza, revenues are now falling and school board budgets are being tightened as the end of the glory days are now beginning to appear.

Just this week Aubrey McClendon has said that Chesapeake’s prospects for oil in Ohio, where Chesapeake had high hopes for the Utica Shale, are now dim. It is easy to look at one of the large maps that the Oil and Gas Journal include in their print editions, showing all the shale deposits in the United States, and to be carried away (as the IEA apparently are) with the vast acreage that is shaded on the map. Unfortunately, as we are seeing, reality tells another story. The size of the resources have been measured in the past, and with the best plays being given preference, the recognition of decline rates, and unprofitable wells have not yet been given the prominence in the popular press that they will ultimately draw.

Figure 1. Shale Plays and Basins in the United States (Oil and Gas Journal)

It seems unrealistic to anticipate the levels of production that are now being projected for future North American production of oil. But, nevertheless, these do tend to crowd other stories on the subject out of the spotlight. And further, if the predictions for American production gains, even in the short term, turn out to be optimistic, then the impacts may be more exaggerated than is currently appreciated. Consider that OPEC now expect that North America will continue to provide the greatest y-o-y increase in supply over other nations, and there are, in fact, very few other nations that will be contributing that much more in the next year.

Figure 2. Non-OPEC supply growth expressed as a year on year change. (OPEC November MOMR)

The MOMR notes that UK oil production has fallen below 1 mbd, for the first time since 1977, while Norway’s production has fallen to levels not seen since 1990. These numbers are part of an overall revision of non-OPEC production for 2013, which OPEC now sees as coming in, as follows.

Figure 3. OPEC projections of non-OPEC production for 2013. (OPEC November MOMR)

In regard to OPEC production, the MOMR has, again, two tables for their production, with the first showing that based on secondary sources.

Figure 4. OPEC production based on other sources ((OPEC November MOMR).

The tables show that Iranian oil production continues to decline, by around 47 kbd from September to October. Yet other sources are now reporting that both China and South Korea may have been helping Iran increase oil exports. As a result production may have increased 70 kbd, instead of declining, though the overall volume remains at around 2.7 mbd, of which exports rose from 1 mbd to 1.43 mbd.

When the “as reported directly” table is compared, Iran is shown to be still producing at around 3.7 mbd.

Figure 5. OPEC production based on direct communication with the producing country ((OPEC November MOMR).

Within Iran the government has partially reduced the subsidies that it was providing for gasoline, which initially reduced demand by about 50 tb/d, and flattening internal demand. But, as we enter the colder months OPEC is estimating that demand will again start to rise.

Concurrently Turkmenistan has stopped exporting natural gas to Iran. Normally Iran would increase imports, over the winter months to around 1 billion cu.ft/day (bcf/d), although this import is partly for geographic reasons, and Iran has, in the past, exported about 80% of the equivalent volume to Turkey. Iran has, apparently, suggested that Turkmenistan increase the delivery to 1.4 bcf/d, but since Turkmenistan can now get a good price for its gas from China, there is more of a debate this year over price, without agreement at the moment. Iran also swops around 35 mcf/d of natural gas with Armenia, in return for electric power.

As a way to try and work around the current sanctions, Iran has been changing to a scenario where it can move more of its oil using its own tankers. The country had been storing millions of barrels in part of this fleet, but that volume is being sold so that the vessels can, instead, haul oil. And there is the possibility that the insurance on these vessels has been “fiddled” to get around the burden imposed by sanctions.

Internally the sanctions are having considerable effect.

Although the government maintains that the official inflation rate is 25 percent, . . . with some analysts claiming that actual figures are double the government rate. In addition, unemployment has soared, with estimates stating that between 500,000 and 800,000 Iranians have lost their jobs. . . . . ."Business is drying up, industry is collapsing. There's zero investment," said an Iranian businessman in September. . . . .the government has attempted to shield the lower classes by offering them cash handouts and subsidizing certain imported staple goods, making them relatively affordable for poorer segments of the population. But even these efforts have had a limited effect, as the price of goods such as Barbari bread went from 1,000 rials to 5,000 rials last week.

There are even suggestions that the economy could “essentially explode” by next spring. On the other hand there are ways of getting around sanctions, and these may allow the crisis to continue to simmer for some time.

All of would suggest that exports of Iranian oil will not be easily available for some time, although, with a new regime in China their commitment to maintaining current levels of trade is now not clear. China will open two new refineries one for 240 kbd in Quanzhou that is scheduled to start next June, and one for 300 kbd that is to be located in Zhanjiang, with oil for the latter anticipated to come from Kuwait. Nevertheless it may be that China, which is currently taking about half the Iranian exports might find it possible to accommodate more.

OGPSS - The quiet steps of a Geothermal movement

The election is now less than a week away, with two entirely different paths possible for our future as we move past the election into next year. The two approaches to energy are particularly different, but it is pointless to do any further comparison, since the airwaves have (on the rare occasion that these differences are explored) discussed these from all points on the spectrum. But nevertheless it gives an occasion to step aside from Iran, for a week, and to draw your attention to something you may have missed in all this debate, and yet is starting to happen on University campuses that are scrambling to meet that ever rising fuel bill.

In the current debate both sides seem to anticipate that the energy future is rosy. As an illustration, I was struck by a comment just this last week:

"Peak oilers have become almost extinct, destroyed by the arrival of new technologies with the U.S. leading the oil supply change," said David Hufton of oil brokerage PVM.

And yet, in the same week I received another newsletter from Go Haynesville Shale predicting (from Seeking Alpha) that 2013 will see the decline in Hanesville production.

Figure 1. Production from the Haynesville Shale in Louisiana (Go Haynesville Shale )

Now there are a variety of reasons for the decline, a significant one being that the number of wells being drilled has fallen dramatically, as the article recognizes. But that is itself, in part, a recognition of the current economics of the business. I had a discussion, just this past week, with the daughter of an investor who had “lost his shirt” over a natural gas well investment. The difference between the hype and the reality is disturbing, and does not bode well for a stable future. Which poses the question as to what the reality of that future might be?

I live in Missouri, and a number of years ago colleagues of mine evaluated the potential benefits of renewable energy and were left severely unimpressed with the potential for wind and solar in this state. At the time I was not sure what the answer for our state was.

The campus where I worked until I retired, (Missouri University of Science and Technology – the new UMR) had been quite revolutionary some decades ago in starting to burn wood with coal, both as a way of controlling emissions and costs. Now those benefits were disappearing and the campus faced the prospect of finding about $25 million for a new boiler, at a time when state funds are not likely to be available, and which philanthropist wants to fund a boiler? So the campus had to be creative. And it was!

Figure 2. Old Campus Power Plant - the question of what to do with the stacks is unresolved.

Starting in the summer of 2010 the campus proposed the use of a ground-source heat pump system as a method of using the Geothermal potential under the campus to lower the overall operating costs of generating power, while at the same time addressing issues regarding the generation of carbon dioxide, and the use of large volumes of water that are one of the costs of conventional coal-fired boiler use.

The initial proposal was approved in remarkable time and over the past summer drilling crews moved in for the initial drilling of the wells. Unfortunately (but realistically) the greatest amount of open space around campus that can be used are the parking lots. And so s number of drilling rigs appeared as the students left for the summer, and proceeded to drill a series of roughly 600 wells, each around 400 ft deep. The last was completed last month, and the wells were then lined with piping and are currently being connected into a triad of networks.

Figure 3. Simplified illustration of the geothermal circuit.

Basically the system works on the idea that the ground, in depth, is at a relatively constant temperature. (For those of us who have mined in depth the old rule of thumb in the Northern UK was 60 deg at 60 ft and 1 degree rise per 60 ft thereafter – but the geothermal gradient varies around the world). Given this relatively consistent temperature, in winter the cool water (the blue line) can be pumped underground, heated and returned through the red line, from which it passes through a heat exchanger system that provides heat to the campus, while then being returned via the blue line to repeat the process.

In the summer the flow is reversed. The hot water from the heat exchanger/chiller is returned to the wells through the red lines, releasing the heat into the ground and cooling before it returns back to the surface through the blue line, and into the chiller/heat exchanger to provide a cooling source for the campus.

Current estimates are that the initial costs (paid for with a bond issue) will be no more than the cost of that boiler (which wasn’t going to be funded, yet was needed), but that the campus will save, in the beginning, some $1 million in energy costs (the remaining energy will be supplied with natural gas and the boilers will be retired in 2014) and this will service the bond. The funds only allow some 60% of the campus to be initially served, through three separate plants that are set around the campus. In time, as savings mount, it is likely that other buildings will be brought into the loop (though some have sufficiently antiquated heating and cooling systems that the entire building will need renovation first.

Over the lifetime of the system (and there is not a lot of fragile equipment in the loop, so this may be more than 50-years) energy savings are likely to rise to more than $3 million a year, as the energy crisis that we are currently pretending isn’t coming finally comes to pass.

Given the benefits that the system will develop it is not surprising that MS&T are not alone in this approach. In fact they learned of the concept at the time that Ball State was beginning their project. That project has just been dedicated and anticipates, being larger than ours, that it will save that campus around $2 million a year. It also includes some 3,600 wells by the time that the second phase of the program is completed.

The idea is beginning to catch on, and there are a small but growing number of campuses now that are in the throes of the same type of effort, though in each case tailored to the individual needs of the different campuses. Hampton University in Virginia is heating their Multi-Purpose Building, Indiana Tech has restored and powered a Civil War era building, Montana Tech will use the heat from mine waters underneath the campus. In Boise, ID the ground water temperature is a little higher (around 170 degrees) and the city has used geothermal energy since 1983, and now Boise State is joining in with its own plant. As with the Montana project, so the program at New Mexico Tech has also been funded as part of the Recovery Act. Some of the potential benefits of that program have been described by the Department of Energy. However that presentation also illustrates the transience of the funding opportunity.

Figure 4. The budget for the Geothermal Technologies Program (DOE)

Given that drop in funding, it is yet still possible, given the savings projected not only here but elsewhere, that this technology may still catch on and become more widely adopted. I’ll keep you posted (among other things with more technical details).

OGPSS - Natural gas production, as shale gas arrives

The natural gas industry in the United States has undergone significant changes in the last twenty years. As I noted last time, until 1993 the industry was beset by regulation that controlled both price and flows. With the removal of those regulations the industry was able to make considerable strides to increase market share. As it became able to do so, the problems perceived from the burning of coal in particular as a power plant fuel, led to moves to increase the amount of electricity that is produced using natural gas. By 2009 the installed capacity to generate electricity included 34% that could be supplied from natural gas.

Sources for installed electricity generating power 2009 (Newell EIA )

The EIA further anticipate that over the next 25 years that natural gas will continue to dominate new plant construction, comprising about 60% of the 223 gigawatts anticipated, with wind, at 11% coming second, while other renewable sources (which include a number of varieties) has about 12% of the growth. Now that doesn’t mean that the US actually produces 34% of its power from natural gas. In fact it is down at around a quarter of the current total, the difference being that companies prefer to use nuclear and coal -fired stations for their base load, and use natural gas more to meet variations in the demand cycle.

Because of this increased use US natural gas consumption has been rising in the past few years.

U.S. natural gas consumption over the past decade (EIA) Note that 68 bcf/day is equivalent to 24.8 Tcf per year.

The total withdrawals of natural gas from domestic sources in 2009 totaled 28 trillion cubic feet (Tcf) of which 78% came from domestic gas wells, and 22% from oil wells. 13% of the 2009 total came from shale gas wells, and 8% from coal beds. Of the gas produced some 14% was re-injected to help maintain pressure in producing wells, and about 1% was flared. 3% of the volume was of non-hydrocarbon gases. The United States also imports around 11% of the gas that is consumed.

I am indebted to Gail Tverberg for the following plot that shows the longer trend in production, as well as the price (note that the difference in production volumes, relative to my numbers above, is that the figure below is just for natural gas wells).

Production of natural gas from US wells, and price of that NG. (Gail Tverberg)

Natural gas production by State, which I previously just ranked, shows that Texas continues to be primary, but that the combination of states outside of the big 5 is rising steadily.

Production of natural gas from different states (source EIA ).

It is worth noting that New Mexico, Oklahoma, Wyoming and the Federal offshore Gulf of Mexico (GOM) are declining while Louisiana is showing the greatest growth. In fact it is so great that Cheniere Energy will convert their LNG plant in the state so that it will be able to export Liquefied Natural Gas (LNG) rather than just store and re-gasify supplies after they have been imported. The hope is to have it on line and allowing the export of LNG by 2015. That growth in production has come largely from the development of the natural gas found in the Haynesville shale.

Location of the Haynesville gas shale drilling (Geology.com )

It was in February of this year that the Haynesville took over the lead in gas production from the Barnett Shale in Texas producing 5.5 bcf/day to the Barnett’s 5.25 bcf. The field has more than a thousand wells in production, with around 2,000 permitted, and over 500 having been drilled but not completed. Part of the more rapid success of the Haynesville, the first successful well was only 3 years ago, has been because the gas could be fed more easily into existing pipelines than the case in Texas. The well location lies south of Shreveport.

The EIA plot of drilling activity in the gas shales shows the growing popularity of the Eagle Ford and Marcellus, presaging future production increases and a challenge to Louisiana.

Drilling activity in the gas shales of the United States (Smith International via EIA )

The changing emphasis also is an indicator that the day of the Barnett shale appears to now be passing into afternoon.

Production from the different gas shales (EIA Newell )

One of the big questions, however, with gas shale production relates to how long they will continue to produce if the production decline rates fall at levels of 85% per annum that have been reported in the past. The long term production from these fields also depends on their profitability, and in this regard it is interesting to see how the EIA sees the price of natural gas moving over the course of the next 25 years.

EIA price projections for natural gas made in the past three years (EIA )

One question, since this price ties in to the volumes of gas that will be produced, continues to lie in the costs required to produce and transport the gas. If that remains below the selling price, and the new estimate price would appear to keep that distinction for the full 25 years, then the amount of gas produced will be much less. The EIA appear to hang their hat on long term sustained production from these wells. That may not be as true for the tighter shale rock than it is for more conventional gas reservoirs of the country.

The EIA has just noted, in their Energy Today post that stripper gas wells produce 11% of the volume of natural gas produced in the United States.

Individual natural gas stripper wells produce no more than about 90 thousand cubic feet of natural gas-equivalent per day over a twelve-month period (some wells also produce natural gas liquids), but because there are so many (nearly 340,000) they collectively account for a significant portion the Nation's total natural gas production—2,912 billion cubic feet, or over 11% in 2009.

Stripper well numbers and contribution to US natural gas production (EIA)

To put the percentage in context, one should also look at the volumes of natural gas that are being consumed and produced in the United States. Consumption over the past decade simplistically declined until 2006, whereafter it has increased, though the EIA now anticipate that it will now stabilize.

The 11% of volume thus translates to about 2 Tcf per year. They are most commonly found in Appalachia, Texas and Oklahoma. The roughly 300,000 stripper gas well total should be put in the context of a total of around 493,000 total gas wells in the USA in 2009.

There is likely thus to be some engagement in terms of the price of the product and thus volumes sold, between imported LNG, domestic conventional gas and shale gas. It will be interesting to see how that develops in the near future.

OGPSS - The new EIA Shale gas report

I had intended starting my country-by-country more detailed analysis this week, but with the publishing of the EIA compendium on world gas shale deposits, and a little controversy I got into in comments elsewhere, I thought it worthwhile spending a post looking at the global prospects for gas shale. I am indebted to Art Berman for first bringing some of the problems to my attention, though I have since looked into the issue sufficiently to draw my own opinions, which this article reflects.

The EIA document (actually prepared on their behalf by ARI) begins by noting the importance of this new resource to the US Energy picture:

The development of shale gas plays has become a “game changer” for the U.S. natural gas market. The proliferation of activity into new shale plays has increased shale gas production in the United States from 0.39 trillion cubic feet in 2000 to 4.87 trillion cubic feet (tcf) in 2010, or 23 percent of U.S. dry gas production. Shale gas reserves have increased to about 60.6 trillion cubic feet by year-end 2009, when they comprised about 21 percent of overall U.S. natural gas reserves, now at the highest level since 1971.

Development of US shale deposits began to be aggressive around 2005, and “technically recoverable” gas resources in the USA are now considered to be 862 Tcf. With this discovery of this potential future domestic supply, it became wise to see what the equivalent potential was elsewhere, and thus the report which looked at some 32 countries, 48 shale basins, and 70 formations. The assessed basins (in red with an estimate, in yellow without) are shown in the map below.

Gas Shale resources evaluated by the EIA

Combined, the total resource base is then assessed to be 6,622 Tcf. Now it is important to draw a distinction at this point, because this is a resource. There is a considerable difference between a resource, which is something out there of value that may or may not be economic to develop, and a reserve, which is that fraction of the resource that is considered viable to develop. In the case of the USA for example, out of the 862 Tcf that makes up the resource, only 60 Tcf (6.9%) is considered to be viable as an addition to the US reserves.

Further (and a point I will get to later) gas from shale is somewhat more expensive to produce, relative to more conventional natural gas deposits. So, when the new volumes developed are put in context of the total natural gas resource available, while gas shales now provide a gain of 40% in the total volume of gas technically available, it may well be that the larger more conventionally available natural gas volumes may be less expensive to produce, and so will be developed preferentially in the next few years.

On the other hand, a domestically available reserve that does not require a nation to expend money on foreign fuels can have considerable benefit, even though it may be comparatively expensive. (And that is a judgment that brings in a lot of additional caveats, but it may very well drive development in countries without much other natural resource, and one thinks of countries such as Ukraine and Poland – where the alternate coal is becoming increasingly politically disfavored). Countries such as Russia and parts of the Middle East, where there are already large reserves of comparatively inexpensive natural gas were not considered in the study – so it is possible that the total volumes available long-term may be understated.

To derive the “technically recoverable” volumes the consultants looked at the volumes of free and absorbed gas available, after having decided the size of the shale deposit, and then used their best judgment as to how much of this could likely be recovered. In general they though it technically possible to recover between 20 and 30 percent, with some higher and some lower estimates within an additional 5%. They did not consider offshore deposits, nor critically, did they consider production costs or accessibility.

‘Free gas’ is gas that is trapped in the pore spaces of the shale. Free gas can be the dominant source of natural gas for the deeper shales.

‘Adsorbed gas’ is gas that adheres to the surface of the shale, primarily the organic matter of the shale, due to the forces of the chemical bonds in both the substrate and the gas that cause them to attract. Adsorbed gas can be the dominant source of natural gas for the shallower and higher organically rich shales.

I am not going to go into the details of the report as it pertains to individual countries, though this provides the bulk of the information that is provided within it. Rather I am going to include those resource values and the related discussion as I come to discuss the resources available to different countries. But as an illustration that not all the shale is likely to be productive, once could consider, for example, the drilling pattern for the Barnett Shale where most activity is concentrated in the area north of Fort Worth. And there are significant areas with very little activity at all.

Drilling activity in the Barnett shale (EIA)

However I will comment about the immediate significance of the resource, its size, and what I see as the short-term impact that these volumes will have on the global energy market. My sense is that they won’t make that much difference, once the initial hype and gasps over the size of the numbers has passed.

The reason for this is that this new resource is not cheap to develop. The initial cost comes in sinking the well, where once the initial vertical segment has been drilled, the driller must bend or deviate the drill until, when it reaches the formation with the gas in it, it is drilling sensibly horizontally. The driller must then hold the drill in the formation (which may be less than 50 ft thick) while the bit opens a hole that runs out perhaps two miles or more. The ability to sense where the bit is and to guide it along that path is a complex, expensive process, and you can’t take someone off the street and have them run a good well in a week. Over time there the number of qualified drillers who can do this has grown, so that in the week of April 8, Baker Hughes reports that of the 1782 rigs drilling in the USA some 50% were drilling for gas, and of the total 57% were drilling horizontal wells. It has taken some time for that level of expertise to develop.

Yet even with the right rig and crew, success is not assured, or even permission to drill the wells. One has also to get the right permits, and the right prospect. And here one can look to the map of the current producing wells in the Marcellus Shale in the Eastern U.S. to illustrate the point.

Wells in the Marcellus Shale (EIA )

You can see that the activity has concentrated much more in West Virginia than, say, New York State. This is partially due to the different compositions and inclinations of the state legislature in each state.

But even with the rigs, the crews the political support, and a well in a decent spot in the formation, success is not assured, or even the most likely outcome, because of the nature of the host rock. The major concern that I have had with the expectations regarding shale gas, relates to the rock in which it is found. Most natural gas deposits are found in relatively permeable rock, so that it is relatively easy for the gas not intersected by the well or the fractures to travel through the rock to those free spaces, and thus out of the well. The permeability of shale is, to be blunt, pathetic. That is, after all, why the expensive fracturing of the well, and the slick-water injection of proppants into those fractures is so critical. But the poor host rock permeability causes a fairly dramatic fall in production from gas shale wells after they are first brought on line. The easily accessible gas close to the fractures and the well makes its way out, and then the rest must struggle through increasingly thick layers of rock to reach the well. As a result there is a dramatic drop in production.

One of the wells that was cited in the comments debate I mentioned at the start of the post was the Day Kimball Hill #A1, which was the highest initial producer that Chesapeake ever drilled, at 12.97 mcf/day when it was brought on line. But:

The Day Kimball Hill #A1 is located in Southeast Tarrant County, Texas, and produced an average of 12.97 million cubic feet of natural gas per day in October 2009. Since shale gas wells decline sharply during the first few years, this Barnett Shale well has seen its production fall to 8.66 million cubic feet in November and 6.79 million in December.

That is a 47% decline in production in 3 months.

It was followed by White South #1H which came in at 17.8 mcf/day, last September. However, because of the low price of NG at the moment, the well has been partially shut-in to produce only 4 mcf/day since. Most shale gas wells don’t produce in this league. There are roughly 15,000 wells in the Barnett, and the wells in Arlington are an exception.

To join (the “monster” wells), a well’s output must average more than 8 million cubic feet of gas per day during its peak month.

Fewer than 1 in 1,000 Barnett wells has attained such a lofty yield for a month, which is enough gas to meet the heating and cooking needs for about 3,300 homes for a year, based on American Gas Association usage data.

While the Barnett Shale underlies more than 20 North Texas counties, the top “sweet spots” are in Tarrant and Johnson counties. All of the 35 biggest wells are in those counties, according to a new report by the Fort Worth-based Powell Barnett Shale Newsletter.

Day Kimball Hill site from Google Earth (Barnett Shale Drilling Activity)

Obviously, if you were a partner in these wells, you made your investment. There is a discussion of well economics which suggests that $5 per kcf is the minimum price (in 2005 costs) at which the wells can make money. But that assumes a 60% decline rate for well production over the first year. But in all the others, even as with these, decline rates from the initial numbers can be dramatically higher. And this is not just true for the Barnett shale . For example there is a report of a decline curve for the Haynesville shale that shows declines of up to 85% in the first year.

Haynesville shale decline curve (Haynesville Shale)

These high decline rates make it more difficult for the well to generate the return on investment that folk expect when they consider only the initial production volume.

The main problem that I see, in the short run, for the average shale gas well is that (as noted above) the producer really needs a price of better than $6 per kcf (and Art would argue higher) to make any money on the well. But there is a globally sufficient supply of natural gas more conventionally obtainable, and increasingly available as LNG at perhaps $4 a kcf delivered into the United States, that it is difficult to see the short-term viability of the industry.

On the other hand, with alternative sources of fuel failing to live up to various promises made for them, it may now be that natural gas is seen as the next hope for broad use vehicular fuel. Legislation has been introduced to encourage this use, and if this becomes more widely adopted then it may be that in this way the market may rise, and prices will hopefully rise with increased demand, to make the shale gas more viable sooner than I think.

Chesapeake on 60 minutes

I had forgotten that there was a story coming up on 60 minutes last night on those folk that had become millionaires from the gas in some of the shales around the country. Fortunately the folks at Go Haynesville Shale have put it up on their front page.

It's worth a visit, and you should also watch the minute of extras in the video above the main story, which shows how those with wealth can make a little more.

Shale, gas and water

This is a short technical note as part of a series that discusses some of the aspects of fossil fuel production. Earlier posts in the series are listed in the column on the right. By the nature of the length of post that I think will hold people's interest, and what I think folk know and want to know, these posts tend to be very simplistic reviews of topics that are often, in detail, much more complex. I am very grateful to those who, in comments, help to illustrate that complexity.

One of the most promising sources of natural gas that has recently started to come into production is that from the shale deposits around the United States. Since it is possible that similar gas or oil-bearing shales occur around the world this provides a new potential source of energy that has some considerable promise, in the short term, for helping to fuel the world.

Shale, as a descriptive term, does not describe just a single rock, however, and there are a large variety of shale types. Consider, if you will, that much of the shale that contains the hydrocarbon started out as the mud at the bottom of a bay, as the algae bloomed, grew, multiplied and died, to be trapped within the mud and gradually buried with it. As the layer was further buried beneath additional layers of material, so the pressure, and increasing heat, gradually turned the oil in the algae into either oil or natural gas. Along the way the mud itself was compressed, largely dewatered, and baked so that it turned into what we now call shale. When these reservoirs are now tapped, they can produce large initial flows of natural gas, for example, in the Haynesville, the Garfield 25 H-1 just started production at some 20 million cu.ft/day at 7,700 psi delivery pressure.

There are other shale types that are found in producing fossil fuels. In the same way that the mud underlay the water where algae grew, it also pervaded the swamps where, during the Carboniferous era, the trees and vegetation grew that, in time, and to a degree under the same type of burial, pressurization and heating, led to the formation of coal seams. The mud underneath that was the soil in which the trees had been growing was also changed, and so it also formed the shale layer that remained under the coal through the eons. (In the North of England we sometimes referred to it as the “seat earth.”)

But while the term shale is used to describe a generic type of rock not all shales are the same, in the same way as not all soils are the same. By geological description the key part of the description lies in the bedded nature of the rock, and its high clay content. But is it the clay part of the content that I want to focus on in this piece.

Geologists are strict with their rules on sedimentary rocks. Sediment is divided by particle size into gravel, sand, silt and clay. Claystone must have at least twice as much clay as silt and no more than 10 percent sand. It can have more sand, up to 50 percent, but that is called a sandy claystone. (See all this in the Sand/Silt/Clay ternary diagram.) What makes a claystone shale is the presence of fissility—it splits in more or less thin layers whereas claystone is massive.

Shale can be fairly hard if it has a silica cement, making it closer to chert, but usually it is soft and easily weathers back into clay. Shale may be hard to find except in roadcuts, unless a harder stone on top of it protects it from erosion.

The reason for stressing the point is that of weatherability, or how the shale holds up in the presence of water. Let me tell a small anecdotal story.

Back some years ago we used to test rock for different companies, and had been sent some samples of a shale, which we were asked to saturate in water before testing. Due to some confusion we did not get that message initially, and the rock sat – as received – over the weekend. First thing Monday we got a frantic call, don’t put the samples in water. Turned out that two different sets of samples had been sent, and the other sample had been immersed in water over the weekend, and when the lab had looked in the bucket that morning, they had found a residual pile of particles as the shale had totally disintegrated in the presence of water. The shale was so sensitive that we ended up doing all the sample prep (cutting, coring, grinding etc) dry to make sure that we could keep the samples intact.

Testing different shale samples for their susceptibility to water attack, their durability if you will, is not that easy. One of the more common tests is known as slake durability, for which there is a standard test protocol. (Free version here. The sensitivity is also perhaps illustrated by the categories into which the results from another one of these tests (the jar slake test) can fall;

Different responses to shale testing in the jar slake test.

The durability tests generally involve the tumbling of ten intact sample pieces of shale in water for ten minutes, oven drying it, and repeating the tumbling and drying. The amount of material retained on a screen afterwards as a percentage defines the durability. But bear in mind that the shale may still have fragmented or softened.

I am putting a little bit of emphasis on how sensitive the shales are, in general, to water, because, when the oil and gas shale reservoirs are developed, the drilling is usually performed with a water-based mud, and the resulting fractures that are driven into the shale to provide pathways for the gas to leave, are created using a water-based frac’ing fluid.

Now there are ways of stopping, at least temporarily, the wetting action of the water on the shale. One way of doing this is by adding more polymers to the water. Particularly at higher concentrations these (which also make the water "slick") can reduce wettability and stop the softening of the shale, but some of that work is still part science and part art. And part of the question is how the shale will behave in the longer term after it has been wetted.

Remember that to get the gas out the fractures through the rock have to be held open, and the way that this is done is to push small particles (called proppant, but similar to sand in nature) into the fracture to hold it open and still give a passage way through the fracture for the gas to get out.

But if the wetted shale along the edges of the fractures does soften with time, then under the pressures of the well, it may deform around the sand particles that are holding the fractures open, and slowly close the fracture, reducing production rate over that anticipated from a fully open fracture, and reducing the potential overall recovery of gas from the well. In that case, in order to sustain production from the well, it will need to be refrac’ed, perhaps more than once.

Horizontal wells and Gas Shales

This post is one in a series, describing some of the ways in which fossil fuels are produced, and in the current part of the series (listed on the right hand side of the site – you should start at the bottom and work up) we are focusing a little more on the procedures that are being used to recover natural gas from formations such as the Barnett, Fayetteville, Marcellus, Haynesville and Woodford shales. In this particular post I am going to concentrate more on the benefits of horizontal drilling through these shale reservoirs, rather than using the more conventional vertical wells that were used historically. This, and the next three posts in the series are likely to be a bit more technically dense than earlier posts but I am trying to illustrate some of the problems of production, and some of the gains that technology is bringing to help solve some of them. And while the reason for the horizontal wells can be simplified in this graph from Chris McGill, there are a lot of other things that have to be considered in deciding whether or not the horizontal well is going to be worth developing.


Comparative production from a vertical and horizontal natural gas well (Chris McGill). Notice the gain in production, but much shorter life of the horizontal well.

To begin with it’s probably best to start with rock pressure. And to explain this I am going to do some simplification, so, as I ask in most of these “techie talks”, to those who do know better please understand that this is trying to explain concepts, but also please do comment on where I may either accidentally or by error, get something wrong. I am also going to repeat some information from earlier posts, since some of you may not have read them.


As we go deeper into the earth, the weight of the ground above us will also increase. For a very simple measure (and to make the illustrations easier to follow) we can assume that this is around a 1 pound per square inch (psi) increase for every foot deeper we go. So if we were, for example, 10,000 ft down then the pressure in the rock due to that weight would, undisturbed, be around 10,000 psi. (This is about 7 times the pressure that you see coming out of a car wash pressure washer for example).

When a oilwell is drilled vertically down into that rock it does not see this pressure, but it does see a part of it. The reason is that the rock on either side of the hole can now expand into the hole, and we’d rather it didn’t. (It’s somewhat as though you step on a rubber eraser – the eraser will bulge out laterally as it compresses vertically under your weight). The resistant pressure in the horizontal direction can be calculated as a function of the vertical pressure through a ratio known as Poisson’s Ratio. Sufficient for our discussion to say that it can have a value of about 0.3. So that if we are 10,000 ft down, then the vertical pressure on the rock will be around 10,000 psi, and the horizontal pressure will be around 3,000 psi. If the well is vertical then the casing for the well may not have to resist pressures of more than the 3,000 psi level.

Now, if instead of just drilling the well vertically I turned and drilled it out horizontally through the rock, then the hole would now have the 10,000 psi squeezing down vertically, and the 3,000 psi coming in from the side. So the first thought that we have is that the casing (the lining that we put into the hole to make sure that it stays open) has to be a bit stronger. Life gets, however, a bit more complicated than that. When you put a hole into ground that is under pressure, the first response of the rock is to try and move the weight of the rock over the hole onto the rock on the sides of the hole. This roughly doubles the pressure that is on that thin layer. Before the hole was put there that particular rock was held in place by the rock around it, and collectively the mass could carry the original pressure. But now there is no rock where the hole is, and thus the confining pressure on the rock there is less. (In technical terms you have shifted the load from a triaxial confinement under 10,000 psi to a uniaxial load of 20,000 psi. if there was no pressure within the well). The result can be that the rock on the sides of the hole crushes under the load. This then puts crushed rock or sand into the hole, and that interferes with lots of things. Now you can possibly stop that by keeping the pressure high in the liquid that you are using inside the hole to get the drilled rock out (the drilling mud), but if you keep that pressure too high, then the oil/gas won’t flow to the well and so you have to drop it down to a certain level by choking the flow out of the well when, after completing the hole, you go back to start production.

Life also gets a bit more complicated in reality, since the presence of the fluid in the rock tends to even out the pressure within it. So that while, relatively close to the surface, and in a dry rock the ratios may be as I gave them earlier, with a fluid saturated rock, and in an over-pressured region, the horizontal pressure can be as high as 80% or more of the vertical value. The values generally get closer to 100% as the wells go even deeper, but that is another story.

So rock pressure is the first problem that you have to deal with. But why do we drill the horizontal holes in the first place, why can’t we just use the old vertical ones. Well the reason is that the old ones didn’t work very well. And to explain that I am gong to try and re-explain an article from Penn State. (then I’ll give the relevant quote).

Shale is a very fine grained rock, and though gas can gather in the small pores of its structure, if the gas is to flow to a well, then it has to migrate through passages that are very narrow, and thus very resistive to that flow. However, as the shale has been formed under geological pressure and over time, the pressures not only compressed it from mud into shale, but they also caused it to fracture. In the Marcellus shale, for example, the cracks that occurred in the shale are roughly vertical, and form two sets that are perpendicular to one another.

The first advantage that a horizontal well has, over a vertical one, is that the well can penetrate a long way through the rock that carries the oil or gas (OG). The amount of OG that comes from the rock is, in part, a function of how long the length of well is in the rock that carries it. So that while a vertical well might produce say 800 bd from a well that goes straight through a 200 ft thick layer of oil-bearing rock, when the well is drilled so that it goes out he equivalent of 4 miles horizontally through the oil-bearing rock, then the production per day may go up to 10,000 barrels. It is not always that easy to find reservoir data from two adjacent wells, one vertical and one horizontal but I found a paper on Natural Gas by Chris McGill, in 2006 from which I took the following graph. (or those who want to see what projections on NG were just those few short years ago – the paper is worth a cautionary read).

Comparative production from a vertical and horizontal natural gas well (Chris McGill).

It is interesting to note (vide the recent controversy over Arthur Berman’s opinions on horizontal well life stability of production), that the Horizontal well here had an operational lifetime of only a year, as opposed to the ten years of the conventional well.

The second advantage relates to the way in which the fractures lie in the rock. Because they are vertical, a vertical well won’t hit very many of them, and so since these fractures provide an easy flow of OG to the well, rather than the difficult path through just the rock, then the well will not show very much production. (And this was the case with many of these shales when they were tested earlier).

However if the well is horizontal (see figure) then the well will intersect many of these fractures and in drawing the fluid from them will also provide an easy path for fluid to ease out of the rock into the fracture paths, so that the entire rock can be more easily drained.

Simplified picture showing two joint sets (the grid) as they could be intersected by a vertical and a horizontal well.

Now in the picture I have shown one set of joints as being bigger than the other. And that is usually the case, because the horizontal pressure, that earlier I had suggested was the same in each direction, actually usually isn’t. The strongest horizontal pressure will tend to close up those fractures that run perpendicular to it, and tend to open the ones that run parallel with it. Thus it helps to know at the level of the shale, what the pressures in the different directions are (those engineering among us generally refer to them as stresses rather than pressures). The best direction to drill is then perpendicular to the maximum horizontal pressure, if we want to take the best advantage of the fractures in the rock. The only problem with this is that it also increases the pressures on the sides of the borehole, so that if we go that way, and the rock is not that strong, then we may be making the borehole stability worse.

But even with a horizontal well the production may not be that great, because the fractures are still relatively narrow, and so flow won’t be that fast. And so there is another tool that can be used, and that is to deliberately put a crack into the rock on the side of the borehole. On a very small scale, if you look at the picture, you can see a shaded zone around the vertical well. If I could make a crack out from the well at that level and grow it out just a short way you can see that it already intersects two of the better joint sets, whereas at the beginning the well didn’t reach any. And if we could do this from the horizontal well and grow that crack out a goodly distance horizontally, then it would intersect a lot of the vertical fractures and production would become high and useful.

There are, however, three snags to forming and growing that crack, all solvable, but all costing additional money. The first is that if we just grow the crack out and then let the weight of the overlying rock close it up again, then we haven’t made a whole lot of difference. So we have to prop the crack open. For this we need to inject relatively fine grained particles (let’s call it sand, though the technical term is proppant) into the crack in enough quantity that it will fill up the crack and hold it open so that it gives an easy path through the rock to the well for the OG. (We won’t go into what a mess pumping sand at more than 10,000 psi makes of the pump – Halliburton gets paid very nicely to fix those problems).

The second snag is that trying to push sand into a thin crack and get it to go very far can be an exercise in futility. Among other things if you are using plain water the sand tends to settle to the bottom rather fast, and if it fills the crack near the well, it then acts as a filter to stop sand going back further into the slot. So now we change the chemistry of the water by adding what are usually known as long-chain polymers. These chemicals thicken the water so that it will (at relatively low chemical percentages) suspend the sand in the fluid. Because these molecules are also slippery (in another variety they are added to the water in crowd control water cannons to produce what is known as Banana Water – since it makes the street too slippery to stand on) they also reduce the friction between the fluid flow and the walls of the crack, and this also helps carry the sand further back into the crack, and gives the slickwater title to the hydrofrac.

The third snag is a bit more technical. You remember that earlier on I talked about the pressure about the hole causing the sides of the horizontal well to crush. Well at the top and bottom of the well instead of the rock seeing this additional crushing pressure, the shifting of the vertical load to the walls of the hole, can mean that the rock will go into tension, where it is much weaker. As a result cracks can appear in the top and bottom of the horizontal hole. Why is this a problem? Because the easy way to cause a fracture to grow is to fill the well with liquid and increase the pressure of the liquid until the rock breaks. (Hence hydraulic fracture or hydrofrac). But if there is a crack there already then just increasing the pressure in the hole causes that crack to grow and it may not be in the direction we want. And so it is time to call in the engineers (who also don’t come cheap) to do the interesting things that cause the crack to grow in the right direction.

The benefits to all this for the Marcellus has been described by Engelder.

"Conservatively, we generally only consider 10 percent of gas in place as a potential resource," said Engelder. "The key, of course, is that the Marcellus is more easily produced by horizontal drilling across fractures, and until recently, gas production companies seemed unaware of the presence of the natural fractures necessary for magnifying the success of horizontal drilling in the Marcellus."

The U.S. currently produces roughly 30 trillion cubic feet of gas a year, and these numbers are dropping. According to Engelder, the technology exists to recover 50 trillion cubic feet of gas from the Marcellus, thus keeping the U.S. production up. If this recovery is realized, the Marcellus reservoir would be considered a Super Giant gas field. . . . . These fractures, referred to as J1 fractures by Engelder and Lash, run as slices from the northeast to the southwest in the Marcellus shale and are fairly close together. While a vertical well may cross one of these fractures and other less productive fractures, a horizontally drilled well aimed to the north northwest will cross a series of very productive J1 fractures.

The article illustrates that concept with a representation of the horizontal well drilled perpendicular to the joints at an outcrop.

Representation of a horizontal well drilled in the Marcellus, shown against the natural fracture pattern (Source AAPG )

The upfront money may give some pause to prospectors. A typical well that drills straight down to a depth of about 2,000 to 3,000 feet costs roughly $800,000.

But in the Marcellus Shale, Range and other companies hope a different kind of drilling might yield better results — one in which a well is dug straight down to depths of about 6,000 feet or more, before making a right angle to drill horizontally into the shale. That kind of well could cost a company $3 million to build, not counting the cost of leasing the land, Engelder said.

The company, in a December financial report, estimated that two horizontal wells are producing roughly 4.6 million cubic feet of gas per day. Tests on an additional three recently completed horizontal wells showed potential for a total of 12.7 million cubic feet of gas per day. Industry experts call those results promising.

The benefits have also been projected here.And while they may be considerable, it is only after the wells are in production, and not only initial flows, but also well lifetimes are established, that the true benefit will become apparent.

But until some solid, repeatable well data emerges, the Haynesville will remain more diamond in the rough than diamond ring. As BMO Capital Markets analyst Dan McSpirit rightly noted in a report last week: "The proof (of Haynesville economics) is in how the wells get drilled and the rates of return such operations yield." He added, "These are early innings. Lasting value creation should be revealed later in the game."

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The costs and estimates of production came from the time that the original post on this topic was written, and costs (as you may have noted from the comments and from other references I have made) can now get as high as $8 million for a horizontal well. But I will come back and write more about penetrations and hydraulic fracture in the next post.