Tech Talk - life gets more difficult at Gazprom

There was a time, not that long ago, when if I was short of a topic for a post, I could Google “Gazprom” and there was sure to be a story out there about another expansion, or take over of a national pipeline – or some other sign of the companies growth and power. But in the natural gas industry there has always been a certain volatility. In the United States Chesapeake, the second-largest natural gas producer in the US, is laying off 800 workers as it completes its plans to re-organize by the end of the month. The price for natural gas is around $3.79 per kcf which still falls below the price required to make many wells in tight shale adequately profitable. I have written about gas price problems a number of times in the past, dating back to at least 2009 and though the price is now up over $1 per kcf from those times, as the recent report in the OGJ noted, Chesapeake had, in estimating returns, anticipated it would be up around $7.21.

Gazprom’s problems however relate more than just to the price of natural gas, and the continuing difficulties in defining future price, although those too still exist. In the agreement that the company signed with China last month, for example, although it says:

All the major terms and conditions of future Russian natural gas supplies to the Chinese market via the eastern route were agreed on, namely, the export volume and starting date, the take-or-pay level, the period of supply buildup, the level of guaranteed payments, the gas delivery point on the border as well as other basic conditions of gas offtake. The price conditions will not be linked to the Henry Hub index.

It turns out that the price has yet to be determined. Gazprom is expected to sell its gas into Europe this winter at around $10.62 per kcf, which is down about 7.5% over last year. Nevertheless the Chinese are hoping to pay no more than $7.10 per kcf. And they have more than a little leverage.

Gazprom had been hoping to market the liquefied natural gas (LNG) from the ExxonMobil fields at Sakhalin Island as well as from their own wells, but that discussion has now fallen through so that this becomes a competitive rather than complimentary source of supply. Concurrently China has just confirmed the increase in purchases of natural gas from Turkmenistan.

Not that many years ago all the exported natural gas from Turkmenistan had to run through Gazprom pipes, and thus the company could charge a hefty premium in carrying the gas to Europe and elsewhere. With the opening of pipelines from Turkmenistan to China, that monopoly disappeared, and now the Chinese have agreed to take some 2.3 trillion cubic feet (Tcf) (65 billion cubic meters) of Turkmen natural gas per year, increasing their take by 882 bcf and requiring an additional pipeline to carry this new volume. Given that the country already supplies over half of Chinese natural gas imports, this will continue to squeeze Gazprom’s ability to control prices in Asia.

This new volume will come from a new field in Turkmenistan, the Galkynysh, which is expected to hold a reserve of 900 Tcf. China is investing $8 billion in the development of the field, and the new pipeline to China.

Figure 1. The location of the Galkynysh field within Turkmenistan (Trend)

And Gazprom’s problems don’t end in Asia. Part of the problem that they ran into at Sakhalin Island is that ExxonMobil is working with Rosneft to build an LNG plant through which to market their product by tanker. This circumvents the pipeline monopoly which has allowed Gazprom to dictate terms in the past. The plant is expected to handle 5 million tons of LNG per year, and is anticipated to come on line in 2018. Initial construction contracts have now been signed.

Roseneft, and Novatek have both now been given permission to export LNG, overturning the Gazprom monopoly, and Novatek has the deposits in the Yamal Peninsula that could be more conveniently marketed to Europe, but with LNG tankers that could also reach Asia and beyond. The natural gas will initially come from the South Tambeyskoye field, which has an anticipated reserve of 17 Tcf, with an expected production of around 1 Tcf per year.

Figure 2. Location of the South Tambeyskoye natural gas field, and the planned site of the LNG plant (Novatek )

The plant will operate three trains, each with a capacity of some 5 – 5.5 mmt. It is perhaps no surprise that China is backing the plan with a 20% investment, for which it anticipates being able to purchase at least 3 million tons of LNG pa. An additional 10% of the funding is likely to come from either Japanese or Indian investors. Total of France also has a 20% investment and presumably will gain a proportionate share of the shipments.

As if these challenges to Gazprom’s dominance were not enough trouble, Gazprom is seeking to have two German companies EON SE and BASF SE pony up another billion dollars because Gazprom has been able to increase the reserves at the Yuzhno-Russkoye field in Siberia.

Figure 3. The Yuzhno-Russkoye gas plant in Siberia that feeds into the Nord Stream pipeline (Nord Stream )

Figure 4. Location of the Yuzhno-Russkoye field (Wikipedia)

And just to rub it in, the European Union is planning on hitting the company with anti-trust charges. Given that the company has been able to dominate natural gas sales into Europe though pipelines, and thus has also been able, in the past, to control prices, this new step could prove expensive to the company, just as it faces greater competition in all its export markets. (This does not even consider the potential for LNG competition out of the United States).

The company is getting its supplies from increasingly expensive locations (hence the need for the cash from the German companies) and the income losses that it has seen in the market due to Turkmen competition are already hurting – but it needs more money if it is to be able to keep up its market share.

Before leaving there is an intriguing graph that Ron Patterson has posted at his site.

Figure 5. Process gain in refineries around the world and in the United States (Peak Oil Barrel )

The plot is at the end of a discussion on the difference between counting all the oil produced in a country and the break-down into crude and other sources that add into the total. One part of this is the gain in volume, process gain, that comes when crude is refined. It therefore acts as a marker of the volume of crude that is running through refineries, and as Ron notes, this has now plateaued for the past few years. Interesting!!!

OGPSS - A June TWIP, and the OPEC MOMR

The EIA has noted, in This Week in Petroleum that, for the first time, the sum of Non-OECD country demand contributed more than half to the total of liquid fuels consumed in the world.

Figure 1. Changes in the relative shares of liquid fuel consumption between the countries in and out of the OECD. (EIA )

It does, however, point out that the projections of the Short Term Energy Outlook are for the two curves to re-intersect at the end of 2014.

Figure 2. Projected changes in liquid fuels consumption, through 2014 (EIA)

The reality of that second assumption is, I rather suspect, more based on hope than reality. Once you start providing power, and all its benefits, to the general population you are on a slippery slope that it is almost impossible to back away from. Consider (as a small example) the problems that Egypt is currently having with the supply of subsidized bread to the general populace. Once you start supplying a commodity at a subsidized price it becomes very hard to change the equation, and too much of the non-OECD world is now living in an economy where energy use is subsidized. The problem that the above graph fails to recognize is that you cannot wean a culture from subsidies in the immediate short term and still expect their government to survive in its present condition.

Thus when the EIA project that global demand will grow to over 92 mbd in the next year, they are likely only being realistic. Their assumption that it may then decline is perhaps more in the nature of wishful thinking.

Figure 3. EIA anticipated growth in demand and supply over the near term (EIA)

There are however a couple of caveats to that last statement, the first of which is that the decline in demand may be more reflective of a lack of supply capacity (our raison d'être) and alternatively it may reflect, as a result of the first, that prices will rise to influence demand. Nevertheless we remain in a condition where the harsh realities that lie just over the horizon remain obfuscated by other events.

As with many other international agencies the EIA continue to anticipate continued growth in the North American supply of liquid fuels. Outside of that growth the increased demand for more than an additional mbd of liquid fuels seems more likely to be likely to be desperately hunting for an invisible savior.

Figure 4. Anticipated growth in liquid fuels supply over the next two years (EIA)

The decline in supply from OPEC in the two years ahead should be noted. It should also be remembered that this is likely to be as much a voluntary control, to ensure price stability in the face of increased North American production, rather than as a result of a short-term supply shortage. However the reality of continued domestic growth in demand in the Middle East, as Westexas has reminded us, is something that cannot be neglected. It has been noted that Saudi Arabia, although having less than a third of Germany’s population, recently surpassed it in terms of oil consumption. It will add several new oil-fired power stations including those at Yanbu and Jeddah. This will feed into an anticipated continued growth in Saudi domestic demand of 5.1% pa.

And this brings us to the OPEC Monthly Oil Market Report (MOMR) for June. OPEC continues to anticipate a global demand growth of 0.8 mbd this year, though they note that there will likely be a growth of 1.2 mbd in the non-OECD nations, requiring a reduction in OECD demand to match the overall forecast. Major growth in demand will continue to be in China (at 0.4 mbd and the Middle East at 0.3 mbd). On the other hand OPEC anticipate cutting their supply (to match anticipated need) by 0.4 mbd over the course of this year. OPEC, therefore, has slightly dropped their projection for year end, however it will still crest above 90 mbd.

Figure 5. Estimates of global oil demand (OPEC June 2013 MOMR)

A large part of demand projection is tied to growth in the global and individual nation economies, and that is a murky crystal ball to view. But OPEC anticipates that these economies will continue to grow at an increasing rate, while recognizing that this projection is in an area with a high level of risk in the estimate. The continued, and perhaps growing unrest in the Middle East continues to cast a further shadow over predictions over both supply and the reality of future demand in those countries. And, as one of the less frequently discussed topics, future output from Russia is not as assured as the average analyst appears to assume.

OPEC is anticipating a relatively strong growth in demand in the second half of the year to almost reach 91 mbd by the end of the year. Overall the growth in supply to meet this demand continues to come from North America.

Figure 6. Anticipated oil supply for 2013. (OPEC June 2013 MOMR)

OPEC itself is reporting a slight increase in overall production (by about 128 kbd) although, as always, there are differences in the numbers between those supplied by the countries themselves, and those reported from other sources.

Figure 7. OPEC crude oil production as reported directly (OPEC June 2013 MOMR)

There continues to be a significant disparity between the numbers reported from Iran and Venezuela, for example, when other sources are reported to the tune of around 1.5 mbd roughly. In the short term Iraqi production appears stable.

Figure 8. OPEC crude oil production as reported by others (OPEC June 2013 MOMR)

With the continued global reliance on increased production from North America, and, in turn, that reliance on improved production from tight formations, I would be a little more confident of the future were it not for plots such as this, which I recently found.

Figure 9. Chesapeake typical well decline curve (Eagle Ford Forum)

It is a curve that I rather suspect continues to be optimistic.

OGPSS - Happy New Year, or perhaps not!

It is the beginning of a New Year, and, belatedly, I hope that all readers find this new period to be one of prosperity, health and happiness. It would be encouraging if the portents for our Energy future would point in that direction, but unfortunately I can’t see nearly as much optimism in that regard as do others who are similarly reviewing where the global energy supply numbers are going. This week the EIA's ”The Week in Petroleum” is illustrative of the optimistic vision.

Figure 1. Recent projection from the EIA on American Oil Production (EIA TWIP Jan 9, 2013)

This plot is from the new Short-Term Energy Outlook from the EIA, which projects the numbers through to 2014, at which time: the Agency anticipates that US domestic production will rise to 7.9 mbd, the highest since 1988. Growth is expected to extend beyond just the Bakken:

In particular, drilling in tight oil plays in the Williston (which includes the Bakken formation), Western Gulf (which includes the Eagle Ford formation), and Permian basins are expected to account for the bulk of growth through 2014. Williston Basin production is expected to rise from an estimated December 2012 level of 0.8 million bbl/d to 1.2 million bbl/d in December 2014. Western Gulf Basin production rises from an estimated December 2012 level of 1.1 million bbl/d to 1.8 million bbl/d in December 2014. Within the Western Gulf Basin, roughly 0.4 million bbl/d of the oil production is outside of the Eagle Ford formation. The Western Gulf Basin accounts for more than half of the onshore domestic liquids production growth due to a comparatively large amount of liquids coming from both oil and gas wells compared with the other key production basins. The Permian Basin in West Texas, which includes plays such as Spraberry, Bonespring, and Wolfcamp, is a third key growth area. EIA estimates that crude oil production from the Permian Basin reached 1.2 million bbl/d in December 2012. Permian Basin production is projected to increase to 1.4 million bbl/d in December 2014.

The overall global concerns for production include a relatively small potential for production growth from the larger oil producers in the world (with the possible exception of Iraq), while there remains an increasing turmoil that began with the “Arab Spring” and continues to spread with ongoing and growing impacts that are likely on Middle Eastern oil production. But it is the story of American production that continues to gnaw at my worry bead string.

In context it should be remembered that, when The Oil Drum was first produced in 2005, national attention was briefly caught by the TV movie “Oil Storm” in which a plausible series of events – a hurricane in the Gulf, a ship collision in the Houston Ship Canal, and a terrorist attack on the Saudi oil terminal at Ras Tanura combined to raise the price of oil to a peak of $130 a barrel, and gas reached a final price of over $7 a gallon, with all sorts of terrible consequences. The day was finally saved when Russia shipped the US a few tanker loads of oil, after the US outbid the Chinese for that oil.

Since then there have been pundits who tell us that these things would never happen. During the real price rise to $147 a barrel (without the disastrous causes) we were reassured that prices would fall again to the $20-$30 a barrel range, though they have not – and those same pundits are now again parading before the media as they reassure us that the US can soon cast off the shackles of oil price control by foreign oil interests. Of the roughly 10 million bd that the US imported in October, some 4.2 mbd came from OPEC, Saudi Arabia sending 1.25 mbd, and Venezuela 0.95 mbd. Outside OPEC Canada supplied 2.68 mbd, Mexico 1.06 mbd and Russia 0.55 mbd. KSA has shown itself adept and willing to adjust flows to ensure that OPEC oil prices remain adequate, and there is no indication that they need or intend to change their approach. Any global increase in supply is likely to be more than offset by increases in demand from China and India, though the reality will be that as US demand declines (if it does) that displaced supply will transfer to meet Asian growth – and it will not then be available were the US projections to fall short, and the country have to increase imports again.

There are some troubling signs on the horizon that suggest the future US supply is not as robust as has been proposed. Chesapeake Energy, who have been a flagship for the development of natural gas, is in sufficient trouble that Aubrey McClendon, the CEO, will not get a bonus this year, amid a number of changes. Shares have dropped nearly 30% and as Art and others have noted, the economics are not as encouraging as the pundits would suggest.

The news from the Arctic is somewhat worse. Shell have been able to recover their drillship, which ran aground after losing its tow in a 70-knot storm with 40-ft waves, and it has now been moved to a safe harbor. The vessel must now be assessed and the program will be delayed. (This is particularly true as the investigations begin to line up, first was the Coast Guard, and now Interior.) The Alaskan Pipeline flows were averaging just under 583 kbd in November (December numbers are late), and that is up from the overall yearly average of 544 kbd, but is running at a 6% decline rate bringing problems in as little as 8-years. Although with monthly flow changing to improve conditions in the winter months, there may be more of a problem than is currently discernable, particularly if future supplies to keep the pipeline flowing are now threatened by the future losses of potential production from the Chukchi and Beaufort seas.

And speaking of pipelines the cancelling of plans for the Bakken Crude Express Pipeline for lack of customers tells more about the anticipated future demand than all the predictions from Dr. Yergin at Cambridge. Energy Research Associates. This also foretells that the Adelman prediction that technology will always return us to cheap oil, as touted by Phil Verleger is likely to continue to be proven false – not that these real events stop those who survive by predicting the future. Fortune tellers have been a facet of society throughout history, only the shape of their crystal balls has changed with time, and the size of their credulous audience.

Whether real or overly optimistic, the US potential increases in fossil fuel production is likely to impact to the potential for US renewable and bio-generated fuels, where the future production levels seem also to be losing their lustre. There is some talk of Dr. Chu leaving the Department of Energy in part perhaps because of this change in focus. However, among the names being floated are those of John Podesta, the founder of the Center for American Progress, who have just ranked their top ten Energy and Environmental Priorities for the first four years of President Obama’s time in office, as follows:

Figure 2. Priorities as quoted by the Center for American Progress.

And most recently the Secretary has been encouraging women and minorities to look at the wind energy industry as an opportunity for employment.

One other candidate is apparently Bill Ritter, the past Governor of Colorado, although the list, at this point, seems to be growing rather than shrinking.

Whether under either individual, or some alternate choice, the next four years of President Obama’s Administration will likely see many more changes than anticipated as occurred during the first term. It is, however, discouraging that there are so few possibilities for realistic optimism for that future.

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.

Rising Energy Prices and their impact

As the United States continues through the interminable process that will end with the national elections in November, the continued poor state of the economy is playing an increasing part in the debate over the likely outcome. What seems to have slipped from the discussion, however, is the contribution that energy costs are making in their impact on the different economies around the world including that of the United States. That awareness is becoming more evident in the UK, particularly in the debate over Scottish Independence. The recent Uswitch report notes:

Energy bills have more than doubled in the last 8 years – if this trend continues bills could reach £1,582 a year by 2015 and £2,766 by 2018. But almost six in ten people (59%) say that energy will become unaffordable in the UK if the average bill hits £1,500 a year, with the average household bill today already £1,252 a year.

Yet the increasing reliance on “green energies” in the United Kingdom, and particularly Scotland, are already recognized as leading to major current and future cost increases, with consequent impacts on the strength of the economies that they support.

Figure 1. Relative energy sources for Scotland and the UK in 2010 (Scottish Government)

 The growth of renewable energy in Scotland has been remarkable over the past decade, and has received consistent support to grow beyond the current levels. The major growth has been in the use of wind turbines, which – as I saw in a recent trip to the UK, are now more prevalent than ever. (And, more encouragingly, were also turning in greater proportion than I had seen in the past).

Figure 2. Installed capacity for renewable energy in Scotland through 2010 (Scottish Government)

  Current plans and projections would increase capacity from the roughly 4.4 GW shown above to a total of 28.8 GW being possible with pipeline and projected other projects. And in 2010 Scottish turbines produced more power from turbines than from hydro power for the first time.

Figure 3. Scottish electricity from renewables by source (Scottish Government) 

 Of these, however, only 3.3 GW have progressed beyond the planning stage. Yet, given that renewable sources have supplied nearly 20% of the need at present, this suggests a much greater role in the future, with less need for more conventional fossil fuels. Currently Scotland gets most (around 75%) of its electricity from five power stations, there are the two coal-fired power stations at Longannet and Cockenzie, one gas-fired station at Peterhead, and two nuclear power stations at Torness and Hunterston. These stations will be phased out as the transition to greater reliance on “wind and wave” with a target of 16 GW to be contributed in 2020.

Figure 4. Path to a Scottish Renewable Energy Future (Scottish Government ) 

 (A. Deployment projection based upon an extrapolation of the annual deployment levels experienced in 2007-08. 

B. Deployment projection based upon an extrapolation of the annual deployment levels experienced between 2009 and the start of 2011. 

C. Deployment projection, based on Scenario B above, adjusted for the improvements in the planning/consent system that were introduced in recent years but which have not yet impacted upon actual deployment rates. 

D. The 100% target line is a straight line extrapolation between current installed capacity and the estimated levels of capacity required to achieve 100% of gross consumption from renewables in 2020. 

This hypothetical line is incorporated to identify and acknowledge the scale of the challenge. In reality, it is recognised that deployment will not follow a straight line and would be expected to accelerate towards the latter part of the decade, particularly given the potential magnitude of offshore wind deployment.) 

 The political beliefs of the Scottish National Party (SNP) now in power, which include a desire to reject nuclear power and move to greener sources of electricity is, however, bumping up against the realities of cost and practicality. The Institution of Mechanical Engineers in the UK has released a report that concluded:

The Institution’s findings suggest that the original renewable energy target split for Scotland of 50% electricity, 11% heat and 11% energy for transport, making the overall 20%, and subsequent revision of the electricity generation target to 100%, did not appear to be supported by a rigorous engineering analysis of what is physically required to achieve a successful outcome in the timescale available. 

During the research for this report, First Minister Alex Salmond announced that the Scottish Government had increased the overall percentage target for energy from renewable sources to 30% by 2020. In light of this report’s analysis, this aspirational target appears to represent an ambition that cannot be justified from an engineering perspective.

The Scottish Government has responded, in part, by emphasizing the goal of reducing energy consumption in the country by 12% by the year 2020. Yet significantly raising energy costs and demanding that society reduce demand are not obvious ways of immediately stimulating economies to return to national prosperity. About 750 million British pounds (BP) ($480 million) worth of power came on line in 2011, but the investment required to meet targets in the future will be much higher. The estimated cost for the next 17 GW of capacity is $70 billion (46 billion BP). The Scottish GNP runs around $225 billion (145 billion BP) and there is increasing question over the ability of the country to be able to attract the funding needed to achieve its targets. 

 Yet the concern that worries me more as these debates continue is that while an increasing reliance on renewable energy sources may well be politically promoted, the financial and technical ability to reach those goals is becoming increasingly unavailable. (See particularly the IME report). For, while the focus of the debate remains on that side of the supply, the construction of alternate power sources to meet the anticipated demand are not being properly addressed.

 In Scotland there is now talk of a new coal-fired power station at Grangemouth following the cancellation of a carbon capture and sequestration project at Longannet. The Cockenzie coal-fired plant will close next year, though there are hopes that it might be replaced with a natural gas-fired plant. But these things take time to permit and construct, and should the required pace of renewable sources falter, then the conservation of energy that the Scottish Government would like to see as a voluntary activity might come to be an involuntary need instead, with consequent significantly more severe impact on industry and the Scottish economy. 

 Why is this relevant to the American election? Well unfortunately, though at a slower pace, there seems to be a similar argument being made in the United States to speed up the phase-out of coal-fired power, as perhaps evidenced by the recent decision to close the Big Sandy coal-fired power plant in Kentucky, under EPA pressure. There is a presumption in discussions of the future energy costs for the country that cheap natural gas will be an easy replacement for coal. However, much of that future relies on the low prices of natural gas, and as Chesapeake are finding, just because there is a market, does not mean it is a profitable one. You can’t make up the difference between producing natural gas for $5 a thousand cu ft (kcf), and selling it at $2/kcf by increasing the volume that you sell, and thereby realize a profit. When all the dust settles it is likely there will be less natural gas on the market, at a greater price, but that is a different story. For now one can only be concerned that the failure to recognize that energy prices are playing their part in restraining national economies seems to have become a neglected part of the national discussion, which is a pity – both in Scotland and in the USA.

The gas shale e-mails and the NYT stories about them

I doubt that this will ever reach the levels of public interest that has led earlier exposures of information to acquire a “gate” appendage, but the New York Times (NYT) has begun a running series of articles, starting this weekend, on e-mails that they have acquired that largely deal with the gas shale business. In the discussion on Focus today, it was the first topic of conversation, and so I thought I would write about what the fuss is about. Not, I should hasten to add, that any of this should come as a surprise to you gentle readers, since many of the “revelations” have been covered here in the past.

There is a considerable body of literature that tends to look at future supplies of natural gas, particularly from shales, through very optimistic lenses. This includes reports from such agencies as the EIA and the IEA that suggest that the world is entering the “Golden Age of Natural Gas.” Recent discoveries and projections have led to estimates that the world will be afloat on natural gas for the foreseeable future, as many countries have natural gas tied to shale layers, and American success in developing these deposits could lead to similar success in other countries, providing large volumes of indigenous fuel, at potentially low cost. Unfortunately, as those who have read my posts here know, much of this is over-inflated and not going to happen. While I discussed the problems with the EIA report back in April (haven’t got round to writing on the IEA report yet,) the fundamental points remain valid. The point brought out by the NYT is that the concerns that I have written about are also prevalent within the industry itself, even while it seeks to draw investors into putting up money to drill more wells. And in that activity, as the articles note, industry has been very successful.

If I can re-iterate some of the concerns, they begin with the cost of the drilling and completion operation. Both parts of this are expensive, the initial cost to drill a vertical well, and then turn it horizontal and run it out thousands of feet within the shale costs millions of dollars, as then does the subsequent series of events that includes fracturing the horizontal well a number (perhaps 30) times and using expensive suspension fluids to force small particles into those cracks so as to prop them open and allow gas to migrate from the rock into the well. The costs as a rough initial marker, run around $5 million dollars per well, though they can go considerably higher.

This sort of investment requires a significant return on investment, and in the best wells initial flow rates of over 10 million cubic feet per day can be achieved. However, as the industry has long known, but likely not the general public, those wells are proving to drop in production very quickly. As I quoted back in that earlier piece:

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.

The initial high yields from these wells fall by as much as 85% in the first year, and while this may still make the producers such as the Day Kimball profitable, that was the most successful well Chesapeake had drilled until then. For the less successful payback is lower and may not cover costs.

Part of the problem comes in that the companies seeking investors suggest that the wells will continue to produce for up to 50 years. I would not deny that were the wells to remain open that long that some gas would be still coming out of the wells at the end of that period. However natural gas is a lot less valuable cubic inch for cubic inch than oil, and whereas a simple pump can raise a fractional barrel of oil a day and be profitable, this is much harder to do with a marginal gas producer.

The reason for this is that, unlike oil and coal, natural gas is usually carried (after cleaning to remove water oil and any other contaminants) through a pipeline that often runs (via additional pumps) directly to the customer. They, in turn, don’t usually store it, but burn it as needed, drawing the supply straight from the pipe. The problem that this gives the marginal producer is that the gas in the line must be at a certain pressure if it is to move down that pipe to the customer, and then come out of the nozzles at sufficient flow to be useful. That pressure has to be achieved, at the well once the natural pressure of the gas in the well has fallen over time and production, with a compressor, which cost money to install, run and maintain. At a certain point in the well life the gas being produced falls below the point at which it becomes economic to pay for that compressor (which is only a part of the total costs that an operating well will incur). It may even be (at the rates of decline being seen in many current wells) that the decline is so swift that as soon as the natural pressure falls below that needed for the pipeline, that the well closes and a compressor is never economical. In these cases the well life may well only be three or four years, rather than the fifty of the company model.

There is another concern that the NYT articles raise, and that deals with the change in reserve estimates that are now being made for new wells. I commented on this back when the changes were made in January 2009. To simplify the explanation of the changes before then a company had to physically prove that it had the reserve, and the volume over which it could estimate that the reserve existed was restricted to a relatively short distance from the validation point (usually a well). Investors thus had some degree of certainty about the size of the reserve that they were investing in. (And those who followed the reality Coal series on Spike this season will have seen how the geology changes rapidly, having an immediate impact on production in even a short distance underground - thereby illustrating why the original rules were realistic as a way of protecting the investor).

The change removed the requirement for physical proof, and allowed the company to make an estimate based on the geological data, as established remotely, and without the need for physical validation. As the NYT article notes, this allowed companies to revise their estimates and some did by up to 200%, with the rationale for doing so no longer as clearly visible and verifiable. As the wells are now brought into production those estimates are not always proving valid, according to e-mails within the industry and which the NYT obtained for their stories. The conclusion of monitors in the EIA, as evidenced by similar e-mails released by the agency, is that many of the companies will go bankrupt.

In some ways the response of the industry reminds me a little of what happened after the climate change e-mails were released to the web in what became known as Climategate. Very little specific focus on the criticism, rather moves to obfusticate the issue, and change the subject. In this regard it is sad to note that in the response that Aubrey K. McClendon, Chesapeake's Chief Executive Officer, released on the story his major defense seemed to be

If the Times was interested in reporting the facts and advancing the debate about the prospective benefits of natural gas usage to energy consumers, it could easily have contacted respected independent reservoir evaluation and consulting firms that annually provide reserve certifications to the U.S. Securities and Exchange Commission or contacted experts at the U.S. Energy Information Administration, the Colorado School of Mines' Potential Gas Committee, the Massachusetts Institute of Technology, Navigant Consulting and others who would gladly have gone on record to confirm the abundant resources that have been made available thanks to the horizontal drilling and hydraulic fracturing techniques that Chesapeake and other industry peers have pioneered in deep shale formations across the U.S.

As I noted in my comment on the EIA report there is a huge difference between a reserve (which is economically realizable) and a resource, which is not necessarily economic. The response did not address, in sufficient technical detail, the points that the NYT and released e-mails make, about the decline rates and thus long-term viability of the wells in production. Nor did it highlight in sufficient detail how, outside of the sweet spots such as the Day Kimbell well site, the less productive wells can be expected to remain economically competitive when their production costs could well be over 50% higher than the current price of natural gas as it is sold to the pipeline. Bear in mind also that the gas from shale is competing against natural gas produced from more conventional wells (at lower cost) and against Liquefied Natural Gas (LNG) which is available on the world market. The response by Michael Levi was similarly disappointing, since it tried to diminish the number of operators who might have problems along the “much ado about nothing,” line. While that by Christopher Helman tries to change the subject a little by suggesting that some wells also produce oil that helps with the economics, (this largely relates at the moment to the Eagle Ford shale) rather than the reality that it is the oil that is driving the well production, not the natural gas. And this was covered in these pages last December.

As I mentioned at the top of the post there is little in the NYT stories that is not well known within the industry. The e-mails bear that out. But it will be interesting to see how many papers pick this story up and also to see whether it acquires legs, or is allowed to quietly fade back into the noise. It isn’t after all as though we were betting our economic future on this, is it?

(Wonder if Andrew Montford is going to be tempted to write a new book?)

Natural Gas versus Coal - perhaps the UK experience revisited?

Back when North Sea oil and gas were discovered the British Coal Industry was a powerhouse in the land. Coal gas was used for domestic cooking, with the fuel generated by large gas works that dotted the landscape. Skip forward a little, and there was a massive campaign to convert the burners that had used coal gas over to a smaller size that allowed them to burn the natural gas becoming available from the North Sea. And with oil and natural gas coming ashore in increasing quantities the British coal industry rapidly faded from its peak to a fainter shadow of energy production, and coal gas became a historical item.

Coal gas is formed by the partial combustion of coal, natural gas (NG), on the other hand, occurs as a hazard in most coal mines. As the coal is mined the pressure comes off the coal, or it is fragmented, and the natural gas can escape. Once it reaches a certain concentration in the air it becomes explosive, and a heat source (a metal pick rubbing on sandstone for example) can ignite it, causing ignition of the gas, with a consequent disaster as those in the mine vicinity can be killed. Thus there are many precautions (which I will describe at another time) to stop that ignition, or to stop the flame from spreading very far.

But the natural gas can also be collected, and if it is collected in a purer form than that diluted by the ventilation currents of the working mine, it becomes a valuable resource, which the British miners now use to help power the mining process itself.

Sixteen generators are installed across 5 deep mine sites. These embedded generating sets are fuelled exclusively on mines gas. Some of the electricity generated is used at UK COAL sites representing a substantial energy cost saving.

However this harmonious use of the fuel projects a different attitude than that which existed as the National Coal Board died. And now that same struggle may be gearing up for a rematch in the United States, as the growing surplus of natural gas leads industry leaders to press Congress about forcing coal’s replacement with NG as part of the new Clean Energy Initiative. So far it hasn’t worked.

For all its pronouncements that gas could be used to replace aging, inefficient coal-fired power plants — and reduce greenhouse gas emissions in the process — lawmakers from coal-producing states appear committed to keeping coal as the nation’s primary producer of power.

However the folks at Chesapeake are now starting to face off against those of Peabody to try and influence the Senate version of Waxman-Markey. And the debate brings renewable energies into the picture, not necessarily to NG’s advantage. (Which is a little odd given that NG plants are generally considered the back-up power when the wind don’t blow or the sun don’t shine).

“By allowing free emission allowances to maintain coal production from existing coal plants, while providing mandates that there be more wind and solar, you squeeze gas out in the middle,” said William F. Whitsitt, an executive vice president at Devon Energy, a major natural gas producer.

This is not really something that it easily fixed in the marketplace, since the return on investment needed for the construction of a major power plant requires that there be a sustained market for the power produced, and concurrently a reliable cost-effective source of the fuel that will be required to generate the electricity for a significant portion of the plant lifetime.

Now the U.S. currently has a glut of natural gas. As a result futures have fallen to $2.508 per million Btu (give or take equal to 1 kcf). This has to start hurting some of the producers since, inter alia, Chesapeake has noted that it is costing them around $4.44 million to drill new wells in the Marcellus, a field in which they anticipate being the biggest player. The company is still very positive about that development – but notice the long-term price they are expecting to justify that optimism:

Based on drilling results by Chesapeake and others in the industry, the company has recently increased its targeted average EUR in the Marcellus from 3.75 bcfe per well to 4.2 bcfe per well. Assuming flat NYMEX natural gas prices of $7.00 per kcf (compared to a recent 10-year NYMEX strip price of approximately $7.02 per kcf), the company’s estimated pre-tax rate of return from a 4.2 bcfe horizontal Marcellus well drilled for $4.5 million is approximately 71% excluding the benefit of drilling carries and more than 1,000% including the benefit of drilling carries.

Back in March Chesapeake was reducing its production from the Haynesville shale however, back then they were also predicting that the drop in drilling activity would produce results before the end of the year.

During March 2009, most Mid-Continent natural gas prices at major interstate pipeline delivery points will average around $2.70 per thousand cubic feet, a price at which most natural gas production is unprofitable. We believe low wellhead prices combined with constrained capital availability will likely cause U.S. drilling activity to decline well beyond the 40% drop already seen since August 2008. As a result, U.S. natural gas production will begin to dramatically decline before the end of 2009 and consequently natural gas markets will regain better supply/demand balance by the end of 2009, if not sooner.

Given the continued excess in the marketplace, it would be nice if the NG industry could find a reliable market of greater size in power generation. They have already managed to corner around 25% of that market – but as yet have not managed to convince folk, such as the manager of our local power plant (which is already constructed to burn natural gas, but which blanked off the nozzles) to switch back.

Perhaps he, like so many others, realizes that as soon as the glut goes away, and the short-lived nature of the gas shale wells being what it is, that will likely happen within the year, then the price will go back up, and it will become less economic than the current coal contract.

Hence the desire of the natural gas companies to get a little more assistance from Congress in the struggle for the future.

It depends on how well they sell, and how well the coal companies manage to resist. All tied up with the debate about climate change, which seems to be less certain with recent publications (in New Scientist among other places) suggesting that the globe may cool for a while before reheating, this could be an interesting debate. And perhaps one with less certain an outcome than the British experience.

The Natural Gas Report for the week

Yesterday I was not all that cheerful about the omens foretelling the future of gasoline and crude in the near term. So today it is time to see what the latest in Natural Gas news is telling us, courtesy initially of the EIA.

This is the time where, as the Weekly Update noted, temperatures soar with the arrival of summer. With that comes increased power demands and increases in gas usage. However even the EIA is noting that so far the temperatures are more moderate than normal (they use data from NOAA), and this is impacting demand. Equally to the point the oversupply that came from the developments in the gas shales have yet to work their way through the system. Rig counts have dropped to 692 (picking up 7 from last week for the first increase in 29 weeks) from their peak last year of 1,606. Of the rigs in service some 391 are horizontal (counting both oil and natural gas), those most suitable to develop the shales. The result is that more natural gas is still being injected for storage, at a higher rate than normal, and bringing it significantly above the levels of both last year (632 Bcf more) and the 5-year average (482 Bcf more).

The industry also faces the potential for an increase in LNG shipments to the US. this year. Energy Trader, over at Seeking Alpha is currently very pessimistic about the situation, given the potential for LNG to be dumped into the United States as a world surplus develops this year. Prior to the development of the gas shales the world was looking at a situation where US supply would not be able to meet demand, and thus additional LNG capacity looked to be a very promising bet. Given the production from the shales, that bet is looking a lot less valuable and since the investments must still be paid off, deliveries to the US that undercut existing prices (given that shale gas is not that cheap to produce) may make this coming winter more of a buyers market than usual.

At the same time Alberta, with conventional gas deposits, is increasing the incentives to boost drilling for this gas, in the face of the gas shale developments.

The province will charge producers a flat rate of 5 percent during the first year of output from new wells, a government statement said. Drillers will also receive a royalty credit of C$200 ($172.64) for each meter (3.28 feet) of new well depth drilled.

The programs had been set to expire in March 2010, Energy Minister Mel Knight said in the statement. They will be extended to March 2011.

Companies including EnCana Corp., the nation’s biggest gas producer, are shutting wells amid a 70 percent decline in New York gas futures in the last year.

The question now becomes how quickly domestic production from the gas shales will decline, in light of their transient (about 2-year) life and the reduced drilling activity, and how much additional supply from LNG sources abroad will combat that decline. Within that puzzle lies the price that consumers are going to be paying for natural gas in the next couple of years. Opinions differ on what will occur. From the Calgary Herald

There are certainly positive signs that are driving the extreme contango in natural gas prices, when you look at winter contracts that are 50% higher than summer contracts. Commodity investors are looking at the collapse in U.S. rig activity which fell to 700 last week from 1600 last summer. They are betting on recovery in U.S. industrial activity. And they are looking at the disconnect between crude oil and natural gas futures.

However there are also signs that the commodity investors may be too early in their enthusiasm. Spot prices for natural gas (that’s the physical market) are well below the near-month futures prices, indicating that excess supply could continue to keep prices low for the rest of the storage injection season at the end of October. In Canada, spot prices are below C$3.00 per thousand cubic feet or US$1.00 per thousand cubic feet lower than U.S. spot prices.

On the other hand the Wall Street Journal sees the recent activity by Exxon Mobil, in starting three new LNG trains in Qatar, at a time when the world market is not capable of absorbing this increase (some 3 Bcf/day). The result:

So why would anyone ship LNG to the U.S.? In part, it's simple economics. Many projects were sanctioned and financed when lower natural-gas prices prevailed.

In Exxon's case, valuable liquids also produced in its Qatari projects take the market breakeven price of the natural gas itself "towards zero," says Deutsche Bank analyst Paul Sankey. Factoring in processing and shipping costs, that gas can be landed in the U.S. for less than $2 per million British thermal units, reckons Noel Tomnay, head of global gas at Wood Mackenzie. The current Nymex price is about $4.

Competing markets also look oversupplied. Wood Mackenzie estimates annual demand in Asia east of India will rise by 1.3 trillion cubic feet by 2015. New projects targeting the region and close to final investment decision amount to more than two trillion cubic feet of capacity.

In Europe, the prevalence of long-term pipeline contracts limits the size of the market up for grabs. Wood Mackenzie estimates about 4.9 trillion cubic feet of discretionary piped and liquefied natural gas per year will compete for a market half that size over the next three years.

Now Chesapeake has said that they can live with $4 (per kcf) natural gas prices but have shut in some 400 million cubic feet of production a day since April, in an attempt to stabilize prices. So far it is not working, at least to the level hoped (though it may be helping). As the EIA report notes the Henry Hub price has now dropped to $3.80. (And the greatest price drop in the country was at the Questar pipeline in Utah, where the price dropped to $2.50 – down 10%).

We will have to wait to see how this all plays out.

My excuses and a natural gas thought

Hmm! Tomorrow I get to go and give the report that brought me all the way over the Atlantic, and so this perforce must be brief, since even us ageing Academics must look over the material at least once. Also The Oil Drum is coming up on a fourth Birthday, and I am trying to do a quick history before it all fades into the past.

Thus, with your indulgence, just another grim look at the price of natural gas, where the seasonal drop is not yet helped, by the reduction in rigs, and new wells. The Natural Gas Weekly Update shows the same steady decline in gas prices that we have seen for the last six months.

Source EIA

And yet when one looks at the stocks of some of the producers, the story is a wee bit different. Chesapeake stock price has started to rise again, a little, as has Devon Energy so maybe we are coming through the end of the bottom of the market in energy – well a little early to tell, so keep watching.

Must dash! But back soon! No more below

Natural Gas and some worrying numbers

Their Website will tell you that they are the number one independent producer of natural gas in the country. When Boone Pickens needed a natural gas partner as part of his plan to change the mix of American Energy Supplies, he turned to Chesapeake. And yesterday they issued a statement that included the following:

Chesapeake has elected to curtail approximately 240 million cubic feet of natural gas equivalent (mmcfe) per day ( 0.23 bcf/day) of its gross natural gas and oil production due to currently low wellhead prices in the Mid-Continent region. The company has curtailed approximately 200 million cubic feet per day of gross natural gas production and approximately 6,000 barrels per day of gross oil production for at least the month of March 2009. The curtailed production represents approximately 7% of Chesapeake’s current gross operated production capacity. Additionally, the company is considering a further 10% reduction in its drilling activity during 2009 if natural gas and oil prices remain low during the next few months. The company’s attractive hedges and cash availability provide it with the operational and financial flexibility to curtail production during periods of unusually low prices, such as the current market environment. The company believes conditions are developing that will support higher prices for natural gas and oil later this year and in 2010.

This got me thinking about how much we use, who produces it, and issues such as the understanding of the different units that are used. So I am working on a standardized presentation of units – and see the sidebar for conversions etc.

Putting the Chesapeake statement in context, the CEO is quoted

During March 2009, most Mid-Continent natural gas prices at major interstate pipeline delivery points will average around $2.70 per thousand cubic feet (kcf), a price at which most natural gas production is unprofitable. We believe low wellhead prices combined with constrained capital availability will likely cause U.S. drilling activity to decline well beyond the 40% drop already seen since August 2008. As a result, U.S. natural gas production will begin to dramatically decline before the end of 2009 and consequently natural gas markets will regain better supply/demand balance by the end of 2009, if not sooner. …… In addition, we have reduced our drilling activity from 158 operated rigs in August 2008 to 110 currently. We are considering a further 10% reduction in our drilling activity, which if implemented, will be in areas where we do not have joint venture drilling carries.

To put the price in context Atlas Energy just reported that their drilling costs in the Marcellus Shale where they are currently developing production in the Applachian Basin, were $1.49 per kcf.

In 2008 the United States consumed a total of 23,241,512 mcf of natural gas, of which 21,328,916 mcf is delivered to customers (91.7%). This averages 63.6 bcf a day of total consumption, with 58.4 bcf going to customers. This is not an even consumption, but as you might imagine, is a function of the month (as shown below).

Natural Gas Consumption by month for 2008 (Source EIA )

And for those curious as to whether the weather was exceptional in those months, the average heating degree days for the regions of the country were higher in the 2008-2009 heating season over the previous season by over 7% on average.

Natural gas is supplied to four main markets electrical power generation (18.2 bcf/d); industrial use (18.2 bcf/d); Residential (13.4 bcf/d) and Commercial (8.6 bcf/d) use. The natural gas that goes to power generation now produces roughly 25% of US electrical power, and has the advantages of being both cleaner than coal, and also more flexible. This is particularly useful as more renewable sources such as wind and solar come into the grid, where their fluctuating power needs to be balanced, and natural gas is better at doing this.

To get some sense of where this came from, consider that Devon Energy drilled 2,441 wells in 2008, with a claimed 98% success rate. 659 of these were in the Barnett Shale, where the company now has a total of 3,809 wells, which produced 398 bcf in 2008. By the end of 2008 company gas production was nearly 1.2 bcf/day. Devon actually produces both oil and gas and so I can’t do the following calculation using their numbers, but let me instead set up a hypothetical company, but using some similar numbers.

Let us assume that this company is producing 1.2 bdc/day of natural gas. It only produces natural gas, and it got this production from 4,000 wells in 2008. If it drilled 2,500 wells in 2008 of which 90% were productive, then it would have 2,250 new productive wells. If one divides the daily volume among the producing wells that gives a daily average production of 300 kcf/day. However it is important to remember that in the gas shales some 60% of production comes from the well in the first year, and if, for simplicity we say that 36% comes in year 2, and that the remainder can be neglected, then I can illustrate the drilling need with a very crude calculation.

Let us say that wells come on stream at the first of the next year. Then at the beginning of 2009 1,750 wells were entering the second year of production while 2,250 were just starting up, then the production number changes so that in their first year the new wells will produce an average 363 kbd and this drops to 218 kbd in the second year, and the well is then done. Now we move forward to the start of 2010, so the original wells drop out of production, and the new wells drop down to second year production values. In order to sustain gas production the company will have to drill an additional 2,167 wells this year, at the assumed new production rate and success rate.

However the price of natural gas having fallen the company which drilled last years wells with say 160 rigs decides to cut back to 110 rigs in the same vein as Chesapeake. Then if the 160 rigs drilled 2,500 wells in 2008, the rig production is about 15.6 wells/year. So the number of wells drilled this year at that rate, but with the lower number of rigs, will be 1,718. At 90% success rate this gives 1,546 new wells at 363 kbd and 2,250 old wells at 218 kbd. The total is roughly 1.0 bcf/day. In other words the company will see a 20% drop in production next year. It gets a little worse in 2011. Consider that if the same number of wells are generated in 2010, then we have 1,546 wells at 363 kbd and 1,546 wells at 218 kbd, so the production drops to 0.9 bcf, at which it stabilizes, if the success rate and well production rates remain constant. As a matter of reality it is likely that they will drop.

To revert back to real numbers the Baker Hughes rig counts for 27 Feb, 2009 had 1,243 rigs operating in North America, of which 78% were gas (970). Of the total some 37% (460) were drilling horizontal wells. Incidentally the site presents these in a rather informative graphic:

Source Baker Hughes
It is interactive and, for example, by selecting for the Williston Basin find that there are 34 rigs drilling, that they are all drilling for oil, and that 89% of them (30) are drilling horizontal wells.

Source Baker Hughes

This is a much faster and more visual understanding of the data than the old way of downloading spreadsheets, which is the way you still have to look to find, for example, that in January Saudi Arabia had 46 rigs drilling for oil, and 28 drilling for natural gas. But it still leaves me wondering what that one rig is doing drilling a geothermal well in Illinois.

Well enough for crystal gazing for today, as I mentioned this is just an illustrative example of what might happen in the none-too-distant future. It is not accurate since some companies are cutting back harder on rig counts than I have suggested, success rates are not all the same (it has been suggested that as an industry average only 28% of the gas shale wells make a profit at a reasonable price for gas). But it might help understand why it is very unlikely that gas prices will remain as low as they are now for very long.