Tech Talk - what the EPA Plan neglects

One of the problems, I suspect, with predictions of future energy use and production is that physical reality can become entangled in the politics of the day. Thus news that tends to negate the optimistic views of future American oil and natural gas production is subsumed by the need to keep the level of those predictions hecause of other political needs.

President Obama has now announced his decisions on a new incentive to combat his perception of the future as it sits threatened by the increased carbon dioxide produced by the burning of fossil fuels, particularly coal. As announced by the EPA, the Clean Power Plan “will maintain an affordable, reliable energy system, while cutting pollution and protecting our health and environment.”

The proposed rule has the intent of lowering carbon dioxide emissions by 30% from the levels of 2005, by 2030. As with many energy-related plans this one will take some time to implement, particularly since individual states have some input to the final program that will be put in place. More to the point, it will influence the thinking of power generators and legislators over the next few years.

Beyond the actual implementation, the real impact will be in the planning departments of the utility companies around the country. There is at least an even chance that, at some time in the future, these will become the regulations that must be followed, and as future power plant construction is planned, so the options that will be considered will now be changed to accommodate these likely regulations.

Realistically the closure of coal-fired plants will likely be followed by the construction of more natural gas plants, since the overall electrical energy needs of the country are unlikely to fall significantly. In the short term this is unlikely to be a problem. However as one moves into the intermediate term (say more than 5 years out) the old plants will have gone, and the country will become increasingly dependent on natural gas, in the same way as Europe is at present. As the old coal plants are demolished, they, and the coal mines that supply them, cannot be resurrected within a five-year period given the amount of permitting, financing and overall planning that is now required for such construction.

Natural gas has advantages over coal, in that it can be supplied by pipeline that makes it less susceptible to weather. But by the same token it is rarely stored on site, but metered along the pipeline as demand rises and falls. As history has shown, this can lead to critical shortages when, at times of high demand, the pipeline cannot keep up with demand.

At present the likelihood of problems seems remote, wells continue to be sunk and production in increasing in fields around the country. But if one goes beyond the picture that is projected as reassurance to those concerned for energy supply in the future the numbers revealed are not that comforting.

Figure 1. The changing picture of natural gas demand (EIA)

One begins with the prediction that the US has about 100 years of natural gas supply with a total extractable volume in reserves and resources of over 2,718 Tcf. It is a reassuring number but, as with the total volumes of either oil or coal in the ground, it does not really give that much information on what will be available as demand continues to rise.

Consider that, increasingly, the volumes of natural gas that are being sought are in shales, where the well must turn and drill along the shale horizon, before being fracked to produce gas and oil within the rock.

Figure 2. Number of rigs defined by type of well (Baker Hughes via EIA and Penn Energy)

The increasing dominance of horizontal well completions brings with it a considerable increase in well costs. You can see this as the technique became of increasing importance after 2005.

Figure 3. Change in the average cost of natural gas wells (EIA )

Well construction prices have continued to rise since that time, with numbers now running up to and beyond $10 million. The rising costs makes it harder to achieve a reasonable return on that investment, particularly as there has been no great increase in the overall price of natural gas to reflect its increased popularity, in large part because of the rush to drill and produce the known reserves.

Figure 4. Recent changes in natural gas prices (EIA )

As a result the number of rigs working in the natural gas fields has fallen, to the lowest levels of the recent past.

Figure 5. Change in the natural gas rig count over the past year. (Baker Hughes )

If you can’t make a profit on the merchandise, then after a while you stop trying to produce it. Despite the optimism that leads folk to anticipate large volumes of low-priced natural gas being able to sustain us into the foreseeable future if the companies cannot make a profit, after a while they stop. Which means that prices will go up, re-opening the cycle, but on a higher step. In time this will bring natural gas prices back up to around $8.00 per tcf, which will make the industry more comfortable.

What it will not do, however, will be to favorably impact the economics of the electricity business, where doubling the cost of fuel has a quite negative effect on prices and overall economics. But concerns over the rising price to be paid has had little impact yet on political decisions on energy in Europe, and one has to presume that a similar blindness to energy price consequences will also prevail in the United States. After all there is lots of natural gas around, it just has to be perceived as remaining a cheap fuel to validate the political plans . . .right ??!!

A gentle cough for CBS and the National Petroleum Council

I was flipping through the news channels last night and came in on the tail end of a CBS story about billions of barrels of oil in Texas. Having missed the introduction, it was not until this morning that I discovered that it was a story about the Eagle Ford Shale.

Energy companies are rushing to the area to tap deposits that could produce up to 12 billion barrels of oil, and enough natural gas to power every American household for at least five years.

By 2020, that number (of new jobs) is expected to increase to 66,000.

I remember writing a short post on the Eagle Ford last December pointing out that the field was currently being more actively developed in the “wet gas” region where the Natural Gas Liquids (NGL) content is high, since this was more profitable than the deeper “dry gas” sections. But I did not remember the numbers being that high.

Being curious about them, a check at the EagleFordShale Web site suggests that the CBS report was triggered by a report from the National Petroleum Council, which was released yesterday. That report had been requested by Energy Secretary Chu to

reassess the North American natural gas and oil resources supply chain and infrastructure potential, and the contribution that natural gas can make in a transition to a lower carbon fuel mix . . . . .(provide) advice on policy options that would allow prudent development of North American natural gas and oil resources consistent with government objectives of environmental protection, economic growth, and national security (and) the United Sates sees a future in which valuable domestic energy resources are responsibly produced to meet the needs of American energy consumers consistent with national, environmental, economic and energy security goals, ... [and the United States] has the opportunity to demonstrate global leadership in technological and environmental innovation. Accordingly, I request the Council’s advice on potential technology and policy actions capable of achieving this vision.

The report notes that “The United States and Canada together produce 4% more oil than Russia, the world’s largest producer.”

Leading World Oil Producers (NPC using BP Statistical Review).


Further, together with Canada, the report points out that the United States produces over 25% of global natural gas production, with the arrival of shale gas being the game changer that may provide over 100 years of supply at today’s demand rates.

Leading World Natural Gas Producers (NPC using BP Statistical Review)

Yet it is in the discussion of those reserve numbers that the shaky timber on which the NPC case is build becomes apparent. When discussing future oil production it notes:

One source is tight oil, found in geological formations where the oil does not easily flow through the rock, such as in the Bakken formation of North Dakota, Saskatchewan, Montana, and Manitoba. Tight oil has also benefited from technologies similar to those used for shale gas, including hydraulic fracturing. Over the next 20 years, tight oil production could continue to grow. A second potentially large supply source is in new offshore areas, particularly in the Gulf of Mexico and the Atlantic and Pacific coasts of the United States and Canada. Access to and potential development of these new U.S. areas would require an Executive Branch level directive to include such areas in the 2012–2017 Leasing Program. New offshore areas could provide both natural gas and oil in significant quantities to supplement the continuing strong production in the Gulf of Mexico. Third, new Arctic oil and natural gas supply have a potential of the equivalent of over 200 billion barrels of oil. This is in addition to existing oil supply and proven natural gas reserves on the Alaska North Slope. The new Arctic resources could yield significant supply after 2025. Fourth, another very large long-term oil supply source lies in the shale oil deposits of Colorado, Utah, and Wyoming. The development of these billions of barrels of oil from these new resource areas will require sustained investment, substantial advances in technology, and environmental risk management systems and approaches.

The report also supplies this estimate of the available natural gas, showing several estimates.

Estimates of the Technically Recoverable Natural Gas Available in the United States. (NPC )

I have recently written of the Bakken Shale, and the problems that I see with its long term production. I have also similarly discussed some of the problems with the Arctic development and the potential size of the reserves available. ) In the later case I noted that the recent USGS report had downgraded, as an illustration, their initial estimate of 10 billion barrels of oil being technically recoverable from the National Petroleum Reserve, to a current estimate of 500 million barrels of economically recoverable oil. That percentage difference between the actual recoverable, relative to the technically recoverable is in line with a 6.9% estimate of the economically recoverable (relative to technically) volumes of natural gas, which I pointed out when I reviewed the EIA Shale Gas report.

If one were to look at these numbers in that light (though the actual detailed resource section with its break down is not yet available from NPC) then the numbers become more credible. Unfortunately it makes the estimates of the contributions that the industry will make to national energy security and job creation a whole lot weaker, if the numbers are only one-twentieth of those which are currently being thrown around.

Unfortunately the report goes on to spend much more time discussing the environmental aspects of oil and gas recovery, and emphasizing such things are the reduction in pad size in the Arctic:

Change in Arctic Pad Size with Improved Technology (API

There is not that much that is encouraging in the way of new technology that is anticipated to come on line to increase the percentages of natural gas and oil that can be recovered, and the report does comment on the need for more graduates as the current work force retires – a need that is not being adequately filled.

It is a weak straw on which to build the projections that CBS used.

OGPSS - The oil and gas of Southern Alaska

Before it was American, Russian visitors had already noted the presence of oil seeps in Alaska, although they had not done anything about it by the time the tsar sold the land to America on March 30th 1867. Russian history would have it that some $165,000 of the $7.2 million of the sale was used to persuade doubting American legislators and members of the media of the value of the purchase. The oil can still be seen, coming from current seeps, such as this one:

Natural oil seep, Oil Creek, Alaska (David Page )

These seeps occur both on and offshore, and as happened in the rest of the country, it was these seeps that brought prospectors to the region, and where the first wells were drilled.

Location of natural seeps along the Alaskan coast. (after David Page and the Copper River and Northwestern Railway )

It is pertinent to note that the creeks shown above are productive salmon spawning grounds, though it was the oil that led to early development.

The first producing field was at Katalia on the Gulf of Alaska. Discovered in 1902, it produced 154,000 bbl of oil before the refinery burned in 1933.

Early Drilling rig at Katalia in Alaska (Cook Inlet Oil and Gas )

The larger fields in and around the Cook Inlet began production with the development of the Swanson River field in 1957. The first Alaskan pipeline was built in 1960 to carry oil from there to the Nikiski refinery (which later supplied the fuel to the International Airport in Anchorage. The Cook Inlet fields peaked in oil production, at 227,400 bd, in 1970. The largest oil field in the region was the McArthur River field, discovered in 1965, but while discoveries continue to be made, the majority of the wells are now past their prime, and will need significant work to be brought back into production. The more recent developments were offshore, with a considerable change in structure from that of the early days.

Unocal Monopod platform in Cook Inlet (Cook Inlet Oil and Gas )

Fields (oil is green, natural gas is red) in Cook Inlet, Alaska (Alaska Department of Natural Resources via Cook Inlet Oil and Gas )

In 1958 natural gas was discovered in the Kenai Peninsula, and by 1962 was supplying gas to Anchorage, 85 miles away. There was sufficient natural gas available that, in 1969, a liquefied natural gas (LNG) plant was built and began shipping LNG to Japan, the first such export from the US to Asia. By 2009 some 1300 tanker loads, with an original deadweight capacity of 36,896 tons, had been shipped through that train.

There were two original tankers on the run, the POLAR ALASKA and the ARCTIC TOKYO, partially made of balsa wood and invar steel and they made the twenty-one day round trip until 1993, when they were replaced by the POLAR EAGLE and the ARCTIC SUN, each with a deadweight of 87,000 metric tons. The ships were renamed POLAR SPIRIT and ARCTIC SPIRIT at the end of 2007, when the registration was moved from Liberia to the Bahamas. They were sold to Teekay Corporation at that time, but leased back for the duration of the project. With the declining production from the plant, the ARCTIC SPIRIT was returned to its owners in April, 2009.

The recent drop in the price for LNG on the world market, meant that the POLAR SPIRIT was returned to its owners at the end of this past April, with the end of the original charter. It now appears to be shuttling between Yokahama and the China Sea, with the last call in the US being in June. The LNG facility was mothballed at the beginning of this summer since Alaskan LNG was no longer competitive on the market.

the plant received needed license extensions last year, but was not able to get a satisfactory price for their LNG. . . . . . business case does not support continuing exports at this time.

The original two LNG carriers were renamed SCF POLAR (which left Las Palmas a couple of days ago) and SCF ARCTIC which left Point Fortin this morning.

The region has never been one of intense activity, with only a relatively few wells being drilled in any one year.

Exploration wells drilled in the Cook Inlet region of Alaska since 1950 (Oil and Gas )

At present there are two jack-leg drills heading for Cook Inlet, with the state providing some of the funding ($30 million) for this new drilling activity.

The wells that have been drilled and brought into production in the past have produced, to date, around 1.3 billion barrels of oil, 7.8 trillion cubic ft (TCF) of natural gas and 12,000 bbl of natural gas liquids in total. At the end of June the U.S. Geological Survey (USGS) announced the results of a new assessment of the resources of the region. There is a considerable amount of coal in the region, which is likely to contain methane, and this is now included.

Potential resources of Cook Inlet, Alaska (USGS )

The excluded region in the above graphic shows the coal that lies below 6,000 ft, and is considered unlikely to hold any gas. In addition to this coalbed methane, the USGS re-evaluated the likely volumes that are held in the sandstone and conglomerates that have, to date, been the host rocks for the oil and gas that has been extracted. Finally the USGS assessed the potential of tight sands in the region to hold technically recoverable volumes of gas.

As the recent experience with natural gas has shown, just because a resource exists, and can be recovered, does not mean that it will make sufficient money to justify the investment in the extraction. Thus the USGS can only say that there is a significant likelihood of oil and gas being present and recoverable, without bringing the costs and price of the fuels on the market into the discussion, and thus defining whether the resource is, or will be a reserve, or not.

Because the volumes are estimates, they vary from there being a 95% chance that there is some 5 Tcf of natural gas available, to a 5% chance that there is 39 Tcf of natural gas present. In the same way they estimate that there is a 95% chance of 108 million barrels of oil (mbo) being present, while there is a 5% chance that there might be as much as 1.3 billion barrels. Unfortunately current prices are not necessarily that favorable to much exploratory drilling to validate some of those numbers, though obviously they are favorable enough to convince the Governor to put up some money.

But another part of the reason for this lack of interest has been because of the much larger volumes of Alaskan oil that lie considerably further North, in the region known as the North Slope, which I will discuss next time. But that is beginning to run out, and there are other problems that are apparent, so the resources further South may have thus become more attractive.

Incidentally the mothballing of the LNG plant is leaving Anchorage with a wee bit of a problem. Until this year the facility has acted as a transient storage facility from which, in periods of high demand (such as the depth of winter) gas could be temporarily withdrawn to make up temporary shortages between demand and supply from the wells in the field. That has now gone.

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?)

Resources, Reserves - the EIA - coal gas and oil for the future.

One of the significant issues that can get folk argumentative, is the role that price plays in determining whether a fuel source still buried in the ground is called a resource or a reserve. For example I have exchanged opinions several times with David Rutledge on his view of the declining reserve base for coal. Most recently he has written in The Oil Drum pointing to the latest paper he has written on the topic, which is available at his website. Part of my rebuttal comment inferred that as the price of the product increased (likely through the lack of other reserves to be able to sustain the energy supply need of countries around the world) so coal will be recognized more and more as a reserve, which will be used, rather than a resource that will not.

The argument is also made that as price goes up the viability of resources that would cost too much to produce would change a significant volume of those resources back into reserves. That holds true for crude oil, in just the same way as for coal, except that with so much of the world’s cheap crude having already been produced, the availability of the resource volume that will convert over as price rises is not necessarily that great. I bring this up because in this week’s TWIP, from the EIA, they address this problem in regard to how much increasing the price of crude in 2009 increased the amount of crude (including condensate). Their answer was 9% for crude and 11% for natural gas.
(And as 1 of 2 UPDATES to the story, Russia has stated - whether because of exploration or increased value is not clear - but that it fully replaced its oil and gas reserves this year (h/t Leanan).)

Gain in Oil reserves (EIA)

Gain in Natural gas reserves (EIA)

The gas gain, as the EIA note, occurred at a time where gas prices were suffering from the additional volumes made available from the shale deposits of the country.

Domestic production of crude has stabilized at around 5.6 mbd, while imports are running at around 8.5 mbd, and refinery input within the US continues to rise. Gasoline production continues to mirror, roughly, last year at this time, while demand is running around 300,000 bd more than last year. This time last year distillate production was reducing, this year it continues to increase, although demand, which dropped precipitately for the last month, is now stabilizing at about last year’s level. And ethanol production continues to creep upward.

Biodiesel production is a little harder number to come by, there is a plot through 2008:

Biodiesel production (National Biodiesel Board)

There are reported to be `173 companies engaged in producing biodiesel (from a number of sources and in a number of ways). If all of them ran at full production it would generate an average of around 175,000 bd, which is not yet much of a significant figure. Additional companies planning to get into production might raise production by 15% but this remains still only a small fraction of what is going to be needed.

UPDATE: I have been pointed to the note earlier this year that the EPA had slashed the cellulosic ethanol mandate for next year:

Cellulosic biofuel was 250 million gallons, now 6.5-25.5 million gallons
Biomass-based diesel was 800 million gallons, and stays there
Advanced biofuel was 1.35 billion gallons, and stays there. . . . . .

“We first considered whether it appears likely that the required biomass-based diesel volume of 0.8 billion gallons can be met with existing biodiesel production capacity in 2011…we believe that the 0.8 billion gallon standard can indeed be met…Of the remaining 0.15 bill gallons, up to 0.026 bill gallons would be met with the proposed volume of cellulosic biofuel. Based on our analysis as described in Section II.C, there may be sufficient volumes of other advanced biofuels, such as imported sugarcane ethanol, additional biodiesel, or renewable diesel, such that the standard for advanced biofuel could remain at the statutory level of 1.35 billion gallons.”

(end of update)

Which brings me back to my original point which is that a change in the perceived selling price of the product (I say that because of the gas situation) has led to significant investment that has raised the reserves of a commodity that is recognized to be getting into short supply.

However, to put this in perspective, the gain in oil reserves was 3.69 billion barrels. The United States uses around (rough number) 20 mbd of oil, or 7.3 billion barrels a year. The gain in reserves will thus provide the equivalent of a 6 months supply, and while production will be spread over a number of years, it really doesn’t change the arithmetic that much. What is forgotten in the discussion, however, is that the equivalent change in reserve size is also occurring in other parts of the world. And while many of these places are, like the United States, in an era where their fields are now depleting, the increased value of the product is likely to slow that decline somewhat.

Coal, which is also where the discussion started, is in an even more robust situation. Coal price is still driven by the cheapest producer to the world market. It is not practical to consider opening a new mine in, for example, Montana, if the power companies around the country are already being adequately served by local deposits and by trains from the Powder River Basin. No-one will put up the investment capital to open new mines without a market, and with the current transient switch to natural gas, that incentive does not exist in the United States.

However the rest of the world is somewhat different. Bear in mind that the prices that oil and gas will reach, in the non-too-distant future, will be significantly above what many nations can pay. If they have indigenous sources of energy – vide coal – and enough of it then they will start building coal-fired power stations. They don’t have to play games with taxing one form of energy to encourage another, they need the cheapest possible source of power. And at the moment we know what that is!

And just to emphasise that, here is the most recent projection for future demand from the EIA.


I will forgo a comment on the assumption at the top of the plot.

George Will is afloat in a sea of fuel

Last Sunday George Will wrote about the abundance of fossil fuels in his column for the Washington Post. He began by surmising that Titusville, PA might have a claim to being most responsible for the modern world through the contribution of oil to world wealth. He then went on to list some of the many folk that have predicted (falsely) the arrival of a peak in oil production and the amount of reserves that are available.

In 1977, scold in chief Jimmy Carter predicted that mankind "could use up all the proven reserves of oil in the entire world by the end of the next decade." Since then the world has consumed three times more oil than was then in the world's proven reserves.

He does not see that America, or the world for that matter, can wean themselves from a dependence on hydrocarbons, and quotes Keith Rattie, the chief executive of Questar, from a commencement speech as well as Edward Morse, from a story in Foreign Affairs in which Morse states that there is plenty of natural gas available – perhaps a hundred years at the present rate of consumption, and that the deep water fields just beginning to be exploited are significantly larger than thought. And he includes Daniel Yergin as stating that" the resource base of the planet is sufficient to keep up with demand for decades to come.”

From all this he concludes that it is only the environmentalists that are going to ensure scarcity for the planet. So where does one begin to disassemble what would appear, at first sight, to be a rational argument based on the utterances of three prominent individuals?

To pick the last first, it has unfortunately not been that long since I last wrote about Dr Yergin and CERA. Earlier this month I noted, after giving a number of occasions in the past that CERA had been wrong, that some of the assumptions that they were currently using to project future oil production were likely to be wrong also.

The most obvious immediate reason is the collapse of the oil industry in Mexico. Having fallen from the projected 4 mbd to potentially only 2.7 mbd next year, global supply is going to have to find another source for that 1.3 mbd. Bear in mind that Mexican production has been falling as fast as 100,000 bd per month at Cantarell and the magnitude of this problem becomes apparent. The current hope of seeing 10 mbd from Iraq by 2020 is, I would suggest, also perhaps more than a little optimistic.

So let’s tick Dr Yergin from the list, and move on to Edward Morse and the prediction of natural gas production from fields such as the Marcellus and from the deep waters of the world. This case is a little more tricky to argue, but only in the sense that there are considerable resources in both these regions of the world and that they will continue to produce significant quantities of fuel for some considerable time. The questions that are being raised are, however, more along the lines of how much and for how long will they produce and at what cost?

Evidence to date (that I am trying to explain in the tech talks, but haven’t got to the downside talks yet) is that by using new technologies these fields can be produced with very high initial yields from slickwater, multi-frac’ed horizontal wells, but that these wells have a much shorter life and faster decline rate than was predicted when the production from these fields were estimated. The deepwater fields require dramatically higher investment costs and while the technology and equipment is available, to some limited degree, there aren’t that many rigs that can be mobilized to drill in these conditions. Further continued production from some of the weaker rocks that the oil lies in, at these depths, is going to continue to be a technical challenge, driving costs higher and higher and further limiting levels of production available. Yes there will be oil, but it will be more expensive and there won’t be nearly as much as one might think at any one given time (the production rate) to even maintain current levels of production very much longer.

Which brings me to look at Mr Rattie’s speech, which is one that I have considerable agreement with. Except for the assumption that we can continue to grow our way into the future in terms of increasing supplies to meet an increase in global demand for energy that will increase by 30 – 50% over the next two decades. He lists some of the anticipated growth:

The Salt Lake Tribune recently celebrated the startup of a 14 MW geothermal plant near Beaver, Utah. That‟s wonderful! But the Tribune failed to put 14 MW into perspective. Utah has over 7,000 MW of installed generating capacity, primarily coal. America has about 1,000,000 MW of installed capacity. Because U.S. demand for electricity has been growing at 1-2 % per year, on average we’ve been adding 10-20,000 MW of new capacity every year to keep pace with growth. Around the world coal demand is booming – 200,000 MW of new coal capacity is under construction, over 30,000 MW in China alone. In fact, there are 30 coal plants under construction in the U.S. today that when complete will burn about 70 million tons of coal per year.

Mr Rattie also points out something that is sometimes missed in the debate about coal and natural gas fired power plants:

America has about one million MW of installed electric generation capacity. Forty percent of that capacity runs on natural gas – about 400,000 MW, compared to just 312,000 MW of coal capacity.

But unlike those coal plants, which run at an average load factor of about 75%, America’s existing natural gas-fired power plants operate with an average load factor of less than 25%. Turns out that the market has found a way to cut CO2 emissions without driving the price of electricity through the roof – natural gas’s share of the electricity market is growing, and it will continue to grow – with or without cap and trade.

That is surely true in the short term, but the questions about natural gas production, and the fact that if natural gas were, for example, to be used at double the current rate (i.e. to produce 50% of the nation’s electricity) then even if the current prediction of 100 years of gas at current levels of consumption were true, then at double the rate, the lifetime of the reserve would be cut to 50 years. Given the questions on production referred to above, it may, be quite likely that estimates are at about twice reality, and thus there might be 50 years of supply, but this is likely to be consumed at somewhat higher rates than current, so that the effective lifetime is going to be closer to 25 – 30 years, I would suspect. (And don't forget that Questar is one of the largest natural gas producers, who may be vulnerable in the fight to retain market share as the increased availability of natural gas from conventional sources struggles against supplies from the gas shales and from LNG supplies - in the short term).

Oh I anticipate that there will be adjustments in the fuel mix in the future, the decline in oil’s share of the market will have to be replaced with some alternate fuel, and natural gas will have to carry some of this burden. I tend to see that there will be problems in getting an adequate amount of energy supplied from renewable sources, as the scale of their use grows, and the realistic availability of good sites for development of new farms reduces. (It is all too easy to just say we need the equivalent of say half of Utah, without recognizing just what percentage of Utah is actually available – just to pick some numbers for the sake of discussion).

Put this all together, and in an ideal world, when gold, oil and natural gas production could continue to increase in availability every year, then George Will’s suggestions might well come to pass. Unfortunately when there is a realistic limit to the actual volumes available, as we are now seeing with gold, so shall we soon see with oil, and before then I would suggest that Mr Will seek additional advice from elsewhere – perhaps here?
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How much natural gas does Turkmenistan have?

The pipeline from Turkmenistan to China is now almost complete, the section running through Turkmenistan, from the Malai field will take the gas to Uzbekistan (albeit Gazprom helped build the pipeline) and thence to Kazakhstan and on to China, with deliveries of up to 40 billion cu. m. (bcm) (1.5 trillion cu ft) per year.

This volume, and where it comes from, has suddenly become a little more important in the overall global supply of natural gas, given that, two weeks ago, the Turkmenistan President fired the folks leading the energy companies, and it is suggested that this was over a report of false data having been provided to a firm auditing the volumes of gas reserves remaining in the Turkmen cupboard. (Hat tip to Gail)

Back in 2008 these reserves had been reported to be around 10 – 14 trillion cubic meters (Tcm). However there has been a considerable question as to the accuracy of these numbers. The IEA has noted the increase in volumes with recent discoveries

Estimates of Turkmenistan’s natural gas reserves vary considerably, introducing a large element of uncertainty into projections of its future contribution to global gas supply. Representatives of Turkmenistan have put total gas reserves in the country at more than 20 Tcm, an amount approaching the range of proven reserves in Iran or Qatar – and far more than the 2.7 Tcm included by BP in its statistical review (2008).

Since 2006, Turkmenistan has announced new gas discoveries, the South Yolotan and Osman fields in the southeast of the country, and in August 2008 also a new gas condensate field, South Gutlyayak. The Turkmenistan government announced in April 2008 its intent to undertake an international audit of the country‘s gas reserves, and first findings of this audit were announced in October 2008. While more appraisal work is needed to confirm the reserves, the vast South Yolotan-Osman field (this is now considered to be a single structure) could hold an optimum 6 Tcm of gas, with estimates for the field ranging from a low of 4 Tcm to a high of 14 Tcm.

As an alternative point of reference the CIA thinks that the reserves are only 2.83 Tcm.

It is the results of that audit that are now being questioned.

On October 12, two separate sources -- Russian journalist Arkady Dubnov, writing for the Russian newspaper Vremya Novostei, and a Germany-based non-governmental organization called the Eurasian Transition Group (ETG) -- alleged that the Turkmen government misled the independent auditors by providing them with inaccurate, hyped data. The end result was that Turkmenistan’s actual reserves are probably far lower than the estimate contained in the 2008 Gaffney Cline report.

However, while denying the accuracy of the story, the President purged the energy sector leadership, for reasons other than the above .

President Gurbanguly Berdymukhamedov has sacked the heads of Turkmengaz, Turkmenneft and Turkmenneftegazstroy for showing an "irresponsible attitude" toward their jobs.
Russian media outlets are linking the top-level purge to allegations that Turkmenistan’s gas reserves have been grossly overestimated.

As a result of the purge, Nura Mukhammedov is replacing Dovlet Mommayev as the head of Turkmengaz. Mommayev had held the post only since July. But, according to a Turkmen state news agency report, Mommayev was around long enough to be guilty of "a number of shortcomings and omissions."

Orazdurdy Hojamuradov was relived from his post of chairman of Turkmenneft "due to transfer to another job."

Berdymukhamedov charged Hojamuradov with "not taking the necessary measures to increase oil production" and allowing the state-owned enterprise’s production to be eclipsed by foreign companies that are "twice as efficient." Annaguly Deryaev, the former minister for the oil and gas development, is taking over the top position at Turkmenneft. Oraznur Nurmuradov was appointed oil & gas minister in his place.

?tamurad Durdiyev was sacked from Turkmenneftegazstroy. According to Berdymukhamedov, the state oil and gas construction company is failing to "cope with its tasks." Durdiyev is being replaced by Akmurad Egeleev.
The Russian newspaper Vremya Novosti reported that a number of senior figures are now under investigation following the delivery of confidential information to western companies hoping to invest in the Turkmen oil and gas industry.

The gas fields that were audited are not the ones that are being used to supply China, and China itself is involved in the assessment and production from those.

Having been given permission to develop the gas fields that will supply the pipeline. It will be developing fields along the right side of the Amu Darya river, itself part of the major gas field reserves found in the Amu Darya Basin.

“Turkmenistan guarantees that the Turkmen side will supply Turkmen natural gas in the volumes stipulated by the agreement,” the Turkmen president’s press service said.

“The Bagtyyarlyk territory is a major part of the promising gas area Sagkenar (on the right bank of the River Amu Darya)”, a Turkmen government official told ITAR-TASS on Wednesday.

Its gas reserves are 1.7 Tcm of natural gas, according to official data. The territory includes Samandepe and Altyn Asyr (Golden Age) gas fields. The former’s proven reserves are 100 bn cu.m. of sulphur-containing gas. The 500-square-kilometre Altyn Asyr has Bereketli, Pirguyy, Yanguyy and Sandykly gas fields, where seismic surveys have been recently carried out.

Having a quick look through Google Earth, the Amu Darya river is currently being extensively dredged in the region.

Amu Darya River showing the dredges at work (Google Earth)

There are several gas fields in Turkmenistan – the largest being in the Amu Darya Basin, with the Dauletabad-Donmez, which straddles the Iranian border. It is considered to hold around 45 Tcm of recoverable gas.

Other major gas fields in the Amu Darya Basin include Gagarin and Yelkui, which are to be developed, and more recent discoveries at Beshir, Chayyrly, Sarykum, Severnyy Yankui and Yuzhnyy Shorkel which have combined reserves of 10.2 BCM. Work on developing the gas field of Byashgyzyl, in the south-eastern Kara Kum region, began in early 1998 and the field's gas reserves have been estimated at 100 BCM.

Yangyguyy, a major gas field on the right bank of Amu Darya River, is to be developed as well.

There has also been some question as to the role of Gazprom in this whole affair. Until last year Turkmenistan was only able to sell the majority of its gas through Russia (it also sells some 8 bcm to northern Iran). This amounted to around 50 billion cu m per year, but as the IEA notes the Turkmen have only just started to get a decent price for their product (relative to what the Russians were selling it for – as I had noted in my earlier post on the subject).

Turkmenistan was receiving $60 per thousand cubic metres (tcm) for gas exports delivered at the Turkmenistan border. From the last quarter of 2006 the price paid by Russia increased to $100/tcm, then to $130/tcm in the first half of 2008, and to $150/tcm in the second half of 2008. Prices paid for gas from Kazakhstan and Uzbekistan have followed a similar trajectory.

In March 2008, Gazprom and the heads of the national oil and gas companies from Turkmenistan, Kazakhstan and Uzbekistan announced that trade in Central Asian gas would, from 2009, take place at European-level prices.

The problem is that Russia fixed the price, and it was significantly higher than the current price at which Gazprom can sell its product.

In fact Gazprom is in dispute with Western Europe because they are failing to purchase the volumes that they had promised in earlier deals, to the current tune of around 10 Bcm.

As a result there was no demand for the gas from Turkmenistan and so there was an accidental explosion in the pipeline leading into Russia, and no gas has been delivered since. Although there have been several meetings but apparently things are now so bad that even they have stopped.

For years, Gazprom has tried to monopolize gas supplies from Central Asia, but when European gas demand and prices dropped, Turkmenistan’s gas pipeline to Russia blew up just like two gas pipelines to Georgia a few years ago. Now, after the pipeline has been repaired, Gazprom refuses to accept the contracted volumes or pay the agreed-upon price. Therefore Turkmen President Gurbanguly Berdymukhamedov did not go to the CIS summit. Instead, the Chinese are filling the gap by building a large gas pipeline to Turkmenistan. China will buy most of Turkmenistan’s gas exports, as it already does from Kazakhstan.

The problem that will arise for the West if China does end up taking most of the natural gas from Turkmenistan is as to where they will be able to replace that 50 bcm delivery. This might be of greater interest to the UK, which is increasingly having to go the world market for natural gas, but given that Russia supplies most of Europe with a significant portion of their needs it is worthy of consideration. Gas from the Yamal Peninsula is not yet available, or even developed while the Barents Sea deposits are even further into the future. However that has not stopped Gazprom from getting half the pipeline that will deliver the gas to Poland.

Readers may note there has been a change in plan. I had planned to write about the changes since I wrote my OMNI letter tonight, but I will postpone that since this is more of a developing story, and thus of more immediate interest.