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 ??!!

Tech Talk - of Wheat and Coal

The release of the latest assessment of the IPCC on the future of the planet, failing their push to cut greenhouse gas emissions, has brought forth headlines and supportive editorials in papers around the world. Yet I could not help but note a couple of things that form the basis for this tech talk. The first was that the report discussed the impacts of climate change (for which I suspect in this case they mean global warming) on agricultural production. They stress the negative impacts on crops such as wheat, and so, being curious, I went to the Wikipedia page that provides a table of wheat production over the past eighteen years, and plotted the data.

Figure 1. Global wheat production in millions of metric tons (after the Food and Agricultural Organization via Wikipedia)

Clearly wheat production is growing rather than, as the IPCC report implies, declining with the increase in carbon dioxide levels and longer growing seasons in parts of the world. More to the point – which is providing more food – (h/t Joules Burn) the two staple crops wheat and corn, have both seen growing production, but it is the slower pace of growth of wheat (at about 0.9%) over corn (at about 1.6%) that is of current concern, and which is to be addressed with new investments in the International Wheat Yield Partnership that plan to more than double yields in the next 20 years. This is needed in large part to match the continued growth in world population, which is likely to continue to rely on wheat to provide roughly 20% of the calories that this population will consume. Gains come both from increased land acreage being used, but also from the yields of that land. In the UK, for example, yields now average 7.8 tonnes per hectare up from 2.5 tonnes in 1940, the current target is to reach 20 tonnes per hectare in the next 20 years. Given that the global average is still down around 3 tonnes per hectare, the ability to bring this productivity to the broader community will give significant help to feeding the world.

I mention this because of the clear disparity between this information and the way that material is presented by the IPCC. Further the real needs of the world and its nations are now increasingly being addressed with less attention to the strident demand of the more alarmist of those who push the climate change agenda, in part perhaps because of the overhyping of the message. The latest illustration of this comes from Japan.

Following the devastation of the tsunami following the Great East Japan Earthquake on March 11, 2011 the Japanese public has been very nervous about the use of nuclear power, banning the restart of 48 nuclear power stations until after a new series of safety checks. This has had two short-term consequences, the financial melt-down of the power companies, which is now being addressed through government bailout and the need to switch to alternate fossil fuels to replace the power that the country obtained from the reactors. The switch was largely to natural gas, and to oil but this has proved to be an expensive undertaking with companies feeling that they could only raise power prices to a limited degree, hence their need now for government funding.

Figure 2. The changing face of electricity supply in Japan following the Earthquake, (MIT technology review )

But the sustained high cost of the gas and oil is estimated to be costing the companies over $30 billion a year and even with the government bailouts this is not an acceptable long term solution, given that it is likely to be years before the safety changes are made in the reactors, and also given the continued public opposition to restarting the reactors. As a result the companies have sought permission to switch back to coal-fired power plants. Concurrently the Japanese Coal Energy Center has been looking for coal resources around the world ranging from Mongolia to Mozambique.

in 2012 Japan was the second largest of the coal-importing nations at 189 million tons (behind China at 289 million) and current plans are to increase the amount of power that the fuel will provide by roughly 20% through construction of new power stations. (Some of these will be needed since, while some nuclear power stations may come back on line others are proving to be too expensive to restart under the new codes, and thus will be permanently closed).

It is this clear benefit of cost that is driving the change, and that benefit is unlikely to disappear over the next couple of decades. The renewable energy industry has not been able to overcome the advantages of coal’s ubiquitous presence and low cost of production. In the case of Japan supplies are anticipated to come from Canada and the United States easing their dependence on Australia and perhaps helping reduce their costs as they develop more international suppliers. Glencore, for example, their Australian supplier, has now reduced costs to $88 a ton, from the $95 being paid last year. It is estimated that there is currently a glut of about 5% of the coal market, and the reduced demands for thermal coal in the United States and Europe is unlikely to change that picture in the short term.

The longer term remains more cloudy, since the potential for the United States to enter, in a significant way, the LNG market and potentially to change those supply costs is not yet clear. It seems, however, unlikely that the volumes that will become available will not have much impact on price, and if that remains the case then coal will continue to grow as the price differential continues to add pressure for the its use in generating cheaper electricity.

Whether this will change the recently better-defined coal resources off the British Isles into a reserve remains, in the short term, unlikely, but even in the UK power costs can only rise so far before the public complaints begin to have an effect.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

OGPSS - Natural gas pipelines and regulation

In the last post on this topic I covered some of the earlier developments in the use of natural gas (NG) as a lighting source, and began to discuss its evolution into a widely used fuel. That use, and the international marketing of NG has largely come about as the increasing use of pipelines has made it easier to move NG from places where it is overly abundant, to those where it is not. A recent example of this has been the Rockies Express Pipeline (REX) which carries NG from Colorado to Ohio, and thence to points East. Out in the West NG is still abundant and so well head prices are low – in 2009 for example it averaged $3.21 per kcf in Colorado. That same year in Maine the residential price was $16.43 per kcf. (against $8.80 in Colorado). The well head price in Ohio fell from $7.88 per kcf, in 2008, the year before the pipeline was completed, to $4.36 in 2009.

The Rockies Express pipeline (Kinder Morgan )

As new fields, such as those in the various shale layers that are now becoming popular, are opened they only become significant as the gas that is produced from the well is connected into a distribution network. Pipeline costs have been estimated as around $1 to $1.5 million per mile. After the pipe is in place it is often hard to see where it runs, in the USA at least.

Pipeline route over the Marcellus Shale, after installation

In 2009 the US used some 22 trillion cubic feet of NG (Tcf) moving ahead of Russia to again become the world’s largest producer and consumer. In that year the greatest production came from five Western states.

Top Gas Producing States in 2009 (NEED )

The need for a network to supply other states, less fortunate in this resource, has largely been met, with new pipelines being installed as needed. However it should be noted that just having the production does not, in itself, create nirvana, since earlier this year New Mexico and the Southwest suffered from shortages since demand exceeded available supply due to an unexpected cold spell.

Natural gas pipeline network around the United States (EIA )

This network has made it much easier to ensure that gas is available to customers, when they need it. And while this has recently become more of an issue, as natural gas turbines are installed to provide back-up power to more intermittent power generators, such as wind and solar farms, NG fueled electric power stations have been the most, in fact almost the only, new power construction in the United States for several years.

As the experience in New Mexico showed, just having a network of pipes in place is not, in itself enough. The first need is that the gas must travel down the pipes to the customers at a given volume, and this requires that it be pumped under pressure. Rather than creating the driving pressure purely at the input end, the pipe travels through a series of compressor stations that raise the pressure along the pipeline length, as friction would otherwise reduce it to below viable levels. For safety reasons gas pressure is reduced as the pipes travel through urban areas, and the normal operating pressure can thus vary between 200 and 1,500 psi. For those that forget Boyle’s Law from high school science, at constant temperature, raising the pressure by a factor of 6 will cause an equivalent reduction in the volume of the gas that is being pumped.

However, if you consider the network as a schematic you will note a couple of additional features.

Flow Diagram of the US Gas Distribution Network (EIA )

The two additions are for temporary storage of gas for use at times when demand is high (Oops none in the Southwest - tsk !). The gas can be stored either as a gas, or it can be cooled to a liquid (which reduces the volume by a factor of 600 and stored in that form. The LNG facilities need a re-gasifier, and, if they are taking the gas from a pipeline, also a liquefaction unit to do the initial conversion. By using these facilities that are dotted around the country, pipelines don’t have to be as large to ensure that there is enough gas for the consumer at the high demand locations around the network.


Locations of storage facilities for natural gas including LNG import terminals (EIA )

I have used a map that shows the location of LNG import terminals, since this is an additional source of NG for the United States. Again the volume that is involved is a function of price, though often, to justify the cost of the parts of the supply train, there is a concurrent long-term commitment to a given price schedule, so that spot prices are not necessarily that valid, and what is paid in Japan, for example, is not indicative of prices elsewhere. That is particularly true at present since the loss in power from the nuclear reactors in Japan is expected to result in a long-term increase in LNG demand to replace the lost power.

Variation in the price of LNG in Japan (Mongabay )

As I write this the current quoted import price for LNG into the United States is $6.78 per kcf some $1.71 over the quoted Henry Hub price for NG.

One of the most powerful drivers in the growth of demand for natural gas has been as a result of its increased use in generating electricity. This is particularly evident as it takes market share from coal-fired power stations due to concerns over the emission of greenhouse gases.

Nationwide, coal-fired electric power generation declined 11.6 percent from 2008 to 2009, bringing coal's share of the electricity power output to 44.5 percent, the lowest level since 1978. Coal consumption at U.S. power plants paralleled the decline in generation, dropping 10.3 percent from 2008.

In sharp contrast, natural gas-fired generation increased 4.3 percent in 2009, despite the 4.1-percent decline in overall electric generation. The natural gas share of generation increased to 23.3 percent—the highest level since 1970. Electricity's share of the total U.S. natural gas consumption has also risen rapidly, growing from 17 percent in 1996 to over 30 percent in 2009

There is a greater capacity for gas-generated power than these numbers reflect, since the utilities still tend to use coal over NG for longer-term operation as the costs are lower.

The growth of this market developed after the Second World War, and the development of a distribution network. However in the years immediately after the war the industry was heavily regulated, both in terms of price and volume, in much the same way as the Texas Railroad Commission had regulated oil. But because the gas entered and left inter-state pipelines it was regulated under the Natural Gas Act of 1938 which among other things forbade the construction of a new interstate pipeline into a state that already had one. In 1954 the Supreme Court voted that the FPC should set wellhead prices for NG. This removed some of the incentive to develop new wells, and from then until 1968 production and prices remained relatively steady. In 1968 however reserves fell from 20 Tcf to 12 Tcf, and in 1969 they were down to 8 Tcf. With the industry still controlled, reserve additions failed to keep up with demand for the next 12 years. However the Arabian oil (and gas) embargo imposed in 1973 led the price of NG to multiply 750% between 1972 and 1976. Consumption fell at these higher prices, and the market re-equilibrated until 1980. But the over-regulation of the industry led to serious problems.

The interstate pipeline experience during this period was an unmitigated disaster. To deal with the shortages in the interstate market, interstate pipelines submitted curtailment plans to the FPC describing how they would determine who got gas and who did not. The plans gave top priority to residential consumers. Boiler fuel users, such as electric utilities, were given lowest priority. Users who experienced curtailed deliveries could either shut down their operations or switch to alternate fuels. During the winter heating season of 1977-1978, gas deliveries in New York and New Jersey were curtailed for everyone except residential consumers. Commercial users received only 94.3 percent of requirements, industrial users only 79.2 percent of requirements and electric utilities only 13.5 percent of requirements.

Just as the regulations were being changed to help resolve these problems, and de-regulate wellhead pricing, the Shah of Iran was overthrown, and prices took off again. This encouraged new drilling and in 1981 for the first time since 1968 more gas was discovered than was consumed that year. Unfortunately this happened just as the rise in prices was moving consumers out of the product. The result was a drop in demand, which bottomed out in 1986. With the increase in supply this generated a “gas bubble.” In 1986 the Texas Railroad Commission changed the rules to ease sales of the gas to end users rather than just the pipeline companies, at the same time the Federal Energy Regulatory Commission began the series of changes that, by 1992, meant that you no longer had to own a pipeline to be able to buy natural gas.

I’ll write about where that took us, and the evolution of the gas producers and market as I continue with this short topic next time.

Biofuel in the air and expensive gas on the ground

There are a couple of items in the news today this week that mark the face of a changing world of energy supply. Of the two the increasing problems that the United Kingdom are facing with maintaining a viable energy program into the future is being marked with an escalating cost and the need for politicians to begin walking back from some of their previous statements. The other is the decision by Lufthansa to use a biofuel mix as a regular fuel for scheduled flights. The latter decision is a little more complex than it first appears, since the logistics of supplying the fuel mean that the aircraft (which will fly the Hamburg to Frankfort route) will only be fueled at one airport, and – to facilitate the monitoring of maintenance and other possible impacts – only a single plane will initially be involved in the trials., which will go on for six months. The testing can now begin since the standards for the fuel have now been approved by ASTM.

After blending with conventional jet fuel, new lubricity, distillation and composition requirements in D7566 must also be met. As a result, the blended jet fuel used in the airplane is essentially identical to conventional jet fuel and does not differ in performance or operability.

The biofuel will be supplied by Neste Oil, which has declared a target of 2 million tons (around 40,000 bd) of jet fuel by 2020. Given that this is a 50:50 fix of biofuel and kerosene to meet the above standard, lowers the volume of biofuel needed, with the source described as:

Produced by hydrotreating renewable raw materials, NExBTL aviation fuel is compatible with all aircraft engines currently in use. Production is based on Neste Oil's proprietary technology, which can make use of a flexible range of various types of vegetable oil and waste-based inputs, such as animal fat from the food industry. Neste Oil is committed to only using verifiably sustainable and fully traceable raw materials that can be tracked all the way back to the original source.

In the United States there have been single plane flight trials, with the “Green Hornet” (flight video ) using a mix that included camelina oil .

Turning from the good to the rather more worrying topic, the British gas industry is in the process of raising natural gas prices by some 18%, which also feeds through into the price that they charge for the electricity generated by the gas, and also supplied to customers. This is occurring at the same time as a report from a British car insurance firm has concluded that the increased price of gasoline (petrol) in the UK has driven some 1.3 million people (out of 31 million registered drivers) off the road, with the cost of car operation reaching $4,800 a year. This is an increase of over 20% in a year, and when taken with the rising price of natural gas is an illustration of the costs that are being incurred as the UK moves more strongly from an exporting to a fuel importing nation.

The U.K. Government is beginning to realize that, without a sufficient domestic resource, they are constrained to pay what the rest of the global community decides is a proper price for their fuel. The UK Government is putting forward a plan that will increase the emphasis on nuclear power and renewable sources of power. The problem is that, to comply with EU rules, the UK is going to have to close a quarter of its generating capacity this decade. The eight nuclear power stations that it is now anticipating private industry will build (though there is some doubt) won’t come on line until perhaps 2025.

Possible Nuclear Power Station locations in the UK (LSE )

In the interim the problems to the consumer of the rising price of natural gas is perhaps being reflected in the same way as it was for gasoline, namely a reduction in demand. In the first quarter of this year, while coal use rose (albeit with two-thirds of the supply imported) by 7%,, the demand for gas fell 20%. Renewable energy sources increased supply by 27% but this should be placed in the context that the overall contribution from renewables was only 3.3% in 2010. Demand has been met by coal

Power companies have been benefiting from local coal production, however, with the small but active number of British facilities recording a 31% increase in output in the first quarter. Deep-mined coal showed an 80% rise as stocks were depleted due to demand from the utilities.

The problem, unfortunately, remains that the coal-fired power stations are going to be pulled off-line soon, and so the cheaper coal-fired power will not be available, and (providing that there are power stations available) the reliance on natural gas will continue to drive prices higher, which is likely to be increasingly unpopular with the British public.

However the first large solar farms in the UK are now on line, although with a combined output of 2.4 MW they are not likely to have much impact on overall supply.

That lesson (of increasing prices costing politicians their popularity) has already been cited as one reason for the release of oil from the Strategic Oil Reserve in the United States. Unfortunately it would appear that this release, coming with the increase in demand that I have referred to earlier, has not had the hoped for impact on oil prices. And, equally unfortunately, that action is still some months before the elections of next year.

The British experience is beginning to show that demand can be curtailed by price, but that still requires that there be an adequate supply to meet such demand. The problems with finding reliable power sources by 2015 for the British electricity suppliers is beginning to become evident and will likely further influence political popularity there. But the UK does not have to hold a national election for some years. That is not the case in the United States, even though the prices of gasoline and natural gas are still well below that of Europe, but where the public is more sensitive to those numbers, and where the elections are a whole lot sooner.

Russia, Ukraine and the annual gas game

There is a developing tradition at the end of the year, in which Russia gets into a spat with Ukraine about the payment of the Ukrainian gas bill. Gas supplies are curtailed to Ukraine, which immediately passes on the cuts to the Western European nations on the other end of the pipeline, and there is a short-term, very public row, at the end of which gas supplies are re-started and the situation gets pushed under the rug for another year.

In trying to develop a longer term solution to the problem, Gazprom (the Russian gas company) and its partners have been developing two pipelines, one around the North, and one following a Southern route, to bring natural gas to Western Europe without going through Ukraine. Austria was asked to join the southern branch (South Stream) today. At the same time the West has been trying to line up enough gas supplies to run its own pipeline from Azerbaijan and Turkmenistan into Europe without going through Russia; the pipeline is called Nabucco.

None of these pipelines is yet in place, and so, as the winter season starts to arrive one would naturally begin to worry that the traditional drama would play out again this year. Thus Gazprom has hastened to proclaim, in an interview with Bloomberg that this year will be different. Ukraine is paying its bills each month, and as long as that continues then gas will continue to flow. Although, at the same time, there have been the usual heavy hints that if bills aren’t paid then taps will again close. And Ukraine is hinting that to meet those bills it will need money from the International Money Fund. However it is also seeking a loan from Europe. And the latest comments from Ukraine suggest that this years bargaining round is only just starting. The reassurances that Ukraine is providing, while superficially calming, also retain the caveat that could warn of future problems.

"Ukraine is ready to comply with its obligations on gas transit through its territory within the next half a year at least," he (Ukrainian presidential envoy for international energy security Bohdan Sokolovsky) said at a press conference in Kyiv on Nov. 9. . . . . Having 27 billion cubic meters of gas and repaired gas transportation system, Ukraine can guarantee the transit of the Russian gas provided it comes to Ukraine's GTS (Gas Transportation Services)," he said.

It’s that little catch phrase at the end that always seems to generate trouble.

UPDATE: Coincidentally Jerome has written an article that explains in much greater detail the background to this situation and yet comes to somewhat the same conclusion I draw. His article is well worth the read in understanding why, however.

And unfortunately it has been trouble in the pipelines supplying gas either to or from Russia that has caused earlier problems around the Russian perimeter, and there seems to be no indication that this year will be any different.

Unfortunately the situation is not that cut and dried. I have written about the concern that Turkmen gas, normally a significant supplier, through Russia into Ukraine, may not be available this year. Further the drop in prices and demand for Russian gas is giving Gazprom some financial problems, since they have not sold some 8.5 billion cubic meters of gas or so that they had anticipated, on top of the actual 142.5 billion cu m they actually have sold the west this year to date. (In context Gazprom would normally sell about 45 bcm to Europe in the fourth quarter, and that is about the amount of gas that they normally buy from Turkmenistan in a year). Because of the contract sales language Gazprom is thinking of fining its customers for not buying their full allocation.

And as Turkey and Azerbaijan negotiate on getting Azer natural gas for the pipelines through Turkey, the prices for transport that are being negotiated appear similar to those that Russia charges:

According to him,( Turkish Minister of Energy and Natural Resources Taner Yildiz) Turkey has offered Azerbaijan a fee of $2.36 per 100 km for transporting every 1,000 cubic meters of the South Caucasus republic’s gas.
“The proposed fees are completely competitive. Russia charges $2.6 for transporting the same volume,” the Turkish minister said.

We recall that during the “gas war” between Russia and Ukraine this January, Kyiv sought to raise transit fees for Russian gas giant Gazprom to $3 per 100 km in case prices for Russian gas increased.

The attempts by Ukraine to get that higher fee have not stopped.

Meanwhile Russian companies are coming under pressure to reduce gas flaring since Prime Minister Putin sees this as a loss in revenue. At the moment Russia is flaring about 20 bcm a year (apparently about a third of that which comes out as a byproduct of Russian oil production).

Incidentally, in regard to my earlier post on Saudi Arabian production, Platts ( has noted that it is not only Asia that saw the reduction in Saudi exports, but that the United States also got a reduced allocation, with imports falling to 745 kbd in August. Whether this is a simple monthly aberration or portends something more dramatic, only time will tell.

An interesting, and worrying talk at ASPO

Unfortunately I have had to miss the ASPO Meeting in Denver this week, and so cannot provide the daily reports that I have written in the past. But I notice that at least one of the talks has already caught a significant amount of press, and that is the one by Arthur Berman on the gas production from shale deposits such as the Barnett, Haynesville and Marcellus.

There has been a considerable hype in the press about the value of the gas from these shales, and the ability that they provide to bring in an “Age of Natural Gas”. Commenting on the situation last year, the CEO of Chesapeake noted

"the U.S. today consumes about 63 billion cubic feet of natural gas per day - in energy BTU equivalency terms, that’s 10.5 million barrels of oil per day, or about half of the amount of oil that the U.S. consumes each day. Of that 63 bcf per day of natural gas consumption, we import about 1 bcf in the form of liquefied natural gas, or LNG, and we import about 8 bcf per day from Canada. This means that we are about 98.5% self-reliant on natural gas supply from North America and about 86% self-reliant on natural gas supply from the U.S. Contrast that with oil, where we are only about 41% North American self-reliant and only about 27% self-reliant from U.S. sources."

This picture of a large supply of natural gas has been strengthened by the increase in production from a number of the gas shale fields, at the same time that the recession hit, and as a result there has been more gas available than needed, and the price has dropped considerably as a result. This, in turn, has led to a considerable reduction in the number of rigs that have been drilling new wells.

Natural gas has been steadily increasing its share of electricity generation, rising to over 20% of the market, on its way to 25%. Natural gas is favored because of its reduced carbon footprint over coal, and it has historically been used since it is somewhat easier to start and stop gas turbines than it is coal-fired power. Thus natural gas is seen as a favored backup to the installation of wind farms, where the vagaries of the wind are backed by the ability to use natural gas when needed.

There are, however, considerable concerns about the ability of wells in the gas shale to produce to the targets that are being set up. I first noted Arthur Berman’s concern about this back in 2007 when I drew attention to a piece he had written in World Oil, where he noted the short life of most of the gas-producing wells; the very high costs for the wells and technology required to create them and, as a result, that only 28% of them return a reasonable profit. (Unfortunately the article itself is now behind a paywall).

Since then I returned to the topic at Bit Tooth showing, among other data, the very high decline rate (now 60%) of many of the gas wells in Texas (where the Barnett shale is) that Swindell has reported.

First year decline rates of Texas natural gas wells (after Swindell)

There is further disquieting news that is now coming out of the Barnett field. The Ft Worth Weekly has just reported that many of those who expected to make substantial amounts of bonus money from drilling companies using their leases have had the agreements withdrawn and lost their money.

In April 2008, the Southeast Arlington Communities of Texas (SEACTX) negotiated a deal with XTO Energy that would bring in bonus money of $26,517 per acre and a royalty rate of 26.5 percent - among the highest in the Barnett Shale play. When leaders of SEACTX, representing about 7,000 property owners with about 5,000 acres, did the math, they figured that more than $100 million in upfront bonuses would be coming into their community of mostly modest to middle-class neighborhoods. . . . . . . . . . Well, that was then and this is now, when natural gas prices have fallen to less than half what they were in early 2008. And as anyone who has been following the Barnett Shale saga knows, drilling companies pulled out of those deals and others in mid-October of last year. Some property owners, whose bonus checks were processed prior to the cancellation, got paid. Tolli Thomas, a spokeswoman for SWFA, estimated that 4,000 to 5,000 people in her area got the money promised to them - and the other 20,000 or so did not.

Prices for drilling these wells run on the order of $5 million apiece, and Chesapeake has, in the past, noted that it takes $4.00/kcf to bring in enough money to cover those costs – with a good well. (Note that this is the Henry Hub price, consumers should add about $3 to this to get the residential price). Those numbers are considerably higher than the ones that Mr Berman used with his calculation two years ago that only 28% of the wells will be financially remunerative.

He recently (April 2009) expressed similar concerns about the Haynesville wells – though his production decline numbers are stunningly higher – as much as 20-30% in a month, for an annual decline rate of 80-90%. The costs that he cites are up at the $7.5 to $9.5 million range for the wells, with a net final cost that the producer has to pay in the region of $7.25/kcf. He therefore concludes that the breakeven point for wells in the Haynesville lies at a price of around $9/kcf Henry Hub; with a minimum reserve of some 2.5 Bcf. He upgraded that opinion in June expressing a concern, that I echo, with the availability of natural gas from a variety of sources (including the Rocky Mountain Express and increased LNG shipments) which will make it difficult to sell gas from formations such as the Haynesville, at a profit.

In his most recent post on the subject some of the possible reasons for the rapid decline (which fall a little along the same explanation as I gave on chalk collapse) which are as follows:

An abnormally high-pressure gradient (0.7-0.9 psi/ft) distinguishes the Haynesville from other shale plays. It may also explain the extremely high decline rates, as pressure depletion transfers stress to the rock and allows proppant-filled and open fractures to compress, thereby reducing the effective reservoir permeability.

Unfortunately for the hopes of a new age for gas, in preparation for a meeting on the Haynesville production last week, he had calculated the numbers for some 67 wells in the Haynesville and was still coming up with decline rates of 25% a month.

He also noted

The average EUR in our study is 1.72 Bcf/well, compared to the 6.5-7.5 Bcf/well reported by many operators. Only two wells of the 67 evaluated have an EUR greater than 6.0 Bcf. At the same time, seven wells have already produced more than 2 Bcf and one has exceeded 4 Bcf.

Petrohawk has the best well performance with an average EUR of 3.4 Bcf/ well (19 wells evaluated). Chesapeake has the most wells on production (29 wells evaluated) but we project an average EUR of only 1.2 Bcf/well.

It sounds as though I missed a really interesting and valuable talk – just have to wait for the DVD’s to come out, I guess!! But in the meantime I have added his site to my recommended reading list, over on the right.

I'm also going to have to reorder some of the technical talks on Sundays so that I can more fully explain his concern about the Haynesville shale.

Reserves and Resources

In trying to estimate the size of the problem that will face the world as the available reserves of fossil fuel begin to decline, one has to make some assumptions about the size of the volumes that are available. It is a debate that can lead to people talking past one another if they make different assumptions about the size of those reserves. This holds true in discussions that dot the web sites of those that write about energy, whether writing about oil, natural gas, coal or uranium.

This current post was motivated by a couple of different stimuli, firstly there was an article on Seeking Alpha about the natural gas reserves of the USA and then I was asked a question about the coal reserve assumptions for Alaska.

The natural gas article illustrates, in some ways, the problem of discussing the remaining gas that the United States has available, and whether we have a problem in future supply. With a consumption of around 23 tcf per year, it questions whether the remaining gas reserve is 337 tcf or 1,747 tcf. It was followed, interestingly, by a second article on natural gas that points out the folly (as it turns out) of being in the natural gas market this past year, as an example of the “no free lunch” argument.

“Natural gas is probably the best demonstration of the ‘no free lunch’ law in commodity indexing, as evidenced by the S&P GSCI Natural Gas Index which commenced at 100 in January of 1994, ended September at 2.63. Over the same period, the natural gas future has increased about 125%. While 2008 served as a strong reminder ‘to know what you own,’ 2009 has reminded investors ‘to know how to be properly exposed to commodities.’”

This ties into estimating the size of the reserve, because, in raising money to develop reserves, you have to be confident that the money that you invest will give you a financial return on that investment. If the price of natural gas has tumbled to $3 or less (per kcf) then you may not make that return, and may even lose money. You will therefore look more cautiously at what are potential sources and be more selective on where you drill. Some of the more questionable areas will no longer be sites that justify the investment. And thus these areas move from being in the reserve account into that of being a resource that is available, but not justifiable as being exploitable AT THE PRESENT TIME.


Yes I know I was shouting, I did because it is that qualifying clause that gets overlooked time and again when discussions arise over what the fossil fuel base is for the world. The condition as to whether the volume has enough worth to justify being developed changes with conditions. Coal in the UK had a considerable future before the oil and gas reserves of the North Sea were developed. At that time the reserve was proven at over 45 billion tons and the coal was being mined at around 200 million tons a year - but times change, and the cheapness of the liquid fuels, relative to the cost of mining, meant that a lot of the coal, although still there, is currently too expensive to produce – relative to the alternative. It is thus no longer counted as being part of the reserve.

Now this gets into the climate change debate a little, since one of the arguments that are raised is that the users of coal do not pay the full price, since the price they do pay does not include some of the social and environmental costs associated with burning the product. Since the customer ultimately pays for the product, this seems in part to be an argument to justify raising the price of coal based energy to the point that other sources become cost effective. The problem is that in some locations it is hard to find current technologies, even at cost equality, that can provide a replacement for coal as oil and natural gas supplies run down.

Which gets us back to the question as to how much of a reserve of oil and gas we have, and how long will it last before we have to face the reality of a return to coal.

And this is where the price of the product controls, transiently, the volume of fuel available. In the short term natural gas prices are down and it becomes harder to justify continuing to drill new wells, if they aren’t going to make money. But as more folk stop drilling, then with the very transient life of the existing wells, the supply will shorten, and after the stored volumes begin to be used up, then prices will rise to the point that an effective market can be reestablished. How long will that take?

Probably until sometime next year is my current guess, though it depends in part on how hard a winter Europe and North America experience this year. (And since that is weather and not climate I’ll hold off on making that prediction today).

In the longer term there are so many power plants that now rely on natural gas that demand will sustain a higher price, and lead to an increase in the drilling rate, until price:supply and demand reach a more stable platform. At that time the reserve volumes that are currently moving into the resource category will start to move back and the projections for a longer “age of Natural Gas” will start to assume a little more reality.

However I would like to throw a small caveat into that debate, at the beginning of the year the SEC changed the rules for counting the validity of an oil or gas resource, loosing the requirement that the fuel be “proved” to be there. The ramifications of that decision are likely to have some impact on this debate.

Oil up, gas down, and Hurricane season is here

I had meant to include the weekly plot of gasoline demand in the last post, that began by talking about the hybrid, but somehow the post drifted into a different direction and I ended up not including it. The graph, from this week’s TWIP, showed that gasoline demand is really remaining fairly constant at a rate slightly above last year(and in about the same relatively flat condition), though you might want to recognize the significant difference in price. This time last year was about the time that price peaked.
Gas demand over the past year (EIA TWIP)
Gas prices over the last two years (EIA TWIP)

The question on where it goes from here does depend on the way the global economy goes, though as you gather, in the case of gasoline, with the spread between supply and demand now controlled by OPEC, I expect that there will be a slow but steady increase.

Natural gas, on the other hand is another story. The Natural Gas Weekly (NGW) report is out today, and shows the slow but apparently inexorable decline in prices is continuing.

Natural gas prices against oil prices (EIA Natural Gas Weekly)


This steady decline in gas prices, which may well continue if there is the influx of LNG at year end, has the potential to significantly hurt the developing production of natural gas from the gas shales. As I previously noted, Chesapeake may well be able to produce from these formations at less than$4 a tcf, but once the price gets down to $3 or so, then I suspect that those bets are off.

The NGW is not very comforting in that regard, noting that

At $3.41 per MMBtu on Wednesday, July 29, prices at Henry Hub were $9.17 per MMBtu, or 63 percent, below last year’s level at this time. Current spot prices at market locations in the lower 48 States average about 62 percent below year-ago levels.

As a result there has been a further increase in storage injection, significantly above the 5-year average figures. The NGW blames this on the unseasonably cool temperatures:

Relatively mild temperatures in each of the Census Divisions in the lower 48 States during the week ended July 23, 2009, likely contributed to the above-normal level of injections into storage. Based on the National Weather Service’s degree-day data, temperatures in the Lower 48 States during the week were, on average, more than 2 degrees cooler than normal and 4 degrees cooler than last year’s levels.

Whether this has anything to do with the lack of sunspots, and the consequent slight drop in received sunlight is a topic for another day. (If the colder weather continues into the winter, then the drop in demand for air conditioning may be compensated by the increased need for heat). Though the stubborn refusal of the global temperature to follow the steadily increasing curve that has been predicted by the AGW models is becoming remarkable.

That difference with prediction is also evident from the subject of the TWIP front page this week, which dealt with the amount of oil from the Gulf of Mexico (GOM) that gets shut in each season due to hurricanes.

Impact of Hurricanes on GOM production (EIA TWIP)

The slow decline in overall production is partly because of the loss of smaller and older producers following recent major hurricanes – production too small to justify the redrilling of wells, and also it is because the fields near the coast are well defined and exploited, and are in overall decline. But the risks from hurricanes are clear, when the platform locations are examined.

6357 oil platform locations in the GOM

The question that the TWIP asks relates to the likelihood of there being strong and frequent hurricanes through the platform-intense regions this season. So far, with the cooler relative sea temperatures there has not been the activity of more damaging years, but the TWIP quotes NOAA as predicting a slightly higher than normal season, with a consequent transient outage of 4.5 million barrels over the season. However the recent identification of this as being an “El Nino” year may change that prediction, though we won’t know until next week, August 6th to be precise.

Whether storms are increasing in severity has been a subject of debate, following such a prediction in “An Inconvenient Truth” , but the data apparently does not show that there has been an increase in storm energy but rather the reverse.

Historic trends in Cyclone Energy (Ryan Maue )

And, as far as oil and gas production from the Gulf is concerned it is only going to take one strong hurricane with the wrong path and, as historic experience has shown, production can be really impacted. (It took years to get the Thunder Horse platform back into commission after it was damaged by Hurricane Dennis in 2005, and the 250,000 bd of oil and 200 mcf of gas production temporarily lost).

The season is yet young, and we’ll just have to wait to see what transpires.