OGPSS - A review of North American future production

This is a good point to recap the intent of the current series of OGPSS articles. Internally, this marks the end of the segment that has dealt with North American oil and natural gas production. The series is not an in-depth review of individual fields but rather seeks to paint a broad background against which to judge the realities of the coming changes in the global supply:demand balance. More detailed discussions are provided by the excellent analysis of such folks as Jean Laherrère, who is even now examining in more detail the production records from the wells in the deep waters of the Gulf of Mexico.

Perhaps more critically, it comes when there are increasing indications that the investment being placed on renewable energy around the world as a replacement for fossil and nuclear power generation might not be adequate to meet the need. For example, this week the British Institution of Mechanical Engineers has pointed out to the Scottish Parliament that their renewable targets for 20% total energy and 100% of electricity production by 2020

did not appear to be supported by a rigorous engineering analysis of what is physically required to achieve a successful outcome in the timescale available.

It is relatively easy for politicians to promise that energy supply is adequate into the foreseeable future. Euan Mearns, for example, has repeatedly written, and guest hosted articles on The Oil Drum which show that supply requires infrastructure and planning over many years, without which (and the absence is evident) those promises become not only unrealistic, but also unattainable.

Just as I wrote this, the White House announced that the decision on the Keystone pipeline would be postponed until after the election next year. In a sense the Administration view echoes the opinion of one of those opposed to the pipeline:

“It’s not like we’ll have an oil shortage,” said Mark Lewis, a partner at the law firm Bracewell & Giuliani who specializes in oil and gas pipelines. “We’ll continue to get product from the sources we get product from.”

If Canadian tar-sands oil moves to Asia, Lewis said, then the U.S. would just continue getting its oil from regions like the Middle East. And the Canadian oil sands would most likely still be developed, with that product entering the same global market.

This series is testing the truth of those remarks and that opinion by looking at the realities of future production and the oilfields that it will come from. As mentioned above, this began with a look at the resources of North America, and it is time to review what was found.

When this series began last April it set out to look at the potential future changes in the North American oil and natural gas supply there were three different parts to that supply. The first is the historic oil, that coming from existing wells and fields, often coming from stripper wells around the country. Then there were the supplies from fields that are currently being developed, and where production is continuing to rise, such as in the Bakken fields of North Dakota and Montana. And then there is the potential that will come from finding and developing new fields in the relatively near term. Perhaps as an indication of my own “Oops” moment, I used the Energy Plan proposed by Governor Perry to illustrate the potential future additional fossil fuel that might be available over the next two decades. That was very similar in promises to a Wood MacKenzie Report prepared for API, and released in September. To give my comments on those projections, I will look first at the summary of projected increase in oil production from that report. This is divided into two parts, the first assumes that current policies continue, and it sees energy supply growing as follows:

Total US Production – using current conditions. (Wood Mackenzie )

The plot shows an increase in oil production from 2010 to 2030 of some 1.2 mbd, which in the overall scheme of things is not really that much change from the present over the twenty year time interval (0.7% per year). Natural gas, on the other hand is expected to rise some 14.4 bcf/day (1.2% per year) which is a little more impressive.

However, if all the wishes of the industry were to come to pass, (the development policy case) then Wood Mackenzie sees considerable potential for supply growth.

Production with an accelerated development program (Wood Mackenzie )

In that developed condition Wood Mackenzie sees oil production increasing 7.6 mbd to 15.4 mbd by 2030, while natural gas production rises by 36.8 bcf/day to 96.9 bcf/day.

The first concern that I have with these plots is that of the declining reserve. In previous posts I have discussed various estimates for the decline in production that occurs in existing wells over time. This occurs with both oil and natural gas wells, and changes with rock type, well type and other factors. For example a recent post by Fractracker on the performance of 756 Marcellus wells notes that horizontal gas wells declined an average of 39% in the last year, while vertical wells declined 47.6%, though those numbers do not reflect wells that were closed because they were no longer producing (16.7% of the horizontal wells and 6.9% of the vertical wells). Figures from other gas shales have reported decline rates in the Haynesville, for example, of 85%. In conventional oil wells (and reservoirs such as the Bakken are, for this discussion, considered as unconventional) the decline rates now lie above 5% . What this means for US production is that, just to stay even, the industry has to add at least 360,000 bd of new production each year, to maintain a roughly 7.2 mbd level of total oil production. (and that is likely to be, at best, the average gain in production over the next ten years from the Bakken and Niobrara combined).

So where does Wood Mackenzie see the gains in production from the “development” case?

Regions where additional production may be obtained (Wood Mackenzie )

The problem that the map shows is that much of the new discovery and development is anticipated to come from the offshore, whether it is East Coast, West Coast, Gulf of Mexico or Alaska. In comments on the post discussing drilling off the Atlantic coast, my quote on it taking four to ten years for production following the start of leasing led to kindly admonishment by Art Berman, Harry Flashman and Rockman on the overly optimistic view that this represented, with the reality of development being more likely to occur over decades. This holds even more true for resources off the Alaskan coast, where the on-land infrastructure is not currently in place. And it fails to recognize the antagonism that state governments (such as those I mentioned from New Jersey) have to offshore drilling on both coasts.

The current increase in oil production in the United States is, in part, due to the development of long horizontal wells, with multiple fractures along those wells to improve flow to economic levels from shales that were previously uneconomical to drill. As long as enough production can be achieved from such wells to keep them viable for the oil industry they will be developed. When they cease to be then they won’t. The rapid decline rates that are found for these wells (as was shown in the posts on Bakken and Niobrara) mean that as production moves from the sweeter spots in the reservoirs out to the leaner fringes, a point will be reached, in a few years, where those economic factors will come into play. As that time approaches the price of oil (for a variety of reasons) will be sufficiently higher than it is today to encourage greater overall production than might be anticipated from today’s figures, but it will be nowhere near enough to meet the levels of US demand. And it will still curtail overall production.

The gain in production that Wood Mackenzie sees in moving to the “development phase” does not really kick in, were all things to come to pass, until about 2016. And even then the main initial gains are assumed to come from the easing of regulations, which is, I rather suspect, a wish, rather than any reflection on what might realistically happen.

Possible gains in future production over the current condition (Wood Mackenzie )

The delay in granting permission for the Keystone pipeline will shift some 700 kbd of US supply out another year at least. But that does bring up the issue of the oil sands. They are the one source where the deposit size is known and adequate, and where gains to help meet demand could be achieved. However, with the delay and possibly even denial of the pipeline, it is now quite possible that the Canadian Government and the other parties concerned might hear again the same blandishments from China that persuaded the Turkmen, and when we finally get around to giving grudging permission for Canada to sell us more oil, that additional tar sand oil may already be heading overseas through pipelines running west.

Whether, at that point, we can then

continue to get our oil from regions like the Middle East

is a point that I will look at as this series continues, and we start to examine the long term potential of sustained oil supply from regions overseas.

Oh, and a quick P.S. for those who remember the post on the Alaskan pipeline, in August it was running at an average of 538,623 bd, with the annual average now running at 568,471 bd.

Shales and the gas within them

This is Sunday, so this is a technical talk about getting fossil fuel out of the ground. While some previous posts have dealt with sandstone and carbonate deposits I’m going to be talking about getting gas out of shale for a couple of weeks, and so, before I started talking about Horizontal Wells, we’d better chat for a minute or so about shale. And when I don’t give an alternate reference for the information, I am likely quoting from the Primer on Natural Gas in Shale, from the Department of Energy.

Folk who live near rivers, or along their outlet to the sea are familiar with the large mud flats that can develop around the outlet. These flats, which extend out into the sea, can cover large areas. When I was in school at Lancaster in the UK, we went to Morecambe Bay when my parents came to visit, and the large areas exposed when the tide ebbed remain a lasting memory. Through geological time these beds of mud have lain under large stretches of water, and so, at the algae that float in the water died, so they fell, and were caught in the mud. The mud is largely made up of clays, which in very small sizes are shaped a bit like a plate, and so as they settle, capturing and covering the algae remains, they tend to create layers (which can later tell us some of the conditions at the time they were deposited). When conditions are right – generally with a relatively warm sea containing a lot of nutrients – the sea can host vast colonies of algae, and over geological time the death of these algae built up considerable organic matter in the mud on the sea bed.

The main gas shale deposits in North America are in the Barnett shale, the Fayetteville, the Woodford, the Haynesville, and the Marcellus while, in Canada, the large fields are in the Horn River and Montney deposits. Not that there are not others, but these are the ones that the Oil and Gas Journal calls “The Magnificent Seven.” As an example the Barnett shale was deposited during the Mississippian Epoch, itself part of the Carboniferous Era, between 315 and 350 million years ago. At that time the map of the Earth looked at bit like this ) .

Shape of the Land and Seas at the time of the Mississippean Epoch

However not all the shales were deposited at that time. The Haynesville, for example is much younger, having been laid down in Jurassic Era, (remember the dinosaurs of Jurassic Park?) which was some140 to 200 million years or so ago, and when the globe looked a bit more familiar.

The map of the earth some 195 million years ago during the Jurassic

The mud that was deposited grew to be very thick – even after it was compressed by the weight of overlying additional sediments that turned into rock, the Barnett shale still can measure between 50 and 600 ft thick.

The individual particles that made up the mud were quite small, so that, as the material was compressed, the resulting rock became relatively impervious. Thus if the gas-generating algal remains were trapped, they were held in the shale, but dispersed throughout it, rather than concentrated in larger pore spaces, such as are found in sandstones. And, to be economic, there still needs to be a significant amount trapped within the pore space, which needs to be at least in the 5 – 12% range to hold enough gas to be worthwhile. Putting this into a different context, the Barnett, for example, is estimated to hold about 325 scf (cubic feet at a standard defined temperature and atmospheric pressure) of natural gas per ton of rock – or in about 13 cubic feet of rock. (Needless to say deep in the ground the gas is very compressed).

As the rock was buried deeper, so the temperature and the pressure also rose, gradually “cooking” the organic material over time. Depending on how deep the rock was buried, and the temperature, the material either turned into an oil, or if it were buried deeper and at a hotter temperature, it would turn into a gas. The relative conditions that set these bounds are sometimes referred to as the oil and gas windows for rock, and can be illustrated with a graph.

Geothermal gradients defining the oil and gas windows as a function of depth and temperature. (From WVU)

The current reservoir depths at which the different shales are now found can differ quite significantly from those at which the gas or oil was first formed, with depths for the Fayetteville being as little as 3,000 ft (0.9 km) to the Haynesville which can be at more than 14,000 ft. (4.3 km). The Barnett is around 6 - 8,000 ft (2.4 km).

Permeability, or the ease with which gas, oil or water can flow through a rock is measured in a unit called a Darcy, but it is sufficiently large that most rock permeabilities are measured in thousandths of a Darcy, or millidarcies (Md). As a point of reference for a rock with a good permeability such as the Ghawar oilfield in Saudi Arabia, Greg Croft quotes values in the 600 Md range.

A microdarcy is one thousandth of the value of a millidarcy, and it is this unit that the permeability of gas shales are often measured. Thus the permeability of the Marcellus shale can be around 20 microdarcy and the Barnett around 10 microdarcy. The density of the rock can be seen from the sample pieces shown at the Chesapeake Web site.

Illustration of gas shales from the Chesapeake web site.

These fine-grained rocks with low permeabilities mean that the producer has to rely on other paths within the rock to allow the gas to escape. Originally this was just the natural fractures that can be found in the rock. As the rock compresses vertical fractures often generate within the rock. These fractures can be quite consistent, though in contrast to the bedding, they normally occur vertically.

Shale fractures from Geology.com

The problem is that conventional vertical wells don’t intersect a lot of these fractures, and thus, when the gas shales were first drilled the production was very low, and often uneconomic.

However when horizontal wells were developed it became easier to intersect a lot of these fractures as the well moved along the reservoir, and so it is time to introduce horizontal wells in the next post.

As usual this has been a very short description of a relatively complex topic, and so questions, and comments are appreciated.

House Hearing on Hydrofracturing

This morning the House Committee on Natural Resources Subcommittee on Energy and Mineral Resources held a Hearing, motivated by (among others) Congresswoman Diana DeGette of Denver, to remove the Safe Drinking Water Act exemption from the hydraulic fluids used in hydraulically fracturing (hydrofracing) oil and gas wells. The exemption was granted in 2005. It is particularly relevant to today and tomorrow’s supplies of energy since it is only through the extensive use of hydrofracing that it is possible to viably recover the large quantities of natural gas that are now being developed from the gas shale deposits around the country.

I was led to listen in by Joe Romm at Climate Progress who seems to have just discovered both Peak Oil and the Gas Shales, and I am glad that I did. The issue seems to have become of increasing public interest since the discovery that one of the larger gas shale deposits in the country is the Marcellus, which can be found under parts of New York and Pennsylvania, and with the large volumes of fluid that are used in the hydrofracing process (of which more in a bit) there is a growing concern (and some rumors generated) that the fluids from that process will get into the local drinking water and surface waters; that the fluids contain toxic materials, and thus the public is being put, unnecessarily, at risk.


The witnesses before the Sub-Committee were:

Mr. Douglas Duncan who is 
Associate Coordinator for the Energy Resources Program of the United States Geological Survey.

Mr. Scott Kell
, President
 of the Ground Water Protection Council and a State Regulatory , Official from Ohio.

Mr. Mike John who is the 
Vice President of Corporate Development and Government Relations, for the Eastern Division
 of Chesapeake Energy Corporation.

Mr. Lynn Helms who is the 
Director of the Oil and Gas Division of the 
North Dakota Industrial Commission, and who spoke of the activity of the Interstate Oil and Gas Compact Commission.

Mr. Albert F. Appleton who is a consultant on 
Infrastructure and the Environment and a 
former Director of the New York City Water and Sewer System.

Of these, Mr. Duncan spoke of the size of the gas shale resource, on land in the United States (and did mention that the USGS was working out how much there was in the rest of the world) but otherwise seemed to try and stay outside of the debate. Interestingly, later in the debate, ho noted that the USGS had data for the public lands in the United States, but had not finished the survey as to what lay beneath private lands.

In his opening statement Scott Kell spoke to the work that the States already do in this regard. He specifically cited two reports, though I only got the reference to the first. That was “Modern Shale Gas Development in the United States – A Primer”, (pdf) and it appears to be an excellent reference to the topic, and I am going to use it to substantiate some of the comments from the panel of witnesses.

He noted that the rumors of ill health caused by hydrofrac fluids suggested up to 1,000 cases of environmental damage focused on six states. He contacted the relevant agencies in those states and found that the reports were unfounded. The Ground Water Protection Council was founded by State Oil and Gas Regulators and is designed to protect the public’s water.

Mike John, speaking on behalf of Cheasapeake, noted that the Marcellus is likely to be a real game changer in regard to US reserves. It will provide an “ocean of natural gas,” with production being limited by demand, since there is now too much supply. They have 94 rigs operating and he described defining the shale in their lease, identifying the sweet spots with 3-D seismic and then drilling, from a single 5-acre site, perhaps 6 t0 10 wells that go down 8 – 10,000 ft (depending on the deposit) and then turn lateral and go out a mile horizontally. He believes that the four major gas shales (Haynesville, Fayetteville, Marcellus and Woodford) will generate half the US demand for natural gas by 2020, at 30 bcf/day.

Lynn Helms spoke of the benefits to come from the Bakken in North Dakota, as a State Official he has no greater priority than protecting the water, but has seen no credible real threat to the water and believes that the industry is adequately regulated.

Thus the first four speakers (or at least the middle three) were of the “it ain’t broke so why fix it,” school, and it was left to the last member of the panel, Albert Appleton, to explain the concerns that had led to the Hearing and possible change in legislation). He has been, as one concerned with the NY water supply, a critical evaluator of what goes on in the watershed that feeds water to the city and the state. He spoke to the fact that we are supposed to be moving away from fossil fuels toward renewable ones, that there are concerns with the fluids that are used in hydrofracing, and the industry that says it can’t afford more regulation is the one that makes these huge profits. His main concern was that the fluids used are toxic and do not biodegrade, so that even though they are stored in deep wells, they are still there as a threat. But there are also concerns that there are not enough regulators to ensure compliance with the regulations, and that water withdrawal may have severe and negative impact on communities. And he returned to the point that the Government is now pouring billions into green energy but this will compete with natural gas, so that if we subsidize the gas by easing the regulations we are undercutting the green energy program. And we have to be concerned about global warming. (Joe Romm is quoting NASA as saying that we will set a new global temperature record within a year or two).

Well after these opening statements, the Sub-Committee members had their say, some speaking more themselves, and one or two merely asking questions. The ad hominem argument that appears in other discussions also popped up here. Congressman Hinchey (I believe) from New York asked Mr Kell where he got his funding and focused in on the oil and gas companies that therefore “bought” the conclusions he had provided. (This was rebutted by the witness). He was particularly concerned with the benzine in the fluid, and returned to its toxic nature and longevity once spilled.

Congressman Boren from McAlester, OK talked about the rigs that are laid down, and the high unemployment in the oil and gas business in his district, for him $4 gas was too cheap. He did note that then Senator Obama voted to provide the exemption, and he wondered why they were trying to “solve a problem that doesn’t exist.” He got the witnesses to differentiate between the depth of the wells (8-10,000 ft) where the fluid is used, and the 2-300 ft of the water supplies of concern. They also pointed out that without the hydrofrac, gas from the shales can’t happen. He noted that the prevailing backup to the wind and solar farms being installed today is natural gas, and so we really need it.

Congresswoman Lummis from Wyoming talked of the “game change” nature of the natural gas, and asked of the consequences of the proposed change. The example given in response was the effect of the LEAF (Legal Environmental Assistance Foundation) legislature in Alabama which was directed at control of coal bed methane and hydrofracing (historic review.) The result of the judgement was to place a two-year drilling moratorium in the state. She urged the Sub-Committee not to remove the exemption.

The State regulators pointed out that the States had been handling this problem for years, without documented cases where there were problems in over 20 years of operation.

Congressman Gohmert of Texas pointed out that they are drilling into the Barnett shale in downtown Ft Worth without problems. Congressman Fleming of Louisiana commented on the developments in the Haynesville shale and how they were a great boost for the local economy, without incidents.

Yet in a reply Mr Appleton returned to the point that non-Federal regulation of the industry was a subsidy to the National Gas Industry.

Congressman Sarbanes of Maryland went back to the toxic chemical point, seeking to determine if any of the fluids were Class 1 chemicals (they are Class 2) He was answered that all sites (to comply with OSHA) must have the pertinent MSDS data sheets for all the chemicals at the site and available – so the fluid chemistry is determinable. However, it was pointed out that the chemistry changes from well to well and site to site, and thus it is impossible to generate a single “one mix fits all.” The fluids from the well are stored on site, in either tanks or double clay-lined pits, from which the fluid (monitored by the agencies on a per barrel basis) is transported to injection wells and pumped deep underground. There are some issues with water quantity however, (though this was not followed up on very much).

In terms of price, Mr John said that Chesapeake could live with $4 gas (per thousand cu ft) but that he expected the price to return to $6 to $8 fairly soon. They have not shut in any of their wells in the Marcellus. In response to the question as to what a typical fracing fluid contains as a chemical package he began to read the table (exhibit 36) below.

Typical fracing fluid contents

Congresswoman DeGette then came into the Hearing and asked questions as to the objection to the legislation. If the chemicals are reported anyway, why is there a problem. Some foks say there are no incidents, but incidents don’t always get reported. And there are stories of contamination, and injuries.

There had been one break in the Hearing and I was distracted a couple of times so that this is not a full and complete report, just what I was able to note.

My sense was that most of the Sub-committee did not see the reason for change, with only two or three members pushing the need for a change in regulation, but I suspect that not all the members were there and that this may have more passion on the part of those seeking the change.

Unconventional Gas - Another Conference and info

While I was attending the EIA Conference in Washington, there was a Conference in Fort Worth on Unconventional Gas ( (hat tip Go Haynesville Shale). To illustrate the value of these reserves I am going to take a table from a paper by J. Daniel Arthur and Bobbi Jo Coughlin that shows some of this information.

From Arthur and Coughlin (pdf)

Their paper deals with the water and other fluids used in hydrofracing the shale, and I will return to it, in a later post. But first notes that I picked up about the Unconventional Gas Conference, starting at Go Haynesville Shale. . Petrohawk gave a paper in which, based on the results of 15 wells in the Haynesville, leads them to predict an average ultimate recovery of 7.5 bcfg for each well which has led them to predict (with 2 offset wells from each current producer) they have a reserve of 150 bcf proven . Last year, before these numbers came out, an analyst for JP Morgan commented

Brian Kuzma, E&P analyst for JPMorgan Securities Inc., says 5-Bcfe wells suggest Haynesville leasehold is worth $40,000-plus per acre. "These wells only cost $5- to $6 million each, which would mean that these reserves would be worth some $1.25 per thousand cubic feet in the ground, using $7.50 gas prices. Given a 5-Bcf well--4 Bcf after royalties--on 120 acres, this equates to $42,000 an acre in value."

Given the enhanced production that Petrohawk are now claiming, that increases these values accordingly.

UPDATE: I have added a link to the second part of Austin Eudaly's coverage of the Conference, and a note on a biomethane development.


Initial production from these wells can range up to 20 mcf/day, with the Petrohawk 15 averaging some 18 mcf although I have not heard any numbers on the decline rates of the wells. We will have to see if they follow the Barnett pattern. It also depends where in the field that you are, since some in North Caddo Parish are reported as coming in quite low. One problem with having wells that productive is that the gas has to go somewhere and at that volume flow, and that number of wells the existing pipelines will not be able to cope. The Tiger pipeline won’t be available until 2011.The City of Shreveport will however be using some of the gas to fuel a new set of buses, purchased with the Stimulus money.. The buses cost over $100,000 more to buy, but will be economic over the longer haul, and they should show up in about 15 months.

In the first paper at the Conference Andy Hopwood, the BP America Vice President gave a few bullet points that Austin Eudaly recorded. As I mentioned in reporting on the EIA Conference, there is anticipated to be a surge in LNG supplies coming out of the Middle East this year. The number is in the 8 -10 bcf/day range and there is some question as to where that will go. Depending on the market much of it may go to Europe or China, but any remaining may well enter the US.

BP will be using America to learn about exploiting gas shales, it is one of the ten flagship technologies that BP has identified for special investment and they expect to take the experience in the US and apply it in places such as Australia, where similar shales can be found. However he reminded the 600 strong audience that conventional gas wells still produce 50% of American gas (which is an interesting decline in itself). Further, though BP has a position in the Haynesville the current glut has caused them to delay any new drilling.

That glut, which was foreseen by a report by Gail at TOD, is likely to be transient, given the short life of most of the gas shale wells, and the rapid drop (to less than 50%) of the number of rigs still operating. The price is now at $3.50 (Henry Hub) (per million btu or kcf) and shows no sign of slowing its steady decline. The weekly EIA report, however does note that some fertilizer operations are restarting with the lower price and this may start to form a floor to further price drops. However with gas being added to storage, even with a cooler temperatures, there is still more than enough to go around.

Update Austin Eudaly has updated his report from the Unconventional Gas Conference, with a report on the paper by Thomas Gardner of Simmons and Co, on the gas glut, (Sensibly describing how it came about and warning that things won’t get better until 2010) and one by Andrew Littlefair of Clean Energy Fuels Corporation, who is a close aide to T. Boone Pickens. The company is the largest provider of natural gas for transportation in North America. If you remember part of Picken’s Plan is to replace the use of natural gas for electricity generation by installing wind turbines. In consequence the freed up natural gas can be used for transportation. The talk covered a lot of the technical aspects of the gas location and the economics of the process, but Austin chose not to cover that.

Meanwhile Clean Energy Fuels has signed an agreement to sell biomethane produced from a landfill in McCommas Bluff to Shell Energy, who will supply it to a utility for power generation. The volume is anticipated to be 4,500 million btu’s (4.5 mcf) per day. The landfill is owned by the City of Dallas and will close in 2042, but is expected to continue to produce gas for at least 30 years after that.

P28 Pick Points

Half-a-dozen or so stories of interest:

As up to seven new LNG ports and a number of carriers are completed this year it is expected that supplies will increase to the United States. The projects have been planned for so long, and cost so much that gas must flow and be sold. The Federal Energy Regulatory Commission has had to develop policies on LNG , but even they defer to the market. Given this potential for over-supply the Freeport LNG terminal is looking into the potential for re-export, and local storage, since peak demand and supply may not be in phase. On the other hand recognizing that the time might be ripe to gain access to a cheaper source of power, Japan’s Tokyo Gas is looking at installing a new LNG terminal. To ensure supplies they have agreed to extend buying contracts for LNG supplies from Alaska. The Japanese, who are the largest users of LNG, need to do this to replace supplies that have been lost due to export reductions from Indonesia. The Alaskan gas sells for roughly 4/7ths of what the Japanese would have to pay for gas from Qatar.

In the lower 48, gas producers from shale are moving to stabilize supplies to the network. A new “Tiger Pipeline” is planned to collect and deliver for Haynesville shale gas into the interstate network. A new well is going into the Haynesville, that will run 17,000 ft horizontally. The Marcellus shale is also seeing some investor interest. XTO expects that gas (natural) prices will head back up before the year is out.

Hopes for energy price increases are hitting the wind industry, just as it comes out of a year where the USA added 8.5 GW of wind power. Of the major states adding wind power, California has seen the smallest recent growth, and in part that is because all the “easy” sites have now been taken, and the costs of permitting are now beginning to bite in the sites that are now in development. As a result Iowa is now second in wind power in the nation and has six manufacturers. But it turns out that the claim that the wind industry had more employees than coal mining relied on skewed counting (they counted everyone in wind, but only the miners in coal mining. But older wind farms are refurbishing with larger turbines and this also helps economically.

There will be a new 500 MW farm in Iowa, if they can get enough land, but construction will start in 3-5 years. In Rhode Island they plan on starting an offshore plant in 2010, they have enough wind for utility size operations which is level 3 on land (out of 7 with 1 being poorest), but have higher levels offshore, which is where the farm will go. In inland Northwest Missouri they now have a town (albeit only 1300 people) that receives all their power from the 4 nearby wind turbines.

The disruption caused by Total giving a contract to an outside, rather than domestic company in the UK may spread to other refineries and include nuclear power plants.

High temperatures in Australia, and particularly Melbourne played some considerable havoc with the Australian Open . Even as that ended, rolling blackouts are anticipated today because of the closure of the power link from Tasmania (due to overheating) . About 20,000 homes in the state (Victoria) are without power and the rise in the demand for energy has reached the limits of what can be provided. Bush fires are also threatening power lines, and a local coal company operation , while the drought is draining local water supplies . Locals are also concerned because of the secrecy of the order of priorities for load shedding.

It is not only in California and Australia that water supply is a problem. In the Central Asian republics Russia is stepping in to sort out possible conflicts since the countries from which the main water supply comes (Tajikistan and Kyrgyzstan( want to develop hydropower, while those downstream (Uzbekistan, Kazakhstan, and Turkmenistan) want the water for agriculture. The Tajiks are willing to offer the Uzbeks water for energy. Turkmenistan is also involved since they send out electric power that must pass through other countries to the end user.

Uzbekistan is demanding 10 per cent of the $0.03 per kilowatt paid by Tajikistan to Turkmenistan.
This year the Uzbeks are also charging Kyrgyzstan and Tajikistan US$ 240 per 1000 m3, up from 145 dollars last year.

And the Tajiks are not taking kindly to the Russian intervention.

For more stories go to The Energy Bulletin or Drumbeat at The Oil Drum