Ideology versus Reality in the UK

This is but another gentle cough! And for those not familiar as yet with the way I write, it is, in the culture in which I was raised, generally considered more polite to gently cough and quietly explain why someone is wrong, rather than engage in the confrontational breast-beating and name calling that seems more prevalent in scientific argument in these latter days.

Which brings us to the new “news” out of the UK. The argument that a nation’s government must, in the end, deal more for the benefit of its voters, than to its political views has been one of the underlying cynical views I have held for the energy future for a long time. Telling a nation that they need to do something “for the good of their grandchildren”, does not go very far when oil prices are rising and they have a cheaper, indigenous source of energy – which is, quite frequently coal - that will allow them to feed themselves, and their children, and thereby provide a path to the generation of said grandchildren.

My anticipated example for this has been, for a while, India and the sub-continent of Asia, where indigenous coal can be a much cheaper resource than increasingly expensive foreign oil, and natural gas which is often politically more difficult to acquire through trans-continental pipelines. And so I was caught a little by surprise, although, based on Euan’s excellent previews it was something which had to happen, but which I did not yet expect, and that is a volte face from the British Government.

The underlying premise to which I have tried to adhere has been one of realism, rather than ideology. As a research scientist for most of my life I have had, too often, to go to meetings where I have had to admit that experimental results did not exactly follow my predictions, and that, as a result, the underlying theory has had to be changed. But that does not mean that the overlying premise changes, only the nuances of the argument. (And for those few interested, the work dealt with how things break.) And in the current case the overlying premise has always been that a nation has to ensure its fuel supply at a viable cost to the nation.

It is something that, inter alia, drove Japan into war over 70 years ago, and now that reality is becoming evident to Her Majesties Government, it is apparently a realization that is beginning to strike home over there too.

In April 2012 coal took over from gas as Britain’s dominant fuel for electricity for the first time since 2007, driven by a collapse in the international price and a rise in the cost of gas. In addition, the tax the Government levies on companies emitting carbon currently stands at £16 per ton, rising to £30 a ton in 2020. But analysts warn that at the current prices this would have to rise to more than £40 to make such coal generation uneconomic. . . . . . Under the Energy Bill, 12 of Britain’s existing 18 coal power stations that could stay open will be exempt from the Government’s emissions performance standard (EPS) that sets limits on CO2 emissions for all new power generation.

The political cost of supporting a coal-based economy have yet to be determined, and the unrelenting assault on coal-fired power has been so widespread and unrelenting that this will not be an easy sell, but this step is something that may well be an indication of where, ideology aside, reality will move to define the future.

In essence the relief of the burdens on the existing power plants will strengthen the base-load capacity (usually provided through coal and nuclear power) and will take some of the strain from the commitment to renewable energy (which is often wind-generated in the UK) and thus work to ameliorate some of the criticism from such folks as the Institution of Mechanical Engineers. (There is no longer any criticism from the Institution of Mining Engineers, since that went the way of the dodo, some years ago.)

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.

Deepwater Oil Spill - closing the well and the series

The operations to seal the Deepwater Horizon well in the Gulf have now succeeded in putting cement plugs into the well that have effectively ensured that it will remain dead. The well itself was effectively killed when the cement was injected some weeks ago, and the work since has been to ensure that some of the potential problems from subsequent failure of that cement, could not occur. And so the relief well had shown that there were no effective quantities of hydrocarbon products in the annulus, meaning that the well failure had purely been through the shoe and up the production casing, and not up the annulus. Much of the original thought had been that the failure was the other way around, and the caution in the approach has been, in part, in case there was at least some failure up the annulus. That turned out not to be the case, but the relief well injected cement that filled in the voids in the annulus, so that with the cement already injected into the casing, the well is, as the Bureau of Ocean Energy Management, Regulation, and Enforcement certified, now permanently sealed.

This does not end operations at the well. Both the original well and the relief well must now follow the procedures for abandonment of the site. The DDII has been preparing for this, but the procedures that must be followed are relatively standard. I am presuming that the plugs that have been discussed are those at the bottom of the well, but there also need to be plugs installed within the well to ensure that there are no possibility of fluids migrating from one horizon to another. To a large extent this has likely been achieved with the filling of the annulus between the end of the lined well and the top of the cement injected earlier this summer. The well is now effectively totally lined on the outside, and there is a plugged production casing in the middle, which retained its integrity over the course of the events.

Nevertheless the regulations will be followed. For your information the relevant bits are, perhaps:

(a) Isolation of zones in open hole. In uncased portions of wells, cement plugs shall be set to extend from a minimum of 100 feet below the bottom to 100 feet above the top of any oil, gas, or freshwater zones to isolate fluids in the strata in which they are found and to prevent them from escaping into other strata or to the seafloor. The placement of additional cement plugs to prevent the migration of formation fluids in the wellbore may be required by the District Supervisor.
(b) Isolation of open hole. Where there is an open hole below the casing, a cement plug shall be placed in the deepest casing by the displacement method and shall extend a minimum of 100 feet above and 100 feet below the casing shoe. In lieu of setting a cement plug across the casing shoe, the following methods are acceptable:
(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effective back-pressure control and shall be set not less than 50 feet and not more than 100 feet above the casing shoe. The cement plug shall extend at least 100 feet below the casing shoe and at least 50 feet above the retainer.
(2) If lost circulation conditions have been experienced or are anticipated, a permanent-type bridge plug may be placed within the first 150 feet above the casing shoe with a minimum of 50 feet of cement on top of the bridge plug. This bridge plug shall be tested in accordance with paragraph (g) of this section.
(c) Plugging or isolating perforated intervals. A cement plug shall be set by the displacement method opposite all perforations which have not been squeezed with cement. The cement plug shall extend a minimum of
100 feet above the perforated interval and either 100 feet below the perforated interval or down to a casing plug, whichever is the lesser.
In lieu of setting a cement plug by the displacement method, the following methods are acceptable, provided the perforations are isolated from the hole below:
(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effective back-pressure control and shall be set not less than 50 feet and not more than 100 feet above the top of the perforated interval. The cement plug shall extend at least 100 feet below the bottom of the perforated interval with 50 feet placed above the retainer.
(2) A permanent-type bridge plug shall be set within the first 150 feet above the top of the perforated interval with at least 50 feet of cement on top of the bridge plug.
(3) A cement plug which is at least 200 feet long shall be set by the displacement method with the bottom of the plug within the first 100 feet above the top of the perforated interval.
(d) Plugging of casing stubs. If casing is cut and recovered leaving a stub, the stub shall be plugged in accordance with one of the following methods:
(1) A stub terminating inside a casing string shall be plugged with a cement plug extending at least 100 feet above and 100 feet below the stub. In lieu of setting a cement plug across the stub, the following methods are acceptable:
(i) A cement retainer or a permanent-type bridge plug shall be set not less than 50 feet above the stub and capped with at least 50 feet of cement, or
(ii) A cement plug which is at least 200 feet long shall be set with the bottom of the plug within 100 feet above the stub.
(2) If the stub is below the next larger string, plugging shall be accomplished as required to isolate zones or to isolate an open hole as described in paragraphs (a) and (b) of this section.
(e) Plugging of annular space. Any annular space communicating with any open hole and extending to the mud line shall be plugged with at least 200 feet of cement.
(f) Surface plug. A cement plug which is at least 150 feet in length shall be set with the top of the plug within the first 150 feet below the mud line. The plug shall be placed in the smallest string of casing which extends to the mud line.
(g) Testing of plugs. The setting and location of the first plug below the surface plug shall be verified by one of the following methods:
(1) The lessee shall place a minimum pipe weight of 15,000 pounds on the cement plug, cement retainer, or bridge plug. The cement placed above the bridge plug or retainer is not required to be tested.
(2) The lessee shall test the plug with a minimum pump pressure of 1,000 pounds per square inch with a result of no more than a 10-percent pressure drop during a 15-minute period.
(h) Fluid left in hole. Each of the respective intervals of the hole between the various plugs shall be filled with fluid of sufficient density to exert a hydrostatic pressure exceeding the greatest formation pressure in the intervals between the plugs at time of abandonment.
(i) Clearance of location. All wellheads, casings, pilings, and other obstructions shall be removed to a depth of at least 15 feet below the mud line or to a depth approved by the District Supervisor. The lessee shall verify that the location has been cleared of all obstructions in accordance with Sec. 250.704 of this part. The requirement for removing subsea wellheads or other obstructions and for verifying location clearance may be reduced or eliminated when, in the opinion of the District Supervisor, the wellheads or other obstructions would not constitute a hazard to other users of the seafloor or other legitimate uses of the area.

This means that there will be some continuing work at the well, but not a lot, and thus from now on I shall only be intermittently posting on that topic, and will start to write about the more general topics that have been neglected over the past few months.

Deepwater Oil Spill - a longer term problem, personnel

The recent take-up of oil through the cap and the LMRP to the Drillship Enterprise has reached a daily rate of 15,800 bd.

For the first 12 hours on June 9th (midnight to noon), approximately 7,920 barrels of oil were collected and 15.7 million cubic feet of natural gas were flared.

On June 8th, a total of approximately 15,000 barrels of oil were collected and 29.4 million cubic feet of natural gas were flared. The Massachusetts began lightering this morning and should finish early morning on the 10th (lightering is a process of transferring crude oil between vessels, in this case, Enterprise to Massachusetts).

The Loch Rannoch is on its way, as, possibly, is the Toisa Pisces. This latter is a Well Testing Service Vessel (WTSV) Dynamic Positioning ship, which has systems for the reception and processing of fluids from well completion, stimulation and repair. For those interested in well flow rates, that measuring capability is among its capabilities.

• Reception of the products from the well via flexible hoses connecting the well to the production system installed on the ship.
• Process and separate water, wasted and un-wasted chemicals, gas, crude oil and solids. The water will be stored in the WTSV’s tanks and later re-injected into industrial waste well or offloaded to a processing facility onshore.
• The crude and gas will be measured in quantity and quality. The combination may be returned to the export line, or if this last is not available, the gas will be flared and the crude stored in the WTSV’s tanks to later be exported to an onshore or an offshore offloading terminal.
• The solids are stored in containers to be disposed to shore.
• Crude ranges are from low to high (12 to 43O) API. Pressures up to 10,000 psi at the well head.

It has been suggested that it might arrive on site on the 19th June. The Loch Rannoch should arrive a few days earlier, releasing the Drillship Enterprise, which, I suspect, has other things that it might now be doing.


The Toisa Pisces was formerly a cable-laying vessel, and is not a FPSO.

Toisa Pisces

My main topic for this post, however, is not the possible change is the fleet over the well, but rather some thoughts on how to avoid this happening again. There were likely a cascade of several errors, each of which alone would not have led to the disaster, but cumulatively they did. So how do we stop it happening again?

In some ways the problem is similar to that the Mining Industry faces after more than twice the number of deaths (29) at the Upper Big Branch Mine in West Virginia in April. In both cases there were safety concerns reflected in the numbers of citations that the companies had received relative to other companies. So how does one install a different attitude in those who work to produce the fuel that we all need? To a degree it has to be done through the imposition of regulations that enforce the concept of safety in daily working life. Including in those regulations should be the appropriate recommended practices for carrying out different tasks in the operation.

But even with those regulations in place, they are only as good as the enforcement of them. If my memory serves, you could not become an Inspector of Mines in Britain during the National Coal Board years, unless you had a First Class Certificate of Competency (which is the examination that allows you to manage a mine). The standards of education and training for inspectors must be high, and they need to require a reputable image.

The problems, in part, for both industries, are that the fossil industry historically has been cyclic in nature. Often driven by the price of oil, when that price is high, there are lots of jobs, and both coal and oil boom. The price falls, times get tight, and lots of folk get laid off. It has happened more than once in my career, as we have students go from having many job offers, to students coming back for graduate degrees because there was no work in the industry. The employees that are laid off go find work in other, less cyclic industries. And so when the next boom comes around they are no longer available. Further the teaching departments at the Universities have closed. It is as a result of this boom and bust cycle that there is a dearth of middle management in many companies that work in the fossil fuel business. For many years they were not hiring, and the folk that they now need as long-time trained and experienced individuals do not exist in large numbers.

The number of both mining and petroleum engineering schools have fallen, and student enrollments, until the recent rise in the price of oil (the $140 one) were bring other departments closer to that action. At one time, for example, Leeds University in the UK was one of the largest mining departments. At that time it was housed in a building that was funded by those in the Industry in 1928. That building is now occupied by the Art Department and somewhere – not quite sure where (this from the alumni office and the secretary in the building that houses the remaining odd faculty member) – there is still someone that teaches the odd course (he was out). There is only one other Mining School in the UK, and it studies hard rock mining at Exeter (used to be Cambourne School of Mines).

The Old Mining Building at Leeds

The commemorative plaque

It is hard to criticize University leaders, who must look to where the students are, and which faculty hire will bring the best return to the University. In recent years that has not been within the ability of the fossil fuel departments, and so they are closing – though the demand for their product is now rising again.

It is one of those interesting items to note that the latest reviews of world oil supply are beginning to suggest, increasingly, that the world is approaching if not past the point of peak global oil production. That will require more mining and petroleum engineers, though at places like Leeds (my alma mater) they will likely only be able to produce the modern version of Thomas Hair, to record the modern version of his “Art of Mining,” rather than the subjects of that art.

So what does all this have to do with regulation and responsibility? Well it is very difficult to maintain high quality folk in industries that go through severe manpower cycles. When regulations are severely enforced under one administration and then almost neglected in another, either because the industry is in disfavor, or the apple of the administration’s eye it is hard to keep the regulatory inspectorate that is a vital part of running a safe industry. The regulations should be fair, be strict, and must be enforced by individuals that have been properly trained to a high level of understanding as to both the technology that they are reviewing and the consequences of error. The historical evidence is clear that Universities cannot be left alone to provide that education, and supply those individuals. The National Mine Health and Safety Academy at Beckley is a start in the right direction for the mining industry, but there are other changes that must be made, in the investment in research into new technology, in the general attitude to those who work to provide the fuels that we need (and will continue to do so).

Treating the industries and those who work in them as pariahs is not the way to solve this problem.

Energy Summit - the second part (until 3 pm)

This is the second post on the contents of the Energy Summit held at the University of Missouri this week. The first post covered the keynote address by T. Boone Pickens, and that can now be seen, together with Chancellor Carney’s opening remarks, and those of Senators Bond and McCaskill as a video. (Warning it is a 1 hr 30 min video and some 219 MB). Mr. Pickens remarks were also picked up by the local Missourian. (The school of journalism was also holding briefings and interviews that ran concurrent with the summit). After the keynote, the Summit got underway with a brief review, by the chief research officers of the four campuses of the University of Missouri system, of the energy related research that each was carrying out. This was a fairly top level skim through a project range that covered fuel cells, hydrogen, a new way of storing gas on carbon bricks, and studies on a wide range of pathways to generate transportation fuels, and also prefaced a number of the papers, poster presentations and displays, the latter two of which were going on outside the main auditorium.

The first invited Speakers then came to the podium with Dale Klein, Chairman of the U.S. Nuclear Regulatory Commission leading off the presentations.

Mr Kein noted that his agency is a regulator, not an advocate, and that he is currently looking at 17 applications for 26 new nuclear plants, with another 3 applications for 5 plants being anticipated. (However this is likely to include the AmerenUE application for a second plant at their Fulton site. The company indefinitely suspended that request this morning, just after getting word that a bill that would allow it to charge for construction before it was finished was not going to happen).

Mr Klein walked us through the process of getting a permit, noting that it would take 30 months to review the application, 12 months to get public comment, and then it might take some 44 months to get the plant built. The current costs are in the range of $5 - $7 billion per plant, and they are licensed for 40 years initially, with a possible 20-year extension. (For comparison he noted that the USS Enterprise, the first nuclear powered aircraft carrier, was commissioned in 1960, and is coming to the end of its service life –within 3 – 5 years. He felt that the public needs more education on the benefits of nuclear power, and what not to be afraid of.

Coming next to the podium, Dr. Joan Woodard ( executive vice president at Sandia National Labs) mentioned her last visit to town, some 35 years ago as she drove out to Sandia to take up her first job there. She talked of nations climbing the energy ladder which takes nations from no power, through burning dung, and then to carbon fuels and to higher levels of consumption as society advances. However she noted that the US curve was flattening as is that of the European Union, and it is other nations, from Korea and Australia to China and India that are growing and seeing increased levels of energy demand as that growth continues. This is, in time, bound to strain the system, due to the demographics of a growing world population combined with growing standards of living, and thus individual energy demands.

She felt that Secretary Chu does a “wonderful job” in explaining the coming mandate that is Climate Change, and she noted the ever-shrinking condition of the Arctic ice cap. (Obviously she has not seen the latest ice data from the Arctic, which shows that the coverage is returning to the seasonal normal for the past 28 years, since she commented that the rate of shrinkage of the ice cap was accelerating, when, if you look at the plot, it obviously isn’t.) Nevertheless, in light of the mandate she felt that the energy enterprise must change to encompass not only the desire for economic prosperity (the ladder) and the regional environment, but also national security issues. In this she felt that while Global Trade can be good, it also creates tensions over such concerns as Russia, and now China buying up large quantities of the world reserves of a number of commodities. And in that regard we must consider that Chinese companies that are doing the purchasing are an extension of the state.

Droughts in Africa will drive migrations, leading to further conflict. Further the US is vulnerable to national disasters. Both of which threaten our security, although she then went on to mention more conventional threats. These include attacks by hackers into the control systems for our energy networks and the threats posed by global proliferation of nuclear knowledge. To protect against these threats we need a system that will, if it does fail, does so “gracefully” but which has high reliability and resilience against attack.

Daniel Cole senior vice president of Ameren then talked about his early job as a “pirate” down at Branson, MO. Here as part of the “tourist” entertainment he would regularly be pelted with bags filled with rock, but simulating gold. That job was excellent training for his current one with the utility. The company has 2.4 million electric customers, and a million natural gas customers. They produce some 16,600 MW which is nominally 61% coal, 30% natural gas fired. However because coal provides baseload and natural gas is for peaking demand supply, it turns out that 85% of actual production is coal-fired. It is also cheaper. But in the process last year, for example, it produced 70 million tons of carbon dioxide.

The nation produced some 6 billion tons. Now if the system goes to a cap and trade system and one might project growth to 6.2 billion tons generated in a couple of years, the cap might instead mandate total production is held to 5.5 billion tons. This amount would then be parceled out as a series of allocations. Each allocation would either be designated to a company at a price or subject to auction. The company could also offset some of its production with some alternate activity (such as paying for no-till farming for example).

They priced the cost that the company would face after the Lieberman Warner bill was proposed. It set a price of $50/allowance (1 ton of carbon) in 2015, rising to $100 by 2030. With the production of the company being 70 million tons, this will give an additional bill of $3.5 billion in 2015. This will mean, according to Mr Cole, the rapid disappearance of existing coal plants, but Missouri currently has the lowest electricity rates in the nation, and such a burden on their carbon production would have to be passed on as a very rapid increase in power costs per kWh to the customer to more than double that of today. The results when the requirements of the Waxman Markey bill were evaluated were even more severe.

Ameren is part of the Electric Power Research Institute (EPRI) which has examined different technologies (pdf) to see if, in fact, these targets are attainable, anticipating increases in efficiency of use, and a 0.1 to 0.7% growth in demand.

Their conclusion was that renewable sources will only act to stabilize carbon dioxide levels, and that while increased use of nuclear power can initiate a drop in levels, it will be a switch to advanced coal generation that will be required to make significant reductions. But to have a real impact the focus must look at coal, focus on adoption of new technology, and be international in application. But the answers will come as silver buckshot not as a silver bullet.

This is the third post on the Energy Summit
The second post covered the Keynote, and the first described the program.

The final speeches of the first day will be covered next.