A little more on coal mining

I am reminded of the high price that nations have to pay, on occasion, for coal by the sad news of the death of thirty miners in a gas explosion at the Tonghua mine in the Chongqing municipality of China. Emotions over coal mining can become easily stirred by the inflammatory words that are sometimes used about the industry that we forget that there is often a real personal cost that comes with the provision of energy to the nations and their people. But the accident helps to emphasize a comment that I believe is important for the longer term preservation, not only of the industry, but also of its people.

In this case, as so sadly is the way in many, the result came about because known safety rules were apparently violated.

"The accident is caused by an illegal practice which violated the mining rules," said Luo Lin, chief of the State Administration of Work Safety said.

. We see the same thing in accidents that occur around the world. But is not only in the “wink and nod” violation of regulation of safety practices in the underground and surface that we should express concern. There are other factors, relating to mining operations, where, I believe that the industry is not doing itself any favors by trying to get around existing regulations.

I was led to this particular topic by a couple of articles (in the Los Angeles Times and the West Virginia Gazette, about the Administration attitude to mountain top removal of material to gain cheaper (and safer) access to the coal underneath. Essentially a number of President Obama’s supporters have been disappointed over his recent actions in regard to the policy in regard to this practice.
Basically they had been led to believe that the new Administration would ban the practice, but instead:

But in recent weeks, the administration has quietly made a decision to open the way for at least two dozen more mountaintop removals.

In a letter this month to a coal ally, Rep. Nick J. Rahall II (D-W.Va.), the Environmental Protection Agency said it would not block dozens of "surface mining" projects. The list included some controversial mountaintop mines. . . . . . . . "It was a big disappointment," said Joan Mulhern, a lawyer for Earthjustice, an environmental law firm that has led court challenges to mountaintop removal. "It's disturbing and surprising that this administration, headed by a president who has expressed concern about mountaintop removal, would let such a large number of permits go forward without explanation."

On the other hand this may be an Administration that is beginning to discover some of the harsh realities of life. That we do need coal, and that it can be mined in a variety of ways, depending on how thick the coal is and how deep. And that safe cheap means of mining are better than the alternatives.

Mountaintop Mining is a particularly controversial method. It is basically used in Appalachia where the coal appears as layers within the rock that make up the hills of that country. The EPA have described the process with diagrams of the different stages of the process. There are also photos on the site of the various stages of the process.

Now while I am in favor of methods of mining that make it safer for those that have to work to extract coal from the ground, (surface mining being much safer than underground) and strongly believe that coal will end up being as least as strong a supplier of energy to the global community in this century as it has been in the past, there are some times where one should be conscious of a larger goal than just producing coal. For example, this week A.T. Massey have been seeking to get a permit to carry out mountaintop removal as an expansion of their current mining in Boone County , West VA. But the regulators are balking, because Massey is apparently trying to get away with as little surface reclamation, after mining, as they can get.

In its permit application, Independence Coal says, "The pre-mining capability of the land is limited to unmanaged forest land and wildlife habitat because of the steep slopes and limited access.
"These steep soils are best suited to trees and shrubs rather than agricultural or other uses," the company said. "The inaccessibility of the area promotes a viable habitat for many wildlife species." . . . . . . In its permit application, Independence says the flat land created could be used for a variety of beneficial post-mining land uses. But the company writes off most of those possibilities.

"Because this mining and reclamation plan will produce level areas on the mountaintop and hollow fills, a variety of land uses after reclamation may be possible," the permit application states.

"Soils are generally too poor to provide intensive agricultural or horticultural development, although hay production and grazing has proven successful in many mined lands in the region," it says.

"Commercial or residential development of this property is not considered feasible at this time, but the nearly level land created by this project may present a future opportunity for economic or residential development."

Independence proposed "to reclaim the permit area to wildlife habitat and recreation." "A diverse vegetative cover will be established, providing habitat, food sources and protective cover for a variety of wildlife," the permit application said. "Over time, native plant species will likely invade the area, adding to species diversity.

"The surrounding area is covered in upland forest. The creation of wildlife habitat on the reclaimed mine site is therefore a viable postmining land use choice."

Now recreating a good wildlife habitat is not, in itself a bad thing. Regenerating the upland forest, with open pastures, may well encourage increased diversity of wildlife over that currently extant. But somehow one does not get the impression that the company intends to go that extra mile to make the results, post mining, of maximum acceptance to the community.

And this is my gripe, I suppose. We need coal as an energy source, the demand will be such that the price that will be paid for it will be quite sufficient for an adequate profit. Under such conditions it behooves the mining companies to go that extra mile to ensure that the land that they leave behind them is in better condition that when mining started. Further it is the role of the government to ensure that regulations are followed in a rational and reasonable manner to the good of all concerned. When this is not done then we find the problems that have plagued the industry around the world. Maybe it is time that we grew beyond that.

Peak Oil comes to Climate Change - but I'm coughing again

Saturdays are when I usually wander around the different sites that devote their time to aspects of the Climate Change Debate, looking to see if there is anything interesting or persuasive that might be of interest. You may note that I have added some of these sites to the blogroll – trying to balance out the numbers so that there are the same on each side of the debate. Over at CEJournal Tom Yulsman has just put up a post querying the open-mindedness of those that engage in this topic. He got a boost in readership at his site this week (which is pro-AGW) because he was cited on Climate Depot, (which is anti) but wonders why folk bother looking at the other side of the debate, since most have their minds made up. To answer him, the reason to look is to try and get both sides of the story – unfortunately when articles appear these days, depending on which side is writing them some of the facts may be missed or given an incorrect emphasis. By looking at reports on both sides it is a little easier to tell who is telling the truth, or skirting the facts.

That being said it led me to Joe Romm’s Climate Progress, which appears to have just discovered Peak Oil.. His post is mainly a diatribe against the auto makers of Detroit. But he begins thus:

Readers of Climate Progress understand two inescapable realities that the overwhelming majority of policymakers, the status quo media, and the car companies (with one exception) do not:

Peak oil is inevitably going to drive up gasoline prices to record levels within a few years, driving an inevitable switch to much more fuel-efficient vehicles and non-oil-based alternative fuels, of which by far the cheapest per mile is electricity.
Avoiding catastrophic global warming requires sharp increases in fuel economy and a switch to low carbon fuels — of which there is only one available in quantity: electricity (as explained here).

Deeper within the story he comments on the changes that global warming will impose on auto makers, as follows:

And by the 2020s, every major country will be engaged in a dire effort to avert catastrophic global warming, which by then will be painfully obvious to even the most blinkered conservative. And that in turn will drive enormous but difficult-to-forecast levels of behavior change in the purchase and use of major energy-consuming products — cars being perhaps the most obvious.

Now since this is a Saturday I am going to challenge that latter remark. We have seen, over the past 150 years, roughly consecutive cycles of warming and then cooling for about 30-years each, which I have written about before and which can be seen on the Hadley Temperature plot. Basically it warmed from 1850 to 1880, cooled from 1880 to 1910, warmed from 1910 to 1940, cooled from 1940 to 1970, warmed from 1970 to 2000, and has been cooling since 2000. So if this cycle persists - with cooling to 2030, then by 2020 the world will not be engaged in a “dire effort to avert climate warming”, but will have moved on to more productive ways of spending its time, since by then the demand of folk like Joe to consider the data only over 30-year increments and thus neglect the short-term cooling, will have worn too thin.

But I am also not sure whether I agree with the other half of his argument relative to the future of automobiles. He concludes that the cost of liquid fuels is going to be such that

Within a decade, the only growth segments in car business will be highly fuel-efficient cars, PHEVs, and EVs. Indeed, that isn’t true just of the United States, but also of the biggest new car market — China.

I am cautious about that prediction for a couple of reasons. The first is that I am waiting to see what the real impact of cars such as the Tata Nano is going to be, particularly in the poorer parts of the world. If the market is as large as I suspect, the volumes of cars that are sold will tend to swamp the switch to electrics for at least another decade. We just don’t have the product in place at a viable price for the electric car to make the sorts of levels of change that he is anticipating.

But there is another point that he, one of the stronger advocates against the coal industry, is unwilling to face in this vision of the future. Where is the electricity to come from to fuel not only the increase in industrial demand, but also this supply of energy for the automotive industry? For if he and those of similar disposition reduce the number of coal-fired power stations, and we don’t have time (the 2020’s being merely a decade away) to install a large number of nuclear power plants, what will be the power source for the electricity?

While I expect wind to provide significantly more power than it now does, and solar will continue to be “almost there”” in terms of costs, these renewable sources are not going to be able to meet the burgeoning demand that can be anticipated. The general opinion that seems to prevail is that natural gas is going to come to the rescue. It is assumed capable and ready to replace coal and oil in the generation of power, can provide fuel for vehicles (along the lines of Pickens Plan) and will be the savior of the decade. The only problem would be if that industry were unable to meet the prodigious production demands that are being put upon it. And sadly, that is at least at present a suspicion that is beginning to harden among a number of us who look at the gas numbers. But then that is the subject of other posts, and will remain a matter for discussion on these pages in the months ahead.

(Nate: this was for you!)

Predicting and investing in the energy future

When Congress passes laws, and politicians put the full resolution of a problem into the “out years”, i.e. those in the future, there is a tendency to see this as a way of providing an “answer” while giving time for the answer to be developed to the scale needed. It also allows the subject to be considered covered, so that other problems can rise to the top of the list. There is an inherent assumption that industry will meet the obligations that are defined in the legislation, and that the needed tools will be invented in time to be useful. So it may well be with the supplies of future renewable energy, those that will be needed to power the country forward at defined points in the future. Any problems associated with the various technologies, whether cellulosic ethanol, solar or wind are assumed to have been resolved by the time that the supply will be required.

There are several dangerous assumptions that are made in developing such policies, and assuming that they will provide for the national need (whether American, European or wherever) when called upon. Considering just a couple, the first of these is that we have the time to evolve the technologies at the scale required, the second is that the funds and knowledge will be available to resolve any existing technical problems in generating viable supplies at the required level. By stating or implying that these things will happen, the public concern is meant to be relieved, and the problem resolved. To meet the growing global need there is an increasing assumption that the answers will come from renewable sources. This is the sector expected to have the fastest growth in supply (the EIA is anticipating an 11% contribution by 2030, with 5.9 mbd of ethanol and biodiesel by that time). (The EIA anticipate that, through 2030 only Libya and Ecuador of the OPEC nations will see a fall in oil production, most will increase with Saudi Arabia producing 12 mbd). So let’s look at these assumptions to see why we might be in trouble.

The first is the time that will be needed to resolve the problem. And to resolve this problem (and the others) someone has to be working on it. Yet, with the decline in the economy, the amount of investment in energy producing plant both conventional (as in oilwells) and in renewable systems is dropping. The IEA has expressed concern over the levels in investment in the oil industry, with projects being postponed or cancelled.

Fatih Birol, The IEA's advisor to 28 industrialized countries, said in an interview he expected oil and gas upstream investment to fall 21%, or about US$100-billion ($113.8-billion), in 2009 from 2008 due to the global recession.

At the same time investment in renewable energy is dropping more rapidly, while existing companies are going bankrupt in the face of the current economy.

Spending on renewable energy, such as wind power, is falling even more rapidly than on oil and gas. The IEA expects renewables investment to slide 38% this year compared to last, Mr. Birol said.

Now that story ends with the usual caveat

Not all agree with the IEA. The agency warned in 2007 of a supply crunch around 2012, a view that some analysts said was actually contributing to higher prices by putting a "fear premium" in the market.

But the reporter fails to grasp a point I have made before, that while it is easy to delay projects, it is much more difficult to accelerate them. The millions of barrels of oil that will no longer be available when needed within the next five years, mean that the need for an alternative supply, the role the renewables are meant to fill, will come earlier than anticipated, and at a level higher than now projected. It is a concern that is also now being voiced by some of the Ministers of the G-8.

Italy, which currently holds the G8 presidency, expressed concern about the possibility of another soaring period of oil prices when the world economy comes out of the crisis.
"When the crisis is over, the risk of insufficient energy supply exists, and as a result high and unstable prices," Italy's economic development ministry said ahead of the meeting.

Now part of the second problem is tied up with the first as cited above with the second quote from Fatih Birol, but a more significant part relates to the nature of the problems in establishing the new renewable plants, and, particularly for the replacement fuels, in making their operation profitable in the short term. Companies that invested in corn ethanol production have seen prices fall and several have become bankrupt, with Pacific Ethanol being the latest. And investors in cellulosic ethanol have also lost some confidence( despite the President’s confidence in the (as yet unproven) technology.

"My administration is committed to moving as quickly as possible to commercialize an array of emerging cellulosic technologies so that tomorrow's biofuels will be produced from sustainable biomass feedstocks and waste materials rather than corn,"

Shrinking an industry when it needs to be growing is not something that has an immediate impact, given the recession, but it makes it that much more problematic to be able to meet future targets. I accept that 2030 is a relatively distant time (the 20-years that will be needed according to the Hirsch report) but unfortunately by picking that interval there is an inherent implication that problems won’t arise before then. And that is where I expect that the greatest error in these assumptions is being made.

There is no longer enough investment in the resources that will be required to provide an adequate supply for the next five years, let alone 20, and while the results of that lack may well bring future funding it will be too late to avert significant negative impact. By focusing only on that long term, we may be missing the intervening hard times. I thus expect that the EIA prediction that oil will not get back to $110 per barrel until 2015, and to $130 by 2030 to be not only unrealistic, but dangerously complacent.
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Gentle Cough - Jevons Paradox and the Christian Science Monitor

The Christian Science Monitor has a comment on the likelihood of people driving more as fuel efficiency gets better. It notes that in its modern form, the rebound effect, should see folks driving more as the cost per mile declines. After all driving was curtailed when gas prices rose above $4.

The author of the piece (Eoin O'Carroll) worked out, with help, the likely effect.

How big is the actual effect? I asked Jim Kliesch, a clean-vehicle expert with the Union of Concerned Scientists, who has reviewed a number of studies on the subject. He walked me through the math, and we calculated that doubling fuel economy would increase driving for the average person by a little over 7 percent.

“It is certainly not of the magnitude to have any significant impact on energy savings,” he said.

Thereby he believes that Jevons Paradox does not apply to cars and fuel efficiency.

I think he misunderstood the Paradox, so this is what I wrote in a comment at the site.

I believe you misunderstand the application of Jevons Paradox. In his original example, Jevons pointed out (as you note) that increasing the efficiency of a locomotive led to an increase in coal demand for coal, their fuel supply.

But you have considered that increasing efficiency would increase the mileage driven by an individual vehicle. That is not what he said, nor, realistically what will happen. Rather it is that by lowering the cost of locomotives, people used more of them, and thus demand rose, not that an individual locomotive drove more miles.

Relevant to the current debate the example is the Tata Nano - by improving manufacturing efficiency to create a car cheap enough for a lower stratum of Indian society (and later the world) their ability to afford the car will drive up gas consumption.

There are many examples - computers, i-pods, cell phones etc etc. It is in the marrying of price with improved efficiency that provides the engine for the Paradox.

And yes, in its correct mode of use, I expect Jevons Paradox to continue working.

Gentle Cough, Saudi Arabian production

Over at The Oil Drum (TOD) Ace has just posted an update to his Forecast of World Oil Production and it is the usual well argued and documented review of one possible future. He concludes that world crude oil (including condensate and from the oil sands) peaked in 2008, at 73.8 mbd. He believes that by 2011 OPEC will no longer be able to offset non-OPEC declines, and that we will be in an irreversible decline. (There is a note that ethanol is now contributing around 1.5 mbd to world liquid fuel production.) He explains the basis for the production estimates and is discouraging of the Arctic being able to produce anything new and significant in time to be meaningful. He sees oil sand production as being restricted to 2.5 mbd (following David Hughes arguments). He does not see Brazil being able to export much as it develops its off-shore fields, and while Iraq has a lot of potential (perhaps as much as 8 mbd) but again tit will be produced oo late for near-term impact.

The post has been followed by several lengthy comments including one on spare OPEC capacity particularly dealing with Saudi spare capacity, also here that I would like to disagree with a little. And since the comment may also apply to other OPEC countries, it may relate to the coming production of oil over the next five years, in a way that makes the future a little less grim than Tony sees it. (He made a more comprehensive review back in March which covers much of this information.


My quibbles with these comments relate to the reality of managing production from a multitude of wells, in the presence of considerable water cut. The volumes that are involved are considerable, and Aramco must pump large volumes of water to sustain existing production. So when Ace says:

First, a little history about what Saudi Arabia claims and what has happened. The chart below shows Saudi Arabia's production history. Oil prices tripled from 2005 to mid 2008. Surely Saudi Arabia's production would have increased given its huge capacity. Instead Saudi Arabia's crude production decreased from 2005 to 2008.

I begin to demur.

I talk with folk who are producing oil increasingly often, one was in my office yesterday, and commented that he had shut in a number of wells because of the declining market. We were discussing EOR and I will suspect it is going to take a bit more than a year, and perhaps two, before even an extremely simple version of one of our systems gets fielded at one of his wells. There is sufficient inertia in the business (read paperwork and regulation) that makes it a lot easier to stop production than to increase it. But, and more to the point, all the time the price of oil was rising in the 2005 to 2008 timeframe, the folks I talk to were extremely cautious – they’d been there before, and were not surprised when the drop came.

Aramco, more than most, design their fields, gathering pipes, treatment facilities that separate the oil/water/gas, and delivery lines to the refineries and other facilities for known production rates. To increase production over that design requires a vast array of capital, and very significant amounts of time. Units are sized for given quantities of oil, certain water cut percentages, and going outside those values, particularly upwards, is not just a case of turning a tap. Thus, when a conclusion is drawn that because Aramco did not increase production, or dropped it, that they are reserve restricted, is reading more into the situation than is justified.

The primary example of this is, I believe, the Manifa field originally scheduled to be now nearly ready for production. To produce the 1 mbd or thereabouts available from the field requires, because of the nature of the crude, that new refineries be built, and these have been planned for. However, instead of there being an increased pressure, and accelerated schedule to bring the refineries into production, they have been delayed and postponed, and now are anticipated for 2013. On the other hand, to meet increasing gas demand, the facility has expanded to include gas from the Arabiyah and Hasbah fields which have been fast-tracked to meet increased domestic demand.

Thus as we look at Saudi production, they did not get over exuberant over the increased price of crude, having been there before, and having been caught that time in the undertow when the prices fell away in an overproducing world. So this time they did not rush to increase production, did not make large investments to immediately change levels, but rather invested more for the long term. Those fields that will come on line take time to develop, and are sized to a certain level of production. If anything they will slip those levels to reduce production, but because of the technical difficulties, will likely not be able to increase levels beyond the design capacity. But remember that reducing production keeps money in the bank for them, and has been shown to keep global prices higher, so they sell less for more. Why try and reverse that model?

And it may be that one or two of the other countries in OPEC may try and follow along. But they are more likely to need the money and have less control of the operation that has been achieved, over the years, in Saudi Arabia.

Now that doesn’t mean that I disagree with most of what Ace wrote, I also suspect that when the economies begin to accelerate upwards again they will find an oil cap below that which we saw last year. Others are already grasping the same point, and it may, eventually, reach the ears of those who are currently busy increasing car mileage by legislation, when, within the time frame they plot, market forces and the rising price of gas, are likely to do their work for them.

P.S. I also disagree with the anticipated 2.5 mbd cap for the oil sands, it may be more likely reach double that, but that is a subject for a different post.

Cost viability and algae

Robert Rapier recently drew attention to the demise of GreenFuel Technologies, the company founded on ideas from MIT and Harvard and supported by millions of dollars in venture capital funding. One of the creative ideas that the company has was to located their plant at existing power stations so that the carbon dioxide generated in the flue gas could be fed into the bio-reactors holding the algae, with the gas also keeping the algae at an optimal growing temperature. It was a company that was in the vanguard of promoting the use of algae in both carbon dioxide collection and liquid fuels production.
The company, however, ran into problems in raising more money in the current climate, and with the technology.

Getting the whole thing to run smoothly, though, was tougher than expected. GreenFuel could grow algae. The problem was controlling it. In 2007, a project to grow algae in an Arizona greenhouse went awry when the algae grew faster than they could be harvested and died off. The company also found its system would cost more than twice its target.

It is that latter part of the paragraph that is the more telling. When folk first consider using algae as a future fuel source, it is often because, when tabulated, algae can produce more fuel per acre per year, than any other crop.

(Source Biodiesel - Growing a New Energy Economy - Greg Paul, Chelsea Green Publishing Company, 2005, 281 pages)
However, getting what has been achieved in the short term, into a production mode that sustains the same yield for year after year is not that easy. Nor is simply finding the best algae the only solution required for the problem.
Given the collapse of GreenFuel, it is perhaps useful to look at some of the things that need to be considered, if you are going to have a shot at a viable algae operation.

First you need to select an algal species. This is not as simple as it sounds, because the initial thought might be to screen all the thousands of algae types that exist around the world to find the ones that (a) hold the most oil and (b) grow fastest. Algae grow by multiplication and so the common metric for the latter is the time it takes to double the volume of algae in a container, with less than a day being a good place to start. And a species that has 50% lipid content (the oil component) is also the sort of ballpark we are looking for. There are a number of candidates that meet (or come close to meeting) these criteria. One of the benefits of the program that the NREL review of algae produced was a filter of the thousands of candidates, that gave data from which to select some of the more productive.

Let us, for the sake of discussion, call one candidate AA, another BB, and a third CC. One of the early things you discover is that some of the better ones grow in salt water (seawater) rather than in river/lake conditions. That makes a little difference, particularly if you are interested in putting your algae operation (we’ll call it a farm) out in the middle of the country many miles from an ocean. So that if you need that water you can either make it or import it, neither cheap.

And speaking of cheap, one of the first steps is to decide how you’re going to contain your algae and growing medium (nutrient). GreenFuels used plastic tubes, but as Fireangel pointed out over at The Oil Drum these are very expensive and he concluded

That leaves gross profit of $3.00. That means at current prices it would take 50 years to just cut even on their investment. That is clearly not feasible. For one thing these polycarbonate sheets take a lot of UV damage and their useful life is almost always less than 15 years (usually 10 years).

It seems that at a recent algal biofuels meeting it was concluded that the large flat race-track type of layout is the only one that stands the chance of financial viability.

But that selection brings its own concerns. For the light to reach the algae throughout the water column in adequate quantity, the water can only be around 6-inches deep. This means that the ponds have to be large, (bringing in construction and other land costs). It also limits the species that can be grown, since the conditions are more tempered by local conditions and survivability. This almost mandates, for open systems, that the local conditions select the algae, rather than picking the best. (Which helps explain why we chose a confinement strategy based on facilities constructed for other purposes and paid for, but that is another story).

So having selected the algae and the farm, the next cost is for the nutrient that the algae needs, and to supply the carbon dioxide. Here the potential for beneficial selections should be considered, some algae for example can use sewage as the nutrient, and if cap and trade comes along, then some of the income can come from the carbon captured and used by the algae. (Proper distribution of the gas, and keeping the right quality and concentration also costs, as may the supply and its transport)

Having grown the algae, the next step is to harvest it and separate out the algae. There are some interesting new concepts (bearing in mind that the algae are a very small percentage of the pond volume).

One way of reducing the costs of separation by using an algae, such as botryoccocus, that weeps oil rather than creating it internally.

Another, Phycal, is trying to harvest oil from algae without killing the algae. Instead, Phycal bathes the algae in solvents which can suck out the oil. Some strains of algae can go through the process four times or more.

There seem to be two snags to the process, the first being that the algal productivity seems to decline with cycle number, and the other is that the biomass itself, once the oil is removed, may have value.

Costs from Solix for example:

Algae biofuel startup Solix, for instance, can produce biofuel from algae right now, but it costs about $32.81 a gallon, said Bryan Wilson, a co-founder of the company and a professor at Colorado State University. The production cost is high because of the energy required to circulate gases and other materials inside the photo bioreactors where the algae grow. It also takes energy to dry out the biomass, and Solix uses far less water than other companies (see Cutting the Cost of Making Algae by 90%).By exploiting waste heat at adjacent utilities (one of our favorite forms of energy around here), the price can probably be brought down to $5.50 a gallon (see Will Waste Heat Be Bigger Than Solar?). By selling the proteins and other byproducts from the algae for pet food, the price can be brought to $3.50 a gallon in the near term.

OriginOil noting that

“The energy cost of extracting algae is 10 times the energy cost ofextracting soybean oil,” Riggs Eckelberry, CEO said.

has a video on their site showing a cheaper way of getting the oil out.

The process also generates glycerin and oxygen as byproducts that could be collected and become part of the saleable product.

Alternately the algae can be used to generate natural gas ) as suggested by Genifuel

It works like this. Algae is grown in ponds and, while it is still wet, is it placed in gasifiers with a chemical catalyst that allows it to cook at relatively low pressures and temperatures, said president Jim Oyler. It cooks at 350 Celsius versus 700 Celsius.

The cooking produces a synthetic gas that is 65 percent methane, or CH4, and 35 percent carbon dioxide along with some other trace materials. The carbon dioxide is then pumped into algae ponds as food. It will be more expensive than natural gas pulled from the earth, but it will require lower subsidies than liquid algae fuel to be competitive with its fossil fuel equivalent. It yields 0.55 liters of gas per gram of dry material, Oyler claimed.

There are thus a lot of considerations (I really did not get into efficient light use, correct fluid temperatures, and secondary processing) which led to the conclusion some time ago that this has to be addressed as a system problem, and set of solutions, rather than piecemeal. Profits and income streams from as many sources as possible have to be included, since without them, as with GreenFuels, the concept is not enough to be sustainable. And to develop the systems approach needs a lot of different inputs.

The TWIP and Mikael Höök's thesis

Being more than usually “out of it” last week I missed the new TWIP, but hopefully can get back on schedule this week. It is actually a good week to do so, since the Summary Page of this week’s information has been written to provide some explanation of the inter-relationships between World Oil capacity and crude prices (and thence gas pump prices). They point out (as I have tried to in the past) that by the middle of last year the spread between global crude production capacity and demand was down to 1 mbd, with operators running at 98 – 99% of capacity. As global markets have dropped, it is very largely the OPEC nations that have “eaten” the cut in production. And it is in this variation in OPEC capacity (non-OPEC continuing to produce about at capacity) that there lies (inversely) the world price of oil.


They end that section with the comment “Although forecasts of future oil market conditions, like the projections of the future performance of this year’s NFL draftees, are inherently uncertain, the development of forecasts that are likely to be most useful requires a good understanding of many contributing factors and indicators.”

Agreeing with that sentiment, it also allows me to disagree with the EIA conclusion that there is now sufficient excess capacity to dampen future price rises. There are two basic concerns – the first is that if the control truly now lies with OPEC, and that there is sensibly no extra production elsewhere (see below) then the OPEC desire to have a higher price (about $75/bbl) becomes more easily achievable for them, particularly if demand rises as it seasonally does. Covering that point with a couple of additional graphs from the TWIP first, I’ll come back to my second point thereafter. Oil has already returned back to $60.

With vacation time coming, and the possibility of more conservative vacations (which may mean more driving to nearby domestic destinations than flying to foreign ones) the intake to refineries is rising, as it seasonally does:

Source EIA
It is of interest to note that within that increased inflow, domestic production has fallen off its recent rise:

Source EIA

(The difference is coming from stock drawdown). On the output side, however, there has not been the usual seasonal increase, rather gasoline demand is remaining remarkably stable. (Given the continued decline in the economy this is worthy of note).

Source EIA

The other concern that I have with the EIA projections relates to decline rates. World projections have held these, as an average, at around 4-4.5%. The actual value is something that was often debated at The Oil Drum and continues to be one of my concerns. Back in February Merrill Lynch anticipated 5%, with a possible increase (due to reduced levels of investment) to 6%.

Arguing for higher numbers comes Mikael Höök's licentiate thesis (he’s one of Kjell Aleklett’s students) produced this month, in which actual field values, which prove to be significantly higher than 4.5%) have been found. He notes that the introduction of newer technology (such as, for example, horizontal wells) accelerate decline rates. He points to real production drops that exceed 10%, and notes that, with time these numbers accelerate (in contrast with many assumptions that they remain constant), citing the Norwegian giant fields where, in aggregate, the decline rate increases 1% per year. (It is only by adding new field production that this fate can be delayed). Smaller fields decline faster, the smaller the category the higher the rate.

Working from the initial Norwegian case, he moves on to consider the global situation. He points out the differences between land-based systems and offshore and between OPEC and non-OPEC (the former tend to see the impact of quotas that don’t usually apply outside OPEC). Decline rates had a mean value of 6.5%. But when land and offshore were compared land averaged 4.9%, while offshore was at 9.4%.

He notes that the OPEC strategy of “resting” fields to go for greater overall production, rather than the shorter term high production rates does yield lower decline rates. (Average OPEC decline 4.8% vs 7.5% for non-OPEC).
Field decline rates differ from those of individual wells, since in the pre-peak production years for the field additional wells can be added to compensate for the decline in older ones, and overall production can be held at a plateau. This plateau continues until somewhere around 40% of ultimate recovery, at which point the decline rate takes hold and increasingly dominates production. He does point out that Ghawar can be assumed to be in the 43 -48% range, which suggests that its decline and “Twilight in the Desert” is coming soon.

The thesis is very readable, covers the biotic:abiotic debate in much better detail than I just did, and in its tables and figures has enough data to be seriously worrying, since the numbers are not theoretical, but come from actual values.

It highlights the concerns that I have with the EIA projected future, and is a free (pdf) download that is well worth the time to read. And when you realize that virtually all the significant numbers for the decline rates are well above many current model presumptions, and that even in this time of recession decline rates continue to act we-e-ell. . . . . . .

Nabucco, or is the Great Gas Game turning into a waltz?

It seems as though, whenever things are relatively quiet in the energy world, which they currently seem to be, then all one has to do is type Gazprom into Google search box, and there will be some interesting snippet.

And lo, it appears that Gazprom is looking into a take-over one of the Hungarian gas pipeline networks. Now that is not what the initial part of the post says, where it notes that the Hungarians are switching their gas purchases from a company (RosUkrEnergo) (RUE) that purchased Russian gas through Ukraine, to a company known as Rosgas AG. As part of the fallout from the January dispute between Russia and Ukraine RUE lost that business, and now Hungary has found a new middleman, Rosgas.

The immediate suspicion is that RosGas AG is yet another in a long line of shadowy intermediary companies created by Firtash and Gazprom. However, in the case of RosGas this may mask a possible attempt by Gazprom to cut gas supplies to Firtash's Emfesz, as a precursor to a company takeover - vastly increasing its share of the Hungarian domestic gas distribution network.

This becomes of some importance when one looks at the relative prospects of the two alternate paths for new gas to reach Western Europe – South Stream and Nabucco. South Stream is being increasingly pushed by Gazprom. The pipeline will bring gas under the Black Sea, and pass through Serbia and Slovenia before reaching Austria. However Eni, who is a 50% partner with Gazprom in this stage of its development, is upset that Gazprom is keeping it out of the negotiations with Serbia and Slovenia. Both countries are anticipated to sign agreements with Gazprom in the near future, without Eni, for gas supplies from South Stream.

And this may be where Hungary comes in, since the competing Nabucco pipeline goes through Hungary to get to the Austrian hub. So that if Gazprom controls the Hungarian pipelines, and can stop competitors’ gas flowing through them (a fact they used to get TNK-BP out of the rich Kovytka field after TNK-BP had developed it.) It is yet another couple of nails in the Nabucco coffin.

Earlier this week, with a fanfare celebrating the coming signature of the Nabucco agreement to run gas through the pipeline across Turkey it looked as though the pipeline was moving rather rapidly forward. However, buried within the story is the backing off of European funding

The European Commission is proposing to scale back its support for the Nabucco project to 200 million euros ($268 million) from 250 million euros, Tarradellas said in February. The aid would be channeled through the European Investment Bank.

At the same time, the last paragraph is interesting.

Friday's statement, signed by leaders of the EU, Azerbaijan, Georgia, Turkey and Egypt, also said the EU and Egypt should "agree on specific projects in developing Egypt's gas reserves and export potential for the EU." It said it was signed "in the presence of the representatives of Kazakhstan, Turkmenistan and Uzbekistan."The statement also called for a memorandum of understanding on energy between the EU and Iraq "as soon as possible." Barroso said a preliminary energy accord with Iraq was "imminent."

There are nuggets in that paragraph – first the pipeline cannot be effective without the gas from Kazakhstan, Turkmenistan and Uzbekistan. But none of them signed the document. Further Azerbaijan does not think that the project is feasible without Turkmenistan. The Turks will get paid for their trouble

The Turkish government has been driving a hard bargain, insisting on collecting a "tax" on the gas being pumped and demanding 15 percent of the transit gas at discounted prices. These requests have been rejected by the European Commission, the executive branch of the 27-nation bloc, delaying the 9 billion-euro project. More than half of the pipeline is to be located in Turkey.

But getting them on board helps negate the pressure that Russia (read Gazprom) is applying to discourage the “stans” from selling Nabucco their gas.

So as steps in the Great Game you could say that Europe took the first by planning Nabucco, then Russia took the second by stopping an adequate supply availability through pressure on Turkmenistan etc. Europe now gets the third, since with the pipeline running through Turkey they can (if politics allows) run connections into Iran, Egypt and Iraq. And before the step is completed Russia moves to step on their toes and gain control of the Hungarian section, thereby taking the fourth.

With Austria involved, maybe this part of the game is turning into a waltz – but with constantly changing partners - we shall see.

Geologic Time, Oil Formation and Secretary Chu

Last week ,as Climate Audit caught, the Seretary of Energy was asked about how oil and gas got into the Arctic Rocks. Now there is a little catch to the question, in that for oil to be formed the local environment has to be quite warm particularly relative to today’s Arctic temperatures (as explained below). Thus, to explain how the oil got there, the Secretary would have to admit that there was a period when the Arctic was warmer than today. However Dr Chu did not want to give that answer, and so he proclaimed that the rock and oil-forming algae were deposited elsewhere and then migrated, under Continental Drift, until they ended up in the Arctic. Steve gave a condensed answer pointing out how wrong the Secretary is on this, but I thought I would use the error as a base for explaining the origins of oil and natural gas in a post that I can then relate to later.

The majority of world opinion on the matter, has concluded that oil and natural gas originated in the bodies of small organisms, such as modern algae, which can include up to around 56% lipid material (their version of fat). This is referred to occasionally as the biotic source, as opposed to an alternate theory, the “abiotic” theory. This latter theory, which came out of Russia and gained some acceptance in the West, in essence says that oil is generated deep underground by chemical reactions, similar to the Fischer-Tropsch process used to make synthetic oil. While the relevance of this process to oil supply has been disputed, it relies in part on the idea that there are deep pools of oil that fill old reservoirs back up after they are depleted and that if we just drilled deep enough to find them we would have an almost inexhaustible supply. And the catch with that relates to the formation of oil and gas through the biotic explanation.


The biotic explanation for oil and gas formation proposes several steps along the way. First we have the rivers and shallow seas where the algae flourished and died. Sinking to the bottom they mixed with the sediment that is also deposited in such places (and which can be seen in parts of the world today). With time, as with the formation of coal, the sedimentary beds that hold the nascent hydrocarbon fuels are buried deeper. With an increasing depth of burial comes an increase in pressure and temperature. As a very rough rule I use 1 psi of pressure for each foot of burial, and 1 degreeF for every 60 ft of depth startin at 60 deg at 60 ft. So that, for example, at a depth of 3,000 ft the ground pressure is 3,000 psi and the temperature will be 110 deg F.

An early step along the way, as our hydrocarbon starts to cook is its transformation to a kerogen. This is the “oil” of the oil shales of Colorado, New Mexico and Utah. It is not yet a liquid and does not flow. To get to that stage it has to be buried deeper and heated longer. That is what Shell is planning to emulate with their process for oil recovery from the shale. By inserting long heaters into holes down through the rock, and raising the temperature to 650 – 700 deg F and holding at that temperature for 2-3 years they hope to complete the transformation. The temperature is higher than that which would be needed for the natural process, because the process must happen faster. With nature and depending on the part of the world you are in (since the geothermal gradient varies) the transition will occur when beds lie in the 3,000 ft to 15,000 depth.) (Temperatures up to 300 deg F range. ) This depth range is often referred to as the oil window, since shallower rocks aren’t cooked well enough and we get kerogen, and if the rock goes deeper then the higher temperatures will “crack” the oil into natural gas.

(Which is where the problem of deeper pools of oil for abiotic oil comes up, since the deeper pools that the theory calls for would exist at depths where the oil would be cooked into gas, and thus no longer available to supply the oil).

As the oil heats it also thins and becomes less sticky so that it can start to slide through the grains of the surrounding rock, passing along small cracks and being pushed up, in part by the water that was trapped in the rock with it, and which starts to collect below the oil. The oil will move up through the layers of rock until it either reaches the surface, or it is trapped below a rock which does not have the passageways (permeability) wide enough for the oil and water to pass through.

Similarly the deeper deposits that have turned into gas will also begin to move up until they too are trapped beneath an impermeable cover or cap rock.

OK, so when did this happen? Well it depends on the place you’re at. But, for example if we go up to the North Slope of Alaska, the rocks that generated the oil are known as source rocks, and the USGS has identified rocks of the Triassic (the Shublick) ; the Jurassic (Kingak) and the Cretaceous periods may all have contributed oil.

Source USGS

Now a quick peek at a geologic column tells us that these are periods of the Mezozoic Era which ran from the end of the Cretaceous ( 65 million years ago) through the Jurassic (ending 165 million years ago) to the Triassic which ended 208 million years ago. They are younger than the Carboniferous, when coal beds were laid down, by some 40 million years or more.

However, to get back to Dr Chu’s point about Continental Drift having carried the oil bearing rocks up to Alaska, after they were formed, if you go to any of the models which show how the plates have moved, the North American plate (which includes Alaska) was already up in place as far as the North is concerned (but then drifted West) by the beginning of the Jurassic.

So while this was a good try by Dr Chu, a Climate Warming devotee, to get around some geological truths, the facts argue against him. (Not to mention more recent findings within the Holocene, our current geological Era), but we'll save those for another day.
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Jatropha, algae and camelina oils

If you had not gathered this before, then you should know that I have been favorably impressed with the potential of algae as a future source of biofuels. However I recognize that there is a considerable amount of research and business development and growth that will have to occur before such fuel makes a significant impact in the market place. Of the other alternative biofuel sources, I was also considerate of jatropha, which seemed to have some significant potential. The fuel comes from the nuts which the shrub produces, and since it can be grown on quite poor land, and in some countries is already in use a fencing plant I anticipated that its potential would be increasingly recognized. Well it has not quite turned out the way that I thought it would, at least not yet.

And so some comments on what has, and has not happened. Jatropha seems to have its own slogan “Soil to Oil” with a Center for Jatropha Promotion & Biodiesel located in Rajasthan in India. Jatropha curcus is a shrub or small tree that can grow on poor to marginal land in tropical parts of the world, growing to a height of perhaps 15 ft. It produces a nut in clusters of around 10, and the nuts contain seeds which are about 37% of an oil that will run a diesel engine without further refining.

Thr oil has been used in a 50:50 blend with jet fuel to power one engine of an Air New Zealand 747 on a 2-hr flight last December 30th. The oil has a lower freezing temperature than jet fuel, and has been estimated to cost around $43 per barrel. This flight was followed, on January 7th by a Continental Airlines flight which used a 737-800, and a mix of oil from jatropha and alga. The flight saw a 3% gain in fuel use by the engine using the biofuel. The algae oil came from Sapphire Energy the jatropha came from Terasol Energy. The biofuel was mixed 50:50 with jet fuel, and there were no modifications made to the engine.

The success of the test has encouraged Sapphire, who are now predicting that they will be able to produce 1 million gal/year (65 barrels/day) of diesel and jet fuel, rising to 10 million gallons (650 bd) by 2018 and 1 billion gallons (65 kbd) by 2025. Sapphire is based in San Diego.

Terasol supplies both oil and feedstocks, concentrating, at the moment, on jatropha and castor bean oil.

Japanese Airlines carried out their own test on January 30th. The Japanese flight, an hour-and-a-half long, used a mixture of 84% camelina, under 16% jatropha oil, and under 1% algal oil.

Camelina, (or wild flax) incidentally looks as though it deserves more investigation, since it grows on poor ground and has twice the yield of soy. Further it also has a low gell temperature.
The spent biomass is recognized as a good animal feed, and it grows in places like Kansas and Montana, perhaps alternating with wheat, in which combination it apparently increases the wheat yield by 15%, and gives 100 gallons/acre of oil.

Dr. Bill Schillinger at Washington State University recently described camelina’s business model to Capital Press as: “At 1,400 pounds per acre at 16 cents a pound, camelina would bring in $224 per acre; 28-bushel white wheat at $8.23 per bushel would garner $230.”

Returning to jatropha, the President of Terasol recently answered some questions for Scientific American. He noted that the main problem the fuel now faces is one of scale.

the main obstacle is the lack of research and practice in large-scale commercial cultivation, as well as mechanized harvesting. Currently most jatropha and castor are grown on smaller, independent farms. The second obstacle is yield and unit of input. Research in plant breeding needs to continue in order to improve the quantity and quality of oils being produced.

They see commercial quantities of the jatropha being available in 3-5 years.

The optimistic view of jatropha’s future is becoming less common, even as it is projected as a fuel of the future. There in fact some doubts

Not only was the cultivation of jatropha supposed to absorb more CO2 from the atmosphere than it released, but the miracle tree could also stabilize and restore degraded soils. That’s surely why Scientific American in 2007 called jatropha “green gold in a shrub,” a plant that “seems to offer all the benefits of biofuels without the pitfalls.”

Fast forward a couple of years. By 2009, governments from China to Brazil, along with several major biofuel companies, had planted — or vowed to plant — millions of acres of jatropha. In India alone, the government has announced plans to subsidize an intensive program to plant jatropha for biofuels on 27 million acres of “wastelands” — an area roughly the size of Switzerland.

The problem, again is one of scale. With the average farm being around 12 acres (at 2-300 gal/acre/year) the current gains come mainly from local use, rather than collection to meet larger national goals.

For example in Mali the nation has some 10,000 km of jatropha hedges that yield about 1 kg/meter/year. If all the nuts were collected and processed this would yield around 5 million liters per yr of oil (85.8 bd). Typical village hedge lies between 2 & 15 km, making oil generation very much a local enterprise. It is growing because there has been a move to provide local women with engine powered grain mills, to start small businesses. But the fuel cost was prohibitive. Collecting and processing the nuts can not only provide the needed fuel, but also inject about $3,800 on average, per village per year. As a result local hedges are growing in length, though somewhat slowly (from 5 – 15 km in 8 years.) The projects have also benefitted from development of a shelling machine for the nuts.

But while the growth is commendable, it is nowhere near working at the scale needed to have a significant market impact.

Can politics be removed from biofuel generation?

The Administration has been praised for its move to rely more on science in the generation of policy, and on Tuesday a new group was announced that will work to encourage a new generation of biofuels.

The working group aims to accelerate funding to biofuels producers, in the hopes that they will phase out fossil fuel use at their own plants, instead using biofuels.

The group, which will be headed by the chiefs of the Environmental Protection Agency, the Department of Energy and the Department of Agriculture, also exists to encourage a new generation of biofuels made from biomass and other non-corn feedstocks.

Part of the study will, however, try to create a standard for assessing the GHG costs of producing and using the new fuel.

Mirroring a similar change in California, EPA is proposing to measure carbon emissions that come as a result of biofuel production. This includes a complicated and controversial formula that adds in emissions that occur when overseas farmers respond to higher food prices by converting forest and grassland to cropland.

“Life cycle estimates of the greenhouse gas relate to the fuel cycle and land conversion,” said EPA Administrator Lisa Jackson. “This research will be very important to future policies.”

It may well be that the “controversial” formula may take the discussion out of pure science, and give the opportunity to ease politics back into the discussion.

Certainly the Administration recognizes the financial cost, with some $800 million of DoE stimulus money being directed at research, development and the funding of test projects. However $484 million will go to demonstration projects, some of which are already being funded. The major emphasis seems to remain on generating ethanol, though an algae biofuels consortium will also be funded. This is to be followed by $1.1 billion in DoA funds much of that will go to help producers, through the biofuels credit program, restructure their businesses to survive. At present production is down and there is not enough (if any) profit to be made between the price of the corn feedstock and the sale of the ethanol.

The carbon costs of each process, will be calculated by the “controversial” formula, but the calculation was first subjected to “peer revew.” Though I guess that the validity of that process depends on the peers that were used.

In regard to the algae effort the Univ of New Haven are looking for better strains of algae to use. They note that some $195 million was raised for investment in algae work last year.

One of the greater drivers for algal biofuel development is coming from DoD who are anxious to find a replacement source for the jet fuel, on which an increasing percentage of their mobile systems run. DARPA have been taking a lead in developing this research. One of their advances has just been given some publicity

Researchers at the university (UT) have already developed an electromechanical process for extracting oil from an alga cell that is rapid, energy-efficient, free of solvents and less expensive than competing methods. The technique employs electric fields to break open the cell.

Another group of researchers at the university is focused on the science of separations research and is identifying techniques to separate the oil from the algae biomass once it has been released.

In another development Richard Sayre at theDanforth Center in St Louis has discussed the use of algae that can be milked instead of being destroyed. The goal of the DARPA program is to reduce the cost of the biofuel to $3 a gallon.

The fact that algae make fuel while consuming CO2 is also being presented to Congress at the same time as a new report on the subject is being released. (pdf).

In perhaps a sign of things to come, an ethanol plant in Iowa is going to add some algal photobioreactors to the plant. The algae will take advantage of the water heat and CO2 generated from the ethanol plant, with hopes to use some 60% of the CO2.

Wind in the Rockies is expensive

Government policy can, once decided, be implemented by a combination of laws and financial incentives/disincentives among other means. Thus, for example, when trying to change the ways in which America gets power, the government can limit the amount of coal burned, both by direct fiat, and by making it too expensive (through the cost of permits). The former limit will be established through the caps on the production of GHG, assuming that there is no immediate vast investment in sequestration. There is a fair amount of debate over whether the financial incentive will be through a direct tax or the more indirect route of charging for allocations. Having heard Congressman Waxman’s aide at the EIA meeting, I believe the decision is long over, and that, if anything does come out of this Congress it will be the cap and trade model that will be used.

That having been said, since the nation is growing in numbers, even if per capita use is held constant (as it has sensibly been in California) any reduction in fossil fuel use will need to be replaced with an alternative. At present the most widely touted of these are wind and solar, and the high costs of solar mean that, for many utilities seeking change, wind has been the choice, but even this is, in some cases, proving to be too expensive an option.

Wind farms are becoming more obvious around the country, and their message is strengthened with a steady campaign of adverts. T. Boone Pickens is seen more as a savior than as a salesman. And the Secretary of the Interior currently is pointing out that there is sufficient wind available to replace all the coal-fired power stations in the country. But under all the hype, and after the cranes have come and gone, the change in energy source has to make economic sense. Wind farms will only be established where there is a credible likelihood of their making money for the investors that raise them. The current comments of the Secretary come as hearings get under way around the country.

Salazar said ocean winds along the East Coast can generate 1 million megawatts of power, roughly the equivalent of 3,000 medium-sized coal-fired power plants, or nearly five times the number of coal plants now operating in the United States, according to the Energy Department.

Salazar could not estimate how many windmills might be needed to generate 1 million megawatts of power, saying it would depend on their size and how far from the coast they were located.

Mark Rodgers, a spokesman for Cape Wind, which wants to build a wind farm off Cape Cod, Mass., estimates it would take hundreds of thousands of windmills. The average wind turbine today generates 2 to 5 megawatts per unit, he said.

This is the first of four hearings, and focused on the East Coast. But the potential states most likely to benefit can be judged from the DoI plan to create Regional Energy Permitting Centers.

To expedite production of renewable energy on public lands while protecting land, water, and wildlife, Secretary of the Interior Ken Salazar today pledged to create four Renewable Energy Coordination Offices, one each in California, Nevada, Wyoming, and Arizona, along with smaller renewable energy teams in New Mexico, Idaho, Utah, Colorado and Oregon.

You may note that these are all in the West.

While the numbers quoted are large, and the potential benefits of moving to renewable energy are continually being cited, the underlying realities of getting a good return on the investment, at a lower cost than the alternative, is being kept quiet. Unfortunately, as an article in USA Today notes, even with the best will in the world, those benefits don’t always happen. And, in the case of Durango, CO, the utility is moving back to coal, from wind.

For two years, the city of Durango, Colo., bought electricity for all its government buildings from wind farms. The City Council ended that program this year, reverting to electricity derived from coal-burning plants and saving the cash-strapped city about $45,000.

The Durango plan has its roots back in 2007 when the city made the move to wind energy.

Green power currently constitute(d) about 10% of city power purchases. The extra the city pays for green energy will add about $120,000 a year to its electrical bill officials said. But the extra cost will be offset by an energy audit aimed at cutting power consumption. With the wind power option, electric customers pay $1.25 per block of 100-kilowatt-hours in addition to their regular rate. The extra that consumers pay for their power funds investment by power producers in alternative-energy sources such as hydropower, solar and wind. But electricity from all sources flows on the same line. In 2006, Durango used almost 8.15 million kilowatt-hours of power at a cost of $779,000.

At the time, as you may notice, the city recognized that the renewable energy would cost more, but felt that it could make up the difference with improved efficiency. Which is the same sort of argument that we are now getting from the new Administration.

Although the above cite is recent, the change actually occurred last December.

City Manager Ron LeBlanc recommended the city stop buying power from renewable energy sources when it became necessary to cut the 2009 budget by more than $500,000. The city council approved the budget, including his recommendation, earlier this month.

The La Plata electric association charges 80 cents more per 100 kilowatt hours for electricity from solar and wind power. LeBlanc says that adds $45,000 to the city’s annual electric bill.

La Plata does not generate the power itself, but is passing along a program from Tri-State.

The LPEA Green Power program was initiated in 1998 when Tri-State – from which LPEA purchases its power – responded to requests by its member systems, to include a green power option as part of its available resources to end-use consumers. Because of this program, LPEA customers who request purchase of green power receive it at LPEA’s cost from Tri-State, $1.25 per 100 kilowatt-hour block per month. Purchasing one block of Green Power costs consumers less than $.05 per day. To date, LPEA is among the leading purchasers of Green Power in Tri-State’s 44-member cooperative system, supplying nearly 800,000 kilowatt hours of Green Power generation each month.

Tr-State had lowered their costs to 80 cents in January, 2008. . However the company has also carried out an Integrated Resource Plan (IRP) looking at future energy supply, based on anticipated need. That plan concluded:

Tri-State proposes to develop and own two new 700-megawatt supercritical coal-based units at the existing coal-based, 360-megawatt Holcomb Station in western Kansas. The efficient units would include best available control technology to minimize air emissions and activated carbon injection to minimize mercury emissions. The IRP clearly reinforces the need for the first 700-megawatt baseload resource in 2012, which is when Tri-State first unit at Holcomb Station could be online.

Since the first Holcomb unit cannot be brought on line until 2012, Tri-State is left with a significant deficiency in both capacity and energy during the interim period; and its options are somewhat limited. For modeling purposes in this IRP, it is assumed that Tri-State will install combustion turbines (CTs) as soon as possible and purchase energy from the market. However, there are many other options available to Tri-State.

These are the coal-fired power plants that then-Governor Sibelius vetoed three times, with part of her argument being that more than 80% of the energy they would produce would be exported. Which leaves one wondering where the power will come from for Durango, since I am presuming that the turbines are gas-driven, and thus too expensive.

(Um! Yes I know that Durango said that they are going back to coal, and have so moved, but Tri-State still has their supply problem, or will as soon as the economy picks back up without the new stations they were relying on.)

Some short notes

The end of the month, and the enforced rest, was going to give me time to catch up on a couple of things, but it turns out that there is a good reason (in the level of medication among others) for the rest, so things will needs must wait. And talking of waiting, it turns out that , despite some earlier predictions to the contrary, spring has been coming later to parts of the Arctic rather than the uniform earlier spring that is usually reported. The location of the relatively earlier warming zone along the southern Norwegian coast makes it appear that the phenomenon may be sea current based).

By the way, also in regard to waiting, the Actress went ahead and ordered her Fusion this weekend, in the same color as the story, but had to travel, and make a number of calls, to find a dealer who had one. Even so the single one on the lot was not quite right, hence the order. We were told to expect a wait of 3-6 months, before delivery. We’ll keep you posted.

Last summer Lausanne became the first Swiss city with an underground metro and there are still plans to move ahead with a more comprehensive metro system for the country, with the goal of allowing a train ride that will take only 12 minutes to get from Zurich to Bern. It was in Zurich, this past weekend that the Nurse became a Grandma, welcome to Pippa Fiona.

Despite heavier than usual snows most of the glaciers in Switzerland are continuing to retreat, but while the headlines are for the one that retreated most (the Gorner retreated 290 m) the average retreat was less than 25 m. No-one makes much mention of the two that advanced.

A quick look at gas and miles travelled

Having missed both This Week in Petroleum, and the monthly release of miles driven, I thought I would just pop these up. Partially because we are seeing a slight pickup in miles driven, in parts of the country, which slowed the drop. (But bear in mind that this plot includes information only up through February.

February miles travelled

Let me just look in more detail at the end of the graph.

Top part of the Curve showing the change in slope.

If we look up at the top, the declining slope of the line is beginning to turn up, a little. When we contrast this with the data from TWIP on gasoline demand, one can see that this is remaining sensibly flat.

(Source EIA)
While the historic pickup that usually applies from April through June is not evident, the slope does appear, if anything, a little positive. But it remains early to make predictions, or do anything much beyond remaining optimistic.