The Shell future - a look at their new projections

I have recently reviewed the predictions made by BP and ExxonMobil as they relate to energy supply and demand in the years to 2030. Shell has just updated their predictions, which extend further out to 2050. In the opening discussion they make the point that new technologies will require, in their words significant time to develop.

New energy technologies must be demonstrated at commercial scale and require thirty years of sustained double-digit growth to build industrial capacity and grow sufficiently to feature at even 1-2% of the energy system.

Thus much of the focus of the report deals with existing fossil fuel capabilities. Specific new factors that have led to the modification of earlier predictions include the greater instability of the global economy; the growth of uncertainty over regulatory steps that will be taken both to address the concerns over climate change, and in light of the Macondo well disaster; the improved supply potential for natural gas both from shales and coal bed methane supplies; and the emergence of a re-invigorated Iraqi energy industry with a potential to develop significant new resources.

Shell has, in the past, developed two different energy scenarios – the first of which it calls Scramble, where the world moves along a Business As Usual (BUA) scenario, only making changes as these become forced upon governments and companies by the impact of changing circumstance. The second is called Blueprint, a scenario that Shell is now announcing it will advocate, where instead of the reactive approach of Scramble, a set of plans is developed to pro-actively address the issues of carbon dioxide generation, and to ensure the world has adequate energy.

The difference between the two approaches was illustrated in the initial document by the predicted sources of energy through the years to 2050. By putting these one after the other, it is possible to compare how supply changes in their two scenarios.

1. Energy supply scenarios for the future – Shell Scramble scenario

2. Energy supply scenarios for the future – Shell Blueprint scenario

One significant change between the two, apart from the lowever absolute level in the lower case, is the smaller role that biofuels play in the more distant out years. For example in the Scramble scenario they are given a much greater role in that future.

Change in biofuel energy production in the Shell Scramble scenario.

In their new set of projections Shell has more forcefully adopted the Blueprint route, and has produced an amended projection of future energy sources through 2030 that makes it easier to compare with the ExxonMobil and BP plots that I have posted in the past.

Comparison of BP and EM energy futures, (The vertical scale is in billions of tons of oil equivalent. )

However, each company having their own set of units, the conversion needed to compare with the earlier plots is that an ExaJoule (EJ) is about equivalent to a Quadrillion Btu (Quad), and a billion tons of oil is the equivalent of 41.9 EJ.

Shell energy sources for the future. Dividing the vertical scale by that 41.9 gives an equivalent full scale value of 19 billion tons of oil equivalent, not that much different from the two other plots above it.

Two things are evident from this plot, one being the increased role that Shell see natural gas playing over the next 20 years, and the other the decrease in the likelihood of biofuels being more of a significant player in that time frame.

The sources for these levels of production are left quite vague in the Shell document. Only the promise of increased production from Iraq – seeming to accept the more optimistic projections of the Iraqi government – is given as a justification for seeing sensibly no decline in overall oil production levels to 2030. However since Shell is a part of some of the new deals which that Government has struck perhaps there are reasons for this optimism. For those who forget:

Officials say the deals will boost Iraq's oil-producing capacity to around 12 million barrels a day by 2017, putting it on a par with Saudi Arabia. That, said Mr. Birol, "may be a challenge to the other oil producers."

Um! Yes!

Shell devote much more of their projection document to the impact of climate change regulation and response than do the other projections. One item that caught my attention was their comment on water needs.

Energy producers are amongst the largest industrial consumers of freshwater. The link between energy production and water will intensify as portfolio choices move increasingly towards more water-intensive production methods such as biofuels and enhanced hydrocarbon recovery methods (EOR). In the US alone, where energy currently accounts for 40% of all freshwater consumption, projected growth in energy production will require an increase of 165% in freshwater withdrawal by 2025.

Shell also tabulated, against their projections, past growth rates for different sectors of the energy supply scenario.



To sustain growth, and to change, for example, current coal burning practice to a total carbon capture and storage (CCS) system for coal use globally by 2050 will require considerable investment and continued research and development, and similar levels of continued development will be required to develop all the sources needed to meet demand needs over the next forty years. It will also require a smarter power distribution system.

Sometime between 2020 and 2030, we can expect the constraining factor for renewables deployment to move from industrial capacity building to accommodation within the energy system. This would impact land-use and require new infrastructure, such as major upgrades to grids 8, 9. These are essential for renewables to maximise their share of the energy mix.

The new report closes by citing some of the factors that might indicate that the world is following a Scramble path, and others that it might be moving toward to Blueprint option.

It will be interesting to see which one turns out, in the end, to be closer to reality. But there are plots in this document that show peak oil occurs around 2020.

API and some thoughts on America's Energy Future

There seems to be a little drop in the intensity of the debate over the arrival of Peak Oil. Given that crude oil prices are hovering around $100 a barrel, and quite likely to go higher over the course of the year, it is perhaps only the recent history of oil at $147 a barrel that stops a more intense debate. After all we have been there - done that, before so why worry? Unfortunately this may be the lull before the storm.

Consider that there has been a change or two, even in the short period of time since our last visit to this price range. Last time it was possible to see an increase in production from places such as the United States, and from Russia. Not huge amounts, but symbolic, that production could respond, somewhat to a potentially more expensive product. But this time around it is likely that we will see both United States and Russian production fall this year, even as prices rise. And with a certain complacency evident in the politicians, whose constituents are now paying higher prices for product, things that might be properly done to at least help out, are not seen as that important at the moment.

The API addressed this issue, at the beginning of the year, through the speech of Jack Gerard, their President. Looking at the “State of American Energy”, he was able to point to the number of new jobs that the industry has been able to create both with the development of the Marcellus gas shales in the East, and with the Bakken developments in the North West. He also pointed to the $95 million in taxes, rents, royalties and bonus payments that the Treasury gets from the industry each day. The totality of current jobs was counted as 2.1 million directly employed in the oil and gas industry and 7.1 million in the affiliated industries that work to support it.

Yet, as he noted,

Over the past few years, revenues to the U.S Treasury from lease sales have decreased, due in part to a lack of opportunities.

Our industry is eager to initiate new projects. But without an adequate level of business certainty, with concerns about policies that might curtail this industry’s ability to access new resources, those projects might never get off the drawing board

Part of that uncertainty comes from the changes in regulation that will control drilling offshore from the United States. Some rigs that could have continued to drill in the GOM, but were halted after the Deepwater Horizon disaster have now moved abroad, and may be gone years before they return to American prospects. But until there is a clear commitment to facilitating American production, that exodus may well continue. The severity of the coming crisis is still not evident in the eyes of the politicians and the general public. Further, as the price of oil rises, it is assumed that the wealth of the companies producing the oil is also increasing, and so (despite rising costs that are not mentioned nearly as often) it is assumed that companies can afford higher payments. And with new quarterly and annual profit statements coming out soon, it is going to be a little difficult to defend that position against what is quite likely to be a set of overall record, or close to record, earnings. Even BP had returned to profit at the end of the 3rd Quarter of 2010.

The fact that they are playing in a shrinking sandbox, as producing countries take over more and more of the profit generating parts of production is not seen as a concern.. Yet, as we have seen in places such as Venezuela, the results of government involvement is quite often to reduce the level of investment in the industry, just as investment costs should, in reality, increase to allow discovery and development of the more difficult reserves that will be needed in the future.

As the Venezuelan experience shows “Twenty billion here, and twenty billion there, and soon they are talking real money,” (to misquote Senator Dirksen). And yet those monies are likely to be inadequate to properly develop the resources of that country. Jack Gerard seems the future in the further development of the gas shales, in increasing production from the Canadian oil sands, and in the development of a significant oil shale industry.

At the present there is too much natural gas available for the growth of the gas shale industry to be assured over the next five years. This is not because of the problems that are being stirred up over the chemistry of the fracking fluids, nor the ability of the companies to properly protect the ground water around the sites, those issues have realistically been solved decades ago, and the furor will die away in time. The problem at the moment relates more to the cost of developing the reserves at a time when the market has natural gas available that is cheaper than can be extracted from some of the gas shale wells. And as long as that holds true the industry is unlikely to grow much.

One thing that API did not mention much in the speech, but which came later, in one of Jane Van Ryan’s blog posts, is a valid concern over the march toward E15, that is the use of 15% ethanol in gasoline. That original target was predicated on the assumption that, by now, cellulosic ethanol would be at or close to large-scale commercial production. Well that has not proved to be the case. EPA backed off a little on the targets last year, as Robert Rapier noted at the time. More recently he has drawn attention to the failure of the Range Fuels plant in Soperton GA , which is now closing. After spending $320 million, and producing one batch of ethanol, the company needs more money to solve technical issues.

As far as the national target is concerned:

Congress initially set 100 million gallons as the 2010 target for cellulosic biofuel, but the EPA cut that to 6.5 million gallons. It appears that the industry might have produced less than 1 million gallons last year, reported ClimateWire on Tuesday, citing an estimate by a government analyst.

(On the other hand Valero is moving ahead with plans to invest $50 million in the Mascoma plant in upstate New York, that move will include the purchase of just under a million barrels of cellulosic ethanol) .

That decline is now, however, the concern expressed by API. Among other issues, there are two problems that higher concentrations of ethanol in the mix may cause that are not necessarily that evident. The first is that those of us who use small engines for mowers, chain saws, trimmers etc may find these running unexpectedly hot if they use the new mix. And albeit the manufacturers warn against its use, most of us fill the can while we are refueling the car, and from the same pump.

The other concern relates to the seals in tanks and underground storage.

Just as there are seals in gaskets in cars that can be affected by E15, similar seals and gaskets can be found at the service station and the pump above the ground and the underground storage tank. The DOE recently released some test results of gas station dispensers and the results were pretty sobering. About 70 percent of the older equipment in existence failed these tests and about 30 percent of the new equipment failed these tests. That is a real liability concern because if you are a service station owner and have to determine whether to use E15 in an existing underground storage tank when the replacement costs for that storage tank could be $50,000 to $200,000. The testing that the DOE did was only above ground.

If that weren’t enough – since we won’t have much cellulosic ethanol, we’re going to have to rely on corn. And what is the story on the price of corn? March prices are $6.59 a bushel, and still rallying.

Output in the U.S., the world’s largest grain exporter, dropped 4.9 percent last year, leaving supply before the 2011 harvest at the lowest in 15 years, the Department of Agriculture said last week. The agency also cut its forecast for global inventories to 127 million metric tons, the lowest since 2007.

“Prices have not risen high enough to slow demand,” said Greg Grow, the director of agribusiness for Archer Financial Services Inc. in Chicago. “The attitude among consumers is that you have to buy the breaks to accumulate tightening inventories.”

I guess one of the interesting questions becomes as to whether we will see $5 a gallon gasoline in 2011 or 2012?

Of course we could talk of alternate investments in geothermal, the less popular renewable. But maybe I’ll hold off on that for another day.

Trying to legislate technology

Over on Climate Progress there is a note on the 100th coal-fired power station to be cancelled or postponed in recent months. This one is in Utah, and was cancelled as a result of the decision of the City of Los Angeles to be “coal free” by 2020. The Intermountain Power Agency was going to build a third power station, some 900-megawatts, to meet LA’s growing needs, but this is not to be.

Los Angeles Mayor Antonio Villaraigosa announced last week that the city -- which purchases about 45 percent of the IPA's power -- wants to end its use of coal-fired power by 2020. Villaraigosa said that the city will replace its coal-fired electricity with energy from renewable sources, natural gas, nuclear and hydroelectric power.

It will certainly be interesting to watch how this plays out, given that the best wind sites in the state appear to be already in use, and that there has been a slowdown in growth of new farms, to the point that Iowa has now passed California by. Certainly Baja California is getting into the act, with the promise of having 75% of the power needed for public lighting to come from a wind farm by 2011. But there is a considerable difference between the 10-megawatts of that plant, and the 900-megawatts just foregone. Solar continues to be very much more expensive, nuclear is unlikely to be available within the time frame anticipated, and there has been some debate about dismantling dams that provide some of the hydroelectric power. So it will fall on the back of natural gas to make up the shortfall, or so it would appear.

This would seem to give additional impetus to the prospects for the Ruby pipeline.

As proposed, the Project is expected to include approximately 675 miles of 42-inch natural gas transmission pipeline, beginning at the Opal Hub in Wyoming and terminating at interconnects near Malin, Oregon. Contracts for the pipe have been signed and pipeline construction companies have been selected. The Project will have an initial design capacity of up to 1.5 billion cubic feet per day (Bcf/d) and will traverse portions of four states: Wyoming, Utah, Nevada, and Oregon. Four compressor stations are proposed for the project: one near the Opal Hub in southwestern Wyoming; one south of Curlew Junction, Utah; one at the mid-point of the project, north of Elko, Nevada; and one in northwestern Nevada.

The connection of a pipeline from the currently underpriced supplies in Colorado and Utah into the Western market through the connection in Oregon and into the Northwestern gas pipeline will likely reduce the costs of gas in the West, while giving Colorado and Utah markets for their gas, at the time that they are potentially losing the Eastern market that was targeted with the Rockies Express. That pipeline has now reached Ohio and was placed to meet the need for cheaper gas in the North East. (among other things by replacing Canadian gas, which is also now going to lose the market in California). This market is now threatened by the potential of gas supplied from the Marcellus shale.

The role that hydrofracing plays in all this provides an interesting sub-text. As I have recently noted, there is a move by two Coloradan Congressmen and one from New York to tighten the regulation of hydrofracing. However
industry officials claim state regulation of the practice is more than adequate and that the chemicals used in fracking need to be kept secret for competitive purposes.

They also argue that in 60 years of fracking there has never been a case directly linking it to the contamination of drinking water wells because so many precautions are taken.

Interestingly Colorado has recently passed tougher legislation governing drilling in the state, which includes the need to list the components of the fracing fluid, legislation which is said to have increased costs in the state, and reduced the level of drilling (albeit the price of gas might just also have some effect on this).

The desire by the Colorado Congressfolk to make the rest of the nation work to the same rules as their gas industry (which incidentally does not have that much of the gas shale which requires hydrofracing to be economic) has yet to be decided in the national Congress, but should the legislation pass then the costs to the California consumer may be significant.

Unfortunately, at the time that they discover that the costs of switching to the more environmentally friendly power generation system is costing them significant dollars (at a time when California is broke) it may be too late to reverse the decision, in the way that Durango recently did and move back to coal, since the coal plants will not, it would appear, now be there.

Whether, with the increasingly levels of demand for natural gas to replace planned coal-fired plants, the natural gas will be there to meet that increased demand is a tale for another day.

(NOTE: When I originally wrote this piece it had a different end section, the original end section, and the reason for the change are discussed in the section below. My apologies for the error in including that material, and my thanks to Gail for catching the error and drawing my attention to it).


. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
When I first wrote this piece, the end segment read as follows:
The role that hydrofracing plays in all this provides an interesting sub-text. As I have recently noted, there is a move by two Coloradan Congressmen and one from New York to tighten the regulation of hydrofracing. The fight is now, apparently getting a little rougher. (H/t Prof Goose) A research professor at Colorado School of Mines has run into some unpleasant reactions.

Thyne said he was threatened with termination as a research associate professor at Mines, a position he still holds through the end of the summer, because of pressure put on the state school by powerful players in the oil and gas industry who were upset with his position that federal regulation of hydraulic fracturing may ultimately be necessary if oil companies don’t find other solutions.

In fact he has moved on to another university (Wyoming) but has been working on a site where there is a possible problem.

Thyne contends there needs to be much more rigorous study of fracking to determine the extent to which it can contaminate groundwater supplies. Industry money currently being poured into the aggressive and highly defensive campaign to defeat DeGette’s legislation would be better spent building a credible scientific case for why the exemption was necessary in the first place, he adds.

Industry officials claim state regulation of the practice is more than adequate and that the chemicals used in fracking need to be kept secret for competitive purposes. They also argue that in 60 years of fracking there has never been a case directly linking it to the contamination of drinking water wells because so many precautions are taken.

But Thyne is currently being employed as an independent consultant by Garfield County to study a case near Silt in which a property owner claims fracking contributed to an ongoing gas seep in Divide Creek.

Interestingly Colorado has recently passed tougher legislation governing drilling in the state, which includes the need to list the components of the fracing fluid, legislation which is said to have increased costs in the state, and reduced the level of drilling (albeit the price of gas might just also have some effect on this).

As for the CSM prof, given that the story has popped out only after he had found a position to move on to, I tend to be a bit cynical about the weight of the pressure that might have been applied to him. Having been peripherally involved in a case of our own where a faculty member’s untimely remarks about a company to the press probably cost our University at least one and likely several large contracts, as well as ruining relations between us for several years. It happens. There were several rude exchanges, so I gather, but it all blew over. As this likely would have.

But given the desire by the Colorado Congressfolk to make the rest of the nation work to the same rules as their gas industry (which incidentally does not have that much of the gas shale which requires hydrofracing to be economic) I am not sure that the overall discussion will have as simple an outcome.

. . . . . . . . . . . . . . . .
The reference to Dr. Thyne is innaccurate. It turns out, as Gail discovered and called to my attention that CSM had commented on the situation, with the following statement:

“I want you to know that no one in the Mines administration recalls having anything but cordial conversations with Dr. Thyne this spring. When Dr. Thyne was quoted during that time by the media, the school received inquiries about Dr. Thyne’s association with Mines.

“As a result, Mines officials phoned and e-mailed Dr. Thyne to inform him of the inquiries, and also to remind him of the university policy that people must be clear in public communications that the opinions they express are personal and do not represent institution positions — one way or another — on issues being discussed.

“Also, as a matter of clarification, Dr. Thyne left employment at Mines in August 2006 due to employment at the University of Wyoming. He has remained in a very limited role on a non-paid basis (in an advisory capacity with graduate students) since then, and that contract ends at the end of August 2009.”

Given the dates at which Dr Thyne changed employment, it appears, therefore that there is significantly less to the story than I had described. My thanks again to Gail for catching this, and my apologies that I did not.