ASPO-USA conference, second day, before lunch
Jim Baldauf, a co-founder of ASPO-USA, provided the opening remarks to the Plenary Sessions of the day. He noted that with a coal mine explosion, the concern over hydrofracks, and the Gulf oil spill, this year could be considered Hydrocarbon Hell. The Macondo well is evidence that we are now having to seek the more difficult oil, with the associated costs.
He also noted that, with a change in Board membership, ASPO-USA will also be moving to Washington, to have a greater ability to influence opinion, and it will also then serve as the site for next year’s Conference.
Michael Klare chaired the first session and introduced Chris Skrebowski to discuss “The Latest Analysis of Future Oil Supply Capacity.” Chris noted that, with the recession hitting in the last two years, it has become more difficult to be predictive, since not only must the capacity available be assessed, but now also the demand levels are a lot more uncertain.
What the years have shown is that there is an oil price, above which the world is driven into recession. There is thus also a maximum price – the Economically Sustainable Oil Price – which will allow the world to keep running while also allowing oil to be produced in the quantities needed to sustain a global growth rate of around 2%. That also requires that the reserves be available to produce that gap, and he did note a gap in recent EIA plots, where the “Unidentified Projects” logo is used to fill the space between anticipated demand, and known supplies.
Simply, it is not resource availability but flow rate that is critical to the future, and economic stability. Cheap oil ended in 2003, and by 2014 there will be problems matching supplies to demand. He based this in part on his Megaproject review of world oilfields. It has been less useful than in the past. In projecting future patterns, he used a depletion rate of 4.7%, (derived from 75% of the fields being in decline at an average rate of 6.7%). The recession, and the drops that it induced, moved the date of the production decline from 2012 to 2014, and his estimate for supply falls between two IEA estimates, which have returned to being a little more optimistic of the future than they were in the recent past. They, however, use a growth rate of 1.4%, but he used a value of 2% since the non-OECD countries are seeing growth rates that may exceed 4%.
Although the end of the plateau may come in 2014, it is likely that there will be price spikes before this that will presage the transition into decline. The date depends on how rapid growth is, and how much there really is in the OPEC spare capacity drawer. While the IEA thinks that this is 6 mbd he thinks it is likely only 4 mbd. But he notes that Saudi Arabia, Kuwait, the United Arab Emirates and Qatar have collectively over 80% of this capacity. Saudi Arabia alone has 66%, and thus effectively now controls oil prices – which are sitting about where they have publically stated that they want them. He quickly toured the other significant producers of oil, and then noted that Saudi Arabia’s spare capacity will soon run out, at which point, in perhaps two years, their ability to control price will also fade.
He noted that in his estimates, which are based on total liquids, NGL volumes have been coming in at about 1 mbd under predictions. He also felt that the anticipated increases in production from tar sands is going to be shown to be optimistic.
Oil is a uniquely critical resource, and its price is controlled by the marginal oil required to meet demand. Thus while this allows oil to be drawn from deep waters, and from tar sands, for those who produce it cheaply, the rising price will provide a great windfall. Where will that money go, and what will be its effect? We can no longer ignore the issues, but must consider what we can do, in the short as well as long term, to mitigate the effects. Improving efficiencies, using alternate sources (though this is a liquid fuels problem) change transportation modes. We cannot however expect that these changes will be fast, since we have too much money invested in the current system.
Jeremy Gilbert began by noting that, unless careful, the “Yes we can” slogan is going to turn into the “No we can’t” reality. In discussing “Uncertainty, Technology and Risk”, he pointed out that in so much of the discussion of the industry there is no recognition of the uncertainty in the numbers cited, or the risks that are increasingly being faced in getting more difficult oil to market. He was more concerned than Chris about what happens after the peak. For it will be the shape of the decline curve at that time that will dictate how fast the world gets into trouble, and how easily the problems can be overcome.
If discoveries are now filling our reserves at 5 billion barrels a year, while we are reducing them by 24 billion then this is not sustainable. We are finding oil, in expensive to produce places, but the rate of discovery is not enough. 50% of the discoveries since 2006 have been in Deep Water, and with more investment it is likely that we could double that volume by 2030, but that won’t be enough.
One problem is that modern technology can estimate the volume of oil in a reservoir quite well. But when it comes to how much can be viably extracted, then this is a much less certain number, and it is also, to a degree, price dependent. Getting those numbers has become more difficult, as the fields that are producing them become owned increasingly by National Oil Companies, rather than the major producers. Those who do not see a problem often cite a) new discoveries b) improved technology and c) improved production to reserves ratios, as evidence that there is no problem. Unfortunately these are not that effective. New reserves tend to be deeper, sourer, more viscous and more remote. Technology can improve performance, but this is typically at the end of the life of the field. The additional volumes recovered then are not greatly significant in the overall scheme, and this will only happen in later years. On the other hand, it should be noted that a 1% increase in recovery efficiency for existing fields would give a year of additional global supply. R/P ratios have a book-keeping use, but since oilfields do not produce at a constant level until one day they stop, it is not that meaningful in reality. The Middle East may be able to sustain a 2% decline rate, but in the rest of the world depreciation is taking an enormous toll.
It should be remembered that it is return on investment – through the price of the product sold, that persuades companies to make the major investments that find and produce oil. There is a long time between the investment and the return, and so stability is a necessary criterion for that investment. Uncertainty as to whether that investment can be recouped means that it may not be made.
Risk is similarly not recognized as much as it should be. He cited the Macondo well fire, noting that as these rigs produce toward the edge of technical capability there is no public recognition of the risks that are involved in that, or where data is available, complacency over the ability to produce the oil. The world has become used to the technical progress that gives more reliable cars and planes. We must balance risk against reward.
And he stressed we have to change from “Yes we can” to “Yes we must,” and that includes the move toward sustainable replacements.
In questions about the nature of recent oil discoveries offshore Ghana and Namibia, these were in fields that were strongly suspected to be there, but are complex geology and in deep water that could not have been profitably recovered a decade ago.
Dr. James Schlesinger then gave the keynote address. He began with a bromide “A resource which is finite is not inexhaustible.” And followed this with others leading to the point that “peakists” have won the argument, though we debate the timing. We should be gracious in victory. Remember that politicians do not want to give pain to their voters, and so they must be reassured as we move into these new times.
We depend too much on the fields discovered 50 years ago, the Ghawar’s and Burgun’s of the world, and while it may not be Twilight in the Desert, it is definitely late afternoon. We are now seeing price spikes for oil based on availability. As fields decline, we will need to find 5 Saudi Arabia’s to replace them, and we can’t even find a second. Iraq may be such a place, and offshore Brazil a second, but neither is in a cheap location to produce. Shale gas may provide some help, but that will likely fade too soon.
In questions he noted again that politicians prefer to be reassurers, but that political tensions are rising as China moves into places such as Iran. The King of Saudi Arabia has talked for some time of the need to leave resources for later generations. The age of subsidies for renewable power sources is likely to be limited, and he pointed to economists who think that demand creates supply.
And he left us to ponder “Sufficient unto the day, is the evil thereof.”
Roger Bezdek then spoke about the problems of writing fuel consumption standards for trucks. For while “Government has to do something,” the bigger question is what?
Trucks divide into 18 classes, but their performance is closely tied to how much load they are carrying, and how they are configures, which increases the complexity, and moves possible classifications into the thousands. Of all the factors energy loss in the engine is most critical. Manufacturers are already working to improve engine efficiencies, but success will only come when the engines are adopted and in use. But what do you regulate, and how do you measure it? And the problem is that there is little data on which to base regulations.
To date it appears that the best practice is better training for drivers, and to give them the incentives. But remember that the drivers may make $35k and if the speed limit, for example, were cut to 55 mph then this could cut their income by 20%. Any changes that are made won’t have any significant impact on consumption for up to 15 years, though it might be wise to buy stock in manufacturers and then sell it at the time the regulations come into effect.
He noted, in response to a question, that natural gas is not a player in truck fuels.
Art began by noting that he expected production from the Marcellus shale to be a disappointment. The questions that he asks relate to the wells being driven, and their possible commercial viability. At best the current data seems to indicate that the wells are marginal, if companies can get $7 to $8 a thousand cubic ft (kcf). (Current prices are under $4 /kcf.)
When he looks at the plays, getting data from SEC filings, he sees that marginal costs are around $7.50 per kcf, (ranging from $5 to $12). Reserves are greatly overstated, and there has been a huge increase in undeveloped reserves. Shareholder equity has thus been hammered. Hedging in the past has helped considerably in covering costs, but that is coming to an end.
Those who cite Eagle Ford as an ideal property that is liquid rich need to do a better economic analysis. When you add up the molecules, there is perhaps a resource that might contain 2,000 tcf. But it is more likely to have only 441 tcf, of which one-third may be technically recoverable. (We use 23 tcf a year).
Similarly in looking at the Haynesville, it seems that only 10% of the 110,000 acre field is going to be economically viable. And this is in “sweet spots” that are scattered even down at the county level.
While the Barnett has 14,000 wells and has provided a lot of data, it is now post peak. And remember that the Earth is not a factory, what is originally found cannot be improved upon. Those who claim profitability may not be factoring in all the costs, since break even may be at $6 or more and they aren’t getting that price.
Further there are overall problems in the flow rates and commercially recoverable volumes for a well. Consider that many wells must produce a minimum of a million cu ft in a month to pay the $5,000 compression costs to put the gas in the pipeline. After 5 years, one-third of the wells can’t make this return. And most produce 45% of total production in the first year.
Oil production from fields such as Eagle Ford need over 100,000 bbl of oil to justify the investment in separators, yet many have only 55,000 bbl of likely production.
Much of the market for the Marcellus shale appeared strong when the field was first developed, but then natural gas in the North East was expensive. Now there are gas pipelines such as the Rockies Express and LNG terminals that will supply cheaper gas. The high population densities and the varying terrain also don’t help.
Charles Maxwell responded that he agreed with the substance of what Art had said but had some different views and opinions. The majors now hold 25% of US production of natural gas, but have been inattentive to shale gas. But at the moment shale gas cannot be sold at a reasonable price. However there are situations where this inactivity is allowing neighboring wells to perhaps recover more natural gas.
The second group of players, with 30%, are the big independents (Anadarko, Devon, Chesapeake etc). They dance to a different tune and a different effective time frame. But they too have made investment decisions based on pricing assumptions that are no longer valid. The excess of natural gas has dropped the price to $3.70 per kcf which was not expected. (Since 6 kcf has the energy of a barrel of oil, this is equivalent to $22.20 bbl oil). They see that while gas is now as cheap as coal, they hope however that there will be a pickup to help and are acting accordingly.
And the remaining 45% of the market plays are held by the smaller “mom and pop” sized investors. They are likely mostly losing money and market share, and may well be in a negative growth mode. Hedging has helped but that will be gone in 18 months. Some (about 75%) have silent partners (often foreign) who are carrying the losses, but how long can this last? He expects the Haynesville to peak in 8 years, the Fayettevile in 4, and the Barnett already has. The Marcellus is too difficult to tell.
He agrees with Art that $7.50 is a good average production cost, and you need a sweet spot to make a recovery. Many small operators do not know how much they are losing. It will be 3- 5 years before prices recover and by this time most of these small operators will be slaughtered. But it will also kill LNG development. He foresees prices going from $3.95 in 2009, to $6 in 2014, but not at an even growth rate.
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