Is peak oil dead?Guest writer | Jul 24 2012 13:05 | 26 comments | ShareThis is a guest post from Chris Nelder, an energy expert who has spent a decade studying and writing about energy and related issues. He has written two books (Profit from the Peak and Investing in Renewable Energy) and hundreds of articles on energy and investing. He blogs at GetREALList.com and writes the Energy Futurist column for SmartPlanet.

Is peak oil dead?

One might think so, judging by a slew of optimistic new forecasts for oil production. Even George Monbiot, notable for his thoughtful previous coverage of peak oil in The Guardian, threw in the towel with his July 2 mea culpa, “We were wrong about peak oil. There’s enough to fry us all.”

Monbiot reversed his position after reading a new report by Leonardo Maugeri, an executive with the Italian oil company ENI and a senior fellow at a BP-funded center at Harvard University.

Maugeri forecasts new global oil production capacity of 49 million barrels per day (mbpd) by 2020, a number that is “unrestricted” by real-world circumstances, and “unadjusted for risk.” This constitutes a whopping 53 percent increase over the current claimed capacity of 93 mbpd in just eight years. While impressive, this headline number obscures some important details.

First, capacity is not production. The world has never produced 93 mbpd. Global oil production was 88.3 mbpd in 2011, according to the International Energy Agency (IEA), which uses a very liberal definition of “oil” that includes biofuels, non-associated natural gas liquids, and other liquids. Under a more restrictive definition used by the U.S. Energy Information Administration (EIA), which counts crude oil plus lease condensate (natural gas liquids that are produced and naturally associated with the crude), and liquids extracted from natural gas production, world oil production was 87 mbpd in 2011. Counting only crude oil and lease condensate, world oil production was 74 mbpd in 2011, a level it has maintained since the end of 2004 despite a tripling of oil prices since 2003.

Therefore, there is a 19 mbpd gap between actual crude oil production and Maugeri’s unverifiable claim of 93 mbpd of oil production capacity, depending on how one construes (or misconstrues) the meaning of “oil.” Much of the capacity and growth Maugeri foresees includes millions of barrels per day of natural gas liquids, of which only about one-quarter are useful as vehicular fuel.

Maugeri generally refers to production capacity throughout his report, not actual production. The only nod to actual production appears in a footnote on page 4, where he says “In the first quarter 2012, average world oil production consistently reached or surpassed 91 mbd.” Since he doesn’t specify the source of this data, we must assume he obtained it from his private, field-by-field database, as the IEA shows production in the first quarter of 2012 to be 90.7 mbpd.

Next, Maugeri adjusts his 49 mbpd increase by various risk factors, and finds that adjusted new production of 28.6 mbpd might be possible by 2020. He expects most of this additional production to come from 11 countries, shown in the following figure.

Maugeri’s Figure 3, of “Worldwide potential additional liquids supply out to 2020 (crude oil and NGLs, excluding biofuels)” for the 11 countries representing the majority of his projected increase.

Maugeri devotes several pages of his report to a light treatment of the risks he accounted for in this adjusted number, offering little purchase for a skeptical reader who might discount the risks differently. We are essentially left to take his word for it.

Finally, Maugeri adjusts for the depletion of currently producing fields and reserve growth, to come up with a final projected increase of 17.6 mbpd and a total world production capacity of 110.6 mbpd by 2020. This is where the really squishy assumptions come into play, which are core to his forecast.

Depletion and decline rates

Most oil analysts are careful to distinguish depletion rates from decline rates. A depletion rate is the percentage of the recoverable oil in a field that is being produced each year; therefore, if new technology were to increase the estimated recoverability of oil in a field, the depletion rate would fall. A decline rate is an annual percentage decline in the rate of production from a given field, so it does not depend on the size of the field. Maugeri mixes up the terms, defining only depletion rate as “The natural decline of an oilfield’s output after years of production. It could be partially offset by reserve growth.”

In 2008, CERA, a consultancy which has one of the few comprehensive databases of the world’s oil fields, and the IEA, which used CERA’s database, estimated decline rates for the world. The IEA found a global average production-weighted decline rate of 5.1 percent per year. CERA estimated the global average production-weighted decline rate of all fields at 4.5 percent per year. A similar 2009 study by Mikael Höök et al. found a production-weighted average decline rate of 5.5 percent per year. Other estimates have ranged as high as 8 percent. All of these studies find that decline rates increase over time, and they are higher for “unconventional” sources like deepwater and shale than for conventional fields. (Source)

Maugeri muddles these important distinctions, claiming that the aforementioned studies are in sharp variance when they are not. He goes on to allege overestimation of “depletion” (we assume he means decline) rates in the past, without any references, and finally concludes, inexplicably, that apart from Norway, the UK, Mexico, and Iran, he “did not find evidence of a global depletion rate of crude production higher than 2-3 percent when correctly adjusted for reserve growth.”

Reserve growth

As a global average, current technology and prices only permit about 30 to 35 percent of the oil in an oil field to be economically recovered, up from about 20 percent thirty years ago. Over time, new technology and techniques make it possible to economically recover more oil, and that additional oil may then be reclassified from resources (the oil in place in a field) to reserves (oil that may be legally claimed as recoverable). This process is called reserve growth.

Maugeri discusses reserve growth at length, emphasizing the vast quantity of remaining resources and asserting that new technology will soon make more of it accessible, particularly from unconventional oil resources. “In fact, the current decade could herald the advent of ‘unconventional oil’ as ‘the oil of the future,’” he claims, “changing the geopolitical landscape that has marked the oil market for most of the 20th Century.”

As an example, Maugeri cites the Kern River field in California, one of the longest-producing oil fields in America. New recovery methods have substantially increased the recoverability of oil from this field over time. What he does not mention is that waterflooding and other enhanced oil recovery methods that enabled reserves growth in Kern River are now routinely used early in the exploitation of oil fields, belying his suggestion that similar reserves growth will be achieved in the future. Nor does he mention that despite the intensive application of enhanced recovery methods, Kern River production has been declining since its last peak in 1985, or that it currently produces about 10 barrels of water for every barrel of oil, at a very significant energy cost. I have visited the Kern River field and studied its production, and found that its energy return on investment ratio is now probably on the order of four, which hardly makes it a shining example of new abundance.

Kern River production history. Source: Chevron

Therefore, while it is true that reserves do grow over time with the application of new technology, it is disingenuous to imply that it will lead to the enormous increases in production, or the far lower decline rates that Maugeri claims. Again, Maugeri only presents the summary results from his private database and does not disclose the recovery factors he is using, so there is no way to judge how realistic his model is.

However, we do know from more than 60 years of history with enhanced oil recovery techniques that they tend to lengthen and thicken the tail of a field’s production, not achieve new production highs. This is even more true today than it was decades ago, when the Kern River reserve growth Maugeri highlights occurred.

Even in the U.S., much of the apparent reserve growth over the past three decades had more to do with the technical reclassification of oil as “proved reserves” under SEC rules than technology, as petroleum geologist Jean Laherrère has detailed at length.

Reserve growth and price

Maugeri’s discussion of reserve growth elides the well-known exaggerations of proven reserves among the world’s major oil producers. Producers in the Persian Gulf, North Africa OPEC, Russia, Venezuela and Canada report “reserves” estimates that can only be economically produced if oil prices are at least double the $70 per barrel assumption in his analysis. He does not provide any further details about the economics of production in his analysis, except to say that “More than 80 percent of the additional production under development globally appears to be profitable with a price of oil higher than $70 per barrel.”

This claim seems highly dubious given recent estimates of production costs. Research by petroleum economist Chris Skrebowski, along with analysts Steven Kopits and Robert Hirsch, finds a new barrel of production capacity in deepwater, some OPEC countries, the Canadian tar sands, and Venezuela’s Orinoco belt will cost up to $80 or $90 a barrel. Canada’s Globe and Mail reported in June that $80 a barrel was low enough to cause several tar sands operators to slash their expansion plans. And arecent report from Bernstein Research found that the real floor of new production in 2011 was around $92 a barrel, and will be closer to $100 a barrel this year.

We also know that the cost of new oil production has been climbing sharply in recent years, along with the cost of all commodities, as shown in the following chart.

Source: EIA

Maugeri acknowledges this fact, noting, “Over this decade, another problem affecting the production of all shale/tight oil plays in the United States will be the inevitable rising costs of services, rigs, labor, and pipelines, caused by the inflationary pressure from the frenetic activity throughout the shale/tight oil and gas sector.” This does not square with this subsequent assertion that “the advancing knowledge of shale oil development and the gradual expansion of the infrastructure necessary to each shale play should balance the rising costs, and eventually drive them down,” and he offers no empirical basis for it.

Likewise, his acknowledgement that “the oil market will remain highly volatile until 2015 and prone to extreme movements in opposite directions, thus representing a major challenge for investors, in spite of its short and long term opportunities,” doesn’t square with his assumption of a minimum $70 per barrel holding firm through 2020 and beyond.

Bakken ballyhoo

Maugeri devotes the longest section of his report to the tight oil and shale gas “revolution” in the U.S., saying it “could be a paradigm-shifter for the oil world.” He extrapolates most of his forecast from the Bakken formation, a tight oil reservoir which underlies parts of North Dakota, Montana and Saskatchewan.

Unrestricted production from shale and tight oil could reach 6.6 mbpd by 2020 in his estimation, or as much as 4.2 mbpd after considering risk factors and depletion. The U.S. is currently producing about 0.9

mbpd from tight oil, so Maugeri’s forecast amounts to a more than four-fold increase in eight years, an extremely optimistic prospect. It is also far more than the EIA expects, having recently forecasted that U.S. tight oil would reach only 1.2 mbpd by 2035. For additional perspective, total U.S. production of crude oil and condensate today is 6.1 mbpd.

He does not mention that, on the basis of Bakken well productivity, it might take 50,000 new successful tight oil wells or more to achieve his forecast, plus many more unsuccessful ones as the productive areas of new fields are delineated. In the IEA’s recent forecast, another 500,000 new shale gas wells might be drilled by 2035, doubling the number of producing gas wells in America. Many of these new tight oil and shale gas wells would need to be drilled near where people live and work, rendering an “unrestricted” forecast for new development all but meaningless. Maugeri refers vaguely to this limitation, noting that “a revolution in environmental and curb-emissions technologies is required to sustain the development of most unconventional oils,” and that if the industry continues to fail to prevent environmental contamination from tight oil projects, “massive over-regulation” could result and new development could be delayed.

Maugeri assumes that oil will sell for at least $70 a barrel to achieve his tight oil production forecast. “Most of U.S. shale and tight oil are profitable at a price of oil (WTI) ranging from $50 to $65 per barrel,” he says, but an executive with an oil company producing oil in the Bakken, who was interviewed by Steve LeVine forForeign Policy in February, said that if prices dropped to $70 per barrel, it could “create an extreme drop in drilling and field production really quickly” in the Bakken, and that “if oil drops to $70, a lot of people will lose money in the Bakken.”

Finally, Maugeri’s assumptions for the production profiles of Bakken wells appear to be far removed from reality. He uses a “combined average depletion rate for each producing well of 15 percent over the first five years, followed by a 7 percent depletion rate” for tight oil wells, while historical evidence shows that Bakken wells typically decline by 80 percent or more over the first five years.

Production profile of a typical Bakken well. Source: North Dakota Department of Mineral Resources

While tight oil production since 2005 has indeed been impressive, there is little basis for the Maugeri’s confidence that its growth trend will continue on its present trajectory through 2020, when real-world costs, siting issues, environmental concerns, and oil industry practices are taken into account.

Conclusion

Although Maugeri does not state explicitly what decline rates he is using, researchers Stephen Sorrell and Christophe McGlade derived an annual average decline rate from the data in his report of 1.6

percent, or about one-third the global decline rates estimated by IEA, CERA and others. After analyzing the IEA data, they found an aggregate global production-weighted decline rate of 4.1 percent per year. At that rate, they found that Maugeri’s forecast for 2020 would reach just 95.1 mbpd, not 110.6 mbpd—a gain of just 2 mbpd over today, not 17.6 mbpd.

We cannot independently evaluate Maugeri’s country-by-country forecasts without seeing the assumptions in his data model, but his summary expectations are optimistic in the extreme. For example, he sees production from Iraq expanding in the next eight years at rates that have never before been achieved, despite a great deal of uncertainty about the country’s stability, its ability to maintain security in the future, and its ability to attract Western oil partners with the knowledge and technology needed to exploit its resources. The failure of Iraq’s recent oil lease auctions do little to give one confidence that Maugeri’s extraordinary forecast can be realized.

More generally, his assertion that, of the countries with more than 1 mbpd of production capacity, only four will have reduced capacity by 2020 is impossible to square with the fact that production has been declining in more 50 of those countries since 2000.

Maugeri’s forecast does not mention a price ceiling at all, an obvious deficiency given the extreme volatility of oil prices over the past four years. We know that as prices approach $120 a barrel, demand shrinks, yet triple-digit prices are precisely what is required to bring much of the new supply Maugeri anticipates online.

To his credit, Maugeri acknowledges that his analysis “is subject to a significant margin of error, depending on several circumstances that extend beyond the risks in each project or country,” and he details numerous important caveats. And to the extent that he reveals the assumptions underpinning his forecast, his transparency is laudable. In the final analysis, however, it is insufficient. He fails to provide adequate justification that his assumptions, being widely divergent from most other industry estimates, are remotely realistic.

We must conclude that the key assumptions about reserve growth and its effect on decline rates in Maugeri’s report are muddled, speculative and unverifiable. And sprinkling those assertions with repeated declamations about how peak oil is a non-issue, insisting repeatedly that the only real constraints on his scenario have to do with political decisions and geopolitical risks, suggests that his report is more about grinding a political axe on behalf of the oil industry than offering a serious or transparent analysis. Finally we must note that Maugeri is well known for his hostility to peak oil, as is BP, which funded his report. After taking real-world risks, costs, and restrictions into account, the case for peak oil—which is about production rates, not production capacity or reserves—seems far more realistic.

Shale oil everywhere… for a whileKate Mackenzie The US is going to be free from the tyranny of imported crude oil soon, according to just about everyone. This is thanks to the wonders of shale gas extraction technologies being applied to sizeable and mostly untapped shale oil reserves. Previously marginal resources can now be economically extracted. Even the Europeans are getting excited about it. It’s a game changer.

You can probably guess what’s coming next…

Bernstein Research’s Bob Brackett (H/T Steve Levine) has an interesting note which examines the performance of shale oil wells in the Bakken formation. While the formation is in both Montana and North Dakota, Brackett narrowed his analysis to those in the former state.

There are high hopes for future output of the Bakken shale, which is why a graph like the below is disconcerting:

The decline cannot be explained simply by the number of wells being operated — because those have increased. A per-well average looks like this:

Writes Brackett:

Remember that over this same time period, the E&P industry invested hundreds of billions of dollars in horizontal drilling and hydraulic fracturing, rolling out new innovations and new completions techniques, longer laterals, higher stage counts, etc.  Yet this wave of innovation was insufficient to increase average well productivity.

But despite these efforts, the average well maintains its healthy production for a short time:

Another point we make concerning these Bakken wells is how rapidly they become stripper wells. Exhibit 6 shows a Bakken type curve for horizontal wells.  We are accustomed to the high early rates, fast decline.  The type curve shown has a cumulative EUR of roughly 250,000 barrels of oil.  Exhibit 7 shows the same type curve in logarithmic scale. This allows us to identify the time at which a Bakken well becomes a stripper well – 6 years into production.

That’s it — a mere six years to “stripper” status.

Two-hundred modern Bakken horizontal wells are now strippers, says Brackett. He has some other interesting little facts: these ‘stripper’ wells initially cost about $10m to drill and have a lateral length of almost two miles. Once they hit “stripper” status of about 15 barrels/day, they produce oil “at the same rate that rain falls in Seattle”. They can keep producing for years at that rate, of course — as long as it’s economic to do so. A quarter of the expected output from a Bakken well will be delivered during its post-peak “stripper” phase.

Brackett stresses he’s not a peak oilist or saying that the end is nigh…

We do believe US oil production will grow over the next several years and that the Bakken and Eagle Ford will become million-barrel-a-day fields, which is in and of itself an outstanding achievement.  But in terms of investment philosophy, we still maintain that (a) the world will not find itself awash in oil (shale or otherwise) and thus we remain bullish on long term oil price, and (b) oily resource plays are rare and the market will ultimately reward those companies that were most successful in establishing positions in the heart of these opportunities.

However he told Steve Levine of Foreign Policy’s (recently closed) Oil & Glory blog that he does believe this trend will hold for the Bakken shale formation in North Dakota, too — on which, as Levine points out, many of the North American oil production forecasts rely.

Right now, just 200 modern Bakken wells are strippers. But in roughly six years, there will be 4,000 of them, Brackett says. “All good things in the oil patch come to an end,” Brackett told me. “In the case of North Dakota, that is a long time — years — off, but even that too will suffer the same fate” as Montana.

While we’re raiding Levine’s posts, he has this prize quote from veteran oil watcher Phil Verleger whom we sometimes feature here on FTAV. Asked by Levine about the forecasts of a US ‘golden age of oil’, Verleger responded (emphasis ours):

Lastly, shale oil production will increase. How much — I am not sure. I am an econometrician and the builder of the first energy models back in 1971-1975.  I have learned though experience that energy models are the most expensive, most cumbersome random number generators ever invented. Three years ago, I would have predicted little output from shale oil.  Now I read forecasts that there will be large supplies. I do not know.

A timely reminder indeed.

Related links:

US shale oil abundance: Bernstein vs the IEAKate Mackenzie When the International Energy Agency’s big annual report came out last week there was a big top line story picked up nearly everywhere: that US oil production will overtake Saudi Arabia by about 2020.

This is due to projected rises in oil being wrung from the sort of shale formations that have been the source of vast new supplies of natural gas in the past few years.

Here are the IEA’s actual US oil production forecasts, in a “New Policies” scenario (click to enlarge):

The ‘New Policies’ scenario includes no new greenhouse gas emission policies beyond what was committed to by mid-2012; average 3.5 per cent world GDP growth to 2035; and average crude oil prices approaching $125/barrel, in 2012 dollars, by 2035.

However, Neil Beveridge and colleagues at Bernstein Research have been sceptical about the predicted shale oil boom for some time, as highlighted in their note about the Bakken shale formation in Montana which we wrote about in August.

They remain unmoved by the IEA’s forecasts, foreseeing an earlier peak and a quicker decline of US oil output:

The renaissance in US liquids production has been remarkable, growing by over 1mmbls/d to reach 8.5mmbls/d this year over the past three years. By 2015 we expect that the US will produce close to 10.5mmbls/d given further growth in shale liquids. This will be comparable to Saudi production but only for a brief period and by 2020 we forecast that US production will have declined back to 9mmbls/d. In contrast, the IEA expect US liquids production to keep growing to 11.1mmbls/d by 2020 following which the US production will plateau and by 2025 start to decline (Exhibit 2).

Beveridge explains:

As we have noted, shale liquids plays are far rarer than their related shale gas plays and already we are seeing decline in some of the core areas of the Bakken oil field highlighting the early onset of maturity in some of these plays (see our report Bernstein Commodities & Power: Something is Rotten in the State of Montana).

And as for the rest of the non-Opec producing world:

Outside of the US, Canada and Brazil will be the largest contributors to non-OPEC supply growth. Again however there are risks. Delays to drilling rigs and FPSOs in Brazil as a result of local content regulations, infrastructure bottlenecks and scaling back of oil sands investments in Canada mean that production growth may not be as rapid as some expect. Excluding biofuels, we project non-OPEC supply will show no aggregate growth over the next 10 years and remain at 48.7mmbls/d compared with the IEA which projects a 2mmbbls/d increase to 50.2mmbls/d in 2020.

Long-term forecasting for energy supply and demand is notoriously difficult, like most other types of long-term forecasting. Unforeseen developments — like technology and prices rendering it economic to extract shale oil — can really throw a curve ball at those who make these forecasts for a living. US shale gas is a very good example. However, reading through the WEO section on oil supply and the somewhat breathless box on ‘light, tight oil’, it’s hard not to wonder if the IEA authors have overshot a little in relating this to shale oil (emphasis ours):

The US Energy Information Administration estimates that unproven recoverable resources of light tight oil at end-2009 stood at 33 billion barrels; adding about 2 billion barrels of proven reserves yields a figure for total remaining resources of 35 billion barrels. Some industry sources claim that recoverable resources will end up being much larger, capable of sustaining a higher level of production for longer than we project here.

Well, it would be weird if no industry sources were claiming that.

Meanwhile, The Oil Drum points out that just last week, Chesapeake’s chief executive Aubrey McClendon was expressing pessimism about the oil potential of the Utica shale formation in Ohio.

Key take-away points from speakers at Allen & Overy meeting:

There is a large existing shale oil (and shale gas) resource base but whether the resources can be developed economically at sufficient scale in many countries is still an issue of uncertainty.

Two promising shale oil plays outside of the US are the Vaca Muerta in Argentina and Bazhenov Shale which both have double digit figures of potentially recoverable resources, with large players like Chevron, Statoil etc. engaging in their development.

The marginal cost to develop shale oil in the US is around 90 USD per barrel with average cost of most plays around 60 USD per barrel.

The effects of the abundance of shale gas in the US, which sent natural gas prices plunging, is unlikely to be replicated in the oil market because of its different market structure (globally connected oil market versus fairly closed domestic gas market).

The US may not produce as much natural gas as currently anticipated in the future, because the industry will be more motivated to drill for shale oil then shale gas, given the availability of drilling rigs, because it is more profitable.

We already see a shift today from dry shale gas basins being drilled to shale oil basins being drilled, including those with associated gas.

In the UK a report is about to be released by the British Geological Survey on shale gas resources and reserves. Of the studied basins, the most promising one is expected to be the Lancashire shale basin because geological studies indicate the reservoir to be more than a 1000 feet thick, as opposed to US based shale plays which are in exceptional cases up to a hundred feet in thickness.

There is a wide spectrum of views on the potential for shale oil production in the United States, with the pessimistic end being a maximum of 1.8 million b/d (of which 0.9 million is already in production) from Corelabs, and the optimistic spectrum expecting 3 to 4 million b/d from shale oil in the longer run (2020s).

If the more optimistic scenarios become reality the consequence would be a substantial decline in US oil imports, falling from 10 million b/d to 6 or 7 million b/d from 2008 to 2015.

Presentation (1) Justin Jacobs, Journalist or the Petroleum Economist

The first presentation about the big picture on shale oil was given by Justin Jacobs, journalist at the Petroleum Economist. He highlighted the importance of the US Eagle Ford & Bakken plays (approx. 27% and 63% of total shale oil supply), and emphasized large production expectations in the short term, with the EIA forecasting 1.5 million b/d shale oil production in 2013.

Figure 1 – Monthly dry shale gas production from January 2010 to June 2012 in the US.

The Petroleum Economist recently made a first map of oil & gas unconventional resources across the world, to be found here, which Jacobs used to demonstrate the large number of unconventional resource plays in the world. He picked two of the most important shale oil plays to keep an eye on for the future:

Vaca Muerta in Argentina, one of the largest discovered outside of the US. Its development cost is 250 billion USD over 10 years (with production potentially amounting to 200,000 b/d by 2020). The Repsol YPF section of the basin holds 22 billion barrels of oil equivalent of recoverable resources according to a Repsol YPF initiatied Ryder Scott assessment.

At present development has been slowed by the nationalisation of Repsol YPF by the Argentinian government who took a majority share. Because the investment required is at minimum several billions YPF is trying to find big players who are willing to invest, including Chinese firms and Chevron.

The Bazhenov Shale in Russia, has drawn interest from ExxonMobil and Statoil who have agreements in place for exploration and geological studies with Rosneft. The first exploratory drilling is to take place in 2013, and the licenses under investigation are expected to contain 15-20 billion barrels of resources. Total resources of the play have been estimated by BofA Merril Lynch at 60 to 140 billion, whereas Jacobs noted that these are wild early stage estimates, but that the shale play’s large size is beyond doubt. He cited Statoil estimating 2014 as an earliest possible production date, however, in his view attractive fiscal terms then currently offered by the Russian

government would be necessary for development to take place. The play has also attracted attention from Lukoil, Ruspetro and TNK-BP.

The key issue according to Jacobs is whether the large existing resources can be developed economically at sufficient scale. The development requires thousands of wells due to the steep decline rate, which necessitates the on-going development of a new services sector in the majority of countries with plays. Similar to calculations by Rune Likvern as well as Arthur Berman and Lynn Pittinger published at the Oil Drum, he cited shale oil development to require high oil prices at 80-90+ USD per barrel.

Another relevant point brought forward was that the abundance of shale gas in the US sent natural gas prices plunging. The effect is unlikely to be replicated in the oil market. The reason is the difference in market structure. The oil market is fungible in its imports and exports and requires a high oil price to meet demand. In contrast the US gas market is fairly closed with production being sufficient to meet domestic demand.

Presentation (2) Richard Sarsfield-Hall, Pöyry Management Consulting

The second presentation was given by Richard Sarsfield-Hall from Pöyry Management Consulting, who posed the question "Is shale oil the brave new hydrocarbon frontier?" He reiterated important common points on the US gas market:

The current low price level of 3 USD per MMBtu. The much higher marginal cost as opposed to current price levels. The oversupply of gas caused by a over-drilling given the cost-price imbalance. The growth of shale oil and shale gas requires more and more wells to be drilled to maintain and

grow production (see Rune Likvern and Arthur Berman’s articles linked to above for more details).

The key issue presented by Sarsfield-Hall was about internal dynamics in the US market, as he sees a drilling competition occurring between the developments of dry shale gas reservoirs (Haynesville, Fayetteville) as opposed to shale oil reservoirs with associated natural gas (Eagle Ford) and shale gas reservoirs with associated liquids (Utica). This occurs because of more favourable economics for one versus the other in today’s market conditions (high oil price, low natural gas price in US). This is also possible because exactly the same type of rig is used for shale gas well drilling and shale oil well drilling. According to Sarsfield-Hall we already see this happening in today’s market, a point quantitatively further emphasised by the third speaker Tim Guiness, Founder Guinness Asset Management. He showed that well drilling has been overtly dropping in dry shale gas plays, while it has been constant or increasing in shale oil and shale oil with associated gas plays.

Figure 2 – Weekly US natural gas rig count and average spot Henry Hub price.

Figure 3 – Weekly US oil rig count and average spot price of WTI crude oil.

Figure 4 - Production of natural gas from various shale plays in the US from 2007 to 2012.

The implications of this competition are primarily affecting the expectations of institutes and market players, as the US may not produce as much natural gas as currently anticipated in the future, because the industry will be more motivated to drill for shale oil than shale gas. As Sarsfield-Hall puts it “There is a definite move of drilling from dry shale gas into shale oil with associated gas, the rush to shale oil potentially means insufficient shale gas delivered, which may result in higher gas prices and/or insufficient volumes to feed potential US LNG exports”. In addition Sarsfield-Hall showed EIA estimates which are primarily dry gas based increases, with little increase in associated gas from the expansion in shale oil. In terms of shale oil we are talking about a 10%-25% production share of total oil production in the coming decades according to EIA projections.

There were some numbers displayed. One key projection was for dry shale gas production, from a firm called ARC Financial, which showed decline expectation of 0.6 bcf/d up to 2013 from a current level of 23 bcf/d for dry shale gas production. Also some US associated gas production numbers were presented as per table 1, which is gas produced from oil fields (either free gas or dissolved in oil as a solution).

Table 1 – Expected US Associated gas production from oil wells shown by Sarsfield-Hall.

In the last part of his presentation he highlighted work POYPRY has been conducting for Cuadrilla, one of the major players in the EU which is trying to get shale gas production off the ground in multiple countries. The study was conducted to calculate the impact of shale gas development in Lancashire in the United Kingdom, the results of which will be published in a couple of weeks. The Lancashire shale basin is interesting according to Sarsfield-Hall because geological studies indicate the reservoir to be more than a 1000 feet thick, as opposed to US based shale plays which are in exceptional cases up to a hundred feet in thickness. This would in theory make UK shale gas in Lancashire much cheaper to develop. The information provided is preliminary, with full details about to be released by the British Geological Survey (BGS) in a report on UK shale gas resources and reserves.

In using Cuadrilla’s scenario for production POYPRY found that UK natural gas imports could be reduced by 21% by 2020-2025 through shale gas developments. Their conclusions were that this could drive natural gas prices in the UK 4-6% lower which would save consumers 810 million pounds per annum. It would not in his view impact the UK achieving its 2020 renewable targets and alter its power generation at the volumes discussed.

Presentation (3) Tim Guinness, Founder Guinness Asset Management.

The last presentation was from an investors' perspective, with Tim Guinness, chairman and founder of Guiness Asset management, and lead manager of their Global Energy Fund, presenting his views. He began by reiterating the reasons why the US has been able to develop their shale plays as:

Improvement in ability to steer the drill bit. Development of ability to drill horizontally. Discovery of how to use hydraulic fracturing. US land and mineral rights. Relatively low population density. Adequate access to water. Existence of large successful oil & gas service industry and independent exploration & production

sector.

He confirmed the switch from dry gas to shale oil/liquid rich shales with associated gas that is occurring, displaying rig figures per type of shale basin (predominantly shale oil, shale gas, and liquid rich with oil + associated gas). In addition he noted that the growth in gas supply has stopped in the US and is on a plateau, whereas oil production is growing substantially due to shale oil. He cited an onshore production estimate for December 2012 at 4.8 million barrels per day, which has been growing since 2008 after 38 years of decline since the peak in the 1970s, of which about 1.2 million b/d is from shale oil.

Figure 5 – US crude oil production to 2012 and forecasts from the EIA.

In his synthesis he compared three different estimates for shale oil production: Sandford Bernstein Oil Shale Forecasts, who expect 3 million b/d in 2016, maintained up to 2024, and peaking around 3.7 million b/d, which would come mainly from Bakken (1.5 million b.d), Missippi Lime (0.9 million b/d), and Eagle Ford (0.7 million b/d). With a cautionary note from Guinness that the forecast by now is 9 months out of date. Corelabs, who expect 1.8 million b/d at maximum from shale oil, of which 900.000 was already in production at the time of forecast (1.2 mb/d at present). In other words we can expect about a 600.000 b/d increase yet to come. The reason is that the sweet spots according to Corelabs are much smaller than people think (too much extrapolation of the good areas). Simmons & Co, who see US shale oil production growing to 1.9 mb/d in 3 years, and 8.3 million b/d of total oil production in 2015. The consequence of the Simmons & Co scenario would be for US oil imports to fall from 10 million b/d to 6-7 million b/d from 2008 to 2015. (see details in this presentation).

Table 2 – US oil production forecast for 2015 from Simmons & Co. Expectation based on 85 USD per barrel of oil and 3.50 USD per McF of natural gas.

Figure 6 - US oil production forecast from 2015 from Simmons & Co, with low, medium and high range scenario's varying due to oil price levels (75, 85, and 100 USD) and service industry drilling rate expectations.

Figure 7 - US oil import forecast up to 2015 from Simmons & Co as per the low, medium, and high range scenarios.

Figure 8 - US oil production forecast from shale oil from EIA.

The final point Tim Guinness discussed was marginal cost, which according to Tudor Pickering for the majority of shale oil plays requires 60 USD, with the highest costing ones amounting to 85-90 USD (see figure 9 for details). He also cited Bernstein Energy research which shows cumulative resources of 30 billion barrels of US shale oil to be available at a cost below 150 USD per barrel. Some of the plays have a very low cost range, such as the Eagle Ford, where a figure of 40 USD per barrel was cited (Tudor Pickering shows this play around 60 USD).

Figure 9 – marginal cost in oily shale plays and other oil basins in the world per comparison from Tudor Pickering.

Figure 10 – marginal cost for shale gas plays according to Tudor Pickering.

Finally in his conclusion, as per recent Bernstein Energy research, Tim Guinness stated that shale oil is not a game changer for these specific reasons:

Quality drilling locations are finite. Shale oil cost structure is high.

Drilling efficiency gains harder to obtain than in gas shales. The industry structure (OPEC) is better for oil. Scale of US shale oil find relative to the oil market is small.

In Tim Guinness' words: “It is akin to something like the discovery of the North Sea, Alaska or GOM. A useful addition but not a game changer, as the world needs 5 new North Seas every 20 years to provide enough oil to meet growing demand.”

http://www.theoildrum.com/node/9569

Marginal oil production costs are heading towards $100/barrel

Kate Mackenzie | May 02 2012 12:01 | 39 comments | ShareBernstein’s energy analysts have looked at the upstream costs for the 50 biggest listed oil producers and found that — surprise, surprise — “the era of cheap oil is over”:

Tracking data from the 50 largest listed oil and gas producing companies globally (ex FSU) indicates that cash, production and unit costs in 2011 grew at a rate significantly faster than the 10 year average. Last year production costs increased 26% y-o-y, while the unit cost of production increased by 21% y-o-y to US$35.88/bbl. This is significantly higher than the longer term cost growth rates,highlighting continued cost pressures faced by the E&P industry as the incremental barrel continues to become more expensive to produce. The marginal cost of the 50 largest oil and gas producers globally increased to US$92/bbl in 2011, an increase of 11% y-o-y and in-line with historical average CAGR growth. Assuming another double digit increase this year, marginal costs for the 50 largest oil and gas producers could reach close to US$100/bbl.

While we see near term downside to oil prices on weaker demand growth, the longer term outlook for higher oil prices continues to be supported by the rising costs of production.

This is important because, as Bernstein analyst Neil Beveridge and colleagues note, the cost of producing marginal barrels of oil plays a big role in determining oil prices.

We’d add that the expectations of said costs also play a big role, but that’s another story… and anyway, the Bernstein team argue their point pretty strongly with this chart:

(DD&A is depletion, depreciation, and amortisation;  F&D is finding and development.)

Also, this research obviously only covers non-Opec producers, and it mostly excludes Russia too. Given Saudi Arabia’s role as the “swing producer”, how are the ex-Opec, ex-Former Soviet Union marginal oil production costs so correlated to Brent prices?

Bernstein argues that it’s because they are, basically, more costly:

While OPEC plays a key role in influencing price through production quotas, in the long run we believe that it is the marginal cost of non-OPEC production which sets the oil price.As global demand has surged over the past decade the marginal cost of production and oil prices have increased, as the industry has venture to increasingly higher cost (smaller, deeper fields) and more marginal regions (deep water, high arctic) to produce the incremental barrel of oil.

And if Saudi Arabia is already comfortable with oil priced at $100/barrel (or higher, judging from the state of the market), then presumably they’re not about to use their much cheaper production rates to save the big listed oil companies from the higher costs they face. Demand destruction might be another matter, but again, we digress…

Here’s a comparison of the median costs and the 90th percentile costs per barrel for this cohort:

(Click to expand.) The cost of producing the marginal barrel corresponds fairly closely to the overall barrel, especially in terms of cash costs. Beveridge et al write (emphasis ours):

We found that the marginal cost increased dramatically between 2002 and 2005, and then rose slightly in 2006 and 2007, peaked in 2008, dropped in 2009 and rose again in 2010 and 2011. The 90th percentile for marginal costs increased with 14% compound annual growth rate while the median marginal costs increased with 9% compound annual growth rate (Exhibit 10).

In addition to calculating the marginal cost required to replace production with new reserves, we also calculated the variable cash costs based on production costs (operating expenses and production taxes).This indicates at what point it becomes uneconomic to produce oil, which would lead to production shut-ins. Given the variability within each company’s portfolio, there presumably is some production that would be shut in even at higher levels than the overall cash costs, but the cash cost gives an indication of the range.

And here’s how that range looks:

Oh, Pemex…

We all remember what happens next, right?

Oil production costs in Goldman’s “flatter” worldMasa Serdarevic Goldman’s analysts, long-time oil bulls, are now expecting a “flatter oil price environment” in the next few years. In other words, they think prices in 2013 and 2014 will be “marginally” lower than current spot levels, and drift down to $85 by 2016.

Clearly not good news for the oil majors who have watched their own costs spike higher over recent years (our emphasis):

We estimate that the global oil & gas industry needs c.US$115/bl to be free cash flow neutral after capex and dividends. Exhibit 3 shows that our estimate of the average breakeven oil price for the

industry (for the purpose of this chart we include the seven US and European majors) is currently US$115/bl on aggregate, while it was US$84/bl only four years ago.

The industry is effectively spending today for a high oil price environment, in our view. As the industry is already spending at a level consistent with US$115/bl, further capex growth from current levels will likely be more constrained unless oil prices move higher.

The note also contained this pretty cool, if dense, chart looking at the breakeven point all the world’s major oil projects. Click to enlarge:

As Goldman notes:

Our Top 360 analysis suggests that the industry has been extremely successful at discovering new barrels which break even below US$90/bl in two main areas: deepwater frontier areas, and unconventional liquids or ‘shales.’

Which is just as well!

Related link: