Peak Watch

What About the Poor?

It would be nice if the poor were to get even half of the money that is spent in studying them.
    — Bill Vaughan, American journalist and author

Today's front month oil contract stands at about $77/barrel. Such prices have not dampened demand in China, where demand growth is running at 11%, or in the United States, where finished motor gasoline consumption reached 9.71 million barrels per day in the week ending July 13, 2007. The volatile but rising oil price since 1999 is the primary signal of a growing supply and demand imbalance in a market with little spare capacity. This indication of scarcity now only inconveniences the wealthy, whose past income growth still allows mostly pain-free purchases. But what about the poor?

A note on a forthcoming ESMAP study, How are Developing Countries Coping with Higher Oil Prices?, describes "policy alternatives adopted by developing countries in response to the increases in world oil prices since the end of 2003." Before looking at the results, let's look at some emerging stories in the developing world to get a feel for what's going on.

• Liquid Fuel Shortages — Nepal hit by deadliest fuel crisis:

  After days of acute fuel shortage, the Kathmandu valley was Tuesday hit with its worst crisis in history as the state-owned petroleum importer and distributor reached the lowest level of fuel stocks and stopped supplies to gas stations.

  "Kathmandu valley now has just 300 kilolitres of petroleum," said Bishwanath Goyal, managing director of Nepal Oil Corporation (NOC). "This is the minimum mandatory stock we have to keep. We can't sell any of it" ...

  Signs saying "No diesel", "No petrol" hung at the entrances of petrol pumps.

  Also see Kenya: Acute Gas Crisis Hits Towns, where "an acute shortage of liquefied petroleum (cooking) gas (LPG) has hit major towns countrywide" and a "survey yesterday showed that some dealers had not received fresh supplies for the past three months."

• Fuel Switching and Efficiency — Thailand boosting palm oil production for alternative fuel:
  

  In a bid to boost consumption of alternative fuel by motorists in Thailand, the Ministry of Agriculture and Cooperatives has drawn up a plan to develop and enlarge the palm oil growing area between 2008 and 2012, a senior ministry official said Sunday...

  The decision to grow more palm oil is aimed at catering to the rising demand for fuel in the future as well as to increase the potential of the industry, said Theera Wongsamut, deputy permanent secretary for Agriculture and Cooperatives.

  The Thai government is encouraging motorists to switch to using alternative energy as local oil prices have jumped sharply, causing the country to apply significant amounts of foreign currency for imported oil.

  Also see Namibia: Free Lights to Counter Power Shortages, where the "national power utility ... NamPower announced that it had budgeted N$14 million for the purchase of compact fluorescent lights (CFLs) to be distributed for free to Namibians in a move intended to counter power shortages widely expected in the southern African region."

• Passing Costs Through — Malaysia has no plans to cut fuel prices:

  Malaysia, which heavily subsidizes fuel prices, sharply raised prices of gasoline, diesel and liquefied petroleum gas in February last year by as much as 23 percent after global crude oil prices shot up to US$70 a barrel.

  Despite the subsidy slash, Malaysia's fuel prices remain among the lowest in Southeast Asia. But the price hike prompted a series of public protests, with demonstrators saying it was unnecessary as Malaysia is a net oil exporter.

  Also see the Philippines, where P0.50 per liter fuel hike surprises motorists. "As if the threat of power and water shortages were not enough, motorists got another whammy Saturday as three major fuel firms raised prices of their fuel products by 50 centavos per liter. QTV-11 television reported Saturday that the 50-centavo hike covered gasoline, diesel and kerosene... It said the oil firms justified the price hike, saying world prices of crude oil had gone up from $65.80 per barrel to $71 per barrel."

The sporadic, almost anecdotal, nature of such stories in the press hides the systematic reduction of oil consumption in the developing world. The poorer countries get priced out of the market, or can not obtain the fuels they require when supplies are tight. The western press rarely covers the issue. Stories that touch on the problem, such as Toiling in the Dark: Africa's Power Crisis (New York Times,  July 29, 2007), surface and are then forgotten. Web searches often turn up reports from 2005, when oil prices first hit $70/barrel. Press accounts from the developing world are hard to find. These stories tend to report on local events, and assume some knowledge of local conditions. Some commentators in peak oil circles have labeled these events with the unorthodox (for economists) term "demand destruction", but the phenomena is poorly documented..

The problem created by high oil prices is widespread, as Africa's Energy Crisis Worsens: Viable Clean Energy Alternatives Are Imperative (Center for American Progress, July 17, 2007) makes clear.

With world crude oil prices nearing $75 a barrel, economies across Africa are grinding to a halt under the burden of soaring energy costs. The spike in world oil prices this summer will exacerbate economic problems, pounding already fragile national budgets and offsetting hard-fought gains from poverty reduction programs, international development aid, and debt relief efforts.

In Senegal’s capital city of Dakar, the cost of taxis has almost doubled since 2005 and blackouts occurred every day last summer because the state-owned utilities couldn’t afford to pay for fuel. The country relies on oil imports to power its diesel-fired generators, and while conditions relaxed somewhat over the winter, power cuts are on the rise again. As of May, the capital was facing 10-hour power cuts several times a week and the government was warning of impending, unprecedented shortages. 

Senegal is paying nearly twice what it was a few years ago to import the same amount of oil. The increased cost alone is more than seven times as much as the country is gaining through multilateral debt relief programs. The government has responded to the energy crisis by providing direct subsidies to consumers. Since the rise in world oil prices began in 2002, these subsidies have increased five-fold, creating yet another incredible burden on the national budget.

The ESMAP survey carried out by former World Bank officials polled 38 developing countries to find out what measures they were taking to cope with high oil prices (graph left, click to enlarge). Countries are divided up into (i) 16 non-oil producers (e.g. Cambodia, Senegal, Nicaragua); (ii) 13 producers who are net oil importers (e.g. Pakistan, Ghana, Thailand); and (iii) 9 net oil exporters (e.g. Argentina, Mexico, Vietnam). China and India fall into the second category, along with Brazil, who proclaimed their oil independence last year.

Of the 38 countries surveyed, 26 have suffered shortages or have resorted to rationing oil products or electricity. Developing countries are very reluctant to pass higher fuel costs on to consumers. This is a very unpopular thing to do in fragile economies where many people are just scrapping by and government budgets are tight. Net oil exporters usually try to absorb most of the price increases, but sometimes can not—see Gasoline Subsidies and Iran. (Iran is not part of ESMAP study.) Countries without oil or net importers pass some of the increased costs on, but, like Senegal, provide a cushion for consumers through subsidies. Price hikes often result in civil unrest, which happened in Indonesia in 2005. Examples abound—protests also followed a price hike in India in 2006.

To protect their citizens from higher prices, 23 developing nations have reduced fuel taxes and 20 have financed fuel subsidies from government budgets. ESMAP notes that tax breaks are especially common among the oil exporters, whose citizens can not understand why they sell oil to others but must also pay higher prices at the pump. More than half of the countries that had market pricing have now suspended it—12 nations never did have it. Various kinds of subsidies may temporarily shield consumers from real fuel costs, and leaders from being deposed, but they also take away from fiscal programs meant to provide essential social services and aid the poor. (See the Center For American Progress article on Africa, link above.)

It is sad to say, but in a world that is likely to see ever-rising oil prices, a government-funded respite from high domestic liquid fuel costs does not come with a longer term exit strategy. Such price-based policies merely postpone an inevitable crisis in which oil may eventually become altogether unaffordable in much of the developing world. The lasting effects for governments and civil societies of continued subsidies will likely be worse than the oil price shocks they are meant to remedy.

It thus makes sense that the prevailing strategy to cope with high oil prices is fuel switching. Only 12 of the countries surveyed by ESMAP have mandated or announced conservation measures or incentives to encourage efficiency, but 28 countries have "implemented or actively promoted switching to alternative sources of energy to reduce dependence on oil." Biofuels from high-yield tropical plants appear to be a perfect fit for net oil importers or non-producers. But appearances can be deceiving.

The Center for American Progress believes that the future for alternative energy is bright in tropical Africa. There is a great potential for generating electricity from wind and solar. It is hard to argue the point. The future of hydroelectric is more uncertain. In Uganda, regional droughts have cut power generation sharply. With aid from the ever-helpful World Bank, the East African country filled the breach with two diesel-fired generators!  In the long run, there is no excuse for importing oil or diesel to generate electricity where renewable alternatives might be available. If peak demands can't always be met, it's still certainly better than the alternative—permanent shortages.

The Center's optimism extends to biofuels. Author Rebecca Schultz tells us:

Biofuel is another sector where the continent could rival major global producers and play a central role in meeting the soaring demand for ethanol in Europe, United States, and China. Africa’s arable lands are well-suited to a range of energy crops, especially in the tropical climate zones around the equator that enjoy optimal rains and a long growing season. Conventional feedstock crops like sugarcane, maize, and soy, as well as new oilseed crops, are already being grown and converted into biofuels.

Democratically-elected Senegalese president Abdoulaye Wade (pictured left) has announced the formation of a Green OPEC "aimed at making African countries less dependent on oil by replacing it with biofuels. This organization, dubbed 'PANPP' ('Pays Africans Non-Producteurs de Pétrole'), unites 15 non-oil producing countries on the continent ... to stimulate the exchange of knowledge, skills and technologies for the development of a biofuels industry."

The problem with large-scale biofuels production is the food versus fuel issue. Higher demand for agricultural commodities creates spiraling food costs. Consider palm oil, a biodiesel fuel crop grown primarily in Malaysia and Indonesia. More palm oil is consumed world-wide than any other vegetable oil used in cooking. This is only one of its many uses (e.g. soap, make-up).

At the end of January, 2007, the crude palm oil (CPO) price on the Malaysian Derivatives Exchange (MDEX) stood at 1899 MYR/ton, where MRY abbreviates Malaysian Ringgit. This was ≅ $543/ton. On July 25th, the price was 2521 ringgit ($736 at today's conversion rate) a ton (Bloomberg, July, 25). The graph (below, left, from LONSUM ) shows the two year price trend. Soybean oil, also used for biodiesel, has shown a similar price rise.

The reasons for higher prices are not hard to find: "Rising demand from China and India, coupled with the government's move to mandate a five percent palm-oil based biofuel blend for all diesel have sent Malaysia's crude palm oil prices soaring over the past year" (Forbes, July 30).

In the May/June 2007 issue of Foreign Affairs, C. Ford Runge and Benjamin Senauer argue that a large-scale biofuels industry will harm developing nations, not help them (How Biofuels Could Starve the Poor). The authors flatly state that "if oil prices remain high -- which is likely -- the people most vulnerable to the price hikes brought on by the biofuel boom will be those in countries that both suffer food deficits and import petroleum." Just as with palm oil, the article argues that the sky's the limit for biofuel crops that compete with food. One of their examples is casava, which is an excellent ethanol source due to its high-starch content. If the developing world turns to biofuels to replace oil, it seems like a case of "damned if you do, damned if you don't."

In the poorest parts of sub-Saharan Africa, Asia, and Latin America, where cassava is a staple, its price is expected to increase by 33 percent by 2010 and 135 percent by 2020...

The production of cassava-based ethanol may pose an especially grave threat to the food security of the world's poor. Cassava, a tropical potato-like tuber also known as manioc, provides one-third of the caloric needs of the population in sub-Saharan Africa and is the primary staple for over 200 million of Africa's poorest people. In many tropical countries, it is the food people turn to when they cannot afford anything else. It also serves as an important reserve when other crops fail because it can grow in poor soils and dry conditions and can be left in the ground to be harvested as needed.

A large-scale "Green OPEC" biofuels industry may never work out for Africa's developing countries, but more power to him if Senegal's president Wade can make it work. Much smaller scale biofuel production that minimizes competition with food remains a hopeful possibility as a substitute for oil. There are also promising crops like jatropha, which "thrives in arid areas and can be grown on desert and marginal lands without taking land out of cultivation for food production and without requiring expensive inputs like fertilizers and water" (Center for American Progress).

A cynic might say that the poor have always suffered at the hands of the rich, and there's no reason to believe that will stop now. The predicament in the developing world brought about by the oil price shocks ultimately results from overwhelming, wasteful demand for oil in places like the United States, and increasingly, China. Peak oil is an issue for most developing countries only insofar as they are suffering even more now than they already were. This is one of the many reasons why there's no ASPO-Uganda. It's becoming long past peak for the poor, so let's hope they can reorganize their local economies to replace something most of them never had much of to begin with—oil & gas products.

Contact the author at dave.aspo@gmail.com

Inside the IEA's Medium Term Oil Market Report

... fugit inreparabile tempus

Translation: Irretrievable time is flying (away)
      — the Roman Poet Virgil (70 - 19 B.C), The Georgics

Peak oil is a sustainability issue. The Paris-based International Energy Agency (IEA) watches over the liquid fuels supply, the lifeblood of the economies of its clients, the OECD nations. Without a reliable, growing oil supply, these economies are in jeopardy. The latest Medium Term Oil Market Report (OMR) issues a stern warning in its first sentence. "Despite four years of high oil prices, this report sees increasing market tightness beyond 2010, with OPEC spare capacity declining to minimal levels by 2012." Has the IEA been converted to the peak oil position? The answer is yes and no.

The news stories accompanying the report seemed to confirm peak oil concerns. Here's an example from the Financial Times (reprint at ASPO-Ireland, July 10, 2007).

The IEA said that supply was falling faster than expected in mature areas, such as the North Sea or Mexico, while projects in new provinces such as the Russian Far East, faced long delays. Meanwhile consumption is accelerating on strong economic growth in emerging countries. The problem is exacerbated by the fact that supply from non-members of the Organization of the Petroleum Exporting Countries [OPEC] will increase at an annual pace of 1 per cent, or less than half the rate of the demand rise.

The widening gap between rising consumption and lagging non-Opec supply will force Opec to increase sharply its production in the next five years. Lawrence Eagles, head of the IEA's oil market arm, told the Financial Times: "If we get to the point were there is insufficient supply, the only way to balance the market will be through higher prices and a drop in demand."

Eagles refers to "insufficient supply" that will force demand down. Sounds good for the peak oil hypothesis, right? But look at the projected demand! The graph left (click to enlarge) shows the IEA's supply & demand forecast, which they call the "global balance". Demand is set at 95.82 million b/d by 2012. That's a 10% leap in five years, with an annual average increase of 4.5%. This is staggering growth. When Eagles refers to supply constraints on demand, he is not talking about a peak in the global oil supply. He is referring instead to possible shortfalls as weighed against the IEA's aggressive medium-term growth forecast.

The IEA's demand data¹ for the last 5 years, including the 2007 projection, serves as an instructive point of comparison. Their data (graph left) shows the recent plateau that began at the start of 2005. Demand has averaged 84.28 million b/d through the 2nd quarter of 2007. (The IEA supply data is similar, averaging 84.85 million b/d through the 1st quarter of 2007.) Demand grew only 6.3% from 2003 through 2006. The anomalous increase in the 4th quarter of this year stands out —  demand jumps to 88 million b/d. The IEA expects our oil thirst to continue at this level in 2008, when quarterly demand is forecast to average 88.27 million b/d,  2.13 million b/d above their 2007 estimate.

The IEA is a political organization, and its demand forecast should be seen in this light. Liquids demand that is not met outside of OPEC (non-OPEC) must be supplemented by the cartel — this is the call on OPEC. The IEA and OPEC constantly squabble over what OPEC's production levels should be, where the bone of contention is their separate estimates of the non-OPEC production share. The IEA guesses low, while OPEC guesses high, saying the market is well supplied despite steeply rising oil prices. The IEA's mission requires them to urge OPEC to increase production to  ease tight supply and prices. However, a close look at the Medium Term OMR reveals that the IEA is not lowballing their estimate. In revising their future non-OPEC supply estimate downward, they are trying to avoid past mistakes in which overly optimistic forecasts did not come to pass.

The IEA's bona fide field-by-field estimate of future non-OPEC production generally agrees with other forecasts regardless of whether their demand projections are exaggerated for political purposes.The growing consensus is reflected in the graph left from PFC Energy's Mike Rodgers (graph left, presented at ASPO-USA's Boston World Oil Conference, October 2007). Note that the graph contains the ExxonMobil non-OPEC forecast, which is entirely consistent with those of the IEA and PFC Energy. Note further that the IEA's demand forecast corresponds to PFC Energy's highest growth case. All three estimates include crude oil, condensate, the Canadian oil sands, and global natural gas liquids (NGLs), including — counterintuitively —  those produced in OPEC countries. NGL's are not subject to OPEC quota restrictions, so their production is seen as market-driven, not restricted by policy.

The IEA non-OPEC forecast (see here) sees 2008 as being a very good year, but its almost all downhill from there. The supply section tells us the crucial considerations:

1. Non-OPEC growth is driven initially by OPEC gas liquids and biofuels... A leveling off in non-OPEC conventional crude supply is notable, but is inconclusive as evidence for an imminent oil supply peak.

2. Upstream construction, drilling and service capacity remains stretched, leaving forecasts prone to adjustment due to cost over-runs and project slippage... [Downward revisions reflect] a tendency for unscheduled field outages. Supply-side uncertainty is further exacerbated by increased instances of resource nationalism and geopolitical risk [see pp. 31-34].

3. [The net global decline rate is hard to calculate, but] a proxy can be calculated by comparing net change in non-OPEC supply for 2007-2012 and gross capacity additions. As seen below, the implied net non-OPEC decline rate for baseload production is around 4.6% per year. This covers not only fields in decline, but also older supply which is at or approaching plateau. With net decline from OPEC assumed at 3.2% per year, this gives a global annual decline of 4%, suggesting that 3.2 mb/d of new production must be found each year just to stand still.

The "notable" plateau of non-OPEC conventional crude production also includes condensate after 2008 (graph left). The IEA's 4% net global decline rate equals the value calculated in Decline Rates and Non-OPEC Supply using data from the EIA, the Oil & Gas Journal, and Skrebowski's Megaprojects schedule (this column, April 11, 2007). Lewis Carroll's Red Queen dilemma, in which 3.2 million b/d must be put on-stream just to stay in-place, recalls Peak Oil -- The Power of Declines, which illustrates the problem by use of a modified version of Skrebowski's Oil-a-Gator graph (this column, April 4, 2007). In some ways, the IEA has definitely moved closer to ASPO-USA's position on non-OPEC production, not to mention that of PFC Energy and ExxonMobil.

The IEA's estimates for future production in Russia and the U.S. Gulf of Mexico illustrate their non-OPEC assessment methods. The EIA admits that its take on production Russia is hampered by a lack of specific field data. Russia is the key, because without increased output from there and the other Former Soviet Union (FSU) countries since the late 1990's, the world would be referring to the peak of production outside of OPEC in the past tense.

Despite the fact that Russia exceeded the IEA's expectations by an average of 250 thousand b/d in the 2001-2006 period, they have now revised their 2011 forecast downward almost 200 thousand b/d due mainly to an "uncertain ... investment climate and tight drilling/service capacity." During the 2009-2011 period, production in Russia's remote Far East  will determine whether their output can continue to grow. Given the IEA's uncertainty about declines in producing fields (graph above left), it is surprising that they use a modest 3% baseline annual decline rate. The IEA sees Russia's output increasing to 10.6 million b/d in 2010, which is "well below published growth targets for producers like Rosneft, Lukoil and TNK-BP."  Oil production then shows a modest decrease thereafter. Although the IEA states that it is too early to tell, they have forecast a peak in Russia's oil production in 2010 as things stand right now.

In the Gulf of Mexico, examined in The Gulf of Despair? (this column, June 27, 2007), the IEA forecasts that production will grow a modest 345 thousand b/d in the medium term, with the largest contributions coming from Atlantis and Thunder Horse (200 thousand b/d each). The IEA gives a long list of deepwater fields (p. 38) that should yield a net 1.1 million b/d addition by 2012, but temper their forecast by assuming a steep 15% baseline decline rate, and acknowledging the "tendency for deepwater fields to peak rapidly, followed by sharp decline." This assessment seems reasonable, but fails to recognize that some fields, like Murphy's Front Runner, have not produced at their anticipated capacity. There is also concern that Chevron's Tahiti may not live up to expectations.

The IEA's position on peak oil is summed up on p. 30 of the Medium Term OMR.

The concept of peak oil production and its timing are emotive subjects which raise intense debate. Much rests on the definition of which segment of global oil production is deemed to be at or approaching peak. Certainly our forecast suggests that the non-OPEC, conventional crude component of global production appears, for now, to have reached an effective plateau, rather than a peak...

While there might be a temptation to extrapolate this trend, citing a peak in conventional oil output, a degree of caution is in order. Firstly, the concept of ‘conventional’ oil changes with time, technology and economics. In the early 1970s, much offshore production was deemed unconventional, but this portion of global supply has since grown to account for 30% of the total. Evolving economies of scale and infrastructure development could do the same for GTL, oil sands and ultra-deepwater reserves in the future, shifting today’s unconventional resource into tomorrow’s conventional supply category. Moreover, rapidly-growing condensate and NGL supply is scarcely ‘non-conventional’ in a technical sense now.

What is deemed "conventional" or "unconventional" liquids production is a red herring. The view here is that ultra-deepwater oil is conventional crude, and natural gas liquids are included in the definition of "oil" by default. The IEA is taking a standard economist's view of scarcity, in which substitutes such as NGLs, biofuels, gas-to-liquids, and oil sands support further liquids production growth as non-OPEC crude and condensate levels off. If one wants to split hairs, one could question whether the forecast outside of OPEC should include gas liquids from the Persian Gulf and North Africa, the lack of a quota restriction notwithstanding. An OPEC nation's investment and production policy may not make the same hard and fast distinction. Biofuels, and oil sands production are not likely to grow much in the medium term, as their own graph shows (2nd above, left). The prospective gas-to-liquids industry has been stopped dead in it tracks by rising costs. The IEA knows this, saying that ExxonMobil "cancelled the 150 kb/d Palm GTL project, reportedly due to doubling costs and reservoir complexity."

The IEA's report downplays the peak of non-OPEC crude and condensate production. Even if their crude, condensate, and gas liquids forecast is accurate, the implications beyond 2012 are troubling. Recent statements by IEA head Claude Mandil and chief economist Fatih Birol, documented by Jerome á Paris (The Oil Drum, Europe), reflect their urgent worries about the the longer term. The IEA Medium Term Oil Market Report take significant steps toward acknowledging the peak oil problem. For this, they should be commended. However, making fine distinctions about what counts as "conventional" liquids production, and what does not, is not helpful in motivating the world to pay attention to critical problems with the oil supply in the next decade.

Contact the author at dave.aspo@gmail.com

1. The IEA provides a glossary of terms. Demand is defined as "total inland deliveries plus refinery fuels and bunkers minus backflows from the petro-chemicals sector. It is thus equivalent to oil consumption plus any secondary and tertiary stock increases." Supply consists of all the different types of liquids the IEA tracks, which presumably corresponds to all produced liquids. One assumes that liquids not consumed end up in primary stocks.

Exaggerated Oil Recovery

Comin' in on a wing and a prayer
Comin' in on a wing and a prayer
Though there's one motor gone
We can still carry on
Comin' in on a wing and a prayer
     — World War II song by Harold Adamson and Jimmie McHugh (1943)

There is never a dull moment for those studying the peak oil question. The National Petroleum Council (NPC) released its long-awaited report Facing the Hard Truths About Energy on Wednesday, July 18th. A prepublication draft of the report contained references to a graph (2nd figure, below left) which was subsequently excised from the full report now available to public. The NPC report talks about peak oil, and the missing graph is part of that discussion.

The NPC's view of peak oil is best summed up in this passage from the Executive Summary (p. 19):

Concerns about the reliability of production forecasts and estimates of recoverable oil resources raise questions about future oil supply and deliverability. These concerns are strongly expressed in “peak oil” forecasts in which (1) oil production does not grow significantly beyond current levels and (2) an inevitable decline in oil production is increasingly near at hand. Views about oil supply tend to diverge after 2015, with peak oil forecasts providing the lower bound. These forecasts generally consider oil supply independently of demand and point to supply shortfalls. Such views contrast with forecasts and economic models that expect market forces to provide incentives for developing global hydrocarbon and other resources to meet energy needs through at least 2030.

The "Hard Truths" report makes the point throughout that prices will stimulate supply to save us from medium-term shortfalls. This economist's view of scarcity is embraced by the EIA, whose longer term forecasts out to 2030 are liberally cited in the supply section (Chapter 2) of the document. The EIA's Simple Model of a Complex World (this column, June, 13th, 2007) provides a detailed look at how the energy department forecasts future liquids supply. Their market clearing model shows non-OPEC supply growing primarily as a function of the oil price, while holding OPEC production at a fixed level in three separate scenarios.

The NPC's excised graph was meant to illustrate how market forces might increase the oil supply to meet growing demand. Adam Smith's invisible hand will supply new oil by means of continuing development of existing conventional oil reserves, new discoveries, unconventional substitutes and enhanced oil recovery (EOR). Examining how EOR might affect the peak of world oil production serves as a warning to analysts like Daniel Yergin, who played a prominent role in putting the NPC report together, and whose unbounded faith in the supply & demand balance prompts him to dismiss peak oil out of hand.

EOR, which is also called tertiary recovery, is used after primary and secondary recovery methods in an oil field have been exhausted. Primary recovery takes advantage of natural reservoir pressure to lift the oil out of the ground. What nature provides is augmented at some point by secondary recovery methods, which involve injection of water or associated natural gas to maintain reservoir pressure. Secondary  recovery techniques are now used more and more in combination with infill and horizontal drilling. These methods have resulted in an average recovery of about 33 to 35% of the original oil-in-place for all fields worldwide. EOR is used, where applicable, to raise recovery factors by some percentage in the tail-end of the production curve (graph left, click to enlarge). EOR methods include:

• Gas flooding (injection) using both miscible or immiscible carbon dioxide (CO₂), complex hydrocarbons (other than methane), flue gas, and nitrogen.
• Thermal methods, including hot water or stream flooding for heavy oil at shallow depths and in situ combustion.
• Chemical solvents, including injection of polymers, surfactants (foam), and micellar-polymers. These are called alkaline-surfactant-polymer (ASP) processes.

The NPC's absent graph (left, click to open) shows a substantial, growing contribution from enhanced oil recovery starting in the year 2000, and continuing until 2030. In so far as the NPC has backed away from this sample forecast, there is no need to directly evaluate its contents. However, it is safe to say that the National Oil Companies (NOCs) have offered enhanced oil recovery as an important remedy for future oil supply ills.

EOR technology is not some new, miracle cure for recovering additional oil in mature reservoirs, as reporter Jad Mouwad reported in his New York Times article Oil Innovations Pump New Life Into Old Wells. (See a previous column, Deconstucting the New York Times, for an analysis.) The NPC report predominantly represents the outlook of the NOCs, and these views are well represented by the Times. It is educational to quote them at considerable length —

The oil industry is well known for seeking out new sources of fossil fuel in far-flung places, from the icy plains of Siberia to the deep waters off West Africa. But now the quest for new discoveries is taking place alongside a much less exotic search that is crucial to the world’s energy supplies. Oil companies are returning to old or mature fields partly because there are few virgin places left to explore, and, of those, few are open to investors...

At Bakersfield [Kern River], for example, Chevron is using steam-flooding technology and computerized three-dimensional models to boost the output of the field’s heavy oil reserves. Even after a century of production, engineers say there is plenty of oil left to be pumped from Kern River.

“We’re still finding new opportunities here,” said Steve Garrett, a geophysicist with Chevron. “It’s not over until you abandon the last well, and even then it’s not over.”

Typically, oil companies can only produce one barrel for every three they find. Two usually are left behind, either because they are too hard to pump out or because it would be too expensive to do so. Going after these neglected resources, energy experts say, represents a tremendous opportunity...

“Ironically, most of the oil we will discover is from oil we’ve already found,” said Lawrence Goldstein, an energy analyst at the Energy Policy Research Foundation, an industry-funded group. “What has been missing is the technology and the threshold price that will lead to a revolution in lifting that oil" ...

Oil companies have been perfecting so-called secondary and tertiary recovery methods — injecting all sorts of exotic gases and liquids into oil fields, including water and soap, natural gas, carbon dioxide and even hydrogen sulfide, a foul-smelling and poisonous gas....

“Yes, there are finite resources in the ground, but you never get to that point,” Jeff Hatlen, an engineer with Chevron, said on a recent tour of the field.

In 1978, when he started his career here, operators believed the field would be abandoned within 15 years. “That’s why peak oil is a moving target,” Mr. Hatlen said. “Oil is always a function of price and technology.”

Enhanced oil recovery has been used in the United States for three decades. CO2 injection gains momentum (Oil & Gas Journal, April 17, 2006) indicates that oil production in America from EOR was 605 thousand b/d in 1986. A Niche for Enhanced Oil Recovery in the 1990s, published by Schlumberger, provides an excellent overview of EOR technology in 1992. Little has changed since then. The early 90's report concludes:

EOR technology does not seem to be on the threshold of any dramatic technological breakthroughs. Instead progress will probably come through gradual evolution, stimulated by growing motivation to recover more oil from known fields. The major contribution to EOR is likely to be from the constantly improving art of reservoir characterization for predicting EOR response and from horizontal drilling.

No dramatic breakthroughs have taken place, but there's no lack of motivation now.

It is instructive to look at the history of EOR production in the United States. The EOR graph (left, click to enlarge) indicates that production appears to have peaked in 1998 at 759.6 thousand b/d, as thermal recovery declines more than offset gains from miscible carbon dixoide injection. (Data is from the Oil & Gas Journal article cited above, see here to get the breakdown.) Production now stands at 649.3 thousand b/d. In 1998, EOR made up 12.1% of total U.S. production; it was 12.6 % in 2006.

The NPC's Executive Summary makes two recommendations regarding EOR (see below), saying that such technology could potentially yield "an additional 90 to 200 billion barrels of recoverable oil in the United States alone, which could help slow the current decline in production." The technology section (Chapter 3) has this to say about EOR production in the United States (p. 22) —

The NPC studied EOR in 1976 and 1984, and raised great expectations for domestic EOR activity (projecting 3 million and 2 million barrels per day, respectively). These expectations have not been met. Peak domestic EOR production occurred in 1992 at 761,000 barrels per day. Current activity is 680,000 barrels per day. In the interim, many technologies have been tried, but most failed. Two successes are CO₂-miscible floods and steam (cyclic, steam-assisted gravity drainage [SAGD], and steam flood).

The NPC's estimates for using EOR to recover additional oil in mature reservoirs derive from the views of Vello A. Kruuska of Advanced Resources International. His research, which centers around recovery of stranded light oil by use of CO₂ EOR methods, has been reviewed by the author in Stranded Oil Recovery and American Energy Independence (The Oil Drum, October, 13, 2006). Kruuska's May, 2007, testimony before the House Subcommittee on Energy and Mineral Resources outlines an aggressive scenario which assumes additional government-funded research into "next generation CO₂ EOR technology" and field demonstrations of Carbon Capture and Storage (CCS) to assure affordable supplies of carbon dioxide. If these steps are taken — a Big If — Kruuska is optimistic that it might be possible to produce as much as 800 thousand b/d of stranded light oil by 2015 (graph left, click to enlarge). If expanded tax credits and CO₂ sequestration incentives are thrown into the mix, production might reach 1 million b/d by that date. The size of the stranded conventional oil resource sounds impressive, but oil flows much beyond what we've seen to date are still up in the air.

It is in this context that the NPC's recommendations for expanding EOR production make sense (Executive Summary, p. 21). The government must 1) support regulatory streamlining and research and development programs for marginal wells, and 2) expedite permitting of EOR projects, pipelines, and associated infrastructure. Recommendation #1 makes it clear that developing advanced EOR technology to recover stranded oil is still mostly a research project. For example, Chevron, so confidently quoted by the New York Times, is betting on research in using surfactants and polymers. The array of technologies listed by the NPC in the Technology chapter (p. 23) are supposed to be ready in either 2015 or 2020. CO₂ EOR recovery requires infrastructure to capture and transport the gas, which would seem to be part of the basis for recommendation #2.

Bringing expensive enhanced oil recovery on-stream is also a function of available technology and oil reservoir characteristics, not just the oil price. Uncertainty abounds in current EOR production projects. Chevron is using sour gas (H₂S) injection at Tengiz in Kazakhstan to help increase production there to somewhere between 430,000 and 500,000 b/d by late 2006, up from the current 298,000 b/d. The achieved incremental production flows will "depend on the [subsurface] effects of sour-gas injection"  (Oil & Gas Journal, op. cit.). EOR technology is not universally applicable in any case.  From Progress in IOR technology, economics deemed critical to staving off world's oil production peak (Oil & Gas Journal, August 4, 2003) —

Olivier Appert, chairman and CEO of the Institut Français du Petròle, contends that IOR [Improved Oil Recovery, overlaps with EOR in this context] technologies "should be adapted on a case-by-case basis, depending on the characteristics of the field and the fluids"...

"Simultaneous water and gas injection is developing rapidly. For heavy oils and nonconventional oils, thermal technologies such as SAG-D (steam assisted gravity drainage), or vapor extraction, where hydrocarbons are replacing steam," are seeing growing use. "There is also a renewed interest for polymer flooding in the case of smart wells and completions."

There is no single technological magic bullet that will "stave off" peak oil, as even the NPC admits throughout its report.

It is reasonable to ask at this juncture why the the NPC is still fiddling while Rome burns, still talking about "accumulating risks" to the oil supply. The IEA has finally made their position on the future oil supply clear — it is in trouble by 2012.  By its own admission, the NPC's previous estimates for EOR production didn't pan out. Thus, the missing graph made an unsupportable conjecture, which is probably the reason it was withdrawn. EOR technology will not provide much help in any time frame that would be relevant to the IEA's demand projections. Conveniently for the NPC, they guarantee that oil production will meet growing demand out to 2015, when we are assured that the technology calvary will arrive. Are you willing to take the chance that the NPC is right? Is a wing and a prayer all we need?

Contact the author at dave.aspo@gmail.com

Peak Oil Down Under

by Dave Cohen

A man either lives life as it happens to him, meets it head-on and licks it, or he turns his back on it and starts to wither away.
     — Gene Roddenberry

Australia serves as a microcosm of a world entering the peak oil era.¹ It can be shown beyond a reasonable doubt that Aussie oil production has peaked. As their oil companies struggle to offset production losses as demand grows, Australians must face up to the stark choices these circumstances present. One road, taken by the United States long ago, creates dangerous, ever-growing dependencies on imported oil to fill the supply and demand gap. The other road, leading to energy independence and security, spawns alternatives that allow Australia to move beyond oil. Will the Land Down Under seize the opportunity they now have to make the right choice?

Official forecasts of Australia's future oil (= crude oil plus condensate) and gas resources and production (OGRA) are made by Geoscience Australia (GA), which is similar in function to the America's USGS. Their latest comprehensive report was issued in 2004. Figure 1 (click the graphic left to enlarge it and keep the page open) shows historical production along with GA's 10%, 50% and 90% probability cases for estimated oil production out to 2025, where "a production estimate at the X% probability (= PX%) level means that there is a X% chance of production being at least as high as the figure shown."

Figure 1 establishes the central fact about Australia's oil production: it has peaked according to the most probable future production scenarios. Only the 10% probability case shows a higher production level, so it necessary to assess how Geoscience Australia's forecast has fared since 2004 and take a look at projects coming on-stream to demonstrate that Australia is definitely past peak — and just in case John Howard's shortsighted government harbors some residual hope (APPEA) that the problem will just magically disappear.

Figure 2 gives the production trend (using EIA supply data) since the beginning of 2001 through March of 2007, along with a rough comparison with the GA's high, middle and low cases. Oil production has mostly followed, but is a little below, the P90% (low production) case. This is not good news for Australia.

The offshore Exmouth sub-basin of the Carnarvon Basin (Figure 3) off the northwest Australian coast is where the action is for new oil projects. Australia's production jumped from a low of 370 thousand b/d in June, 2006, to a highpoint of 510 thousand b/d in October. The increase was mostly due to the Enfield development coming on-stream in July, 2006. Enfield, which is operated by Woodside and Mitsui, was built with a production capacity of 100 thousand b/d using 5 producing wells along with 8 water and gas injection wells, all connected to a floating storage and offloading platform (FPSO). Figure 4 gives Enfield's production profile since then, indicating that production reached 74 thousand b/d in the early fall, a level which supported the October rise.

From November on, including an anomalous jump in February, 2007, Australian production has averaged only 469 thousand b/d. Part of the problem has been at Enfield, where "ENA-03, one of the major production wells, was shut-in due to unexpected sand production and early water breakthrough" in October. Woodside's guidance indicates that 2007 production is expected to average only 45 to 55 thousand b/d. It is doubtful whether Enfield will ever produce at or near capacity.

BHP shores up dwindling oil (The Australian, July 5, 2007) discusses the bigger picture and sets expectations (new projects with planned capacities are highlighted in blue).

Commitment to a $2 billion oil development [operated by BHP Billiton] off Australia's northwest coast  will lift the country's daily production by as much as a sixth in 2010. But there will still be only a short-lived respite from inexorable increases in crude oil and petroleum product imports, which have risen sharply in the past four years and pushed Australia from energy surplus to deficit... The [Pyranees] project, which is expected to be operating by late 2009 or early 2010, is being geared to produce around 96000 barrels of oil a day.

Graeme Bethune, managing director of specialist energy consultant EnergyQuest, said it was likely that when Pyrenees was in full production [in late 2009 or early 2010], Australia's daily oil output would reach more than 600,000 barrels. "That's the good news. Pyrenees is the last major oil project to be committed in Australia. There are no more oil projects in the pipeline," Dr Bethune said.

Woodside and Mitsui are spending more than $US720 million on the Vincent oil project north of Pyrenees and this is scheduled to have peak production of around 100,000 barrels beginning next year. BHP and Woodside are also constructing the Stybarrow oil project to the west of Pyrenees at an estimated cost of $US600 million, capable of producing up to 80,000 barrels a day. And Australian independent AED Oil is planning to produce more than 25,000 barrels of oil a day from an estimated $US100 million development of the Puffin field about 700km west of Darwin in the Timor Sea, with first oil expected by September.

Woodside initially specified Vincent's capacity as 100 thousand b/d as quoted above, but has apparently revised their expectations downward to a peak production rate of between 60 and 80 thousand b/d (Woodside link op cit.). There is also reason to doubt the quoted maximum rate for the Pyrenees fields (Crosby, Ravensworth and Stickle). The proved reserves are listed at 80 to 120 million barrels (mmbbl) of recoverable oil, but reservoir volumes this small could never support a production rate of 96 thousand barrels per day. This rate sustained over the course of a year would amount to 35 million barrels of oil! A source on Western Australia’s developing hydrocarbon potential cites "potential" recoverable reserves of 300 mmbbl, which might support the quoted peak rate for a short time. The FPSO at Vincent may indeed have a capacity of 96 thousand barrels per day, but it is questionable whether this capacity will ever be fully utilized.

Other new fields may not produce as advertised. Woodside gives their 60% share of proved + probable reserves for Vincent² as 43.8 mmbbl, which adds up to about 73 mmbbl altogether (see Figure 3 from their partner Mitsui). As with Pyrenees, it is difficult to see how reserves volumes this small could support a peak production rate of 60 to 80 thousand b/d for very long, if at all.

Australian energy expert Graeme Bethune's best estimate for 2010 is 600+ thousand b/d, some 100 thousand barrels below the peak year 2000. This forecast accords with Geoscience Australia's P50 case, but production at this level is now pushed out a few years into the future. The capacities of all the fields mentioned here add up to 321 thousand b/d, counting Vincent as 70 thousand and taking the problems at Enfield into account. Added to the latest March, 2007 figure of 466 thousand b/d, the tally would be 787 thousand b/d, exceeding Australia's year 2000 highpoint. How can this be?

Production uncertainties in the offshore fields of northwestern Australia are accompanied by steady declines in all their other major oil basins, as shown in Figure 5. Only the Exmouth sub-basin production has seen erratic growth since 1985, with the exception of a short-lived production spike from the Timor Sea in the 2000 - 2001 period. Both Timor and Carnarvan production have fallen off recently, but only the latter is capable of picking up the slack out to around 2010. Whether production will actually meet EnerygQuest analyst Graeme Bethune's expectation of 600+ thousand barrels a day at the end of this decade is anybody's guess.

Now that it has been established that peak oil Down Under has almost certainly come and gone, and that near term production increases may be disappointing, it is appropriate to ask what Australia is doing about it. Prime Minister John Howard's government is doing next to nothing, according to Bruce Robinson and Phil Hart of ASPO-Australia. The graph (left, click to enlarge) adds a projected oil demand line from Geoscience Australia to their P50 estimate. As consumption increases and production decreases steadily after the 2010 secondary peak, Australia must close the gap by importing oil. Australians tend to speak of their oil self-sufficiency, which is defined here as the ratio of liquids production/consumption. The Australian notes —

According to the Australian Petroleum Production and Exploration Association, the nation's energy deficit - cost of imports less the value of exports - in 2005-06 was $12.8 billion.

Within three years domestic oil production will have increased but industry analysts believe demand will also increase. This means that self-sufficiency, now down to around 54 per cent [in 2007] from 90 per cent early in the decade, will scarcely be improved.

One weak government response was to increase subsidies on liquified petroleum gas (LPG), a mixture of propane and butane. About 77% of Australia's production is called "naturally occurring LPG", which is "sourced directly from underground reservoirs, generally as an associated product of crude oil and natural gas production." The other 23% is produced during oil refining. Conversion of vehicles to run on LPG is becoming more popular, and conversions in Australia have increased following the government incentives. This measure will make only a small dent in overall oil products demand, however.

Australia is rich in natural gas (see Figure 6), which makes possible large-scale initiatives using Compressed Natural Gas (CNG) as a fuel for vehicles. There are large hurdles to overcome, including the fact that CNG is indeed a gas, not a liquid, and also taking into account the huge distance between where the gas is produced (the northwest) and where most of it would be consumed (the southeast).

A tepid demand-side response is offered by TravelSmart, a joint initiative of Australian, State and Territory Governments that promotes alternative forms of transportation. It is discouraging that the peak of oil production in Australia is not among the various reasons offered for considering walking, cycling and using public transport. Although the program is admirable, it would be fair to say that TravelSmart, which is currently implemented as a number of different voluntary initiatives, is merely peak oil window dressing at this point.

Unlike America, which has been traveling down the dangerous foreign oil dependency road for decades, Australia has a chance to fix the problem now. Is Australia's current inaction due to the fact that their oil production will increase a bit in the short term? Do Aussie policy-makers believe that oil imports will always be easily available at reasonable prices? Such myopic visions of the future ignore the global warning signs that peak oil is near. Rather than slip into a perilous import dependency, Australia can take the initiative toward energy independence that would guarantee their economic well-being for a long time to come.

Contact the author at dave.aspo@gmail.com

1. Bruce Robinson and Phil Hart of ASPO-Australia kindly gave me some guidance. I would like to thank them both for their assistance with this article.

2. Woodside originally planned to tie in Vincent production with the smaller, neighboring Van Gogh (20 thousand b/d, due in 2009) and Theo discoveries, but these fields are now operated by Apache. Consequently, Woodside decided to go it alone at Vincent using an FPSO moored in 1100 feet of water.

Gasoline Subsidies and Iran

by Dave Cohen

What [name a country here] has succeeded in creating is not an economy impervious to shocks, but merely one which enables their consequences to be postponed to a later date.
       — Peter Schiff

Violence erupted in Iran last week when Ahmadinejad's government imposed gasoline rationing, limiting drivers to 100 litres (26.39 gallons) per month of petrol at the subsidized price of about $0.42 per gallon. Angry protesters burned gas stations as they denounced the belt-tightening measure and the politicians who imposed it (photo below, source). Sanctions on Iran, the Islamic Republic's policies, and subsidies on gasoline in other countries adversely our ability to cope with a liquid fuels peak that is likely to arrive by 2015. The rioting also revealed the sacrosanct nature of driving, and just how tough it's going to be to change people's transportation habits all over the world to mitigate the effects of the crisis.

Iran's upstream oil industry is a mess. The UN has imposed sanctions due to Iran's game of hide and seek with uranium enrichment, but those restrictions mostly affect their nuclear ambitions. As detailed in U.S. puts squeeze on Iran's oil fields (reprint from Los Angeles Times, January 7, 2007), renewed U.S. pressure has dried up most foreign investment there. Iran desperately needs capital to reverse faltering production in its aging oil fields, where geological declines are estimated to be 8% or greater.

According to Fereidun Fesharaki, president of FACTS Inc. in Honolulu, cited in Gas use at issue in Iran as oil production sags (Oil & Gas Journal, May, 2006) --

Iran is losing 350,000 b/d/year of oil production capacity ... and the decline rate could increase to 500,000 b/d/year by the end of the decade. Onshore decline rates have risen to 8%/year from 7%/year and offshore decline rates to 13%/year.

"These numbers are alarming, particularly as they come at the same time as runaway demand," Fesharaki said. "It is now possible to see a future with little or no oil export revenues within 2 decades."

Production of Ahwaz Bangestan oil field, for example, has fallen to 160,000 b/d from 250,000 b/d and will fall to 60,000 b/d within 1-2 years. A gas injection program could increase production to 220,000 b/d and maintain it at that level.

A simple calculation using Chris Skrebowski's Megaprojects (≥ 40 thousand b/d) list of upcoming oil field developments¹, based on an 8% decline rate, shows that Iran's current production of 3.9 million b/d would be approximately the same in 2013 even if every project comes on-stream as scheduled. Japan's Inpex Holdings pulled up stakes in Azedegan, due in 2009, last year. India's Essar Oil is now negotiating the development rights. Phase II of the Darquain (Darkhovin) field operated by the Italy's ENI was scheduled to expand production there from 50 thousand b/d to 160 thousand b/d in 2006, but is now delayed until late 2007. Tales of Iran's rapid demise may be exaggerated, but their production has fallen off 5.8% since 2005 according to EIA supply data. Hossein Kazempur Ardebili, Iran's OPEC representative, claims that the downturn in Iran's production is due to its cartel quota restriction, stating that they have a productive capacity of 4.25 million b/d. The IEA lists Iran's spare production capacity as 5 thousand b/d. They can't both be right.

Iran's Achilles' heel (Reuters) is their rising internal liquids consumption. America's financial war on Iran is meant to exploit this weakness. The Islamic Republic's refining capacity is about 1.6 million b/d, but their downstream industry provides only about 60% of their gasoline consumption, which is growing because they are practically giving it away. Iran must import the rest, which is a considerable drain on their revenues. (Click on the image left and keep the page open.) Figure 1 shows that Iran's petrol prices are the 3rd lowest in the world, even when the 25% price hike Iran implemented in May is taken into account. Figure 2 indicates that  gasoline subsidies make up an astonishing 38% of Iran's state spending. Figure 3 estimates that an Iranian citizen spends $4.49 to fill up a Honda Civic. Iran's oil production is probably maxed out now, so they can not increase exports to cover their gasoline bills. The Reuters article explains the situation —

"Sanctions have led to limited technology transfer, higher operating costs, and a much slower pace of development," said Stuart Lewis, Middle East director at energy consultancy IHS.

Iran last year embarked on a multi-billion dollar, five-year program to revamp and expand the refining system to 3 million barrels per day (bpd) from around 1.6 million bpd now. But analysts say state funding for the program is inadequate... India's Essar is in talks with NIOC [National Iranian Oil Company] to build a new $2 billion, 300,000 barrels per day plant, while China's Sinopec last year signed a deal to upgrade Iran's 170,000 bpd Arak refinery and has also upgraded plants in Tehran and Tabriz....

The country's domestic fuel consumption is rising at around 10 percent per year, encouraged by the subsidies that make its gasoline among the cheapest in the world... Fuel subsidies dampen the financial incentives to build new refinery capacity, analysts said. New plants may cut dependency on expensive imports, but they would also divert potentially lucrative crude exports to domestic refineries and the subsidized market.

With NIOC's budget so limited, the state oil company would rather channel investment to the upstream sector, analysts said. "From the financial perspective there is less incentive to do this, it is more politically driven," said Saad Rahim, analyst at Washington-based consultancy PFC Energy. "If you're NIOC and you have a billion dollars to spend, you'd rather put it towards upstream oil output."

Iran can't financially support its upstream industry, let alone make the larger downstream investments it requires to meet burgeoning gasoline demand. Trying to quench their gasoline thirst by building out their refining capacity is self-defeating for Iran in any case — hence, the rationing implemented last week. As PFC's Rahim points out, NIOC would much rather invest what money they've got in the upstream part of the business to prop up sagging production. It is clearly in Iran's best interest, and best for the global oil supply, if Iran sharply curtails their internal consumption and reinvigorates their upstream oil industry to increase exports. Presumably, many in the Iranian leadership see the wisdom in this course of action.

What are the chances that Iran can turn things around? Aside from cheap petrol, America's foreign policy, Iran's insistence on stringent production sharing agreements, their budding nuclear program, furious Tehran drivers hurt by sanctions, and fundamentalist mullahs all stand in the way. The prospects look dismal, but Supreme Leader Ayatollah Ali Khamenei supported the rationing, saying " if this huge amount [spent on imported gasoline] is gradually reduced, definitely it will be spent on people's lives, employment, investment, construction of schools and roads."

Gasoline subsidies pose grave problems in a world that is likely on the brink of a peak in world oil production. Artificially low fuel costs encourage consumption and keep that demand insensitive to price increases. From Where gasoline is cheap (CNN Money, May 11, 2007) —

"Roughly two-thirds of new oil demand is coming from countries that have subsidized oil markets," said Christopher Ruppel, a senior geopolitical analyst with the consulting firm John S. Herold. "So demand is not going to be affected if oil goes from $60 a barrel to $80."

Ruppel said China still has gasoline subsidies, although lately the government has been trying to whittle them back. The average price for a gallon of gas in Beijing is $2.44...

... but the second-highest demand growth [after China] isn't in the fast-growing economies of India or Brazil. It's Saudi Arabia, projected to consume 5.6 percent more oil next year, according to Ruppel. Iran is number three, guzzling 3.3 percent more. Russia and Egypt, which Ruppel said both have heavy gas subsidies, are also high on the list.

And the raw numbers aren't small either. The Saudis used more than 2 million barrels of oil per day in 2006, and the Iranians used 1.7 million. India, a faster-growing economy with far more people, used 2.5 million...

Looking again at Figure 1, and also Figure 4, it is evident that the bottom twelve gasoline price positions are mostly occupied by large oil producers with state-sponsored subsidies, large, growing consumers, or both. The Mexican (consumption ranks #7), Chinese (#3) and Russian (tied for #5) subsidies are more modest than those in the OPEC countries, but prices far beneath those in the wealthy OECD nations (Europe, Japan, Australia, Canada) stimulate demand nonetheless. And then there is the profligate United States, where prices are unconscionably low by the standards of the other developed countries. Whether American consumption is "subsidized" is a matter of interpretation. In the absence of a state-sponsored discount, analysts who study the real cost of gasoline and imported oil in the U.S. tend to stress cost externalities such as military spending or the many social costs. What is absolutely clear is that the prices Americans are paying at the pump in 2007 are not yet high enough to rein in growing demand.

Last week's riots in Tehran were not unique. When India raised gasoline prices 4 rupees to 47.49 rupees per liter ($3.94/gallon) and diesel by 2 rupees to 32.45/liter in June, 2006, nationwide protests followed. The Congress party revoked those price increases in the last year, despite an Indian crude basket price of $67. However, with prices now about $70, "pressure has built within the [Indian oil] industry for a rise that could revive shares of hard-hit state-run refiners such as Indian Oil Corp. (IOC) and put a mild dampener on resurgent oil demand growth." The latest report (Times of India) indicates that the oil ministry's plans to increase fuel prices will be put on hold for fear of "upsetting (political) allies" and reviving inflation.

Were gasoline prices in the U.S. to jump a few dollars following an oil supply disruption or an imposed tax — or, God Forbid, a floating cap on consumption implemented through rationing — it is easy to imagine American consumers reacting just like their counterparts in Iran and India. As things stand now, it seems likely that a variety of scapegoats would be identified and attacked without addressing the underlying problem, which is rampant, unsustainable consumption.

Subsidizing gasoline prices — wherever or however it occurs — amounts to throwing away a precious, finite resource with no regard for the consequences that will surely follow down the road. Subsidies give the illusion of abundance and undermine market mechanisms that might encourage efficiency and fuel substitutes — such as they are — as prices rise. This kind of discounting of the future may be an irremediable part of our human nature, but events in Iran now illustrate the foolishness of this kind of behavior. Can we take home the right lesson from Iran's experience? Only time will tell.

1. Skrebowski lists Yadavaran (onshore, 2011, 300 thousand b/d) and Kushk - Hosseinieh (same, 2010) as separate projects, but they are identical, only then name has changed. "Yadavaran" is now the preferred name. Iran claims that this recent discovery (reprint, Tehran Times, 2004) in the southwestern province of Khuzestan holds 3 billion barrels of recoverable oil and will support a production rate of 300 to 400 thousand b/d.