Peak Watch

Sleepwalking Toward the Oil Precipice

The foolish man seeks happiness in the distance; the wise grows it under his feet.
     —James Oppenheim

The time has come to discuss what we can expect from OPEC as it relates to our prosperity in the coming decade. After 2010, crude produced outside the cartel will plateau and gradually decline, so any growth in the conventional oil supply must come from OPEC.

OECD policy-makers and consumers must now understand that OPEC's short term policy on supply-side relief, which is not to provide any, is also their longer term policy. Do not count on OPEC to bail us out of the oil crunch. We must adjust our expectations to reflect reality, not our hopes and dreams.

Delusional expectations placed upon OPEC's ability and willingness to expand the oil supply are going to make our lives untenable within a few short years. Harmful price impacts are already happening now. For most citizens, future impacts will far outweigh questions about who the next president of the United States will be as things stand now. In the absence of a major and immediate policy shift in the United States that aims to substantially reduce our oil consumption, it will be OPEC, not our elected government or "Big Oil" companies, that sets the minimum (floor) prices for liquids fuels.

This week brings news that OPEC president Chakib Khelil "does not rule out oil prices reaching $200 a barrel, even though supply is adequate, because the market is driven by the dollar's slide."

[Khelil] added: "The prices are high due to the fact of the recession in the United Sattes and the economic crisis which has touched several countries, a situation which has an effect on the devaluation of the dollar, and therefore each time the dollar falls one percent, the price of the barrel rises by $4, and of course vice versa," he was quoted as saying in brief remarks to journalists on Sunday.

He added that: "If this (the dollar) strengthens by 10 percent, it is probable that (oil) prices will fall by 40 percent" [Note — to $71.35/barrel at today's price]

... "But I don't think that an increase in production would help lower prices, because there is a balance between supply and demand and the stocks of gasoline in the United States have recorded a surplus and are at their highest level for five years."

Note — Khelil's assertion about current U.S. gasoline stocks is false (graph left). Falling gasoline stockpiles are now at the top of the 5-year average for April, and below that average for other months. On the other hand, large harmful diesel price hikes and shortages are occurring all over the world.

Although it is true that there is a negative correlation between the dollar's value and oil prices—the latter rises as the former falls—there is no good reason to believe that the plunging dollar has caused the price shocks of the last 8 months (both references are to James Hamilton's Econbrowser).

Khelil's thoughts on the oil price are simply another in a long series of excuses OPEC puts forth to justify their production policies. OPEC's president is actually saying that $200/barrel oil in the next few years is OK as far as they're concerned.

Two Views of Your Future

We need to set realistic expectations about OPEC's future contributions to the oil supply. I have come to see that most people do not share my enthusiasm for graphs, tables and simple arithmetic, but if your future prosperity rested on understanding these numbers and what they mean, you would make the effort, right? That's my challenge to you. My job is to present the material as clearly as I possibly can.

The first graph¹ comes from PFC Energy's Global Liquids Supply Outlook, a presentation by Bob MacKnight given on March 26, 2008. The graph shows the non-OPEC crude oil peak in 2010, but focus your attention on the "Call on OPEC" crude oil.

You can see three lines showing three separate scenarios for OPEC crude oil output growth out to 2020, one for yearly additions of 1.1%, one for 1.7%, and a third for 2.4%. These are the low, middle and high cases, respectively. As you can see, most world oil growth depends on OPEC crude (and natural gas liquids) production after 2010.

In PFC's low growth scenario, OPEC must supply 33 million barrels per day (mmb/d) to the world market in 2010, 37 mmb/d in 2015 and 46 mmb/d in 2020. Each growth scenario requires ever-higher OPEC crude production levels as shown, e.g. 37-45 mmb/d in 2015 spans the low to high growth cases.

Our second visual aid, Table 1.5 from OPEC's 2007 World Oil Outlook, shows OPEC's evaluation of the call on themselves in their reference case. Let's calculate the shortfall between OPEC's reference case and PFC's low growth scenario. OPEC's reference case in 2007 did not include Ecuador, which joined the cartel in November, 2007. You may thus add Ecuador's 0.5 mmb/d to OPEC's reference case for each year.

Subtract the adjusted OPEC Crude number in the table from PFC's Low Case number in each year Y.  In 2010, the shortfall is 33 − 30.7 = 2.3 mmb/d. In 2015, the shortfall is 2.7 mmb/d. In 2020, the shortfall is 6.7 mmb/d. 

You can now easily see that OPEC's call on itself is lower than PFC's lowest growth case² by a wide, ever-increasing, margin. I daresay that the reference case reflects what OPEC intended to produce—as of 2007—regardless of our expectations. It matters not whether these expectations come from the EIA, the IEA, IHS Energy/CERA, Wood Mackenzie, CGES or any other "experts" you care to name. Only OPEC's opinion matters here because they are in the Driver's Seat in 2010 and thereafter.

Are you going to pin your hopes on OPEC changing the call on itself upward as the years unfold? Think about their sit-on-your-hands policy, their persistent claims that the "market is in balance," Khelil's unconcerned view of $200/barrel oil ... well, I hope not.

It's Worse Than You Think

Although the foregoing paints a bleak picture, the situation is actually worse than you might think. OPEC's reference case may now be viewed as overly optimistic. Some points to consider are listed below. Things get a bit complicated in #1 and #3, so please be patient.

1. OPEC's average monthly production in 2008 (from the IEA's April Oil Market Report ) is 32.28 mmb/d, so you might say "Well! OPEC is producing more to ease the tight world market." OPEC is mostly adding to its total average monthly output by acquisition, not greater production in the core "OPEC 11". Angola joined the cartel in early January, 2007. Ecuador joined in November, 2007. There are now 13 countries in OPEC. Average monthly crude output was 29.71 mmb/d in 2006, and 30.66 mmb/d in 2007 adding in Angola's 1.61 mmb/d (= 29.05 mmb/d for the "OPEC 11"). Take the 2008 output number and subtract both Angola and Ecuador. The total for the "OPEC 11" is 29.97 mmb/d. This number has hardly moved over the last 27 months.

   The adjusted OPEC reference case total of 30.7 mmb/d in 2010 implies production of 28.30 mmb/d from the core "OPEC 11" if we assume current output levels for Angola and Ecuador (= 2.4 mmb/d). This is actually a decrease of 1.41 mmb/d from the 2006 level before either country joined the cartel.

   Summing up, total output from the usual suspects—Saudi Arabia, the UAE, Kuwait, Iran, Iraq, Nigeria, Algeria, Venezuela and the others—is assumed to be below the 2006 level in 2010 in OPEC's 2007 reference case. OPEC's Table 1.5 shows that the call on its crude is actually lower in 2010 than it was in 2005.
   

2. How much of this OPEC production will be available for export? Less than there used to be according to CIBC's OPEC's Growing Call on Itself. Consumption is rising in the Persian Gulf countries and elsewhere. Read the CIBC report and The Sierra Club Solution for a discussion of the export trends (ASPO-USA, January 30, 2008).

3. Recent Saudi statements seem to indicate an official change in policy that further confirms the Paradigm Shift position (ASPO-USA, June 20, 2007). This argument states that the Saudis and other oil exporters will not produce their oil in an unconstrained way to meed world demand. King Abdullah told us that "I keep no secret from you that when there were some new [oil] finds, I told them, 'no, leave it in the ground, with grace from god, our children need it'." Saudi Oil Minister al-Naimi validated the King's remarks in the Arab News (April 20, 2008).

   Top oil exporter Saudi Arabia has no plans to embark on further capacity expansion as long-term oil demand forecasts fall and alternative fuel supplies rise, the Saudi oil minister told industry newsletter Petroleum Argus.

   The holder of the world’s largest oil reserves sees no need to go beyond its 2009 capacity target of 12.5 million barrels per day “at least up to 2020,” Minister of Petroleum and Mineral Resources Ali Al-Naimi said.

   Long-term future energy demand forecasts have fallen sharply, he said in the interview given to the weekly on April 11, casting doubt on the need for more Saudi oil.

   Demand forecasts have fallen as low as 106 million bpd in 2030, down from previous estimates as high as 130 million bpd. The world currently consumes around 86 million bpd.

   This development adds a new wrinkle to what we already knew about Saudi intentions. See The Saudis Are Blowing Smoke Again, ASPO-USA, March 12, 2008. Saudi Arabia's (i.e. OPEC's) low demand projections could be called "a self-fulfilling prophecy" in so far as lower OPEC output after 2010 will price many consumers out of the oil markets. Worse yet, PFC's projection (graph left) shows that even unconstrained OPEC production would only boost world production to less than 100 million barrels per day by 2015 in any case! That's it, that's all there can be and ever will be based on PFC's depletion estimates for OPEC as a whole. (Look through their presentation.)
   

   PFC's low growth case exceeds OPEC's reference case after 2009. But without substantial new contributions from the Saudis over the next decade—we have now been told there won't be any—the reference case itself now appears to be too generous. Oil minister al-Naimi is now asking us to look at OPEC's "low growth" scenario instead of the reference case as shown in Table 4.2 of their 2007 World Oil Outlook (graph left). Take the adjusted shortfalls calculated above for OPEC's reference case for each year and then add the negative number given in Table 4.2. The OPEC crude shortfalls with respect to PFC's low 1.1% growth case are now as follows: 3.6 mmb/d in 2010; 6.1 mmb/d in 2015; 13.5 mmb/d in 2020.

   We have moved further into negative territory regarding OPEC's response to PFC's call in the low growth scenario. If this isn't bad news, I don't know what is.

4. If the foregoing isn't alarming enough, consider that substantial increase in OPEC production in the coming decade would require major contributions from Iraq, Nigeria and Venezuela, now that we know that a 12.5 mmb/d production capacity from the Saudis is all we're going to get. (All links are to past ASPO-USA columns.) Prospects for large production increases from these three countries is unlikely for reasons peculiar to each.

We have now set realistic expectations about OPEC's future contributions. They will not produce enough crude oil in the next 12 years to meet even a minimal growth scenario. Few subjects are more important than the potential contribution of OPEC crude to world production as we move toward 2020.

I hope you have been able to negotiate through this sometimes tortuous discussion because there is little else I can do personally to convince you that we're all in Big Trouble. In the New York Times' The Big Thirst, the inestimable Jad Mouawad, who is now coming to his senses, quoted former peak oil skeptic Vaclav Smil—

“The country has been living beyond its means,” said Vaclav Smil, a prominent energy expert at the University of Manitoba. “The situation is dire. We need to do relative sacrifices. But people don’t realize how dire the situation is.”

Unless we take some drastic actions, it will be All OPEC, All the Time after 2010 when you will turn on the radio or switch on the TV to listen to the inevitable stories about whether gasoline will finally hit $5 or $6/gallon. But in 2008, our public discourse on the oil situation is still a joke. We need to stop blathering about the boosting the Strategic Petroleum Reserve, opening up ANWR, taking OPEC to court, cutting federal taxes on gasoline, raising taxes on Big Oil, punishing speculators, counting on imaginary cellulosic ethanol, waiting for mass production of plug-in hybrids, and all the other nonsense we are bombarded with every day.

We are sleepwalking toward the oil precipice. OPEC will not meet the fantastic expectations placed upon it by the "experts." I can only hope that Americans grasp this reality soon, because all we're doing right now is rearranging the deck chairs on the Titanic.

Contact the author at dave.aspo@gmail.com

Notes

1. You will see that non-OPEC crude, condensate, oil sands, and natural gas liquids (NGL) are bundled together with OPEC natural gas liquids. This is standard accounting, because OPEC NGL output is not restricted by the cartel's quota system. Therefore, it is always put on the non-OPEC side of the ledger.

2. OPEC has a "high growth" scenario that only slightly changes the calculations made here. The deficits for this boom scenario work out as follows: 2.4 mmb/d in 2010; 1.8 mmb/d in 2015; 5.3 mmb/d in 2020.

Has Russia's Oil Production Peaked?

Good night, and good luck.
    —Edward R. Murrow

Has Russia's oil production peaked? The answer might as well be yes in so far as their smallish medium-term growth possibilities are fairly well-delineated and longer term growth will require levels of investment that are not likely to to be forthcoming in time to remedy the situation. This report is a follow-up to For Russia, An End to Growth is In Sight, which establishes the basis for this view (ASPO-USA, August 15, 2007).

What you need to know about Russia's future oil production is as easy as 1-2-3.

1. The slowdown in Russia's output growth since 2003 is crystal clear (graph below left, Wall Street Journal).
2. The small set of large (≥ 50,000 b/d) new fields coming on-stream by 2012 is precisely known. Mature depleted Russian oil basins (Western Siberia, Tartarstan) and tough new fields (Eastern Siberia, Far East) require huge investments in infrastructure, new wells, enhanced oil recovery, etc. to maintain or add to production.
3. Government policy does not cap oil output but rather impedes exploration & production activity with burdensome tax rates on Russian oil companies. The Federation—Vladimir Putin and his sidekick Dmitry Medvedev—also hassles and seeks to eject foreign operators (and their capital) after they have exhausted their usefulness, e.g. Shell at Sakhalin-2.

There is no compelling reason to believe that Russia will break out of the current plateau—€”permanent decline?—of oil production as it did after 1999. Even if Russia changes policies that currently stifle investment to promote future production, that money will work, increasingly in vain, to maintain, not grow, oil output. And even if a modest medium-term gain of 2-3% over current production levels should somehow be achieved by 2012, that will very likely be the end of the line for Russia production growth.

The fact that the skittish oil markets have finally noticed that Russia's output growth is flagging doesn't add much to what anyone who has looked at the situation and can interpret a graph already knows. As for optimistic expectations, those are usually the product of standard bureaucratic dogma that "all will be well," ignorance following from an inability to subtract, or our typically human emotional investment in a happy future—not the data and its reasonable interpretation.

Fuzzy Data and Expectations

This update is prompted by the news that Russia's production fell 1-2% in the first quarter of 2008, depending on the type of data examined. The Wall Street Journal's Russian Oil Slump Stirs Supply Jitters cited the IEA's calculation that production of 10 million barrels per day (b/d, crude oil + condensate + gas liquids) was down 1% in the 1st quarter compared with 2007, noting that "industry watchers and Russian officials generally blame the country's production slowdown on a combination of weather and tight electricity supplies in some parts of the country." Electricity? That's another subject.

Reuters cited Russian Energy Ministry data indicating that "oil production [crude + condensate] edged down to 9.76 million barrels per day from 9.79 million b/d in February, and well below the post Soviet high of 9.93 million b/d reached in October last year." The preliminary EIA data is slightly higher than the Russian official data, but shows the same winter trend.

Despite the discouraging results in the 1st quarter, the IEA's March, 2008 Oil Market Report (graph left) was still forecasting that Russia crude output would grow this year by as much as 250,000 barrels per day. They have now revised that forecast down to an all liquids addition of only 0.8% while taking a "cautious approach" according to IEA analyst David Fife.

The IEA's sudden wariness, which has never been apparent before, has caused them to withhold their future Russian forecast "pending [the] spring results, which could eliminate weather-related distortions typical of winter months" (AP, April 15, 2008). Their hesitancy is absurdly shortsighted—€”Russia's fate does not depend on any winter's weather conditions or what happens in the Spring quarter of this year. The agency is now, like Napoleon during the harsh Russian winter of 1812/13, in retreat.

Optimism still abounds in some quarters. The Wall Street Journal cites some hopeful sources—

Many Russian oil officials say the industry could still resume growth. Some Western analysts point to more optimistic data and forecasts. Citigroup said in a report late last month that it expects Russian oil volumes to increase by 1.5 million barrels a day between now and 2012, largely thanks to new projects in eastern Siberia. Still, it cautioned: "Russian oil production growth is no longer to be taken for granted." Russia's energy ministry expects a rise of 1.8%...

Note: Citigroup's happy projection provides for an increase of ≅‰… 15% within 4 years!

Citigroup's economists are surely an authoritative source on future Russian output, but perhaps it would behoove us to look at the investment issues and what the facts are on—and under—the ground in order to maintain some perspective about what's going on here. First, the finances.

Pressure on Investment in the Russian Oil Sector

The IEA's February Oil Market Report gives us the basic facts about Russian taxes on operators. "Russian oil companies pay three separate taxes on their activities," including—

1. A royalty on crude production; taxed at 22% after certain allowances
2. An export tax; based on the market price of Urals crude in the preceding two months. Light products attract a 30% discount on the tax charged and fuel exports benefit from a 60% discount.
3. A corporate profit tax of 24%, charged on net income, in common with other industries.

This added up to $65/barrel as of last February and the net profit for Russian oil companies was only about $10/barrel at that time. This staggering tax burden cuts significantly into the amount Russian operators have left over for exploration & production. It thus comes as no surprise that Rosneft is borrowing money, secured by crude oil export contracts, to finance its short-term debt (from Moscow journalist Sergei Blagov in Jamestown Foundation's Eurasia Daily Monitor, February 28, 2008). Can Rosneft can carry out its investment plans in Eastern Siberia?

In December 2005, Rosneft paid some $260 million for a license to develop the East Sugdin oil and gas field, with reserves of some 200 million tons of oil and more than 40 billion cubic meters of gas...

In order to achieve significant production growth, Rosneft plans to invest 50 billion rubles ($2.04 billion) in Eastern Siberia this year, and up to 600 billion rubles ($24.5 billion) through 2020, [Rosneft CEO Sergei] Bogdanchikov said. Rosneft expansion plans for Eastern Siberia largely rely on the Vankor oil deposit, which has estimated reserves of 500 million tons, he said. However, Bogdanchikov complained that the company's investment resources were limited, as it faced a tax burden of some 60%, while oil companies outside Russia pay about half that amount...

... Rosneft may still acquire new licenses, but developing new oil and gas fields in Eastern Siberia would require billions of dollars in investments. Therefore, it remains to be seen whether Rosneft's expansion could prove economically viable in the longer term.

Deutche Bank oil and gas analyst Leonid Mirzoyan states that "Rosneft is still unlikely ... capable of footing the expensive bill for developing the Vankor field on its own" (Moscow Times, April 3, 2007). Rosneft has been snapping up development licenses and shares, but they are overextended. How will Rosneft finance future development at Sakhalin-III, Vankor, North Vankor, Yurubcheno-Takhomskoye, East Sugdinsky, Verkhnechonsk and all the rest while continuing to drill more and more wells to get expanded production from older (former Yukos) properties like top Western Siberian subsidiary Yuganskneftegaz? And still pay their taxes? Rosneft's CEO Bogdanchikov doesn't know, and neither does anybody else.

Although plans have been announced to cut taxes by an estimated $4.2 billion in 2009, Leonid Fedun, vice president of OAO Lukoil, remains unimpressed. The Wall Street Journal quotes Fedun as saying that "Russia's oil industry needs $1 trillion of investment during the next 20 years just to maintain production of 10 million barrels a day." Lukoil will see a savings of about $1 billion after 2010, which will speed up development of the Filanovsky field in the Russian sector of the North Caspian. In line with Fedun's pessimistic view, Lukoil recently cut its 2008 growth forecast from 5% to 1.8-2.0%.

Various optimistic estimates—€”including Citigroup's absurdly cheerful private report, one presumes—have used Russian oil company growth targets to justify their forecasts. Forward-looking statements from TNK-BP, Rosneft or Lukoil are becoming increasingly worthless as a guide to future activity in light of the lack of capital available for exploration & production. Russia also has a paucity of large new fields coming on-stream and must fight off declines stemming from depletion in their mature oil basins.

Continuing Depletion and New Oil Fields

Lukoil's Fedun believes  Russia has peaked now (Yahoo! News, April 14, 2008). Here is what he told the Wall Street Journal about both the short and longer term prospects—

In an interview, Leonid Fedun, vice president of OAO Lukoil, one of Russia's biggest oil companies, said a mild winter and higher temperatures mean Siberia's icy ground is less stable, making it harder to move drilling rigs between oil wells.

He acknowledged that the fall also reflects a longer-term trend -- the depletion of Siberia's older fields. "Western Siberia is repeating the fate of Prudhoe Bay, with a time lag of five to six years," he said. "When the well's productivity falls, you have to keep drilling more and more. You've seen it in Alaska and the Gulf of Mexico, and now you're seeing it in Siberia."

It will come as no surprise¹ to veteran peak oil observers that Western Siberia is going the way of Alaska or the North Sea. Putting this in context, much of Russia's production growth in the last few years came from the offshore Sakhalin-I Chayvo field in the Far East, which peaked at 250,000 barrels per day in February, 2007. Rosneft now expects Sakhalin-I output to fall to about 160,000 barrels per day in 2008. Exxon Neftegas was drilling record-setting new wells at Chayvo back in April, 2007 but production will never return to peak levels at Sakhalin-1.

Declines at Sakhalin-1 must be offset by the implementation of year-round production of 70,000 b/d at Sakhalin-II, the Yuzhno-Khylchuyuskoye ("YK") field in Timan-Pechora, which will likely produce 150,000 b/d sometime in 2009, and an unknown contribution from Rosneft's Vankor in East Siberia starting this year. Rosneft has set its sights on 500,000 barrels per day from Vankor by 2015. (See These Are the Good Years for an update on factors affecting Vankor, ASPO-USA, February 20, 2008.) A few other large (≥ 50,000 b/d) projects are listed at 2008 Megaprojects page at Wikipedia, including the Salym field expansion which will likely add another 62,000 b/d in 2010.

Scheduled new projects delimit Russia's ability to expand oil production in the medium term. If one makes the conservative assumption that Russian output outside of the projects mentioned here will decline in the 2-3% range each year from now on, it is easy to see that Russia's post-Soviet growth is coming to an end. New project delays would only make the situation worse. Managing decline rates in the existing production base (in the medium term) depends directly on how much investment is available for new wells, new drilling technology (e.g. laterals) and enhanced oil recovery. There are tax discounts on some of these activities.

An End to Growth is Still In Sight

Everyone will have to wait & see how Russia fares in the next few years, but the only surprises will be on the downside—the limited upside possibilities are already mapped out. The Federation's growth is constrained by lack of investment, too few new large projects coming on-stream, and the geological facts of life.

It appears that Putin's policy is to intentionally restrain development through onerous tax burdens on Russia's oil companies. The Urals Blend is selling at $109.66 today. Perhaps Putin truly understands, like the Saudis apparently do, that keeping some of Russia's oil in the ground is a better longer term strategy than producing it in an unfettered way now and accruing future rate of interest returns on the unburdened revenues. All things considered, Russia is the largest crude + condensate producer in the world, and Vladimir Putin is no dummy.

Contact the author at dave.aspo@gmail.com

Notes

1. Read part 1 (For Russia, An End to Growth is In Sight) for a thorough discussion of developments in Russia.

 

An Unconventional Play in the Bakken

The devil is in the details
      —German Proverb

Last week the U.S. Geological Survey (USGS) released its long-awaited reassessment of the undiscovered recoverable oil potential in the Bakken Formation of North Dakota and Montana. The USGS estimated "mean undiscovered volumes of 3.65 billion barrels of oil," which sounds like a lot. Senator Byron Dorgan (D-ND), who commissioned the study, was delighted with the result, saying "this is great news, this is 25 times the amount of the previous assessment."

Oil is now being produced in the Elm Coulee section (graph left) of the Bakken and more oil will be produced there and elsewhere as the years go by. Although one can quibble about the USGS numbers—and we will—the more important question is what will the oil flows be from the Bakken?

A proper understanding of the likely conversion rate of Bakken recoverable oil to flows (measured in barrels per day) reveals that this unconventional play will have little effect on peak oil concerns or America's perilous oil dependency. This understanding comes from an examination of the geology and production practices in the Bakken.

Bakken Geology and Oil Production

Often called the Bakken "shale," the productive sandstone lithofacies lie within the formation's middle member sandwiched between the shale source rocks above and below, as shown in the graph (left) from Julie LeFever of the North Dakota Geological Survey. Landmark's Bakken Horizontal Best Practices Review indicates that the highly pressurized productive (pay) layers have a net thickness of 6-15 feet, low porosity (8-12%), low permeability (0.05-0.5 millidarcies) and a water saturation of 15-25%. The oil produced is light, with an API gravity of 42°. The pay zones have only minor natural fracturing according to Landmark and other sources.

All of these reservoir characteristics combine to make the Bakken play unconventional, which for the non-specialist means that it is challenging to lift this oil out of the ground.

What makes the Bakken play possible? As LeFever says, "technology has finally caught up to the Bakken Formation. The ability to fracture stimulate these horizontal wells is what makes this play work." Operators must drill down vertically about 10,000 feet and then "kick out" almost as far (± 9500 feet) horizontally through the productive sandstone layers. These long-length laterals maximize wellbore contact with the reservoir. Accordingly, wells must be widely spaced (e.g in 320 acre parcels).

The reservoir must be stimulated along the lateral drill length by the injection of fracturing fluids combined with a proppant to hold the fractures open to improve the permeability—the ability of a rock's ability to transmit fluids to the borehead.

It takes great human and technological skill to steer the drill bit horizontally through the pay layer. A large number of drilling and well completion design decisions—open hole or cement liner?—must be made to maximize well productivity. Many well designs have been unsuccessful. A "lessons learned" interview with Halliburton's Tom Lantz reveals the complexities of drilling at the Bakken. Operators must study spectral log data and carry out sophisticated well completion diagnostics. Sometimes older or unsuccessful wells can be revived using this sort of data.

All of this is very expensive. An AP report North Dakota shale oil recoverable tells the story—

According to Jim Ehrets, a Denver-based geologist with Headington Oil Co. of Dallas, it costs about $5 million to drill a well tapping the middle Bakken, and companies need crude prices of at least $50 a barrel to make it economical. Even with crude prices now double that, "there still is a ton of risk," he said.

Given the expense and complexity of drilling in the Bakken, it is no wonder that there is "a ton of risk" for operators—success is not guaranteed. The risk is so large that "drillers began sharing technology about two years ago on how to recover the oil" according to the AP report.

What about the successful wells? Unfortunately, a successful well at the Bakken will produce a few hundreds, not thousands, of barrels of oil per day. Landmark's 3000 foot horizontal well simulation (graph left) reveals that in the best case, with a permeability after hydraulic fracturing of 0.66 milladarcies, the well would produce 150,000 thousand barrels (averaging 375 stock tank barrels per day) after 400 days or so (purple line). As the curve shows, cumulative production declines dramatically thereafter, leveling off at approximately 370,000 barrels over the well's lifespan of 18+ years.

Elm Coulee provides a real-world snapshot of Bakken production as it stood in 2006. Headington Oil Company has made some useful data available that helps us evaluate how things might go in the future. Here are the pertinent facts & figures—

• The cumulative oil production 6 years after discovery is 32 million barrels. Production from about 350 wells had reached 1.6 million barrels in March, 2006. This works out to 53,000 barrels per day with an average well producing about 152 barrels per day.

• About 520 square miles are under development and there were 20 drilling rigs working continuously as of November, 2006.

• Headington estimates ultimate recovery from the area will be somewhere in excess of 250 million barrels, assuming ≅ 500,000 barrels will be ultimately recovered per square mile.

Combining Headington's Elm Coulee data with the Landmark simulation, we can draw the following conclusions—

• Well productivity drops off rapidly after the first year or so of production. If other parts of the Middle Bakken are as productive as the drilled parts of Elm Coulee, and constant large investment in drilling activity in the western Williston Basin continues, we might see peak production somewhere in excess of 100,000 barrels per day. This is an educated guess, but this estimate is not off by an order of magnitude, i.e. we are talking about peak production rates in the very low hundreds of thousands, not millions, of barrels of oil per day.

• It will likely take another 5-10 years to ramp middle Bakken production up to its peak level as described just above.

To put this in perspective, the ultra-deepwater Thunder Horse field in the Gulf of Mexico is supposed to produce at a peak level of 200,000 barrels per day in fairly short order should British Petroleum get its act together and put the field on-stream. Once Thunder Horse produces at peak rates for a while—assuming it reaches BP's target production capacity—declines thereafter are likely to be fairly steep. The middle Bakken, which likely will never produce as much as Thunder Horse at peak production, will also have a much shallower decline curve. Production will go on for decades in the Bakken, but thousands and thousands of wells will be required to extend the play over those years.

It's the size of the oil tap flow, not the size of the ultimately recoverable oil tank, that matters for peak oil calculations. But how much oil will eventually be recovered from the Bakken? Let's take a brief look at the USGS numbers.

Skepticism About the USGS Estimates

With oil near $114/barrel today, surely we can all agree that the era of cheap, abundant oil is over. The USGS has played a significant role in leading us to the present crisis in so far as their estimates have abetted complacency about future oil supply problems.

The U.S. Department of Energy uses the Geological Survey's extravagant estimates directly (e.g. the IEO 2006) to predict future discoveries and reserves growth numbers. These putative reserves predictions are then used to dismiss peak oil concerns. Over the last several years, the EIA's demand-driven model, which implicitly assumes that these huge recoverable reserves volumes will be produced as needed, has consistently served up erroneous predictions about future oil prices.

The inflated USGS estimates for the Bakken are no exception to the historical pattern, although some people are catching on that salvation does not lie just around the corner. As noted above, the USGS came up with a mean (≅ F50) estimate of 3.645 billion technically recoverable barrels of oil in the 5 assessment units (AU) of the Bakken-Lodgepole total petroleum system (TPS, graph left). Here are the tabulated estimates and the some key text from the USGS fact sheet—

The assessment of the Bakken Formation indicates that most of the undiscovered oil resides within a continuous composite reservoir that is distributed across the entire area of the oil generation window (fig. 2) and includes all members of the Bakken Formation. At the time of this assessment, only a limited number of wells have produced from the Bakken continuous reservoir in the Central Basin–Poplar Dome AU, the Eastern Expulsion Threshold AU, and the Northwest Expulsion Threshold AU. Therefore, there is significant geologic uncertainty in these estimates, which is reflected in the range of estimates for oil (table 1 [graph above left]).

Here are some telling—damning?—observations and comments on the USGS results—

1. Operators in Elm Coulee, which forms part of the Elm Coulee-Billings Nose AU, were skeptical about the USGS estimates. The International Herald Tribune reported that "Donald Kessel, vice president of Houston-based Murex Petroleum Corp., said he believes the Geological Survey's assessment of how much oil can be recovered in the Bakken may be a little on the high side. "That's a lot of zeros," Kessel said Thursday [about the 3,645,000,000 barrels].

2. The Elm-Coulee-Billings Nose AU has the smallest mean estimate, coming in at 410 million barrels, yet that is the only part of middle Bakken play undergoing extensive development. Headington's guess was somewhere in excess of 250 million barrels for "the area", but it is not clear whether this is just for Elm Coulee, or also includes some other parts of the Survey's assessment unit.

3. The USGS indicates that its largest estimates are for the areas where, by its own admission, "only a limited number of wells have produced." This includes the Eastern Expulsion Threshold AU, for example, where the Survey estimates an astonishing 973 million undiscovered and unrecovered barrels. There's always more oil where you haven't looked, according to the USGS.

4. Middle Bakken expert Tom Lantz (link op. cit.) has this to say about the geology of some of the undeveloped but supposedly oil-rich assessment units covered by the USGS—

   Certainly the thrust of the Middle Bakken play is moving north and east into the deeper sections of the basin in North Dakota. Since the lithology changes from higher quality dolomitic facies to a lower quality sandy/silty facies, the reservoir does not seem to be nearly as forgiving in North Dakota ... as it is in the original play area [Elm Coulee]. The ultimate extent and duration of the play will hinge on how effective we are in understanding these changes and tailoring the drilling and completion designs to exploit this lower quality reservoir. [emphasis added]

That's enough—you get the idea. It's hard to swallow the Geological Survey's story.

The Middle Bakken play is nevertheless a success story. Given the difficult geology of the oil-bearing reservoirs, sophisticated lateral drilling and well completion technology has been applied to allow the recovery of relatively large amounts of high-quality oil. Congratulations to those intrepid operators who are lifting oil out of the Middle Bakken. Despite this success, however, the Middle Bakken is clearly not an answer to our peak oil problems and dependency on foreign oil.

Contact the author at dave.aspo@gmail.com

Lost At Sea

If I look confused it's because I'm thinking
     —Samuel Goldwyn

If you're not confused, you're not paying attention
     —Tom Peters

It is crucial for those warning others about the dangers of peak oil to look at the effects of increasing oil prices (graph left) on economic growth. For some years to come, peak oil constraints will be manifest in the oil price, not in disruptive, recurring and systemic spot shortages—at least in the United States. What effects have oil price increases had on real U.S. GDP growth in the last 7 years? To be honest, nobody really knows—yet. We will all find out eventually.

There is no peak oil supply shock until world production of oil derived from fossil fuels production (crude + condensate + gas liquids) actually begins its irreversible decline sometime in the next decade. Until then, the correct answer to most peak oil inquiries is price, price, price as slow or no supply growth coupled with ever-higher energy costs creates more and more unsatisfied demand. Substitutes and efficiency measures (e.g. plug-in hybrids) will not save our bacon, despite what optimistic policy wonks and pandering presidential candidates say (NPR's Morning Edition, April 7, 2008).

Oil is not like iPhones. No studies link real GDP and iPhone price trends. Keith Sill, a senior economist¹ with the Philadelphia Fed, tells us why oil prices are important in his The Macroeconomics of Oil Shocks.

Oil prices matter for the economy in several ways. Changes in oil prices directly affect transportation costs, heating bills, and the prices of goods made with petroleum products. Oil price spikes [shocks] induce greater uncertainty about the future, which may lead to firms’ and households’ delaying purchases and investments. Changes in oil prices also lead to reallocations of labor and capital between energy intensive sectors of the economy and those that are not energy-intensive. For these reasons and others, oil price increases may lead to significant slowdowns in economic growth...

With the release of the latest unemployment numbers, most observers are convinced that the United States is now in recession following the dramatic GDP growth slowdown (0.6%) in the 4th quarter of 2007. Most attribute the apparent recession to the credit crisis resulting from the collapse of the Housing Bubble. (See A Recipe For Disaster, ASPO-USA, March 26, 2008.)

What about the role of the oil price in the economic slowdown? For economists, this remains an open, and perhaps unanswerable, question. Macroeconomic models can not explain the complex, non-linear historical relationship between oil prices and GDP, especially over the last 6 or 7 years, although researchers like the University of Michigan's Lutz Killian are trying to explain why Not All Oil Price Shocks Are Alike.

The big open question concerns the lack of a recession—up to now?—despite rising oil prices since 2002 (graph left from the BEA). It's worth noting that average GDP growth in the last 6 quarters is 2.18%, whereas growth in the 6 quarters previous to that period was 3.13%.

All this should be considered in light of the fact that what you don't know is often more important than what you do know.

No Oil Price Relief For Consumers

Current evidence² points to a downturn in both U.S. GDP growth and oil consumption which has not been accompanied by a decrease in the oil price. This is the worst of all possible worlds for American consumers.

The EIA data now indicates that U.S. oil demand fell off 3.7% between December, 2007 and January, 2008. That's a huge drop off, far larger than the usual seasonal pattern (last year's decrease was 1.2%). The 4-week period ending March 28th shows a more modest 1.3% decrease compared to the previous year. Other preliminary data for the 1st quarter of 2008 suggests that "U.S oil consumption has declined in the first quarter by nearly 475,000 barrels a day as compared to last year" according to the Associated Press report Drop in US first-quarter oil use appears most since Sept. 11 terror attacks—

Jan Stuart, economist at UBS Securities LLC in New York, said "Macro [economist] folks won't officially label the U.S. economic environment a recession for some time, but at first glance (first-quarter) oil data sure look bearish," in a report Thursday.

Preliminary data for February and March, subject to revision, show that pressures from record-high crude oil and products prices and the uneasy U.S. economy have continued to cut deeply into demand. [emphasis added]

This last statement in the AP story begs for explanation. How can U.S. demand be down nearly ½-a-million barrels a day in the 1st quarter while oil prices continue to rise? (This story is about oil market fundamentals, I will not be discussing dollar value or trading effects on the price.) The monthly average oil price series from economagic for NYMEX WTI shows a 10.7% jump to $105.56 in March over February. The price at this moment is $107.80, up this week on news that OPEC will not be raising production again—no surprise there!

The standard explanation for rising prices over the last several years is the global demand shock brought about by soaring consumption levels in the developing economies, including both the oil exporters (e.g. Russia, Saudi Arabia) and the Asian economies (e.g. China, India). Since rising oil prices have occurred in a context of global GDP growth, including the United States, they have been seen as a sign of health, not a drag on economies. Dr. James Hamilton explained the situation back in 2005 in his Economic consequences of the high price of oil.

By contrast, global oil production has increased steadily during the current episode [in 2004].³ The run-up has been caused this time not by a shortage of supply but rather by booming world demand (see What's up with oil prices?). The strong world economic growth that produced this demand overall must be regarded as good economic news, not bad. And although we have again seen West Texas intermediate [WTI] nearly double from $28 in September 2003 to $54 today [in 2005], this time the increase required a year and a half rather than just three months.

Both the gradualness of the price move and the circumstances attending it have left consumers and firms substantially less nervous about the current economic situation than they were in August of 1990, with none of the postponing of spending decisions that characterizes most economic downturns. U.S. car and light truck sales are only down 1% for the first five months of 2005 compared with the first five months of 2004, hardly enough to bring the auto sector to its knees, let alone the rest of the economy with it.

None of the factors mitigating the effects of oil price increases that Hamilton cites in June, 2005 are true now in April, 2008. The average monthly oil price has gone up 42.3% over the past 9 months, an increase that can hardly be called gradual. This looks a lot like an "oil price shock."

Consumer confidence is dropping like a stone, the consumer spending growth rate (graph left) has taken a sharp downturn, and the anecdotal evidence reveals that consumers are postponing spending decisions, according to the Wall Street Journal's Personal Spending Up Mere 0.1%, But Inflation Pressures Are Muted (March 29, 2008). Hamilton recently commented on the continuing downturn in auto sales at his weblog Econbrowser. Consumer spending growth appears to have slowed after the post-hurricane oil price increases in the 3rd quarter of 2005.

It is clear that high oil prices during a recession can not be a a good thing. What is not clear is whether prices will stabilize at their current level for a while during the downturn or continue to rise. Now that the current situation is somewhat clear, let us turn to the question of macroeconomic effects of high oil prices.

Lost at Sea

It is hard to tease out how much of the current downturn is due to higher oil prices as opposed to the rest of the mess we face. For some time now, observers like A. Gary Shilling have predicted that consumer spending was about to crash after the housing collapse due to alarming trends in savings rates and debt service payments.

So it is difficult to argue now that the oil price has been the prime mover in the not-yet-official U.S. recession. We're cast adrift, lost at sea, on this crucial issue.

Past recessions have often been preceded by oil price shocks, however, and Hamilton states that "both theory and evidence [are] consistent with the interpretation that [the oil price/recession] effect results from the disruption of the pattern of spending by consumers and firms on items whose utilization is sensitive to energy prices and supplies." See Questioning Peak Oil Economic Assumptions for a discussion of the relationship between oil prices and recessions (ASPO-USA, November 28, 2007).

Based on Hamilton's work, Keith Sill (op. cit.) presents an accessible model of the effects on GDP growth of net oil price increases resulting from exogenous oil shocks. An oil price shock is exogenous when it originates outside the U.S. economy e.g. the price shock resulting from the supply disruption caused by the Iran-Iraq war in October, 1980. Such a shock is not a feedback from the needs of the growing economy itself, as Hamilton posited back in 2005 when he noted that oil price hikes had not caused a recession in the United States.

Net oil price increases (1st graph left) reflect price movements in a given period—the previous 36 months in Sill's example—which serve as a "good proxy" for exogenous changes in oil prices and have a "more stable relationship with real output (GDP) growth." The net oil price increase is zero if a given month's average price is lower than some prior month in the 3-year series. Otherwise, the net oil price increase is the percentage increase from the previous highest month's price.

Sill uses a statistical analysis (a regression) and an impulse response function to measure the "dynamic effect of an exogenous oil shock on real GDP growth." Here's the main result:

Figure 6 [2nd graph above left] shows that an increase in the net price of oil leads to a drop in real output growth that gradually increases over time until it reaches a maximum four quarters after the shock hits. After that, the growth rate of real output gradually recovers, so that after about three years, the effect of the oil shock has largely worn off and real output growth is back on its trend path (in the figure, the trend growth rate of real output has been removed). The impulse response function indicates that a 10 percent increase in the price of oil results in real output growth falling 0.55 percent at its maximum impact. This translates into about a 1.4 percent permanent reduction in the level of real output. Even a modest external increase in the net price of oil has a significant impact on real output, according to our analysis. [emphasis added]

To evaluate this result, let's look at net oil price increases over the last 2 and ½ years. Only positive (non-zero) results are shown. A quarterly net increase is the average of the months in that quarter.

Quarter	Net Oil Price Increase
2005 III	5.30%
2006 II	2.70%
2006 III	1.63%
2007 III	2.46%
2007 IV	5.83%
9/07 - 11/07	8.33%
2008 I	3.83%

Discussion: There haven't been any oil price shocks exceeding 10%. Rather, we've had a series of mini-shocks. The three-month period 9/07-11/07 does not fall within a single quarter, but shows the largest increase (8.33%) occurred last fall. That's a hefty new oil price rise.

The standard view (e.g. Hamilton, 2005, op. cit.) is that increases since 2002 had little effect—compare with the real GDP numbers in the BEA graph—because the oil price was riding atop the economic growth wave. The GDP numbers bear this out until quarter IV of 2005. GDP growth is erratic and down on average thereafter, but this is coincident with the collapse of the Housing Bubble (graph left). No oil price signal is detectable.

What about net oil price increases that have occurred in the last 6-7 months? If Sill's model has any validity in 2008, the 9/07-11/07 price shock (8.33%) would have effects on real GDP 4 quarters or so after the increase. This drag effect on real output would occur in the latter part of this year just when the economy will be trying to emerge from the current supposed recession according the standard view.

For the recent price hikes to count as a real "oil price shock" for economists, the event would have to be exogenous to the U.S. economy. At first glance, this appears to be the case in so far as U.S. GDP growth has slowed considerably during the recent period and oil consumption is down (see the EIA numbers above.) This view may be correct, but is complicated by the price effects on oil consumption and any positive feedbacks to the U.S. economy following from increased oil consumption elsewhere—these feedbacks come primarily China and other Asian economies who trade with the U.S.

The bottom line is that we still do not know what effects all these ever-more painful oil price increases are having on the U.S. economy. We are still lost at sea.

To sum up, we have beat this horse to death without coming to any firm conclusion. It seems obvious that Americans can not absorb these net oil price increases over and over again, especially in a slumping economy, without incurring some very substantial losses sooner or later. Peak oil remains primarily a price phenomenon for now, but it's hard to sort out the effects because the messed up U.S. economy has multiple failures. The effects of oil price escalation on real U.S. GDP growth will be revealed over time, and it is hard to avoid the conclusion that the eventual outcome will not be salutary for American consumers.

Contact the author at dave.aspo@gmail.com

Notes

1. Sill took the time to speak with me while I was preparing this column. My thanks to him.
2. I say "consumers" because that is the commonly accepted term. As far as I'm concerned, the downfall of our civilization began when American citizens were commonly labeled "consumers" in the 1970s.
3. Obviously, Hamilton wrote this in 2005 before he and the rest of us became aware that world oil production was entering a 3-year plateau (EIA data).

—

First Things First

Experience has shown, and a true philosophy will always show, that a vast, perhaps the larger portion of the truth arises from the seemingly irrelevant.
     —Edgar Allan Poe

On March 19th, 2008, the Air Force successfully completed another in a series of tests designed to switch their planes over to synthetic fuel blends made partly from a  Fisher-Tropsch (F-T) coal-to-liquids (CTL) process. In 2006 the Air Force successfully flew a B-52 using the new fuel mix. The latest demonstration involved a B-1B Lancer, which flew at supersonic speeds over Texas and New Mexico using a blend of F-T and JP-8 jet fuel.

"The goal is to have every aircraft [certified for] synthetic fuel blends by 2011," said Maj. Don Rhymer, assigned to the Air Force Alternative Fuels Certification Office. "By 2016 we hope at least 50 percent of this fuel will be produced domestically."

Will the Air Force's scheme be implemented? Coal-to-liquids conversion emits lots of carbon dioxide but produces a viable substitute for diesel and jet fuel made by refining crude oil. An epic battle is shaping up between those concerned about climate change and those seeking to lower their transportation fuel costs and enhance their energy security. But this the right battle to fight?

The Air Force Pushes For Coal-to-Liquids

Although the Air Force program is currently purchasing gas-to-liquids synfuel purchased overseas, they are pushing for a CTL facility to be built in Montana. While coal is plentiful in the American West, natural gas is far too precious in the North American market to be used as the input for F-T conversion. McClatchy's Air Force leads push to liquefied coal fuel  (March 30, 2008) tells the story—

With every $10 rise in the price of a barrel of oil costing the Air Force $600 million, the service is converting its entire 6,000-plane fleet to run on a synthetic fuel mixture. Tentative plans call for construction of a coal-to-liquid fuel plant at a Montana air base...

Air Force officials have been testing synthetic fuels based on coal or natural gas. They plan to certify the fleet of nearly 6,000 aircraft to fly on a 50-50 blend of synthetic fuel and traditional petroleum-based jet fuel by 2011.

Assistant Air Force Secretary Bill Anderson said the search for affordable, cleaner-burning alternative fuels was driven by economic and national-security concerns.

Let's state the obvious up front—the Air Force is surely "peak oil aware." Branches of the military and the intelligence services do scenarios planning. "The United States would be all but powerless to protect the American economy in the face of a catastrophic disruption of oil markets, high-level participants in [Oil Shockwave] concluded yesterday."

Even without a large oil shock like those of the 1970s, relentless price increases and the possibility of declining global liquids output leading to supply shortfalls in the U.S within the next decade has led the Air Force to the coal-to-liquids solution. If the Air Force thought we're going to be swimming in oil by 2016, their target implementation date, they would not be proposing using F-T to meet their jet fuel needs.

Many obstacles stand in the way of the Air Force's plan. The climate change lobby is not going to roll over on the issue, which creates a bad precedent and provides momentum for carbon-intensive F-T operations in the United States. "I think across the board there is going to be opposition from the environmental movement," said John Topping, the president of the Climate Institute in Washington. "I'd say it's going to be almost universal because of the climate concerns" (McClatchy). The Congress will probably have a Democrat majority after the fall elections. This likely means tough sledding for the Air Force.

As awareness of the climate problem grows in the United States, the economic squeeze brought on by higher oil prices brings pressure to implement supply-side solutions to alleviate soaring diesel fuel costs.

Diesel Fuel For Truckers?

On April 1st, truckers staged a slowdown to protest high diesel prices. Truckers Protest Fuel Costs tells the story (Associated Press).

Tons of freight idled across the country Tuesday as independent truckers pulled their rigs off the road while others slowed to a crawl on major highways in a loosely organized protest of high fuel prices.

Using CB radios and trucking Web sites, some truckers called for a strike Tuesday to protest the high cost of diesel fuel, hoping the action might pressure President Bush to stabilize prices by using the nation's oil reserves.

"The gas prices are too high," said Lamont Newberne, a trucker from Wilmington, N.C., who along with 200 drivers protested at a New Jersey Turnpike service area. "We don't make enough money to pay our bills and take care of our family." [emphasis added]

Last week's A Recipe For Disaster touched on the record-high prices for diesel fuel in the United States, which is now $4.025/gallon according to AAA's Daily Fuel Gage Report. The big rigs get only 5 or 6 miles to the gallon, so long-haul truckers' profit margins are now disappearing. Trucker Lamont Newberne told the AP that "a typical run carrying produce from Lakeland, Fla., to the Hunt's Point Market in The Bronx, N.Y., had cost $600 to $700 a year ago. It now runs him $1,000".

According to data compiled by the ATA and the Air Transport Association, the 2007 fuel bill for all U.S. passenger and cargo airlines was $41.2 billion, but the diesel tab for moving goods by truck was $112.6 billion (graph left). Trucking fuel consumption far surpasses use for air travel.

Clayton Boyce, a spokesman for the American Trucking Association (ATA), says his group "is pushing for a number of measures to keep the prices down or to otherwise help truckers, including allowing exploration of oil-rich areas of the U.S. that are now off limits...." It would take years and years to get any diesel fuel from the outer continental shelves, presuming there are commercial oil reserves out there. Where is the diesel supply going to come from? The Air Force's Anderson has it all figured out—

With the Air Force paving the way, Anderson said the private sector would follow — from commercial air fleets to long-haul trucking companies.

"Because of our size, we can move the market along," he said. "Whether it's (coal-based) diesel that goes into Wal-Mart trucks or jet fuel that goes into our fighters, all that will reduce our dependence on foreign oil, which is the endgame."

A beleaguered trucking industry will seize the opportunity initiated by the Air Force to push for coal-to-liquids. It won't matter politically that such production, like drilling on the outer continental shelves, is many years away, providing no tangible relief for truckers any time soon. It won't matter that the quantities of diesel produced will be fairly small, or that coal-to-liquids using an F-T process are exorbitantly expensive and present technological hurdles, despite the success of South Africa's SASOL, which operates the only CTL plant running anywhere in the world today.

Between A Rock and A Hard Place

A heavyweight bout is coming soon between the climate lobby, who are trying to reduce carbon dioxide emissions, and the transport industry, which wants cheaper liquid fuels. The latest issue of the Oil & Gas Journal contains a comprehensive special report GTL, CTL finding roles in global energy supply that sheds light on the conflict (by Iraj Isaac Rahmim, March 24, 2008). The coal-to-liquids data (chart left) buttresses the positions of both the climate and transportation antagonists. The data comes from a National Energy Technology Laboratory (NETL) study for the Air Force.

A 50,000 barrel-per-day CTL plant configured as NETL specified will produce 27,819 barrels of diesel and 22,173 barrels of naphtha, which is a principle component of jet fuels like the Jet-B used in the Air Force's certification tests. The F-T process also produces small amounts of lubes and waxes, which can be hyrdrocracked to make more diesel or naphtha. The naphtha itself "[can] be steam-cracked to syngas and recycled back to the F-T reactor to increase production of high quality diesel" according the Oil & Gas Journal report. These numbers will appeal to the transportation industry.

The NETL data also shows that the envisioned F-T plant will produce 32,481 tons of carbon dioxide running at full capacity every day, a ratio of 1.32 tons of CO2 to every ton of coal burned. Without carbon capture, compression and sequestration (CCS) technology, CTL is viewed as a disaster from the climate perspective. This CTL plant would emit 11.8 million tons of carbon dioxide operating at full capacity over a year's time.

Let's put this in perspective. Carbon dioxide emissions declined by 1.3 percent in 2006 to 5,877 million metric tons according to the EIA (Science Daily, May 24, 2007). The 50,000 barrel-per-day CTL plant would add 0.2% to the U.S. 2006 emissions. On the other side of the debate, the U.S. consumed an average of 5.818 million barrels of (kerosene-type) jet fuel and (middle) distillate fuel oil (mostly diesel) in the 4 weeks ending March 28th, 2008 according to the EIA's latest Weekly Petroleum Status Report. The CTL plant's output is 0.8% of this total.

A number of CTL projects are on the drawing board in the United States (chart left from the Oil & Gas Journal). Rentech and Peabody have formed a partnership to look into the feasibility of two 10-30 thousand barrel-per day projects, one in Montana and another somewhere in the Midwest. Only one of the projects listed is larger than the CTL specification used in the NETL study.

None of the projects are anywhere close to implementation because of several factors listed by Rahmim, including 1) uncertainty about future carbon policy and the CCS option and 2) unit CAPEX costs running between $70,000 and $100,000 per barrel of capacity.

First Things First

The coming battle between climate activists and those in the transportation industry is strangely discordant with peak oil concerns. We want to reduce carbon dioxide emissions, right? We want the transportation segment of the economy to function, right? The debate doesn't focus on the main issues. First, global middle distillate (diesel) production has been flat for some time now and is not expected to increase much, if at all, in the future. Second, expensive substitutes such as coal-to-liquids will not be available at scales that make much difference in any time frame we might care about to relieve the supply side of the equation. And there are insufficient railroads to replace long-haul trucking or air freight.

Looking out a decade from now, carbon emissions from diesel in the U.S. are likely to decrease because overall middle distillate consumption is likely to decrease due to price escalation and constrained world supply. Any carbon emissions coming from CTL are not going to replace what will be lost, which is a good thing from the climate perspective. It is a disaster if you want a functioning economy. We will require a functioning economy to fix all of our other problems, including anthropogenic climate change.

Here we are, seemingly between A Rock (climate) and A Hard Place (CTL substitutes for oil). But do these two diametrically opposed positions really form the horns of our dilemma? No. Peak oil is "the third eye" gateway to higher consciousness in this debate.

The peak oil issues will be at most a sideshow in the forthcoming debate about coal-to-liquids here in "the Saudi Arabia of Coal."  The Air Force clearly knows about peak oil, but does not frame the problem in those terms. It seems that only a few people are able to bend their minds around the idea—publicly— that we've got bigger fish to fry in the upcoming decade than either side in the debate is willing to admit. "I think the principle of 'first things first' does apply,’ said Al Gore, "and has to be followed if we are to have any chance of success." But he wasn't taking about peak oil.

Contact the author at dave.apso@gmail.com