The Visable Change in Asia’s Energy Consumption

As people are coming to understand, Asian economic growth over the past two decades—despite its great adoption of oil—essentially runs on electricity, most of which is supplied by the burning of coal. Here is the night sky over Asia twenty years ago, as captured in a still photograph from a film loop provided by NOAA’s national geophysical data center. (see: NOAA -Nightime Lights of China 1992-2010):


Recently, in the past three months, a consensus has begun to form that China’s use of coal may have just slipped past the fattest part of its growth curve. That may be true. But as you can seen on the 2010 photograph below, China is not the only “country” in Asia that has seen its demand for electricity advance strongly, since 1992:


It’s understandable for people to be encouraged by recent trends in global coal consumption, mostly in the United States. If China’s rate of coal consumption growth is also about to slow, that too is encouraging. The problem however, is that China would be slowing its rate of growth from a very, very high level of absolute demand. Further, as you gaze across other regions of southeast Asia in the above photos, global coal consumption is less about “country” and more about population. 1.2 billion people in the world are still unserved by electricity. A good portion of them live in India, for example, where you will notice the “advance of nighttime” lights has also been quite strong.

While there is certainly a possibility that Non-OECD countries will adopt more wind and solar—owing to the relative simplicity of those technologies—we need to be sober about current trends. The great trajectory of coal underway the past decade has a number of competitive advantages, especially the phenomenon known as path dependency. This is why I say the great news for clean energy, on a global scale, does eventually arrive. But, not until later in the century. Before then, the world unfortunately is transitioning even harder to fossil fuel energy, of the dirtiest kind.

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The Great California Energy Crash

California, which imports over 25% of its electricity from out of state, is in no position to lose half (!) of its entire nuclear power capacity. But that’s exactly what happened earlier this year, when the San Onofre plant in north San Diego County unexpectedly went offline. The loss only worsens the broad energy deficit that has made California the most dependent state in the country on expensive, out-of-state power.

Its two nuclear plants — San Onofre in the south and Diablo Canyon on the central coast — together have provided more than 15% of the electricity supply that California generates for itself, before imports. But now there is the prospect that San Onofre will never reopen.

Will California now find that it must import as much as 30% of its power?

The problem of California’s energy dependency has been decades in the making. And it’s not just its electrical power balance that presents an ongoing challenge. California’s oil production peaked in 1985. And despite ongoing gains in energy efficiency via admirably wise regulation, the state’s population and aggregate energy consumption has completely overrun supply.

Some will say, however, that California doesn’t need to concern itself with domestic energy production. As an innovation economy, in the manner of Japan or South Korea, many have said California can simply import greater and greater quantities of energy in exchange for its intellectual capital and the services and products it provides to the world. But the problem with such a notion is that it extrapolates the trend too far.

Only a century ago, California was an emerging giant of oil and gas production, building much of its wealth from natural resource extraction. It was inevitable that this would change over time. However, given the state’s high priced electricity, its wrongly devised transportation system (which is heavily exposed to oil prices), and its deep financial distress, the nation’s largest economy is having to exchange greater amounts of capital to keep itself running.

Indeed, the latest data shows that California energy production from all sources — oil and gas, nuclear, hydro, and renewables — has just hit new, 50-year lows:

California’s Great Energy Crash: State Energy Supply at Fifty-Year Lows

Since 1985 (the year that state oil production peaked above one million barrels a day), the state of California has seen its portfolio of energy production steadily decline, from an all- time high above 3,600 trillion BTU (British Thermal Units) to 2,500 trillion BTU (latest available data is through 2010). Because the contribution from both nuclear and renewables during that period has been either small or simply flat, the steady decay of California’s oil and natural gas production has sent the state’s energy production to 50-year lows.

However, during those five decades from 1960 to 2010, California’s population more than doubled, from nearly 16 million to nearly 38 million people.

Additionally, California built out its freeway system and expanded greatly into counties such as Riverside and San Bernardino. Indeed, in San Bernardino County, population quadrupled from 1960 to 2010, from five hundred thousand to over two million, with the attendant homes, public infrastructure, state highways, and freeways.

This great expansion of California’s residential and industrial topography was a tremendous value proposition back when energy, especially oil, was cheap. But now we are in a new pricing era for oil. Equally, California must also pay some of the highest electricity rates in the country. In counterpoint to the dreams of energy conservation, while California’s population merely doubled, its electricity demand rose nearly fivefold, from 57 million KWh in 1960 to 258 million KWh in 2010.

Essentially, California, like the rest of the country, has built a very expensive system of transport, which is now aging along with its powergrid.

Surely in the forty years that followed 1960, the prospect that California would have to import greater quantities of fossil fuels and electricity was no cause for alarm. However, the capital that is now required each year to maintain its aging highway system and purchase out-of-state oil and electricity, is mounting. While it’s true that California’s GDP is mighty and ranks as the 8th largest in the world, it’s also true that even smaller US states have seen their energy production not fall, but rather advance, in the era of higher-priced energy. Surprisingly, California’s total energy production is now lower than Pennsylvania’s, which is an intriguing contrast given that the Keystone State figures so prominently in the history of early oil and coal production.

Who will produce all the energy that California will need to buy in the future?

Golden State Hit by Nuclear Power’s Inherent Complexity

In the wake of the Fukushima disaster, a number of countries and communities are reassessing the risk and the cost of nuclear power. Overall, however, it is the aggregate complexity of nuclear power that is driving the global stagnation and now the decline of this particular source of energy.

The complexity of nuclear power — its enormous expense, its dependence on government financing, its long construction timeline, and its perceived and actual risk — means that bringing new plants online is ploddingly slow and aging plants are increasingly likely to see their licenses rejected for renewal. From a recent LA Times article, California energy officials plan for life without San Onofre:

California energy officials are beginning to plan for the possibility of a long-range future without the San Onofre nuclear power plant. The plant’s unexpected, nearly five-month outage has had officials scrambling to replace its power this summer and has become a wild card in already complicated discussions about the state’s energy future. That long-range planning process already involves dealing with the possible repercussions of climate change, a mandate to boost the state’s use of renewable sources to 33% of the energy supply by 2020 and another mandate to phase out a process known as once-through cooling, which uses ocean water to cool coastal power plants, that will probably take some other plants out of service. “Some of the weaknesses we have in the infrastructure [of Southern California] are laid bare by San Onofre,” said Steve Berberich, chief executive of the California Independent System Operator, the nonprofit that oversees most of the state’s energy grid… Before the current shutdown at the plant, officials had planned only for a scenario in which one of the reactors would be off line. No one had anticipated a complete shutdown. The plant’s 2,200 megawatts of power provide electricity to about 1.4 million homes, but the facility also provides voltage support to the transmission system that allows power to be imported from elsewhere to the region San Onofre serves, particularly San Diego.

San Onofre’s processing ability has been damaged by faulty computer modeling, which caused excessive and accelerated wear in its steam generator tubes. The cost and timeframe for a solution may be so great that the return on such an investment may not be worth it. But again, note the complexity involved here, which runs the spectrum from computer programming that guides the reactors’ operation to the critical role that this southern California power source plays in the grid. In powergrids, nuclear power plants play an infrastructural role but are also critically dependent on receiving power from elsewhere in the grid. As Japan discovered, its own power plant structurally survived the tsunami but failed when it lost external power.

In 2010, the year for which the latest data is available, California consumed 258,531 million KWh (kilowatt hours). 26% of that total was imported mostly from other US states (54,406 million KWh) and a small amount came from Mexico. California’s two nuclear plants provided 32,200 million KWh, about 12% of the total power that the state consumes from all sources.

Roughly speaking (because supply, demand, and capacity fluctuate from year to year), the loss of San Onofre will increase California’s potential dependency on out of state power by at least another 5%. This will indeed push out-of-state power dependency to 30%.

California’s Soaring Oil Dependency

California, like Texas, has been a giant in the history of US oil production. But after reaching a peak rate of production in 1985-86 at around 1.1 million barrels per day, California now produces half that amount, at 540 thousand barrels per day.

Just as in other post-peak producing regions of the world, such as Mexico and the North Sea, there is a constant flow of hope and theorizing that once again California could increase its oil production. While it’s true that opening offshore blocks to development could eventually stabilize and possibly raise the state’s aggregate production, it is highly unlikely that onshore production can now be moved higher. The reason is that best technology practices are already well-deployed in California’s onshore production — where old, original fields continue to produce, but at much lower rates.

More important is that California now has over 35 million registered vehicles, nearly matching its population. That makes California automobile rich but public-transit poor, as the state remains highly leveraged to gasoline.

Indeed, the post-war buildout of California followed the low-density, urban-sprawl model that was replicated throughout the nation after 1950. Accordingly, cities like Los Angeles are having to make a Herculean effort to resurrect a light rail system (built on the grid of its historic trolley network, once the largest in the world).

But 60 years of automobile-driven development will not be undone easily. The state is already spending a disproportionate amount of capital each year just to maintain the existing highway system (an issue we will explore in Part II of this article). And despite that ongoing investment, Californians drive on roads with some of the poorest conditions in the country.

Let’s take a look at the history of California’s oil production against its historical consumption of gasoline:

The spread between the quantity of oil produced in California and the quantity of gasoline consumed started to blow out in the mid 1980s, when gasoline consumption rose above oil production as measured in BTUs. Many believed this to be sustainable. But as the rest of the country would discover, a price revolution in oil would eventually hurt the economy very badly — and, consequently, oil consumption. In BTU terms, the difference between production of oil and consumption of gasoline reached its widest in 2006-2007, when annual consumption was running above 1,900 trillion BTUs and oil production at 1,250 trillion BTUs.

Now consumption, like production, is falling. Will consumption follow production downward, relentlessly?

The prospect that petrol consumption has peaked in California, along with the rest of the United States, is exciting if one is viewing such a transition through the lens of efficiency, sustainability, and post-industrialism. However, the dream of a non-industrial economy, like all good ideas, reaches a terminus when we consider that a majority of human services and products are still delivered and produced through physical processes. The State of California does not deliver state transportation, health care, education, police and fire protection, and public works digitally through the Internet. Instead, energy, delivered through tangible infrastructure, is required to run the Golden State.

In Part II: California: The Bellwether for the Rest of America, we take a look at the severely-pressured state budget of California, as well as other measurements of its economy indicating that the direction of its energy balance is entering dire territory. What exactly is the cost of California’s energy consumption? And what does it mean, as companies like Facebook build data centers outside the country to access external sources of electricity, that California cities such as Stockton declare bankruptcy?

There is no miracle solution for California. Even if we assume that the country continues to enjoy cheap natural gas prices, the cost of imported electricity from NG-fired power generation will not fall, because the cost of electricity transmission will continue to rise as the grid ages and requires new investment. Eventually the price level of higher energy and lower quality public services will also catch up even to higher wage employees, because a hollowing-out effect is going to pare down the number of service providers — teachers, merchants, construction workers, and even health care professionals and lawyers.

Such woes, however, are not unique in any way to California. They are shared by most US states right now; California is simply further down the timeline at this point. The key question here is what are the steps Californians (and the rest of us) should be taking?

Click here to access Part II of this report (free executive summary; paid enrollment required for full access).

Dear Readers: I’m currently writing a long-form post twice a month now for Chris Martenson’s excellent website, Peak Accordingly, I’ll be publishing the first (and free) part of these essays here at Enjoy. — Gregor

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The History of U.S Oil Production Rebounding

Excitement continues to run at very high levels, over the rebound in US crude oil production. Coming out of the new, historic low of 4.95 mbpd (million barrel per day) in 2008, the annual average of US production in the first 4 months of 2012 is currently on pace at 6.156 mbpd. This new production has largely been made possible by the price revolution in crude oil, which finally broke through the long-term, $25 ceiling during 2003-2004, and which is now mostly sustaining marginal production around the $90 level. A question: has the US, since its own production peaked near 10 mbpd in 1971, seen this kind of production rebound before? Let’s first take a look at the past decade. | see: US Average Annual Oil Production mbpd 2001 -2012.

If maintained, the current rebound would add back a little more than a million barrels a day to US production, compared to the 2008 low. Some analysts fervently believe that, despite ongoing declines from existing US fields, that production will go even higher into the end of this decade. Well, just leaving that issue aside for now, given that so much of this new production depends on sustained high prices, let’s briefly take a look at a previous rebound in US oil production. | see: US Average Annual Oil Production mbpd 1972 -1985.

Coming out of the 1976 low, at 8.136 mbpd, US production rebounded over the following 9 years by 800 kbpd–not quite a million barrels per day. However, a volume comparable to the current rebound. Afterwards, the 40 year decline in US production resumed its decline.

The course of US production into 2020 will be more dependent than usual on price. An increasing portion of total global production is crowded into the marginal price band of $80-$100 a barrel, and yet the world economy appears to struggle–on the demand side–at that very same level. Thus, new marginal production in the US and elsewhere is fated to continually pass back and forth, in and out of the domain of economic viability, as the world economy chokes, recovers, and chokes on high oil prices.


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Global Solar Buildout: Hockey Stick Growth

From a very small base, and from a tiny position in world energy supply, the buildout of global solar power is starting to go parabolic. Last year, according to the just released BP Statistical Review (you must access the Excel workbook for solar data), global solar generation nearly doubled to reach 55.7 TWh (terrawatt hours). | see: Global Solar Consumption in TWh (terrawatt hours) 2001-2011.

To put this power capacity in context, North America generated almost 100 times as much power in 2011 from all sources (coal, natural gas, hydro, nuclear, wind, solar), to reach 5204.5 TWh. By that measure, solar power capacity on a global basis can barely be detected, and is therefore a kind of joke, right? Uhm no, that would be wrong.

As world nuclear power goes into retreat, because of its enormous expense, catastrophe-risk, and complexity, it is power generated by solar that offers easy time-to-completion benefits and project clarity, especially in the developing world. (Indeed, nuclear power again lost primary energy share last year, according to the BP Statistical Review). Moreover, as the world is no longer able to fund economic growth with oil, owing to flat global supply, the industrial economy continues to migrate towards the electrical grid. While this certainly means that coal fired power generation will dominate for the next decade, it’s also the case that a more robust powergrid will become the receptacle for solar power.

While I am not ready to sign on to a Singularity’s version of solar buildout, the possibility that solar power reaches 10% of global power generation by the end of this decade should give you some idea of the new world made possible by plummeting solar voltaic prices, and, the array of other technological advances in capturing the diffuse energy of the sun. To accomplish this gain in primary energy share, solar will need to advance from last year’s 55.7 TWh to approximately 2200 TWh. That probably sounds impossible to most observers, but I would point out that at current growth rates, those levels could be achieved as early as the year 2018.

It is not a mistake that global solar capacity has begun a parabolic move. While many will conclude that demand is the main driver of this growth—and that is not incorrect—it is actually the increasing difficulty and complexity of other power generation construction which is now casting off advantages, to solar power. Do not underestimate the speed of solar.


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The 2012 BP Statistical Review: Coal Wins

The 2012 BP Statistical Review, covering 2011 world energy data, has been released. With global oil production roughly flat for a seventh year, coal once again gained global share of total primary energy consumption. World consumption of coal rose 5.4% in 2011, as oil consumption eked out a very small, 0.7% gain. As for other sources, nuclear use fell notably by -4.3%. And world natural gas consumption was restrained to a 2.2% advance, owing to a large retreat in European demand. Finally, while starting from a small position, both hydropower and renewables (biofuels, solar, wind) once again made very strong gains.

As a result, coal’s share of primary energy consumption has now risen above 30%, as coal continues its relentless attack on oil’s market share. Nuclear’s share falls below 5%, while natural gas and hydropower maintained their positions compared to 2010.

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The Correlation Between The American Home and Oil

If there’s one asset the world has little use for, it’s an American single family home priced above 250K, reachable only by car. The great, post-war buildout of America’s suburbs relied upon the continuance of a favorable arbitrage between rising wages, and low transportation costs. Now that this profitable scheme has come to an end, it should be no surprise that Robert Shiller remarked this week that housing “may not recover in our lifetime.” While some stabilization has been seen since the start of the US housing bust, Case-Shiller data showed this week that many cities hit new price lows. Interestingly, Robert Shiller is now himself noting the energy and transport cost pressure on US housing, and used the phrase “walkable cities.”

To illustrate how I see the future price path of homes in non-walkable cities, I made up the following graphic:

Walkable cities are very nice indeed, and I’ve been fortunate to live in several of them: Boston, New York, San Francisco and now my present city, Portland. But the majority of American homes, in order to capture any future increase in value, will need to benefit again from rising wages and flat to falling energy costs. At the current juncture, those are two trends unlikely to appear any time soon. Advantages will accrue, therefore, to US residential real estate near rail lines. Cities that wish to thrive will need to face up to these realities soon by halting all investment in roads and highways, diverting transport funding to rail and BRT (Bus Rapid Transit), and by extending these transport networks further into residential communities through walking and bike paths.


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The Middle East and Africa: Consuming A Bunch of Oil

Over the past decade, Asia’s transition to the leadership position in global oil consumption is well known. Starting in 2002, OECD countries slowed their consumption growth for oil and subsequent to 2005 actually saw their consumption decline. This process freed up limited oil supplies to Asia, which now accounts for 31% of total global oil use, as of the latest data. | see:  Regional Share of Total Global Oil Consumption (as of Q4 2011).

Less discussed is the emergence of new oil demand from the Middle East and especially Africa. While oil demand from younger populations in the Middle East is subsidized, and offers the prospect that future subsidy removals could slow demand, Africa’s capability to hit the world with new demand looks particularly intriguing. With roughly 1 billion people on the continent, the trajectory of future African demand could follow the same path of other emerging Asia with a ferocious insensitivity to price rises as new users come onstream, consuming only a little oil individually. Moreover, as you can see in the chart, African demand accounts for less than 4% of world demand, even though it contains over 14% of world population. In other words, in a world of flat supply, in which crude oil production has been trapped below 74 mbpd of production since 2005, Africa could easily add 2-3 mbpd of new demand over the next several years. If not more.

A small amount of petrol is a life-changer to a new user, adopting short-trip motorized transport for the first time. There are myriad reasons to watch Africa, and many who are involved in everything from agricultural development to mobile communications already do. But Africa as an emerging source of oil demand, the kind that could rapidly escalate and catch the world by surprise, is another reason to study this emerging continent closely.


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EIA Revises Two Decades of Oil Data

With the most recent release of international oil production data, EIA Washington has revised figures back to 1985. This is one of the most comprehensive revisions I have seen in several years. Generally, the totals were revised slightly lower, and this was especially true for the past decade. Data for the full year of 2011 has now completed. | see: Global Average Annual Crude Oil Production mbpd 2001 – 2011.

Since 2005, despite a phase transition in prices, global oil production has been trapped below a ceiling of 74 mbpd (million barrels per day). New production from new fields and new discoveries comes on line, but, it has not been at a rate fast enough to overcome declines from existing fields. Overall, global decline has been estimated at a minimum of 4% per year and as high as 6+% a year. Given that new oil resources are developed and flow at much slower rates, the existing declines present a formidable challenge to the task of increasing supply. I see no set of factors, in combination, that would take global production of crude oil higher in 2012, or next year, or thereafter.


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U.S Coal Exports @ 20 Year High

For the full year of 2011, the US exported 107,259 thousand short tons of coal. This was the highest level of coal exports since 1991. More impressive: exports recorded a more than 25% leap compared to the previous year, 2010. (see data here, opens to PDF).  Additionally, this was also a dramatic breakout in volume from the previous decade, which ranged from 40,000 – 80,000 thousand short tons per annum.  The below chart, from EIA Washington, does not capture the full year, though it certainly portrays the trend. Nota bene: this chart tracks the quarterly volumes of coal exports:

In an early 2010 post, Can the US Significantly Increase its Export of Coal?, I wondered whether a weaker US economy, partially kicked off oil, would have to source more of its energy from coal—thus putting a cap on any increase in coal exports. Or, whether the same economy, transitioning in part to more natural-gas-fired power generation, would possibly find a way to free up more coal for export. We may now have our answer.


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The Great BTU Race

The world’s major central banks — including the Bank of Japan (BOJ), the European Central Bank (ECB), and the Federal Reserve — appear to have finally won a major battle in the deflationary war that broke out five years ago in 2007. While the ultimate victor is yet to be determined, it now seems likely that a period of nominal growth could ensue for another two years, perhaps even longer.

This will not be high-quality growth. And little of the growth will be real.

Commodity prices will surely eat away at most, if not all, of any gains that may occur in global GDP. Additionally, while non-OECD growth actually has a chance of achieving some GDP gains in real terms, the prospects for the OECD are not as encouraging.

The Race for BTU Has Begun

It’s important to put yourself in the minds of OECD policy makers. They are largely managing a retirement class that is moving out of the workforce and looking to draw upon its savings — savings that are (mostly) in real estate, bonds, and equities. Given this demographic reality, growth in nominal terms is undoubtedly the new policy of the West.

While a ‘nominal GDP targeting’ approach has been officially rejected (so far), don’t believe it. Reflationary policy aimed at sustaining asset prices at high levels will continue to be the policy going forward.

While it’s unclear how long a post-credit bubble world can sustain such period of forced growth, what is perfectly clear is that oil is no longer available to fund such growth. For the seventh year since 2005, global oil production in 2011 failed to surpass 74 mbpd (million barrels per day) on an annual basis. But while the West is set to dote upon its retirement class for many years to come, the five billion people in the developing world are ready to undertake the next leg of their industrial growth. They are already using oil at the margin as their populations urbanize. But as the developing world comes on board as new users of petroleum, they still need growing resources of other energy to fund the new growth which now lies ahead of them.

This unchangeable fact sets the world on an inexorable path: a competitive race for BTU.

When Oil Can’t Take You There

It was not supposed to be this way.

Less than ten years ago, the universal assumption was that liquid BTU would ferry the world through its next phase of growth. The central thesis underpinning these forecasts, of course, was a belief in the large size of the world’s total resource base. Because this view was so widely shared by geologists, its soundness was not questioned. It’s critical to understand that within the industry itself, there was a nearly universal assumption that higher prices would make the next tranche of oil resources commercially economic — and easily so.

For example, when ExxonMobil declared in early 2004 that they could bury the market in oil should prices ever move above $40 a barrel, they believed that forecast very strongly.

Let’s consider that the role of the petroleum geologist in this regard, whose task is to locate and make recoverable these resources. It was not then, nor would it be now, a very appealing prospect for that professional to consider that the next set of resources might be so expensive to develop that many economies and regions might not be able to afford them. You can see such perspectives in books that appeared 4-5 years ago, such as The Myth of the Oil Crisis, which correctly identified the vast oil resources still to be extracted, but missed the slow rate at which these resources would be developed. Indeed, if there is a single concept that trips up experts and laymen alike, it is the changing rate at which many natural resources have started to come to market in the past decade.

And because of this, we’ve seen a number of forecasts for significantly higher oil production coming from the media and the financial sector during the past few years.

Last autumn, for example, I chronicled the flurry of exuberant calls for US oil independence and showed that a 2 mbpd decrease in US oil consumption had been completely marginalized in favor of a 0.5 mbpd increase in order to deliver a positive headline that the US was becoming less dependent on foreign oil because of increased supply. In Selling the Oil Illusion, American Style, I noted that such an uptick in US triumphalism was likely to accompany high oil and gasoline prices, as a way for the US to tell itself a reassuring story while the pressure increases on politicians and policy makers.

Indeed, Dan Yergin’s There Will Be Oil in last year’s Wall Street Journal was the start, I think, of a campaign to pressure the government to open more lands for drilling in the United States. Since then, high gasoline prices have been all the rage on every blog, talk show, public news radio station, and in the media at large. However, not since those naive days of 2004-2005, when oil first crossed the $40 mark, have I seen such an outlier supply call than the one that came through Citigroup in just the past few weeks.

The Latest Big Call: North America as Oil Giant

Ed Morse leads an energy research team at Citigroup and is well known for accurately calling oil’s price in 2008. But Citigroup’s recent call for a potential doubling of North America’s liquid petroleum production over the next ten years seems little more than a dream-wish.

Once again, we turn to the Wall Street Journal, which has now shown a definite habit for providing free space to those who call for North American energy abundance and independence. Speaking of Canada, the United States, and Mexico, Mr. Morse writes:

….theoretically total oil production from the three countries could rise by 11.2 million barrels per day by 2020, or to 26.6 million barrels per day from around 15.4 million per day at the end of 2011.


What Mr. Morse fails to mention in his op-ed is that the rate at which Canada, US, and Mexico would have to produce this new oil to meet his prediction would require new oil development and production at a rate of growth seen in the boom-days decades ago, a rate that is simply no longer possible.

Yes, the United States doubled its production of crude oil in 30 years between 1940 and 1970. Yes, from 1970 to 2000, Mexico nearly quadrupled its production of oil. Yes, Canada doubled production from 1980 to 2010. But let’s consider the time span of those periods: They were all 30-year timeframes, not 10-year timeframes.

More important is that for the US and Mexico, the peak of oil production is now in the past. The US peaked in the early 1970’s, and Mexico peaked in the last decade as its singular giant, Cantarell, entered decline. Only Canada has been able to inch up production, but there, too, lies an overlooked barrier: Again, the rate at which Alberta Tar Sands oil is developed and then produced is much slower than conventional oil.

Mr. Morse and the team at Citigroup have made the same mistake that was more prevalent a decade ago. They have mistaken the size of the resource base for the actual flows that are now economically, and geologically, possible.

Rate-Limiting Realities

Have you tired yet of the word rate?

Enrolled members of read my discussion of the two below charts earlier this year. The charts show two different forecasts, five years apart, of future oil production from Canada — much of which has depended on growth from the Alberta Tar Sands. However, I am using them again in the face of the Citigroup claims so that a wider audience can see how limited the rate of the growth can be, as we face the next set of oil resources.

Recall too that it’s not just Citigroup; many Americans and US politicians believe that Canada is a petro-giant who will easily be able to increase oil production quickly to feed future US demand.

Moreover, lest the implication go unnoticed, Ed Morse’s team did indeed (rather foolishly in my opinion) not only call for a potential doubling of liquid petroleum production by 2020, but went on to claim this would be enough supply to actually move the price of oil downwards, to $85 a barrel by that time:

Excess Canadian crude oil produced from oil sands is expanding at a rate of one million barrels a day every five years. The more that’s produced, the less of a market there will be for oil from Venezuela and some other OPEC member countries with similar-quality oil, requiring them to either curtail production or lower prices. Even if oil prices rise in the medium term, we expect 2020 prices to be no more than $85 per barrel, compared with today’s prevailing global price of $125.

It is quite incomprehensible that CITI could make such a call. I must be blunt: this is not serious forecasting, and there is no support in current trends — or those of the past 5-8 years — that would support such a price call.

Even CERA, Cambridge Energy Research Associates, has logged the explosion in the costs to bring on the marginal barrel of global supply, as has IEA Paris, and other energy teams such as Barclays.

Essentially, the CITI team is calling for a price of oil 8-10 years from now of $85 dollars a barrel, which is essentially the price already needed today to bring on a marginal barrel of supply.

From Africa to Brazil, and from Russia to Canada, there is precisely nothing in the trends of the past 10 years that indicates finding and exploration costs for new oil are either set to fall or even level out. Geology and the cost of energy itself preclude such a possibility.

But as I mentioned, it is not just economists who mistakenly project fast rates of development from the domain of stubborn, slow, physical reality of the world’s resources. The following two charts show the forecast of future production from CAPP–The Canadian Association of Petroleum Producers. The first chart is from 2006, and projects production through 2020:


Basically, in 2006 (which significantly raised the forecast from the year prior), the industry expected Canada to be producing 3.5 mbpd of oil by 2010; 3.75 mbpd by 2011; and 4 mbpd by 2012!

Now here is the second chart, from 2011, forecasting production out to 2025.


As we can see, 2010 saw only 2.7 mbpd of annual production.

More revealing is that back in 2006 (the first chart), the industry expected Canada to be approaching 4 mbpd of production by 2011-2012. However, the latest data shows that the 2011 annual average only reached 2.9 mbpd, with recent months hitting 3 mbpd. In other words, the industry itself, on a five year time-frame, missed its forecast by nearly a million barrels. That is not a small miss for country producing only 3 mbpd.

But given that this is the nature of new oil resources, we should only be surprised that analysts such as the team at Citigroup should have the bravado to call for future production growth at a rate totally unsupported by the nature of these resources.

The Race for Resources

What the team at Citigroup and other so-inclined geologists and economists are correct about, however, is that human economies will undoubtedly go after the next layer of fossil fuels — at least until the economics of such a quest beats us back towards some other set of alternatives.

So while North American oil production has virtually no chance to increase, as believed by the cornucopians, there is little doubt that in the quest to gain relief from permanently high oil prices, every possible BTU in North America will be accessed and utilized. More broadly, as the acceptance of the new era of high-priced oil finally (and I do mean finally) broadens out to the wider public, the scramble for solutions will also unfold.

What do I mean by permanently higher oil prices? Well, given that the cost of the marginal barrel has risen so much the past decade and that Asia continues to add to its demand in a relentless fashion, this price forecast from the U.S. Energy Information Administration (EIA) in Washington looks about right to me: (Annual Energy Outlook 2012):


The lower price path offered by EIA is now out of the question. Only a deflationary depression, sustained for more than several years, would allow for such low oil prices.

Because of geology, and because the non-OECD can afford even higher prices, the world faces a price path — with large oscillations — between the Reference case and the High Oil Price case.

Transitioning to Other BTUs

In Part II: Promising Investments as the Race for BTUs Heats Up, I lay out the latest global energy data showing how the world is already trying to transition away from oil and slamming the door shut on the prospect for any new net growth in global oil production and supply.

Are we closer than ever before to a tipping point, a regime change in which acceptance of high oil prices will broaden out in society? Four years of extraordinary, emergency provision of new credit by Central Banks should be sufficient to create a two-to-four-year mini-boom dominated by the world digging up fresh BTUs as the realization finally sets in that no more oil is forthcoming.

Finally, I identify 2-3 areas of investment that will play upon the coming scramble new energy resources.

Click here to read Part II of this report (free executive summary; enrollment required to access).

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The New Price of Oil

In the Spring of 2011, when Libyan oil production — over 1 million barrels a day (mpd) — was suddenly taken offline, the world received its first real-time test of the global pricing system for oil since the crash lows of 2009.

Oil prices, already at the $85 level for WTIC, bolted above $100, and eventually hit a high near $115 over the following two months.

More importantly, however, is that — save for a brief eight week period in the autumn — oil prices have stubbornly remained over the $85 pre-Libya level ever since. Even as the debt crisis in Europe has flared.

As usual, the mainstream view on the world’s ability to make up for the loss has been wrong. How could the removal of “only” 1.3% of total global production affect the oil price in any prolonged way?, was the universal view of “experts.”

Answering that question requires that we modernize, effectively, our understanding of how oil’s numerous price discovery mechanisms now operate. The past decade has seen a number of enormous shifts, not only in supply and demand, but in market perceptions about spare capacity. All these were very much at play last year.

And, they are at play right now as oil prices rise once again as the global economy tries to strengthen.

The Subordination of Cushing

Through the dominant force of its own demand, the US economy largely controlled the oil price for many decades. For years, it was common practice therefore to gauge world demand through the weekly updates to oil storage at Cushing, Oklahoma as well as total oil storage in the United States. If the US was demanding more oil from the global market, and thus either not adding to oil inventories or drawing them down, then a signal was given, pointing to future oil price strength.

But this dynamic began to break down coming into 2005-2007. That was the period when US oil demand — because of rising prices — began its current decline. Now that US oil demand is down over 12% from its mid-decade peak, the fluctuation of oil inventories in the US no longer drive prices.

The chart below shows that US inventories have been on an upward trend since 2005, and are now near decadal highs above 300 million barrels even though oil prices are back above $100:

What we’re now seeing is that US inventories and US demand are now subordinate to numerous other factors, ranging from emerging market demand, to market perception of spare capacity.

Lessons of Libya

A useful fact learned during last year’s Libyan civil war is that Saudi Arabia does not necessarily posses the 2-3 mbpd of spare capacity which most have assumed for years. Moreover, Saudi Arabia ceded the position of top world oil producer to Russia over 5 years ago in 2006. Indeed, Saudi Arabia made no production response to the loss of Libyan oil last spring. Producing near 9 mbpd, it was only by June that Saudi production was lifted by 600 thousand barrels a day (kbpd). That is a hefty production increase to be sure, but it raised questions as to how quickly spare capacity in the world can be brought online.

By the time Saudi Arabia had lifted production, the OECD countries led by the IEA in Paris had already decided to release oil from official inventories. But this, too, did little to calm oil prices — and as I pointed out last June, only created further problems. In The Dark Side of the OECD Oil Inventory Release, I explained that, by lowering OECD inventories, the market would correctly deduce that safety buffers had been reduced further. Combined with the Saudi increase in production, this only reduced spare capacity further.

The result was even stronger prices as WTIC ran back to $100 (until all global markets floundered on a flare-up in the EU financial crisis). Indeed, it is no longer US inventories of crude oil but the fluctuations in the emergency cushion of all inventories in the OECD (of which the US is part) that is now the more important factor in oil prices:


The loss of Libyan production caused a dramatic drawdown of OECD total oil stocks, which were already in a downward trend starting the previous summer in 2010. OECD inventories fell on both an absolute basis and on a comparative basis to the trailing 5 Year Average as the above chart shows. Taking these inventories from a high of 2800 mb to 2600 mb only 6 months later, combined with unrest across the entire Middle East, was more than enough support to boost WTIC oil prices from $85 to above $100 last spring. Additionally, as we can see in the chart, the decline in OECD oil inventories was maintained into the end of 2011.

These are important conditions to consider when trying to understand how oil prices now, in early 2012, are once again on the rise.

The Decline of Spare Production Capacity

The latest global production data shows that Saudi Arabia was producing 9.4 mbpd on average during 2011, an increase of 500 kbpd over 2010. To accomplish this, The Saudis had to increase production from 9 mbpd in 1H 2011 to 9.8 mbpd during 2H of 2011. But paradoxically, this production increase has only made the global oil market even tighter, as spare capacity shrinks further.

Let’s recall that nearly 60% of global oil supply comes from outside of OPEC from countries like the US, Canada, Brazil, Mexico, China, Australia, and the big producer—Russia. There is no spare capacity in this non-OPEC grouping and there hasn’t been for years. Sure, there is oil to be developed in non-OPEC countries; but that is not production capacity (meaning it is not supply that can be brought online quickly).

Moreover, Russia, the country that single-handedly saved non-OPEC production from going into steep decline, massively increased its contribution to world supply in 2002. But in the past two years, it has seen its production growth taper off and flatten, to just shy of 10 mbpd.

That leaves the oil market, tasked with the job of pricing, to figure out the ongoing mystery that is the “true” spare production capacity in OPEC. That it took 4-5 months for Saudi Arabia to increase production is a concern. Such delays should seriously give pause to those analysts who’ve regurgitated the belief over years that Saudi has 2-3 mbpd that can be brought on quickly.


Although EIA Washington currently judges OPEC spare capacity to be higher than during the lows of 2003-2008, it’s historic figures show that spare capacity has been declining since a 2009 high.

Moreover, the failure of non-OPEC production to increase within last decade counts as a true surprise to the global oil market. The faith in non-OPEC supply over the last decade helped to keep prices subdued, until that faith was shattered by 2007′s wild spike.

The problem now is that the oil market has been re-educated. Faith in the non-OPEC countries’ ability to increase supply is no more. Meanwhile, the great deceleration in Russian oil supply growth, has spooked the market. Combined, a market with 74 mbpd of production and a theoretical spare capacity of 3 mbpd simply creates too much uncertainty.

And consider this: the amount of total spare capacity is now equal to the 3 mbpd of demand that’s been taken offline in Europe, Japan, and the United States over the past 7 years, as oil prices have risen from $40 to the $100 level. Thus the oil market has quite correctly rationed supply, at higher prices. If prices were to fall to $50 or $60, the world’s lost demand could be rebuilt rather quickly.

Killing discretionary demand is now the proper function of the oil market in an age of flat supply growth.

Quantitative Easing and Granger Causality

We should also remember that the global economy would be mired in a textbook deflationary depression were it not for the continual and gargantuan US$ trillions that have been provided by central banks since 2008.

Early 2009 saw oil prices slip briefly below $40. But, of course, that’s the price level appropriate to a world during an industrial crash — with reduced shipping, halted economies, and dislocated consumer demand. The world can have those prices again, if it chooses. But it must also be willing to accept a global recession to achieve such low oil prices.

Thus, there is a misconception that currency debasement is the main driver of oil prices. However, given the new supply realities, that simply isn’t true any longer.

The chart below is helpful in explaining why. There is no question that coming out of 2000, the decline of the US Dollar as expressed by the USD Index was a true component of the rising oil price. During that period, as the USD was falling, global oil supply was still increasing. The descent of the US Dollar was unquestionably part of the repricing process, as the USD Index fell from a high of 120.00 in 2002 to 80.00 in 2005:


But see how the most ferocious part of oil’s price advance started to unfold after 2005, when, as the USD continued falling, the global supply of oil stopped growing.

If we think of this comprehensively, we have to conclude that the debasement of currencies is no longer the primary factor in the price of oil on a valuation basis. Rather, it is that quantitative easing prevents a deflationary industrial collapse, thus keeping the global economy alive and able to consume more energy.

We can therefore say that in our post-credit bubble collapse era, and with global oil supply now flat, that quantitative easing causes higher oil prices (through Granger causality). It keeps economies from collapsing (for now) and thus brings demand up against very tight supply. As we can see from the chart above, the USD Index has for 3 years now been bouncing off the bottom it first reached in 2008. In a way, this is helpful because it brings to light the new dominant factor in global oil prices: supply.

Supply is now Primary


Supply, and the recognition of supply, are now the dominant factor in the oil price. A point so obvious, it hardly seems worth making. However, the developed world is still largely operating on the classical economic view that higher prices will make new oil resources available.

That is true. But, it’s just not true in the way most anticipate.

While higher prices have brought on new supply, these resources have been slow to develop, are more difficult to extract, and generally flow at lower rates of production. As the older oil fields of the world decline, the price of oil must reflect the economics of this new tranche of oil resources. There are no vast, new supplies of oil that will come online in 2013, 2014, and 2015 at the scale to negate existing global declines.

During the entire time that global oil supply has been held at a ceiling of 74 mbpd, since 2005, a lot of new production in the Americas and Africa especially has come online. But it has not not enough to increase total world supply. And the price of oil has finally started to price in that new reality.

Here Comes Volatility in Oil Prices

The pricing dynamic discussed above is accentuated by the crisis cycle: the repetitive oscillation between acute and chronic phases of the ongoing debt crisis, mitigated by central bank reflationary policies.

In Part II: Get Ready for Oil Price Volatility to Kill the ‘Recovery’, we forecast how today’s protractly high recent oil prices are already sending a signal that a new hit to global demand is underway.

Generally, it appears that the oil price is making its move too early in the year — which will likely serve as a sucker punch to the fragile world economy — thus making spectacularly high prices before year end less likely, and a sharp market correction and return to economic recession more so.

Investors will be wise to take prudent precautions before this nasty wake-up call arrives.

Click here to access Part II of this report (free executive summary; enrollment required for full access).

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Accounting for America’s Energy and GDP

There are complexities associated with the calculation of US energy expenditures against its GDP. The above chart only records domestic consumption of energy. But you see, the United States is a country that does not bear the full cost of the externalities associated with its total consumption of goods. This leads most economists to an analytical error: they believe the US over the past two decades has been able to achieve higher levels of GDP with either reduced, or level, energy consumption. However, all US consumption and manufacturing that has been outsourced, primarily to Asia, is left unaccounted for–and that is not trivial. You may regard the coal-fired manufacturing of Asia, now required to produce our goods, as simply the offshored portion of our total BTU consumption. It was not just cheap labor that OECD countries have sourced in the developing countries. It was the cheaper BTU, primarily coal, burned with little regulation and little regard for the environment, that we in the West now exploit. And so you have to ask yourself a question: what if America was forced to produce GDP with the full and accurate accounting of our total energy consumption, repatriated from its “externality?” What would the calculation, in the above chart, show? Well, the answer is certainly not lower, than 9% of GDP.


Further Reading: Green Growth–An Oxymoron? , Institute for Integrated Economic Research – Kunz, Koppelaar, Raettig, Balogh

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The Future of Global Oil Production

Since 2005, European oil consumption has fallen by 1.5 million barrels a day. And, in the same period, US oil consumption has fallen by 2 million barrels a day. If oil was priced at $60 a barrel, rather than $100 a barrel, then a fair portion of that lost demand might return. Instead, since 2005, global crude oil production has been bumping up against a ceiling around 74 million barrels a day. Thus, the tremendous growth in oil demand which emanates from the developing world, in Asia primarily, has been supplied by the reduction of demand in Europe and the United States. Why doesn’t the world simply increase the production of oil to 77, or 78 million barrels a day? After all, that is precisely the history of global oil production: a continual increase in supply to capture the advantage of rising prices.

Today, in 2012, I observe that many analysts of global oil production—and the interaction between oil prices and the global economy—continue to engage in a guessing game about the future. But, frankly, the future has already arrived. And it is not a random future, but a future that was held to be improbable, if not impossible. For each extra barrel of oil produced over the past seven years from Russia, and Canada, there has been a loss of production from the North Sea, from Mexico, from Indonesia and elsewhere. And in the case of OPEC, there has been a stubborn flatlining of production growth, which, in the true spirit of argumentum ad ignorantium, has been taken as proof of OPEC’s hidden and secret supply. Thus, we are led to the newest and strangest meme of all: the failure of global oil production to grow over seven years, in the face of a phase transition in oil prices, is not even suggestive of peak oil. But rather, proof of oil’s imminent supply resurrection.


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Prices for A Million BTU by Source

The price differential for a million btu is blowing out once again, between Global oil and North American natural gas. The extraordinary discount has persisted for some years. But today, with West Texas Intermediate (WTIC) oil above $100 and Brent oil above $110, the spread has reached new highs. The energy content of natural gas is trading at an 83% discount to WTIC Oil, and at an 85% discount to Brent oil. An economist might be persuaded to say: “That is a gap that must eventually close. Or, at the very least, which gives North American energy markets a huge, competitive advantage to source cheap, domestic btu compared to the rest of the world.” I would not disagree. However, the infrastructure problems associated with energy transition do not make such switching from expensive oil to cheap natural gas an easy, or rapid, endeavor. I address these issues continually, but a post of mine from last year, Vexed By Natural Gas, might be worth a read for those who want to ponder the situation further.

As you study the chart below, consider for a moment a less well advertised price spread: the disparity between North American natural gas (which remains landlocked) and the price for landed LNG in the United Kingdom. As energy market observers already know, North American natural gas will—in the next couple of years—be released through LNG export terminals in British Columbia (Kitimat) and Louisiana (Sabine Pass). That will trigger a rather momentous price convergence globally, as world LNG prices adjust to the entry of North American volumes.

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