DOE 2014 Wind vision a new era for wind power in the United States

DOE 2014 Wind vision a new era for wind power in the United States

Many potential sites with high quality wind energy resources have minimal or no access to electrical transmission facilities.

From the perspective of planning reserves, wind power’s aggregated capacity value in the Study Scenario was about 10–15% in 2050 (with lower marginal capacity value), thereby reducing the ability of wind compared to other generators to contribute to increases in peak planning reserve requirements. In addition, the uncertainty introduced by wind in the Study Scenario increased the level of operating reserves that must be maintained by the system.

Transmission constraints result in average curtailment of 2–3% of wind generation,

With wind penetration increasing to the levels envisioned under the Study Scenario, the fossil fleet’s role to provide energy declines while its role to provide reserves increases.

At the end of 2013, out of a global 318 GW wind power capacity,  offshore wind was 2.2% (7 GW), mainly in Europe, with a small amount installed  in Asia.

Wind power is capital intensive, which makes costs for wind highly sensitive to the cost of capital. In the United States, the weighted average cost of capital available to wind project sponsors is artificially inflated by the fact that federal incentives for wind power development are delivered through the tax code.

Figure 2-8. Components of installed capital cost for a land-based, utility-scale reference wind turbine. Source: Tegen, al. 2013. Cost of Wind Energy Review. National Renewable Energy Laboratory

Figure 2-8. Components of installed capital cost for a land-based, utility-scale reference wind turbine. Source: Tegen, al. 2013. Cost of Wind Energy Review. National Renewable Energy Laboratory











Operations and Maintenance (O&M) Costs

Market data on actual project-level O&M costs are not widely available. [My translation of what that means? This is why it’s hard to know the real EROI and cost of wind projects, since these are kept secret so that wind subsidies and investment money can be found].

O&M costs are an important component of the overall cost of wind power and can vary substantially among projects. Anecdotal evidence and analysis suggest that unscheduled maintenance and premature component failure in particular challenge the wind power industry.  O&M costs generally increase as projects age.

a recent report found U.S. wind O&M costs comprise scheduled maintenance (20.5%), unscheduled maintenance (47.7%), and balance of system (31.9%).

O&M is around 25% of lifetime turbine costs and levelized replacement costs are 30% of O&M.

Low Natural Gas prices  have pushed demand for wind power down

The increase in natural gas reserves enabled by advances in horizontal drilling and hydraulic fracturing has been among the more important energy supply-side developments impacting wind power. In response to this new supply (along with tepid demand from a sluggish economy), natural gas prices have fallen dramatically from their peak in mid-2008, prompting a considerable amount of fuel-switching in the power sector. The share of natural gas-fired generation in the U.S. power mix increased from 21% in 2008 to 27% in 2013, while coal-fired generation declined from 48% to 37% over this same period. Though coal prices have remained relatively steady, these developments with natural gas have pushed wholesale power prices down from the highs seen in 2008, resulting in increased competitive pressures for wind power.

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Mined Oil sands EROI 5, in-situ 2.9, or 1 if refinement, transportation, & environmental costs included

Nuwer, R. Feb 19, 2013. Oil Sands Mining Uses Up Almost as Much Energy as It Produces. InsideClimate News.

EROI SURFACE MINED oil sands (20% of reserves)

EROI 5  according to J. David Hughes research released Tuesday.

EROI 5.5 to  6 (Brandt)

EROI in-situ Steam Injected oil sands (80% of reserves)

EROI 2.9 : 1 — In-situ Steam injected tar sands, which comprise 80% of tar sands. These are gotten from deeper below the earth than mined oil sands, with an EROI of just 2.9 : 1, or 1 unit of natural gas to create 2.9 units of oil.

EROI 3.5 to 4 (Brandt)

Or perhaps an EROI of only 1?

Hall, who wasn’t involved in Hughes’ study, thinks the EROI for oil sands would be 1:1 if the tar sands’ full life cycle—including transportation, refinement into higher quality products, end use efficiency and environmental costs—was taken into account.

Brandt’s figures may be too high because he doesn’t account for the energy to convert oil sands to synthetic fuels, the transport of pentanes and other diluents to thin the tar for pipeline transport to refineries, the energy to refine them, and deliver to customers.

Compared to the EROI of 25 for conventional oil, this is barely a viable operation.

EROI is about to go down even lower. Hughes based his calculations on the highest quality 25.6 billion barrels of Canadian tar sands oil that are currently under active development. The143 billion barrels of oil sands under Alberta’s boreal forests are low quality, and only 8% are accessible with surface mining.

“Those EROI numbers are going to go down as we move away from the highest quality to the lesser quality parts of the resource. I’d expect that downward shift to probably start about now.” Hughes said.

“They have to use a lot of natural gas to upgrade this heavy, sticky, gooky almost tar-like stuff to make it fluid enough to use,” said Charles Hall, a professor at the State University of New York’s College of Environmental Science and Forestry. Hydrogen from gas heats the tar sands so the viscous form of petroleum it contains, known as bitumen, can be liquefied and pumped out of the ground. That’s how gas helps turn tar sands “into something a bit closer to what we call oil.”

With most of the world’s highest quality resources already exhausted, companies are turning to formerly undesirable alternatives such as tar sands oil, which come with higher energetic price tags yet lower returns.

“We built our nation, economy and civilization on cheap energy—that’s where this incredible growth of the U.S. economy has come from,” said Hall, who coined the term EROI in 1979. “But that characteristic high energy return on investment fuel from much of the last century is no longer here.”

Hughes’ figures include the energy it takes to mine bitumen as well as to upgrade it to synthetic oil that can be put into a refinery. It also includes the liquefied natural gas used to turn it into dilbit (diluted bitumen) so it can flow through pipelines.

Both Hughes and Hall think the new data should be factored into the debate over Canada’s tar sands reserves, which cover an area about the size of Florida.

What isn’t often mentioned, Hughes said, is the energy required to extract the oil, or the rate at which it can feasibly be recovered.

“Unless we talk about all 3 metrics—size of the resource, net energy and rate of supply—we’re not getting the full story,” he said.

If you accept the fact that fossil fuels are finite—and I think most people would—then using a lot more fossil fuels for recovering energy as opposed to doing actual work basically uses them up quicker with no net payback in terms of useful work,” Hughes said. “It’s an issue of diminishing returns.”

Canada is touted as having the third largest oil reserves in the world. But its supply of conventional oil is shrinking, and oil sands extraction has been growing fast in the past decade, from about 700,000 barrels per day in 2000 to 1.7 million today.

While no rigorous studies have been conducted on the association between diminishing EROI values and increased greenhouse gas emissions, Hughes thinks “it’s a pretty safe assumption to make” that they are linked.

Those emissions are only going to increase as Canada ramps up to the 5 million barrels per day already approved for extraction, said Simon Dyer, policy director for the Pembina Institute, a Canadian non-profit focused on developing sustainable energy solutions.

Whether mining tar sands oil makes sense financially, depends on the world market price of oil—and on whether a company has already paid off its infrastructure costs or is building a new mine.

With the current price of synthetic crude oil sometimes dipping as low as $30 per barrel, a company that has paid off its infrastructure can still make a profit. For a company that’s still building, however, the market price would have to be about $100 per barrel in order to justify construction, Hughes said.

“Cost-wise, this is the most expensive oil being produced today,” Dyer said. “It’s a pretty clear indicator that our solution to energy needs is not chasing lower and lower quality fossil fuel resources that come with higher impacts.”

If oil sands oil eventually finds an easy outlet to the Gulf Coast—perhaps through the proposed Keystone XL pipeline project—the price for upgraded synthetic oil will likely rise to reflect the world market value, currently $110 per barrel.

Profitability aside, the development of Canada’s oil sands reserves will never offset declines in crude oil. At the world’s current rate of oil consumption—32.2 billion barrels per year—Canada’s tar sands oil reserves remain at a finite 168.6 billion barrels, enough to keep the world fueled for less than six years.

Brandt A.R., J. Englander and S. Bharadwaj (2013). The energy efficiency of oil sands extraction: Energy return ratios from 1970 to 2010. Energy.

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J. David Hughes: Oil Sands peak 2018 @ 3.6 Mb/d + photos 1984 & 2011

[This old post may turn out to be true if oil prices stay low, given how expensive it is to mine oil sands, transport them, refine them, and deliver to customers — some estimate an overall EROI of 3:1]

OIL SANDS GROWTH 1984-2011 A Visual Chronology – and Forecasts for the Future

by J. David Hughes, Global Sustainability Research Inc

Canada Peaks at 3.6 mbd in 2018 without major new oil sands developments

oil sands peaks 3.6 mbd 2018 without new dev

The Oil Sands Footprint from Space SO FAR

Oil sands July 23, 1984 .17 million barrels/day

Oil sands July 23, 1984 .17 million barrels/day


Oil sands May 15, 2011 1.59 million barrels/day (est)

Oil sands May 15, 2011 1.59 million barrels/day (est)



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New Threat to Oil sand Projects

Newfound Threat to Oilsand Projects

Researchers discover ancient salt formation key factor in Alberta steam fracking disasters.

By Andrew Nikiforuk, 28 Jul 2014,

Also See: Next Oil sands Threat: Cracking Caprock

A new study suggests that naturally occurring upward flow of groundwater in the oilsands region is creating fractures and weaknesses that may explain a series of catastrophic events for the controversial mining industry.  The findings were published in a PhD thesis last year and soon will appear in a paper for the American Association of Petroleum Geologists Bulletin.

These findings have significant implications for worker safety, groundwater protection, the security of massive industrial wastewater disposal in the region as well as the economics and placement of more than 100 steam plants and mines.

Recent eruptions of steam, bitumen and groundwater at oilsands operations may all represent an industrial collision with a natural process that drives salty groundwater into bitumen-bearing reservoirs where it fractures and weakens the rock near and above bitumen deposits.

These calamities cost the industry tens of millions of dollars. The disasters also required large-scale cleanup efforts or resulted in project abandonment.

Ancient groundwater channels can carve holes in cap rock (a shale/sandstone layer that purportedly seals bitumen formations from other rock layers). In addition this protective cap rock thins or erodes to nothing in many places in the tarsands.

In other words, no geological seal exists to prevent industry made fractures caused by high-pressurized steam injections or waste water injection from erupting to the surface.

Breaking the Cap Rock

Approximately 80 per cent of Alberta’s bitumen deposits lie deeper than 75 metres and cannot be mined. As a consequence, these deep deposits, all capped by rock, are currently being heated to as high as 300 degrees Celsius with highly pressurized steam.

Given that there are more than 100 steam plant facilities poking thousands of holes into irregular layers of bitumen, there is “a need to improve the collective capabilities of operators, service providers and regulatory bodies in the area of caprock integrity management,” noted the event’s organizers.

Industry uses either a steaming tool called steam-assisted gravity drainage or cyclic steam stimulation to melt a resource as hard as a hockey puck.

The overlaying caprock acts as a primary but not always impermeable seal that keeps steamed bitumen from seeping into aquifers, neighbouring industry wellbores and other geological formations, as well as the forest floor and lakes.

In general, industry tries to keep the pressure significantly low enough to ensure the caprock does not break — but high enough to push the melted bitumen out.

It is a very fine line. In 2006, French multinational company Total blew a 300-metre crater in the forest while trying to steam up a shallow formation of bitumen.

Although regulatory reports on the event weren’t published until four years later, the “catastrophic event” put caprock integrity on the agenda and forced Total to abandon its project.

Ever since then, all steam-based bitumen operations, the industry’s most energy-intensive facilities, report yearly on caprock integrity. The Society of Petroleum Engineers devoted a sold-out workshop on the subject last spring in Banff.

Half of all bitumen now produced from the oilsands relies on a form of oil production that injects highly pressurized steam into deep deposits of cold bitumen.

Harvard researcher and University of Calgary graduate Benjamin Cowie traces four significant and costly events in the tarsands to a newly identified geohazard: the erosion of salt formations underneath bitumen deposits by the movement of groundwater.

Echos of fracking

Recent studies by petroleum scientists as well as annual industry progress reports to the Alberta Energy Regulator show that the technologies used to steam deep bitumen deposits have created the same sort of problems now plaguing the hydraulic fracturing of unconventional oil and gas resources across North America.

Both technologies inject highly-pressurized fluids into formations where the resulting pressure can crack or fracture overlying rock and well casings in unpredictable ways. These fractures can bring fluids or gases to the surface, contaminate groundwater or connect with other existing wells.

The end result for both technologies are the same: hydrocarbons go where regulators don’t want them or industry can’t control them.

Alberta regulators described the Total blow-out as a fracking issue in a 2011 presentation. “Given ongoing caprock integrity concerns associated with fracturing and hydro-fracking in the subsurface to initiate production, these findings will have relevance to other shallow thermal and non-thermal operations, including in-situ bitumen/extra-heavy oil operations, and production of other emerging unconventional commodities such as tight oil and shale gas.”

The problem seems most pronounced at cyclic steam operations such as those run by Canadian Natural Resources Ltd. and Imperial Oil, where steam is injected into the ground for weeks at a time from pads that typically contain as many as 20 wells. After a soaking period, melted bitumen is brought to the surface.

Cowie suspects that fractures and faults created by the new hazard have collided with industrial activity along the eastern fringes of bitumen mining in northeastern Alberta.

1. In 2009 bitumen seeped to surface at CNRL’s Primrose operation in Cold Lake. Four more seeps appeared in 2013 resulting in a $50-million cleanup operation. CNRL eventually excavated 82,508 tonnes of impacted earth and drained an entire lake. The fourth largest oil spill in Alberta history is still under investigation.

2. In 2010 Shell’s Muskeg River mine hit a gusher of sulfate-rich and salty groundwater connected to the Devonian while excavating a tailing pond. It took more than a year to contain a rupture that spurted 2,000 cubic metres of salt water an hour. It cost millions of dollars to plug the leak. Researchers say that “it is almost certain that more conduits exist throughout the oilsands region, and that this will not be the last incident of brine discharge in an oilsands system.”

3. In 2006 Total blasted a 75 by 125 metre surface crater in the boreal forest at its Joslyn Creek steam plant resulting in the abandonment of the project. The event rendered nearly 30 million barrels of bitumen unrecoverable. Alberta regulators, which didn’t report on the event for four years, later compared the Total blowout to an uncontrolled frack job in a 2011 presentation. “Given ongoing cap rock integrity concerns associated with fracturing and hydro-fracking in the subsurface to initiate production, these findings will have relevance to other shallow thermal and non-thermal operations, including in-situ bitumen/extra-heavy oil operations, and production of other emerging unconventional commodities such as tight oil and shale gas.”

4. In the 1980s Texaco created a geyser of bitumen and salt water outside of Fort McMurray. There is little literature on the blowout. But it may have connected to a Devonian aquifer too. —Andrew Nikiforuk

The events include the massive 12,000 barrel bitumen seepage to the surface by Canadian Natural Resources Ltd. (CNRL); a huge blowout at Total’s Joslyn steam plant project in 2006; and a large groundwater gusher at Shell’s Muskeg River mine.

That 2010 disaster turned a newly created dam for mining waste into a lake full of 7-billion litres worth of highly saline water.

Harvard researcher Benjamin Cowie, who recently presented his findings to industry, now argues that all of the events share one geological feature: they occurred along the edge of an ancient salt formation that runs in a northwest to southeast direction through the Athabasca and Cold Lake oilsands deposits.

Geologists call it the Prairie Evaporite and it is part of the Devonian formation that lies underneath the tarsand deposits.  But based on the chemistry of water samples collected by industry from the region, Cowie believes that ancient glacial water is not only eating away the rock but creating new weaknesses under these bitumen layers targeted by industry.

In some places the highly saline water has erupted into bitumen formations where industry has recorded the sudden appearance of sinkholes or seeps of highly saline water. Many of these naturally occurring seeps run directly into the Athabasca river.

In addition Cowie suspects that that aquifers with high salt content have dissolved and weakened the rock infrastructure beneath bitumen deposits and in some places created vertical fractures as the highly pressurized salty water rises toward the surface.

At this point industry-made fractures created by oilsands mining and steaming operations then collide with these up swells of water or connect to metre scale fractures created by the dissolution of salt by the groundwater movement.

“This is a big regional process and an entirely new environmental risk for the oilsands,” Cowie said in an exclusive Tyee interview.

Underground saltwater can destroy seal of cap rock

The Alberta Energy Regulator (AER), which is mapping the area to identify geological factors that may affect cap rock seals, now supports Cowie’s findings.

A 2013 paper presented to the American Rock Mechanics Association in San Francisco said that the regulator had identified “a complex sub-Cretaceous structure created by salt dissolution and collapse, which has implications for cap rock integrity and also for the disposal of produced and process water into Devonian strata.”

The paper also warned that ancient groundwater channels can carve holes in cap rock (a shale/sandstone layer that purportedly seals bitumen formations from other rock layers). In addition this protective cap rock thins or erodes to nothing in many places in the tarsands.

In other words, no geological seal exists to prevent industry made fractures caused by high-pressurized steam injections or waste water injection from erupting to the surface.

Earlier this year the AER abruptly suspended proposed shallow steam plant operations over a large area of the tarsands, worth billions of dollars, due to concerns about punching holes through the cap rock and polluting groundwater.

New clues to Cold Lake disaster

The regulator’s San Francisco presentation also revealed that large science gaps now exist on the issue. Stress regimes below 350 metres in the region are “not well understood and there is very little publicly available data.” Nor has groundwater been properly mapped or monitored in the region.

A June 2014 preliminary report by CNRL on its large bitumen seepage in Cold Lake also underscores how poorly industry understands the complexity of rock structures in the region.

The company’s first report on the causes of the headline-making event blames industry made rock fractures that allowed bitumen and steam to break through a shale barrier and then travel by natural fractures, faults or badly cemented wellbores to the surface.

Since 2009 CNRL Primrose East steam operation in Cold Lake has leaked thousands of barrels of bitumen and steam to the surface in as many as five identified distinct ground fractures contaminating both surface and groundwater.

However, the CNRL report does not mention the possibility that the erosion of a salt formation underlying its Primrose East field may also play a role in weakening local geology by inducing fractures and faults.

Nor does the CNRL’s report make any reference to the 2013 AER study or Cowie’s work.

But an independent technical panel, which reviewed CNRL’s causation work, flags the novel geological hazard as a major concern.

The panel noted, for example, that the geological weaknesses created by dissolving unique salt formations under the bitumen deposits in Primrose East “could influence shale integrity.”

Salt-related subsidence could also result in changes in rock stress and fractures that damage bitumen bearing zones, adds the technical report. “Clearly identifying these potential geologic hazards” is imperative, adds the report.

New factor in assessing risk

Some bitumen miners, however, have quietly recognized the new geohazard and have recently set up agreements to share data on what’s happening in the Devonian formation and how these events might compromise industrial activity.

One recent industry presentation, for example, noted that the dramatic erosion of salt deposits by glacial waters in the eastern portion of the Athabasca tarsands deposit “has created additional complexity” for steam plant operations.

Another 2014 presentation warned, “the presence of a highly transmissive aquifer in the ‘Intact’ Prairie Evaporite Formation will need to be considered as part of their risk analysis and, as needed, risk mitigation plans.”

Bernhard Mayer, a University of Calgary hydrologist who supervised Cowie’s PhD thesis, says the government and industry need to do a “more detailed investigation of the nature of these localized pathways between the McMurray formation and underlying Devonian units.”

They also need to study “the integrity of cap rocks overlying the bitumen-containing units and assess the cap rock integrity in view of the stress regime and the pressures associated with steaming operations.”

Cowie adds that there is little information about the complex geological phenomena.

“The extent of recent rock dissolution beneath the oilsands region is unknown and I think the absence of information poses a real risk to oilsands producers.”

By linking all these serious events to one mechanism Cowie hopes that regulators and industry “will pay more attention to it” and perform better regional mapping to study the risks.

During the catastrophic Joslyn steam blowout and the bursting of the previously unknown saline aquifer at Shell’s Muskeg mine, bitumen workers could have been seriously injured near the discharge sites, says Cowie.

The geohazard could also significantly affect economics by “requiring more detailed geological characterization to truly identify what’s happening with groundwater in these systems, or in the worst case, substantial and expensive cleanup efforts would be required if a leak does occur.”

David Schindler, a world famous water researcher and long-time critic of rapid bitumen development, called Cowie’s research clear and significant and urged provincial authorities to change how projects are approved and monitored.

“Once again, the scientific homework is done after the assignment is due. When will the Alberta government ever learn?”




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Global oil risks in the early 21st century, Energy Policy 2011

[This is a large excerpt from an excellent 18-page paper I think predicts how the future will unfold as well as a good overview of our predicament. Alice Friedemann]

Fantazzini, Dean; Höök, Mikael; Angelantoni, André. 2011. Global oil risks in the early 21st century. Energy Policy, Vol. 39, Issue 12: 7865-7873

The Deepwater Horizon incident demonstrated that most of the oil left is deep offshore or in other difficult to reach locations. Moreover, obtaining the oil remaining in currently producing reservoirs requires additional equipment and technology that comes at a higher price in both capital and energy. In this regard, the physical limitations on producing ever-increasing quantities of oil are highlighted as well as the possibility of the peak of production occurring this decade. The economics of oil supply and demand are also briefly discussed showing why the available supply is basically fixed in the short to medium term. Also, an alarm bell for economic recessions is shown to be when energy takes a disproportionate amount of total consumer expenditures. In this context, risk mitigation practices in government and business are called for. As for the former, early education of the citizenry of the risk of economic contraction is a prudent policy to minimize potential future social discord. As for the latter, all business operations should be examined with the aim of building in resilience and preparing for a scenario in which capital and energy are much more expensive than in the business-as-usual one.

An economy needs energy to produce goods and deliver services and the size of an economy is highly correlated with how much energy it uses (Brown et al., 2010a, Warr and Ayers, 2010). Oil has been a key element of the growing economy. Since 1845, oil production has increased from virtually nothing to approximately 86 million barrels per day (Mb/d) today (IEA, 2010), which has permitted living standards to increase around the world. In 2004 oil production growth stopped while energy hungry and growing countries like China and India continued increasing their demand. A global price spike was the result, which was closely followed by a price crash. Since 2004 world oil production has remained within 5% of its peak despite historically high prices (see Figure 1).

The combination of increasingly difficult-to-extract conventional oil combined with depleting super-giant and giant oil fields, some of which have been producing for 7 decades, has led the International Energy Agency (IEA) to declare in late 2010 that the peak of conventional oil production occurred in 2006 (IEA, 2010). Conventional crude oil makes up the largest share of all liquids commonly counted as “oil” and refers to reservoirs that primarily allow oil to be recovered as a free-flowing dark to light-colored liquid (Speight, 2007). The peak of conventional oil production is an important turning point for the world energy system because many difficult questions remain unanswered. For instance: how long will conventional oil production stay on its current production plateau? Can unconventional oil production make up for the decline of conventional oil? What are the consequences to the world economy when overall oil production declines, as it eventually must? What are the steps businesses and governments can take now to prepare? In this paper we pay particular attention to oil for several reasons. First, most alternative energy sources are not replacements for oil. Many of these alternatives (wind, solar, geothermal, etc.) produce electricity— not liquid fuel. Consequently the world transportation fleet is at high risk of suffering from oil price shocks and oil shortages as conventional oil production declines. Though substitute liquid fuel production, like coal-to-liquids, will increase over the next two or three decades, it is not clear that it can completely make up for the decline of oil production. Second, oil contributes the largest share to the total primary energy supply, approximately 34%. Changes to its price and availability will have worldwide impact especially because alternative sources currently contribute so little to the world energy system (IEA, 2010).

Oil is particularly important because of its unique role in the global energy system and the global economy. Oil supplies over 90% of the energy for world transportation (Sorrell et al., 2009). Its energy density and portability have allowed many other systems, from mineral extraction to deep-sea fishing (two sectors particularly dependent on diesel fuel but sectors by no means unique in their dependence on oil), to operate on a global scale. Oil is also the lynchpin of the remainder of the energy system. Without it, mining coal and uranium, drilling for natural gas and even manufacturing and distributing alternative energy systems like solar panels would be significantly more difficult and expensive. Thus, oil could be considered an “enabling” resource.

Oil enables us to obtain all the other resources required to run our modern civilization.

Peak oil is the result of a complex set of forces that includes geology, reservoir physics, economics, government policies and politics.

There are a number of physical depletion mechanisms that affect oil production (Satter et al., 2008). Depletion-driven decline occurs during the primary recovery phase when decreasing reservoir pressure leads to reduced flow rates. Investment in water injection, the secondary recovery phase, can maintain or increase pressure but eventually increasingly more water and less oil is recovered over time (i.e. increasing water cut). Additional equipment and technology can be used to enhance oil recovery in the tertiary recovery phase but it comes at a higher price in terms of both invested capital and energy to maintain production.

The situation is similar to squeezing water out of a soaked sponge. It is easy at first but increasingly more effort is required for diminishing returns. At some point, it is no longer worth squeezing either the sponge or the oil basin and production is abandoned.

Another way to explain peaking oil production is in terms of predator-prey behavior, as Bardi and Lavacchi (2009) have done. Their idea is that, initially, the extraction of “easy oil” leads to increasing profit and investments in further extraction capacity. Gradually the easiest (and typically the largest) resources are depleted. Extraction costs in both energy and monetary terms rise as production moves to lower quality deposits. Eventually, investments cannot keep pace with these rising costs, declining production from mature fields cannot be overcome and total production begins to fall.

Hubbert (1982) wrote: There is a different and more fundamental cost that is independent of the monetary price. That is the energy cost of exploration and production. So long as oil is used as a source of energy, when the energy cost of recovering a barrel of oil becomes greater than the energy content of the oil, production will cease no matter what the monetary price may be.

Currently, around 60 countries have passed “peak oil” (Sorrell et al., 2009)— their point of maximum production. In most cases this is due to physical depletion of the available resources (e.g. USA, the UK, Norway, etc.) while in a few cases socioeconomic factors limit production (e.g. Iraq).

Attempts to disprove peak oil that focus solely on the amount of oil available in all its forms demonstrate a fundamental, and unfortunately common, confusion between how much oil remains versus how quickly it can be produced. Although until recently oil appears to be more economically available than ever before (Watkins, 2006), others have shown this to be an artifact of statistical reporting (Bentley et al., 2007). Further, it is far less important how much oil is left if demand is, for instance, 90 Mb/d but only 80 Mb/d can be produced. Still, the most realistic reserve estimates indicate a near-term resource-limited production peak (Meng and Bentley, 2008; Owen et al., 2010).

Total oil production is comprised of conventional oil, which is liquid crude that is easy and relatively cheap to pump, and unconventional oil, which is expensive and often difficult to produce. It is vital to understand that new oil is increasingly coming from unconventional sources like polar, deep water and tar sands. Almost all the oil left to us is in politically dangerous or remote regions, is trapped in challenging geology or is not even in liquid form.

Today, over 60% of the world production originates from a few hundred giant fields. The number of giant oil field discoveries peaked in the early 60s and has been dwindling since then (Höök et al., 2009). This is similar to picking strawberries in a field. We picked the biggest and best strawberries first (just like big oil fields they are easier to find) and left the small ones for later. Only 25 fields account for one quarter of global production and 100 fields account for half of production. Just 500 fields account for two-thirds of all the production (Sorrell et al., 2009).

As the IEA (2008) points out, it is far from certain that the oil industry will be able to muster the capital to tap enough of the remaining, low-return fields fast enough to make up for the decline in production from current fields.

Oil sources are not equally easy to exploit. It takes far less energy to pump oil from a reservoir still under natural pressure than to recover the bitumen from tar sands and convert it to synthetic crude. The energy obtained from an extraction process divided by the energy expended during the process is the Energy Return on Energy Invested (EROEI).

Since giant and super giant oil fields dominate current production, they are good indicators for the point of peak production (Robelius, 2007; Höök et al., 2009). There is now broad agreement among analysts that the decline in existing production is between 4-8% annually (Höök et al., 2009). In terms of capacity, this means that roughly a new North Sea (~5 Mb/d) has to come on stream every year just to keep the present output constant.

Peak oil is the point in time where production flows are unable to increase. It is not just underinvestment, political gamesmanship or remote locations that make oil production increasingly difficult. The physical depletion mechanisms (increasing water cut, falling reservoir pressure, etc.) will unavoidably affect production by imposing restrictions and even limitations on the future production of liquid crude oil. No amount of technology or capital can overcome this fact.

Some consequences of having extracted much of the easy oil are the following:

  1. It takes significantly more time once a field is discovered to start production. Maugeri (2010) estimates it now takes between 8 and 12 years for new projects to produce first oil. Difficult development conditions can delay the start of production considerably. In the case of Kashagan, the world’s largest oil discovery in 30 years, production has been delayed by almost ten years due to difficult environmental conditions.
  2. In mature regions, an increased drilling effort usually results in little increase in oil production because the largest fields were found and produced first (Höök and Aleklett, 2008; Höök et al., 2009).
  3. Because the cost of extracting the remaining oil is much higher than easy-to-extract OPEC or other conventional oil, if the market price remains lower than the marginal cost for long enough producers will cut production to avoid financial losses. See Figure 3.
  4. Uncertainty about future economic growth heightens concerns for executing these riskier projects. This delays or often cancels projects (Figure 4).
  5. Most remaining oil reserves are in the hands of governments. They tend to under-invest compared to private companies (Deutsche Bank, 2009).
  6. Possible scarcity rents have to be taken into account. Hotelling (1931) showed that in the case of a depletable resource, price should exceed marginal cost even if the oil market were perfectly competitive (the resulting difference is called scarcity rent).

If this were not the case, it would be more profitable to leave the oil in the ground, waiting to produce it until the price has risen. Hamilton (2009a, 2009b) noted that while in the 1990s the scarcity rent was negligible relative to costs of extraction, the strong demand growth from developing countries in the last decade together with limits to expanding production could in principle account for a sudden shift to a regime in which the scarcity rent is positive and quite important. In this regard, the Reuters news service reported on April 13, 2008 that Saudi Arabia’s King Abdullah said he had ordered some new oil discoveries left untapped to preserve oil wealth in the world’s top exporter for future generations, the official Saudi Press Agency (SPA) reported. Therefore, a possible intertemporal calculation considering scarcity rents may have already influenced (i.e. limited) current production. Although the sudden fall of prices at the end of 2008 is difficult to reconcile with scarcity rents, the following quick price recovery to the 70$-120$ range during the enduring global financial crisis indicates that this aspect cannot be dismissed. This is despite the assertion by Reynolds and Baek (2011) that the Hotelling principle “… is not a powerful determinant of nonrenewable resources prices,” and that “…the Hubbert curve and the theory surrounding the Hubbert curve is an important determinant of oil prices.” We agree that the Hubbert curve, which defines the depletion curve of a non-renewable resource, may be the prime determinant of oil price but it is not the only one.

Figure 3. Global marginal cost of production 2008. Source: LCM Research based on Booz Allen/IEA data (Morse, 2009).

Figure 3. Global marginal cost of production 2008. Source: LCM Research based on Booz Allen/IEA data (Morse, 2009).



After 2014, it appears that global oil production will begin its decline (See the second report of the UK Industry Taskforce on Peak Oil and Energy Security (UK ITPOES, 2010), Lloyd’s (2010), Deutsche Bank (2009, 2010), the report by the UK Energy Research Centre (Sorrell et al., 2009a) and the 2010 World Energy Outlook by the IEA (2010).)

Deutsche Bank (2009) asserts that for American consumers this point is when energy represents 7.5% of gross domestic product. This value is close to the one calculated by Hamilton (2009b) but is based on monthly data and uses a different methodology. In a more recent report, Deutsche Bank (2010) lowered this threshold to 6.5% because “…the last shock set in motion major behavioral and policy changes that will facilitate rapid behavioral changes when the next one comes and underemployment and weak wage growth has increased sensitivity to gasoline prices. Last time it took $4.50/gal gasoline to finally tip demand, this time it might only take $3.75/gal to $4.00/gal to do it.” However, they also highlighted that “Americans have become comfortable with paying more for gasoline, and it may take higher prices to force behavior change”.

Hamilton (2011) highlighted that 11 of the 12 U.S. Recessions since World War II were preceded by an increase in oil prices. Unfortunately, there is no clear alternative source of energy able to fully substitute for oil (see, for example, Maugeri (2010) for a recent nontechnical review of the limits of alternative sources of energy with respect to oil). It possesses a combination of energy density, portability and historically very high EROEI that is difficult for alternatives to match. 4. A timely energy system transformation not assured. As oil production declines, significant changes to the currently oil-dependent economy in the medium term are likely to be needed. However, it isn’t clear that there will the financial means to implement such a change. For example, Deutsche Bank (2009, 2010) suggested that the widespread use of electric cars in the second part of this decade will be the disruptive technology that will finally destroy oil demand. Apart from technology and resource constraints (lithium necessary for electrical batteries is quite abundant in nature but production is currently very limited), the availability of sufficient financial resources to transition the entire vehicle fleet seems dubious. As Hamilton (2009b) demonstrates, tightened credit follows high oil prices and most vehicles are purchased on credit. Others suggest that natural gas is the next energy paradigm. Again, will be there sufficient financial resources to switch to it as oil production declines? Reinhart and Rogoff (2009, 2010) found that historically, after a banking crisis, the government debt on average almost doubles (86% increase) to bail out the banks and to stimulate the economy. They also showed that a sovereign debt crisis usually follows, not surprisingly as we saw Iceland, Greece, Ireland, Hungary and Portugal turning to the EU/ECB and/or the IMF for financial help to refinance their public debts to avoid default. The need to switch to alternative energy sources with the enormous financial investments that such a task would require— and the simultaneous presence of large public and private debts — may well form a perfect storm.

Demography will also be extremely important in the next decade as well. Europe and the United States have aging populations and their baby boomers are entering pension age. China faces a similar demographic problem due to their one child policy, too.

The combination of declining oil production (and thus oil priced high enough to cause recessions), high taxes, austerity measures, more restrictive credit conditions and demographic shifts have the potential to severely constrain the financial resources needed to move the economy away from oil and to alternative energy sources. Another consequence of this combination of forces is the likely contraction of the world economy (Hamilton, 2009b; Dargay and Gately, 2010).

Businesses and governments struggle with alternating circumstances of insufficient cash flow to handle price spikes and plummeting prices that don’t cover their cost structure. Long term planning in this ever-changing environment becomes extremely difficult and investment — even highly needed investment — can drop precipitously.

Friedrichs (2010) also cautions that after peak oil countries have several sociological trajectories available to them: they can follow predatory militarism like Japan before WWII, totalitarian retrenchment like North Korea, or, ideally, socioeconomic adaptation like Cuba after the fall of the Soviet Union. Given the recent century of conflict and the extensive weapon stocks and militaries held by modern nations (especially the United States, which spends on its military almost as much as the remaining countries of the world combined (SIPRI, 2011), there is simply no guarantee that the relatively peaceful period currently experienced by developed nations that is conducive to rapid energy source transitions will continue much longer.

A further challenge is that, strictly speaking, for the last 150 years we have not transitioned from previous fuel sources to new ones — we have been adding them to the total supply. We are currently using all significant sources (coal, oil, gas and uranium) at high rates. Thus, it’s common but incorrect to say that we moved from coal to oil. In fact, we are using more coal now than we ever have (IEA, 2010). We never left the coal age. The challenge of moving to alternative energy sources while a particularly important source is declining, in this case oil, should not be underestimated.

Brown et al. (2010b) show how significant the squeeze of declining gross production and increasing producer country consumption can be, which they have named the Export Land Model. Increasing producer country consumption due to population growth acts as a strong magnification factor that removes oil very quickly from the export market. Using the top five exporting countries from 2005 (Saudi Arabia, Russia, Norway, Iran and United Arab Emirates), they construct a scenario in which combined production declines at a very slight 0.5% per year over a ten year period for a total of 5%. Internal oil consumption for these exporters continues to grow at its current rate (2010). In this scenario net oil exports decline by 9.6%, almost double the rate oil production declines.

This accelerated loss of exportable oil can be seen in many producer countries that have passed their peak. Indonesia has withdrawn from OPEC because they have no more exportable oil to offer the world market. Egypt is already incurring a public debt and is on the cusp of becoming a net oil importer, which will exacerbate already stretched public finances. As producer countries continue to grow their oil use even modestly and production declines (again, even modestly), there is an extremely high risk that net exportable oil will decline much faster than most observers are currently expecting.

Other mitigation efforts like increased solar, wind and geothermal production may not be prioritized since they do not help the situation — they produce electricity and the world’s 800 million transportation, food production (i.e. tractors and harvesters) and distribution vehicles require liquid fuel.

A contracting economy presents governments with a host of problems that are not easy to resolve. Promises made to the citizenry, some in the form of social welfare programs, pensions and public union contracts, will be impossible to keep as the energy base of the economy declines. Downward wage pressure and reduced business activity will lower tax revenue. With lower revenues and greater demands in the form of social welfare support by an increasingly poorer citizenry, it is difficult to see how the accumulated (and growing) government debt can be paid back without rampant inflation. Though it is still unclear whether the government response will be hyperinflation (to minimize the debts) or extensive and massive debt defaults (deflation) — or both — it is not likely that business as usual will continue as oil production declines.

Some governments may also have to contend with food and fuel riots as they did in 2007 and 2008. Other forms of crowd behavior, namely hoarding of fuel and food, may exacerbate the situation and governments should prepare accordingly.

Supply Chains

Manufacturers in particular will have to contend with increased difficulties making and delivering products as oil production declines (Hirsch et al., 2005). It will prove imperative that business addresses this Schumpetarian shock (a structural change to industry that can alter what is strategically relevant) in a timely fashion (Barney, 1991).  A significant benefit of cheap oil was that distance was relatively inexpensive. It is possible now to manufacture goods using far-flung operations. However, as oil declines, distance will, once again, become increasingly expensive, and oil price may begin to act as a trade barrier for many productsAnother risk as oil production declines is the possibility of oil supply disruptions. If this should occur, much modern manufacturing may be impacted. Just-in-time manufacturing systems in which warehoused parts are minimized through the frequent replenishment of parts by parts suppliers — sometimes with multiple deliveries a day— have little tolerance for delivery delays.  To prepare for this risk requires more than the drive for manufacturing efficiency that has generally characterized business. Supply chains should be examined with the aim of building in resilience and greater agility (Bunce and Gould, 1996; Krishnamurthy 2007), implying the loosening of tight and often brittle couplings between suppliers and manufacturers (Christopher 2000; Towill 2001, Mitch Leppo ). With little or no slack in the system (fewer warehoused parts, etc.), just one supplier failing to deliver a part or supplier hoarding can shut down a production process.


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Oil Shocks. Airplanes are energy gluttons. Shut down the airports. Refine crude for ships, trains, and trucks.

[As oil declines and the energy crisis worsens, airplanes ought to be the first to be denied fuel, since they are 600 times less energy efficient than large cargo ships, 120 times less efficient than trains and 15 times less efficient than trucks (kilojoules/tons per kilometer (at best) airplanes 30,000, Large cargo ships 50, Trains 250, Trucks 2,000. Sources: Smil, Vaclav. 2010. Prime Movers of Globalization. The History and Impact of Diesel Engines and Gas Turbines pp 160, 204, Ashby, M.F., 2015. Materials and sustainable development table A.14. Alice Friedemann]

Nygren, E., et al. 2009. Aviation fuel and future oil production scenarios. Energy Policy 37/10: 4003-4010

Jet fuel is extracted from the middle distillates fraction and competes with the production of diesel. Aviation fuel is almost exclusively extracted from the kerosene fraction of crude oil.

Today global oil production is roughly 81.5 million barrels per day (Mb/d), which is equivalent to an annual output of 3905.9 Mt.

Aviation fuels include both jet fuel for turbine engines and aviation gasoline for piston engines. The dominant fuel is jet fuel originating from crude oil as it is used in all large aircraft. Jet fuel is almost exclusively extracted from the kerosene fraction of crude oil, which distills between the gasoline fraction and the diesel fraction. The IEA estimated the world’s total refinery production in 2006 was 3861 million tonnes (Mt). The aviation fuel part was 6.3%, implying an annual aviation fuel production of 243 Mt (corresponding to about 5 Mb/d), including both jet fuel and aviation gasoline.

Figure 3 shows how the world’s refinery production is divided into different fractions.

Figure 3: Distribution of world refinery production in 2006. The total production was 3861 Mt. Source: International Energy Agency, 2008b. Key World Energy Statistics 2008 and previous editions, see also:

Figure 3: Distribution of world refinery production in 2006. The total production was
3861 Mt. Source: International Energy Agency, 2008b. Key World Energy Statistics 2008 and previous editions, see also:

If the refinery would like to increase jet fuel production, diesel production must decrease. During the year the proportion between diesel and jet fuel production changes and the fuel most profitable at that moment is produced.

Swedish Environmental class-1, ultra-low sulphur, diesel is a prioritized product, which has the consequence that no jet fuel at all is manufactured. The kerosene fraction is blended directly into the diesel fraction to provide the correct viscosity properties. Having fewer products is a way to increase the efficiency of the refinery.

The conclusion to be drawn is that aviation fuel production is not a fixed percentage of refinery output. In 2006, aviation fuel was 6.3% of world refinery production. The kerosene fraction is an average of 8-10% of the crude oil, but all kerosene does not become jet fuel or diesel. Kerosene can also be used to decrease the viscosity of the heavy fractions of crude oil and is used as lamp oil in certain parts of the world.

The environmental parameters that define the operating envelope for aviation fuels such as pressure, temperature and humidity vary dramatically both geographically and with altitude. Consequently, aviation fuel specifications have developed primarily on the basis of simulated performance tests rather than defined compositional requirements. Given the dependence on a single source of fuel on an aircraft and the flight safety implications, aviation fuels are subject to stringent testing and quality assurance procedures. The fuel is tested in a number of certified ways to be sure of obtaining the right properties following a specification of the international standards from, for example, IATA guidance material, ASTM specifications and UK defense standards (Air BP, 2000). Tests are done several times before the fuel is finally used in an airplane.

Today, the increasing addition of biofuels to diesel is a problem for the aviation industry. One of the more common biodiesels is FAME (Fatty Acid Methyl Esther). FAME is not a hydrocarbon and no non-hydrocarbons are allowed in jet fuel, except for approved additives as defined in the various international specifications such as DEF STAN 91-91 and ASTM D 1655. Consequently, biofuels-contaminated jet fuel cannot be utilized due to jet fuel standards. The problem with FAME is that it has the ability to be absorbed by metal surfaces. Diesel and jet fuel are often transported in a joint transport system making it possible for FAME stuck in tanks, pipelines and pumps to desorb to the jet fuel. The limit for contamination of jet fuel with FAME is 5 ppm. FAME can be picked up in any point of the supply chain, making 5 ppm a difficult limit and therefore the introduction of biofuels to the diesel fraction has had a negative impact upon jet fuel supply security.


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Peak soil, Peak Phosphate, Peak Fertilizer means Peak Food

Amundson, R., et al. May 7, 2015. Soil and human security in the 21st century. Science 348.

A group of leading soil scientists has summarized the precarious state of the world’s soil resources and the possible ramifications for human security in the journal Science.

This paper describs threats to soil productivity — and, in turn, food production — due to soil erosion, nutrient exhaustion, urbanization and climate change.

“Soil is our planet’s epidermis,” said Sparks, echoing the opening line of the article. “It’s only about a meter thick, on average, but it plays an absolutely crucial life-support role that we often take for granted.”

Sparks, who is the S. Hallock du Pont Chair in Soil and Environmental Chemistry in the Department of Plant and Soil Sciences at UD, has been chair of the National Academy of Sciences’ U.S. National Committee for Soil Sciences since 2013.

He and his five co-authors, who are also members of the national committee or leaders of soil science societies, wrote the paper to call attention to the need to better manage Earth’s soils during 2015, the International Year of Soils as declared by the United Nations General Assembly.

“Historically, humans have been disturbing the soil since the advent of agriculture approximately 10,000 years ago,” Sparks said. “We have now reached the point where about 40 percent of Earth’s terrestrial surface is used for agricultural purposes. Another large and rapidly expanding portion is urbanized. We’re already using the most productive land, and the remainder is likely to be much less useful in feeding our growing population.”

According to the Sparks and his colleagues, soil erosion greatly exceeds the rate of soil production in many agricultural areas. For example, in the central United States, long considered to be the “bread basket” of the nation, soil is currently eroding at a rate at least 10 times greater than the natural background rate of soil production.

The loss of soil to erosion leads to the loss of key nutrients for plant growth, requiring a need for commercial fertilizers. However, the current rate of fertilizer production is unsustainable. The evidence for this is in the recent spike in the price of fertilizers. The primary components of fertilizer are either very energy-intensive to produce or they are mined from limited supplies on Earth. It’s a classic supply-and-demand situation leading to large price increases that must eventually be passed on in the price of food.

The increase in fertilizer prices is not likely to be temporary. The largest reservoir of rock phosphate in the U.S. is expected to be depleted within 20 years, he says, at which point we will need to begin importing this source of the essential nutrient phosphorus.

“Unless we devise better ways to protect and recycle our soil nutrients and make sure that they are used by crops efficiently rather than being washed away, we are certainly headed for nutrient shortages,” Sparks said, adding that disruptions in food production could become a source of geopolitical conflict.

“Human civilizations have risen and fallen based on the state of their soils,” Sparks said. “Our future security really depends on our ability to take care of what’s beneath our feet.”

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Bloomberg News: Tesla’s new battery doesn’t work that well with solar

Randal, T.  May 6, 2015. Tesla’s new battery doesn’t work that well with solar. Bloomberg.

Even Elon Musk’s SolarCity, the biggest supplier in the U.S., isn’t ready to install Tesla’s home battery for daily users.

Tesla Chief Executive Elon Musk introduced a new family of batteries designed to stretch the solar-power revolution into its next phase. There’s just one problem: Tesla’s new battery doesn’t work well with rooftop solar—at least not yet. Even Solar City, the supplier led by Musk, isn’t ready to offer Tesla’s battery for daily use.

The new Tesla Powerwall home batteries come in two sizes—seven and 10 kilowatt hours (kWh)—but the differences extend beyond capacity to the chemistry of the batteries. The 7kWh version is made for daily use, while its larger counterpart is only intended to be used as occasional backup when the electricity goes out. The bigger Tesla battery isn’t designed to go through more than about 50 charging cycles a year, according to SolarCity spokesman Jonathan Bass.

Here’s where things get interesting. SolarCity, with Musk as its chairman, has decided not to install the 7kWh Powerwall that’s optimized for daily use. Bass said that battery “doesn’t really make financial sense” because of regulations that allow most U.S. solar customers to sell extra electricity back to the grid.

For customers of SolarCity, the biggest U.S. rooftop installer, the lack of a 7kWh option means that installing a Tesla battery to extend solar power after sunset won’t be possible. Want to use Tesla batteries to move completely off the grid? You’ll just to have to wait. “Our residential offering is battery backup,” Bass said in an e-mail.

Musk said in a quarterly earnings call on Tuesday said that demand for the batteries has been “crazy off the hook,” with 38,000 reservations for the Powerwall. While storing residential power with the Powerwall is still more expensive than grid power, he said, “that doesn’t mean people won’t buy it.” Demand for the new batteries, including those for businesses and utilities, has been so strong that the company may need to considerably expand its $5 billion battery factory that’s under construction in Nevada.

The Economic Case for Tesla’s New Battery Gets Worse

SolarCity is only offering the bigger Powerwall to customers buying new rooftop solar systems. Customers can prepay $5,000, everything included, to add a nine-year battery lease to their system or buy the Tesla battery outright outright for $7,140. The 10 kilowatt-hour backup battery is priced competitively, as far as batteries go, selling at half the price of some competing products.

But if its sole purpose is to provide backup power to a home, the juice it offers is but a sip. The model puts out just 2 kilowatts of continuous power, which could be pretty much maxed out by a single vacuum cleaner, hair drier, microwave oven or a clothes iron. The battery isn’t powerful enough to operate a pair of space heaters; an entire home facing a winter power outage would need much more. In sunnier climes, meanwhile, it provides just enough energy to run one or two small window A/C units. 

But SolarCity doesn’t offer a discount for multiple batteries. To provide the same 16 kilowatts of continuous power as this $3,700 Generac generator from Home Depot, a homeowner would need eight stacked Tesla batteries at a cost of $45,000 for a nine-year lease. “It’s a luxury good—really cool to have—but I don’t see an economic argument,” said Brian Warshay, an energy-smart-technologies analyst with Bloomberg New Energy Finance.

The Powerwall product that has captured the public’s imagination has a long way to go before it makes sense for most people. Even in Germany, where solar power is abundant and electricity prices are high, the economics of an average home with rooftop solar “are not significantly enhanced by including the Tesla battery,” according to an analysis by Bloomberg New Energy Finance.

That won’t stop homeowners from buying Tesla’s new batteries.  In the U.S., the product’s launch prompted a record day of inquiries from prospective new customers, according to SolarCity’s Bass. “There’s a tremendous amount of interest in backup power that’s odorless, not noisy and completely clean,” he said.

Tesla is probably making very little profit on the home batteries at this point and might even be selling them at a loss, according to research by BNEF. Both Tesla and SolarCity are just getting started, trying to get some traction before Tesla’s massive $5 billion battery factory begins production next year. That’s when the battery market really gets interesting.

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How much energy does it take to make a car? by David Fridley, LBL

David Fridley. August 25, 2009.  Embodied and operational energy of vehicles. 

I read an article today by Xiaoyu Yan titled Energy demand and greenhouse gas emissions during the production of a passenger car in China in journal Energy Conversion and Management, August 2009. It is a life-cycle assessment study of vehicles that summarized 9 additional studies, all published in peer-reviewed journals.

The findings are quite interesting, and show the impact both of a country’s fuel mix and efficiency level on the amount of energy used to build a vehicle and the proportion it accounts for life-cycle energy use.

For a typical American car of 1324 kg (2,919 lbs), the figures were (in MegaJoules):

Material Production 93,730 MJ

Car Assembly 25,240 MJ

Total 119,150 MJ

For a typical Chinese car of 765 kg (1,767 lbs) , the figures were:

Material Production 149,720 MJ

Car Assembly 17,430 MJ

Total 167,150 MJ

The higher material production figure for China is almost entirely due to the fact that its electricity system is 80% powered by coal, so in primary energy terms, each kWh of electricity used translates into more total primary energy than would be the case in the US.

As for operational energy, each gallon of gasoline contains 121 MJ, so the production energy in the US translates into 985 gallons of gasoline equivalent. If you assume the vehicle gets 28 mpg and is driven 10,000 miles a year, the car would consume more energy in operations than production in just 2.8 years. If the car is used for 10 years and driven the same amount each year, total consumption would reach 3570 gallons of gasoline. In this situation, the embodied energy of a car accounts for just 22% of the energy consumed by the car over its lifetime.

In the case of China, production energy translates into 1237 gallons of gasoline equivalent. The average mpg is 35, and the typical vehicle miles traveled per year is 9000 km, or 5590 miles. In this situation, it would take 7.7 years for the operational energy to exceed the energy used in manufacturing. Similarly, over a 10-year lifetime, the vehicle would consume nearly 1600 gallons of gasoline. As a result, the embodied energy of a Chinese car would account for 47% of the total energy consumed by the car over its lifetime.

This shows that it’s difficult to making blanket statements about the relationship between embodied energy and operational energy-it’s highly dependent on factors that can vary widely, but in all the studies reviewed, operational energy was the largest proportion of total energy use, which is pretty much a logical conclusion.

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2. Schafer A, Heywood JB, Weiss MA. Future fuel cell and internal combustion engine automobile technologies: a 25-year life cycle and fleet impact assessment. Energy 2006;31:2064- 87.

3. Hussain MM, Dincer I, Li X. A preliminary life cycle assessment of PEM fuel cell powered automobiles. Appl Therm Eng 2007;27:2294- 9.

4. Funazaki A, Taneda K, Tahara K, Inaba A. Automobile life cycle assessment issues at end-of-life and recycling. JSAE Rev 2003;24:381- 6.

5. Hakamada M, Furuta T, Chino Y, Chen Y, Kusuda H, Mabuchi M. Life cycle inventory study on magnesium alloy substitution in vehicles. Energy 2007;32:1352- 60.

6. Wagner U, Eckl R, Tzscheutschler P. Energetic life cycle assessment of fuel cell powertrain systems and alternative fuels in Germany. Energy 2006;31: 3062-75.

7. Eriksson E, Blinge M, Lovgren G. Life cycle assessment of the road transport sector. Sci Total Environ 1996;189/190: 69-76.

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Livestock diseases, Science Mag Review of “Arresting Contagion”

Science 17 April 2015: Vol. 348 no. 6232 p. 294 DOI: 10.1126/science.aaa7672

The fever on the farm

Arresting Contagion Science, Policy, and Conflicts over Animal Disease Control Alan L. Olmstead and Paul W. Rhode Harvard University Press, 2015. 477 pp.

The riots were in their 13th year. Two federal officials had recently been shot, and one of them had died from his injuries, but the local grand jury, drawn from an aggrieved and angry community, refused to indict the shooter. The year was 1922, and farming communities across the United States were vigorously resisting new regulations imposed by the Bureau of Animal Industry (BAI) that were intended to eradicate a parasitic infection known as Texas fever in domestic cattle.

Arresting Contagion is at once a biography (even a hagiography) of the BAI and a penetrating glimpse into the behavioral economics that defined early animal disease control efforts in the United States. The book begins in the late 19th century, a time of enormous innovation in agriculture and infrastructure. Animals were bred and killed on an unprecedented scale and transported over vast distances, both domestically and internationally. This created enormous opportunities for diseases—including Texas fever, contagious bovine pleuropneumonia (lung plague), bovine tuberculosis, pork measles, and hog cholera—to emerge and spread. The book focuses on how some of these devastating livestock diseases were progressively controlled—a story that is complete with setbacks and victories, heroes and villains.

From 1904 to 1915, James Dorsey, who falls firmly into the villain category, did a good trade in cheap cattle that had failed a tuberculin test, passing them off as healthy animals to unsuspecting farmers. This practice created at least 10,000 foci of tuberculosis among dairy herds across the United States and likely contributed to tens of thousands of cases of human tuberculosis (1). Compared to “TB James,” Typhoid Mary was an amateur.

A pleasant contrast to Dorsey can be found in Daniel E. Salmon, who became the first person to be awarded a veterinary degree in the United States in 1876 and was appointed the first chief of the BAI in 1884. Within eight years of his appointment, lung plague had been eradicated in the United States. Under his leadership, veterinary scientists showed medical researchers the way by demonstrating that insect vectors could transmit disease, developing the first killed vaccine, and identifying the human hookworm parasite. Salmonella bacteria, discovered by his research group in 1885, were named after him in 1900.

In their book, Olmstead and Rhode probe the motives that drive individuals to comply with, or reject, efforts to mitigate animal disease transmission. These motives are both fascinating and, more often than not, uncomfortably predictable. For example, many men who made money moving cattle refused to believe in contagions altogether. In the early 1880s, Chicago stockyard owners argued that their animals were in perfect health and that it would be financial suicide for them to sell unwholesome meat. Yet, inspections conducted in September 1886 revealed an industry plagued by filth and disease, a condition that persisted until federal legislation was established and regular, mandatory inspections were instituted. The authors make a strong case that disease is too important to leave to market forces and that the government has an essential role in controlling zoonotic disease.

In addition to regulation, the authors emphasize the need to incentivize farmers and merchants to comply with health and safety regulations. For example, in the 1920s, after their own cattle had been cleansed of Texas fever, farmers started to demand vociferously that disease control be mandated for still-infected cattle populations, which were now a major threat for disease reintroduction. Compensation for culled animals and the (limited) legal provisions that entitle farmers to recover damages from disease are also well addressed in the book.

Written by two economists, the book features a number of terms that may not be familiar to readers from health backgrounds, such as “externalities,” “rent-seeking,” and “public choice theory.” There are also occasional infelicities of phrasing: Cattle herds are ravished (rather than ravaged) by disease, and scientists attain notoriety (rather than fame) from their discoveries. Apart from these quibbles, the book is comprehensive, is well written, and contains a substantial amount of original research. This, along with extensive notes and references, will make it useful to those who are grappling with the recent resurgence in zoonotic diseases brought about by the rapid expansion of the livestock sector in developing countries and elsewhere.


  1. National Archives and Records Administration, Records of the Bureau of Animal Industry, Chief of the Bureau to Fitts, 9 July 1920.
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