Can Energy Storage Make Wind and Solar Power As Reliable As Coal?

Wind and solar power generated 3.5% and about 0.1%, respectively, of US electricity last year.  These figures represent large increases from much smaller levels in the last decade as the cost of these technologies declined significantly, particularly for solar photovoltaic (PV) modules. However, other barriers to wider deployment remain, including their intermittent output.  Energy storage is often portrayed as the killer app for overcoming the intermittency of renewables, and a number of interesting developments have occurred on this front, including a new "hybrid" wind turbine with integrated storage from GE. To what extent could more and cheaper storage enable wind and solar to function as the equivalent of high-utilization, baseload generation? 

Assessing that potential requires, among other things, recognizing that energy storage is neither new nor monolithic. Nor is the intermittency of renewable energy a single challenge.  For example, the output of a wind turbine and the wind farm in which it operates varies on time scales of minutes, hours and days, as well as months and years.  The output of a PV installation varies somewhat more predictably, but no less dramatically. 

Generating companies and project developers have an array of new storage options, involving various battery technologies, flywheels, and compressed air. Pumped storage, in which water is pumped uphill and generates power later when it flows back downhill, is an old, though hardly obsolete option and already operates on a large scale. According to the National Hydropower Association the US has 22,000 MW of installed pumped storage. This, too, is expanding and remains one of the cheapest forms of power storage in terms of cost per megawatt-hour (MWh) delivered.   Enough new projects have received preliminary permits to more than triple that figure, in 23 states.

All of these storage alternatives have limitations or drawbacks.  Batteries and flywheels, while very responsive, are still expensive.  Compressed air storage often relies on unique local geological features, and some versions essentially function as a supercharger for a gas-fired turbine, resulting in some emissions. Pumped storage works well at a variety of scales but is less responsive than batteries, has a larger physical footprint, and requires suitable terrain. 

What makes GE's "brilliant turbine" with battery storage look clever is that, with the help of predictive models, it requires a very small amount of battery storage--perhaps as little as that in an electric car--to smooth the output of the turbine for 15 minutes to an hour. That provides significant benefits, including financial ones, in terms of integrating it predictably into the power grid. However, it doesn't transform the turbine into a fully dispatchable generator capable of sending power to the grid whenever demanded.  That would require storing much more energy per turbine and delivering it at rates sufficient to replace the entire output of the installation for at least several hours, along the lines of concentrated solar power installations with thermal storage.

Even these techniques don't get us to the point at which a dedicated wind farm or solar installation could replace a baseload coal-fired power plant of similar capacity running 80% of the time.  For starters, energy storage doesn't alter the total amount of energy collected from the wind or sun.  In an area with good onshore wind resources, generating the same energy as 100 MW of coal capacity would take around 267 MW of wind turbines, because the wind doesn't blow at optimum speed all the time, and other times it doesn't blow at all. The wind farm would also need enough storage to absorb any output over 100 MW, and then make up any shortfalls below 100 MW for the longest duration that would be expected.  The figures for a solar installation would be similar. It just doesn't sound very practical, unless storage became dirt cheap.

Fortunately for renewable energy developers, that isn't what grid operators expect of wind or solar.  In most situations the local grid takes their output whenever it's available, though not necessarily at the price that a generator capable of committing its capacity in advance or responding on demand would receive.  So there's a financial incentive for renewables to add a bit of storage to "firm up" some capacity, while bulk storage appears to be more desirable as a separate asset available to the grid, just like a "peaking" gas turbine, to support multiple renewable sources. Of course in that case there's no guarantee that the power stored would come from renewables.  It's likelier to come from whatever is the cheapest off-peak generation in that market.

So while it's easy to see how improved energy storage can enhance the economics of renewable energy and enable it to be integrated into the grid to a greater extent than otherwise, it's less obvious that even cheap, large-scale energy storage is a panacea for intermittent renewables like wind and solar.  It might even have greater benefits for low-emission but more reliable forms of generation, such as nuclear and geothermal, by allowing them routinely to shift a set portion of their output into more valuable segments of the regional power market. 

Disclosure: My portfolio includes investment in GE, which makes products mentioned above.

The 2013 Energy Trust Barometer: Mixed Readings

Yesterday's panel discussion in Washington, DC on "The Trust Factor" in energy couldn't have been more timely. The stakes for lost trust seemed especially apparent against the backdrop of an EU probe into allegations of price fixing in the spot oil market, involving some of the industry's largest players, and coverage of the IRS and Associated Press wiretapping scandals.  The session was hosted by The Energy Collective and communications firm Edelman, which presented the energy-related findings from its latest annual Trust Barometer.  The theme of this year's survey was a "Crisis of Leadership."

Edelman found a small improvement in the US public's trust for the energy industry, compared to last year.  Yet energy's trust level of 59%, which is slightly better than government's 53%, falls far short of the 80% trust score for the technology sector, followed by the automotive, food and beverage, and alcoholic beverage industries in the 70%'s. Energy's position isn't encouraging, considering its importance to the overall economy, but the details resist a blanket assessment.  Meanwhile, non-governmental organizations (NGOs) enjoyed a big jump in trust from 2012 to 2013, up to 70%.

Trust levels within energy differed widely by energy source, with a 30% gap between renewables, which garnered 65%, and oil at 35%.  Natural gas and utilities came in near the average for energy as a whole, reflecting closer customer connections for the latter, and the technology-driven, cost-saving growth of the former, notwithstanding concerns about hydraulic fracturing.  Although renewables have been involved in some messy bankruptcies and an ongoing debate over subsidies, their reduced environmental impacts and links to cutting-edge R&D puts them closer to the technology end of the trust spectrum.  Oil--arguably just as technology-focused as renewables--suffers from the fallout from events like Deepwater Horizon, and perceptions of inadequate stakeholder engagement.  Yet this disparity in trust levels also creates mutually beneficial opportunities for partnership.

I thought the most surprising findings were those describing how the factors that affect trust have evolved in recent years. In the past trust could be earned by simply focusing on operational results, including financial performance and company rankings; now that's just the cost of admission. Engagement with customers and employees, along with business ethics and transparency, topped the list of today's trust factors. This might explain at least part of the gulf between oil and renewables.  In my experience, oil executives live and breathe operations and shareholder returns, although broader definitions of stakeholder relations have been gaining ground in the last decade or so.  Yet the insular nature of these businesses, which have lived under decades of regulatory and anti-trust scrutiny, works against their embrace of new media and other tools of open engagement with both customers and critics.

The panel discussion that followed the Edelman presentation was also quite interesting.  Paula Gant of the American Gas Association memorably described the synergies between natural gas, renewables and energy efficiency as a symphony.  Jason Walsh of the Department of Energy's Office of Energy Efficiency and Renewable Energy addressed concerns about the reform of subsidies for renewable energy, while reminding the audience that private investment in renewables stood at $269 billion last year.  Peter Nelson, communications director of Resources for the Future, a nonpartisan, highly trusted NGO, offered his thoughts on the politicization of environmental issues, which seems linked to polarization over climate change.  Robert Dillon, communications director of the US Senate's Energy and Natural Resources Committee, pointed out that much of the current debate is over facts, asking, "Who owns the facts?"  The panel was moderated by Paul Bledsoe, a veteran of Congress, the White House and policy circles.  His comment that, "It's a stakeholder world, not a shareholder world," encapsulated what might have been the key takeaway of the day for companies. 

As good as the panel discussion was, when I left I was still mulling over an implication raised by Amy Hemingway of Edelman in her remarks at the start of the session.  Energy policy involves the intersection of government and energy companies.  It surely complicates the challenging tasks we face, with regard to resource management and environmental stewardship, that much of the public doesn't trust government or energy to solve our important problems.  Both institutions suffer from serious trust gaps, while NGOs, who as one panelist observed have significantly fewer constraints on their statements and actions, enjoy more trust than either one (or both together?)  Especially for the energy industry, getting things done increasingly requires more than good plans and solid returns. Its "license to lead", as another panelist described it, must be earned by engaging in activities that usually aren't second nature for experienced engineers and finance experts.

How Is Expanding Oil and Gas Production Consistent with Addressing Climate Change?

Last month the International Energy Agency (IEA) reported that the amount of carbon dioxide emitted for each unit of global energy use was essentially unchanged between 1990 and 2010, despite the implementation of global climate agreements and the expenditure of hundreds of billions of dollars for renewable energy projects and incentives. Just a few days earlier, the US Environmental Protection Agency released its annual inventory of US greenhouse gas (GHG) emissions, showing a 1.6% reduction from 2010 to 2011. US emissions were up 8% since 1990 but have fallen 5% since 2000 and nearly 8% from their pre-recession peak in 2007. Much of the US's recent divergence from the global trend is attributable to the displacement of coal from the power sector by shale gas.

As unwelcome as the IEA's finding was, it is unlikely to have shocked anyone who understands the scale of global energy systems and the continued reliance of many developed and developing countries on coal for power generation. The transition to lower-carbon energy systems is underway, as reflected in the details of the IEA report. However, it will take additional decades to reach targets consistent with limiting the projected global temperature increase to 2° C, which the IEA indicates would require a 60% reduction in the carbon intensity of energy by 2050 from current levels. That implies that energy companies still need to develop additional oil and gas resources in the interim, in order to support the economic activity that--among other things--will be necessary to fund the recommended investments in cleaner energy and energy efficiency.

At first glance that might seem paradoxical. After all, oil and gas account for 55% of US GHG emissions and around 40% of global emissions today. However, when gas displaces a higher-emitting fuel like coal, global emissions fall. This has been a matter of some controversy, due to uncertainty about the contribution of fugitive methane emissions from shale gas wells. Yet the estimates in the EPA inventory indicate that methane emissions from US natural gas systems actually fell by 9% between 2005 and 2011, even though US natural gas production grew by 27% over that interval, with shale gas output increasing by 950%. A new analysis from ExxonMobil indicates that on a lifecycle basis, replacing coal with shale gas in power generation reduces GHG emissions by an average of 53%, while also reducing overall freshwater consumption by half.

Assessing the role of oil in the decarbonization of global energy is more complicated. Oil exploration and development must continue, even in a static or eventually shrinking market, because reserves that have been produced must be replaced, by either new discoveries or further development of existing fields. Simply allowing today's oil fields to decline and hoping to make up their energy contribution from other sources would be very risky, particularly for the transportation sector with its extremely high reliance on oil. Moreover, four-fifths of the emissions from petroleum occur during end-use combustion. That means that most emission reductions from petroleum must come about through reduced demand, via some combination of increased fuel efficiency, fuel substitution--particularly in those markets where oil is still used in electricity generation--and/or reductions in transportation metrics such as vehicle miles traveled.

In a recent Bloomberg op-ed, Michael Levi of the Council on Foreign Relations considered the impact of increasing US oil production from the standpoint of both the "social cost of carbon" and its incremental contribution to global emissions. He concluded that even at a high estimated environmental cost, the climate impact of an extra barrel of US oil would come in under $10 per barrel, well below its economic value. He also concluded that significantly higher US oil production would add little to global emissions. Its impact would be even smaller if OPEC producers reduced output to try to preserve high oil prices. Mr. Levi addressed that scenario in an earlier op-ed.

Last month's IEA report concluded that the world is not yet on track to reduce emissions by enough to limit temperature increases to 2° C, and more must be done. Yet even if we were on that track, the IEA forecasts upon which the report was based suggest that combined oil and gas consumption in 2035 would still be about 2% higher in 2035 than in 2010, with a bit of a shift from oil to gas. On today's trajectory, both oil and gas will grow, even as renewable energy and energy efficiency expand significantly. On either basis, an all-of-the-above approach to energy encompassing oil and gas, along with renewables, carbon sequestration, nuclear power and efficiency is fully consistent with addressing climate change.

A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation. 

Ex-Shell Chief Hofmeister Promotes US Fuel Diversity

Alternative fuels have lost some of their luster in the US, lately, for understandable reasons.  Oil production here is booming based on shale resources that keep expanding, while the market for ethanol, our most successful alternative fuel, has stalled at the long-anticipated "blend wall", resulting in ethanol plant closures and bankruptcy filings.  More advanced cellulosic biofuel is still only available in minute quantities, and last year's sales of electric vehicles will displace less than 24 million gallons per year of gasoline--around 0.02% of US gasoline demand.  With all this in mind, it seemed like an excellent time to speak with former Shell Oil Company President John Hofmeister, who recently joined the advisory board of the Fuel Freedom Foundation, a group dedicated to expanding fuel diversity. 

I don't conduct many interviews for Energy Outlook, but I wouldn't have missed the opportunity to discuss energy with Mr. Hofmeister.  Given the focus of Fuel Freedom Foundation, which arranged the call, I started by asking him what kind of changes he expects in the US fuel mix over the next 10 years.  Mr. Hofmeister replied that his outreach efforts at Fuel Freedom, together with Citizens for Affordable Energy, which he founded after retiring as head of Shell's US operations, are intended to "make sure something has changed 10 years out. Left to our own devices, not much will change."  With plans and "enablers of change" from government, he sees an opportunity to "transform the nation in 10 years." He went on to describe what that transformation might include, in the form of further decreases in our dependence on imported oil and more "inward investment".  He also clarified that he includes domestic oil in his list of alternatives. 

When I asked him about the barriers impeding the fuel diversity that he advocates, he immediately mentioned the interest groups that spring up, pro and con, whether concerning oil, natural gas, the lifecycle and materials for advanced vehicle batteries, or infrastructure for hydrogen fuel cell vehicles.  He would like to see federal and state governments enable change and "tell the interest groups to back off."  He observed that despite the shale revolution, "we still rely on imports and can't agree on creating new markets for natural gas" or to build the Keystone XL pipeline.  These disagreements stifle development. Together with federal regulation of hydraulic fracturing, this results in "government as disabler", not enabler of change.

We had a lively conversation about some of the specific fuels that would make up the more diverse mix Mr. Hofmeister would like to see in the marketplace, such as methanol, ethanol, natural gas and electricity.  I expressed some of my own concerns about the energy-equivalent cost of methanol and the safety risks involved in its use on the service station forecourt.  He replied that with expanded supply based on abundant US natural gas, the price of methanol could fall significantly from today's level of $1.60/gal. (equivalent to wholesale gasoline at $3.25/gal.)  That's certainly conceivable, because at a typical 70% conversion efficiency, the natural gas feedstock to produce a gallon of methanol would only cost about $0.37 at recent industrial gas prices.  He also envisioned fuels like this being dispensed in a closed system, to maximize safety.

We discussed natural gas as a bridge fuel for vehicles and whether it might be hard to get off this bridge, later.  In response he pointed to what he called the "EV lifestyle"--the improved convenience and driveability already experienced by EV owners who don't need extended driving ranges--and seemed to agree with my own view of electrification as  a given in the long-run.  He also suggested that this transition could be promoted by a coherent and comprehensive plan.  Earlier, he had pointed out that the administration's "all of the above" approach was just a concept, not a plan, because it lacks the targets, milestones and accountability necessary for a real plan--a point on which an ex-CEO and current strategist were bound to agree.

I couldn't end the interview without asking Mr. Hofmeister whether the tremendous recent turnaround in US oil production had led him to alter his idea, expressed in various talks and in his book, "Why We Hate the Oil Companies," for the US to establish an energy equivalent of the Federal Reserve Bank.  "I'm convinced it's the way to go," he said. "There's too much politics in energy policy now." He believes an "Energy Reserve Board" would stimulate the economy with investments focused on short, medium and long-term goals.  "What energy needs is consistency."

My half-hour conversation with him validated my view that John Hofmeister isn't your typical oil guy.  His ideas are grounded in the scale and complexity of the energy industry, but not bound by its conventional wisdom.  Although I didn't agree with all of them--particularly concerning the degree of government intervention necessary--his responses to my questions were forthright and reflected long and careful analysis, along with a strong sense of the benefits available to the US from a more rational and planned approach to our national energy endowment and opportunities.

Engineering Carbon Out of Energy

• Because of the slow progress in displacing fossil fuels with renewables, carbon capture and sequestration should receive much more attention as a game-changing technology.
• The challenges that must be overcome for CCS to be deployed on a large scale remain significant.

Yesterday I ran across an excellent article in The Atlantic on the importance of carbon capture and sequestration (CCS).  In light of last week's warning from the International Energy Agency that efforts to reduce the carbon intensity of global energy have yielded minimal results over the last two decades, the authors' chosen title, "Learning to Live with Fossil Fuels", seems particularly apt. Although neither they nor the IEA are suggesting we abandon renewable energy, they do effectively question the conventional wisdom that climate change can only be addressed by abandoning coal, oil and natural gas within the next decade or two. 

I'm predisposed to their argument, because it aligns with my own view--the result of long and careful analysis--that the transition to a low-carbon economy is going to take a lot longer than optimists hope.  A speaker at yesterday's policy briefing on renewable energy from the Worldwatch Institute and REN21, marking the annual release of the latter group's always-useful Renewables Global Status Report, stated that long-term energy scenarios in which renewables don't significantly increase their market penetration are no longer credible, and that only scenarios including medium-to-high penetration rates by mid-century are credible today.  I had to wonder whether he had been looking at the same data as the IEA, even though he cited their "2DS" scenario in support of his view.  Sarewitz and Pielke, Jr. appear to take quite the opposite view in The Atlantic: We cannot ignore the potential of CCS, because it is not self-evident that renewables will sweep away carbon-based energy any time soon, for reasons of economics, politics, and "complex social arrangements." 

In their brief article, they do a good job of summing up the major options for capturing CO2, including some of the major challenges to be overcome, as well as how the captured CO2 might be used or disposed.  Underground storage, enhanced oil recovery, and conversion back into fuels are all technically feasible, despite significant obstacles of public acceptance, logistics, and cost. However, I believe they seriously underestimate the challenges of capturing CO2 from the air, instead of power plant smoke stacks. 

The desirability of doing so is clear; the atmosphere is everywhere, convenient to whatever use to which me might put the captured CO2, while power plants aren't always located near the oil fields, saline aquifers, or fuel markets that offer the best potential for storage or reuse. The problem is that, while 397 parts per million (ppm) of CO2 in the air is high enough to cause great concerns about global warming, it is still quite low in engineering terms.  Expressing it as a percentage it's 0.04%, or about 1/1000th the typical concentration of CO2 in flue gas.

Before writing this post I literally dusted off one of my old chemical engineering texts to look up the equations of mass transfer.  I was reminded that the flux, or flow, of molecules from one fluid into another--from air into the capture medium, for example--is proportional to the difference in their concentration in the two fluids.  What that means in practical terms is that extracting the same quantity of CO2 from the air as from flue gas will entail larger and more complex hardware, more energy, and probably a much higher cost per ton, barring a breakthrough that emulates green plants, which use chlorophyll, sunlight, water and nutrients to do this cheaply on a vast scale every second of the day during the growing season.

In any case, have a look at the article and give some thought to how CCS might, as the authors suggest, "transform the political debate" around mitigating climate change.

Will Water Limit Fracking in Arabia?

• Poor water availability could hamper efforts to develop Saudi Arabia's shale gas resources, in order to meet growing gas demand from Saudi industry.
• Water recycling and alternative fracking fluids could provide the solution.  

Recent comments by Saudi Arabia's oil minister, Ali Al-Naimi, indicated that Saudi Aramco would soon begin exploring the country's shale gas resources. As another means of reducing oil consumption in the Kingdom's electricity sector, in order to preserve oil exports, this appears to make both practical and economic sense. However, as noted by the Wall St. Journal, compared to the US Saudi Arabia has much less water available for the hydraulic fracturing of shale and tight gas reservoirs. Absent a reallocation of its substantial conventional gas production, Saudi shale gas could become a key factor in global energy security. However, the techniques employed to extract it might be different from those that currently dominate the US shale gas scene.

It must seem odd that Saudi Arabia would even be interested in shale gas, a resource that wasn't exploited in the US until conventional gas production was declining steadily. Saudi Arabia might still be the world's largest oil producer, at least for now, but it is not the "Saudi Arabia of natural gas". Although the country has proved gas reserves comparable to those of the US, it apparently didn't win nature's gas lottery on the Arabian Peninsula. Saudi gas reserves and production amount to only about 10% and 19%, respectively, of the Middle East's gas totals. Iran and Qatar are far ahead. And while Saudi gas production has doubled since 2000, output in neighboring Qatar has expanded by a factor of six in the same interval.

Much of the Kingdom's conventional gas reserves are associated with oil production and are often required to be reinjected to maintain reservoir pressure and oil output. Available Saudi gas has been preferentially allocated to industrial projects, such as petrochemicals expansion. As a result, little new gas was supplied for power generation, so the Saudi electricity sector has been burning large and increasing quantities of oil that could otherwise be exported. The need for additional gas has become acute, but exploration in the vast Empty Quarter has not yielded the expected gas bonanza, while the internal price of natural gas has been constrained at levels well below even recent low US natural gas prices--too low to make most new production attractive on its own merits.

As if the economics of shale gas development weren't challenging enough in such an environment, the key ingredient that has fueled the US shale revolution, water, is in short supply in Saudi Arabia. The needs of cities and industry in this arid country exceed the water supply from aquifers to such an extent as to require 27 desalination facilities, delivering nearly 300 billion gallons annually. At several million gallons of water per hydraulically fractured shale gas well, the logic of burning oil to desalinate water to produce gas looks questionable. Fortunately, there are multiple emerging pathways for reducing or eliminating net water consumption in "fracking".

For starters, many US producers now routinely recycle the 10-30% of injected water that typically flows back from the well after hydraulic fracturing, for use in subsequent wells. Recycling has become the standard in places like Pennsylvania's portion of the Marcellus shale, reducing the call on fresh water for fracking. The oil services industry offers various techniques for cleaning "flowback" water, and new ones are under development, including the use of algae.

Drillers can further reduce freshwater consumption through the use of nitrogen in foam or other forms. ERDA, a precursor of the US Department of Energy, conducted research on that technique in the 1970s, and it has been refined since then. Nitrogen is readily available from air separation plants and does not depend on water, though it does require energy.

Another approach for waterless fracking has been field-tested in Canada, using gelled propane. A blog post in Scientific American described some of the pros and cons of this method, which is more expensive where water is cheap but might fit the bill in dry regions where LPG is readily available. For that matter, it might make sense in New Mexico if the Mancos Shale of the San Juan Basin turns out to be another viable tight oil play.

The upshot is that a shortage of fresh water shouldn't constitute an insurmountable obstacle to exploiting Saudi Arabia's unconventional gas resources, which Mr. Al-Naimi cited at 600 trillion cubic feet. However, it remains to be seen whether shale gas development is the best answer to a problem that has been created by selling natural gas to industry for as little as $0.75 per million BTUs, while burning $100 oil ($17 per million BTU) to generate electricity. Whether the ultimate solution is shale gas or something else, resolving this gap in Saudi industrial policy could have a significant impact on future oil prices.

A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.  

How Will Oil's Current Slide Affect Gasoline Prices?

• How far could crude oil prices fall, and what does it mean for US pump prices this summer?
• The broad trends behind oil's current weakness could persist for some time. 

We all carry assumptions around with us.  For many who follow energy one such assumption is that oil prices, and thus gasoline prices, generally rise over time.  In an otherwise fairly well-reasoned blog post I read yesterday, that logic underpinned the case for electric vehicles (EVs) becoming more attractive to consumers.  Yet if we review the history of oil prices, it becomes clear that they don't only rise.  Just recently, the price of Brent crude oil, the current world benchmark, has declined roughly 11% since the start of April, prompting speculation about where it's headed from here and what that might mean for motorists.  It's worth stepping back from the day-to-day volatility of the market to consider what's behind this drop, as well as how OPEC might respond if the recent trend continues.

Start with the fundamentals of demand and supply.  Demand in the developed world remains weak. Despite modest GDP growth in 2012, US oil demand fell by 2% last year and is now 11% below its 2005 high.  This year, the unemployment rate is down a bit, but economists see signs of another  "spring swoon." The outlook seems no better in the other big economies, including China, prompting the International Energy Agency last week to cut its estimate of annual oil demand growth to just below 800,000 barrels (bbl) per day, with the US government cutting its estimate even further.  Meanwhile, many refineries are either undergoing maintenance or about to, reducing the most direct element of demand, at least temporarily. 

On the supply side, US production growth remains the big story.  US crude oil output is currently 7 million bbl/day, up nearly a million bbl/day in just the last year, and projected to average at least 300,000 bbl/day more than that for 2013. Overall, the IEA anticipates non-OPEC oil supply to increase by 1.1 million bbl/day this year.  Whenever non-OPEC growth exceeds the growth of demand, while inventories and spare production capacity are adequate, that puts pressure on OPEC and oil prices tend to weaken.  North Korea, Iran and a few other hot spots provide ample geopolitical risk, but the market has already absorbed the loss of about half of Iran's exports due to sanctions, while some other problem areas, such as Sudan/South Sudan, are being resolved. 

Taking all this into account, the market seems to have concluded prices were too high.  This is the other face of speculation that is never subjected to Congressional investigations.  Yet it also seems premature to assume this is the start of a major move downward, or an imminent oil price collapse.  Nick Butler of the Financial Times suggested that normal economics would take us to around $70/bbl, though I think he underestimates OPEC's cohesion and their willingness to absorb pain to defend a crucial price threshold.  Their experience in 2008-9 provides a vivid recent reminder that selling 10% less oil at something close to the current price is a much better deal for them than selling all the oil they can at $35/bbl.

It's also not clear how quickly a sharp drop in prices would undermine the output of the Bakken, Eagle Ford and other big US shale oil plays. These reservoirs require more intensive drilling than conventional oil fields, and many of the drilling rigs in use there were redeployed from gas-rich opportunities after the US price of natural gas slid sharply in the last several years.  It also seems that some of the weakness in Brent is specific to its market. West Texas Intermediate (WTI) crude hasn't dropped as quickly, thus narrowing the gap between the two from $20/bbl as recently as February to about $11 today.  So those parts of the US where refiners still import significant quantities of foreign crude pegged to Brent, such as the east coast, might see more gasoline price relief than those where abundant supplies of cheaper, WTI-related crude have kept pump prices lower.

And that's what it boils down to for most Americans, who don't burn crude oil or invest in oil futures.  The Energy Information Administration (EIA) of the US Department of Energy recently issued its Summer Fuels Outlook, projecting that US gasoline prices would average $3.63 per gallon for the April-September "driving season", down from $3.69 last year and up just slightly from last week's $3.61/gal. However, that forecast was based on a July Brent crude price of $107/bbl.  Crude oil makes up around two-thirds of the retail cost of a gallon of gasoline in the US, where fuel taxes are relatively low compared to other developed economies. If Brent merely held where it is today we could see summer gasoline prices below $3.50/gal. for the first time in several years.

Longer-term, oil and gasoline prices remain as unpredictable as ever.  However, the trends combining to produce today's weaker prices could well have staying power.  It's still relatively early days in the US shale, or "tight oil" upsurge, with more growth expected, and new-car fuel economy continues to improve.  Those factors support the trend of falling US oil imports, which will take pressure off global markets, no matter what happens to demand in Asia.  At least until we see a different configuration of factors the argument for suspending our assumption of steadily rising future oil and motor fuel prices looks pretty robust.  That suggests that the case for EVs and alternative fuels must be made on the basis of other factors and, if anything, be prepared to weather another period of lower fuel prices should oil continue to weaken.