Thursday, July 26, 2012

How Secure Are Green Jobs?

It's been an article of faith among advocates of "green jobs" from expanding renewable energy deployment that wind and solar installation jobs are secure because they can't be sent offshore, even as the manufacturing of wind turbines and solar equipment increasingly shifts to Asia.  A story in MIT's Technology Review casts doubts on that assumption, for reasons that have much to do with recent reductions in the cost of solar photovoltaic (PV) cells, modules and panels.  Green jobs, which in any case shouldn't be viewed as the main selling point of renewable energy, turn out to be much like other jobs in facing competition from automation, as well as from globalization.

Why would it suddenly make sense to consider installing utility-scale solar panels using the robots highlighted in the article?  PV module costs have declined dramatically in the last two years.  As I've noted in other postings, this trend reflects the expected experience curve effects--such goods become cheaper as you produce more of them--but also the fierce competition resulting from enormous over-building of global PV manufacturing capacity as countries competed with each other to offer generous subsidies for this industry.  One consequence of these PV hardware price declines is to increase the share of "non-module" costs in the total installed cost of solar panels. Because the power produced by PV is still more expensive than conventional energy in most markets, that tends to shift the focus of innovation toward ways to reduce the costs of the mounting hardware, inverters, and labor used to put these arrays in place.

The article makes it clear that only certain parts of the solar installation trade are currently threatened by robotic installation.  Robots apparently aren't suited to rooftop and small ground installations, yet.  However, with politicians busily blurring the distinctions between outsourcing and offshoring, while neglecting the ongoing transformation of work by automation, computing and telecommunications, it's worth recalling that energy remains a capital-intensive commodity business.  Keeping costs down is crucial for both energy providers and their customers, and thus for the entire economy they energize.  When labor is involved in producing energy, its productivity must be very high, or it naturally becomes a target of innovation and process reengineering.  That needn't mean low wages, but it does imply fewer workers working smarter, with more automation.

The energy industry offers excellent opportunities in many sectors, especially those that are growing rapidly because of new technology or the removal of artificial constraints.  Yet we shouldn't fool ourselves that these jobs are any more protected or permanent than any others, especially in segments that aren't yet cost-competitive.

Friday, July 20, 2012

Food vs. Fuel and the Midwest Drought

It was bound to happen.  As long as US corn output continued to climb year after year, the federal mandate to blend steadily increasing quantities of ethanol into gasoline could be accommodated without creating a shortage of this staple grain.  Unfortunately, crops are subject to all sorts of uncertainties, including the severe drought conditions that the middle of the country is experiencing this year.  Estimates for this year's corn crop have been revised downward, and corn prices have already broken through $8 per bushel, up from less than $6 a month ago, with consequences for the livestock, processed food and ethanol industries, as well as for export markets.  As soaring feed grain prices begin to translate into higher grocery prices for meat, poultry, dairy and other goods, will consumers demand relief from the EPA, which has the authority to curtail ethanol volumes?  The current betting appears to be that the administration will stand fast on the mandate, but anything can happen in an election year. 

Ethanol now accounts for at least 10% of US gasoline blending, by volume.  To meet that demand, ethanol producers will require around 5 billion bushels of corn.  In recent years, the ethanol industry's expanding corn demand was met by a combination of increasing yields and planting more acres in corn.  However, corn yields per acre are dropping sharply this year, potentially pushing output below last year's 12.4 billion bushels, if conditions don't improve soon.  That's in contrast to earlier expectations that this year's corn crop would exceed last year's by 20% .  This isn't the first time that the food vs. fuel trade-off inherent in crop-based biofuels has become an issue, but it might be the first time when both the demand for corn for ethanol is so high and the need for that ethanol in the gasoline blending pool is arguably so low.  In this context, food vs. fuel quickly boils down to a debate over the tangible benefits of corn-based ethanol as a fuel.  There's growing evidence that those benefits have been oversold, despite industry claims.

Start with the widely touted study from Iowa State University indicating that ethanol saved consumers $1.09 per gallon at the gas pump in 2011 and $0.89/gal. in 2010.  I read both the original study and its updated version when they came out.  It seemed obvious to me that the authors' grasp of gasoline markets and oil refining were inadequate, but I lacked the time necessary to dig through their math to uncover the source of their exaggerated results.  Fortunately, a pair of researchers from MIT and my alma mater, U.C. Davis, have now done that work and concluded that the Iowa State paper's findings--and the claims based on them--depended on a "spurious correlation": the relationships they saw were coincidental.

In contrast to the Iowa State studies, the MIT/Davis paper is very readable, and I recommend it to you.  In addition to debunking the statistics, the authors point out the key flaws in their counterparts' logic.  Foremost among these is that in order to have a large influence on gasoline prices, ethanol would have to have had a large impact on crude oil prices, which are the largest determinant of gas prices, by far.  From 2005-11 US ethanol production expanded by 10 billion gallons per year, the energy equivalent of 350,000 barrels per day of oil, or 0.4% of 2011 global oil supply. I've argued many times that the oil market responds disproportionately to modest changes in supply and demand, but the idea that a few hundred thousand barrels per day could translate into the equivalent of $45/bbl exceeds the wildest dreams of any trader I ever met.  The MIT paper concludes with the authors summarizing the likely impact of ethanol on gasoline prices as "near zero and statistically insignificant."

However, if ethanol hasn't done much to hold down gas prices, could a drop in US ethanol production resulting from paring back the ethanol mandate to reduce the pressure on corn prices cause a big spike in gasoline prices?  That's where the analysis in a paper presented to members of Congress yesterday comes in.  Dr. Elam's report suggests that rather than displacing imported crude oil, the main effect of increasing US ethanol use in fuels has been to divert domestic gasoline production into exports, while US crude imports have fallen based on a combination of lower demand (from the recession) and improved product yields per barrel of crude oil refined.  Even if you are inclined to be skeptical of these findings because the study was supported by poultry interests, data from the US Energy Information Agency and elsewhere show that US refineries are not fully utilizing their capacity, are exporting significant volumes of gasoline, and have a wider array of domestic and imported crude oils at their disposal than they did just a few years ago. In short, we're in a far better position to forgo a few billion gallons of ethanol this year than we would have been in 2008, the last time food vs. fuel concerns spiked along with gas prices. 

Corn growers have experienced droughts before, and in the past the price of corn sorted out who needed it most.  However, the market can't prioritize fairly among the competing calls on a drought-diminished corn crop when the single largest segment of demand is locked in place by a federal mandate. This represents a massive distortion that only the government can rectify. I'm sympathetic to the ethanol industry's dilemma.  After all, the federal government virtually begged them to overbuild capacity, but it couldn't guarantee they would earn a profit, even when it was providing a $0.45/gal. subsidy for their customers, who are required by law to use their main product.  However, the economic and environmental benefits of ethanol are too modest to shield this industry while forcing all other corn users to absorb the likely shortfall in corn supply.  The most sensible remedy would be to unshackle ethanol demand, at least temporarily, and waive at least a portion of the ethanol mandate for 2012-13.

Wednesday, July 18, 2012

Should the US Become An Oil Exporter, Again?

Last week I missed attending a fascinating panel on the growth of US oil production, hosted by  the New America Foundation in Washington, D.C. Fortunately, I was able to catch most of the live webcast, which is still available for replay. Much of the discussion focused on the potential of new "tight oil" production techniques, similar to those used to extract shale gas, to help usher in a new period of relative oil abundance.  If this comes to pass, among other things it could challenge long-established views about exporting US oil.  The politics of oil exports look absolutely dire at the moment, but the economic and logistical benefits--not just for oil companies but to the nation--are such that we shouldn't dismiss the possibility lightly.

Two hours was not enough time to do justice to all the ramifications of resurgent US oil production, and I know from following the Twitter feed for the event that some in the web audience were frustrated by the limited attention given to the climate implications of these developments.  However, if you'd like an overview of the possible economic and geopolitical impact of the US becoming more self-sufficient in petroleum for at least the next decade or two, this stellar panel was highly informative and worth your time.  Much of the discussion focused on tight oil, liquid hydrocarbons trapped in rocks that can't be economically tapped by conventional drilling, but that have proved susceptible to combinations of horizontal drilling and hydraulic fracturing similar to those that have unleashed the current shale gas boom. Although the full potential of this resource hasn't been reflected in the latest forecasts from the Energy Information Agency (EIA) of the US Department of Energy, the results from the Bakken shale in the Dakotas and the Eagle Ford shale in Texas are instructive.  Together these two fields now produce around 750,000 barrels per day, or 12% of current US crude oil output, up from just a trickle a few years ago.  They also hold billions, and possibly tens of billions of barrels of recoverable resources.

I was a little surprised that the first panelist to mention the possibility of exporting some of this oil--with appropriate caveats--was Adam Sieminski, the newly confirmed EIA Administrator. After all, current US law restricts the export of most US crude oil production, with special exceptions for some oil from Alaska, California, and near the Canadian border.  In practice, crude exports from those fields have declined to very low levels.  Despite that, and even after significant reductions in imports since the onset of the recession, the US is still a major net oil importer.  If that's the case, and if US refineries can benefit from the increasing domestic output, why would we even consider exporting any of this new oil?

Unfortunately, the answer doesn't reduce to a neat soundbite; it depends on two key factors that require a bit of explanation.  The first issue is the quality of the oil coming out of these tight oil plays, which at least so far has been very high. Oil from different fields varies as much as fingerprints, even when we consider only a few characteristics of concern to refiners, and these differences strongly influence the market values of the various grades of oil.  Light crudes refine easily into valuable products like gasoline, diesel and jet fuel, while heavier crudes require more processing, using more expensive hardware, and often yield large quantities of low-value products like petroleum coke, even after intensive refining. There's also sulfur content--the sweet to sour spectrum that overlays the light/heavy distinctions--as well as other impurities.  Eagle Ford crude is light and sweet, as is the North Dakota Sweet crude produced from the Bakken. These crudes compare favorably with West Texas Intermediate (WTI), Brent and other premium crude streams.

The second, related factor involves the complexity of US oil refineries and the crude diet they've evolved to run. As production of high quality crudes in the continental US declined over the last four decades, many refiners invested billions of dollars to enable their facilities to run some of the heaviest, most sour crudes from around the world, because these were more readily available and usually significantly cheaper than the light sweet crudes.  This trend was particularly evident on the West Coast and Gulf Coast. The addition of complex processing hardware like hydrocrackers, delayed or fluid cokers, and residuum fluid catalytic crackers has given these refineries tremendous flexibility, but it also increased their operating costs and made it harder for them to go back to a diet of much lighter crudes.  As a result, while many of them could handle significant quantities of light crude from the tight oil fields, this would be less than optimal, resulting in economic penalties and perhaps eroding the advantages that have recently enabled gulf coast refiners to capitalize on export markets for their products. Those penalties would translate into discounts for the tight oil grades, compared to similar international crudes, much like the large gap in value we currently see for WTI compared to Brent, though for different reasons as discussed previously.

At current production levels, the mismatch of quality and capabilities isn't as big a problem as the lack of infrastructure for transporting these crudes to market.  That has resulted in discounts so large that it makes sense for private equity firm Carlyle to plan to ship large quantities of Bakken crude by rail from North Dakota to the Philadelphia refinery they've just acquired from Sunoco.  However, if tight oil output grows in line with forecasts such as those in a recent analysis from Citibank, domestic sweet crude refiners will have more than enough supply and the excess must either be sold to heavy crude refineries at a discount or left in the ground.  That's where exports come in. 

The last time exporting domestic crude became a big issue was in the late 1980s, when output from Alaska's North Slope (ANS) field reached peak levels of roughly 2 million barrels per day, far more than west coast refineries could absorb. I was trading crude on the West Coast at the time, and I observed first-hand the effects of the export restrictions that had been put in place when the Trans Alaska Pipeline was originally approved.  Those restrictions didn't just depress the price of ANS crude; they also depressed the price of the California crudes with which ANS competed, and made both types less attractive to produce. West coast consumers benefited from a few years of lower gasoline prices than they would have otherwise paid, but the net result was less industry investment and probably higher oil imports in the long run.  By the time ANS exports were finally approved in 1996, the field was already in decline and the biggest opportunity had been missed. 

The advantages of allowing a portion of these new tight-oil streams to be exported would derive from the difference between the global market premium for crude of this quality and the typical discount paid for the lower-quality crudes that gulf coast refiners would continue to import in order to optimize their product yields and costs.  A difference of just $5 per barrel across a million barrels per day of exports would translate into a nearly $2 billion per year improvement in the US trade balance.  The benefits might also include higher tax revenues and royalties if exports supported higher production.  The biggest drawback I see is that in the event of a global supply disruption, some domestic crude would be committed to non-US buyers, reducing our emergency cushion.  However, that problem might be circumvented by requiring exporters to include provisions in their contracts allowing them to suspend deliveries whenever the US government released oil from the Strategic Petroleum Reserve, or a similar contingency.

Perhaps the best summary of the benefits that US oil exports could provide was given by President Clinton, when he authorized exports from the Alaskan North Slope: "Permitting this oil to move freely in international commerce will contribute to economic growth, reduce dependence on imported oil and create new jobs for American workers."  It's probably premature to provide a similar exemption for tight oil now, but it's certainly not too soon to start the national debate that should precede such a decision.

Wednesday, July 11, 2012

The 2013 US Energy Agenda

It's tempting to focus mainly on the energy issues that have come up in the context of the presidential campaign, such as the Keystone XL pipeline, tax breaks for energy companies, and whether and how to regulate hydraulic fracturing, a.k.a "fracking".  Yet whoever is inaugurated next January, and however he resolves these issues, he will also face a much wider array of energy concerns, including some that are outgrowths of current policies or have emerged after a long gestation.  Though not intended as an exhaustive list, here are a few such issues that merit close attention from the next president's energy team.

They should begin by taking a fresh and objective look at the overall US energy posture and devising a clear and concise way to describe it to the public.  Big changes have taken place, with many of the issues that preoccupied us for the last decade or longer having become less relevant or out of date.  Topping that list is the sense of energy scarcity that has burdened us since the oil crises of the 1970s and early 1980s.  There's a realistic possibility that the combination of "tight oil" and the gas liquids production from shale gas could push domestic US petroleum/liquids production back above its early '70s peak of around 11 million barrels per day. At the same time, our net oil imports are declining, due in large part to the weak economy.  However, as the share of fuel efficient vehicles in our car fleet increases, it's reasonable to think that we've already seen the peak of US demand for petroleum fuels, even after the economy returns to healthy growth.  The net result might fall short of energy independence, but it will put us in a much better position than our largest economic rivals in terms of real energy security. 

Then there's shale gas.  Not only has it reversed a worrisome decline in US natural gas production that prompted numerous projects to import liquefied natural gas (LNG), but it has upended our assumptions about future prices and emissions in the electric power sector, while completing the divorce of oil and electricity that began in the 1980s.  Now we're talking seriously about exporting natural gas. When you combine all these changes with biofuels that are contributing roughly a million barrels per day to US supply (in volumetric, though not BTU-equivalent terms) the need to revisit some of our most basic assumptions about energy looks compelling. 

Energy scarcity isn't the only paradigm that needs to be rethought.  The current administration apparently took office with a view that was prevalent in the environmental community and among some in energy circles, that the solutions to climate change and energy security were effectively synonymous and synergistic.  That view predates the shale/tight oil revolution and was founded on the notion that renewable energy and efficiency were the only serious answers to both concerns.  That linkage was always oversimplified, because it ignored the trade-offs inherent in the shortcomings of every energy technology available.  And now, thanks to unexpected technological developments, we face an explicit choice between energy abundance based on hydrocarbons and a lower-emissions future based on renewables and electric vehicles that won't reach the required scale for decades, despite promising early signs. The transition from the former to the latter appears long and largely unpredictable, nor will it be cheap. 

The next administration also faces a set of practical issues, along with the big-picture reframing described above. Two of these issues involve urgent tasks.  The first is the growing need for a thorough evaluation of the recent and current approach to incentivizing renewable energy technologies and projects.  Since early 2009 we've spent tens of billions of dollars on a constellation of federal grants, tax credits, and loan guarantees to stimulate the growth of a domestic renewable and advanced energy industry and the deployment of its products. There's a lot of new hardware on the ground, but the sustainability of this industry looks uncertain. Although only a fraction of the companies that received federal support have failed, the tally has grown large enough--with the addition of Abound Solar last week--that it's no longer acceptable merely to shrug off these losses as par for the course.  We need some hard-nosed, detail-oriented outsiders to conduct a comprehensive post-expenditure review and extract the major lessons learned.  That should be an absolute prerequisite before anyone contemplates renewing or expanding any of these programs, including the Pentagon's $210 million "green fleet" program.

Another urgent clean-up task is the reform of the federal Renewable Fuel Standard (RFS).  This 2007 mandate was premised on the imminent arrival of cellulosic biofuel technologies that have turned out to be much harder than expected to transfer from demonstration to commercial scale.  That has resulted in drastic annual revisions to the cellulosic biofuel targets of the mandate, but even these lower targets have not been achieved.  Instead, the EPA imposes penalties on refiners and gasoline blenders for failing to blend non-existent volumes, with consumers ultimately absorbing the higher costs at the pump.  The attractive vision of abundant renewable fuels has thus turned into a bureaucratic game.  And while corn ethanol supplies 10% of gasoline and consumes nearly 40% of the US corn crop, it cannot more than double to meet the entire 36 billion gallon per year RFS target for 2022, nor should we wish it to.  Instead, the RFS must be updated to reflect reality, and the associated biofuel-credit trading system should be restructured to squeeze out the fraud that is infecting it, instead of leaving refiners and blenders--and again ultimately consumers--to pick up a tab estimated at $200 million

These items don't constitute an entire energy agenda by themselves, but together with a few higher-profile proposals from among those that both campaigns will announce and debate during the next four months, they could fill out a worthy first-hundred-days' energy plan for 2013.

Thursday, July 05, 2012

A Sign of Sanity in Solar Manufacturing

I've been writing for some time about the chronic overcapacity in global solar manufacturing and the consolidation this is likely to produce.  Now here's a sign that at least one company realizes how bad the situation is.  GE is apparently delaying the construction of its previously announced Aurora, Colorado, thin-film solar panel factory, and "taking this opportunity to re-look at our solar strategy."  I couldn't find a GE press release to back this up, but it's been reported by RECharge and confirmed by Forbes.  It's easy to read too much into a single event, but I think this looks significant, particularly in the wake of Monday's Chapter 7 bankruptcy filing by Abound Solar, incidentally another recipient of a sizable federal renewable energy loan guarantee.

If this information is correct, GE is backing away--for at least 18 months--from building a 400 MW thin-film photovoltaic (PV) solar line in Colorado.  That suggests that they have concluded that even a brand new facility using the latest technology and large enough to compete on scale with thin-film leader First Solar wouldn't be able to earn an attractive margin in this market.  And as a global competitor, GE would presumably regard the new US tariffs on China-based PV manufacturers as insufficient to resolve global PV overcapacity that appears to be stuck at about the same magnitude as demand, despite the continued rapid growth of the latter.

In the last year I've seen numerous articles and blog posts attributing the recent PV price declines to the predicted scale-related effects that have long anchored the industry's central narrative: If we build and deploy enough PV, the cost will fall to the point at which it will be competitive with conventional electricity generation.  That may still be true in the long run, but few of these advocates seem to have understood that the industry was getting ahead of its own narrative--that a big slice of the recent price declines was the result of intense competition among producers who over-expanded and whose margins have contracted sharply or turned negative in the process.  That's a good reason for GE to hit the pause button and focus on improving its technology in the lab, rather than the fab, while other, less well-capitalized firms struggle to survive long enough to participate in the expected growth surge when solar reaches "grid parity" on a sustainable basis.

PV is an important energy technology with a bright future, but its present doesn't look so great.  It's not unusual for manufacturing industries to experience boom-bust cycles, though in my experience those are more common in commodities like chemicals and fuels.  However, it is distinctly unusual for governments to contribute so much to the inflation of the boom part of the cycle through a wide array of incentives, loan guarantees and loans to manufacturers and with subsidies--in some cases extravagantly generous ones--to the industry's customers.  Such interference may have been necessary to jump-start PV supply and demand, but it will almost certainly make for a harder and messier landing for companies, investors and employees, and in cases like that of Abound Solar for taxpayers.