California’s Carbon Border Wall

With all that’s been happening in Washington DC, you may have taken your finger off the pulse of California climate change policy. But now’s a good time to check back in. There’s a new cap-and-trade proposal in town, and it’s turning lots of heads in the state capital.

California is deep in deliberations over cap-and-trade as it prepares to meet a new and ambitious GHG emissions reduction target. The state is aiming to reduce emissions to 40% below 1990 levels by 2030. This makes the GHG emissions reductions we’ve achieved so far look timid.

While the state has charted an emissions reduction path out to 2030, the existing GHG cap-and-trade program sunsets in 2020. This means the legislature needs to reauthorize – or replace – the current program to meet this post-2020 ambition. The 260 million metric ton question: What policy can most effectively deliver on this target?

The new cap-and-trade proposal, SB 775, would replace the existing cap-and-trade program in 2021. It has some pundits swooning. David Roberts of Vox writes a glowing endorsement of what he sees as a “clean break” from California’s existing GHG emissions trading program. But other policy experts offer a different view. Economist Rob Stavins argues there’s no need to “repeal and replace” the state’s effective cap-and-trade system. Professor Ann Carlson warns that it could “cause many more problems than those it attempts to solve”.

The proposal covers a lot of ground in 19 pages (Dallas Burtraw provides a great review here). I want to unpack one key piece: the proposed border adjustment. This may sound wonky and weedy, but it’s really important because it aims to bring imports under California’s cap-and-trade program. There’s a lot to like about this idea in theory. But the reality could be a different story.

The Leakage Problem

To put this border adjustment into context, let’s quickly review the problem it’s trying to address. The problem is that California’s climate change policy applies to only a small subset of the sources contributing to the global climate change problem. Pricing carbon only within the state could potentially send business – and associated emissions – out of state.

Suppose you are a California-based producer of an emissions-intensive product, such as cement, glass, or refined oil products. Under a statewide cap-and-trade program, you are required to purchase emissions permits for your GHG emissions. In other words, the policy increases your production costs. If out-of-state producers can supply the California market, this could mean you lose California market share to out-of-state rivals who don’t face the same cost increase. If you are a California-based operation that exports its products, this could make it harder for you to compete in out-of-state markets. In either scenario, the policy can shift production out of California. The associated emissions “leakage” erodes emissions reductions achieved within the state.

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The Current Response

Concerns about leakage loom large, so it is essential that California’s cap-and-trade program incorporate some meaningful response to this problem. Right now, the response comes in the form of free permit allocation. A share of permits (approximately 15%) are distributed free to those industries that are deemed to be at leakage risk.

You may be wondering how requiring firms to purchase permits – and then handing them back for free- achieves anything at all. The key is that emitters are required to turn in permits to cover their emissions, but these same firms are allocated free permits based on production. So you (the producer) see both an emissions tax (which provides an incentive to invest in emissions abatement) and a production incentive (which helps to ‘level the carbon playing field’ with out-of-state producers and thus mitigate leakage).

If we are concerned about emissions leakage (and we should be), this output-based free permit allocation approach can strike a balance between incentivizing emissions abatement and mitigating leakage. That’s the good news. The less-good news is that this strategy comes with side effects. For one thing, it dilutes the carbon price signal that California consumers receive when they are making their consumption decisions. It also allocates the revenue from the sale of valuable permits to industry when this revenue could alternatively be put towards other good uses.

The Proposed Alternative

There’s more than one way to skin this leaky cat. SB 775 proposes an alternative that I think most (all?) economists would prefer in theory. The idea is simple and elegant. First, identify imported products whose price would be materially impacted by the carbon permit price. Then require importers of these products into California to purchase permits for the emissions baked into their product. As for California-based exporters, they are exempt from the obligation to purchase permits for emissions associated with products sold outside the state (the SB 775 language on this is hard to parse…. thanks to Michael Wara for clarifying this important point!)

Why is this the theoretically preferred approach? For one thing, consumer prices in California rise to fully reflect the carbon price signal. This helps us consumers account for the full costs of our consumption, and adjust our behavior in response. Second, California can use the revenues from the sale of permits for other purposes, versus freely allocating to industry (although exempting exports means no revenues are collected from exporting firms).

The upshot is that this border adjustment seems like a winning proposal in theory. But the winning horse, in theory,  need not be the most fit to ride through the real-world challenges that lie ahead.

Comparisons between an elegant proposal-on-paper and the existing workhorse that’s spent years slogging through messy policy implementation can be misleading. It’s easy to find flaws in the current permit allocation approach to leakage mitigation when compared against some theoretical ideal. But the more relevant point of comparison is the border adjustment after it hits the buzzsaw of reality.

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Here’s my wet-blanket list of reality-bites concerns:

• We import lots of stuff from lots of places: Under the border adjustment, California will need to estimate the carbon emissions baked into all the emissions-intensive products we import. There is already some precedent for this kind of accounting exercise covering one product under the state’s low carbon fuel standard (LCFS). Nine full-time staff have been hard at work estimating the GHG emissions factors for transportation fuels consumed in the state. This table summarizes the hundreds of “carbon pathways” (e.g. “South Dakota corn ethanol”, “Brazilian molasses ethanol”) that span the space of transportation fuels. It can take months to estimate a single pathway. The number of source-product combinations would increase dramatically under the border adjustment.
• A cap on consumption emissions is harder to measure: It’s worth pointing out that, under a border adjustment, the state’s emissions targets and the associated emissions cap would have to be redefined. California currently caps emissions from in-state production. But under a border adjustment, the cap-and-trade regulation would cap emissions associated with in-state consumption. This means using the aforementioned emissions factors to estimate emissions in our imports, and subtracting the emissions from in-state production that get exported outside the state.
• Export reshuffling? Under the SB 775 proposal, emissions associated with California production destined for export markets would be eligible for a border tax “refund”, whereas emissions associated with production that stays in California would remain under the cap. This asymmetric treatment of what stays home and what gets sent outside of California creates an incentive to re-allocate more emissions-intensive production to the export market in order to avoid the carbon price.
• Legal challenges:  The border adjustment could pose a triple threat to the program: challenges from within the state, challenges under the commerce clause, and challenges from WTO. The legal resources required to defend this provision could be large. Notably, the SB 775 language does include an escape clause. If a judicial opinion, settlement, or other legally binding decision reduces the state’s authority to implement the border adjustment, the legislation authorizes a return to free allowance allocation for the affected products.  But this return would be messy, in part because it would require a re-adjustment of the emissions cap

Conclusion

California is demonstrating a working example of how emissions leakage can be mitigated in a regional emissions trading program. There’s no question that the current approach falls short of the theoretical ideal. But the real question is:  could an alternative approach work better? SB 775 has raised the profile of an important conversation about what those alternatives could look like.

My concern with the border adjustment proposal is that it seems to put the cart before the proverbial horse. Success hinges critically on our ability to come up with legally-defensible measures of greenhouse gas emissions intensities for all the carbon-intensive products we import. It’s worth noting that exploratory work along these lines is already underway (Resolution 10-42 directed the Air Resources Board to review the technical and legal issues related to a border adjustment for the cement sector). Given all that’s at stake, we should double down on these efforts to develop and test this approach before we bet the farm on its real-world durability.

One Stone, No Birds

Capping greenhouse gas (GHG) emissions at individual facilities is a bad idea whose time, unfortunately, may have come in California. Unlike a statewide cap or tax on emitting GHGs, facility-specific caps have essentially zero support among environmental economists, as I discussed in a blog in January.

Capping GHGs at specific facilities would undermine California’s leadership in creating cost-effective mechanisms for fighting climate change. If the caps are binding, their primary effect will be to drive GHG-intensive industry out of the state, moving the emissions, not reducing them.

Nonetheless, recent changes to a bill in the California legislature (Assembly Bill 378) suggest that’s where we’re headed.  AB 378 is one of (at least) two competing bills that would extend California’s GHG cap and trade program past 2020, which is when the current legislated program ends. Previously, AB 378 had stated that GHG reductions should be achieved in a way that also addresses public health issues from local air pollution, particularly in disadvantage communities. This is a great idea for which there are many possible policy options.

Unfortunately, AB 378 was amended in April to add specific requirements for facility-specific caps, which  will directly conflict with cost-effective climate change mitigation:

(c) The state board [California Air Resources Board] shall not permit a facility to increase its annual emissions of greenhouse gases compared to the annual average of emissions of greenhouse gases reported from 2014 to 2016, inclusive.

(d) The state board may adopt no-trade zones or facility-specific declining greenhouse gas emissions limits where facilities’ emissions contribute to a cumulative pollution burden that creates a significant health impact.

Wait, if legislators are worried about local air pollution in disadvantaged areas (known as environmental justice or EJ communities), why would they cap GHGs instead of regulating the local air pollution? After all, it’s the local pollutants (NOx, microscopic particulates, and toxics like benzene and formaldehyde) that create health impacts in surrounding communities.  The impact of greenhouse gases is the same regardless of where on earth they are released.

The answer goes back to a paper by Cushing, Wander, Morello-Frosch, Pastor, Zhu and Sadd that was released last September, which Meredith discussed last October. The paper shows (figure 3, reproduced here) a significant, though very imperfect, correlation between GHGs and one measure of local pollution released from industrial facilities.

The paper also shows that GHG emissions are higher on average in EJ communities than in those that are not considered disadvantaged. And, the paper suggests that total GHG emissions from industrial sources in California were higher in 2013-14 than in 2011-12, before California’s cap-and-trade program began. A longer time-series look at industrial GHG emissions confirms the claim of Cushing and co-authors. But it also shows that the largest change occurred between 2011 and 2012, before cap-and-trade started, so it is hard to know if cap-and-trade accelerated or slowed the trend.

A new paper by Kyle Meng of UC Santa Barbara sheds more light on the question of GHG emissions in EJ communities. Meng’s paper confirms that GHG emissions have been about 40% higher, on average, in EJ communities than other areas in California. But his analysis shows that GHG changes since the beginning of cap and trade have not differed on average between EJ and non-EJ communities. Meng looks at the changes in GHG emissions in 2013-2015 (data for 2016 have not yet been released) compared to 2012, the year before the program started. He finds no statistically significant difference between EJ and other communities over the three cap-and-trade years in aggregate, though if anything emissions have fallen slightly more in disadvantaged communities. He also finds substantial GHG drops in 2015 in both EJ and non-EJ communities.

Even if EJ communities have seen about the same GHG change as non-EJ areas, if GHGs at a facility generally move in tandem with local pollutants, isn’t restricting GHGs a tool that could kill two birds with one stone? Unfortunately, the answer almost certainly is no.

The reason is that restricting GHGs at specific facilities gives companies incentives to make changes that just shift the GHG emissions elsewhere, particularly out of state. The California oil refining industry has been at the center of these facility-cap discussions, and provides a good illustration of the problems.[1]

If a California refinery were faced with a binding GHG cap, the two most likely ways it would comply are by reducing the amount of oil it refines (and thus the amount of gasoline and other refined products it produces) and/or by changing the type of oil it refines.

Reducing the amount of oil it refines means that there is less in-state production of gasoline and other products. But that does not reduce the amount of gasoline we consume in California, at least not by much, because (with an extra 10-20 cents per gallon for shipping) California-specification gasoline can be brought in from refineries around the world. So, the reduction in in-state production just creates “leakage” of production to out-of-state facilities, generally taking high-paying jobs with them.

In fact, that is exactly what happened after the fire at Exxon’s Torrance refinery in February 2015, causing gasoline prices to spike. It takes about a month to order and receive delivery for imported gasoline that meets California specifications. As the figure below shows, gasoline imports to the west coast (the vast majority of which are to California) skyrocketed about a month after the mid-February fire (the blue lines). The fire drastically reduced GHG emissions from the Torrance refinery, but those were likely more than offset (due to additional transportation) by increases in emissions from refineries elsewhere in the world.

Some advocates for restricting refinery GHG emissions have argued that we just need to get off of gasoline, and this would be a first step.  I completely agree that we need to replace gasoline, but facility-specific GHG caps are not a step in the right direction. The Torrance refinery fire took out about 10% of the state’s capacity to produce California-specification gasoline, but as the figure below shows it did not put a noticeable dent in California gasoline consumption, which has continued to trend upward since 2013.  Consumption in March through December 2015, after the fire, was 2.6% higher than the same months in 2014.

Other supporters of capping GHGs from in-state refineries argue for the need to prevent imports of crude oil from the Canadian tar sands, which is substantially more GHG intensive (in production and refining) than other crude. (Though let’s not forget that the GHG emitted when you burn a gallon of gasoline in your car are still much greater than all the upstream GHG emissions from creating that gallon.) But just as reduced production in-state will push that production to more distant refineries, reducing California purchases of Canadian tar sands crude will push purchases of that crude to more distant refineries.  The effect of this supply “reshuffling” on world GHG emissions will likely be very small and may not even be a net reduction.

If capping GHGs at California facilities won’t do much to lower world GHGs, might it still lower local pollution? It might, because sometimes lowering a facility’s GHGs is indeed associated with lowering its local pollutants. But the fact that this association is very imperfect suggests that squeezing GHGs to reduce local pollutants will miss many of the opportunities for reducing local pollutants, opportunities that the facilities won’t have an incentive to pursue unless their local pollution is regulated directly.

And capping GHGs at industrial facilities will do nothing to reduce by far the largest source of dangerous local emissions, which is exhaust from trucks, ships and construction equipment.

Moreover, because designers of the state’s climate change programs understand that leakage and reshuffling are not really reducing global GHG emissions, and that they are likely to hurt the California economy, the programs include incentives (and some restrictions) to prevent these responses.  So, to the extent that facility-specific caps reduce in-state GHG emissions, they do so in ways that other state policies are specifically designed to prevent.

Hazardous air quality in disadvantaged communities is a very serious problem, but capping GHG emissions at facilities in those communities is not a serious solution.  And in the process it will undermine California’s programs and leadership in addressing climate change.  Let’s solve local air pollution by regulating (and taxing) it directly.

[1] The refining industry is also the subject of a proposed rule of the Bay Area Air Quality Management District (rule 12-16) that would cap GHG emissions from each refiner in the bay area. The Advisory Council to BAAQMD (of which I am a member) has put out a report recommending against adoption of rule 12-16.

I tweet energy articles, research and blogs (and a few opinions) most days @BorensteinS

Evidence of a Decline in Electricity Use by U.S. Households

It has been slowing down for decades, but is electricity use by American households now going down?

Americans tend to use more and more of everything.  As incomes have risen, we buy more food, live in larger homes, travel more, spend more on health care, and, yes, use more energy. Between 1950 and 2010, U.S. residential electricity consumption per capita increased 10-fold, an annual increase of 4% per year.

But that electricity trend has changed recently. American households use less electricity than they did five years ago. The figure below plots U.S. residential electricity consumption per capita 1990-2015. Consumption dipped significantly in 2012 and has remained flat, even as the economy has improved considerably.

Source: Constructed by Lucas Davis at UC Berkeley using residential electricity consumption from EIA, and population statistics from the U.S. Census Bureau.

Broad Decreases

The decrease has been experienced broadly, in virtually all U.S. states. The figure below shows that between 2010 and 2015, per capita residential electricity consumption declined in 48 out of 50 states. Only Rhode Island, Maine, and the District of Columbia experienced increases.

Source: Constructed by Lucas Davis at UC Berkeley using residential electricity consumption from EIA, and population statistics from the U.S. Census Bureau.  Electricity use per capita is measured in megawatt hours.

This pattern stands in sharp contrast to previous decades. During the 1990s and 2000s, for example, residential electricity consumption per capita increased by 12% and 11%, respectively, with increases in almost all states. Previous decades experienced much larger increases.

Energy-Efficient Lighting

So what is different? Energy-efficient lighting. Over 450 million LEDs have been installed to date in the United States, up from less than half a million in 2009, and nearly 70% of Americans have purchased at least one LED bulb. Compact fluorescent lightbulbs (CFLs) are even more common, with 70%+ of households owning some CFLs.  All told, energy-efficient lighting now accounts for 80% of all U.S. lighting sales.

It is no surprise that LEDs have become so popular. LED prices have fallen 94% since 2008, and a 60-watt equivalent LED lightbulb can now be purchased for about $2. LEDs use 85% less electricity than incandescent bulbs, are much more durable, and work in a wide-range of indoor and outdoor settings.

Source: Energy.Gov, “Revolution…Now”, September 2016.

Is this really big enough to matter? Yes! Suppose that between LEDs and CFLs there are now one billion energy-efficient lightbulbs installed in U.S. homes. If operated 3 hours per day, this implies savings of 50 million megawatt hours per year, or 0.16 megawatt hours per capita, about the size of the decrease above. Thus, a simple back-of-the-envelope bottom-up calculation yields a similar decrease to the decline visible in aggregate data.

Alternative Hypotheses

No other household technology is as disruptive as lighting. Incandescent bulbs don’t last long, so the installed stock turns over quickly. Air conditioners, refrigerators, dishwashers, and other appliances, in contrast, all have 10+ year lifetimes. Thus, although these other technologies have also become more energy-efficient, this can’t explain the aggregate decrease. The turnover is too slow, and the gains in energy-efficiency for these other appliances have been too gradual for these changes to explain the aggregate pattern.

Traditional economic factors like income and prices also can’t explain the decrease in electricity use. Household incomes have increased during this period, so if anything, income effects would have led electricity use to go up. Moreover, between 2010 and 2015, the average U.S. residential electricity price was virtually unchanged in real terms, so the pattern does not seem to be the result of prices.

Another potential explanation is weather. The summer of 2010 was unusually hot, so this partly explains why electricity consumption was so high in that year. But the broader pattern in the figure above is clear even if one ignores 2010 completely. Moreover, I’ve looked at these data more closely and there is a negative trend in all four seasons of the year: Summer, Fall, Winter, and Spring.

Rebound Effect?

This is not the first time in history that lighting has experienced a significant increase in energy-efficiency. In one of my all-time favorite papers, economist Bill Nordhaus examines the history of light from open fires, to candles, to petroleum lamps, to electric lighting. Early incandescent lightbulbs circa 1900 were terribly inefficient compared to modern incandescent bulbs, but marked a 10-fold increase in lumens per watt compared to petroleum lamps. However, as lighting has become cheaper, humans have increased their consumption massively, consuming thousands of times more lumens than they did in the past.

Economists refer to this price effect as the “rebound effect”.  As lighting becomes more energy-efficient, this reduces the “price” of lighting, leading to increased consumption.  An important unanswered question about LEDs is to what extent will these energy efficiency gains be offset by increased usage? Will households install more lighting now that the price per lumen has decreased? Will households leave their lights on more hours a day? Outdoor lighting, in particular, would seem particularly ripe for price-induced increases in consumption. These behavioral changes may take many years to manifest, as homeowners retrofit their outdoor areas to include additional lighting.

Conclusion

It is not clear yet whether U.S. household electricity use has indeed peaked or this is just a temporary reprieve. Probably the biggest unknown in the near future is electric vehicles. Currently only a small fraction of vehicles are EVs, but widespread adoption would significantly increase electricity demand. It is worth highlighting, though, that this would be substitution away from a different energy source (petroleum), so the implications are very different from most other energy services.

Source: Pexels.

Over a longer time horizon there will also be entirely new energy-using services that become available, including services that are not yet even imagined. The 10-fold increase in electricity consumption since 1950 reflects, to a large degree, that U.S. households now use electricity for many more things than they did in the past. The recent decrease is historic and significant, but over the long-run it would be a mistake to bet against our ability to consume more energy.

 

For more see Davis, Lucas W. “Evidence of a Decline in Electricity Use by U.S. Households,” Economics Bulletin, 2017, 37(2), 1098-1105.

Save the California Waiver!

How a “little” California vehicle standard prevented an urban “airmaggedon”

My midlife crisis did not lead to me to buy a German convertible — which would assist me in tanning my bald head and at the same time increasing the earth’s albedo — but rather to a rigid exercise regimen. I have discovered my love for running. Yesterday morning I left my hotel room in Berlin on a sunny day and headed towards the Reichstag along the river Spree. And I nearly choked. The stench of Diesel was pretty much unbearable. European cities are living through an “airmageddon”, with concentrations of some of the most toxic particulate matter in major urban centers breaking record levels in recent years on bad days.

Part of the problem is the incredibly high penetration of diesel engines in passenger cars. Germany registered 3.35 million new cars last year, of which 45.9% had a diesel engine and 2% had alternative (read hybrid or CNG) engines. The reason for this is that regular gasoline is expensive. The cheapest gas I could find in Berlin is $5.56 per gallon. A gallon of diesel is $4.58 per gallon. This difference is not due to the underlying cost of the fuel but the fact that diesel is taxed at a significantly lower rate. Also, using a VW Golf as an example, the diesel engine uses roughly 20% fewer gallons (excuse me liters) per mile than a power equivalent Otto (read regular) engine. The upfront price of diesel cars is higher, but for said Golf you break even after 18,000 miles and are printing money thereafter. Plus, diesel-powered cars are fun to drive as even a small Golf has the torque of a small tractor.

In theory diesel engines with the right filtering technology and regular checkups and adjustments are “clean”. But there is the problem that not everyone brings their diesel to an annual checkup. Further there is the little problem of criminal and reckless lying of companies like VW on the true emissions of these vehicles. Many European cities have introduced Low Emission Zones, where only the cleanest cars get to drive into the urban core and now some major cities are contemplating banning diesel cars outright from their downtowns. As my former student Hendrik Wolff points out, these policies have been reasonably successful  at improving air quality. Really fixing this problem for the Europeans is going to require a U-turn on diesel. A straightforward policy intervention would be abandoning the favorable tax treatment of this fuel. This is politically difficult, as French manufacturers have specialized in the production of small diesels. Any punishment of diesels would be regarded as failure to make Peugeot great again.

But why do we not have this problem in the United States? We know that we Californians are just a bunch of regulation-loving outdoor fanatics having massaged kale for breakfast. But this bunch of hippies has historically had the most stringent tailpipe emissions standards in the world. This was made possible by the so called “California Waiver”, which allows California under certain settings to set stricter standards than the ones required at the federal level. These tailpipe emissions standards were impossible to attain with the small popular diesel engines until very recently. And VW only managed to get there by committing fraud. European manufacturers historically had pushed to radically ramp up the increase of diesels sold in the United States. California regulation stopped this invasion of the diesels in its tracks. California was an appealing market for diesel vehicles because at the time they appeared to be more fuel and somewhat more greenhouse gas efficient. Further, under the Clean Air Act other states could adopt California’s standards without seeking approval from EPA (in fact in 2007, Connecticut, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon, Pennsylvania, Rhode Island, Vermont, and Washington had done so, which is of course a large share of the US market for passenger vehicles).

Does this mean diesel emissions are not a big deal in California and elsewhere in the US? Of course they are. Big trucks are largely powered by diesels and there are a massive number of trucks on US roads. CARB and the US EPA have done a lot to make sure that the diesel fuel going into trucks has become cleaner by requiring low-sulfur diesel. But is this regulation efficient? Is it working? The answer is that I have no idea. Economists have largely ignored regulation of big-rig trucks. The externalities from these trucks are likely significant in terms of pollution, congestion and accidents. But I am aware of next to no papers in the economics literature which have attempted to quantify these externalities.

So what would I like economists to do? Get to work on quantifying the externalities from big diesel trucks. And everyone should light a LED candle in support of the California Waiver. It will need all the support it can get for the foreseeable future.

Is the Duck Sinking?

This has been a spring of leaks. Most of you probably heard about the hole at the Oroville Dam. In my house, we’ve had leaks in both our skylight and our car. Yes, it’s great to be out of the drought, but like other Californians, we’re feeling a bit waterlogged.

All this water means that the hydro dams are cranking out lots of electricity. Reservoirs are at high levels, even before the major snow melt, so we’re letting a lot of the water run through the dams and producing cheap hydropower morning, noon and night.

If you believe the saying, ducks take to water well. But in the electricity world, the bountiful water is creating problems for the industry’s favorite waterfowl.

Long-time blog readers have heard several mentions of the “duck curve” – the aptly named graph that depicts energy demand net of wind and solar generation over the course of a day. I’ve reproduced one of the original versions below, which was created circa 2013 and shows projections out to 2020. Much of the focus has been on the duck’s neck – the rapid increase in non-renewable electricity demand as the sun sets on solar plants and people turn on lights.

 

As of last spring, the projections in the duck curve were materializing on schedule, as Meredith’s blog post described. During 2016, however, utility-scale solar PV capacity in the state grew by another 50%. As a result, net load in the middle of the day on a recent Sunday (April 9) bottomed out at 10,000 MW (see the green line in the graph below), instead of the 14,000 MW projected for 2017 in the forecast duck (the dark orange line labeled “2017” in the graph above).

Source: Daily Renewables Watch, CAISO (Thanks to the ISO for this and other great data sources.)

All the solar and hydropower have led to a new phenomenon – negative prices in the middle of the day. The blue line in the graph below depicts day-ahead prices for Sunday, April 9 in Southern California. For comparison purposes, the red line depicts day-ahead prices at the same location on the second Sunday in April 2012. Looks like another version of the duck, albeit drawn by a preschooler, and this time with price on the vertical axis.

Source: California ISO OASIS

Note that I picked April 9 as an example. Through yesterday, there were 19 days during March and April 2017 with negative midday prices in the day-ahead market in the South. They’re certainly more common on weekends, when people take breaks but the sun doesn’t. But, 7 of those 19 days were weekdays. Also, I’m focusing on the South, as that’s where most of the grid-scale solar is located. For the three days I checked, though, prices were also negative in the North.

Let’s first wrap our heads around what it means to have a negative price. On these days, if you were in southern California, the ISO was willing to pay you to consume electricity. Nearly all retail customers are on fixed tariffs that do not vary with wholesale prices, so they were still paying positive prices for electricity. But, if you were exposed to wholesale prices, you would have made more money the more electricity you consumed – just plug in your least efficient electric space heater and watch the dollars role in.

You may wonder why an electricity generator would be selling into the market when prices are negative. If you’re the owner of a large solar plant in the desert, for example, can’t you just turn off your connection to the grid, instead of having to pay to feed electricity into the market? Similarly, why would a gas or nuclear plant use costly fuel to sell into a market with negative prices?

There are a couple reasons generators might be willing to sell at negative prices:

• The production tax credit. Some renewables owners (mainly wind) are eligible for a production tax credit, which essentially pays them, in the form of a tax credit, for every MWh they produce. So, not producing means that they have to forego this credit. In theory, producers will pay to sell into the wholesale market as long as they’re paying less than the tax credit.
• The Renewable Portfolio Standard. Under California’s Renewable Portfolio Standard (RPS), utilities are on the hook to provide 33% of their electricity from renewable sources by 2020 and 50% by 2030. The utilities sign contacts with renewable providers and, while terms likely vary, the utilities want to meet their RPS targets. In the extreme, the utilities are on the hook to pay a penalty (which was $50/MWh early on) if they don’t. So, they generally want to encourage the renewable providers to produce. For example, under a very simple power purchase agreement, the utility would pay the renewable provider a pre-specified price per MWh irrespective of the wholesale market price, leaving them no incentive to shut down when prices are negative.
• Operating constraints. For some power plants, varying the output level entails high costs, particularly starting and stopping the plant. I think of those as analogous to the extra fuel, plus wear and tear, planes expend taking off. So, if it costs a lot to restart a nuclear plant, for example, you’re willing to pay not to have to turn it off to avoid incurring those costs.

In the graph below, we can see that the state’s lone nuclear plant, and even some thermal (which is essentially analogous to fossil-fuel) plants were still operating on April 9 when the prices were negative.

Source: Daily Renewables Watch, CAISO

The cost of turning plants on is also reflected in the real-time prices from April 9. Just like the day-ahead prices, they were negative in the middle of the day. But, they really spiked during the morning and evening ramps (to $1000/MWh!) when plants needed to turn on to meet the additional demand.

What do the negative prices tell us? At a fundamental level, they tell us that we have too much of a good and suppliers need to pay people to take it off their hands. Right now, California has too much renewable electricity. Emphasizing this point, a recent briefing from the California Independent System Operator noted that renewable “curtailments” were at record levels in March 2017, amounting to over 80 GWh, which is more than a typical day’s worth of solar production that month.

Is there anything to do about the negative prices? Negative prices certainly highlight the value of storage, where the basic idea is to buy low and sell high. Buying when prices are negative is especially lucrative. Standalone storage is still expensive, but the costs are rapidly declining. Increased electrification of transportation may provide one type of storage or at least flexible demand.

Another solution is to expose more retail consumers to wholesale prices, or find other ways to encourage customers to respond to real-time prices. Economists have bemoaned the disconnect between wholesale and retail pricing for years—maybe the prospect of being paid to consume electricity will help more people see the value of this?!?

In addition, generators that historically operated through the belly of the duck, including nuclear, combined heating and power, and conventional natural gas plants might be encouraged to reduce their output. For example, while it may not be practical to cycle nuclear generation on a day-to-day basis, maybe refueling outages could be scheduled for the spring, when excess supply problems are generally the worst.

Proponents of western grid integration note that removing barriers to exporting electricity will help California share some of its renewable electricity, especially when in-state demand is low and hydro supplies are high. (This is not intended as a comprehensive list of the solutions – an ISO discussion includes more here.)

To round out the post with another duck-ism, the duck may look calm, but we need to pay attention to what’s going on below the water line – the zero price line in this case. The duck is paddling furiously, as operating an electricity system with a lot of renewables isn’t easy.

Benefiting from Green Jobs

The renewable energy industry and its proponents regularly draw attention to the industry’s job creation potential. For example, the American Wind Energy Association reported that the US wind industry supported 88,000 jobs at the start of 2016, a 20% increase in one year. The Solar Foundation announced there were over 260,000 solar workers in 2016, which was a 25% increase over the prior year. By contrast, the coal extraction employed only 74,000 workers in 2016, and coal power plants employed another 86,000 workers.

The creation of so-called “green jobs,” such as those in wind and solar, is often cited as a justification for promoting renewable energy through tax credits, renewable portfolio standards and net energy metering.

I recently had the privilege to moderate a panel discussion on green jobs at the Berkeley Energy & Resources Collaborative’s (BERC) Energy Summit. The panelists were the Energy Institute’s Reed Walker; Carol Zabin, Director of the UC Berkeley Labor Center’s Green Economy Program; and Anna Bautista, Vice President of Construction & Workforce Development at Grid Alternatives.

Many economists remain skeptical of green job claims as a motivation for policy. Severin Borenstein has emphasized that job creation claims usually cherry pick data. To understand the effects of a policy on employment one needs to consider the effects throughout the economy. If a policy is promoting a more expensive form of energy, it could very well be destroying jobs on net.

Our panel discussion didn’t address these issues. Instead, the discussion explored equity issues surrounding green jobs. Who benefits? Who doesn’t? Are green jobs “good” jobs?

I left the discussion doubtful that policymakers should view the growth in the number of green jobs as a solution to job losses in other, less green, parts of the energy sector.

Green Jobs Not Much Help to Displaced Coal Miners

At the same time as solar and wind employment is skyrocketing, coal industry jobs are plummeting. Energy Information Administration data shows a 25% drop in coal mining employment from 2008 to 2015. In 2015, 94 coal-fired power plants with a capacity of nearly 14,000 Megawatts closed. Read more about the decline of coal here.

“Coal Miners Memorial – Richlands” by Big Ed’s Photos is licensed under CC BY-NC-ND 2.0.

Reed Walker has done research showing just how painful job losses can be to workers. His research looked at how the 1990 Clean Air Act Amendments affected workers in newly regulated firms and industries. The basic idea is to compare workers’ earnings trajectories in newly regulated sectors compared to similar workers in other sectors, before and after the regulations went into place. While many workers were unaffected by the regulatory change, the present-discounted earnings losses for displaced workers after the policy change exceeded their pre-regulation annual earnings. When workers lose their jobs and have to find employment in another industry, their incomes drop significantly, on average.

A recent US Department of Energy report explains why moving from coal mining to renewable energy would be an especially painful transition for workers:

First, the coal job losses and renewable job gains are happening in different places. This means relocation costs pose a significant barrier to workers switching from coal to renewables. Second, renewable energy jobs pay less. The median wage for solar installers is 20% below that of coal miners. Third, the skills needed in an extractive industry like coal mining are very different from those needed in a construction industry like solar or wind.

Putting forward green job creation as the solution to coal industry workers’ woes is unlikely to be well received by miners.

Green Jobs Not Necessarily a Path to the Middle Class

While coal miners might not be landing green jobs, other workers are. Are green jobs sustainable opportunities for these workers? Analysis suggests the reality is mixed.

The majority of green jobs in solar are construction jobs, that is, installing systems. A 2016 report from UC Berkeley’s Labor Center by Betony Jones, Peter Philips and Carol Zabin analyzes differences between construction jobs in the utility-scale segment of the renewable energy industry and jobs in the rooftop solar industry. The study finds that in California most workers in the utility-scale segment earn wages and benefits, and receive training that can sustain a middle class lifestyle. The report attributes this to the fact that utility-scale projects in California employ workers who belong to labor unions or receive equivalent wages and benefits to union members.

Jobs in rooftop solar, on the other hand, pay lower wages and offer more limited benefits. The Solar Foundation jobs report shows that most solar installers (69%) work on these lower paid residential and commercial distributed solar projects, not on the higher wage utility-scale projects.

Workers on utility-scale renewable projects in California receive union electrician wages, which are higher than rooftop solar installer wages.  SOURCE: Betony Jones, Peter Philips and Carol Zabin. The Link Between Good Jobs and a Low Carbon Future, July 2016, p. 15.

The report stops short of arguing that renewable energy policy should favor utility-scale renewable energy over roof-top solar. However, in a separate blog, Jones and Zabin cite one of Severin Borenstein’s blogs and point out that environmental and economic objectives provide a rationale for policymakers to favor utility-scale projects over rooftop solar.

Green Jobs Create Opportunities for Some Workers

Green jobs may not be the solution to coal country’s woes or an inevitable path to the middle class. Yet these jobs are providing meaningful opportunities for thousands of people.

In 2016, solar ranked second in employment among energy sectors behind oil/petroleum, but ahead of natural gas. Wind ranked seventh, ahead of nuclear.

Groups like Grid Alternatives are trying to increase the accessibility of renewable jobs to the highest need communities. Grid Alternatives is a non-profit organization that trains people coming from low income and minority communities to work in the rooftop solar industry. Rooftop solar jobs may not be as attractive as utility-scale jobs, but Grid Alternatives’ success in recruiting candidates show that these jobs are still desirable to some workers.

“Wayne National Forest Solar Panel Construction” by Wayne National Forest is licensed under CC BY 2.0.

Setting Realistic Expectations

The growth in the green jobs sector has been extraordinary, and many people have benefited, but green jobs do not cure all energy sector job woes. I worry that proponents of green jobs have set expectations too high.

Policymakers and advocates should honestly address the challenges presented by trends in the energy industry. Displaced workers need a sufficient social safety net and workforce training to prepare them for the jobs they are most suited for and most interested in. These may not be green jobs, and that is ok.

Meanwhile, where green jobs are being created, workforce training that connects a wide range of workers to these jobs makes sense. This will help put more green in the hands of people who need it most.

Renewables Dis-integration?

This post is co-authored with Duncan Callaway.

Ahhhh Hawai’i, where the waves are big, the beaches are long, and the renewable energy ambitions are large:

Source                                                                           Source

As you may have heard, Hawaii has set a goal of 100% renewable energy penetration by 2045. This is pushing the Aloha state to the bleeding edge of renewable energy integration.

We were lucky enough to spend our spring break at a conference hosted by our colleagues at the University of Hawaii. Although the focus of the conference was on the integration of renewables into the grid, there was lots of talk about possible dis-integration.

Living off-grid might seem like a pretty out-there idea. It’s true that, in the past, “grid defection” has been limited to survivalists and bohemian-types who can get excited about living like this:

Source

But with solar PV and storage costs falling relative to conventional grid-supply systems, the economics of grid defection are changing fast. And off-grid living is not what it used to be:

A Hawaii developer is planning a 410-home project that would become the first off-grid community of this magnitude.

If grid defection takes hold, this would take concerns about stranded assets and utility death spirals to a whole new level. Grid dis-integration is a development we should be paying attention to.

The economics of grid defection

Let’s start by distinguishing a grid defector – the subject of this blog-  from a load defector (that’s you if you have PV panels on your roof).

“Grid defectors” are consumers who fully disconnect from the grid and supply their electricity needs with their own power generation. “Load defectors” remain grid-connected, but get some fraction of their electricity from a source other than their incumbent utility. Importantly, load-defecting solar PV customers continue to rely on grid services. They draw power when demand exceeds their solar supply, and inject surplus generation when there’s excess supply.

The economics of solar PV load defection already pencil out in many places (even the Kentucky Coal Museum!). For many consumers (the US passed the 1 million solar PV installation mark last year), net bill savings appear to exceed private investment costs. This is partly due to falling PV technology costs. But it’s also thanks to retail prices that can significantly exceed the variable costs of supplying electricity, net metering policies, and other subsidies. For example, the graph below shows how Hawaii’s residential prices per kilowatt hour (kWh) reflects not only the variable costs of generation (green line), but also a substantial amount of fixed cost recovery (black line). When a net metered solar customer generates her own power, she avoids paying the sizeable fixed cost component that was being collected through her volumetric payments for electricity.

Source: This graph shows the average residential electricity price in Oahu. The green line measures the generation component (fuel costs and costs of buying energy from independent power producers). The black line measures non-fuel and fixed costs.

The economics of grid defection are more complicated. If you want to unplug from the grid AND maintain the same level of reliability and power quality, you’ll need to make investments in a battery (or a backup generator) in addition to PV. In 2014, analysts at the Rocky Mountain Institute estimated that an off-grid PV-battery system would average about 80 cents/kWh in Hawaii. The graph above shows how 80 cents/kWh is still a long way from grid parity.

We’ve made some updated calculations with an eye towards rapidly declining solar PV and storage costs (with the help of Berkeley graduate student Jonathan Lee). The graphs below show just how fast PV and battery prices are falling.

Solar PV source: Tracking the Sun IX                                                                 Battery source: https://www.bloomberg.com/news/articles/2017-01-30/tesla-s-battery-revolution-just-reached-critical-mass. While the battery figure shows costs for EV batteries, these cost reductions carry over.  It’s been estimated that over 18 months in 2015 and 2016, grid-connected battery system costs fell 70 percent.

Without getting too far into the weeds, we use a moderately aggressive scenario for solar and storage costs ($0.40/W for solar panels, $100/kWh for batteries), plus a host of other assumptions for system installation costs. We estimate that a stand-alone system would cost about 30 cents per kWh (assuming less than an hour a year of supply shortage). This is within the range of residential electricity prices in recent years (see above graph)… and that’s before accounting for state and federal incentives.

That grid defection could actually be cost-effective may seem inconsistent with everything you thought you knew about economies of scale in electricity generation. It’s true that generation costs per kWh are lower when electricity is generated at utility-scale, versus on your rooftop. The catch is that, as solar PV and storage costs fall, the additional cost associated with generating and storing electricity on a smaller scale could be more than offset by the transmission/distribution/retail service costs you can eliminate with a decentralized system.

If PV and storage costs get low enough, it could become more efficient to start grid dis-integrating (versus making additional investments in grid infrastructure). This is a mind-bending concept for those of us accustomed to thinking that the grid simply can’t be beat.

Stranded assets of the future?

Preparing for grid dis-integration?

Renewable energy developments in Hawaii can read like postcards from the future. Hawaii has been on the forefront of the distributed solar revolution, with PV penetration exceeding 15 percent on some islands. The state was the first to shut down net metering in response to costly solar load defection. Today, Hawaii is anticipating the next challenge that is grid defection.

Economists prescriptions for dealing with inefficient load defection emphasize cost causation: set real-time per-kWh prices at true variable costs. But there’s a hitch. When rates are set to recover real-time marginal costs, revenues can fall far short of total system costs. These residual fixed/sunk costs have to be recovered somehow.

If there’s no risk of grid defection, there’s room to be sloppy about recovering these residual fixed costs with some kind of fixed charge. But in a place like Hawaii, sloppy fixed cost recovery could lead to inefficient grid dis-integration in the not-so-distant future. So what’s the right way to recover sunk investment costs? Lumping them into customers’ fixed cost charges would lead to early/inefficient grid defection. Lumping them into per kWh costs has led to inefficient load defection. Exit fees could offer a solution. The socialization of cost recovery via general tax revenues has also been suggested. The jury in Hawaii is still out.

Grid defection may seem like a long way off for the rest of us. But the regulatory paths chosen in Hawaii’s renewable energy laboratory can inform decisions that the rest of the country will ultimately be confronted with. We’ll be watching this Hawaiian grid dis-integration story closely. And hoping to visit those long beaches and big waves again sometime soon.

 

 

Missing Money

If you work in electricity markets and someone mentions “missing money,” it doesn’t make you think of a lost wallet or a sticky-fingered bank teller. Instead it evokes regulatory policies that lower the revenues electric generation companies can make in wholesale markets. Missing money is more than just a concern of corporate CEOs and shareholders. It could soon be a serious impediment to a low-carbon economy.

Money has been going missing for many years, according to owners of power plants.  They’ve used the term for more than a decade to refer to the fact that wholesale electricity markets have price caps (mostly between $1,000 and $10,000 per MWh) that constrain how much sellers can make when supply is tight. Without that income, generators argue, it may not be profitable to build new capacity, or extend the life of existing capacity, that is needed to meet demand.

More recently, the definition of missing money has been expanded to include the price impacts of subsidized or mandated renewables generation. In California, New York and many other states, wind and solar are pushing down wholesale prices and making continued operation of some nuclear and fossil fuel generation unprofitable.

That may make some environmentalists cheer, but it makes many regulators worry, because wind and sun are not very predictable or controllable. In some cases, grid operators have said those conventional generators are needed to assure that demand can be met locally or systemwide and have offered them out-of-market payments to stay open.

For instance, new subsidies are under consideration for some nuclear plants to compensate for their missing money, but those proposals are triggering objections from gas-fired and coal-fired generators, because keeping the nukes open worsens their own missing money problem.

California’s Topaz Solar Farm

In a meeting I attended a few years ago, a solar advocate stated proudly that when solar enters a market wholesale prices always drop. I wondered aloud how producers in food, auto, steel, or any other industry would feel about government policy that drives down prices in their markets by subsidizing or mandating the use of higher-cost supply. (At the time, the solar power was much higher cost, even accounting for most estimates of the costs of GHG emissions from fossil-based sources.)

Of course, governments intervene in many energy and energy-related markets with mandates and restrictions that affect firms unevenly.

• Automakers must meet the federal Corporate Average Fuel Economy standard;
• Gasoline sellers must blend in ethanol to meet the federal renewable fuels standard (as well as the Low Carbon Fuel Standard in California, and the 10% ethanol minimum in Minnesota, among other state mandates);
• The electric vehicle mandate in California lowers the demand for gasoline (and raises the demand for electricity), as well as lowering demand for conventional vehicles;
• Some areas now require increased use of biogas (captured methane from landfills, dairy farms, and other natural sources) to replace fossil-based natural gas;
• Energy efficiency programs lower the demand for electricity everywhere.

Yet, you don’t hear talk of the missing money problem in the auto, oil refining and retailing, or natural gas markets, even when regulations reduce demand for their output.

Missing money is often discussed in terms of fairness: When policies change and the values of existing investments are affected, are losers due some compensation? That is a more pressing question in electricity, where the accelerated renewables rollouts in some places have lowered the quantities incumbents sell and dramatically reduced the wholesale prices they receive (as Meredith discussed last May).

Still, what makes electricity truly different is not the fairness issue, but the electrical engineering: supply and demand must balance every second in order to keep the grid stable. The grid operator has few, and very blunt, instruments to affect demand, so it relies almost entirely on controlling supply. In the short run, missing money can threaten the viability of plants that are needed for balancing the system, potentially requiring much more expensive alternative supply options, or forced reductions in demand.

There is also a long-run efficiency concern: If firms see an unstable regulatory environment where capital values can swing wildly with regulatory decisions (what former Duke Energy CEO, Jim Rogers, calls “stroke-of-the-pen risk”) they are less inclined to invest, even if capacity is desperately needed and may be well-remunerated in the short run.

These problems will almost certainly worsen in places where renewable energy targets are increasing, like Hawai’i with its 100% target by 2045, and California, which may soon adopt a similar goal.

In other industries if government policies reduce investment in supply capacity, prices rise and consumers purchase less for a while. That sort of market adjustment is not an option in electricity markets as they are currently configured.

So, if a state wants to ramp up renewables, but the missing money problem is such a political, economic, and, ultimately, operational barrier, why not offer compensation for the disappeared dollars. Ah, if only it were that easy…

You see, at some point every firm discovers they are missing money. They invest in a market and then demand turns out to be softer than they expected, or other firms also invest in the market creating over-supply, or their costs rise (or their competitors’ costs fall), or they run into unforeseen logistical problems, or any number of other reasons that firms lose money. Money goes missing due to bad management or just bad luck.

All of those reasons are present in electricity markets as well, and are part of why many generators’ income statements look more red than black these days.  How big a part? That’s a very tough question to answer.  Soft demand, for instance, interacts with expanded renewables to push down wholesale prices.  Any attempt to allocate responsibility will be subject to great uncertainty and, with much money on the line, to endless dispute. Plus, it will depend on what you think generators should have known and when they should have known it about renewable energy policies.

And even if we could sort all that out, there would be a disturbing asymmetry in such a compensation policy. We don’t tax a gas plant’s “found money” when mercury restrictions drive out coal-fired competitors, or levy a fee on nuclear plants in markets that start to price CO2 emissions, thereby driving up the market price and their profits.

Ok, even if we don’t compensate losers in general, can we address the grid reliability issues that may result?

Yes we can, but it’s not pretty and may not look much like a market.  At the system level, it means the grid operator procures “capacity” (or requires retail electricity suppliers to do so). Capacity is the ability to deliver electricity, though the obligation to do so is sometimes not fully specified or doesn’t match up well with what’s actually needed for grid reliability.  (A new Energy Institute working paper (WP-278) does an excellent job of explaining this murky topic.)

For particular local supply concerns, the grid operator identifies generation that is especially critical and signs contracts for their services in a bilateral negotiation. The plant operator’s threat is to shut down, so it may exaggerate its costs in order to push up the contract price, while the grid operator wants to get a reasonable price, but still assure that the operator is able to cover its costs. Starts to sound a lot like regulation, doesn’t it?  In fact, it can lead back to cost-of-service compensation for the plant. Everything old is new again.

My point is not that it’s impossible to address the missing money problem(s), or that we should give up on competitive wholesale electricity markets. Research has shown that electricity markets create a lot of economic value (in efficient operation of fossil generation and nuclear generation, as well as efficient dispatch of electricity grids).

But at the same time, we need to move to lower carbon generation technologies. That will create economic disruption even if we do it primarily through a price on carbon, and especially if we don’t. If we are lucky, solutions will be worked out that keep grid disruption to a minimum and maintain incentives for efficient investment. But that will require thoughtful understanding of the missing money problem and careful weighing of the array of imperfect policy responses.

I tweet news and research on energy most days @BorensteinS

 

Four Reasons Why Chile Is the Biggest Solar Market in Latin America

With the U.S. Federal government pulling back sharply from efforts to address global warming, I’ve found myself looking outside the United States for good news on climate.  One of the most compelling recent trends comes from Chile, the little-engine-that-could when it comes to solar power. Despite having only 3% of the population of Latin America, Chile has almost three-quarters of the installed solar generating capacity.

Some have pointed to the near-zero electricity prices, inadequate transmission, and other challenges in the Chilean market to suggest that these investments were somehow a mistake, or unsustainable. But I don’t buy it. Here are four reasons why Chile is, and will continue to be, a very attractive market for grid-scale solar.

#1: Electricity Demand Growth 

Electricity demand in Chile is forecast to increase 2.6% annually over the next two decades. Not impressed? The same number for the United States is 0.7%. Now it’s true that the last couple of years have seen slow growth, with the Chilean copper industry hurt by low copper prices in 2015 and 2016. But copper prices have been increasing since November and, moving forward, electric vehicles and batteries are expected to significantly increase global demand for copper. Historically, with the exception of a few hiccups, Chilean electricity demand has grown steadily for three decades.

Source:  World Bank Development Indicators.

Most of the future growth is expected to come, not from mining, but from Chile’s residential and commercial sectors. This is consistent with recent work by Catherine Wolfram and co-authors who find large scope for energy-demand growth in middle-income countries like Chile. In the coming years, Chile will continue to close the development gap between itself and high-income countries like the United States, and this means widespread adoption of lots of energy-using devices.

#2 The Atacama Desert

At-a-ca-ma!  Dry? The Atacama Desert in Northern Chile is the driest place on the planet.  Some parts of the desert have never seen a drop of rain since recordkeeping began. The Atacama is high, flat, and bone dry — the ideal location for solar. The sun beats down day after day with rarely a cloud in sight with some of the highest levels of solar radiation anywhere in the world.

Chilean President Michelle Bachelet inaugurating the Amanecer Solar Plant in June 2014, Source: Creative Commons, Gobierno de Chile

Also important is that the Chilean government is expanding transmission, with an aim to connect Chile’s “Northern” and “Southern” grids by 2018. This is key for solar producers in the Atacama because the bulk of electricity demand is in the South, and the new transmission link will allow them to access Southern customers.

#3 Limited Natural Gas and Coal

Another key factor for Chile is that it does not have significant reserves of natural gas.  Chile has two LNG import terminals, but LNG is expensive, averaging two- to three- times typical prices for natural gas in North America. This is expensive enough that natural-gas fired plants struggle to compete with unsubsidized grid-scale solar.

The Mejillones LNG terminal in Northern Chile, Source: Interfax

Moreover, although Chile has rich copper and other mineral resources, it has very little coal. Coal can be imported, of course, but there is political opposition in Chile to coal based on environmental concerns.

 #4 Commitment to a Free Market

It doesn’t get mentioned as frequently, but another important factor is Chile’s commitment to the free market. Chile has been viewed as a bastion for free market economics since Milton Friedman and the “Chicago Boys” wielded great influence during the 1970s and 1980s. Deregulation and privatization have not always been good for Chile’s environment, but in this case the transparency of the market and lack of government interference has helped give private investors the confidence to enter the market aggressively. All electricity generation in Chile is privately owned, and there are over one dozen international firms operating in Chile’s solar sector.

The Chilean solar boom has occurred without any explicit tax on carbon or subsidy for renewables. The favorable conditions in Chile have nonetheless led to eye-poppingly low prices for solar. During auctions in August 2016, for example, the winning bid was $29.10/MWh, the lowest price ever for solar. Companies have had some trouble financing projects at these low prices, but the economic viability of these projects hinges on energy demand and supply forecasts, not about regulatory or political risk, which Chile has effectively minimized through its long-time laissez faire approach to markets.

Comparison to Mexico

The next big solar boom in Latin America is expected to happen in Mexico. Nearly half of projected solar installations for 2017 are in Mexico, and large contracts have been signed for 2018 and 2019. These investments may all go according to plan, but Mexico’s electricity market is less open than the market in Chile, so it makes these investments more risky for investors.

Perhaps the more important difference, however, is that Mexico has access to low-price North American natural gas. Natural gas is already the biggest source of electricity generation in Mexico, and 60% of new capacity between now and 2020 is expected to come from natural gas. Low-price natural gas doesn’t make it impossible to invest in renewables, but it does make it harder.

Conclusion

I’d be very interested if readers can come up with other potential explanations. But I’m pretty sure that these four explanations all play an important role. With good reason, Chile is the biggest solar market in Latin America. And, looking forward, none of these factors is likely to change overnight. After all, the Atacama has been dry for over 3 million years.

Chile is a fascinating case study that illuminates some of the broader underlying economics behind electricity markets. Some of these factors, like robust electricity demand growth, are present in a large number of other countries. Other factors, like the lack of natural gas reserves, are more unusual, though not unique to Chile.

Source: Reve

A Tale of Two Standards

Economists have long complained about Fuel Efficiency standards. Are we happy now?

The past 50 days felt like the beginning of a game of environmental policy Jenga. The new administration is starting to pull pegs from the tower of environmental and energy regulations slowly built up over the past 50 years. Whether this tower will crumble is a legal question, which I am not qualified to comment on, so I’ll stick to economics.

Maybe the most significant development is President Trump’s call for a review of the Corporate Average Fuel Economy standards, which were updated under the Obama Administration requiring the auto industry to deliver a fleet average of at least 54.5 mpg by 2025. This means that the average new car sold would achieve roughly the fuel economy of a current day Toyota Camry Hybrid. This is no doubt ambitious and US manufacturers have complained publicly about the significant costs this would entail, which would be largely passed through to consumers (or so they claim).

Let’s think about the economics of standards for a minute. Standards come in as many flavors as Ben and Jerry’s ice cream. The CAFE standard was introduced after the 1973-4 oil embargo and is so complex that a number of my colleagues are spending significant parts of their careers understanding it and its consequences. The most recent version of the standard regulates vehicles by class (passenger cars vs. light trucks) and within class by footprint (trackwidth times wheelbase). The table below shows what the proposed standards are trying to achieve (Source: Wikipedia. Sue me.)

If you do the back of the envelope calculation, this is equivalent to a roughly 28% improvement in gallons per mile (the right measure) from the 2017 model year to 2025 for all passenger cars and small footprint light trucks and a 17% improvement for the bigger “light” trucks. This sounds like a lot. And the car industry is crying wolf. A number of think tanks are immediately translating this burden into massive domestic job losses. However, if you read the collected works of the brilliant former EI student Chris Knittel, you will know that auto manufacturers have funneled technical progress into more power rather than into more fuel efficiency. For example, a 1980 Honda Civic in its base model had 55 horsepower which got 34 mpg. The 2017 base model has 158 horsepower and gets roughly 35 mpg. Same fuel economy – thrice the power. The argument has forever been: “Power. It’s what consumers demand”. Chris’ paper suggests that the historical improvements in fuel efficiency amounted to about 2% per year. The Obama goals are about 3% a year. So an acceleration would be required, yet it’s not a moonshot.

The issue is of course that emissions of greenhouse gases and local pollutants from the transportation sector in the United States account for 26% of greenhouse gas emissions and a significant share of local pollutants – toxics and particulate matter. It is well understood that there is an underlying market failure, whereby consumers do not pay for the full social cost of their actions resulting in excessively large emissions of these damaging compounds.

Consumers left alone have no incentive to do the right thing. The regulator is supposed to step in here and provide consumers with incentives to make socially optimal decisions. An emissions tax is the first best thing to do. In its best version there would be a separate tax for the local pollutants and the global pollutant. We would cheer loudly.

A gasoline tax is second best. Half of us would clap.

A very distant third+ best is a standard, such as the CAFE regulation discussed above. Hence the average economist would have gladly done away with these standards in exchange for the more efficient policy instruments. CAFE standards have significantly reduced emissions of greenhouse gases by increasing the fuel economy of the fleet. One can make nice arguments about how this has benefitted the US in the form of less reliance on foreign oil as well. However, it is also clear that these standards are an expensive and inefficient way to regulate these emissions.

So, you ask, do all economists hate all standards? The answer is no. At least for this economist, there are many standards that make a great amount of sense. Take for example appliance standards. The individual consumer frankly has no idea how much electricity a refrigerator consumes. In fact, I would wager that the average person would have no idea what units electricity is measured in for billing purposes and what price they pay (I am not even hoping for knowledge of marginal price). Since the customer does not observe this information, (s)he has no incentive or ability to make an efficient investment decision when it comes time to buy that new fridge. Appliance standards set targets that regulate the energy efficiency of these durable devices, so we get an average efficiency of appliances moving us closer to a privately and socially optimal level of electricity consumption. So, in settings where the efficiency of a device is not observable, I am gung ho for technical standards (that optimally would also take into account the extensive margin – size – of the device as Ito and Sallee point out).

For gasoline, this is not the case. The vast majority of consumers know how many miles their car goes on a tank and how much it costs to fill a tank. They hence observe the efficiency of the equipment when they purchase it. It is on a big label on each vehicle in fact. This is admittedly also true of refrigerators. However, in real world usage situations where your teenager floors the car at each traffic light and opens the refrigerator door 48 times a day to see what’s in there, it is much easier to gauge the car’s consumption of gas than the fridge’s consumption of electricity.  Many of us would argue it would be much more effective to price the emissions (and safety) externalities of vehicles directly instead of regulating them via an inefficient fuel economy standard.

But, and this is a big “but.” Like HUGE. If the choice is between a CAFE standard and no regulation, I might very begrudgingly take the CAFE standard. I would assume that not all  environmental economists would agree on this point, since CAFE is an extremely expensive way of regulating carbon emissions. Jacobsen (AEJ 2013) finds that the old CAFE standards cost a whopping $616 per ton of CO2 abated. But it does not only regulate carbon emissions, it indirectly also controls vehicle weight to a certain degree, which Michael Anderson and I show has significant external costs in terms of fatality and injury risk in collisions. CAFE is far from efficient, but it does regulate the externality, which is massive. Maybe the most powerful, but least well documented argument in favor of CAFE is it will somewhat accelerate technological progress, and some of that will spill over into the rest of the world’s markets. And the rest of the world is buying a boatload of cars.

Abandoning any kind of emissions regulation from the transport sector is simply wrong. It’s basic economics. While I see no chance for a reasonable carbon tax (say $39 ton or higher), I would hope that reasonable voices on the hill would continue to push for one.  In the meantime, CAFE standards to me are better than no regulation.

I like a good game of Jenga. But when the tower crumbles, we will bury future generations’ welfare under a pile of pollution. This is not what we should be doing.