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.

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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.

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.

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.

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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:

surfSource                                                                           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:grid


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:solarhouse

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.

robertsgraphSource: 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.

pricegraphSolar PV source: Tracking the Sun IX                                                                 Battery source: 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.

powerlinesStranded 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.



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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.

MissingMoney2Money 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).

MissingMoney3Still, 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?

MissingMoney1Yes 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


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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.


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.

sunedison fotovoltaica Chile

Source: Reve
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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.

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What Counts as Success in Energy Efficiency Programs?

Most countries’ plans for reducing greenhouse gases rely heavily on energy efficiency programs. So, even if you aren’t an energy efficiency specialist, it’s important to understand how, and how well, those savings get counted. When it comes to measuring the impacts of energy efficiency programs, this means disentangling which energy consumption changes can be credited to the program, and which would have happened anyway. For those of you who aren’t steeped in the intricacies of this energy efficiency accounting exercise, let me provide a bit of background.

My husband often compares electricity market regulations to the rules for Dungeons & Dragons, a 1980s gaming craze that captivated some – mostly pre-teen boys – and bemused everyone else. It involved multiple 100+ page rulebooks that explained things like how many “experience points” a character might get for slaying a certain monster.

Energy efficiency policy can be as complex as Dungeons & Dragons. This isn’t a criticism. It’s endemic to energy efficiency policy for one fundamental reason: it’s really difficult to measure the savings from energy efficiency programs. There’s no meter that runs backwards to measure those savings. As a result, there are lots of discussions and evolving rules on how to measure them.

To take an example, imagine that your local utility offers rebates for homeowners who buy energy efficient hot water heaters. The task for the regulators is then to assess how much less energy homeowners will consume because of the rebate program.

One of the core issues is figuring out how many homeowners would have bought an efficient hot water heater even without the utility rebate. Those who would have are labeled “free-riders” – they get paid the rebate for doing something they would have done anyway.

A standard method for measuring savings from a rebate program is to first develop an “engineering estimate” of the savings associated with each hot water heater replacement and then add those savings up across everyone who applied for a rebate. This represents the “gross” savings.

The next step is to figure out what share of homeowners are free-riders and then take that share out in order to estimate the “net” savings. Sometimes, regulators ask consultants to survey homeowners about whether they would have bought the efficient hot water heater absent the rebates. This can be an inherently difficult process – effectively asking people to construct a counterfactual world for their past selves.

Colleagues and I have argued elsewhere that there are better ways to develop estimates of savings from energy efficiency programs, including randomized controlled trials and other quasi-experimental approaches. One of the advantages of these approaches is that they provide an estimate of the net-to-gross ratio. (They can also highlight other shortcomings of the engineering estimate approach I described above, for instance if the engineering estimates are too optimistic.)

For instance, a few years ago, Judd Boomhower and Lucas Davis applied a quasi-experimental technique to evaluate a “cash-for-coolers” rebate program in Mexico that subsidized refrigerator and air conditioner replacements. They found that even without the rebate about half of the participants would have replaced their inefficient appliances with a more efficient one, and many would have done so for a lower rebate than they were paid.

Despite this sort of evidence, I’ve heard several energy efficiency advocates, recognizing the difficulty in calculating net-to-gross ratios, assert that it doesn’t really matter. They say things like, “The climate doesn’t care about the difference between net and gross savings.” The implication seems to be that we should pat ourselves on the back for achieving the gross savings.

But, focusing on gross savings is problematic for two reasons:

  • We will not solve climate change by focusing only on U.S. energy customers. (This point has come up repeatedly on this blog, such as here and here.) One implication of this is that we need to export the right policies to the rest of the world. So, it’s essential to figure out whether an energy efficiency program causes people to take certain steps or whether they would have taken them anyway.

Imagine, for example, that the hypothetical utility rebate program for hot water heaters has a low net to gross ratio (i.e., a lot of people would have bought the efficient hot water heater even without the rebate). Maybe they would have bought the efficient hot water heater because of another energy efficiency policy, such as efficiency standards. We need to know if standards are doing all the heavy lifting  so that other parts of the world will adopt the most effective policies.

And, it’s really true that other countries are watching what we’re doing carefully. A couple months ago, I spoke to a deputy energy minister from the Pakistani province of Punjab, who was more up-to-date on California net-metering policy than me.

  • It’s a waste of money. Paying people to do something they would have done anyways is not a good use of taxpayer, ratepayer or anyone’s money. If there aren’t very many cases (i.e., if the net to gross ratio is high) and it’s the inevitable outcome of an otherwise very successful program, we can live with it. But it’s important to know the net to gross ratio and not just focus on gross savings, so that we know how much money is going to waste.

Beyond this, there could be distributional implications. For example, if low-income consumers are less likely to participate in energy efficiency programs, then their rates are being used to subsidize higher income customers to do something they would have done anyway. That’s not just inefficient use of funds, it’s unfair to the neediest in our society.

So, we need to continue to sharpen our pencils and apply state-of-the-art measurement techniques to energy efficiency programs. It’s critical to know how much bang we get for every energy efficiency buck, especially in a time when the national political winds are likely to push back against government energy efficiency programs. The rest of the world is watching!

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How Would Energy Prices Adjust to the Border Adjustment Tax?

In a recent Saturday Night Live episode, Baldwin-as-Trump is casting about for clever ways to get Mexico to pay for the border wall. But with each attempt, the joke is on him, and Americans are left footing the bill.



The following week, in what could be construed as life-imitates-art, White House Press Secretary Sean Spicer announced a plan to finance the wall: Use the Congressional Republicans’ proposed tax reform “as a means to tax imports from countries that we have a trade deficit from, like Mexico”.

This was a confusing development on many levels. For one thing, it reversed Trump’s earlier opposition to the border adjustment tax proposal on the grounds that it is “too complicated”. Moreover, Trump’s key arguments in favor of the border adjustment (i.e. boosting employment and made-in-the-USA exports) are inconsistent with what the border adjustment is designed to do (raise revenues in a trade-neutral way).

In the wake of this announcement, there’s been much speculation about how this proposal would affect the US economy. Energy markets have been getting lots of attention because the petroleum sector could be particularly impacted. Some analysts and media reports are projecting gasoline prices increases on the order of 30-40 cents per gallon. But proponents of the plan –including some world-class economists– maintain that these price increases are illusory.

Before unpacking these back-and-forth disagreements about what the impacts would/would not be, let’s quickly review what’s being proposed (and why).

A Better Way?



Republicans are laying the foundations for a major overhaul of the tax code. The Ryan-Brady GOP plan, “A Better Way: Our Vision for a Confident America”, proposes a number of substantial changes in how businesses pay taxes. The current system taxes corporate income – net of costs of goods sold, wages, depreciation, etc.-  at a relatively high marginal rate of 35%. The new proposal would replace this tax, which many view as excessively burdensome, with a ‘destination-based cash-flow tax’ (explained in more detail here). Cash-flows (revenues net of wages and asset purchases which can be written off immediately) are taxed at a lower rate of 20%.

All else equal, this reduction of the corporate tax rate would significantly reduce government revenues. Not good news when you are trying to finance a border wall, increase defense spending by $54 billion, etc. This is where the border adjustment tax (BAT) comes in.

The BAT makes two important ‘adjustments’. First, businesses that import goods and intermediate inputs are not able to deduct these import costs. Second, businesses that export goods to other countries are not required to pay tax on revenues from foreign sales. If the US is running a large trade deficit (as it is now), revenues earned via taxing imports will exceed revenues lost from exempting exports. The Tax Policy Center has estimated that the BAT would raise $1.18 trillion over 2016-2026.

What would BAT do to domestic gas prices?

If you are a big net importer, you are not feeling good about this BAT idea.


 Chevron (refinery pictured here) is a major importer of foreign crude. Source

A recent report by energy economist Phil Verleger looks in detail at how these proposed changes could impact U.S. markets for petroleum products. On the importing side, Verleger assumes that refiners who rely on foreign-sourced inputs would see a 25% increase in import prices under the BAT. Facing this kind of cost increase, refiners would go looking for domestic sources. But domestic oil producers are under no obligation to supply the domestic market. If domestic revenues are taxed while export revenues are exempt, they will demand a higher price from domestic refineries to compensate for the tax disadvantage of selling at home versus abroad. Taken together, Verleger estimates that the average retail price of gasoline would increase by 13% (approximately 30 cents a gallon). Other industry analysts have reached similar conclusions.

One important thing to note about these kinds of analyses is that, to keep things tractable, they hold some important variables fixed. The Verleger study is careful to note that accounting for all of the various channels the BAT could work through “would be complex and far reaching and would likely differ substantially from the petroleum specific calculations presented in this paper.” But this begs the question: how do projected impacts change if key variables are turned loose?

What gives with this kind of BAT?

On the face of it, it seems like this border adjustment tax should benefit exporters and hurt importers (who will then pass that hurt through to you the consumer). But it’s more complicated than that because the BAT is designed to tax all imports and exempts all exports. Purchasers of our exports finance their purchases by selling us imports. If they sell us less, their purchasing power drops.

In a textbook model of how these pieces fit together, the BAT would trigger a currency adjustment, and the US dollar would appreciate to fully offset any real effects on import and export prices. To see how this works, suppose a US refinery is buying oil from Mexico at a price of 1000 pesos per barrel. Once the BAT is introduced, the 25 percent tax on imports raises this cost to 1250 pesos/barrel (all else equal). But if the dollar appreciates by 25% as some are predicting, prices paid for Mexican imports (in US dollar terms) would be unchanged. In other words, in theory, the BAT would not penalize imports or favor exports. Terms of trade effects would be undone by the currency adjustment.

Paul Ryan has declared it “obvious and mathematical that a currency adjustment would occur”. However, building on our it’s-more-complicated theme, the theory that yields this elegant and mathematical result conditions on some strong assumptions. Federal Reserve Chairwoman Janet Yellen is among those questioning these assumptions, and the real-world considerations that this theory ignores. Examples include factors that limit the pass-through from currency changes into U.S. import prices and the reactions of other countries who can impose their own import taxes in retaliation.

There has to be a better “Better Way”

There are many reasons to think that exchange rate adjustment to the proposed BAT will be slow and incomplete. If this is the case, the prices consumers pay for gas –and imported goods from avocados to zippers– will increase. The economic impacts could be significant and negative.

Reducing corporate taxes will encourage good things like innovation and investment in economic growth. But it would also reduce tax revenues. To make up the shortfall, we need to find something else to tax.  With the GOP Better Way proposal, we run a real risk of penalizing other good things, namely all imported goods and domestic consumption. This would impose real costs on American consumers and the economy as a whole.

Ideally, we would reduce taxes on corporate income and raise needed revenues by penalizing damages versus other goods. Another Republican tax proposal, one that has received relatively less attention than the GOP plan, aims to do just that. The Conservative Case for Carbon Dividends proposes to tax domestic carbon emissions. It would incorporate a different kind of border adjustment, one that is designed to tax the carbon emissions associated with imports (versus the imports themselves).  Under this proposal, some consumer prices (including gas prices) would rise. But these increases would reflect real social costs and trade-offs, versus distortions imposed for the sake of revenue generation. Now that sounds like a better way.



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What Do We Want From California Climate Policy?

When you listen closely to debates over California climate change policy, it becomes clear that the disagreements are along two dimensions: what is the best approach to meeting the state’s goals and what exactly are those goals. I think the differences are increasingly about different goals, rather than about different methods of achieving those goals.

goalsofclimatepolicy1Setting aside those who think climate change isn’t happening, isn’t man-made, or just isn’t a problem, participants in California’s climate policy debate often speak of four intertwined goals:

A. Reducing California’s GHG emissions to a specific target

B. Demonstrating to the world that a state (or country) can significantly reduce GHG emissions without significant economic cost

C. Creating new knowledge and technologies that lower the cost of reducing GHGs globally

D. Reducing local pollutants, particularly in disadvantaged communities

I wrote about local pollutants in my January blog. I still believe that it is important for both ethical and political reasons to address local pollution at the same time, though not with the same policies, as GHGs. So, I will focus here on A, B and C.

Most of the discussion in Sacramento is around goal A, hitting California’s GHG emissions target, but that is undoubtedly the least important for three reasons:

First, as I’ve talked about before California is just over 1% of global GHG emissions, and global emissions are all that matter for climate change. Climate science does not dictate any one numerical reduction goal that California “must” meet. For the foreseeable future, more reduction is always better, so long as it doesn’t cost too much.

goalsofclimatepolicy2Second, the difficulty of meeting California’s emissions target will depend greatly on a host of unpredictable factors that are unrelated to the state’s emissions reduction policies, such as the growth rate of the state economy and the price of oil, as co-authors and I showed in a study released last August. Advances in low-GHG technologies will also reduce the cost of meeting a numerical goal, and advances in extracting fossil fuels, such as fracking, will increase the difficulty of lowering GHGs.

Third, reducing California’s contribution to climate change requires more than reducing GHG emissions from inside California. We buy all sorts of goods from out of state whose production generates GHGs. With the exception of a very imperfect attempt to account for out-of-state electricity (and, to some extent, transportation fuels), the GHG impact of imported goods are not counted in the state’s reduction goals. Just as with carbon offsets, real change depends on “additionality”, or in this case what might be called “subtractionality”: is a reduction of GHG emissions from one source actually reducing worldwide GHG or is it moving emissions to another location?

Developing and Demonstrating Credible, Scalable Solutions

Subtractionality is also central to goal B, credibly demonstrating that reducing GHGs needn’t significantly harm an economy. It’s clear that outsourcing our GHG emissions to other states or countries isn’t a model that can be scaled up to reduce global GHGs. So, honestly measuring leakage and reshuffling – even in cases where California may not be able to control it or penalize it — will be critical to convincing other governments of California’s success. The demonstration goal also weighs against expensive or non-replicable approaches to GHG reduction, even if they help reach a numerical target.

Demonstrating that other economies can grow on a low-GHG path is also the basis for goal C: innovating to lower the cost of reducing GHGs. Knowledge creation of this sort necessarily means experimentation which, by its very nature, means some disappointments. But knowledge creation is where California has the most to contribute.  The state is known for its innovative and risk-taking knowledge economy.

Knowledge creation and innovation means much more than extending the science of renewable energy and storage technologies, though those are big pieces of the puzzle. It also means figuring out how to operate a reliable grid with a high share of intermittent resources, such as wind and solar. And developing technologies and programs that lower the cost of efficient demand-side participation in electricity markets. And it means creating business models for electric vehicle charging that maximize the value of having EVs on the grid.goalsofclimatepolicy3A Plan of Attack for California Climate Policies

All of that seems like a lot to ask from California’s climate policies, and it would be if we could only deploy one policy. But, California has multiple climate policies, which suggests a plan of attack that could make progress on all three goals.

First, recognize the reality that the state’s emissions goal is a goal, not a line in the sand.  Commit to aggressive policies that are expected to meet targeted emissions levels under the most likely scenarios, but recognize that actual emissions will be higher or lower depending on unpredictable factors. This gives the state’s cap-and-trade program the flexibility to maintain a minimum price when emissions are on track to come in below the cap and enforce a credible ceiling price when emissions are not going to get down to the cap. This would make the cap and trade program both more effective and more politically credible.

Second, create a full-economy consumption-based accounting of California’s GHG emissions. This would include sectors that are not part of the cap and trade program, such as agriculture, as well as out-of-state production in sectors that are under cap and trade, such as oil refining. This measure would include all imports, and would exclude all exports.  It would not be intended to be a device for enforcing policy, but rather a scorecard for honestly assessing how well the state is reducing its overall contribution to climate change. Ideally, such a scorecard would be calculated by an entity that is not politically invested in the answer, the equivalent of a Congressional Budget Office for California’s climate policy. If California is going to demonstrate the ability to reduce emissions without harming the economy, it needs this sort of all-encompassing and independent accounting.

Third, focus complementary policies on the areas where the market mechanism — cap and trade — is least effective, where specific market failures are identified. Probably the most important such case is in developing new knowledge and technologies. “Complementary policies” should include support for basic science to develop new technologies, as well as mandates for using specific technologies, such as the state’s electric vehicle mandate. But, importantly, every dollar spent or mandate enacted should be clearly tied to a need for policy intervention beyond the price in the cap and trade market. By the way, I would include in this knowledge creation policy the experiment that we are now running as the state ramps up the use of intermittent renewables. Complementary policies may also be justified where market prices are shown not to be effective, such as with some energy efficiency programs where buyers of appliances, houses, or other goods do not accurately incorporate energy prices.

As the California legislature discusses how to extend the state’s climate programs beyond 2020, we have an opportunity to learn from the experience so far and adjust policies in order to improve their impact in California and, more importantly, in the rest of the world. Now is the time to make the big changes we need, before we lock in for another decade or more.

I’m still tweeting interesting energy news, research and stats @BorensteinS

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Breaking News! California Electricity Prices are High

In case you missed it, a recent investigative piece in the LA Times unearthed the shocking fact that California retail electricity prices are high,  about 50% higher than the national average. The article’s main focus is on the fact that California has a lot more installed nameplate generation capacity then has historically been the norm. There are several causes identified in the piece.  Deregulation of the market in the late 1990’s is pointed to as a culprit. Somewhat inconsistently, the construction of regulated, rate-based plants also takes much of the blame. One factor that was barely mentioned, however,  was California’s renewable electricity policy.

The story of how California’s electric system got to its current state is indeed a long and gory one going back at least to the 1980’s. The system still suffers from some of the after effects of the 2000 era crisis.  The Long Term Procurement Process (LTPP) put in place in the wake of the crisis, and overseen by the CPUC, has been criticized from many sides.

However, since the power crisis of the early 2000’s settled down, the dominant policy driver in the electricity sector has unquestionably been a focus on developing renewable sources of electricity generation. As is well known (outside of the LA Times apparently), California has one of the country’s most aggressive renewable portfolio standards (RPS).  The RPS requires each firm that sells electricity to end-users to procure an increasing fraction (33% by 2020, 50% by 2030) of the energy they sell from renewable sources.

Desert Solar Array
The Times article’s focus on generation capacity does (a bit unwittingly) provide a nice starting point for a discussion about the cost and implications of this renewable energy policy. The policy, while undoubtedly effective at reducing the carbon intensity of the power sector, has also been quite disruptive to the economics of the sector.  It is forcing a rapid (and early) replacement of conventional sources with renewable, but variable, generation sources such as solar and wind. Since 2010, about 80% of new capacity has come from renewable sources and it’s likely that much of that capacity would not have been built if not for the RPS.  (Much of the remaining 20% has been coming online to replace the retired SONGS nuclear plant or capacity slated for retirement due to environmental issues with their water cooling  processes.)


New Capacity in California ISO by fuel type

Proponents of strong renewable standards have pointed to the fact that new contracts for renewable energy carry price tags that are (at worst) only modestly above those for a new conventional natural gas power plant. However comparing the cost of a brand-new solar plant to that of a brand-new gas plant overlooks two important facts.  First, renewable, variable output sources offer very different operational capabilities than conventional sources.  Second, right now we don’t really need new capacity of any kind, and are in fact struggling to find ways to compensate the generators that are already here.

The renewable portfolio standard provides an interesting contrast to the federal mileage standards on vehicles. Both require the replacement of older legacy, high-carbon sources with newer,  lower-carbon ones. However automobile standards work by requiring people to buy more fuel-efficient cars when they decide to buy a new car. Renewable portfolio standards require utilities to buy low-carbon energy by a certain deadline rather than when they are deciding to “trade-in” their old power plants. In California at least, the result has been a much more rapid turnover of legacy sources to the newer, cleaner ones. Another implication, however is the fact that the system now has a large amount of what can appear to be excess capacity. This is because renewable policies are rapidly forcing new “green” capacity into a market that was more or less fully resourced before the mandates really started taking effect.

I don’t mean to imply that the “replace it now” approach is definitively worse.  Research has shown that standards applied only to new purchases can inefficiently extend the lifetimes of older technology, from cars to power plants.  This can significantly dilute the environmental benefits of a technology mandate.  In contrast, instead of extending the lifetimes of old plants, the RPS is in effect forcing the early mothballing of legacy capacity. This improves the environmental impact, but also increases costs, sometimes in subtle ways. The effect grows larger with stricter mandates. At higher percentages, the RPS starts to displace increasingly newer (and cleaner) sources of generation.  The economic effects can be mitigated by allowing for renewable energy generated elsewhere in the country to count toward RPS compliance, but California has largely rejected such policies.

Largely due to the RPS, we have a surge of new, low marginal cost energy, flooding into a wholesale market that already had enough generic energy, thereby driving down wholesale prices. Since wholesale prices cannot support the cost of this much generation (new and old), increasingly the gap must be  made up through rising margins between wholesale and retail prices.  Utilities and other retailers have to pay  high market prices for new renewables instead of being able to “buy low” on the wholesale market.  Because all retailers face the same regulation, they pass these costs on to end users. And this doesn’t even consider the costs of new transmission, most of which is being added to boost the power system’s ability to access and absorb large amounts of renewable energy. Transmission costs, which are also charged through to electricity end users as part of the retail prices cited in the Times article, will continue to grow in coming years. The Tehachapi transmission project alone is projected to cost over $2 Billion.

The result is the seemingly perverse situation where customer rates are rising while (conventional) generation sources are simultaneously struggling for revenue and threatening to retire. Such conditions are a recurring theme on this blog and are often drivers of significant change. Unfortunately, despite the glut of electrical energy, we will likely still need the conventional capacity to handle the ramping and back-up needs created by the increased reliance on variable sources (wind and solar).

One of the debates lurking in the background is who should be responsible for the cost of these disruptions. Richard Schmalensee has observed that deregulation may make it easier for State policy makers and regulators to ignore wholesale market effects. This is because the assets being stranded today are largely owned by non-utility generation companies in contrast to the late 1990’s when the stranded assets were a joint problem of regulated utilities and their rate payers.

California led the way with developing renewable energy in the 1980’s,  with the deregulation of the power sector in the 1990’s and 2000’s, and now with high-volume renewable mandates since 2010. We are learning a lot about how to physically manage and finance a cleaner energy system. We also need be realistic about the costs of such policies.  When you combine the cost of policies of the past with the aggressive goals for the future, you get retail electricity prices that, yes, continue to be pretty darn high.


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