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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.

Catherine Wolfram View All

Catherine Wolfram is Associate Dean for Academic Affairs and the Cora Jane Flood Professor of Business Administration at the Haas School of Business, University of California, Berkeley. ​She is the Program Director of the National Bureau of Economic Research's Environment and Energy Economics Program, Faculty Director of The E2e Project, a research organization focused on energy efficiency and a research affiliate at the Energy Institute at Haas. She is also an affiliated faculty member of in the Agriculture and Resource Economics department and the Energy and Resources Group at Berkeley.

Wolfram has published extensively on the economics of energy markets. Her work has analyzed rural electrification programs in the developing world, energy efficiency programs in the US, the effects of environmental regulation on energy markets and the impact of privatization and restructuring in the US and UK. She is currently implementing several randomized controlled trials to evaluate energy programs in the U.S., Ghana, and Kenya.

She received a PhD in Economics from MIT in 1996 and an AB from Harvard in 1989. Before joining the faculty at UC Berkeley, she was an Assistant Professor of Economics at Harvard.

74 thoughts on “Is the Duck Sinking? Leave a comment

  1. To deal with the “problem” of an oversupply of energy in California, mainly from renewable sources, I have been surprised not to see discussion of enhancing the grid connections from California to the rest of the country so that the excess electricity can be made available to a wider set of potential customers. In that much of the western US is sparsely populated and often experiencing the same weather (i.e., sunny vs. cloudy; windy vs. still) as much of California, the additional customers are likely beyond the cost-efficient transfer distance of the high-voltage/alternating-current (HV/AC) power lines. Recognizing the problems of time-varying supplies of electricity from renewable energy sources and that the HV/AC cost-effective transmission distance is generally smaller than the size of weather systems, Alexander (Sandy) MacDonald and colleagues published a paper in Nature Climate Change in January 2016 (Future cost-competitive electricity systems and their impact on US CO2 emissions, DOI:10.1038/NCLIMATE2921) that input detailed weather information to a model of the electric grid to demonstrate that a national network of high-voltage/direct-current (HV/DC) power lines, so basically an interstate highway system for long-distance energy transmission, could greatly benefit the country and lead to greater than an 80% reduction in national CO2 emissions. With the present system, the strategy for going renewable would seem to require significantly overbuilding renewables in each region so that a large storage system can be charged up and used to overcome the intermittency problem; with the national HVDC network that was proposed, electricity could potentially be sold to utilities across the country, so, for example, meeting the East Coast summertime afternoon air-conditioning load with solar energy from the southwestern US and wind from the upper Great Plains to help power the southeastern US, etc. By undergrounding the required lines in existing rights of way of interstate highways, railroads, etc., not only would one be interconnecting the country and providing the opportunity to greatly reduce national CO2 emissions, but also overcoming time-consuming battles about rights of way for aboveground lines, reducing the vulnerability of our national grid to natural disasters and terrorism, making the national grid less vulnerable to powerful solar flares and EMP pulses from high-altitude nuclear explosions, spread out energy and economic development by providing the opportunity for rural areas to have ready access to connect to the national grid, and creating both construction jobs in the near-term and high quality maintenance and operations jobs for the longer-term.
    Unfortunately, there is no federal agency charged with making this happen; instead, partnerships drawing as needed on the private and public sectors could likely make this happen most rapidly. We have a small group of young people at the Climate Institute (climate.org), partnering with other groups of young people in a few universities around the country, who are working through some of the various issues that need to get resolved (e.g., access to rights of way, compatibility of soils and cables, national security implications, etc.), and would welcome other groups helping to push the effort along—at least to get it considered. The notion that there is excess (mostly) renewable energy just being given away (or even offering money to be take) seems irrational and unacceptable given the need for the US and world to switch away from fossil fuels. I would certainly suggest that this might be an excellent topic for the Energy Institute to be looking into and encouraging.

  2. Very intuitive article from a professor who has done and in doing a lot in energy for economic growth in developing countries. Prof indicated there is the need to pay attention to part of the duck below the zero price line. Jim Lazar enumerated a number of loads to shift into this period as a way of teaching the duck to fly and that is commendable.
    One additional way to teach the duck to fly is to export additional investments into renewable energy to the developing world where consumers find it difficult to pay for power and have them use it for day time activities like pumping water for irrigation, transportation etc. Prof is a member of DFID energy for economic growth committee. She can facilitate this by identifying potential investors and co-funding them with DFID funds into the developing world
    I would be grateful id Central Tongu Constituency of the Volta Region of Ghana can benefit from such an investment.

  3. There’s too much focus here on a single price signal, when other price signals are either ignored or missing entirely. The CAISO bid cost recovery (BCR) is a side payment to fossil plants that continue to run through these negative DA/RT price periods, but the CAISO does not report the BCR cost per MW or per MWH, nor does it take bids on this service. The RA payments, while there is a bid process, are similarly beyond market scrutiny. IOU-owned resource cost recovery is largely assured through the ERRA proceedings no matter what operational decisions are made. If these were included in these types of analyses, I suspect that we would see many fewer hours of “negative” prices and we could identify which resources are really being subsidized or carried through other side payments.

  4. “It’s a bit early to celebrate.” Oh, I agree. It’s 13 years too early. The point is that the CAISO is already experiencing the reality of operating a system with 50-60% renewables, and that means the operational problems raised by high renewables can be identified now and worked out now. We don’t need CAISO studies about the theoretical difficulties of the post-2020 duck curve nearly as much as we need analysis of the actual difficulties (and their resolutions!) of actual hours (now) and days (soon) with 50+% renewables. As Jim Lazar already pointed out above, there are many conceptual ways of resolving duck curve issues. I’m trying to point out that real-world experience is happening already, and probably at a larger scale (64% peak renewables yesterday, 51% as I write, on a weekday before noon) than the CASIO was expecting.

    • One of the curious issues that CGNP uncovered while researching their testimony is the modest use of PG&E’s Helms Pumped Storage. Per the CEC, pumped storage is the only practical means for storage of the intermittent energy from solar and wind generation. In CGNP’s data request number 9 in the CPUC proceeding considering DCPP abandonment, we ask why the Helms capacity factor is so low. Between 2003-2016, the annual capacity factor ranged between 0.84% and 4.69% – all very modest values. For yet unknown reasons, PG&E rebuffed CGNP’s data request.

      • This light use of Helms is troubling. Of course, Helms was built to provide load-factoring service to Diablo Canyon, because even 35 years ago, it was well understood that the inflexibility of nuclear plants was a challenge to manage. It added about $2,000/kW to the booked value for Diablo Canyon, and that cost is NOT covered by the very high price arrangement that the CPUC approved for Diablo. But to have it in place, and not being used a lot, is quite troubling. I would expect to see the entire 1,212 MW load being used during the mid-day bulge of solar to pump water uphill, and then reversed in the evening to mitigate the duck curve challenges.

        Perhaps the Haas folks have access to the hourly dispatch of Helms during the days when negative prices have been experienced.

      • Gene Nelson claims Helms capacity factor is always under 5% in the last 14 years. Because Helms has 3 generators, but typically doesn’t use more than 2 for pumping, and because Hems has a round-trip efficiency be;low 80%, Helms spends about twice as many hours pumping as generating. Thus it pretty much can’t have a capacity factor above 33%. Still, 5 is a lot less than 33.

        • David Marcus: I agree that 5 is considerably less than 33….Here is the link from the U.S. EIA that shows Net generation Helms Pumped Storage (6100) conventional hydroelectric hydraulic turbine reversible (pumped storage) annual data:
          https://www.eia.gov/opendata/qb.php?category=3211&sdid=ELEC.PLANT.GEN.6100-WAT-PS.A
          (The URL must be supplied to a browser without any line feeds.) Per PG&E Helms has a 75% efficiency, which is one of the best statistics for any pumped storage facility. The annual production tabulated is divided by 1,212 MW * 365.25 Days/Year = 442,683 MW*Day/Year to obtain the average number of hours of operation per day. The maximum is 1.126 hours/day in 2016 and the minimum is 0.201 hours in 2005. P.S. the postulated means of operation that you specified in your response merely turns Helms into an extremely expensive resistor since the water is just being circulated through “the nearly four miles of 28-foot diameter tunnels (that) connect the powerhouse and two reservoirs.” (Per PG&E)

      • I don’t work for PG&E but I can answer your question. First, in the day-ahead time frame when PG&E has to decide when and how to bid in Helms, the price differentials that determine whether it makes sense to pump when energy is cheap and generate when energy is dear are typically too small to produce operating profits. Second, the CAISO’s market design provides NO actionable price discovery. Negative prices in the real-time market are only known after the fact when they can’t be acted upon rather than ahead of time when PG&E might be able to make some rational decisions (I have been complaining about this problem for 20 years now). Third, it is true that only two of the three pumps at Helms can be operated most of the time because in addition to reading the plans backwards when DCPP was built, PG&E failed to build enough transmission into Fresno and it has never made economic sense to rectify that error.

        It’s quite simple to operate a pumped storage plant (or a battery for that matter) so that it produces operating losses. It is much more difficult to operate any kind of storage so that it breaks even or better on an operating basis. Helms is used primarily to provide spinning reserve and possibly some frequency regulation.

        Also keep in mind that even if Helms was pumped up every evening and run down every day, its capacity factor would still be small compared to a fossil-fired plant because (if memory serves me correctly) it can only store about 5-5.5 hours worth of energy at its full discharge rate of 1200 MW.

        • The solution is evident more fully using Helms, but it probably requires bypassing the CAISO DA/RT market. PG&E should be directly contracting for zero-cost solar and wind power (and remember wind is actually negatively priced) to Helms on a prescheduled basis. The RT/DA markets are already distorted by a number of factors (e.g., UOG cost recover, BCR, RA payments) so taking this step shouldn’t be too inconsistent with other CAISO actions such as OOM dispatch.

          • Please note that the same thing is happening currently in Germany, Austria and Switzerland. It’s simply very difficult to use pumping units efficiently with renewables, because their production varies everyday so the exact price is really hard to predict in advance, and as written above any decision you take might easily, given the significant percentage of loss in the round trip, end up making you lose money instead of being profitable.
            An additional problem is that pumped storage only have a limited capacity which is too small compared with the time factors of wind production, that typically tends to be high for a few days, and then low for several days. This means they are quickly either full or empty and can not after that profit anymore from the price variation.

            On the other hand, they have always worked efficiently with nuclear, and most of the pumping unit existing of the world have been built to be used in association with nuclear, because of the predictibility and short term night/day cost variation it creates. In an extended manner, nuclear works better with storage and makes it more profitable than renewable. Cheap storage would help nuclear in areas where it’s not in a position to produce all the time as baseload, and not make redundant with renewables.

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