Electricity is an increasingly complex industry in the midst of transition to renewables and decarbonization. Using my 25 years’ experience as an engineer, policy analyst, and academic, I help my consulting clients think through their toughest technical challenges and formulate their best business strategies.
The good news is: solar. The bad news
is: uncontrollable rooftop solar. How do we utilize the production of rooftop
solar in the middle of the day?
This is an especially significant
problem for California. The California ISO coined the term “duck curve” to describe
that state’s net load – that is, load minus renewable production from solar
photovoltaic (PV), wind, and run-of-river hydro production. On a mild
sunny day, the problem that the duck curve illustrates is that net load falls
so low that other generation cannot follow it.
The same challenge is emerging in other places, as well. In Australia, for example, Paul Simshauser of Griffith University, South East Queensland, describes the same situation there in his warm, northern state. (Click here to download his paper.)
Interestingly, Simshauser’s data shows that air-conditioning (AC) is a significant contribution to the rising neck of the magpie goose during critical summer days (that is, a significant contribution to the increase in net load during the evening of such days after the sun goes down). Although I do not have the specific data on hour-to-hour consumption for inland California, I believe that a similar pattern would apply there and in many regions with high AC consumption. In Texas, for example, residential consumption in summer greatly exceeds that in spring and fall. It is well understood that summer peak consumption is driven by AC load during times of high temperatures that persist into evenings.
To illustrate, Figure 1 shows net
load for Central Texas during August 2018 (data courtesy of Grant Fisher and
Esha Choudhary of Pecan Street Inc.). The blue line shows net load
(consumption, including AC, minus rooftop PV production) for a sample of Austin
homes. The data points are 15-minute average power consumption, averaged
over the sample of homes with both AC and rooftop PV that Pecan Street
monitors. Each day, net load falls (becoming negative, implying net export to
the electric distribution system) during the day, but then rises again and
experiences a peak in the late afternoon and evening, with solar production
decreasing just as AC consumption increases: the upward sloping
“neck” of the duck or magpie goose.
This combination of AC needs that persist after the sun goes down and PV production that falls precipitously at sundown suggests a way forward: to pre-cool houses in the hours before sundown. Researchers working under the U.S. Department of Energy’s Building America program have modeled two example homes for several regions using EnergyPlus. (Click here to download the report.) They found that pre-cooling is an effective way to reduce peak residential load.
However, pre-cooling will result in higher energy consumption by 2% to 8% overall. This increase in energy consumption can be thought of as analogous to “round-trip losses” in a battery storage system, implying that storing energy involves overall more energy consumption than using the energy when it is produced. Results depend on both weather patterns and the thermal insulation and thermal mass of the housing stock.
pre-cooling interact with the duck curve? Pre-cooling can increase
consumption when the sun is shining and decrease it after the sun goes down.
This has two advantages. First, with significant rooftop solar, there is
significant export during the day to the electric distribution system. There
are limits to the amount of such exports, and California is heading toward a
situation where PV production may otherwise have to be curtailed during the
day. Therefore, pre-cooling could offer significant benefits by increasing
utilization of renewables during the day, while also reducing non-renewable production
in the evening. Second, pre-cooling will reduce the “ramp rate”
of net load; that is, the rate of increase in net load over time, which is
represented by the upward sloping neck of the duck. Because net load must
be matched by other generation, and because generation has limited ability to
ramp, reducing the slope of the “neck” can ease the need for ramping
Sometimes chemical battery storage is advocated as a solution to the mismatch between PV production and electrical demand. Interestingly, the higher energy consumption with pre-cooling found by the DOE Building America program is similar in magnitude to the round trip losses of a Tesla battery. In contrast to a chemical battery, pre-cooling does not require (much) capital investment, at least for a well-insulated home. While pre-cooling might not work for typical current Queensland housing stock, it might be effective in regions where there is already significant investment in insulation. Much housing stock in Texas, for example, has double-glazing as well as ceiling and wall insulation, and further investments in building efficiency would not only help with improving prospects for energy storage but also pay dividends in overall energy savings. I understand from Scott Jarman of Austin Energy that this Austin utility already practices pre-cooling in some of its controlled residential thermostats in preparation for critical peaks.
So, could we pre-cool all residences all the time? Pre-cooling homes could effectively be practiced more widely and not just on critical peak days. The idea would be to significantly pre-cool well-insulated homes while PVs were still producing significant power, and then to allow indoor temperatures to drift upward as the sun goes down. This would facilitate better utilization of PV production and reduce the slope of net load in the evening.
I have not performed the detailed modeling to evaluate the potential explicitly, but figure 1 suggests what might be possible for Austin. I considered shifting the AC consumption represented in the Pecan Street data to occur three hours earlier. I accounted for the round-trip losses by assuming that 10% more electricity for AC would be required when shifting consumption by three hours. The result is shown in the orange line, which has less variation than the blue line: peak consumption is significantly lowered, there is lower net export of solar to the grid, and the ramp rate of the net load is significantly reduced. To be clear: the blue line simply shows the effect on net load of bringing forward AC consumption by three hours and increasing it by 10%, whereas a more careful simulation is required to obtain actual results with a real home.
What does data for
a single day tell us? Figure 2 depicts net load for the specific day of August
1, 2018. We can see that the general duck-like shape of the net load as shown
by the blue line has been flattened by bringing AC consumption forward in time:
as shown by the orange line, peak of net load is lower, net
electricity exports from homes have been eliminated for this day, and the
“neck” of the duck rising to the peak has a lower slope. Simulation
of a pre-cooling strategy would undoubtedly show a different detailed pattern
of net load, but a similar general effect could be expected.
Won’t consumers balk at spending more money on higher electricity usage to pre-cool their homes? California is addressing this problem by introducing new lower time-of-use (TOU) rates for electricity during sunny hours.
Traditional TOU rates were designed to shift consumption to nighttime, say after 10pm or 11pm, when load is typically lowest. Some argue, however, that these traditional TOU rates are ineffective, and recent evidence from Bruce Mountain, Victoria University, Melbourne, (click here to download the presentation) supports that claim, by suggesting that such traditional rates, with low prices overnight, have not convinced homeowners to shift their consumption to nighttime in the state of Victoria. No one wants to do their laundry in the middle of the night to save a few pennies.
But with the new TOU rates they would be willing to do their laundry, dishes, and electric-vehicle charging – and pre-cool their homes — in the afternoon. The new, improved version of TOU with lower prices during middle hours of the day was mentioned in the DOE Building America study, and that’s exactly what California is doing.
Renewables challenge us to rethink our basic assumptions. To mix metaphors, there is more than one way to skin a duck — or a magpie goose. With high PV penetration, we cannot always control supply to meet demand. We need to change demand to follow supply. And that’s what pre-cooling will achieve.
Next time: more ways to change demand to follow supply.
Even if you are in Cambridge, I do not advise you to buy the hardback copy. Instead, there is now an updated paperback copy available that includes corrections and additions. Click here to purchase.
There are a number of other optimization books out there, but if you want a careful introduction to optimization, convexity, and optimization, with multiple power systems case studies, please consider this book and the slides for my associated graduate course, “Optimization of Engineering Systems.”
This is what I came across recently: a luxury brand store window display of “renewable chic,” where a solar panel, as part of the vignette, is being used to partially illuminate the mannequin. Putting aside the irony that the solar panel itself was apparently being illuminated by grid-powered lights, there are broader implications we need to anticipate with the increasing popularization of small-scale solar. Let’s think twice about increasing small-scale rooftop solar, because right now the economics just don’t make sense.
First of all, there is the compromise in quality of service. Small-scale—up to a few kW—rooftop solar systems are set up primarily to inject as much power as can be generated from available sunlight. In small numbers on individual distribution feeders, this is not a problem. But in large numbers, technical challenges such as voltage control and fault protection on distribution feeders become problematic. Until recently, interconnection standards did not allow rooftop solar systems to participate in voltage control. (This may be remedied for new installations with updates to the IEEE 1547 Interconnection Standard.)
This leaves us with at least two salient and interacting concerns.
First, the expense. Small-scale rooftop solar remains much more expensive to install than large-scale solar, because existing household rooftop sites are unlikely to have the best exposure and orientations toward the sun and because the small-scale is almost always going to involve higher costs per unit capacity than large-scale installations. The store display shows this latter issue in microcosm: there was presumably several hours of labor and significant installation cost for this panel of just a few hundred watts! Rooftops of several kW are less expensive per unit capacity than this small panel, but even larger installations are less expensive per unit capacity. In the United States, it is reported that small-scale solar is double or more the cost of large-scale solar.
(An added concern: if large-scale solar is located far from urban centers, the solar may be cheap, but it may also require expensive transmission upgrades. A good compromise will often be medium-scale developments using large commercial and industrial rooftops and community installations. This way, the solar is nearly as cheap and there is no significant extra cost for transmission. Click here to read more about locating distributed generation in urban areas.)
Second, solar production is variable, depending on the available sunlight, which means that the power injection into the grid is variable. But, as I said earlier, small-scale installations are mostly set up to inject as much power as possible from the sunlight. So, as sunlight levels change, the power will vary. Sometimes large amounts of solar power production will coincide with times when the power is not needed.
In contrast, large-scale installations are easier to set up as being dispatchable. That is, large-scale solar can be controllable to produce less power when that power is not needed. Such circumstances are bound to become more common, as the so-called California duck curve shows. To date, essentially no residential rooftop solar has been dispatchable, so when it is sunny in California but demand is low, there is a need to dispatch down the remaining thermal generation. This might be acceptable by itself, but when the sun goes down in the evening, the demand typically increases in California, and this is threatening to result in situations where the thermal generation has insufficient ramping capacity to cope with the net variation–that is, to cope with the difference between load and solar generation that must be supplied by the rest of the system.
Storage is sometimes put forward as a solution to the duck curve. Moreover, additional power electronics associated with battery storage can help both with the fluctuations in solar production and with the regulation of voltage levels in the distribution system. Storage can be a cost-effective solution when there are issues such as distribution feeder capacity limits that can be alleviated through storage. So while there are specific situations when investment in battery storage can make sense, it is generally still a relatively expensive solution. There is no doubt in my mind that battery storage will eventually be cost-effective when costs decline significantly from today’s levels. In the meantime, until battery prices become much lower, existing pumped-storage and reservoir hydro facilities are important storage resources to be utilized now. Moreover, dispatchability of solar would mitigate some of the immediate need for storage. In an analogous situation in Texas, dispatchability of large-scale wind has been helpful in ERCOT being able to integrate so much wind power.
This brings the discussion back to small- versus large-scale. Large-scale installations are likely to be more cost-effective ways to provide large amounts of solar. They also are easier to set up, so that they can be dispatched down when required. However, having gone down the path to installing a lot of expensive, non-dispatchable small-scale rooftop solar installations, jurisdictions such as California, Australia, and Germany have consigned themselves to spending even more money to buy battery storage to balance the solar. It is hard to reconcile this policy with the imperative to decarbonize the electricity system cost-effectively. Other states and countries should take note: until storage becomes cheaper, larger-scale solar installations will reliably bring more cost-effective decarbonization results.
The Australian Competition and Consumer Commission (ACCC) recently released “Restoring Electricity Affordability & Australia’s Competitive Advantage,” a comprehensive report that analyzes the reasons for very high prices and “sets out 56 recommendations to reset the National Electricity Market, boosting competition, reducing costs and improving consumer and business outcomes.” (Click here to find the full report.) I generally agree with its recommendations and want to focus here on two issues: retail price structure and inherited customers.
First, the problem of confusing retail price structures. There are several features that complicate the comparison of retail tariffs from the various retailers in the Australian market, including the interpretation of discounts. The ACCC has recommended the establishment of requirements to make it easier to compare one retail offering to another and has recommended restrictions on third-party intermediaries. It advocates for the establishment of a “default offer rate” to which all discounted offers would be compared.
The default offer rate is likely a workable solution, but I would like to suggest a much more prominent role for government- or regulator-sponsored websites such as energymadeeasy.gov.au in Australia and powertochoose.org, in the Electric Reliability Council of Texas (ERCOT). Part of the success of the powertochoose.org website was due to heavy promotion from the very start of retail competition, and I believe that better promotion of government-sponsored sites in Australia would also facilitate retail competition, even going beyond the ACCC’s recommendation in chapter 14.
In the case of powertochoose.org, retailers provide information to the website, and consumers wanting to compare rates can simply enter their zip code (post code) to see available offers and evaluate their prospective bill, according to their level of typical monthly energy consumption. It is important to understand that this website is not organized by a third-party intermediary, the likes of which have been criticized by the ACCC. This type of official comparison website, set up by the regulator in order to provide unbiased, consistently formatted, apples-to-apples consumer information, could provide the “reference bill amount” advocated by ACCC in recommendation 32.
Second, the problem of incumbents inheriting customers. That is, the successor company of a previous retailer tends to maintain a large fraction of its pre-competition customers, who may not explore cheaper retail options from the competition, thus disadvantaging new retailers – even when they offer a cheaper product. In its retail restructuring, Texas devised a pricing strategy aimed to give a short-term advantage to new retailers by establishing a temporary, artificially high price that the incumbent had to charge. In effect, this became an easy “price-to-beat” for new retailers. Once a certain number of customers switched to the new retailers, or once a sunset date had passed, the price-to-beat was eliminated.
The price-to-beat was set above expected market-based prices for retail offerings, which may seem like a giveaway to incumbents, but it actually provided an opportunity for new retailers to make an initial entry into the market and undercut the incumbents, thus weakening the significant advantage of the incumbents.
As the powertochoose.org website shows, there are now plentiful retail offerings in ERCOT competing for customers on a level playing field. It is probably fair to say that the temporary price-to-beat strategy helped produce a vibrant retail market.
How does the price-to-beat relate to Australian restructuring? Australian retail restructuring is arguably past any initial transition period, so how could something analogous now be implemented? Here’s a possibility: Note that the ACCC report recommends that state governments take over some of the “excessive” network costs in order to allow for a bill reduction. This price reduction could be used to create Australia’s own price-to-beat. One possibility would be to allow the discount to flow first to customers of non-incumbent retailers, who would then be able to offer lower prices than the incumbents. While this might be criticized as being akin to an “introductory” credit card rate, the key issue here is to establish a more advantageous position for non-incumbent retailers using an instrument with a well-defined sunset clause. Greater competition keeps prices lower, and the regulator-sponsored website makes it easier for consumers to find those prices. A possible recipe for a vibrant retail market in Australia.
Energiewende, German for “energy transition,” was the theme of the “Texas-Germany Bilateral Dialogue on Challenges and Opportunities in the Electricity Market” conference held in Austin in late February. The conference was organized by the German American Chambers of Commerce and supported by the German Federal Ministry for Economic Affairs and Energy, in cooperation with ERCOT.
As is well-known, Germany has invested significantly in low-carbon technologies, and their efforts have arguably led to reduction in the cost of production of solar photovoltaics worldwide. Talking at the conference about the transition to a low-carbon energy system were representatives from the German federal government and ERCOT, as well as several companies and consultancies.
I asked about the levels of carbon dioxide emissions in electricity production in Germany and ERCOT. Somewhat remarkably, given the emphasis on carbon dioxide in the Energiewende, there was no direct information about carbon dioxide emissions in any of the presentations. There was information about the shares of renewables, but different speakers had different numbers relating to the total electrical energy and the contributions from various resources.
So I did some calculations. I found about 0.52 metric tons of carbon dioxide emissions per MWh of electricity production in ERCOT and between 0.33 and 0.43 metric tons of emissions per MWh in Germany — assuming 1 metric ton of emissions per MWh of coal generation, 0.5 metric tons per MWh of gas generation, and negligible emissions from renewables and nuclear, and using the energy contributions presented by Falk Bomeke, PhD (German Federal Ministry for Economic Affairs and Energy), Bill Magness (President and CEO, ERCOT) and Arne Genz (German Federal Ministry for Economic Affairs and Energy).
ERCOT per capita consumption of electricity is about double that of Germany, and the emissions calculations indicate that electricity generation in ERCOT emits more carbon dioxide per MWh, resulting in significantly more emissions of carbon dioxide per capita in ERCOT compared to Germany. Clearly, Germany has worked toward reducing its carbon dioxide emissions and has done so without an abundant endowment of low carbon resources.
In contrast, Texas has an astonishing endowment of natural gas and renewables. Although cities such as Austin and San Antonio have set targets for renewable integration, Texas policy has, largely speaking, been indifferent to carbon dioxide emissions. Imagine how much lower emissions would be if Texas policy was re-oriented toward a low carbon future.
Electricity markets have been restructured in many countries around the globe. There is a variety of different designs, and the differences can significantly affect our ability to handle new challenges, such as integrating high levels of renewables. What are the key differences between the US and EU electricity markets? I was able to pursue that question in depth during my research sabbatical at the Florence School of Regulation (FSR) last fall. It was one of the issues addressed in an online debate I had with Daniel Dobbeni, founding president of the European Network of Transmission System Operators (ENTSO-E). Below you can watch the full debate (55:12), hosted by FSR director Jean-Michel Glachant.
The definition of seams. Seams, we agreed, include the technical transmission limitations between regions (for example, between countries in Europe and between ISOs in the US) as well as the regulatory and market differences between these regions. Mr. Dobbeni observed that the long-life of electricity system assets together with the history of development in European countries have played an important part in forming these seams, but that they are evolving with the advent of system changes, including renewables. He advocated for removing the seams, and I agreed.
I argued for a consistent architecture to be applied across as large an area as possible, observing that such consistency was perhaps even more important than, for example, whether or not the market design was nodal (as in the US) or zonal (as in the EU). I mentioned that there were still significant seams at the day-ahead level in the US, particularly in the west, and to a lesser extent in the east, where there are several large ISOs with seams between them. There still remain significant technical seams due to limited transmission between the west, the ERCOT part of Texas, and the east. In the EU, the EU Pan-European Hybrid Electricity Market (EUPHEMIA) has removed seams due to market differences in the day-ahead level across many countries through so-called “market coupling” between the regions.
Mr. Dobbeni observed that seams should also eventually be removed in the intraday markets, which are in place in Europe but not the US, and that he was concerned about the technical difficulty of market coupling in balancing markets. I discussed what I understand is the fundamental philosophical difference between US markets and EU markets: in the US, the real-time market is the “final” market; in the EU, the day-ahead market plays most of this role, with the so-called balancing market at least historically being more akin to the deployment of ancillary services in a US-style market. Moreover, I commented on the need to reach geographical scale to enable real-time management of congestion issues such as loop flow.
Mr. Dobbeni emphasized that congestion management was being complicated by the increase in renewables. In addition, he observed that congestion management across borders was particularly complicated and that US-style ISOs that spanned borders were able to consider overall issues in a way that was difficult for the EU-style markets at the country level. He advocated for the enlargement of regions beyond member states, enabling balancing beyond individual states, with which I definitely agreed!
US RTOs and some larger European countries, I observed, are likely at a large enough geographical scale to effectively balance renewables. We agreed that reducing the effect of technical and regulatory borders between regions was desirable to help with balancing renewables, but that it might be difficult to imagine, for example, amalgamating PJM and MISO in the US for various political reasons. Analogous difficulties apply in the EU.
In response to a question from a listener, Mr. Dobbeni mentioned the organizational differences between the EU and US: in the former, the TSO owns assets and operates the market; in the latter, there is a separation of ownership of transmission and operation of the market.
A question was posed about interconnectors, and I responded that building transmission across borders in the US was a challenge, and that this posed particular difficulties in building transmission between renewable-rich regions and population centers in different states. In the EU, security of supply is particularly important in the context of interconnectors between countries, whereas this is less pressing in the US.
We also recognized that energy prices are not bringing forth new capacity, and that prices are more uncertain than in the past. Consequently, even though we both were skeptical about capacity markets, there is evidently a problem. Mr. Dobbeni observed that, while there was overall a very large generation capacity in the EU, there are regional variations in capacity and many uncertainties in the long term. Restructuring in the US, I added, had focused on the generation-side. Now we need more participation by the demand-side in the market as part of the solution to the market providing the right amount of capacity. I also emphasized that the next five years will be the test of the ERCOT energy-only market.
Hurricane Maria has caused huge damage in Puerto Rico, particularly to infrastructure such as the electricity system. My sincerest sympathies go to everyone there, both in PR and in other regions. As my previous work on electricity network interdiction suggests, repair of electricity networks can depend significantly on the long lead-times to order and build extra-high voltage and high voltage transformers. As Puerto Ricans begin to restore services such as electricity, an issue that should be considered carefully is the desired end-point for their replacement electricity infrastructure and whether they should effectively rebuild their previous network or build according to a new design.
Most expansion of transmission networks, and most repair situations, involves adding or replacing equipment in an existing network. This significantly constrains the sort of solutions that can be accomplished.
However, PR is faced with a rather different problem. Although I am not personally familiar with the full extent of damage, the reports in the press suggest significant destruction of most of the network. Repair back to the state prior to the hurricane may involve rebuilding essentially everything. Under such circumstances, and given that future hurricanes may be at least as destructive to a conventional electricity system, it is prudent to step back and consider alternatives.
As an example of an alternative, perhaps a more distributed structure that plans for distributed renewables would be a better approach. Existing electric distribution networks are typically limited in the amount of distributed generation they can integrate. In the mainland US at least, the limits are typically not due to the distribution line capacity itself, but to things like “protection schemes,” typically using fuses, that were designed with the assumption of one-way flow toward consumers. In an existing system, upgrading to allow for net flow from the distribution system into the transmission system can require significant incremental investment to replace protection systems. For a system being fully built from scratch, however, it may be possible to incorporate more flexible protection systems from the start.
This and other issues should be considered carefully before large amounts of money are spent in PR on rebuilding a system according to a design that has already been shown to be vulnerable to the next hurricane.
Despite the end-of-school-year mania, I managed to get away to the 2017 IEEE Innovative Smart Grid Technologies conference in Washington, DC, in late April, to talk about the Smart Grid grad course that I was wrapping up at UT. I participated in a panel, “Innovations in Smart Grid Education,” chaired by Dr. Kenneth Lutz of the University of Delaware, with participants from MIT, the University of Illinois at Urbana-Champain, Wichita State University, and Clemson University.
I talked about the Smart Grid grad course I taught at UT this semester, making the point that “smart grid” discussions in practice are often focused on the distribution system and end-use, despite typical definitions in the literature being more general. I took an expansive definition in this class, including transmission and generation, for example, which also allowed me to invite colleagues from ERCOT and Oncor to participate.
Why do I use an expansive definition in my pedagogy?
Because the phrase “smart grid” implies that the existing grid is stupid. In fact, for many years in North America and elsewhere, operation of the transmission grid has been incredibly sophisticated — far more sophisticated than any other infrastructure system I’m aware of.
When we focus only on making the distribution grid smart, we risk throwing the baby out with the bathwater, by not building on the existing smarts in the transmission system.
In terms of pedagogy, this means students need to be aware of the entire grid, both smart and not-so-smart, in order to avoid a skewed perspective on the electricity system. As we look toward solving problems such as integrating high levels of distributed solar PV, we need to remember that the existing transmission and generation system provides the foundational infrastructure.
Highlights of the course include an overview of architecture of the smart grid, the generation and transmission system, distribution systems, and end-use. The strongest common theme: we are all searching for a good textbook!
Ross Baldick PhD provides strategic consulting to the electricity industry. Professor of Electrical and Computer Engineering at The University of Texas, he is the author of "Applied Optimization: Formulation and Algorithms for Engineering Systems."