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.
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.
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."