The Risks of Going Solar
If you’re thinking of putting solar panels on your roof to save money on your electricity bills, you should recognize that there is risk involved. In some ways, this is no different from any other long-lived investment. For example, if you pay extra for a hybrid or plug-in car, you run the risk that gas prices fall after you buy the car and your investment doesn’t pay off.
What’s different with distributed solar is that much of risk is in the hands of a regulator. That changes the nature of the uncertainty. With most financial risks, there’s a big chance that the underlying prices will go up or down by say 5% but a much smaller chance that they’ll change by over 50%. Also, we have years of experience tracking things like gas prices, so we think we have some understanding of their likely future variations.
Regulators around the world are making decisions that either highlight the solar risk or attempt to mitigate it. We’ll get to a couple examples below, but first, let’s go through the basic components of an investment calculation for a potential solar customer.
If you don’t have solar, you pay your local utility for electricity. In most parts of the world, you pay a monthly fixed charge and then a price for each kilowatt-hour you buy. In some cases, the price you pay per kilowatt-hour increases with the amount you consume over the month with what’s known as increasing-block pricing.
If you’re contemplating solar, the crucial question to ask is how the kilowatt-hours produced by your solar panels will be treated. The two prominent options are “net metering” and “buy-all, sell-all.”
Under net metering, the solar production is netted off your electricity consumption and you pay your utility for the balance. For example, if you usually consume 1,000 kWh of electricity per month and then install solar panels that generate 600 kWh per month, your net electricity consumptions goes down to 400 kWh. Most states in the U.S. have net metering.
You should also estimate what your new monthly utility bills will be. Given that utility rates are very rarely as simple as a single price per kWh, a 60% reduction in net consumption, as in our example above, could lower your bill by more or less than 60%. For example, if the fixed monthly charge is large, the percentage bill reduction could be considerably smaller, but if you have increasing-block pricing the saving could exceed 60%. Also, if you will ever be selling electricity back to the grid, you’ll want to know how the utility will reimburse those sales.
Finally, if your solar will be net metered, you should determine over what time period the netting takes place. While most states net on a monthly or even annual basis, smart meters allow utilities to track electricity consumption at the hourly or even sub-hourly level. My read of the recent Nevada Public Utilities Commission decision suggests that they are moving to netting out solar consumption hour-by-hour (see point 126 on p. 66 of the Nevada order while NV Energy’s tariff suggests that it could even be every 15-minutes).
With hour-by-hour netting, you’re more likely to be selling to the utility in some hours and buying in other hours, whereas with monthly netting, you’re more likely to always be buying, which effectively credits the solar production at the retail rate. (Solar providers typically size the solar systems so that customers are at least buying a little electricity from the grid over a month.)
Under a buy-all, sell-all system, customers with solar panels continue to pay the utility for 100% of their consumption, and simultaneously sell 100% of the solar output back to the utility. This is also sometimes referred to as a “value of solar” tariff, as the ideal is for the regulator to determine the true value of the solar to the electric system and set the solar purchase price equal to that value.
Once you’ve calculated how much less (or more) you’ll be paying for electricity over the life of your panels, the key thing to recognize is that there could be regulatory decisions in the future that change the answer. And, regulators tend not to dabble in small 5% changes, so the changes can be dramatic.
Here are some recent regulatory decisions that either highlight that risk, or have attempted to mitigate it.
Nevada (high risk). Two months ago, Nevada regulators issued a decision that left many existing solar customers holding bad investments. Nevada is a net-metering state. The regulators didn’t eliminate net metering, but they implemented three changes that
made existing solar owners considerably worse off: (1) they increased the monthly fixed charge that solar customers will pay from $12.75 per month to almost $40, though the increase will be phased in over time, (2) they changed the netting to hourly rather than monthly, and (3) they instituted a low rate for sales to the grid. If the decision sticks, Greentech Media calculated that customers who signed 10-year contracts in 2015 would be losing money relative to not going solar beginning in 2017.
Minnesota (low risk). Minnesota decided in 2014 to allow its utilities to adopt a value of solar tariff, but so far none of them has. If they do, they must recalculate the value of solar every year, but individual customers are guaranteed the rate that they started with for at least 20 years. Also, solar customers are still paying for 100% of their consumption, so they will experience any changes to rates exactly the same whether or not they have solar.
With a locked in payment for your solar, you run the risk that you buy solar at the wrong time (e.g., right before the value of solar goes up) but other than this timing risk, solar customers are pretty insulated from future regulatory changes. Note that low risk is different from high return. The benefits to going solar in Minnesota are a function of the yet-to-be-determined value of solar.
California (medium risk). California recently issued a decision affirming that solar customers would continue to be net metered through 2019. Also, California grandfathers existing solar customers to the net-metering rates for 20 years, meaning they are effectively paid the full retail rate for 20 years, whatever the retail rate happens to be.
But, customers are still exposed to changes in the rates, which are very much in flux. This can impact both what solar customers are paying to their utility and what they would have paid without solar.
As Severin has explained, California’s investor-owned utilities have steeply increasing block rates, but those are scheduled to flatten over time. For example, PG&E’s rate for consumption in the top tier in the beginning of 2015 was 33.3 cents/kWh, but it’s scheduled to come down to 23 cents/kWh by 2019. So, if you calculated what you would save with solar based on the early 2015 rate, your solar investment will be worth considerably less than you thought. Also, California has committed to moving to time-of-use pricing as the default in 2019, with yet-to-be-determined peak periods.
Spain (high risk). Solar customers in much of Europe are in a buy-all, sell-all model. Consumers continue to pay for 100% of their consumption and the utility installs a second meter to measure the solar production and compensates it with a “feed-in-tariff” (FIT) rate. My read is that Spanish regulatory changes in 2013 (a) made consumers pay for hourly meters and (b) started CHARGING them for every kWh generated onsite.
In an attempt to help customers recognize the inherent risk, Arizona now requires solar customers to sign a form acknowledging that, “the Commission may alter its rules and regulations and/or change rates in the future. If this occurs, your PV system is subject to those changes and you will be responsible for paying any future increases to electricity rates.”
Regulatory decisions like these are becoming more and more common. They are also arcane, long and dense, as regulators operate through adjudicatory processes and need to address stakeholder comments. So, expect change if you’re contemplating going solar, and get ready to access your inner lawyer to wade through the changes.
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Catherine Wolfram View All
Catherine Wolfram is the William F. Pounds Professor of Energy Economics at the MIT Sloan School of Management. She previously served as the Cora Jane Flood Professor of Business Administration at the Haas School of Business at UC Berkeley. From March 2021 to October 2022, she served as the Deputy Assistant Secretary for Climate and Energy Economics at the U.S. Treasury, while on leave from UC Berkeley. Before leaving for government service, she was the Program Director of the National Bureau of Economic Research’s Environment and Energy Economics Program, Faculty Affiliate of the Energy Institute at Haas from 2000 to 2023, as well as Faculty Director of the Energy Institute from 2009 to 2018. Before joining the faculty at UC Berkeley, she was an Assistant Professor of Economics at Harvard. 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 working on several projects at the intersection of climate and trade. She received a PhD in Economics from MIT in 1996 and an AB from Harvard in 1989.
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This is a timely and valuable posting. While I agree with the risk regulatory actions bring electricity consumers investing in rooftop solar, it is important to recognize the risk as extending significantly beyond that introduced by actions of public utility commissions (PUC).
PUCs are to be held responsible for sending the wrong price signals and incentives for investment in rooftop solar. Capture theory can greatly help explain the PUCs role in this regard.
PUCs and regulators in general, however, whether in the US or overseas are on the receiving side of major influences: fuel price changes and fluctuations, pressures from environmental and energy efficiency groups, the role of organized markets, major fluctuation in wholesale electricity prices, the role of the PUCs as instruments of public policy, and the inability or rather unwillingness of proponents of solar energy to engage in understanding the true risks to rooftop solar posed by a changing electricity market as well as the risk inherent in basically incomplete or lagging regulations.
While my tendency is to apportion the blame on the PUCs as well as on proponents of rooftop solar energy, a good share of the blame need to be levelled at ourselves as energy professionals for the rather limited assessment of rooftop solar impact on the energy mix, the distributed generation equation, and the clean energy debate not to mention the role of solar in the economy at large.
It’s not clear to me that consumers installing rooftop solar should face the same risks in the energy markets as bulk generators. It depends on whether you view rooftop solar as a new commodity producer, or as a net energy reduction akin to energy efficiency. Rooftop solar is on the customer side of the meter which probably changes that equation.
Yes, rooftop solar is on the customer side. And, we wish that consumers installing rooftop solar don’t face the same risks in the energy markets as bulk generators and in fact they don’t. But as long as consumers installing rooftop solar are connected to the grid they remain susceptible, within bounds, to what goes on in the electricity market at large. This can be witnessed here in the US and internationally in regulatory decisions over interconnection charges, rates for sales to the grid, among others.
Yes, I agree with that premise, but on the other hand utilities should be required to continue commitments to customers akin to the same commitments that they make in long term PPAs. Utilities have gamed the system so that their shareholders were able to lock in 30+ year investment returns but have refused to provide reciprocal commitments to customers. Utilities gave those same long-term assurances to third party generators because the financial industry demanded them in the 1980s and 90s. If solar rooftop customers are to be exposed to market risks, then they also should be afforded the same hedging tools that are available to generators. It’s simply about political will on the part of the PUCs.
This discussion leads to a bigger question: Should residential customers with solar be required to face volatile wholesale spot prices? That’s the implication of going to hourly intervals and noting negative prices. But why should that be the case? Utilities sign multiyear PPAs with other generators. Residential customers are much less sophisticated than those generators and the transaction costs of negotiating contracts different from the utility tariffs (if even allowed) are high. Providing fixed power transaction prices with residential (and most commercial) customers makes sense from a public policy perspective.
Very nicely written posting that captures the risks of solar well.
One additional thought…. Once a customer invests in solar, the customer can only compare the cost of solar to the cost of utility supply immediately prior to the solar investment. Should rate designs change, the customer does not have visibility to the counterfactual risk that is described in this posting associated with rate design changes. Said more clearly, if a customer has a $400/month bill, and a rate design change lowers it to $250/month, the customer paying $300/month for solar never “sees” the foregone opportunity for a $250/month bill. Now, this isn’t entirely true, since one way to lower bills for high usage customers is to raise the monthly fixed charge, which would affect the customer with solar supply, but such charges are typically in the $10 to $25 range, which is small compared to the overall cost of electricity.
This suggests that there isn’t likely to be much of a ratepayer constituency that would oppose rate design changes, so the majority of opposition to rate design changes that would lower bills for high usage customers is likely to come from the solar industry.
These comments don’t apply to the risks of changes to net metering or buy/sell, which could be applied retroactively to reduce the value of bill credits received from solar production, of course.
Carl, the solar industry has a number of different types of purchase and lease arrangements, some of which are tied to existing utility rates. That’s why there’s so much interest in rate design going forward by both solar customers and vendors.
Catherine… Spain is an outlier. Buy all/Sell all is rare. As you probably know most of the distributed solar in the world is sold via FiTs. Assuming about half the installed PV is distributed this means about 100 GW out of the 125 GW of DG PV is sold via FiTs. In the lion’s share of cases (Germany, Italy, Australia, Japan, etc.) you only sell what you don’t self-consume. This means that 2 kW of onsite demand in hour X matched up against 3 kW of generation will result in a 1 kWh of sale.
This is a much needed post that draws attention to the risks that customers face when they go ahead and install solar on their roof. I have a few comments. First, regarding the future of inclining block rates in California, while you mention the projected decline in upper tier rates of roughly 10 cents/kWh, you don’t mention that the CPUC also intends to create a super user surcharge. While the surcharge has not been quantified, it will apply to usage that is significantly higher than the first tier. This is essentially a third tier rate which will make solar (and energy efficiency) more attractive to large consumers who are currently in the fourth tier. Second, you mention that the time period for the TOU rates that will kick in at some point is unspecified. This is bound to create controversy. And it already has done so. See this letter to the editor. http://www.contracostatimes.com/letters/ci_29537493/feb-22-letters-editor. Third, you don’t mention the risks associated with the federal income tax credit. Very few people expected that it would be extended by five years. Given the vagaries of Congress, it could just as unexpectedly be taken away. It will drastically affect the attractiveness of solar to customers who own their systems. And it will drastically affect the attractiveness of solar firms that lease the arrays (because they get to keep the income tax credit). Fourth, Hawaii, which has promised to give the rest of the country a postcard to the future, has eliminated NEM entirely. Other states might follow that lead. Fifth, more and more utilities are proposing to move toward three-part rates which will lower the volumetric price of electricity, making solar less attractive. Some utilities are going to have three-part rates for all customers while some will have them just for their solar customers. Finally, I have a couple of minor quibbles. You state that it is easier to predict gasoline prices than electricity prices. I don’t know of too many drivers who saw the massive drop in gasoline prices that took place over the past 18 months. And you also state that commissions don’t concern themselves with small changes in rates. Most of the cases go unnoticed because the rate changes are small.
Having said all of that, solar remains very attractive in high cost states such as California. Falling panel prices, continuation of net energy metering and continuation of the income tax credit are key drivers. On top of which comes the leasing model. One of my friends said to me at a dinner party: “Ahmad, you have nothing to lose if you lease solar panels. No upfront cash payments and guaranteed lower electric bills”. After a careful consideration of the options, I chose the energy efficiency route. I believe the cleanest kWh is the one that is not produced (because there is no demand for it), and the second cleanest one is the one that is produced by solar. Here is more: http://ahmadfaruqui.blogspot.com/2016/02/fighting-500-electricity-and-gas-bills.html
With the measurable externalities of global warming, if you are simply looking at your electric bill you are not seeing the big picture at all – and being rather selfish in the process. I am putting solar on my house in New Mexico and it will never pay back if you do current worth on the investment in terms of the utility bill. But with 70% of electricity in New Mexico coming from coal, the pay back is really enormous, Economists are why we are in trouble.
Of the various regulatory Risks of Going Solar, Catherine Wolfram indentifies two biggies, reducing the size of the net metering interval and shifting the rate design to include a smaller energy charge and a greater fixed charge. But the risk of these two can be much larger than Dr. Wolfram suggests. Reducing the size of the net metering interval exposes rooftop solar customers to the possibility of negative prices, while cost re-classification could result in (greater) demand charges instead of greater monthly customer charges.
In “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August, I point out that a surplus of wind in West Texas forced the wholesale price for electricity below zero for about 25% of the pricing periods during that April, at least in West Texas.
Transmission constraints generally kept these negative prices from spreading to the rest of Texas. Negative prices did spread to other parts of the state for just less than 1% of the rating periods. As Dr. Wolfram well pointed out, these pricing periods are sometimes as short as 15 minutes (as they were in West Texas at the time), though are often one hour.
Many ISO do not seem to allow prices to go negative. In West Texas, the combination of transmission constraints and the various credits given to wind led to negative prices. I believe that similar combinations elsewhere will force ISOs to allow negative prices in their dispatch programs.
I have long seen the need for utilities outside the footprint of an ISO to implement real time “value of solar” prices that are similarly negative. Hawaii seems to be ripe for such negative solar prices. Utilities outside the footprint of an ISO can implement “value of solar” prices using a Walrasian auction, as is discussed in many of my articles.
I actually disagree with the concept of a separate price for “value of solar.” If we are to use prices to influence generation, there shouldn’t be a separate price for solar versus other spot generation imbalances. A different price for unscheduled versus scheduled generation, yes, but not a separate price for just solar.
There will often be many prices during any pricing interval. For instance, a single 15 minute period may be part of a 24×7 contracted delivery of power with one price and part of a 16×5 contracted deliveries with another price. A third price might be applicable to variances. Variances would include both solar that is dumped into the system and hiccups in the 24×7 or 16×5 deliveries, whether the hiccup is positive or negative.
Utility rate making often includes the concept of cost classification, where costs are identified as energy related, customer related, and demand related. In the context of Risks of Going Solar, customer related and demand related are combined into the concept of a fixed charge.
The discussed increase in the monthly charge is only one way to reduce the energy charge. The other way, and I believe a better way, to decrease the energy charge is to increase the demand charge, or to implement a demand charge when there is not a demand charge in place.
Customer charges impose greater burdens on small, often lower income, residential customers, while demand charges tend to protect these smaller customers, as is discussed in
• “Curing the Death Spiral,” with Lori Cifuentes (Tampa Electric Company), Public Utilities Fortnightly, 2014 August;
• “Demand a Better Utility Charge During Era of Renewables: Getting Renewable Incentives Correct With Residential Demand Charges,” Dialogue, United States Association for Energy Economics, 2015 January; and,
• “Fairly Pricing Net Intervals While Keeping The Utility Financially Healthy,” 48th Annual Frontiers of Power Conference, cosponsored by The Engineering Energy Laboratory and The School of Electrical and Computer Engineering, Oklahoma State University, Stillwater, Oklahoma, 2015 October 26-27.
Thus, as we see a continued growth in solar, I see a growing need for finer pricing intervals and a growing need for demand charges. Fortunately, the huge growth in interval meters allow these better rate designs. We just need to political will to implement something other than a monthly charge for energy.
What you have identified is what large energy market participants have been dealing with since the issuance of FERC Order 888/889 in 1996 – major regulatory risk causing a devaluation of their capital investment. It has now trickled down to the consumer level. Fair enough.