Understanding Critical Issues in the Nation’s Rapidly Changing Electricity Markets
Last updated: April 20, 2017
Advancements in technology have enabled consumers to install solar panels on their roofs more cheaply than ever before. This presents utility companies—which have for decades monopolized energy markets in the United States—with new challenges.
Utilities, many of which own the energy grids that distribute power, are reckoning with how to make money selling energy to customers who can produce it themselves. They need to determine how to regulate use and maintenance of the energy grid as more consumers use their own rooftop-generated solar power and sell some of it back to the utility. Regulators are grappling with how to implement policies that accommodate the needs both of rooftop solar customers and utilities. All parties must learn to adapt to a world with increasingly cheap and reliable renewable energy.
These issues are playing out around the country over an energy billing practice called “net metering.” The practice allows utility customers with rooftop solar to sell excess power back to utilities for some level of reimbursement, offsetting the upfront costs of installing solar panels.
Some states are looking beyond basic net metering practices and implementing dynamic ways to value all sources of distributed energy, including rooftop solar, small hydropower and geothermal. These new approaches address the limitations of net metering as a static method of reimbursing self-generated solar power, and reflect the nuanced discussions about the appropriate value of distributed energy resources (DERs) that are happening around the United States. In March 2017, the New York Public Service Commission voted to approve new rates that will value distributed energy systems—including but not exclusive to rooftop solar—based on time of energy use, location and grid needs. Other states like Massachusetts and California are making dynamic changes to their distributed energy policies, a more detailed discussion of which can be found below.
In 2017, net metering and distributed energy policies are under debate and could change in six key states.
How Net Metering Works
When homeowners and businesses install rooftop solar panels, the electricity they generate can be used to offset their monthly electric costs through a billing practice called net metering. If they produce more energy than they use, customers can sell the surplus power back to the utilities.
Based on the “net” difference between what people with rooftop solar generate and what they use, customers can lower their power bills or even receive “negative” power bills, where the power company pays the customers for their excess electricity. For the vast majority of states and utilities, distributed solar power has negligible effects on retail electricity prices and is likely to continue into the foreseeable future.
Net metering originated in the United States in 1979 as a way to compensate customers for their investment in renewable energy. This practice allowed utilities to capitalize on the growth of residential rooftop solar and other small-scale renewables—methods of distributed generation that stand in contrast to the classic centralized generation model normally supported by utilities.
Many utilities contend that existing net metering policies amount to a subsidy that is too expensive for the utilities as more customers adopt rooftop solar. The solar industry maintains that solar customers should be free to produce and consume their own self-generated power, and that rooftop solar panels bolster total grid capacity. The current controversy centers around the correct value of the surplus energy, as utilities seek to lower the price they pay for electricity from rooftop solar owners.
In 2016, 47 states and Washington D.C. took some type of policy action on rooftop or community solar. In just the last quarter of that year, 42 states and Washington D.C. took some form of action on distributed solar policy or rate design. Some utilities reimburse customers for their solar power at the higher “retail rate,” which is the same rate that they charge customers for grid power, also known as “parity pricing.” Other utilities reimburse customers at the lower “wholesale rate,” which is closer to the utility’s cost of producing or purchasing electricity from a third party. Still other utilities reimburse on a sliding scale between retail and wholesale, and in general the variety of rates depends on the pricing decisions that state Public Utility Commissions make on a regular basis. Until 2013—when Public Utility Commissions in California and Arizona considered raising monthly fees on solar users—most state policies and regulations favored the expansion of rooftop solar and thus paid the higher retail rate.
The Growth of Solar
Solar power is a major source of economic growth in the United States, with the residential solar market growing steadily since 2008. In 2016, almost 374,000 individuals worked, in whole or in part, for solar energy firms, according to the 2017 U.S. Energy and Employment Report. More than 260,000 of those employees spent the majority of their time on solar, with the remaining working only part time in the solar industry. The solar workforce increased by 25 percent in 2016.
The cost of solar has also dropped precipitously due to gains from economies of scale in Chinese production, ease in financing and favorable policies like tax credits and consumer rebates. In 1977, the average global price of solar power was $76.67 per watt. In 2015, the cost of solar plummeted to just 70 cents per watt, a decline of over 99 percent. The price of utility-scale solar energy hit an all time low in the fall of 2015 at 5 cents per kilowatt hour, according to Lawrence Berkeley National Lab. This is within the range of average wholesale electricity prices of 3 to 6 cents per kilowatt hour. The 2016 minimum unsubsidized levelized cost of energy for utility-scale thin film solar PV is $46 per megawatt-hour (MWh), compared to $60 per MWh for coal. The same measure of the cost of power for rooftop solar residential PV is $138 per MWh.
Rooftop solar plays an important role in the United States and other countries as they transition to a low-carbon economy by retiring old fossil fuel power plants and ramping up renewable energy. Bloomberg New Energy Finance (BNEF) estimates that renewables will account for two-thirds of the 8.6 terawatts of new generating capacity and almost 60 percent of the $11.4 trillion that will be invested in global power generation between 2015 and 2040. BNEF predicts that by 2040, global investment in utility-scale, rooftop and other small-scale solar will reach $3.4 trillion out of a total $7.8 trillion that will be invested in clean energy. The U.S. Bureau of Labor Statistics forecasts that the 2014-2024 job growth outlook for solar PV installers is 24 percent, much faster than the seven percent average for all occupations. The industry continues to grow rapidly, although the extension of the investment tax credit in 2016 pushed some projects into 2017 or later, causing a slowdown in major states states like California and making the third quarter of 2016 only the second time in five years that the residential photovoltaic (PV) market fell quarter-over-quarter.
The technology needed to successfully transition to a low-carbon economy already exists. The main challenge now is how to properly value electricity that flows from customers to utilities, instead of the other way around. This will be achieved successfully only when utilities, policymakers and solar companies can work together to develop mutually beneficial solutions that capitalize on the economic and sustainability benefits of solar power.
Policymakers, solar companies and utilities don’t always see eye-to-eye on the costs and benefits of net metering.
Utilities use the money from electric bills to maintain the grid and, in some cases, generate power. Since solar users have lower power bills, some utilities, regulators and utility industry groups claim that they are not sufficiently contributing to grid maintenance and are shifting those costs to customers that do not have solar. Utilities see these lower bills as endangering their legal obligation to provide consistent power and to maintain grid infrastructure. As a result, they argue that solar-equipped consumers are not paying enough for their use of the grid under some current net metering policies.
Utilities are particularly fearful of a scenario where grid maintenance costs rise, renewable energy costs drop and more rooftop solar customers leave the grid entirely. As customers leave, infrastructure and generation rates would continue to rise for the remaining ratepayers, giving them even more incentive to defect from the grid and switch to renewables. This phenomenon received widespread attention when a utility industry report referenced a similar occurrence in the telecom business and referred to it as a “death spiral.”
In recent years, solar customers have had either negligible or net positive effects on non-solar customers. A 2014 study commissioned by the Nevada Public Utility Commission (PUC) affirmed the findings of most other cost-benefit analyses of net metering: “non-participants are very nearly neutral and will experience neither a large benefit nor a cost due to new (net metering) installations.” Ultimately the Nevada PUC disregarded the study findings because it took issue with some of the pricing assumptions that the study made. Regardless, this highlights utilities’ fear that the burden on non-solar customers, and their own business model, could grow as more people continue to install rooftop solar.
In December 2016, the California Independent System Operator (CAISO), the state’s grid operator, said that the rapid growth of distributed solar was forcing it to rethink the need for a new transmission line in the Central Valley that would cost between $115 million and $145 million. A 2016 study by CAISO finds that utility-scale solar plants, with the correct type of power inverter technology, can provide critical reliability services to the grid.
Solar customers and installers argue that they are actually subsidizing the power grid, and warn utilities that they are depending on an outdated billing model. Surplus energy generated by solar panels reduces the strain on electric grids on warm days when demand soars and utilities are forced to buy additional power at high rates from third parties. Distributed generation also benefits all ratepayers by lessening utilities’ need to build and maintain new, expensive power plants and transmission lines because the electricity is used closer to where it is generated. But under today’s utility business model, these firms often make money by building new infrastructure, including power plants. This model poses a challenge in integrating additional solar power onto the grid because utilities have little incentive to support this type of distributed energy.
Utilities and solar companies often see themselves in opposition to one another, but they are actually better suited to cooperation than competition. Utilities want to avoid the “death spiral” by maintaining revenue and retaining ratepayers, and solar companies know that the majority of their customers will need to rely on the grid for at least some of their electricity when the sun is not shining.
Net metering and similar forms of compensation for distributed energy sources are policies with built-in compromises. But until broader reforms are made to utility business models and regulations, many experts see these policies as vital tools to integrate renewables into the energy economy, cut carbon emissions, and transition away from fossil fuels. By facilitating the use of small-scale renewables, net metering can help states meet their greenhouse gas reduction targets.
Six States to Watch in 2017
In March 2017, after more than five years of attempts at compromise between Arizona Public Service (APS), one of the state’s largest utilities, and solar advocates, the parties settled on a rate design system that gives a set of compensation options to distributed solar customers. The compromise compensation mechanism came after the Arizona Corporation Commission (ACC) voted in December 2016 to eliminate retail net metering. The agreement sets the “export rate” for rooftop solar customers at $0.129 per kilowatt-hour (kWh) for surplus energy that they send back onto the grid, starting in 2017. That rate would decline by 10 percent per year for new rooftop systems, and new customers can lock in their 10-year rate based on the year they sign up for the program. The agreement also creates an “offset rate” of around $0.105 that will be credited to solar customers’ utility bills for every kWh of self-generated solar power they consume.
The rates customers would receive under the new system—either for selling power back onto the grid or the “offset” rate for energy consumed onsite—are below the current rate for retail net metering. Existing solar customers can keep their original retail compensation rate for 20 years. If approved this summer by the ACC, the state energy regulator, Arizona will join a growing list of states where utilities and solar advocates have scrapped retail net metering for compromise deals based on a commonly agreed-to value of solar power.
In February 2017, the ACC approved new rates for Tucson Electric Power and its parent company, UNS Energy, that include new solar fees of $2.05 per month on residential and $0.35 per month for small commercial customers. These fees add around $8.50 to an average customer’s monthly bill.
In December 2016, the Nevada Public Utilities Commission (PUC) voted to restore retail net metering for residential solar customers of Sierra Pacific Power Company, a subsidiary of Berkshire Hathaway-owned utility NV Energy, located in the sparsely populated northern part of the state. The order came about a year after the PUC issued a different decision phasing out retail net metering, prompting an outcry from solar customers and advocates. This back-and-forth between solar advocates and utilities over the rules governing net metering is set to continue. One month after the PUC issued its order, NV Energy formally requested the PUC reverse its decision to restore retail net metering. The PUC had 40 days from the time of the request to either grant or deny it but determined it needed more time to make a decision so granted itself an extension.
In September 2016, Gov. Brian Sandoval’s New Energy Task Force recommended comprehensive statewide energy reforms, including a push for lawmakers to pass a bill that would reinstate retail net metering until regulators can approve a comprehensive measure on the value of solar. As the task force investigated the value of solar, the PUC approved a negotiated settlement between SolarCity, the Nevada Bureau of Consumer Protection, and utility NV Energy, grandfathering retail rates for about 32,000 solar owners for 20 years. In June 2017, the PUC is expected to take up net metering again in the general rate case for Nevada Power, NV Energy’s subsidiary serving the southern, more populous portion of the state.
In January 2016, the California Public Utilities Commission enacted the successor to the state’s net energy metering known as NEM 2.0. The policy upheld retail rates paid back to solar customers for their surplus energy, an important element for which solar companies had advocated. The new policy regime also implements a “time-of-use” (TOU) rate change for solar net metered customers starting in 2019, meaning payback rates will change depending on the time of day customers use and produce energy. The PUC did this to align net metering rates with the real-time costs of generating and transmitting energy across the grid. The new TOU rule falls under a broad set of residential rate changes the California PUC put in place in 2015.
In June 2016, San Diego Gas & Electric became the first utility in the state to switch to NEM 2.0 after hitting the net metering cap, the limit that states set on the percentage of the grid’s peak load that can come from rooftop solar. The utility reports that 90,000 of its customers have already installed rooftop solar. Pacific Gas & Electric and Southern California Edison, the state’s other two large utilities, will transition no later than July 2017.
In September 2016, the California PUC rejected challenges by three investor-owned utilities to NEM 2.0. The utilities claimed that the new policy would cause unlawful cost shifting and cross subsidization. The PUC denied this claim and stated that “cost-shifting, subsidies, and similar incentive mechanisms are not inherently unlawful,” but rather are mechanisms the state uses to support programs and objectives. In March 2017, PV-Magazine reported that switching to NEM 2.0 has slowed down California’s residential solar market, although reports from California Solar Energy Industries Association (CalSEIA), GTM Research and others differ on whether the modest slowdown was caused by implementing NEM 2.0.
In February 2017, the Indiana Senate voted to end the state’s net metering program by 2027. The measure would replace net metering with a system requiring solar customers to sell all of the power they produce back to the utility at the wholesale price and buy it back at the retail price, in a so called “buy-all, sell-all” solar model. Solar energy accounts for less than 1 percent of Indiana’s power generation, and the state’s current net metering program is capped at 1 percent of summer peak. In early April 2017, the Indiana House passed a revised version of the bill, the Senate approved it days later. On May 2, 2017, Gov. Eric Holcomb signed the bill into law, drastically reducing the compensation rate that solar customers receive for their excess power. The new law allows those who install a rooftop solar system before 2022 to be grandfathered until 2032, but sets a far lower rate for people who install solar panels after 2022.
In April 2016, after months of solar policy debates in both houses of the Massachusetts state legislature, Gov. Charlie Baker signed a law that increases the net metering cap and lowers reimbursement rates for large-scale distributed solar projects like community solar arrays or large installations for commercial and industrial customers. The law strikes a compromise between utilities and solar advocates by raising the cap by three percent and maintaining reimbursement rates closer to the retail rate for smaller-scale residential solar installations. Before the law passed, net metering projects were capped at four percent of the utility’s load for private projects and five percent for municipal and government projects. The new law raises the caps to seven percent for private projects and eight percent for public projects and enables utilities to charge a minimum fee.
The Massachusetts Department of Energy Resources is now in the process of designing a new solar incentive program that is required by the law Gov. Baker signed in 2016. The Solar Massachusetts Renewable Target (SMART) Program sets a base price for solar through a competitive auction, allocating larger blocks of solar energy over time and declining incentive prices. SMART creates a system where solar projects of different types would be eligible for different incentives. As of March 2017, utilities and solar companies are continuing to work with the state on the SMART solar program design.
In March 2017, the New York Public Service Commission (PSC) voted to approve new rates that will value distributed energy systems–including but not exclusive to rooftop solar–based on time of use, location and grid needs. This approach is different from simple net metering policies that pay back customers a retail or wholesale rate but do not take into account their location or time of energy use. The policy is a compromise between rooftop solar users and utilities because it grandfathers in all residential and small commercial customers to net metering through 2020, but larger projects will move to the new tariff system that uses adjustable rates.
The new compensation structure, called Value Stack, creates a methodology for determining avoided costs and the values of DERs. After utilities and other stakeholders go through the first phase of the Value Stack process, the PSC will issue another order to improve the valuation process and more accurately identify energy costs and values of DERs. Utilities have until May 1 to develop pricing for DERs depending on their location. The commission will then issue another order to improve the Value Stack and identify costs and values of DERs more accurately.
Last updated: April 20, 2017