The New York Department of Public Service released its long-awaited staff report on the value of distributed energy on Thursday, which is the first step in moving community and commercial projects away from retail-rate net energy metering.
For the past year, stakeholders have been at the table hammering out how to more fully value distributed energy generation, most of which is solar PV, while not completely upending the existing market.
“At the very highest level, we feel this is good progress,” said Melissa Kemp, policy co-chair of the New York Solar Energy Industries Association.
Among the recommendations, the report states that existing solar projects should receive the full retail-rate net energy metering (NEM) credit for 20 years from the date of installation. The report also calls for preserving retail-rate NEM for new residential and small commercial projects through 2020, then stepping down the credit until it aligns with the ultimate LMP+D value in the DER docket -- in line with a settlement agreement reached between several utility and solar stakeholders earlier this year.
The entire aim of the docket is to move away from a traditional NEM policy. The staff report states that "NEM provides an imprecise and incomplete signal of the full value and costs of DERs. [...] The purpose of this ongoing proceeding is to develop accurate pricing for DERs that reflects the actual value DERs create."
It turns out that achieving accuracy is an incredibly complex process. While compensation for residential and small commercial DER projects will remain unchanged in the near term, the report establishes new interim compensation measures for commercial and industrial, as well as larger community distributed generation projects. The latter makes up a significant portion of New York state's enormous net metering interconnection queue.
The transition path
For community-scale and C&I projects, the transition to new rates begins right away, but will evolve over time. The phase one rate is essentially a blend of an energy value, capacity value, environmental value and a market transition credit.
For projects that are already underway but will not come into service until after these new rates go into effect, they can be compensated under the current net metering policy if they pay 25 percent of the interconnection costs or execute an interconnection contract within 90 days of the phase one order being issued. Work on a phase two proposal will start immediately, and it will be filed in December 2018.
"We are encouraged to see the report set out a path that could finally get the community solar market off the ground in New York -- it would allow an initial set of projects to proceed under current net metering rates, and start delivering savings to customers across the state,” said Jeff Cramer, executive director of Coalition for Community Solar Access. “We appreciate that it seeks to more accurately reflect locational values and societal benefits while also providing some degree of certainty. But this is a brand-new construct for the industry, and it is complicated.”
Although the phase one rate is complex, it is actually less complex than it was even a few weeks ago in a straw proposal. The energy value is perhaps the most straightforward, and will be calculated “the same way as charges for mandatory hourly pricing customers are calculated and will therefore include avoided losses,” according to the DPS proposal.
The capacity value is where significant disagreement comes in, although the solar industry is confident it will be a value they can work with. One previous proposal from the commission staff was to define the capacity value based on the peak hour in the previous year, multiplied by the capacity spot price in NYISO. But that would produce an incredible amount of variability, which the commission acknowledges, and would make project financing a nightmare.
So instead, the proposal suggests a capacity value that is the capacity portion of a utility’s supply charge for the service class, with a load profile that is most similar to the solar generation’s load profile. “It’s basically a capacity value that could be predictable,” said Kemp.
But, just to keep things interesting, the phase one proposal also offers an alternative: for the capacity to be assigned to specific summer hours. The proposal argues that it would produce a similar capacity value, but would encourage projects to be designed to address summer peaks. “Solar could lose significant value,” said Kemp, as peaks are often later than the time during which solar PV systems reach their peak output. “But this isn’t just about losing value. It’s about predictability.”
While stakeholders will undoubtedly be filing comments around the capacity value, there may be more agreement around the environmental value. The DPS staff admits that it will be a crude calculation, and essentially they are just trying to get a value that is equal to or greater than the social cost of carbon as calculated by the U.S. Environmental Protection Agency. For phase one, the environmental value will be defined using the price of Tier 1 renewable energy certificates in New York’s market. The commission will also take steps to ensure there isn’t double counting of RECs once this value is in place.
Another point of contention was defining the distribution value. On that issue the proposal essentially punts to phase two: “The Value of DER process has not produced a valuation methodology that identifies and includes all potential distribution system values and this is an area where significant evolution is expected during Phase Two.”
For phase one, there will just be the market transition credit (MTC) -- except some projects will not get the MTC, and they will get some other form of additional compensation for value provided to the distribution grid. The latter compensation is incredibly complex, and involves taking a demand response rate and picking it apart to get a “locational system relief value” that is applied to the 10 highest hours per year. Many stakeholders will certainly take issue with the complexity proposed here, even though it may not affect most projects in the near term.
Most projects theoretically would just get the MTC. The MTC is expected to make the estimated compensation for a project equal to the existing net metering in the first tranche, 10 percent less than net metering in the second tranche and 20 percent less in the third tranche.
For most utilities, tranches zero and one, which would essentially preserve compensation at net metering values, offer significant headroom. Staff determined a reasonable upper bound for possible net revenue impact during phase one to be 2 percent of a utility's incremental net annual revenue. Based on that calculation, National Grid defines tranches zero and one as having more than 2 gigawatts of capacity. However, Central Hudson and Orange & Rockland, two utilities with significant community solar pipelines, have defined tranches zero and one at 39 and 76 megawatts, respectively.
“We want to make sure there’s enough room for projects to be able to be developed for the next two years,” said Kemp. Once the rate drops to 80 percent of retail net metering, it could be challenging in some utility territories to make community solar pencil out, especially when including low-income customers.
Some stakeholders have a concern about the complexity of the phase one rate and also the fact that community solar will be valued differently than on-site residential solar, which could unfairly cut low-income customers out of community solar. “The methodology is so complicated that consumers will never understand it, putting an end to [community solar] adoption by the mass market, and the inability to predict the value with any certainty will keep the investment community from wanting anything to do with financing [community solar] projects,” argues Robb Jetty, founder of Renovus Solar.
But other stakeholders are sure they can make it work. “Our members are digging into the models now to evaluate the impact on project economics across the state,” said Cramer, “and we will use the comment opportunity to provide final feedback we have on making sure this interim program can work for customers."