Net metering and community solar
The shifting net metering policies in the United States affect the economics of community solar as well as residential solar.
Community solar relies on economic incentives offered by state net metering policies to attract subscribers and maintain viability. As traditional net metering continues to come under scrutiny, the effect of decreased compensation has the potential to hinder the deployment of community solar.
Traditional net metering policies give credits to utility customers at retail rates for excess energy exported to the grid, effectively “rolling back” the meter for excess energy that onsite systems feed back into the grid and charging the customer only for the “net” energy the customer uses.
Virtual net metering and community solar, as the terms are most commonly used, are variations on traditional net metering.
“Virtual net metering” extends the benefits that a customer would receive by feeding excess electricity from his or her own solar system into the grid to customers who do not share the same meter as the solar installation. The customer may be in a different location or the same location as the solar installation. A typical example of a customer in the same location is an installation on the roof of an apartment building, the earned net metering credits of which are distributed among participating tenants on all floors.
“Community solar” projects, “solar gardens” or “solar farms” are utility-scale solar arrays that feed their electricity to the local utility but sell subscriptions in that electricity or in certain panels to local residents. The local residents receive bill credits from the local utility for their shares of the electricity. Put differently, such projects use virtual net metering to bring the benefits of net metering to customers through a solar installation in a different location than the subscribers. A developer can build a solar array at a site location optimal for solar power production that is miles away from its subscribers located in multiple buildings, and still distribute earned net metering credits among all of those subscribers. The key to financing community solar is whether a project has and can maintain subscribers. Those subscribers are motivated in large part by utility bill savings offered by net metering.
Net metering and community solar policies are largely created and regulated at the state level.
The general trend is for state-level re-examination of traditional net metering policies with a focus on revisiting compensation rates in particular. Nevada and Hawaii were the first two states to walk back their net metering programs. The two states overhauled their net metering programs at the end of 2015, disrupting solar markets particularly in Nevada. A trend toward gradual changes in policy has since emerged in other states. (For more detailed reporting on this trend, see “Net Metering Debate Moves East” in the June 2016 NewsWire and “Net Metering: Opportunities on the Road to Reform” in the October 2016 NewsWire.)
At the same time traditional net metering policies are being re-evaluated, community solar appears to be gaining in popularity. Seven states and the District of Columbia took action on community solar in 2015. As of the third quarter of 2017, at least 13 states have taken action. Twenty-six states have at least one community solar project in operation. The balance of this article examines developing community solar policies in two key community solar states — Massachusetts and Illinois — and how they intersect with net metering.
Massachusetts is one of the top four US states with the largest amount of installed community solar capacity as of mid-2017. The state is expected to remain among the top four in terms of new community solar capacity installed over the next two years. The current community solar regime in Massachusetts offers net metering coupled with solar renewable energy credits, or SRECs, but a replacement program is expected to become effective in 2018.
Massachusetts has statewide caps that limit the percentage of a utility’s load that can be net metered.
After a statewide cap on total net metered systems was reached in mid-2016, Massachusetts implemented a new policy preserving close to retail rates for net-metered electricity from new systems sized at 25 kilowatts or below and systems with public offtakers, but reducing compensation to 60% of excess generation for new projects over 25 kilowatts with private offtakers.
Massachusetts enacted an SREC and successor SREC II program to support its renewable portfolio standard targets.
Community solar development in the state has benefited from the SREC II program. The current SREC II program allows qualifying facilities to generate SRECs that generators can then sell on the open market or, if that fails, sell through the Solar Credit Clearinghouse Auction II. Utilities need SRECs to demonstrate the percentage of their electricity that is supplied from renewable energy. Any utility that comes up short at the end of the year must pay an alternative compliance payment.
The SREC II program assigns different types of projects a multiplier as to the amount of SRECs to which it is entitled for electricity generated based on factors such as type, size, location and ratepayer level of income.
Community solar projects fall into the category with the highest multiplier. Projects that qualify for the SREC II program can generate SRECs for 10 years. These projects may continue to generate and sell SRECs after any new program is implemented.
Massachusetts is replacing the SREC II program with the Solar Massachusetts Renewable Target (SMART) program.
The SMART program is intended to replace SRECs and temper the pricing volatility of the SREC market. The Massachusetts Department of Energy Resources adopted final regulations at 225 CMR 20.00 in late August. The program aims to add 1,600 megawatts of solar capacity using an innovative approach. Eligible projects must be five megawatts or smaller. The program will first set a base incentive price for the first 100 megawatts of projects through a competitive bidding process, then allocate eight 200-megawatt blocks of solar energy over time using declining incentive prices.
Based on the initial clearing price, different types of projects will be eligible for different rates of compensation and term lengths based on factors such as system size, location, type of offtaker (community solar, low-income and public entity offtakers each have an adder), use of battery storage and use of a solar tracker. There are also subtracting factors for use of certain types of land including greenfield land. The base compensation rates decline 4% per capacity block. Compensation rate adders will decline by 4% per tranche of capacity. The first tranche for each adder is set by the program at 80 megawatts, with the Department of Energy Resources choosing the capacity of additional tranches.
The SMART program also includes provisions preventing segmentation of larger facilities into smaller facilities to obtain more favorable rates as well as several consumer protection provisions. Systems 25 kilowatts or below are eligible to receive compensation under the SMART program for 10 years while systems over 25 kilowatts are eligible for 20 years.
In calculating incentive payments, the program distinguishes between standalone solar generation units, which do not serve an associated on-site load before being interconnected to the grid, and behind-the-meter solar generation units, which do serve an on-site load and receive compensation under existing programs including net metering. The program offers an alternative on-bill credit for standalone solar generation units that do not fall under the existing net metering regime, but are enrolled in a tariff establishing a bill credit.
This bill credit tariff is likely to be particularly relevant for community solar projects, as three of the main Massachusetts utilities have already hit their net metering caps.
The SMART program does not lift the current statewide caps on net metering. Draft bills S. 1824 and H. 2712 are currently under consideration by the Massachusetts legislature, each proposing to raise public and private net metering caps by 5%.
The SMART program directs electric distribution companies to file tariffs for approval. The distribution companies filed a draft model tariff in docket D.P.U. 17-140 that is currently open for comment. They also issued a request for proposals on November 13 for the initial 100-megawatt block. Bids had to be submitted between November 27 and December 5. The results will be announced by January 11, 2018. The aim is to have the SMART program in place in early 2018.
Illinois offers net metering coupled with SRECs, similarly to the current scheme in place in Massachusetts.
SB 2814 or the Future Energy Jobs Act passed in Illinois in December 2016 directing electric utilities to expand net metering to apply to community renewable generation projects, facilities on property owned or leased by multiple customers within a utility service territory and projects that service multiple customers within a single building, each up to two megawatts. The new law also directs the Illinois Power Authority to develop a draft procurement plan.
Net-metered systems in Illinois are generally credited at the retail rate, but capped when net-metered systems account for 5% of the total peak demand of a utility’s eligible customers, measured in the previous year. After the cap is reached, new installations are credited for the cost of energy only. The state does not expect caps to be reached before late 2019, when it intends to update the final plan.
The new law requires each electric utility to file tariffs for community renewable generation projects by August 2017, meaning the amount each utility will pay for net metered electricity. The tariffs were filed and approved in late September.
The Commonwealth Edison Company tariff was approved in docket no. 17-0350. Notably, the tariff does not include compensation for transmission- and distribution-related charges. The MidAmerican Energy Company tariff was approved in docket no. 17-0368. The approved tariff compensates customers at only the supply charge, modified by certain adjustment factors. The Ameren Illinois Company’s revised rate similarly compensates subscribers at a lower-than-retail rate.
The Illinois Power Authority released a long-awaited long-term renewable resources procurement plan on September 29. The plan is part of a larger effort to meet the state RPS targets.
Among other things, the plan commits the Illinois Power Authority to implement an “adjustable block program” that includes administratively determined prices for renewable energy credits rather than pricing through competitive procurement, as well as a “community renewable generation program” that is a subset of the adjustable block program for community solar.
The adjustable block program brings some certainty to REC pricing. Two types of projects are eligible to participate in the program: “photovoltaic distributed renewable energy generation devices” and “photovoltaic community renewable generation projects.”
Photovoltaic distributed renewable energy generation devices cannot be larger than two megawatts in size. They must connect to a distribution system rather than the transmission grid, be on the customer side of the meter and be used primarily to offset that customer’s own electric load.
Photovoltaic community renewable generation projects are similar, except they must credit the value of the electricity generated to subscribers.
At least 25% of RECs awarded under the adjustable block program must come from distributed renewable energy generation devices no larger than 10 kilowatts, 25% from distributed renewable energy generation devices above 10 kilowatts up to two megawatts, 25% from photovoltaic community renewable generation projects and the remainder are allocated by the Illinois Power Authority at its discretion in response to demand.
There is a statutory requirement for utilities to prepay the purchase price in full for REC contracts entered into for systems no larger than 10 kilowatts, and 20% of the purchase price for larger systems and community renewable generation projects. Contracts must be at least 15 years in length. Community solar projects must demonstrate a minimum level of subscribers before receiving payment for RECs. At least 50% of project capacity must be subscribed under the current draft of the plan.
The adjustable block program uses a “block” concept. A block represents a certain amount of generating capacity at a certain REC price. Progression from one pricing block to the next is triggered by volume of deployed capacity. When a block’s allocated capacity is filled, it closes and the next block opens at a different price, predicted to be 4% lower than the price for the previous block.
To pre-empt end-of-block rushes, all projects submitted within 60 days of the opening of the program will be included in the first block regardless of capacity filled, and for future blocks, the power authority will announce when capacity has been met but hold the block open for 14 days. Opening block volumes would be initially allocated at 22 megawatts each for small systems, large systems and community solar projects in group A (projects in Ameren, Mt. Carmel Public Utility and rural electric cooperative service territories) and 52 megawatts each in group B (projects in ComEd, MidAmerican and municipal utility service territories).
The Illinois Power Authority intends loosely to set pricing of the blocks using its own REC pricing model with adders for certain types of systems.
Adders to the base price are proposed for systems in the large system and community solar project categories (decreasing as size increases) as well as an additional adder for projects in the community solar project category that have 50% or more residential subscribers.
Community renewable generation projects cannot have a single subscriber accounting for more than 40% of the nameplate capacity of the project. Subscriptions must be portable for a customer moving within the service territory and transferable by the customer to another subscriber within the territory. The IPA is required to purchase RECs from subscribed shares of community renewable generation projects.
There are extensive proposed consumer protection measures.
The comment period for the draft plan ended on November 13. The plan must be approved by the Illinois Commerce Commission before it can take effect. Objections were required to be made to the ICC by December 18, and the ICC must decide by December 26 whether hearings are necessary. The ICC must confirm or modify the plan by a statutory deadline set for April 3, 2018.