New Jersey’s new solar power incentives program should use competitive solicitations to minimize costs and differentiate between project types and locations to ensure “a robust and diverse fleet,” consultants recommended to the Board of Public Utilities on Friday.

The BPU commissioned The Cadmus Group to produce the “New Jersey Solar Transition Final Capstone Report” in response to the Clean Energy Act of 2018 (AB-3723), which required the state to replace the Solar Renewable Energy Certificate (SREC) market with a lower-cost program to encourage solar development.

Ariane Benrey, program administrator, presented the report at a meeting Friday, where the BPU also approved two measures related to the state’s offshore wind projects and Public Service Electric and Gas’ (PSE&G) $778 million smart meter deployment (EO18101115). PSE&G will be the second utility in the state to install smart meters, following Rockland Electric. Smart meter proposals by Jersey Central Power & Light and Atlantic City Electric are pending before the BPU.

State of Transition

The Clean Energy Act required that the SREC program close once solar totals 5.1% of electricity sales, a threshold the state hit in April 2020. (See Solar Subsidy Program Ending in New Jersey.)

An interim, “transition” program took effect in May for projects registered with the state by the 5.1% milestone date but not yet operational, as well as projects registering after the milestone but before implementation of the successor program that is the subject of the capstone report.

Renewable energy credits (RECs) under the transition program range between $91.20 and $152/MWh, compared with an average of $214/MWh during the last five years of the SREC program, according to the state.

Under New Jersey’s 2019 Energy Master Plan, in-state solar would comprise 34% of the state’s electric generation by 2050 as part of Gov. Phil Murphy’s midcentury goal of 100% “clean energy.” The plan seeks 5.2 GW of in-state solar by 2025, 12.2 GW by 2030 and 32 GW by 2050.

The state registered about 3,476 MW of solar under the SREC program and estimates about 700 MW will be added under the transitional incentive, leaving about 8,020 MW to be filled under the successor program by 2030.

For the successor program, Cadmus recommended the BPU implement a fixed-incentive program, similar to the transition incentive, to “provide strong certainty, business visibility and especially ‘finance-ability.’” It said the fixed incentive would complement net metering incentives in the near term and could evolve into a “total compensation” program “to reflect more holistically the value of these projects to the market, grid and environment.”

It said the new program should ensure flexibility through a timetable of re-evaluations and potential revisions “while providing the industry with enough line-of-sight to enable long-term investment.”

The largest solar projects should receive incentives based on competitive solicitations, with administratively set incentives for smaller projects, Cadmus said. “This will enable market price discovery while establishing minimum incentive levels.”

The consultants also urged the use of megawatt-based targets that consider historical trends and segments that may have been underutilized in the past, such as commercial rooftops, solar carports and front-of-the-meter “grid supply” projects.

They also recommended differentiating between project customer classes, installation types, locations and technologies, noting that “variations in tariffs and interconnection costs across electric distribution company service territories, along with differences in construction costs between solar installation types, can have significant impacts on overall project economics.”

The BPU should order a study on the state’s total feasible capacity for solar, Cadmus added. “New Jersey was an early leader in solar in the United States and has developed a robust market. That relatively long history of success in installations, however, suggests that the developer community has likely spent significant time prospecting for optimal projects and that some of the best opportunities for solar may have been taken already for various project types or otherwise did not work under existing market structures,” it said.

‘Total Compensation’ vs. Fixed Incentives

The “total compensation” incentive, like the Solar Massachusetts Renewable Target (SMART) program, acts like a contract for differences between the value of energy and the total compensation paid.

One advantage of the SMART program, Cadmus said, is that it includes adders and subtractors to encourage a diversity of project types and discourage large-scale, ground-mounted projects in undeveloped spaces. Projects on landfills, parking lots and in “dual-use” agriculture — growing crops such as wheat, potatoes and beans under solar canopies — receive adders.

But the consultants said the SMART approach is also complex and can result in unintended consequences, with larger, front-of-the-meter (FTM) projects crowding out behind-the-meter (BTM) systems. As of September 2019, 60% of the large building-mounted and canopy systems in the Massachusetts program were installed as standalone projects instead of BTM systems. “BTM systems provide several benefits, including more economic opportunities to pair with battery storage and reduce on-site demand … reducing interconnection costs and utility work associated with creating new standalone service,” Cadmus said. “Amending regulations to correct this flaw has been proposed as part of the [current] review of the program.”

Fixed incentives offer set prices that are paid in addition to any revenues the facility may earn from electricity sales and costs avoided through reduced energy consumption. The programs, such as Connecticut’s Zero Emissions Renewable Energy Credit (ZREC), typically require transmission and distribution utilities to purchase RECs from solar electricity generators through long-term contracts.

Providing solar developers a reliable revenue source over a long period reduces lenders’ risks and the cost of capital. The simplicity of fixed incentives also reduces transaction costs.

But regulators can have problems determining the appropriate price level, Cadmus said. “If the price level is set too high, the market will accelerate too quickly, solar developers will capture excess profit and undesirable electricity rate increases may occur. Conversely, if the price level is set too low, the market will grow too slowly or not at all.”

And because it involves long-term contracts, fixed incentives lack market-responsiveness, although “program design can help mitigate some of these potential disadvantages,” Cadmus said.

The consultants proposed minimum 15-year incentives in the PSE&G territory, ranging from a low of $55/MWh for a community solar ground-based project to a high of $180/MWh for a commercial carport system with third-party ownership. Minimum incentives for residential rooftop systems were estimated at $95/MWh.

The 127-page report followed more than a dozen stakeholder meetings and a series of focus groups since January 2019.

With the release of the report, BPU staff recommended the board direct further stakeholder proceedings on developing the successor program. “The capstone report and underlying analysis should be considered as guidance only and … does not bind the board in any way on the development of a successor program or related incentives,” Program Administrator Benrey said.

BPU President Joseph Fiordaliso said the acceptance of the report was an “important step” in the development of a replacement for the SREC program, whose development in 2004 led to heated debates over its price tag.

He said he welcomed feedback on the report. “We [the BPU] don’t have all the answers,” Fiordaliso said. “Collectively, hopefully, we will.”

In a related matter, the board also approved a waiver of a requirement that applicants to the Community Solar Energy Pilot Program provide an interconnection upgrade cost assessment (QO20080556). The waiver applies only to projects proposed in the PSE&G service territory for program year 2, applications for which are due by Feb. 5. PSE&G informed BPU staff that it is unable to perform the requested interconnection cost assessments because of staffing constraints and an increase in interconnection study requests. In lieu of the assessments, applicants can submit a letter explaining why interconnection of the proposed project is likely to feasible.

Offshore Wind

The BPU on Friday also approved a solicitation for a consultant to help BPU staff work with PJM on transmission development for its offshore wind projects.

The board in November asked PJM  to conduct a competitive solicitation for upgrades to connect 6,400 MW of offshore wind to the regional grid under its FERC Order 1000 “state agreement approach.” (See NJ Asks PJM to Seek Bids for OSW Tx.)

Jim Ferris, bureau chief for new technology at the BPU, said PJM is incorporating the state’s request into the 2021 Regional Transmission Expansion Plan (RTEP) and is working with BPU and PJM staff and transmission developers to solicit options for the board’s consideration.

Ferris said the consultant will be asked to assist staff in the preparation and review of documents required for the RTEP process, engage with stakeholders, aid in an independent review of all submitted proposals and provide recommendations for the best transmission solutions resulting from the process.

Fiordaliso said the BPU lacks staff with the expertise to manage the complicated RTEP process. “If we don’t have people who are well versed in certain subject areas, the learning curve is steep,” Fiordaliso said.

Commissioner Dianne Solomon said it made sense to bring in outside expertise. “We’re wading into waters that really need some specialized background and information,” Solomon said. “Far be it from me to tell PJM what to do, but I hope they too will engage consultants in areas in the past where they’ve said they don’t have sufficient staff to address some of these issues.”

The board also unanimously approved a memorandum of understanding to provide the South Jersey Port Corp. with $1.8 million in funds generated by the Societal Benefits Charge “to support the development” of a facility to manufacture monopiles for offshore wind turbines at the Paulsboro Marine Terminal in Gloucester County (QO20120770).

Kelly Mooij, director of the BPU’s Division of Clean Energy, said developing an OSW supply chain with manufacturing in New Jersey will produce economic benefits and help reduce the cost of reaching the state’s clean energy goals.

Gov. Murphy announced the $250 million Port of Paulsboro project last month, saying it would be the largest industrial offshore wind investment in the U.S. and create more than 500 jobs at full buildout. Construction will break ground this month, with production beginning in 2023. EEW Group, a German monopile manufacturer, will operate the facility.

Commissioner Bob Gordon asked if $1.8 million was enough for the facility. He said he has been a supporter of the idea of developing a supply chain for OSW in New Jersey but wondered if the BPU knows what the funds will be used for.

“It just seems to me that $1.8 million is not a make-or-break expenditure and is almost an afterthought,” Gordon said.

Fiordaliso said the funds will be used for infrastructure on the site.