Offshore wind developers yesterday presented a proposal to set up a mechanism for financing up to 1,100 megawatts of wind farms off the Jersey coast, but the proposal raised more questions than it answered among state regulatory officials.
The proposal, a consensus mechanism agreed upon by several offshore wind developers, suggests a framework for how the New Jersey Board of Public Utilities (BPU) could award ratepayer-subsidized credits to the wind farms for the electricity they generate. That would guarantee the projects a steady stream of funding that should convince banks to invest in the clean energy technology.
What the proposal failed to spell out, however, was any semblance of what these projects -- priced at upward of $5 billion by some -- would cost ratepayers, who ultimately will foot the bill, under bipartisan legislation signed into law by Gov. Chris Christie.
That left BPU and Division of Rate Counsel officials frustrated, particularly over lack of details of how precisely the developers' proposal would work.
"There’s a lot of work to do. The things I'm concerned about include whether risks are being shifted to ratepayers," said Stefanie Brand, director of the Division of Rate Counsel after the two-hour stakeholder meeting. "I'm worried about the cost. It's expensive."
Just how expensive will not be apparent until the offshore developers submit applications to the BPU, a process that appears to be growing more extended given the complexity of turning the developers' mechanism into an actual regulation. Board staff repeatedly pressed the developers for more details about many aspects of their proposal, saying the commissioners would be reluctant to act on any proposal with so many questions left unanswered.
"If there are any unanswered questions, I don’t think the board will go for it," said Mark Beyer, chief economist for the agency.
Under the offshore wind bill, the developers propose the price they will receive for the power the wind turbines produce. It will be up to the state agency to determine whether the cost is justified when weighed against other factors, such as generating cleaner power, jobs an offshore wind industry could generate, and increasing reliability of the regional power grid. The price would remain unchanged for 20 years.
In approving a price for the credits, the board would consider the project’s total revenue requirement, including its cost of capital, debt service, operations, maintenance, overhead and administrative expenses. The agency also will establish the amount of credits each project is allowed to sell in each year.
One utility executive has projected the cost to ratepayers for paying for offshore renewable energy certificates (ORECs), the credits developers earn for electricity from the wind farms, could run as much as $600 million a year. Those payments would be offset by electricity generated by the turbines and the capacity payments the farms receive for providing extra power to the grid. It is still unclear exactly how much those payments, which will be returned to electric customers with certain exceptions, will be.
Under the developers proposal, the board would also establish an offshore wind carve-out, specifying a schedule of how many credits power suppliers would have to buy from the offshore wind farms, similar to requirements set for the solar energy sector.
While the developers insisted their proposal was not that complicated, it entails setting up a "clearinghouse’" to manage the stream of revenue from suppliers who are obligated to buy the credits. The clearinghouse also would oversee the payments from the regional power grid for the electricity and capacity provided by the wind farms, payments that are supposed to go back to ratepayers.
Besides questions revolving around how the clearinghouse would function, board staff also pressed for more clarity on a reserve fund suggested by the developers, which would help the offshore wind farms meet revenue requirements if there is insufficient demand for the credits they produce or a power supplier defaults on its obligations to buy credits.
A third stakeholder meeting on the issue is scheduled in two weeks, but board staff hinted that with so many questions still unresolved, there may be a need for more meetings.