Stakeholders in recent filings with the New York Public Service Commission highlighted the difficulties the state faces in trying to integrate its clean energy goals with the wholesale power market operated by the New York Independent System Operator (NYISO) and, in particular, its capacity market that is designed to provide revenue to ensure enough capacity is built or stays online to keep the lights on.
The PSC began the proceeding, 19072/19-E-0530, in August to review the alignment of the NYISO’s resource adequacy programs with the state’s renewable energy and emission reduction goals. The commission stated that this inquiry was necessitated by its duty to assure safe and adequate electric service at just and reasonable rates.
The Climate Leadership and Community Protection Act (CLCPA), which became law in July of this year, requires that 70% of New York’s electricity must come from renewable resources by 2030 and 100% from emissions free resources by 2040. It also calls for 9,000 MW of offshore wind to be installed by 2035, 6,000 MW of solar power by 2025, and 3,000 MW of energy storage by 2030.
The challenges the state faces in meeting its multiple goals was summarized by several stakeholders as a fundamental conflict between the current wholesale market design and the state’s environmental policies.
In its filing, the Long Island Power Authority (LIPA) said the NYISO‘s “current resource adequacy mechanisms are not compatible with the State’s energy policies and mandates.” LIPA recommended several changes, including the exemption of state-mandated renewable resources from NYISO’s buyer side mitigation (BSM) measures.
Operators of capacity markets, such as NYISO, use BSM to essentially create a floor price for new capacity that is justified as needed to avoid skewing market pricing by artificially low prices from subsidized resources, such as nuclear plants receiving zero emission credits that states such as New York and Illinois have implemented.
But if state-mandated resources are not exempted from BSM, load serving entities would likely be forced to buy more capacity than necessary, resulting in higher prices for customers, LIPA argued.
In response to the NY PSC’s request for comments on mechanisms used in California or those under development at the PJM Interconnection, LIPA said “it is not clear” whether these approaches are better than the proposals within NYISO to expand buyer-side mitigation exemptions, while the ISO-NE approach is worse. PJM’s solution, for instance, could deprive renewable resources of capacity market revenues, which are often an essential source of funding for renewable energy projects.
In addition, if the costs of renewable technologies continue to fall, LIPA said NYISO “should revisit the implicit assumption that natural gas generation is the ‘marginal’ capacity resource.” NYISO’s existing installed capacity (ICAP) market demand curve for capacity is based on the net cost of new entry of a new natural gas turbine.
Similar concerns were voiced by the New York Municipal Power Agency (NYMPA), a joint action agency composed of 35 municipal members. If resources subsidized by ratepayers by mechanisms such as renewable energy credits (RECs), zero-emission credits or offshore wind RECs are exempted from capacity markets, “there is a real possibility that ratepayers will be paying twice, once through an extra-market mechanism, and again through the capacity markets,” NYMPA said in its filing.
On the other side of the equation, NYMPA noted that if capacity revenues are insufficient to support renewable projects, ratepayers may have to pay more under the indexed RECs the PSC has adopted for offshore wind projects and is considering for other resources. NYMPA said either approach would be “anathema” to its primary concern, costs to consumers.
Calling the current ICAP market an “untenable barrier” to achieving the state’s public policy goals, the New York Power Authority (NYPA) said the wholesale power market requires “significant” and prompt modifications. NYPA put potential solutions in two broad categories, a status quo approach that retains current ICAP mechanisms with modifications and an IRP approach that would use a central procurement authority similar to the way the California ISO works.
NYPA stressed that any approach undertaken should recognize the contribution of its hydroelectric resources and resources whose REC contracts have expired toward meeting the state’s goals. The authority also noted that the central procurement approach could increase costs because load serving entities would have to enter into power purchase agreements, which could “materially increase their debt obligations” because PPAs are treated as debt from an accounting perspective. NYPA suggested that the New York State Energy Research and Development Authority could step into the central procurement role, allocating the costs of procurement to LSEs while enabling them to avoid carrying individual PPAs on their books.
In its filing, the New York Association of Public Power (NYAPP) recommended that NYISO’s ICAP market be made voluntary, not mandatory. The association also said it supports NYISO’s carbon pricing proposal, which would provide competition derived revenue to renewable energy projects and lessen the need to fund projects through administered processes.
NYAPP’s backing of a carbon pricing mechanism is also supported by multiple stakeholders, including the Independent Power Producers of New York (IPPNY), a joint filing by Calpine and Vistra Energy, Exelon and a coalition of stakeholders that includes Advanced Energy Economy, the Alliance for Clean Energy New York, the American Wind Energy Association, and the Solar Energy Industries Association. That coalition also backs the idea of having NYISO serve as a centralized agent, procuring increasing amounts of clean energy.
The Advanced Energy Management Alliance also recommended the creation of a centralized procurement entity but suggested that NYISO could fulfill that function if the PSC were to require that NYISO procure an increasing amount of clean resources, including demand response resources, each year through the ICAP market.
A group of New York investor owned utilities, filing as the Joint Utilities, proposed two capacity market redesign approaches. The first, the Multiple Value Pricing model, would develop different demand curves for different resource classes based on their characteristics. Under that construct, resources that satisfy state policy goals would not be subject to BSM and would clear the ICAP market separately from other resources.
The second approach, the Future Clean Capacity Requirement, would eliminate BSM for all resources that meet state policy goals and would increase the installed reserve margin used to establish the demand curves based on the expected shortfall between traditional capacity and resources scheduled to meet state policy goals.
The Joint Utilities also said they oppose any measures that would result in mandatory utility power purchase agreements.
A variety of stakeholders, including the Natural Resources Defense Council, the Sustainable FERC Project, the Sierra Club and Vote Solar, in a combined filing, also backed the idea of making NYISO’s ICAP market voluntary, which, they argued, would give utilities greater flexibility to provide reliable service via varied portfolios that include renewables, energy storage and demand side management resources. In their filing, the environmental advocates also recommended improvements to energy and ancillary service markets to meet the needs of a grid dominated by variable renewable resources, such as changes to pricing rules that would send more robust signals to load when energy is scarce or plentiful.
NYISO, in its filing, said it is considering a variety of potential market design changes, ranging from modest to fundamental alterations of its rules. It’s comments in this proceeding addressed the centralized “California” model and on the Fixed Resource Requirement Alternative (FRRA) under review in PJM.
NYISO said that the California model could not be imported into New York without modification, and while that model could produce “economically optimal results,” it is concerned that its reliance on regulated long-term PPAs could shift the risks of capacity procurement from private investors to consumers.
NYISO said that while PJM’s FRRA model avoids BSM issues, it also deprives state-supported resources of capacity payments through the wholesale market. In addition, the model might not effectively insulate the wholesale capacity market from the price-suppressing impacts of new entry by state-sponsored projects.
NYISO also mentioned the Capacity Auctions with Sponsored Resources (CASPR) construct used in ISO New England that some parties have suggested be adapted for use in New York.
A CASPR-like mechanism could potentially facilitate “an orderly retirement of less competitive conventional resources and contribute to maintaining competitive market price levels for all resources,” NYISO said, but noted “considerable uncertainty” regarding how the exit of surplus capacity could be paired with the entry of public policy resources.
NYISO said it has not determined whether to move forward with a CASPR proposal and is still in the process of evaluating it and other concepts. NYISO’s goal is to complete the development of proposed market design improvements by the end of 2020.
In its filing, Potomac Economics, NYISO’s market monitor, said it found “low-cost flexible resources are systematically under-compensated for operating reserves, while the costs borne by emitters of carbon dioxide emissions are far below the level that New York State environmental policy is based on.”
Potomac Economics recommended the use of a resource adequacy model to adjust the capacity value of resources based on size because large generators provide less reliability value than an equivalent amount of capacity of small generators, and adjust the capacity compensation for long-lead time units based on their lower reliability value.
Potomac Economics recommended two changes to the BSM rules that would “allow subsidized resources to sell capacity whenever it would not result in artificial capacity price suppression.” First, would be the use of a CASPR model adapted for New York but that does not address the concern that merchant natural gas plants could preempt state policy resources. A second approach would address this concern by modifying the BSM rules to enable resources that are subsidized “to promote legitimate policy objectives” to be given a priority for mitigation exemptions and incorporates the actual timeframes for development of different resources.