ISO-NE Request, PJM Board Decision Put Future of Capacity Markets Firmly in FERC’s Hands
Actions taken last week by two of the nation’s leading RTOs put the future of centralized capacity markets, and specifically how these markets accommodate out of market state-sponsored subsidies, squarely in the hands of the Federal Energy Regulatory Commission (“FERC”). The question of how to treat generation resources that are the beneficiaries of out of market subsidies driven by state policy preferences in centralized, FERC-jurisdictional capacity markets where all generation resources are supposed to compete on equal footing has vexed the power industry for several years. This week’s actions by ISO-NE and PJM set the stage for FERC to opine on this overriding issue, which will likely impact billions of dollars’ worth of investment for years to come.
First, on February 14, 2018, ISO-NE reiterated its request that FERC approve its Competitive Auction with Sponsored Resources (“CASPR”) proposal. The CASPR proposal would allow retiring resources that earn capacity supply obligations (“CSOs”) in ISO-NE’s capacity market to transfer those obligations to new, subsidized resources that do not have CSOs. The existing resource would then retire and pay the subsidized resource for meeting the capacity obligation. The price paid to those new, subsidized resources would be determined by a second auction (called a “substitution auction”) that would have lower prices than the primary auction, in a manner similar to the settlement process that occurs today between the real-time and day-ahead energy markets. Retiring resources would earn the difference between the primary auction and the substitution auction, thus incentivizing them to retire. In supporting the CASPR Proposal, ISO-NE argued that “[FERC] is tasked with determining whether the CASPR proposal is just and reasonable pursuant to the standards of section 205 of the Federal Power Act. This role does not require the Commission to find that the ISO’s existing Tariff is unjust and unreasonable; accordingly, certain stakeholders’ preference for the status quo . . . is not relevant.” ISO-NE requested an March 9, 2018 as an initial effective date for the CASPR Proposal, meaning FERC is highly likely to issue an order by then.
Second, in a surprising move, PJM’s Board elected to file competing capacity market proposals- one supported by PJM management and the other supported by PJM’s independent market monitor (“PJM IMM”) –for FERC to consider. By way of background, PJM’s stakeholders have been discussing capacity market reforms to incorporate state subsidies for over a year. From this process, two main proposals emerged. The first was the “Capacity Repricing Proposal” supported by PJM’s management, and the second is the “MOPR-ex” proposal supported by the PJM IMM. To summarize, the Capacity Repricing Proposal accommodates state subsidies by addressing such subsidies only when it comes to settling the market price that all committed resources are paid, but would determine capacity commitments as it does today and allow subsidized resources to bid alongside non-subsidized resources for capacity commitments. Meanwhile, the MOPR-ex proposal (short for “Minimum Offer Price Rule extended”) ascribes a higher, administratively determined minimum offer price to subsidized resources when they offer into a capacity auction. Both proposals are likely to raise capacity market prices relative to what they are today, but have very different impacts. Most notably, although the Capacity Repricing Proposal presents no additional risk to a subsidized resource when it comes to whether such resource receives a capacity commitment, the MOPR-ex proposal essentially penalizes a subsidized resource by raising its offer price and making it less attractive than its lower, subsidized offer price - thus increasing the odds that it does not receive a capacity commitment.
While neither of these proposals received the endorsement of the majority of PJM stakeholders, PJM’s CEO Andrew Ott noted last month that PJM’s management would recommend to PJM’s Board that it file the Capacity Repricing Proposal. However, after pushback from several stakeholders in the ensuing weeks, including the majority of states in PJM, PJM’s Board elected to have FERC decide the issue, and said it would file both proposals for FERC’s consideration. Specifically, in a February 16 letter to PJM’s stakeholders, Ott noted that “[t]he Board has directed PJM to file both the Capacity Repricing and MOPR-Ex proposals with the Federal Energy Regulatory Commission under Section 205 of the Federal Power Act. Each approach represents a distinct, just and reasonable policy alternative to address the consequences of state intervention. Deciding between these policy options requires a balancing of federal and state interests, raising questions of federalism and comity that have already presented themselves before the courts, including the U.S. Supreme Court. Accordingly, the Board concluded that this question should fall to the Commission as the federal policymaker not to the PJM Board.”
Further, Ott stated that “the Board believes certain elements of each proposal would benefit from further stakeholder input. For this reason, PJM’s filing will request that, once the Commission selects a policy direction, it should then direct the respective rule changes (either Capacity Repricing or MOPR-Ex) to a time-bound settlement judge proceeding, with expectation that such a process will bring refinement, compromise and more consensus support for what ultimately will be presented to the Commission later this year as a package of proposed rule changes.”
As ISO-NE’s and PJM’s proposals move to FERC, input from various stakeholders is expected to be intense as the future of capacity markets hangs in the balance.
FERC Issues Landmark Order on Energy Storage Participation in Wholesale Markets
On February 15, 2018, FERC issued its long-awaited order on energy storage participation in RTOs, Order No. 841. The 240-page order requires each RTO to “establish a participation model consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, facilitates their participation in the RTO/ISO markets.” Importantly, each RTO’s participation model, which must consist of a distinct set of rules for energy storage resources, “must (1) ensure that a resource using the participation model is eligible to provide all capacity, energy, and ancillary services that the resource is technically capable of providing in the RTO/ISO markets; (2) ensure that a resource using the participation model can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer consistent with existing market rules that govern when a resource can set the wholesale price; (3) account for the physical and operational characteristics of electric storage resources through bidding parameters or other means; and (4) establish a minimum size requirement for participation in the RTO/ISO markets that does not exceed 100 kW.” The order also makes a definitive ruling that “the sale of electric energy from the RTO/ISO markets to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.”
Notably, the order, which arose from a notice of proposed rulemaking (“NOPR”) issued in November 2016, did not include any rules related to the aggregation of distributed energy resources, which was a subject of the NOPR. Instead, FERC set that issue for a technical conference to be held April 10, 2018, in a separate proceeding (RM18-9-000).
Given the complexity and scope of Order No. 841, FERC gave each RTO 270 days after the rule's publication in the Federal Register to file necessary tariff changes, and 365 days thereafter to implement the changes. Thus, much work will be done in each RTO’s stakeholder process to finalize a multitude of technical and tariff requirements for energy storage’s participation in each RTO’s market, with varying rules likely to arise from each RTO. A recent Platts article predicted that the rule is likely to eventually have the greatest impact on the economics of peaker plants and reduce scarcity pricing, although the rule’s total impact on the electricity sector remains to be seen.
FERC Order on Frequency Response Set to Bolster Grid Resilience, Raise Interconnection Costs on Renewable Energy Resources
On February 15, 2018, in a highly technical yet important order that will impact all new generation resources, FERC issued Order No. 842, “Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response.” The order makes several revisions to FERC’s pro forma Large Generator Interconnection Agreement (LGIA) and the pro forma Small Generator Interconnection Agreement (SGIA) and requires “newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection.” FERC also noted that the “changes are designed to address the potential reliability impact of the evolving generation resource mix,” particularly as more intermittent, renewable energy resources interconnect to the nation’s bulk power system.
In a statement accompanying the order, FERC Commissioner Cheryl LaFluer stated that “[c]hanges in our nation’s resource mix, including particularly the lower percentage of synchronous generation, have contributed to declining frequency response performance in the Eastern and Western interconnections. However, recent technological advancements have enabled new non-synchronous generating facilities, such as wind and solar, to cost-effectively include primary frequency response capabilities in their facilities.” LaFleuer went on to note that “we recognize the unique operating characteristics of energy storage facilities, and require that transmission providers include in their pro forma LGIA and SGIA specific accommodations and limitations on when electric storage resources will be required to provide primary frequency response.”
The new requirements, which are expected to raise interconnection costs associated with new generation facilities, and particularly those of renewable energy resources that have not provided primary frequency response in the past, “apply to newly interconnecting generation facilities that execute, or request the unexecuted filing of, an LGIA or SGIA on or after the effective date” of the order, which is set to be 70 days after the publication of the order in the Federal Register. Further, depending on the configuration of projects in FERC-jurisdictional interconnection queues, the rule could also impact the queue position of projects currently under development.
