By Jennifer Chen, NRDC Alum
FERC Upholds PJM’s Treatment of Demand Response
In the wake of the U.S. Supreme Court’s EPSA decision lifting the uncertainty clouding FERC’s authority over demand response, FERC has been able to decide matters put on hold pending that ruling. At the last open meeting, FERC issued orders denying requests for changes in PJM’s treatment of demand response, from PJM’s Independent Market Monitor, demand response providers, industrial customers and Public Service Enterprise Group. This set of decisions is a mixed bag of good and bad news for demand response.
FERC rejects PJM Market Monitor complaint (EL14-20)
FERC rejected PJM’s independent market monitor’s complaint that the PJM’s capacity market rules do not treat demand response resources comparably to generation resources, affirming that comparable treatment should reflect characteristics of the resource and does not require identical treatment. The market monitor claimed that certain requirements applying to generators should also apply to demand response; in particular, the daily must-offer and availability requirements applying to generation capacity resources should also apply to demand resources, as should the offer cap of $1,000 per MWh (instead of the higher offer cap proposed for demand resources).
In denying the complaint, FERC stressed that generation resources are in the business of providing energy and ancillary services while demand response resources include hospitals, schools, businesses and homes whose primary purpose is typically not providing energy and ancillary services. Thus, it made sense to not require that these resources offer into the day-ahead markets because it is likely these entities may have reasons for providing demand response during emergencies to support the reliability of the system but not under other circumstances. On the offer cap issues, FERC noted that PJM’s offer cap mechanisms for generation and demand response, while different, still allow both types of resources to submit bids consistent with their short-run marginal costs.
Viridity Energy, Inc. v. PJM Interconnection, L.L.C. (EL12-54)
FERC denied Viridity’s complaint that PJM’s tariff is unduly discriminatory as applied to end-use customers participating in PJM’s Emergency Load Response Program through (a) one demand response provider for both capacity market and energy and ancillary services purposes versus (b) two demand response providers, one for capacity market and another for energy and ancillary services purposes. Under PJM rules, an end-use customer that registers with one demand response provider for capacity and a different provider for energy (case (b)) does not receive a guaranteed energy payment when called to reduce load in response to an emergency. Viridity argued that the payment for load reductions should be equal in either case (a) or (b) because the end-use customers are similarly-situated.
FERC denied Viridity’s complaint, citing reliability and double payment concerns, among other reasons. In particular, customers represented by two different demand response providers could submit duplicate offers for the same capacity megawatts covering the same time period, which could create reliability problems by erroneously indicating to PJM that there is twice the demand reduction than is actually available during an emergency condition. In addition, market participants may have to pay twice for the same reduction.
PJM Interconnection, L.L.C. (ER14-822-002, -003)
FERC denied rehearing requested by demand response providers challenging the Commission’s May 2014 order accepting PJM’s change requiring that demand response resources respond within 30 minutes instead of two hours. FERC found that the demand response providers’ cost impact arguments did not undermine the PJM’s reliability rationale in making the change. FERC also found that PJM’s compliance filing satisfied the requirements of its May order.
PJM Interconnection, L.L.C. (ER14-504-001)
FERC denied a rehearing requests filed by industrial customers in PJM, appealing FERC acceptance (in a January 2014 order) of PJM’s cap on limited-availability demand response products. FERC disagreed with the customers that the cap did not impose excessive costs, in balancing reliability with an adequate opportunity for limited-availability demand response to participate in PJM’s capacity markets. FERC found that limited-availability demand response is different from and need not be treated the same as annual demand response. Limited-availability demand response could include clean resources, such as a customer’s willingness to turn down air conditioning or suspend widget manufacturing, as well as dirty resources like diesel back-up generators. Annual demand response can be resources like natural gas back-up generators that don’t have run time limitations due to environmental constraints.
PJM Interconnection, L.L.C. (ER13-2108-001)
FERC denied PSEG’s rehearing request appealing FERC approval of PJM’s requirement that a demand resource provider seeking to participate in PJM’s capacity market auctions demonstrate its ability to perform when needed in advance of the relevant base residual auction. FERC disagreed with PSEG’s interpretation of PJM’s tariff changes and found that this obligation applied to all capacity resources.
New York Independent System Operator, Inc. (ER16-120-000 EL15-37-001)
FERC rejected several major elements of NYISO’s compliance filing made in response to a 2015 FERC order requiring NYISO to create a new process for managing “reliability must run” (RMR) generators. NYISO had proposed to incorporate the generator retirement process into its existing “gap solution” planning framework, under which NYISO deals with urgent grid reliability needs that cannot be timely addressed in NYISO’s biennial reliability planning process. Within that framework, NYISO proposed to manage the process of identifying generation solutions for the reliability need, but shift responsibility to the New York Public Service Commission (PSC) for choosing potential transmission, demand response, and other non-generation solutions. (NYISO proposed to give a list of potential non-generation solutions to the PSC.)
FERC rejected NYISO’s proposal, finding that it improperly delegated authority to the PSC to evaluate and select alternatives and could result in a discriminatory selection based on resource type. FERC also found that NYISO’s proposal could allow the PSC to dictate the choice of a permanent non-generation solution outside of the Order 1000 planning process. For those and other reasons, FERC ordered NYISO to develop a separate reliability must run (RMR) process outside of the existing gap solution framework.
FERC also rejected NYISO’s plan for bidding RMR generators into the ISO’s capacity auction, and its formula for allocating RMR costs. However, FERC did approve other aspects of NYISO’s proposal, including using going-forward costs as a compensation mechanism for generators under RMR agreements, and use of net present value to compare solutions.
FERC Orders Changes to MISO-PJM Interregional Planning in Northern Indiana Public Service Company v. Midcontinent Independent System Operator, Inc. and PJM Interconnection, L.L.C. (EL13-88)
FERC partially granted a 2013 complaint filed by NIPSCO requesting reforms to the interregional transmission planning process between MISO and PJM. Noting significant congestion costs along the PJM/MISO seam and the fact that no transmission project had ever been approved under the RTOs’ joint process, NIPSCO made a number of recommendations to incent cross-border projects. These interregional projects are particularly important to ensuring that the grid can efficiently deliver low-cost clean energy resources (such as wind, which is typically produced in far-flung places) to where most of the electricity is consumed.
In response to the complaint, FERC ordered MISO and PJM to revise their joint operating agreement to include timely, specific deadlines for each step in the coordinated process. FERC also ordered MISO to reduce its minimum voltage threshold for interregional economic transmission projects from 345 kV to 100 kV and eliminate the $5 million cost threshold for such projects because these cost and voltage thresholds could eliminate projects that could benefit both regions.
FERC denied NIPSCO’s request asking that the RTOs’ individual and joint processes follow a common timeline but asked MISO and PJM to submit an informational filing describing how they could do so and what impacts that would have on the RTOs’ planning process. FERC also rejected NIPSCO’s suggestion that the RTOs develop a joint model using the same assumptions in the cross-border transmission process, but directed MISO and PJM to explore using such a model and submit an informational report on the issue.
FERC Staff Storage Presentation (AD16-20)
FERC Staff, at the April meeting, highlighted the data requests it sent on April 11 to the six FERC-regulated RTOs/ISOs regarding their rules for energy storage participation in their wholesale markets. In addition to the data requests, FERC will address storage interconnection issues (RM16-12) at a May 13 conference scheduled in response to the American Wind Energy Association’s petition to revisit FERC’s pro forma large generator interconnection agreement, a petition we supported (RM15-21).
Staff noted the electric storage industry has grown significantly and the need for faster and more flexible resources to integrate variable renewable resources has made electric storage resources increasingly important. Staff also noted that while reforms enabling emerging technologies, such as storage, to compete alongside traditional resources have helped alleviate some of the barriers for storage, it is important to continue this work to ensure these resources have fair access to the markets which they benefit.
In light of these developments, Staff is asking whether barriers to the participation of storage in the capacity, energy, and ancillary service markets exist and whether tariff changes are warranted. In particular, Staff is seeking information about wholesale market rules affecting storage participation including: (1) what types of storage resources are eligible to participate in the markets; (2) what are the technical qualification and performance requirements for market participation; (3) what are the bid parameters for different types of resources; (4) what are the opportunities for aggregate storage resources or storage connected at the distribution level to participate at the wholesale level; and (5) how is storage treated when it is receiving electricity for later injection to the grid. Staff is seeking public comment on these topics as well. RTO/ISO responses are due May 16, and public comments are due June 6.