May 22, 2020
As frustration grows among a wide range of stakeholders over the design of PJM’s capacity market resulting from FERC’s landmark and controversial December 2019 order instituting an expanded Minimum Offer Price Rule (MOPR), PJM indicated last week that it is committed to working with states and stakeholders to negotiate alternative, long-term solutions to the recently-approved expanded MOPR. The MOPR, which is estimated to cost PJM consumers billions of dollars annually and inhibit the growth of clean energy resources in PJM, comes at a time when several states are actively exploring alternatives to PJM’s capacity market, particularly Maryland, Illinois. and New Jersey.
Notably, PSEG and Exelon filed joint comments this week with New Jersey regulators urging the state to adopt the Fixed Resource Requirement (“FRR”), arguing that it would more effectively help New Jersey meet its clean energy goals. The FRR is permissible under PJM’s current rules, as well FERC’s December 2019 order, and, under the FRR, a state could procure capacity on a zonal level and set compensation for resources providing capacity, rather than relying upon PJM’s broader regional market for capacity. If states were to adopt the FRR, resources participating in such a state’s FRR plan would not be subject to the MOPR. However, the FRR is not without its own set of challenges, and critics of the FRR point to the fact that, by relying on state-by-state capacity procurements rather than a broader, regional approach, costs to consumers could rise. Notably, PJM’s independent market monitor estimates that moving to an FRR construct would cost New Jersey ratepayers between $32 million and $386.4 million more than PJM's 2021/2022 capacity auction would.
The robust discussions between PJM, states and stakeholders over the long-term design of PJM’s capacity market are unlikely to subside any time soon, and are likely to enter a new phase later this year once FERC approves final rules to be utilized by PJM in its next Base Residual Auction (which has still not been scheduled), and, as FERC’s December 2019 order (and the June 2018 order that preceded it) are appealed to the 7th Circuit.
On Tuesday, May 19, 2020, the North Carolina Utility Commission (“NCUC”) issued an Order Dismissing Carolina Utility Customers Association’s (“CUCA”) Petition for Expedited Approval of Temporary Adjustments to Electricity Billing Demand Charges (the “Petition”) for commercial and industrial ratepayers. The Petition was in response to the March 19, 2020 Order Suspending Utility Disconnections for Non-Payment, Allowing Reconnection, and Waiving Certain Fees issued by NCUC (the “Waiver Order”) in light of the state of emergency declared by the North Carolina Governor as a result of the COVID-19 pandemic (the “State of Emergency”), which ordered all public utilities to (i) immediately cease customer disconnections for non-payment of bills, (ii) waive the application of late fees, (iii) suspend individual regulations and tariff provisions that prevent or condition reconnections of disconnected customers, (iv) provide appropriate notice to customers of these changes, and (v) work with customers at the end of the State of Emergency to establish reasonable payment arrangements for billing arrearages.
Nevertheless, CUCA filed the Petition on March 31, 2020 to request that NCUC take additional steps to protect commercial and industrial ratepayers. Specifically, CUCA sought temporary adjustments to the minimum and maximum factors used to calculate the electricity billing demand component of the rates currently set out in the industrial and commercial rate schedules of Duke Energy Carolinas, LLC (“DEC”), Duke Energy Progress, LLC (“DEP” and, together with DEC, “Duke”), and Dominion Energy North Carolina (“DENC” and, together with Duke, the “Utilities”). In this regard, CUCA requested that NCUC temporarily eliminate the monthly minimum and maximum billing demand factors, prorate the current monthly demand charges calculated using actual demand factors to reflect a partial month of operation for sites that have significantly curtailed or expanded consumption, and review other tariff provisions to provide more flexibility for such ratepayers while the State of Emergency continues to disrupt their normal operations. CUCA further requested that the relief sought remain in force for the duration of the State of Emergency, for an additional sixty (60) days thereafter for commercial ratepayers, and six (6) months for industrial ratepayers to ensure their protection until normal operations resume.
After receiving comments and statements from the Utilities, CUCA, the Public Staff and several consumers, NCUC was not persuaded by CUCA’s arguments, which NCUC found were too broad and lacked evidentiary support. Despite being cognizant of the economic hardships industrial and commercial ratepayers are experiencing in this environment, NCUC recognized the Utilities’ need to recover their fixed costs to continue generating the necessary electricity to meet the demands of their customers. NCUC understood that reducing the billing demand factors to calculate charges for industrial and commercial ratepayers would likely shift a larger portion of fixed costs of service to other customers and sectors under the Utilities’ current rates and tariffs, and it was simply unwilling to let this happen.
Instead, NCUC was satisfied with continuing the measures set out in its Waiver Order, as well as the Public Staff’s proposed targeted approach for addressing ratepayer hardships, which it felt are just and reasonable to address the State of Emergency and its aftermath. NCUC was particularly moved by the Utilities’ endorsement of the Public Staff’s proposed targeted approach for responding on a customer-by-customer basis and their stated commitment to work and be flexible with industrial and commercial customers during and after the State of Emergency. Going forward, one can expect NCUC to oversee the handling of requests for payment accommodations made by industrial and large commercial ratepayers and hold the Utilities to their commitments.
It has become increasingly clear that the drop in electricity demand will continue long after stay-at-home and social distancing orders are lifted, prompting experts and analysts to predict a reshaping of the power markets. Electricity consumption is expected to decline globally this year, with an estimated 5% decrease in the United States and 8% decrease in Europe, leading to the biggest decline since the Great Depression. One of the reasons that recovery is expected to take years is because, generally, electricity demand mirrors economic activity. With the rise of unemployment and increasing number of companies modifying their business models to allow employees to work from home more often—and even permanently sometimes—it is unlikely that economic activity will generate electricity demands at pre-pandemic levels any time soon. One notable exception is China, which, despite experiencing a decrease in electricity demand and being the epicenter of the COVID-19 outbreak, is still on pace to increase its consumption by 3% this year.
Notably, in response to the potential long-term ramifications to the U.S. energy sector, FERC announced yesterday that it is convening a technical conference to examine the long-term impacts of the COVID-19 pandemic on July 8-9, 2020.
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