A Path Begins to Emerge: Industry Responses to FERC Proposals Respecting State Policies and Eastern Wholesale Markets
On May 1-2, 2017, the Federal Energy Regulatory Commission (“FERC”) held a two day conference focused on the interplay between state policy goals and the organized markets for energy and capacity operated by Regional Transmission Organizations (“RTO”) and Independent System Operators (“ISO”) in the East. The conference focused on what steps, if any, FERC should take to protect the integrity of wholesale markets given the recent proliferation of state policies intended to facilitate the development and maintenance of resources to meet state renewable goals and reliability needs, including whether modifications to the offer floors applied in eastern markets for capacity – referred to as the Minimum Offer Price Rule (“MOPR”) – are necessary. Among other things, FERC may have convened the conference in response to the recent decisions of the states of New York and Illinois to create Zero Emission Credit (“ZEC”) programs, programs intended to provide financial support to nuclear generation facilities. The legality of these ZEC programs are currently being challenged in federal district court. Challengers to these types of programs argue that these payments distort the wholesale power markets and encroach on FERC’s exclusive authority over wholesale markets, while defenders argue that the programs represent the legitimate exercise of state authority.
Following the technical conference, FERC issued a notice inviting interested parties to submit comments on five different potential paths that FERC could pursue in response to such programs:
- Path 1 – Limited or No Minimum Offer Price Rule: FERC’s approach would either not apply the MOPR to state-supported resources or would limit application of the MOPR to state-supported resources only where federal law preempts the state action providing that support.
- Path 2 – Accommodation of State Actions: FERC would allow state-sponsored resources to participate in the markets for energy and capacity, with a mechanism to adjust prices to reflect the results that would have been produced but for the state support.
- Path 3 – Status Quo: FERC would continue to allow RTOs/ISOs to apply the MOPR to some state-supported resources, with continued litigation over the specific application of that rule to state-supported resources.
- Path 4 – Pricing State Policy Choices: FERC’s approach would foster the integration of state public policies and attributes into wholesale market mechanisms to the maximum extent possible and in a resource-neutral way.
- Path 5 – Expanded Minimum Offer Price Rule: FERC would seek to minimize the impact of state supported resources on wholesale market prices by expanding the scope of the MOPR to apply to all capacity resources that receive state support.
On June 23, 2017, over 70 interested parties submitted initial comments on the various paths identified by FERC staff, including RTOs/ISOs in the East, state public utility commissions, trade organizations, and public interest groups.
- A number of commenters, including the Electric Power Supply Association (“EPSA”) and PJM, expressed support for allowing the participation of state-sponsored resources while making appropriate adjustments to market prices. PJM, in particular, noted that it is actively considering modifications to its capacity market that would allow the participation of state-sponsored resources while preventing state subsidies from affecting market clearing prices. EPSA similarly expressed support for such an approach, while emphasizing that FERC should immediately take steps towards the implementation of stronger MOPRs by the end of 2017 to protect against potential market distortions while longer-term efforts are pursued. Other commenters, such as the PJM Independent Market Monitor (“IMM”), argued that allowing the participation of state-sponsored resources would only serve to disrupt competitive markets. The PJM IMM, for instance, explained that all Path 2 solutions “share the attribute that they facilitate the forcing out of nonsubsidized economic units by subsidized uneconomic units” and that such an approach “is fundamentally inconsistent with the Commission’s market-based approach” to capacity markets.
- Opinions about the merits of Path 3 – i.e., maintaining the status quo of applying the MOPR to some state resources and continued case-by-case determinations over the degree of permissible state action—were divided.
- Significant numbers of stakeholders expressed concern about maintaining the status quo. For instance, the New Jersey Board of Public Utilities (“NJ BPU”) expressed concern that the existing market construct “does not value attributes of a diverse energy portfolio” and “may favor fossil fuel generators,” and argued that markets need to more effectively price resource attributes. Similarly, the New York Public Service Commission (“NY PSC”) argued that “[t]he unquestioned need to address legitimate state interests and maintain effective, workable, wholesale electric markets are impossible to reconcile under current rules.”
- Other parties, however, took a different view. Exelon, for instance, argued that the status quo represents a viable path forward, but could be improved upon by clarifying that the MOPR should only apply to “large buyers seeking to support market prices by introducing new, uneconomic supply” while continuing to exempt existing resources and state programs addressing environmental externalities. According to Exelon, clarifying the limited scope of the MOPR would serve to avoid further litigation and reduce uncertainty.
- There was significant support for taking steps to ensure that wholesale markets value a broader range of attributes as outlined in Path 4. A number of parties emphasized the need to ensure that such attributes are more consistently valued across states and done in a resource neutral way.
- For instance, the New York Independent System Operator (“NYISO”) observed that “[w]hile current wholesale market designs function well to send economically efficient market signals to maintain reliability, the markets do not value externalities such as environmental attributes.” NYISO added that it is working with stakeholders, the New York Department of Public Service, and others to “examine the feasibility of modifying NYISO’s market design to more effectively complement New York State’s ambitious environmental policies.”
- Similarly, the American Wind Energy Association (“AWEA”), the Independent Power Producers of New York (“IPPNY”), and New England Power Generators Association (“NEPGA”) favored a carbon price as “the most market-oriented and technology-neutral solution” for addressing the externalities that state policies are pursuing. Specifically, AWEA stated, “Carbon Pricing in the wholesale market could better enable states to fix this market distortion by forcing generators to internalize these costs and bid the true economic value of their electric output.” IPPNY noted the variety of parties that expressed support for a carbon price in their pre-conference comments and stressed the urgency of the issue, stating that “[i]nvestors must be given confidence that they can make rational investment decisions that are needed to maintain reliability with assurance that their investments will not be undercut by the price suppressive impacts of state public policies.”
- The comments reflected a diverse array of viewpoints regarding what changes should be made to existing MOPRs. A number of comments, including the majority of state public utility commissions and other state instrumentalities, argued that taking steps to broaden MOPRs would interfere with the ability of states to pursue legitimate policy objectives. For example, the New York Power Authority (“NYPA”) argued that the “overbroad MOPR in the NYISO markets . . . restricts the ability of new, and likely cleaner generation assets to participate in the NYISO markets.” Others, such as EPSA, emphasized the importance of robust MOPRs to protect against price suppression resulting from state programs.
While both FERC staff and industry participants appear acutely focused on the intersection between state and federal policy, there is significant uncertainty regarding what steps FERC will take in response to the comments. There appears to be little consensus among industry participants on the best going forward approach. Given FERC’s current lack of quorum and the decision of Commissioner Honorable to depart the Commission on June 30, 2017, the priorities of the Trump Administration’s nominees to the Commission are bound to shape both the timing and substance of any further developments in this proceeding and other FERC proceedings related to these issues.
 Coalition For Competitive Electricity et al v. Zibelman, et al., No. 1:16-cv-08164 (S.D.N.Y. Oct. 19, 2016); Electric Power Supply Association, et al., v. Anthony M. Star, No. 1:17-cv-01164 (N.D. Ill. Feb. 14, 2017). Those challenging these programs have relied on the Supreme Court’s ruling in Hughes v. Talen Energy Mkg., 136 S. Ct. 1288 (2016) (“Hughes”), where the court struck down a Maryland financial incentive program for natural gas generation facilities on the basis that it interfered with FERC-jurisdictional wholesale market prices. In Talen, the Court found that the program at issue intruded on FERC’s authority over wholesale rates because the contracts awarded to generators tied the compensation received by the generation owners to the facilities’ participation in the PJM capacity market. On July 14, 2017, the U.S. District Court for the Northern District of Illinois issued an order granting motions to dismiss suits challenging the Illinois program. Electric Power Supply Associtation, et. al., v. Anthony M. Star, No. 1:17-cv-01164 (N.D. Ill. July 17, 2017). Notably, the court distinguished the Illinois program from that at issue in Hughes on the basis that a generator’s receipt of ZECs is not directly conditioned on a generator’s participation in FERC-jurisdictional markets as was the case in Hughes. While the court recognized that the receipt of ZECs could have an indirect effect on a generator’s bidding behavior, the court emphasized that the key difference was that “the ZEC program does not mandate auction clearing in [FERC-jurisdictional markets], and the state, while taking advantage of these attributes to confer a benefit on nuclear power, is not imposing a condition directly on wholesale transactions.” It is likely that the outcome of any subsequent appeals, and the pending action challenging the New York program, will provide further clarity regarding the bounds of the states’ authority to achieve their public policy objectives without encroaching on FERC’s authority.
 Reply comments are due on July 14, 2017.