158 FERC ¶ 61,137

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners:  Cheryl A. LaFleur, Acting Chairman;

                                        Norman C. Bay, and Colette D. Honorable.

ORDER GRANTING COMPLAINT IN PART AND DENYING IN PART

(Issued February 3, 2017)

1.                On June 24, 2016, the New York State Public Service Commission (New York Commission), New York Power Authority (NYPA), Long Island Power Authority (LIPA), New York State Energy Research and Development Authority (NYSERDA), City of New York, Advanced Energy Management Alliance, and Natural Resources Defense Council (collectively, Complainants) filed a complaint against the New York Independent System Operator, Inc. (NYISO) pursuant to sections 206 and 306 of the Federal Power Act (FPA)[1] and Rule 206 of the Commission’s regulations.[2]  The Complainants allege that the application of NYISO’s buyer-side market power mitigation rules in section 23.4 of NYISO’s Market Administration and Control Area Services Tariff (Services Tariff) limit full participation of Special Case Resources (SCRs)[3] in NYISO’s installed capacity (ICAP) market; interfere with federal, state, and local policy objectives; and are therefore unjust and unreasonable.  The Complainants seek a blanket exemption from the buyer-side market power mitigation rules for all SCRs, including SCRs currently subject to mitigation.  In the alternative, the Complainants seek to exclude from the calculation of SCR offer floors payments received from the retail-level demand response programs specified by the Complainants.  In this order, we grant the complaint in part to allow a blanket exemption for new SCRs from the buyer-side market power mitigation rules, and deny it in part insofar as the Complainants request that
   the blanket exemption apply to SCRs currently subject to mitigation.  Also, we require NYISO to make a compliance filing within 30 days of the date of this order, as discussed below.

I.                   Background

2.                NYISO’s buyer-side market power mitigation rules provide that, unless exempt from mitigation, new capacity resources must enter the New York City or G-J Locality[4] ICAP markets (mitigated capacity zones) at a price at or above the applicable offer floor and continue to meet the offer floor until their capacity clears twelve monthly auctions.[5]  The buyer-side market power mitigation rules apply to SCRs, such that SCRs located in a mitigated capacity zone will be subject to an offer floor, unless the projected ICAP spot market auction price will exceed an SCR’s offer floor for the first twelve months that the SCR reasonably anticipates to offer to supply unforced capacity (UCAP).[6]  The SCR offer floor will be equal to the minimum monthly payment for providing ICAP that the SCR receives, “plus the monthly value of any payments or other benefits the Special Case Resource receives from a third party for providing Installed Capacity,” or that the designated ICAP supplier for the SCR receives for the provision of ICAP by the SCR.[7]
3.                NYISO’s application of buyer-side market power mitigation rules to SCRs in its ICAP market has been previously challenged and modified through various proceedings.[8]  As relevant here, since 2008, SCRs have been subject to NYISO’s buyer-side market power mitigation rules in the same manner as all other market participants subject to those rules.[9]  In May 2010, the Commission accepted NYISO’s proposed method for calculating offer floors for mitigated SCRs based on certain payments and benefits received by SCRs and, in that calculation, excluded payments an SCR receives from state demand response programs.[10]  Subsequently, in March 2015, the Commission granted rehearing of its determination regarding the calculation of SCR offer floors, specifying that it did not intend to grant an exemption “for all state programs that subsidize demand response.”[11]  The Commission found, among other things, that the state may file with the Commission pursuant to section 206 of the FPA to exclude payments from particular state demand response programs from the calculation of SCR offer floors if it believes that their inclusion interferes with a legitimate state objective.  The Commission stated that it would make a determination based on the specific request, giving public notice and subject to comments and protests, so the determination could be made based on a full record.[12]

II.                Complaint

4.                The Complainants argue that subjecting SCRs to NYISO’s buyer-side market power mitigation rules presents an unreasonable barrier for customers to participate in both wholesale- and retail-level demand response programs.  They assert that this barrier to SCR program participation increases customer costs and reduces the effectiveness of demand response programs.  Therefore, the Complainants continue, subjecting SCRs to NYISO’s buyer-side market power mitigation rules is unjust and unreasonable; interferes with New York State’s energy policy objectives under the New York Commission’s Reforming the Energy Vision (REV) proceeding and the state’s authority over retail distribution rates; and interferes with the state’s local system planning authority by limiting the state’s ability to rely on demand response to be used as an alternative to traditional distribution system investments and to address system peaks.[13]
5.                Specifically, the Complainants contend that applying the buyer-side market power mitigation rules to SCRs will likely compel them to choose between the wholesale- and the retail-level demand response programs, even though those programs are intended to address different systems, yield distinct benefits, and compensate for different services provided.  They contend that demand response providers will evaluate which program yields the greater financial benefit or imposes less onerous participation requirements, and choose accordingly.[14]  In other words, the Complainants continue, if the risk of mitigation compels demand response providers to choose between wholesale- and retail-level demand response programs, the New York Commission will have to decide whether to:  (1) increase payments offered under the retail-level programs to lure demand response providers from the SCR program; or (2) oversee the retail-level programs that struggle to enroll demand response providers and are incapable of maximizing the potential benefits of demand response.  According to the Complainants, the first option would unnecessarily increase customer costs without a commensurate increase in the amount of demand response enrolled in all programs, while the second option would significantly limit the efficacy of the retail-level demand response programs.[15]
6.                The Complainants assert that the primary objective of the retail-level demand response programs in New York is “to reduce load during distribution system peaks in order to avoid expensive distribution infrastructure upgrades otherwise needed to meet those peaks.”[16]  The Complainants explain that, while the retail-level demand response programs support distribution system reliability, NYISO’s SCR program is designed
   to support bulk transmission system reliability at or near peak system conditions.  The Complainants further explain that the retail-level programs and NYISO’s SCR programs are often called upon at different times of the day and on different days of the year.
7.                The Complainants assert that exempting SCRs from the buyer-side market
   power mitigation rules would be consistent with federal energy policy.  According to
   the Complainants, the U.S. Supreme Court, in FERC v. Electric Power Supply Association,[17] noted that Congress directed that the deployment of demand response enabling technology will be facilitated, and that “unnecessary barriers to demand response participation in energy . . . markets shall be eliminated.”[18]  The Complainants argue that, by harmonizing the wholesale-level demand response programs that the Commission regulates with the retail-level demand response programs, the Commission would be extending and be consistent with the market reforms the Commission adopted in Order Nos. 719[19] and 745.[20]  According to the Complainants, the Commission repeatedly has acknowledged that promoting demand response reflects national energy policy and has enacted reforms to increase demand response participation in wholesale energy markets.[21]  The Complainants argue that it would be irrational, inconsistent, and counterproductive for the Commission to undermine its efforts to eliminate barriers to demand response in the energy market, but then erect barriers in the ICAP market.
8.                The Complainants also request that the Commission grant a blanket exemption
   for SCRs from the buyer-side market power mitigation rules that applies to existing SCRs currently subject to mitigation.  They argue that it would be arbitrary, irrational, and inconsistent to find that mitigation only would interfere with state policy objectives if it occurs after the date of a Commission order granting a blanket exemption for SCRs.[22]
9.                Alternatively, if the Commission declines to grant a blanket exemption for SCRs, the Complainants ask that the Commission find, at a minimum, that the payments from each of the retail-level demand response programs specified by the Complainants be excluded from the calculation of SCR offer floors.[23]

III.            Notice of Filing and Responsive Pleadings

10.           Notice of the complaint was published in the Federal Register, 81 Fed.
    Reg. 43,594-95 (2016), with answers, interventions, and comments due on or before
    July 14, 2016.[24]  Timely motions to intervene were filed by:  Independent Power Producers of New York, Inc. (IPPNY); Exelon Corporation; Electric Power Supply Association (EPSA); National Rural Electric Cooperative Association; American Public Power Association; NRG Power Marketing LLC and GenOn Energy Management,
    LLC; the PSEG Companies; and Consolidated Edison Company of New York, Inc. (ConEd), Orange and Rockland Utilities, Inc., and Central Hudson Gas & Electric Corp. (collectively, Companies).  NYISO’s Market Monitoring Unit (MMU) filed an out-of-time motion to intervene.
11.           On July 21, 2016, NYISO filed an answer to the complaint.  The Companies filed timely comments and MMU filed out-of-time comments.  IPPNY/EPSA filed a timely protest.  On August 8, 2016, the Companies filed an answer.  On August 9, 2016, the Complainants filed an answer.

A.                NYISO’s Answer

12.           NYISO asserts that it is reasonable to exempt SCRs from the buyer-side market power mitigation rules because the evidence to date does not demonstrate that the retail-level demand response programs have the ability to support the use of SCRs to suppress ICAP market prices.[25]  For instance, NYISO explains that, while the compensation available from the retail-level demand response programs has continued to increase
    over time, there has not been a corresponding material increase in the amount of UCAP procured through the SCR program.[26]  Therefore, according to NYISO, under current circumstances, applying the buyer-side market power mitigation rules to SCRs results
    in over-mitigation and is not warranted.  However, NYISO also states that, if conditions were to change in the future so that SCRs possessed the ability to suppress ICAP market prices, then NYISO would, as required under the Services Tariff, propose additional mitigation measures.[27]
13.           With regard to exempting SCRs currently subject to mitigation, NYISO answers that, as a general matter, retesting or exempting resources that were determined to be subject to mitigation disrupts settled market expectations and is inequitable.  However, NYISO states that, because only 3.3 MW of SCRs have been determined to be subject
    to mitigation over the past five years of enrollment, the impact, if any, on the market or market participants’ expectations would be minimal.  Under this narrow circumstance, involving a very small quantity of SCR with little, if any, potential for market disruption, NYISO states that it does not object to revisiting prior determinations as requested in the complaint.[28]

B.                 Comments and Protests

14.           The Companies support the complaint.  The Companies argue that the wholesale- and the retail-level demand response programs are complementary to each other, but serve different purposes, provide different benefits, and compensate distinctly different services.[29]  The Companies contend that subjecting SCRs to potential mitigation presents an unreasonable barrier for resources to participate in both the wholesale- and the retail-level programs because the artificial barrier to SCR program participation increases customer costs and reduces the effectiveness of demand response programs.  They agree with the Complainants that subjecting SCRs to NYISO’s buyer-side market power mitigation rules could compel demand response resources to choose between the NYISO-administered SCR program and one of the retail-level demand response programs and, thereby, reduce overall demand response participation even though participation in
    each program could provide distinct benefits.[30]
15.           The Companies also argue that demand response resources are unlikely to
    be used as a tool to exercise buyer-side market power, reflect a relatively small
    portion of the overall New York Control Area’s capacity, and are a valuable tool
    for maintaining reliability.  The Companies further contend that demand response
    resources are an essential public policy capacity resource, the development of
    which should be encouraged, as recognized by the Energy Policy Act of 2005.[31]
16.           IPPNY/EPSA protest the complaint.  They argue that the Complainants’ contention that the wholesale- and the retail-level demand response programs are distinct is flawed.  For instance, according to IPPNY/EPSA, the Complainants incorrectly presume that the sole purpose of all of the retail-level demand response programs is
    to provide load relief on local distribution facilities to avoid or delay more costly
    utility distribution system investments.  IPPNY/EPSA contend that this premise is contradicted by the Complainants’ own statements and their references to the New York Commission’s REV proceeding in the complaint.  According to IPPNY/EPSA, the REV proceeding clearly demonstrates that the New York Commission’s policy to promote the deployment of demand response is being driven by a variety of reasons, including reducing peak load on the bulk power system, and thereby replacing traditional wholesale electric generation with demand response providers—the same purpose as NYISO’s SCR program.[32]  Moreover, IPPNY/EPSA assert that, even though the Complainants argue that the number of hours that the wholesale- and the retail-level demand response programs have been activated at the same time is small, payments provided from the retail-level demand response programs were likely aimed at encouraging SCRs to participate in NYISO’s wholesale markets to replace wholesale electric generators with demand response and at providing other wholesale market benefits.[33]
17.           In addition, IPPNY/EPSA argue that the application of the buyer-side market power mitigation rules to SCRs does not interfere with the state’s ability to encourage
    the deployment of demand response resources through the retail-level demand response programs and does not “constitute[] an impermissible extension of Federal jurisdiction into matters of State authority under the FPA.”[34]  IPPNY/EPSA contend that all SCRs in the mitigated capacity zones are subject to NYISO’s buyer-side market power mitigation rules and that those rules simply define the parameters for SCRs’ participation in NYISO’s ICAP market, and do not proscribe SCRs’ participation in the retail-level programs.  According to IPPNY/EPSA, if an SCR bids its offer floor and fails to clear the ICAP market, the Complainants are correct that the SCR may be unavailable to support bulk system reliability; however, IPPNY/EPSA continue, it is also true that the SCR was not needed by the system.
18.           IPPNY/EPSA also argue that the Complainants’ claim that the application of the buyer-side market power mitigation rules to SCRs could result in an SCR choosing the NYISO-administered SCR program and foregoing participation in the retail-level demand response programs has no merit.  IPPNY/EPSA contend that an SCR would only be subject to an offer floor if the payments it received from the retail-level demand response program were sufficiently high to make the SCR uneconomic under NYISO’s mitigation exemption test, i.e., the retail-level program payments exceeded the expected NYISO program revenues.[35]
19.           IPPNY/EPSA argue that granting the complaint would (1) interfere with just and reasonable wholesale price formation—a matter within the Commission’s exclusive jurisdiction; and (2) allow artificial price suppression in contravention of the FPA’s core mandate to set just and reasonable rates and would cause existing capacity resources to
    be under-compensated.[36]  IPPNY/EPSA maintain that the Complainants have failed to demonstrate that a state cannot implement retail-level programs and policies promoting demand response without exempting SCRs from the buyer-side market power mitigation rules.
20.           IPPNY/EPSA also assert that, under the Services Tariff, SCRs receive the same ICAP market payments as generators and have the same potential to impact the market
    as generators.  According to IPPNY/EPSA, because SCRs “can significantly impact capacity prices,” exempting SCRs from the buyer-side market power mitigation rules
    will give SCRs the incentive and ability to artificially suppress ICAP market prices.  IPPNY/EPSA claim that, for that reason, the Commission has already ruled that NYISO’s buyer-side market power mitigation rules should be applied to all capacity suppliers, including SCRs.[37]  They add that, allowing a blanket exemption for SCRs would undermine the core principles behind the Commission-approved buyer-side market
    power mitigation rules—namely, that NYISO should not permit uneconomic new
    entry to artificially suppress ICAP market prices because doing so distorts the market price signals that are necessary to encourage investment in new, and the maintenance
    of needed existing, generators to meet reliability needs.[38]
21.           IPPNY/EPSA ask that if the Commission grants any aspect of the complaint, it nevertheless reject the Complainants’ request to apply an exemption to SCRs currently subject to mitigation.[39]  IPPNY/EPSA argue that continuing to apply new exemptions from the buyer-side market power mitigation rules prospectively is consistent with existing Commission precedent.  According to IPPNY/EPSA, granting the Complainants’ request would set a bad precedent that policy changes made by the Commission that affect market rules will be applied retroactively, upsetting settled expectations and introducing an even higher level of uncertainty into the market.[40]
22.           MMU protests the complaint insofar as it requests a blanket exemption from
    the buyer-side market power mitigation rules for SCRs.  MMU asserts that a blanket exemption would be inappropriate because it could encourage the development of programs for resources that are specifically designed to suppress ICAP market prices.  Nevertheless, MMU states that program-specific exclusions from the calculation of SCR offer floors may be appropriate in many cases and makes certain recommendations for evaluating individual retail-level demand response programs.[41]

C.                Answers

23.           The Companies claim that IPPNY/EPSA’s contention that granting a blanket exemption for SCRs would adversely impact wholesale market prices has no merit.  According to the Companies, IPPNY/EPSA incorrectly assume, without evidence, that
    all SCRs will bid into the ICAP market as a single capacity supplier, as opposed to as individual capacity suppliers or as small aggregated capacity suppliers.  The Companies reiterate that individual demand response resources subject to mitigation are generally too small to have a significant impact on ICAP market prices.[42]  Moreover, they contend that IPPNY/EPSA put forth an “unsubstantiated claim” about SCRs receiving two payments to provide service when other generators receive only one payment.[43]  The Companies state that SCRs participating in the NYISO wholesale market are being paid for load relief at the bulk power level at such times and locations as NYISO deems necessary, while SCR providers who participate in the retail-level demand response programs receive a separate payment from the utility to provide distribution-level load relief at such times and locations as the utility may deem necessary and to enable the local utility to defer construction of distribution-level capital asserts.  As such, the Companies continue, SCRs are providing two different sets of services in two different venues.[44]
24.           The Complainants assert that, contrary to IPPNY/EPSA’s argument that the
    retail-level demand response programs are intended to serve multiple policy objectives, including those of the REV proceeding, these programs were developed to support distribution system reliability and to defer the need for costly investments in utility distribution systems, thereby moderating upward pressure on retail distribution rates.  Moreover, the Complainants contend that the retail-level demand response programs operate independent of NYISO’s transmission-level SCR program and compensate demand response resources for a service provided to the distribution system that is not compensated by the wholesale market.[45]
25.           Similarly, the Complainants, emphasizing the distinctions between the wholesale- and the retail-level demand response programs, contend that IPPNY/EPSA’s arguments regarding two payments to SCRs have no merit.  According to the Complainants, IPPNY/EPSA conflate and link programs that provide compensation for distinct services—(1) demand response services provided to the bulk system under NYISO’s SCR program, and (2) the retail-level demand response programs activated as needed
    to address contingencies on the distribution system or to provide load relief when distribution system demand approaches peak levels.[46]  Moreover, the Complainants
    claim that demand response resources are poor tools to use to exercise buyer-side market power because they only comprise approximately four percent of capacity in the New York Control Area.[47]
26.           Additionally, the Complainants reiterate that the status quo of mitigating SCRs interferes with legitimate state policy objectives.[48]  For example, they assert, if a portion of the distribution system becomes congested, the efficient approach is to increase retail-level demand response program payments for demand response in that local region.  The Complainants state that, in this example, if the retail-level demand response payment reaches the forecasted ICAP market price, new SCRs would fail the mitigation exemption test and be denied ICAP market payments.  In addition, the Complainants maintain, if
    the retail-level demand response program payment is less than the ICAP market clearing price, the retail-level program would be less lucrative than the SCR program for the demand response resource, in which case a “rational SCR provider” would choose to participate in the SCR program alone to avoid mitigation and secure the higher program payment.  The Complainants assert that one of the state policy objectives is to maximize the deployment of demand response resources in New York State and the unproductive competition between the wholesale- and the retail-level demand response programs would interfere with the state’s plenary retail rate-setting and distribution system operations and planning authority.[49]

IV.             Discussion

A.                Procedural Matters

27.           Pursuant to Rule 214 of the Commission’s Rules of Practice and Procedure,[50] the timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding.
28.           Pursuant to Rule 214(d) of the Commission's Rules of Practice and Procedure,[51] the Commission will grant MMU’s late-filed motion to intervene, given its interest in
    the proceeding, the early stage of the proceeding, and the absence of undue prejudice or delay.
29.           Rule 213(a)(2) of the Commission’s Rules of Practice and Procedure,[52] prohibits an answer to a protest unless otherwise ordered by the decisional authority.  We will accept the Companies’ and the Complainants’ answers because they have provided information that assisted us in our decision-making process.

B.                 Commission Determination

30.           As discussed below, we grant the complaint in part and deny it in part, and
    require NYISO to make a compliance filing within 30 days of the date of this order to revise its buyer-side market power mitigation rules in section 23.4 of the Services Tariff to exempt SCRs from the buyer-side market power mitigation rules, effective as of the date of this order.[53]  We find that the Complainants have demonstrated that NYISO’s Services Tariff is unjust, unreasonable, unduly discriminatory or preferential, under section 206 of the FPA, because it applies NYISO’s buyer-side market power mitigation rules to SCRs, which have limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices.  This finding is consistent
    with the Commission’s minimum offer price rule policy; specifically, that buyer-side market power mitigation rules are intended to address “market power exhibited by
    certain entities seeking to lower capacity market prices.”[54]  We deny, however, the Complainants’ request to exempt existing SCRs currently subject to mitigation, for
    the reasons discussed below.
31.           Consistent with our previous findings granting exemptions from the buyer-side market power mitigation rules in certain circumstances,[55] we find that SCRs have limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices.  The retail-level demand response program payments to SCRs do not provide SCRs with the incentive and ability to artificially suppress ICAP market prices.  Specifically, the evidence submitted in this proceeding demonstrates that SCRs are not effective tools of price suppression.  The Complainants maintain that SCRs are capable of providing two distinct services—both at wholesale and at retail—but that those services do not necessarily overlap or affect one another.  In fact, the Complainants demonstrate that the payments offered to demand response providers at the retail level
    are not tied to participation in NYISO’s SCR program.[56]  Moreover, NYISO states that, based on historical data, payments from the retail-level demand response programs
    have not shown a corresponding, material increase in participation in NYISO’s SCR program.[57]  In fact, NYISO’s data demonstrates that, despite significant increases in the payments from retail programs, the participation in the SCR program has remained somewhat flat.[58]  NYISO also contends that a further increase in the breadth or amount of payments from retail-level demand response programs would not present a credible risk for ICAP market price suppression.[59]  Thus, based on the record before us, we find that the payments from the retail-level demand response programs have not provided SCRs with the incentive and ability to artificially suppress ICAP market prices.  Importantly, to the extent that the payments from the retail-level demand response programs later prove to provide SCRs with the incentive and ability to artificially suppress ICAP market prices, NYISO has an obligation under its Services Tariff to mitigate such behavior.[60]
32.           IPPNY/EPSA argue that, under the Services Tariff, SCRs receive the same compensation as generators and have the same ability to influence ICAP market prices.  However, IPPNY/EPSA’s argument is based on the incorrect assumption that SCRs—which are generally individual or small aggregated sets of “resources”—have the same ability to suppress ICAP market prices as a single, large market participant.  Further,
    we agree with the Complainants that the limited nature of SCRs makes them an
    unlikely source to either have or exercise buyer-side market power,[61] and that they
    do not have the incentive and ability to do so, as discussed above.
33.           We disagree with MMU’s and IPPNY/EPSA’s overall argument that a
    blanket exemption for SCRs from NYISO’s buyer-side market power mitigation
    rules is inappropriate because it allows SCRs to offer into the wholesale ICAP market
    at uncompetitive levels, resulting in artificial price suppression.  In contrast to IPPNY/EPSA’s argument, we note that payments from the retail-level demand response programs have not resulted in a corresponding, material increase in the amount of capacity procured through NYISO’s SCR program.[62]  Further, the payments SCRs receive from the retail-level demand response programs are actually for providing services that are separate and distinct from the payments that SCRs receive for participating in NYISO’s ICAP market.[63]  While the wholesale- and the retail-level demand response programs may complement each other, they serve different purposes, provide different benefits, and compensate distinctly different services.[64]  For example, the Complainants note that over 75 percent of ConEd’s networks peak at times that differ from the statewide peak load, with some networks peaking mid-day and others peaking in the late evening.[65]  The Complainants also explain that the retail-level demand response programs and NYISO’s SCR program are often called upon at different times of the
    day and on different days of the year.
34.           We believe that a blanket exemption from NYISO’s buyer-side market power mitigation rules for SCRs effective as of the date of this order allows appropriate flexibility for, and avoids the creation of unnecessary barriers to, the participation of demand response in the wholesale markets.[66]  Specifically, the Commission’s concern regarding buyer-side market power stems from scenarios in which “buyers or their agents can exercise market power to reduce capacity market prices below competitive levels by paying out-of-market subsidies to support new capacity, and then offer that capacity into the organized capacity market at prices below costs to drive down the market price.”[67]  With that concern in mind, the Commission seeks to ensure that buyer-side market power mitigation rules strike a careful balance between over-mitigating and under-mitigating new capacity resources.[68]  As outlined above, we find that NYISO’s existing buyer-side market power mitigation rules over-mitigate SCRs that have limited or no incentive and ability to artificially suppress ICAP market prices.  Therefore, NYISO’s existing buyer-side mitigation rules impose an unnecessary barrier to the participation of demand response in NYISO’s wholesale markets, contrary to Commission policy.[69]
35.           Finally, we deny the Complainants’ request that the blanket exemption also
    apply to all SCRs currently subject to mitigation.  The Commission’s long-standing practice has been that any exemption granted from NYISO’s buyer-side market power mitigation rules only will be applied prospectively to new entrants.  For example, in
    the Commission’s order directing NYISO to implement a competitive entry exemption from its buyer-side market power mitigation rules, the Commission confirmed that
    new entrants that had received final offer floor determinations were bound by those determinations and, thus, could not apply for the competitive entry exemption.[70] 
    While the Commission has allowed for mitigation redeterminations before a resource enters the market, the Commission has not allowed for such redeterminations after the resource enters the market.[71]  The same rationale applies here.  Accordingly, we deny
    the Complainants’ request to rerun the mitigation tests for SCRs currently subject to mitigation.

The Commission orders:

(A)The Complaint is hereby granted in part, and denied in part, as discussed
in the body of this order.

(B)NYISO is hereby directed to submit a compliance filing within 30 days of the date of this order, as discussed in the body of this order.

By the Commission.  Commissioner Bay is concurring with a separate statement    attached.

( S E A L )

Kimberly D. Bose,

Secretary.

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

(Issued February 3, 2017)

BAY, Commissioner, concurring

Today, the Commission partially grants a complaint to allow a blanket exemption for new special case resources (SCRs) from NYISO’s minimum offer price rule (MOPR).  I concur with this result but would go further in reconsidering the MOPR’s rationale and applicability in the wholesale electricity markets.  Despite the best intentions of the Commission, in my view, the MOPR has turned out to be unsound in principle and unworkable in practice.  No other market in the United States is subject to the same construct in which a federal agency reviews state action and imposes an administrative price floor on supply offers from certain resources that have received state support.  This places the Commission in direct and recurring conflict with the states, ignores the pervasiveness of state and federal policies that support resources in one fashion or another, and represents a significant intervention in the market that raises costs to consumers. 

It is first important to understand the reach of the MOPR.  The MOPR was initially designed to mitigate exercises of asserted “buyer-side market power.”  But this label – buyer-side market power – is imprecise and somewhat of a misnomer, for it has come to have a far broader meaning than what its name might otherwise suggest.  True attempts to exercise buyer-side market power (or monopsony power) would constitute anti-competitive behavior and should be addressed.  Over time, the Commission’s theory of the MOPR has changed, morphing from an examination of monopsony power to an examination of whether states have provided support or a subsidy to a resource that is selling into the capacity market.  Such subsidies are viewed as harmful to the market, resulting in application of the MOPR, which forces the resource to offer its capacity at a price above the level it would be willing to accept absent the MOPR.

The premise of the MOPR appears to be based on an idealized vision of markets free from the influence of public policies.  But such a world does not exist, and it is impossible to mitigate our way to its creation.  The fact of the matter is that all energy resources receive federal subsidies, and some resources have received subsidies for decades.[72]  Yet the MOPR is only concerned with state subsidies, not federal ones, though both can have a similar impact on markets.  And even with respect to state conduct, the MOPR’s review is incomplete at best.  The MOPR does not mitigate the wholesale offers of utilities located in vertically integrated states.  Nor does the MOPR examine whether existing resources have previously benefited from a state subsidy.  In short, the MOPR suffers from a troubling lack of coherence that calls into question the soundness of its underlying rationale.  

Given the pervasiveness of public policies that support resources, I believe the MOPR has proven to be unworkable in practice.  It has developed in an ad hoc fashion, without specifying a clear test for the amount of state support that triggers mitigation.  Yet all state action that increases or decreases electricity supply has an impact on the wholesale markets.  A prompt siting decision or a favorable zoning exemption may provide more economic benefit than a subsidy but only the subsidy is likely to result in application of the MOPR.  While these state actions may be more significant than the subsidies subject to the MOPR, they are lawful.[73]  The Supreme Court has now made clear that states are permitted to enact a wide range of policy choices that can affect the wholesale market.[74]  After the decision in Hughes, the Commission cannot defend the MOPR on the grounds that the states have overstepped their authority except in the rare situation where the state action impermissibly interferes with wholesale rates.   

Nor has the Commission been consistent about when it will stand in the way of state action and when it will not.  There is wide variation among the eastern market operators on the resources subject to the MOPR.  NYISO’s MOPR applies to all resources entering a limited number of mitigated capacity zones and continues to apply until that resource has cleared in 12 monthly spot auctions, unless the resource qualifies for an exemption.  In PJM, the MOPR only applies to new natural gas resources, not to renewable resources.  In ISO-NE, all new resources are subject to the MOPR except for 200 MW per year of renewable resources.       

The theory underlying the MOPR also rests on multiple assumptions – assumptions that remain untested.  The MOPR is not applied to the state, which may not actually be a buyer and which is acting on behalf of its citizenry, but to the resource, which is offering to sell capacity to the market and which may be a commercial entity.  The theory, in other words, assumes such a congruence of interests between the state and the resource that the resource is mitigated for the conduct of the state.  Tellingly, while the Commission applies elaborate screens to detect the exercise of seller market power, it does not apply similar screens to detect buyer-side market power in capacity markets.  The Commission simply assumes it exists.  The Commission has not explored or tested these assumptions in its orders, and it does not know whether they are true.         

Not surprisingly, as an institutional matter, imposition of the MOPR places the Commission in constant tension with the states.  While there are times when the Commission must check state action that impermissibly interferes with the wholesale markets, it should endeavor to do so only when necessary.  I believe that respect for federalism requires no less.  In our constitutional order, states are rightly celebrated for being laboratories for experimentation.[75]  Among other things, those laboratories may incentivize the development of needed energy infrastructure, the deployment of innovative technologies, or the establishment of Renewable Portfolio Standards.  Given their plenary police powers, states are free to use their authority to act on behalf of their citizens, as long as they do not “intrude on FERC’s authority over interstate wholesale rates.”[76]  The Commission should be especially mindful of state policy when it comes to electric generation because section 201(b)(1) of the Federal Power Act denies FERC jurisdiction “over facilities used for the generation of electric energy.” 

A resource receiving any amount of state support now faces a considerable degree of legal uncertainty.  The Commission has not sought to explain, let alone reconcile, the relationship between the MOPR and preemption.  As a result, one hurdle to the development of state-supported resources is the prospect of preemption and an examination of whether the state conduct impermissibly interferes with the Commission’s authority over the wholesale markets.  Even if this hurdle is crossed, however, the resource could still be subject to the MOPR.  This places material, if not untenable, risk on the resource, for its offers in the capacity market may be raised to a level that prevents the resource from clearing the auction.  Resources and states are deserving of as much regulatory certainty as the Commission can provide to them.  Instead, as a practical matter, the Commission has erected a double hurdle for resources that receive state support, without providing sufficient guidance on when the MOPR is triggered or how it can be overcome.

An examination of other areas of the law is instructive, because it demonstrates the anomalous nature of the MOPR in according so little deference to federalism concerns and in impeding legitimate state policies.  Under the Constitution, for example, the dormant commerce clause forbids states from discriminating against out-of-state commerce.  This prevents states from placing undue burdens on interstate commerce and promotes competition in the marketplace.[77]  But even here there is an important exception for states when they are acting as market participants.  This exception is, in large part, grounded in federalism concerns.  “Restraint in this area is . . . counseled by considerations of state sovereignty, the role of each State ‘as guardian and trustee for its people.’”[78]  States, if they wish, may act as a market participant to benefit their citizens, even if they favor their own at the expense of others and market efficiency.[79]

Notably, a similar respect for federalism and the role of the states in our constitutional order can be seen in antitrust law.  While federal antitrust law forbids anti-competitive conduct, there is an important exception for “States when acting in their sovereign capacity.”[80]  This exception, known as the Parker doctrine, “represents an attempt to resolve conflicts that may arise between principles of federalism and the goal of antitrust laws, unfettered competition in the marketplace.”[81]  The Supreme Court has explained that “[i]f every duly enacted state law or policy were required to conform to the mandates of the Sherman Act, thus promoting competition at the expense of other values a State may deem fundamental, federal antitrust law would impose an impermissible burden on the States’ power to regulate.”[82]  As a result, in deference to federalism, competition law provides a specific exception for state action, even if the state action has anti-competitive effects.

Beyond the recurring cost to FERC’s relationship with states, it is important to recognize the economic costs of the MOPR as well.  While the MOPR is often characterized as a pro-market policy, correcting the intrusions of the states, this assumes that a market can and should be free from out-of-market influences; there is the judgment that such influences are undesirable and that they can be managed through administrative review and mitigation.  In point of fact, out-of-market influences are everywhere.  Supply-side resources face a diverse range of costs and benefits that are the result of a myriad of public policies and choices by state and federal agencies.  In the vast majority of situations, we should let those costs and benefits simply pass through our markets and have an impact on supply and demand. 

Instead, the MOPR not only frustrates state policy initiatives, but also likely requires load to pay twice – once through the cost of enacting the state policy itself and then through the capacity market.  If states have chosen to provide out-of-market revenue to some resources, the resulting capacity market price should send a signal consistent with the actual capacity needed in light of such revenue.  In contrast, a capacity price that is based on an administratively-determined MOPR may not send an efficient signal for entry and exit.  Administrative attempts to remove such revenue could result in

inefficiently high capacity prices that signal the need for new capacity when no such need exists.

For example, assume a state has partially subsidized 200 MW of capacity in a 10,000 MW capacity market.  If that 200 MW resource is willing to offer capacity at a lower cost as a result, then the cost minimizing outcome, which is by definition efficient, is to allow that resource to offer in to the market at the lowest price it is willing to accept.  Is this offer and resulting clearing price “artificially suppressed”?  If the starting point is the theoretically economic ideal of an outcome free from the impacts of state and federal policy, then the answer may be yes.  But, if the starting point recognizes the reality in which we live, then the price is appropriate.  The pervasiveness of public policies that provide subsidies or impose costs on resources makes it futile to attempt to unwind them all.  Assuming that it is even possible to determine a “subsidy-free offer,” any attempt to unwind completely all subsidies and added costs necessarily assumes that some regulatory entity is capable of calculating the correct offer that resources must submit to the market.  The clearing price from such a process could not credibly be called a market-based outcome.  If a wholesale market operator tried to create an ex ante market free from the influence of public policy and the myriad of state and federal actions that impact supply and demand, this would create the most administrative construct of all.  In short, the cure would be worse than the alleged disease. 

I would approve of a MOPR to address monopsony power or when a state action would otherwise be preempted under Hughes.  What the Commission should really be saying when it applies the MOPR is that a state has impermissibly interfered with wholesale rates.  And when that happens, the state’s action must be mitigated.  For that reason, I would harmonize the reach of the MOPR with the law of preemption under the Federal Power Act.  The Commission should only apply the MOPR in the uncommon situation when state action is not permitted under federal law.  States, no less than industry, are entitled to as much regulatory certainty as the Commission can provide them and an appropriate level of deference under principles of federalism.  This, in turn, may result in a better functioning capacity market with less complexity and administrative pricing in its operation.   

Relaxing the MOPR could stand alone as a policy change or it could be coupled with other market designs that better harmonize state and federal policy goals with wholesale markets and promote just and reasonable rates and reliability.  One option would be to transition towards a decentralized capacity market with a voluntary capacity auction.  Reliability is protected because the wholesale market operator would still have to set a reserve margin; load serving entities (LSEs) would be required to procure the needed capacity.  States could play a role here or they could allow their LSEs to rely upon the voluntary auction or sign bilateral capacity contracts.  This design provides more flexibility to states and accommodates their choices.  It allows states to attach value to energy in a way that the eastern markets do not.  It is also fairly simple and straightforward.  The Commission has found capacity market designs with these features to be just and reasonable.

The most market-oriented solution with the greatest transparency, simplicity, and, perhaps, efficiency would be to transition over time to an energy-only market.  Assuming the scarcity pricing level is set at the appropriate level (the value of lost load), it addresses the “missing money” problem and eliminates the need for a capacity market.  But I recognize that it would be a big step for a wholesale market operator to propose an energy-only market – only ERCOT has adopted this design – and that some may be concerned about the politics of scarcity pricing.  The trade-off for critics concerned about costs, however, is that there would not be a capacity market.  A decade ago, in the aftermath of the Western Power Crisis, there would have been little appetite for an energy-only market.  Now, however, the wholesale market operators, market monitors, and FERC do much better market monitoring, FERC has an anti-manipulation authority, and natural gas is abundant and low priced, so there should be less price volatility in most regions.

For all those reasons, I respectfully concur.

______________________

Norman C. Bay

Commissioner

[1] 16 U.S.C. §§ 824e, 825e (2012).

[2] 18 C.F.R. § 385.206 (2016).

[3] The Services Tariff defines SCRs as:  “Demand Side Resources whose Load is capable of being interrupted upon demand at the direction of the ISO, and/or Demand Side Resources that have a Local Generator, which is not visible to the ISO’s Market Information System and is rated 100 kW or higher, that can be operated to reduce Load from the NYS Transmission System or the distribution system at the direction of the   ISO . . . .”  NYISO, Services Tariff, § 2.19 (16.0.0).

[4] The G-J Locality consists of Load Zones G, H, I, and J, which are zones “within which a minimum level of Installed Capacity must be maintained.”  NYISO, Services Tariff, § 2.12 (4.0.0).

[5] Id. § 23.4.5.7 (3.0.0).

[6] Id. § 23.4.5.7.5 (3.0.0).  In NYISO, UCAP is the measure by which NYISO rates ICAP suppliers to quantify the extent of their contribution to satisfying NYISO’s ICAP requirement, and to measure the portion of that requirement for which each load serving entity is responsible.  Id. § 2.21 (3.0.0).

[7] Id. § 23.4.5.7.5 (3.0.0).

[8] N.Y. Indep. Sys. Operator, Inc., 122 FERC ¶ 61,211, at P 120 (March 2008 Order), order on reh’g and compliance, 124 FERC ¶ 61,301 (2008) (September 2008 Order), order on reh’g and compliance, 131 FERC ¶ 61,170 (2010) (May 2010 Order), order on reh’g and compliance, 150 FERC ¶ 61,208 (2015) (March 2015 Order); N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 153 FERC ¶ 61,022, at P 2 (2015) (Renewables/Self-Supply Complaint Order), order on reh’g, 154 FERC ¶ 61,088 (2016) (Renewables/Self-Supply Rehearing Order).

[9] September 2008 Order, 124 FERC ¶ 61,301 at P 41.

[10] May 2010 Order, 131 FERC ¶ 61,170 at P 137.

[11] March 2015 Order, 150 FERC ¶ 61,208 at P 30.

[12] Id.

[13] Complaint at 41.

[14] Id. at 42-43.

[15] Id. at 44.

[16] Id. at 44 & n.128 (citing Proceeding on Motion of the Commission to Develop Dynamic Load Management Programs, Case No. 14-E-0423, Order Adopting Dynamic Load Management Filings with Modifications, at 11-12 (N.Y. Pub. Serv. Comm’n
June 18, 2015)).

[17] 136 S. Ct. 760 (2016) (EPSA).

[18] Complaint at 48 & n.141 (citing EPSA, 136 S. Ct. at 769).

[19] Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281 (2008), order on reh’g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292, order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).

[20] Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322, order on reh’g and clarification, Order No. 745-A, 137 FERC ¶ 61,215 (2011).

[21] Complaint at 50.

[22] Id.

[23] Because we are granting the blanket exemption for SCRs, as discussed below, we will not discuss or rule on the Complainants’ alternative request to exclude from the calculation of SCR offer floors payments received from specific retail-level demand response programs.

[24] The date was later extended to July 21, 2016.

[25] NYISO July 21, 2016 Answer at 6 (citing Seirup Aff. ¶¶ 9-10).

[26] Id. at 6 (citing Seirup Aff. ¶ 8).

[27] Id. at 7 (citing NYISO, Services Tariff, § 23.1.2).

[28] Id. at 7-8.

[29] Companies July 21, 2016 Comments at 3.

[30] Id. at 4.

[31] Id. at 4-5.  See Energy Policy Act of 2005, Pub. L. No. 109-58, §§ 1261 et seq., 119 Stat. 594 (2005).

[32] IPPNY/EPSA July 21, 2016 Protest at 11-12.

[33] Id. at 12-13.  For example, IPPNY/EPSA point to NYSERDA’s Demand Management Program (DMP), the main point of which, IPPNY/EPSA argue, is to reduce the level of wholesale capacity.

[34] Id. at 13.

[35] Id. at 15.

[36] Id. at 14.

[37] Id. at 15.

[38] Id. at 16-17 (citing Renewables/Self-Supply Complaint Order, 153 FERC ¶ 61,022 at P 105).

[39] Id. at 19-20.

[40] Id. at 20.

[41] MMU July 22, 2016 Comments at 3-4.

[42] Companies August 8, 2016 Answer at 4-5.

[43] Id. at 5 (citing IPPNY/EPSA July 21, 2016 Protest at 18).

[44] Id.

[45] Complainants August 9, 2016 Answer at 13-14.

[46] Id. at 22-23.

[47] Id. at 24-25.

[48] Id. at 18-19.

[49] Id. at 20-21.

[50] 18 C.F.R. § 385.214 (2016).

[51] Id. § 385.214(d).

[52] Id. § 385.213(a)(2).

[53] Once the Commission finds that the challenged tariff provisions in a section 206 proceeding are unjust, unreasonable, or unduly discriminatory or preferential, “the Commission shall determine the just and reasonable rate . . . to be thereafter observed and in force, and shall fix the same by order.”  16 U.S.C. § 824e(a) (2012).

[54] Renewables/Self-Supply Complaint Order, 153 FERC ¶ 61,022 at P 10.  See also Consol. Edison Co. of N.Y., Inc. v. N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,139, at P 2 (ConEd Complaint Order), order on reh’g, clarification, and compliance, 152 FERC ¶ 61,110 (2015) (ConEd Rehearing Order).

[55] See, e.g., ConEd Complaint Order, 150 FERC ¶ 61,139 at PP 45, 50 (finding that NYISO’s buyer-side market power mitigation rules were unnecessarily applied to unsubsidized, competitive entrants with no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices); Renewables/Self-Supply Complaint Order, 153 FERC ¶ 61,022 at P 10 (finding that NYISO’s buyer-side market power mitigation rules were unnecessarily applied to certain renewable and self-supply resources with limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices).

[56] Complaint at 54-55.

[57] NYISO July 21, 2016 Answer at 6.

[58] NYISO July 21, 2016 Answer, Attachment II, Seirup Aff. ¶ 9.

[59] Id. ¶ 10.

[60] See, e.g., NYISO, Services Tariff, § 23.1.2 (0.0.0) (obliging NYISO to file new mitigation measures under section 205 of the FPA if it identifies conduct that constitutes an abuse of market power and is not addressed by other tariff provisions).

[61] SCRs are limited in the sense that their performance is subject to being called by NYISO during a mandatory event; SCRs do not have the discretion to reduce load at will and expect to get paid.

[62] See NYISO July 21, 2016 Answer, Attachment II, Seirup Aff. ¶ 8.

[63] Complaint at 31, n.84 (explaining that, for example, that ConEd’s Distribution Load Relief Program “involves cost-based payments made to a retail customer pursuant to a retail tariff to provide retail load relief on the distribution system”) (citation omitted) (emphasis in original).  The Complainants explain that the retail-level demand response programs are distinguishable further by the facts that the SCR program and the retail-level programs typically are called on at different times, and that the money paid to demand response resources compensates them for the distinct services and benefits provided under the different programs.  Id. at 31.

[64] Id. at 41.

[65] Id. at 25 n.62 (citing Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Case No. 14-M-0101, Comments of Consolidated Edison Company of New York, Inc. and Orange & Rockland Utilities, Inc. on Staff’s White Paper on Utility Ratemaking and Utility Business Models, at 5 (filed Oct. 26, 2015)).

[66] See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 16.

[67] ConEd Complaint Order, 150 FERC ¶ 61,139 at P 2 (citing PJM Interconnection, L.L.C., 128 FERC ¶ 61,157, at PP 90-91 (2009)).

[68] See Renewables/Self-Supply Rehearing Order, 154 FERC ¶ 61,088 at P 31 (“[T]he focus on incentive and ability appropriately balances the need to mitigate the exercise of buyer-side market power to ensure just and reasonable ICAP market prices with the risk of over-mitigating new entrants.”); PJM Interconnection, L.L.C., 143 FERC ¶ 61,090, at P 26 (2013) (finding that PJM’s buyer-side market power mitigation rules “appropriately balance[] the need for mitigation against the risk of over-mitigation”), order on reh’g and compliance, 153 FERC ¶ 61,066 (2015).

[69] See, e.g., Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 16 (finding that “enabling demand-side resources, as well as supply-side resources, improves the economic operation of electric power markets by aligning prices more closely with
the value customers place on electric power”).

[70] See ConEd Rehearing Order, 152 FERC ¶ 61,110 at P 77.

[71] See, e.g., Astoria Generating Co., L.P. v. N.Y. Indep. Sys. Operator, Inc.,
151 FERC ¶ 61,044, at P 51 (2015).

[72] U.S. Energy Information Administration, Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2013 (2015), available at https://www.eia.gov/analysis/requests/subsidy/pdf/subsidy.pdf.

[73] See Hughes v. Talen Energy Mktg., LLC, 136 S. Ct. 1288, 1299 (2016) (holding that federal law preempts state actions that “intrude on FERC’s authority over interstate wholesale rates”).

[74] Id. at 1299 (declining to address “the permissibility of various other measures States might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector” and noting that “[n]othing in this opinion should be read to foreclose Maryland and other States from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation’”).

[75] New State Ice Co. v. Liebmann, 285 U.S. 262, 310 (1932) (Brandeis, J., dissenting).

[76] Hughes, 136 S. Ct. at 1298.  See also PPL Energyplus, LLC v. Solomon, 766 F.3d 241, 255 (3rd Cir. 2016) (“The states may select the type of generation to be built – wind or solar, gas or coal – and where to build the facility.  Or states may elect to build no electric generation facilities at all.  The states’ regulatory choices accumulate into the available supply transacted through the interstate market.  The Federal Power Act grants FERC exclusive control over whether rates are ‘just and reasonable,’ but FERC’s authority over interstate rates does not carry with it exclusive control over any and every force that influences interstate rates.”), cert. denied, 136 S. Ct. 1728 (2016).

[77] H.P. Hood & Sons, Inc. v. DuMond, 336 U.S. 525, 539 (1949) (“[E]very consumer may look to the free competition from every producing area in the Nation to protect him from exploitation by any.”).

[78] Reeves, Inc. v. Stake, 447 U.S. 429, 438 (1980) (quoting Heim v. McCall, 239 U.S. 175, 191 (1915)).

[79] Id. at 442-47 (upholding South Dakota resident-preference program for cement manufactured at state-owned facility).

[80] N.C. State Bd. of Dental Exam’rs v. F.T.C., 135 S. Ct. 1101, 1110 (2015).

[81] S. Motor Carriers Rate Conference, Inc. v. United States, 471 U.S. 48, 61 (1985).

[82] N.C. State Bd. of Dental Exam’rs, 135 S. Ct. at 1109.