C.Electric Resource Adequacy
The question of whether generators in a particular region have appropriate incentives to deliver firm energy was raised at several of the technical conferences. At every conference, natural gas pipeline representatives emphasized that they are in the business of delivering gas to meet customer needs, but that the customers themselves must arrange for gas supplies. There were differences of opinion, however, with regard to the perceived need for firm delivery arrangements from natural gas pipelines as between electric industry representatives at the conferences.
In the Southeast, characterized by electric service being provided by vertically-integrated electric utilities, firm natural gas pipeline arrangements appear to be the norm. As a result, in this region, there appears to be little concern about ensuring adequate pipeline infrastructure.68 In regions with restructured electric markets and an RTO or ISO, natural gas-fired generators appear to rely more heavily on pipeline capacity release and interruptible services for delivery of gas supplies. Some contend that this practice appropriately reflects the variability with which gas-fired generators are dispatched in RTO/ISO regions, while others suggested the practice indicates a need to provide greater incentives to generators to arrange for fuel supplies in a way that ensures reliability. Conference participants suggesting enhancements to RTO/ISO market rules generally focused on the terms of organized wholesale electric capacity markets and performance incentives for resources clearing in those markets. Several participants at the Northeast conference stated there is a need for additional pipeline infrastructure but there was also recognition that options are limited for addressing the gas infrastructure issue in the near term and that, under current market structures, generators have few incentives to obtain long-term primary firm pipeline service or invest in alternative fuel capabilities.
Most organized wholesale electric capacity markets provide no more than a one-year or seasonal price. Various technical conference participants noted the tension between a short-term one-year price from capacity markets and the long-term decision to contract for firm fuel supply. Representatives from the RTOs and ISOs with organized capacity markets indicated that they are aware of this tension and are exploring potential market design changes. PJM stakeholders are considering multi-year pricing mechanisms, including a voluntary long-term auction.69 A recent letter from PJM indicated that stakeholders are still discussing long-term options and noted that stakeholders agreed to attempt to develop business rules for a multi-year pricing mechanism in time for a May 31, 2013 filing, which could be applied to the May 2014 auction.70
Participants in some regions questioned whether the incentives, penalties, and/or participation requirements in the organized wholesale electric capacity markets are adequate to incent performance and ensure a firm fuel supply. Participants in virtually all regions with capacity markets indicated that their capacity markets do not consider the firmness of a generator’s fuel supply when clearing resources. At the Northeast conference, a representative of ISO-NE indicated that a generator’s Forward Capacity Market (FCM) penalties for not showing up are too low, though one generator argued that forward capacity market nonperformance penalties are substantial. ISO-NE’s representative indicated that its Strategic Planning Initiative includes plans to strengthen capacity market performance incentives. On October 22, ISO-NE shared with stakeholders a white paper on FCM performance incentives that included a proposal to make FCM resources’ revenue contingent on performance during scarcity conditions.71 Stakeholders are currently considering these proposed modifications.
In the Mid-Atlantic region, one gas company in PJM argued that PJM’s Reliability Pricing Model (RPM)72 nonperformance incentives are too weak to encourage a
generator to pay for firm contracts or dual fuel; the gas company argued that PJM should consider increasing penalty provisions or treating a capacity resource as a limited capacity resource. A representative of PJM, however, noted that a generator with an RPM commitment that fails to perform will be penalized with an Unforced Capacity (UCAP)73 reduction and thus earn less in future years. A NYISO representative indicated that they could consider improving their UCAP nonperformance perepresentative of NERC noted that because many capacity market incentives such as Equivalent Forced Outage Rate (EFORd)74 penalties are retrospective, the penalty’s impact does not arrive until three years later. The NERC representative noted that this may be a concern given not only the longer-term dependence on gas, but the near-term dependence on gas because in the next three years a substantial number of coal units will be going offline for retrofit.
Discussion at the conferences affirmed that each region meets resource adequacy requirements in its own way. Focusing on the RTO/ISO markets that rely on capacity market constructs regulated by the Commission, a number of issues have been raised regarding whether and how to structure gas-fired generator’s performance incentives. PJM, ISO-NE and NYISO each have somewhat different market designs and each has commenced work to evaluate performance incentives in their respective regions. MISO continues to study the issue, with plans to refine and update studies evaluating whether generation capacity is sufficient. In CAISO, conference participants stated that gas infrastructure is expanded in anticipation of load (as opposed to responding to firm contracts) and CAISO’s non-performance penalties are adequate.
Staff believes that resource adequacy issues in these markets should continue to be addressed in the first instance by market participants, states, and other stakeholders in each region. Unlike the communication and scheduling issues discusses earlier in this report, generic guidance may not be helpful at this time for regions considering how to structure market rules to ensure that generators have appropriate incentives to deliver firm energy. Significant attention and resources are being devoted to these matters, concrete issues have been identified, and responses to those issues are being formulated.
Staff will monitor progress on these initiatives and encourages industry representatives to contact staff if guidance is required.
The question of whether generators in a particular region have appropriate incentives to deliver firm energy was raised at several of the technical conferences. At every conference, natural gas pipeline representatives emphasized that they are in the business of delivering gas to meet customer needs, but that the customers themselves must arrange for gas supplies. There were differences of opinion, however, with regard to the perceived need for firm delivery arrangements from natural gas pipelines as between electric industry representatives at the conferences.In the Southeast, characterized by electric service being provided by vertically-integrated electric utilities, firm natural gas pipeline arrangements appear to be the norm. As a result, in this region, there appears to be little concern about ensuring adequate pipeline infrastructure.68 In regions with restructured electric markets and an RTO or ISO, natural gas-fired generators appear to rely more heavily on pipeline capacity release and interruptible services for delivery of gas supplies. Some contend that this practice appropriately reflects the variability with which gas-fired generators are dispatched in RTO/ISO regions, while others suggested the practice indicates a need to provide greater incentives to generators to arrange for fuel supplies in a way that ensures reliability. Conference participants suggesting enhancements to RTO/ISO market rules generally focused on the terms of organized wholesale electric capacity markets and performance incentives for resources clearing in those markets. Several participants at the Northeast conference stated there is a need for additional pipeline infrastructure but there was also recognition that options are limited for addressing the gas infrastructure issue in the near term and that, under current market structures, generators have few incentives to obtain long-term primary firm pipeline service or invest in alternative fuel capabilities.
Most organized wholesale electric capacity markets provide no more than a one-year or seasonal price. Various technical conference participants noted the tension between a short-term one-year price from capacity markets and the long-term decision to contract for firm fuel supply. Representatives from the RTOs and ISOs with organized capacity markets indicated that they are aware of this tension and are exploring potential market design changes. PJM stakeholders are considering multi-year pricing mechanisms, including a voluntary long-term auction.69 A recent letter from PJM indicated that stakeholders are still discussing long-term options and noted that stakeholders agreed to attempt to develop business rules for a multi-year pricing mechanism in time for a May 31, 2013 filing, which could be applied to the May 2014 auction.70
Participants in some regions questioned whether the incentives, penalties, and/or participation requirements in the organized wholesale electric capacity markets are adequate to incent performance and ensure a firm fuel supply. Participants in virtually all regions with capacity markets indicated that their capacity markets do not consider the firmness of a generator’s fuel supply when clearing resources. At the Northeast conference, a representative of ISO-NE indicated that a generator’s Forward Capacity Market (FCM) penalties for not showing up are too low, though one generator argued that forward capacity market nonperformance penalties are substantial. ISO-NE’s representative indicated that its Strategic Planning Initiative includes plans to strengthen capacity market performance incentives. On October 22, ISO-NE shared with stakeholders a white paper on FCM performance incentives that included a proposal to make FCM resources’ revenue contingent on performance during scarcity conditions.71 Stakeholders are currently considering these proposed modifications.
In the Mid-Atlantic region, one gas company in PJM argued that PJM’s Reliability Pricing Model (RPM)72 nonperformance incentives are too weak to encourage a
generator to pay for firm contracts or dual fuel; the gas company argued that PJM should consider increasing penalty provisions or treating a capacity resource as a limited capacity resource. A representative of PJM, however, noted that a generator with an RPM commitment that fails to perform will be penalized with an Unforced Capacity (UCAP)73 reduction and thus earn less in future years. A NYISO representative indicated that they could consider improving their UCAP nonperformance perepresentative of NERC noted that because many capacity market incentives such as Equivalent Forced Outage Rate (EFORd)74 penalties are retrospective, the penalty’s impact does not arrive until three years later. The NERC representative noted that this may be a concern given not only the longer-term dependence on gas, but the near-term dependence on gas because in the next three years a substantial number of coal units will be going offline for retrofit.
Discussion at the conferences affirmed that each region meets resource adequacy requirements in its own way. Focusing on the RTO/ISO markets that rely on capacity market constructs regulated by the Commission, a number of issues have been raised regarding whether and how to structure gas-fired generator’s performance incentives. PJM, ISO-NE and NYISO each have somewhat different market designs and each has commenced work to evaluate performance incentives in their respective regions. MISO continues to study the issue, with plans to refine and update studies evaluating whether generation capacity is sufficient. In CAISO, conference participants stated that gas infrastructure is expanded in anticipation of load (as opposed to responding to firm contracts) and CAISO’s non-performance penalties are adequate.
Staff believes that resource adequacy issues in these markets should continue to be addressed in the first instance by market participants, states, and other stakeholders in each region. Unlike the communication and scheduling issues discusses earlier in this report, generic guidance may not be helpful at this time for regions considering how to structure market rules to ensure that generators have appropriate incentives to deliver firm energy. Significant attention and resources are being devoted to these matters, concrete issues have been identified, and responses to those issues are being formulated.
Staff will monitor progress on these initiatives and encourages industry representatives to contact staff if guidance is required.
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