B.Mid-Atlantic Region
According to some participants representing generators in the Mid-Atlantic region, power markets provide no incentive to purchase firm contracts for pipeline transportation. Various other participants in the Mid-Atlantic Region conference pointed out that there are multiple ways a gas-fired generator can firm its fuel supplies—through firm contracts for pipeline transportation, dual fuel, storage contracts, and access to more than one pipeline. A North American Electric Reliability Corporation (NERC) representative noted the appeal of a requirement for generator “firmness” that would account for the multiple ways to firm-up fuel supply, and identified a potential firmness requirement as an item more suited for an RTO/ISO proposal rather than a NERC standard.
The prevalence of dual fuel capability in both the NYISO and PJM regions was noted. Participants stated that both the PJM and NYISO markets provide some incentive or requirement for dual fuel. A representative of PJM said that its Reliability Pricing Model (RPM) uses a dual fuel reference unit to determine the Cost of New Entry for the wholesale electric capacity market demand curve, which helps set the price of capacity. In NYISO, according to conference participants, generators in downstate New York (New York City and Long Island) are required to have alternate fuel capability under state reliability requirements. Participants generally indicated that gas markets in PJM are more liquid than those in NYISO given the availability of various pipelines and storage.
While many representatives of generators indicated that they currently are able to secure pipeline capacity, several pipelines noted that liquidity and flexibility experienced thus far in the Mid-Atlantic region are not necessarily indicative of the flexibility that will be available in the future as gas-fired generation grows. Representatives of an LDC and a pipeline also argued that cost causality needs to be matched with cost responsibility. An LDC representative asserted that today certain costs of serving generators’ variability and hourly flows are being paid by LDCs.
The issue of the use of secondary firm contracts and recallable capacity release contracts (rather than primary firm contracts) as a means of serving gas-fired generation was discussed. Several contend the practice of relying on types of transportation services other than primary firm transportation to fuel gas-fired generation is not a reliable solution given the higher rate of curtailment of secondary firm customers. Some pipeline participants also noted that while producers have funded some new pipeline capacity, these pipelines only extend far enough to get the natural gas from the producing region to a liquid pooling point, and there is still a need to build infrastructure to get natural gas from the supply area to generators. Some LDC representatives noted that for generators behind their citygates, even if the generator has firm gas contracts on an interstate pipeline, it still needs firm natural gas delivery capacity on the LDC’s system.
Several participants also raised concerns about planning—whether the planning horizon is long enough and whether market participants are planning appropriately. Noting the differences between electric and gas planning horizons, a pipeline noted that pipelines do not plan for growth; rather they build to accommodate firm customers. An industrial participant argued that market signals are not a substitute for planning and contended that the region may need a longer-term planning horizon. A generator noted that while a long-term electric planning process exists, what is missing is consideration of fuel security.
There was no consensus among Mid-Atlantic conference participants as to the best way to address the gas-electric scheduling mismatch. A representative of NYISO stated that it currently releases its day-ahead dispatch results earlier (10 a.m. EST) than PJM does (4 p.m. EST). NYISO’s representative noted that the earlier release allows gas-fired generators to be better informed for the first timely pipeline nomination cycle which occurs at 11 a.m. (CST). Feedback from participants representing generators on whether they preferred the earlier release or later release was mixed. NYISO’s representative also reported that it is considering moving the day-ahead dispatch results release to earlier than 10 a.m. (EST) (when gas markets are more liquid) or later (to facilitate better gas supply and transportation price certainty when bidding), and will continue to explore scheduling through its stakeholder process. Conference participants noted that in PJM, where the natural gas market is relatively liquid and there are many pipelines and storage reservoirs, generators thus far have been able to acquire natural gas supplies and pipeline capacity in later pipeline nomination cycles. Conference participants noted that in
NYISO where the gas market is less liquid it is not always easy to acquire gas after the first timely pipeline nomination cycle.
With regard to the process for allowing generators to modify bids to reflect actual fuel costs, NYISO permits it if a generator had to switch fuels or procure more expensive intra-day gas if the ISO increased its dispatch level. According to the PJM representative, PJM does not currently permit this, but PJM would be open to considering it.
Some participants representing generators encouraged the creation of more nomination cycles. Pipeline representatives noted that some pipelines in the region already offer hourly nomination cycles and stated that more frequent nominations will not help if there is inadequate pipeline capacity.
Regarding communications, a representative of NYISO noted that it does not necessarily understand how pipeline outages impact the electric system and which generators will be affected. Representatives of PJM and a pipeline mentioned a partnership which would include exchanging control room operators. They expect that spending time in each others’ control rooms will help to bridge the language gap and learn about each other’s industry. Various conference participants also noted their interest in tabletop exercises that simulate reliability scenarios. A representative of NYISO noted that several combined gas-electric utilities, along with certain pipelines within its area, recently ran a useful tabletop exercise.
Conference participants indicated that there is no formal outage coordination process across industries, but some expressed support for a formalized process. Some conference participants noted there is a tension between wanting to openly discuss publicly available information on outages and the impact on operations, and concern about whether unit-specific discussion would violate regulations against undue preference or discrimination. Pipeline representatives noted reluctance to discuss granular impacts at the level of individual shippers beyond the information the pipelines make publicly available on electronic bulletin boards. One participant noted that enhanced outage coordination gives rise to heightened concern over manipulation. Various participants indicated concern about specifying shipper-level information in discussions.
Participants from both the natural gas and electric industries suggested clarification of the Standards of Conduct and Natural Gas Act Section 4b undue preference and anti-manipulation rules would be helpful.10 One participant suggested
“common sense leeway” to the Standards of Conduct rules in emergencies. A pipeline trade association representative noted that some RTOs/ISOs have adopted the Standards of Conduct in their tariffs and RTOs/ISOs are concerned about sharing information with pipelines. PJM’s representative asked whether it can tell pipelines which generator units will be dispatched.
Participants articulated different views on the markets’ ability to send appropriate signals. One pipeline representative argued that electric market signals do not factor in reliability and another participant argued that generators in unregulated markets have no incentive to contract for firm pipeline transportation. A PJM representative noted that its wholesale electric capacity market does not pay generators if they do not run and capacity factors11 decline if generators do not run. A generator representative stated that PJM’s capacity market sends the right signals, while a pipeline representative argued that PJM’s nonperformance penalties are weak and do not justify paying for fuel security. A NERC representative noted that many capacity market incentives, such as Equivalent Forced Outage Rate—demand (EFORd)12 penalties, are problematic because they are retrospective and the impact arrives three years later.
In general, participants in this technical conference urged the Commission to “be patient” and check back with the regions to see that they continue to make progress on most issues involving gas-electric coordination, although there was interest in having the communications issues clarified.
Mid-Atlantic Regional Initiatives
A representative of NYISO noted that NYISO, PJM, ISO-NE, the Ontario Independent Electricity System Operator (IESO), and possibly also Midwest Independent System Operator (MISO) are planning a comprehensive study across pipelines serving these regions that would incorporate retirements and infrastructure changes over five to ten years. The study will examine planned generation retirements, new transmission lines, and new pipelines for the next five to 10 years and try to identify any electric reliability problems. The study is expected to be available sometime in 2013.
On communications between the RTOs/ISOs and the pipelines in coordinating outages, representatives of PJM and NYISO discussed educational processes and
operator training and exchange programs, and the development of protocols for the sharing of maintenance schedules.13 As mentioned above, several combined utilities went through a tabletop reliability scenario exercise with several pipelines, where they examined different scenarios based upon loss of supply.
According to some participants representing generators in the Mid-Atlantic region, power markets provide no incentive to purchase firm contracts for pipeline transportation. Various other participants in the Mid-Atlantic Region conference pointed out that there are multiple ways a gas-fired generator can firm its fuel supplies—through firm contracts for pipeline transportation, dual fuel, storage contracts, and access to more than one pipeline. A North American Electric Reliability Corporation (NERC) representative noted the appeal of a requirement for generator “firmness” that would account for the multiple ways to firm-up fuel supply, and identified a potential firmness requirement as an item more suited for an RTO/ISO proposal rather than a NERC standard.The prevalence of dual fuel capability in both the NYISO and PJM regions was noted. Participants stated that both the PJM and NYISO markets provide some incentive or requirement for dual fuel. A representative of PJM said that its Reliability Pricing Model (RPM) uses a dual fuel reference unit to determine the Cost of New Entry for the wholesale electric capacity market demand curve, which helps set the price of capacity. In NYISO, according to conference participants, generators in downstate New York (New York City and Long Island) are required to have alternate fuel capability under state reliability requirements. Participants generally indicated that gas markets in PJM are more liquid than those in NYISO given the availability of various pipelines and storage.
While many representatives of generators indicated that they currently are able to secure pipeline capacity, several pipelines noted that liquidity and flexibility experienced thus far in the Mid-Atlantic region are not necessarily indicative of the flexibility that will be available in the future as gas-fired generation grows. Representatives of an LDC and a pipeline also argued that cost causality needs to be matched with cost responsibility. An LDC representative asserted that today certain costs of serving generators’ variability and hourly flows are being paid by LDCs.
The issue of the use of secondary firm contracts and recallable capacity release contracts (rather than primary firm contracts) as a means of serving gas-fired generation was discussed. Several contend the practice of relying on types of transportation services other than primary firm transportation to fuel gas-fired generation is not a reliable solution given the higher rate of curtailment of secondary firm customers. Some pipeline participants also noted that while producers have funded some new pipeline capacity, these pipelines only extend far enough to get the natural gas from the producing region to a liquid pooling point, and there is still a need to build infrastructure to get natural gas from the supply area to generators. Some LDC representatives noted that for generators behind their citygates, even if the generator has firm gas contracts on an interstate pipeline, it still needs firm natural gas delivery capacity on the LDC’s system.
Several participants also raised concerns about planning—whether the planning horizon is long enough and whether market participants are planning appropriately. Noting the differences between electric and gas planning horizons, a pipeline noted that pipelines do not plan for growth; rather they build to accommodate firm customers. An industrial participant argued that market signals are not a substitute for planning and contended that the region may need a longer-term planning horizon. A generator noted that while a long-term electric planning process exists, what is missing is consideration of fuel security.
There was no consensus among Mid-Atlantic conference participants as to the best way to address the gas-electric scheduling mismatch. A representative of NYISO stated that it currently releases its day-ahead dispatch results earlier (10 a.m. EST) than PJM does (4 p.m. EST). NYISO’s representative noted that the earlier release allows gas-fired generators to be better informed for the first timely pipeline nomination cycle which occurs at 11 a.m. (CST). Feedback from participants representing generators on whether they preferred the earlier release or later release was mixed. NYISO’s representative also reported that it is considering moving the day-ahead dispatch results release to earlier than 10 a.m. (EST) (when gas markets are more liquid) or later (to facilitate better gas supply and transportation price certainty when bidding), and will continue to explore scheduling through its stakeholder process. Conference participants noted that in PJM, where the natural gas market is relatively liquid and there are many pipelines and storage reservoirs, generators thus far have been able to acquire natural gas supplies and pipeline capacity in later pipeline nomination cycles. Conference participants noted that in
NYISO where the gas market is less liquid it is not always easy to acquire gas after the first timely pipeline nomination cycle.
With regard to the process for allowing generators to modify bids to reflect actual fuel costs, NYISO permits it if a generator had to switch fuels or procure more expensive intra-day gas if the ISO increased its dispatch level. According to the PJM representative, PJM does not currently permit this, but PJM would be open to considering it.
Some participants representing generators encouraged the creation of more nomination cycles. Pipeline representatives noted that some pipelines in the region already offer hourly nomination cycles and stated that more frequent nominations will not help if there is inadequate pipeline capacity.
Regarding communications, a representative of NYISO noted that it does not necessarily understand how pipeline outages impact the electric system and which generators will be affected. Representatives of PJM and a pipeline mentioned a partnership which would include exchanging control room operators. They expect that spending time in each others’ control rooms will help to bridge the language gap and learn about each other’s industry. Various conference participants also noted their interest in tabletop exercises that simulate reliability scenarios. A representative of NYISO noted that several combined gas-electric utilities, along with certain pipelines within its area, recently ran a useful tabletop exercise.
Conference participants indicated that there is no formal outage coordination process across industries, but some expressed support for a formalized process. Some conference participants noted there is a tension between wanting to openly discuss publicly available information on outages and the impact on operations, and concern about whether unit-specific discussion would violate regulations against undue preference or discrimination. Pipeline representatives noted reluctance to discuss granular impacts at the level of individual shippers beyond the information the pipelines make publicly available on electronic bulletin boards. One participant noted that enhanced outage coordination gives rise to heightened concern over manipulation. Various participants indicated concern about specifying shipper-level information in discussions.
Participants from both the natural gas and electric industries suggested clarification of the Standards of Conduct and Natural Gas Act Section 4b undue preference and anti-manipulation rules would be helpful.10 One participant suggested
“common sense leeway” to the Standards of Conduct rules in emergencies. A pipeline trade association representative noted that some RTOs/ISOs have adopted the Standards of Conduct in their tariffs and RTOs/ISOs are concerned about sharing information with pipelines. PJM’s representative asked whether it can tell pipelines which generator units will be dispatched.
Participants articulated different views on the markets’ ability to send appropriate signals. One pipeline representative argued that electric market signals do not factor in reliability and another participant argued that generators in unregulated markets have no incentive to contract for firm pipeline transportation. A PJM representative noted that its wholesale electric capacity market does not pay generators if they do not run and capacity factors11 decline if generators do not run. A generator representative stated that PJM’s capacity market sends the right signals, while a pipeline representative argued that PJM’s nonperformance penalties are weak and do not justify paying for fuel security. A NERC representative noted that many capacity market incentives, such as Equivalent Forced Outage Rate—demand (EFORd)12 penalties, are problematic because they are retrospective and the impact arrives three years later.
In general, participants in this technical conference urged the Commission to “be patient” and check back with the regions to see that they continue to make progress on most issues involving gas-electric coordination, although there was interest in having the communications issues clarified.
Mid-Atlantic Regional Initiatives
A representative of NYISO noted that NYISO, PJM, ISO-NE, the Ontario Independent Electricity System Operator (IESO), and possibly also Midwest Independent System Operator (MISO) are planning a comprehensive study across pipelines serving these regions that would incorporate retirements and infrastructure changes over five to ten years. The study will examine planned generation retirements, new transmission lines, and new pipelines for the next five to 10 years and try to identify any electric reliability problems. The study is expected to be available sometime in 2013.
On communications between the RTOs/ISOs and the pipelines in coordinating outages, representatives of PJM and NYISO discussed educational processes and
operator training and exchange programs, and the development of protocols for the sharing of maintenance schedules.13 As mentioned above, several combined utilities went through a tabletop reliability scenario exercise with several pipelines, where they examined different scenarios based upon loss of supply.
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