B.Scheduling-Related Issues
Several conference participants raised issues related to gas and electric scheduling and pipeline capacity release.51 Generators participating in the RTO/ISO markets stated that managing fuel procurement risk can be a challenge because the operating days between the natural gas and electric industries are not aligned, and the timeframe for nominating natural gas transportation service, including pursuant to a capacity release, is not synchronized with the timeframe during which generators receive confirmation of their bids in the day-ahead electric markets. While electric scheduling practices and market rules within some regions are being refined to better align with gas scheduling opportunities, changes to gas scheduling practices can have national implications given the way pipeline systems are operated. As a result, whether gas scheduling practices need to be changed and, if so, what changes are warranted has been a matter of debate among the industries for a number of years.
Scheduling Practices
Standard pipeline services are generally designed as daily services, and the gas day covers a 24-hour period beginning at 9:00 a.m. Central clock time (CCT). For most rate schedules, tariffs provide that the pipeline may insist that gas be taken on a uniform hourly rate of flow although the pipeline tariffs generally provide that the pipeline permits fluctuations in flow on a best efforts basis. The NAESB gas standards, which the
Commission regulations incorporate by reference, currently provide shippers one day-ahead nomination opportunity, the Timely Nomination Cycle (11:30 a.m. CCT the day prior to gas flow), and three opportunities to revise that nomination, one in the day-ahead (the Evening Nomination Cycle (6 p.m. CCT the day before gas flow) and two within the gas day (the Intra-Day 1 (10 a.m. CCT the day of gas flow) and Intra-Day 2 (5 p.m. CCT the day of gas flow)). In the event a pipeline cannot fulfill all service requests, the pipeline allocates capacity according to its nomination priorities. As a general matter, (1) nominations of firm transportation service from “primary” points of receipt to “primary” points of delivery, which is termed “primary firm” service, have the highest priority; (2) nominations from alternative or additional “secondary” receipt or delivery points, which is termed “secondary firm service,” is next in priority and (3) interruptible service is the lowest priority.
Schedules made during the Timely Nomination Cycle establish the allocation of pipeline capacity for the next gas day. In this cycle, the priorities listed above apply so primary firm nominations have priority over all other nominations. During the next three cycles, primary and secondary point nominations are treated equally, so a request to change quantities at a primary point will not bump already scheduled secondary firm service. A revised firm nomination during the Evening and Intra-Day cycles, however, can bump already scheduled interruptible service from prior cycles. During the final Intra-Day- 2 cycle, primary and secondary firm nominations cannot bump already scheduled interruptible service. Pipelines are permitted to offer additional nomination opportunities.
In contrast, electric generators are dispatched during the operating day hour-by-hour. A gas-fired generator may operate for many hours throughout the day or may operate only during peak hours. Increasingly, gas-fired generators are being dispatched as flexible resources, ramping up and down within the hour and across the day to help balance the electric system.
There is no defined electric day, but for most entities the standard 24-hour calendar day begins at 12:00 a.m. local time. Similar to the gas industry, electric generators in wholesale electric markets bid into the market prior to the given electric day, commonly known as the day-ahead market. For these generators, the time to obtain the best natural gas prices is typically before the Timely Nomination Cycle, because the gas markets would be most liquid at this time.52 However, an electric generator’s day-
ahead electric bids generally are not confirmed by the RTO/ISO until after the Timely Nomination Cycle for pipeline service.53
Various generators participating in the RTO/ISO markets noted that these differing timelines result in significant price and/or supply risk for gas-fired generators because, to obtain the best gas price, the generators would need to nominate pipeline transportation service before they know if their electric bid has been confirmed. Generators also noted that, given the operating day mismatch, a pipeline nomination will cover parts of two electric days and therefore involve multiple iterations of the unit commitment process as day-ahead commitments turn into real time dispatch and the day-ahead commitments for the next electric day.54 Concern also was expressed about whether the standard gas nomination schedule provides sufficient ability for generators to revise their nominations as needed by dispatch requirements, whether located within or outside RTO and ISO markets.
Representatives from the gas and electric industries participating in the conferences offered different perspectives on whether changes need to be made in either industry’s scheduling framework. As several pipeline representatives pointed out, some pipelines offer to shippers more than the NAESB standard four daily nomination cycles. For example, in March of this year, the Commission approved a proposal by Texas Gas Transmission LLC (Texas Gas) to allow firm shippers contracting for Enhanced Nominations Service an additional eleven nomination cycles each gas day.55 Some pipelines offer a firm no-notice service under which firm shippers can receive delivery of gas on demand up to their firm entitlements on a daily basis, without incurring daily scheduling and balancing penalties. The purpose of no-notice service is to enable firm shippers to meet unexpected requirements such as sudden changes in temperature. Some pipelines also offer firm shippers enhanced services that allow for greater flexibility in the rate at which their gas can flow. This service, as well as the no-notice service described above, is provided at a higher rate.
Also, representatives of the NYISO and ISO-NE present at the conferences stated that they have considered ways to change the schedule of the day-ahead unit commitment process to better coincide with the gas timely nomination cycle. For example, ISO-NE is considering moving up the timeline for day-ahead unit commitment and the resource adequacy assessment process in an effort to provide additional time to gas-fired generators to procure gas supplies and transportation services so that adequate generation capacity is available in real time.56 However, it was pointed out by several participants at the conference that one disadvantage of moving the day-ahead unit commitment timeframes closer in time to the gas Timely Nomination Cycle and therefore, further from the real time, is that electric load forecasts become less accurate. Some conference participants also indicated that one reason it has been difficult to change the day-ahead unit commitment process is the absence of a standardized electric schedule across markets, similar to the standardized gas day.
A related scheduling issue raised by conference participants involved the service priorities for transportation services offered by interstate pipelines and the “no-bump” rule.57 As noted above, primary and secondary nominations cannot bump already scheduled interruptible service during the final Intra-day 2 cycle, which is at 5 p.m. CCT.58 Discussion at some of the technical conferences indicated that the general consensus supporting the no-bump rule may no longer exist. Some generators with firm pipeline service stated that they would like to see additional nomination opportunities and in some cases, elimination of the no-bump rule. They contended that the current gas nomination cycles do not provide sufficient flexibility to generators facing weather-driven electric load variations, and the no-bump rule impedes their ability to use their firm service flexibly. However, other firm gas shippers, such as industrial users in the Southeast, argued in favor of retaining the no-bump rule. They stated that elimination of
the no-bump rule could cause fewer shippers to use interruptible transportation, resulting in lower overall utilization of pipeline capacity and a greater share of fixed costs allocated to firm shippers.
As noted by many conference participants, prior efforts of NAESB participants did not reach consensus on the creation of a unified gas and electric timeline,59 revisions to the gas nomination schedule to permit additional intra-day changes, or elimination of the no-bump rule. Several participants maintained that these changes were not a high priority and accordingly, should not be a priority for the Commission. To the extent changes are made, most conference participants agreed that these issues are interrelated and cannot be considered in isolation, and that any changes would need to be implemented in a way that makes sense for both industries from both regional and national perspectives.
Staff believes that further discussion is necessary to explore whether coordinated refinements to gas and electric scheduling rules are appropriate. Existing Commission policies and regulations provide a certain degree of flexibility in the near term for utilities to address coordinated scheduling issues on a regional basis and for pipelines to provide enhanced scheduling. As noted above, several RTOs/ISOs are considering or have refined their market practices and some pipelines have modified services and nomination cycles to meet the needs their customers. These efforts improve operations across both the gas and electric industries and should continue to be pursued. However, they do not address whether industry-wide changes would be appropriate to improve the longer-term harmonization of gas and electric operations. Taking a broader view of gas-electric scheduling issues could lead to greater operational efficiencies in both industries.
To that end, staff will continue to engage industry on gas and electric scheduling issues, including the effect of the Commission’s no-bump rule. During this outreach, staff will monitor the progress being made on the following activities highlighted by conference participants:
ISO-NE’s consideration of moving the timeline for its day-ahead unit commitment and resource adequacy assessment process and allowance of bid adjustments and hourly re-offers;
NYISO’s consideration of moving releasing day-ahead dispatch results to early than 10 AM (EST), when gas markets are more liquid; and,
The ability of natural gas pipelines to offer additional nomination opportunities after 5 PM or provide for electronic scheduling that could be completed faster than the current four hour processing time.
Progress on these nearer-term activities may facilitate greater coordination between the gas and electric markets while longer-term initiatives are being evaluated.
Capacity Release
In many regions, natural gas LDCs contract for firm long-term pipeline service based on their winter peak demand. Consequently, those LDCs generally have excess natural gas transportation capacity in the summer when gas demand is lower. In contrast, gas-fired electric generation in most, but not all, regions experience demand peaks in the summer time when LDC use of pipeline capacity is relatively low.60 As a result, gas-fired generators have generally been able to utilize released pipeline capacity from the LDCs to meet their gas delivery needs.61
As the relative amount of gas-fired generation increases, some contend that in the future these dynamics will no longer hold true. Gas-fired generation has increased to an extent that some pipelines are operating at increasing load factors, with diminishing availability of capacity to serve new gas-fired generation needs. For example, in New England, which experiences relatively high winter electric demand, gas-fired generators are increasingly competing with LDCs for pipeline capacity.
In response to these concerns, participants at every technical conference expressed a desire for more flexible capacity release on pipelines. Issues raised included a desire for more opportunities for intra-day releases and short-term or even hourly releases, enhanced ability to facilitate pre-arranged bilateral release deals, and more streamlined processing of capacity release transactions. In some cases, technical conference participants discussed “gas demand response,” but did not specify what that meant or how it could be implemented on the gas pipelines. In at least one case, a large generator with firm gas contracts suggested that more transparency regarding how pipelines analyze their systems to determine available pipeline capacity would be desirable.
The Commission’s current pipeline capacity release program is designed to permit expeditious and flexible releases.62 A firm shipper (releasing shipper) sells its capacity
by returning its capacity to the pipeline for reassignment to the buyer (replacement shipper).63 Released capacity is offered for bid on the pipeline’s website and awarded to the highest bidder. Firm shippers may also enter into a pre-arranged release directly with a replacement shipper. If the prearranged release is for a term of one month or less it need not be posted for bidding. The replacement shipper may pay less than the pipeline’s maximum tariff rate, but not more for releases that are long term in nature. Short term releases, those for one year or less, are not subject to price limitations tied to a pipeline’s maximum tariff rate.64 Many pipelines also permit replacement shippers to prequalify for releases, which expedites the assignment of capacity.
With respect to the flexibility of releases, the regulations provide that releasing shippers can release capacity at any time and that “pipelines must permit shippers acquiring released capacity to submit a nomination at the earliest available nomination opportunity after the acquisition of capacity.”65 Under the regulations, the pipelines must process these releases in one hour. As a consequence of the Commission’s posting and bidding rules, an LDC and a generator, for example, could negotiate a short term release at a market-determined rate at any nomination cycle permitted by the pipeline, including releases during the intra-day process.66 In addition to capacity release, shippers can make bundled gas sales to third-parties.67
The Commission’s capacity release regulations, including the NAESB WGQ standards, therefore provide shippers with considerable flexibility to acquire released capacity or obtain gas on a timely basis. However, the implementation of a capacity release remains subject to the scheduling opportunities available. As a result, it may be
that the concerns expressed by conference participants are driven more by the desire for greater pipeline scheduling flexibilities, or by an unwillingness of firm transportation contract holders to release capacity, than the Commission’s capacity release rules. Staff notes that no specific reforms in the area of capacity release were suggested by conference participants, nor was the relationship between capacity release and underlying pipeline scheduling opportunities generally discussed. Nonetheless, given the significant number of conference participants that raised capacity release rules as an issue to be address, staff believes is it necessary to continue to engage industry with respect to this issue.
Several conference participants raised issues related to gas and electric scheduling and pipeline capacity release.51 Generators participating in the RTO/ISO markets stated that managing fuel procurement risk can be a challenge because the operating days between the natural gas and electric industries are not aligned, and the timeframe for nominating natural gas transportation service, including pursuant to a capacity release, is not synchronized with the timeframe during which generators receive confirmation of their bids in the day-ahead electric markets. While electric scheduling practices and market rules within some regions are being refined to better align with gas scheduling opportunities, changes to gas scheduling practices can have national implications given the way pipeline systems are operated. As a result, whether gas scheduling practices need to be changed and, if so, what changes are warranted has been a matter of debate among the industries for a number of years.Scheduling Practices
Standard pipeline services are generally designed as daily services, and the gas day covers a 24-hour period beginning at 9:00 a.m. Central clock time (CCT). For most rate schedules, tariffs provide that the pipeline may insist that gas be taken on a uniform hourly rate of flow although the pipeline tariffs generally provide that the pipeline permits fluctuations in flow on a best efforts basis. The NAESB gas standards, which the
Commission regulations incorporate by reference, currently provide shippers one day-ahead nomination opportunity, the Timely Nomination Cycle (11:30 a.m. CCT the day prior to gas flow), and three opportunities to revise that nomination, one in the day-ahead (the Evening Nomination Cycle (6 p.m. CCT the day before gas flow) and two within the gas day (the Intra-Day 1 (10 a.m. CCT the day of gas flow) and Intra-Day 2 (5 p.m. CCT the day of gas flow)). In the event a pipeline cannot fulfill all service requests, the pipeline allocates capacity according to its nomination priorities. As a general matter, (1) nominations of firm transportation service from “primary” points of receipt to “primary” points of delivery, which is termed “primary firm” service, have the highest priority; (2) nominations from alternative or additional “secondary” receipt or delivery points, which is termed “secondary firm service,” is next in priority and (3) interruptible service is the lowest priority.
Schedules made during the Timely Nomination Cycle establish the allocation of pipeline capacity for the next gas day. In this cycle, the priorities listed above apply so primary firm nominations have priority over all other nominations. During the next three cycles, primary and secondary point nominations are treated equally, so a request to change quantities at a primary point will not bump already scheduled secondary firm service. A revised firm nomination during the Evening and Intra-Day cycles, however, can bump already scheduled interruptible service from prior cycles. During the final Intra-Day- 2 cycle, primary and secondary firm nominations cannot bump already scheduled interruptible service. Pipelines are permitted to offer additional nomination opportunities.
In contrast, electric generators are dispatched during the operating day hour-by-hour. A gas-fired generator may operate for many hours throughout the day or may operate only during peak hours. Increasingly, gas-fired generators are being dispatched as flexible resources, ramping up and down within the hour and across the day to help balance the electric system.
There is no defined electric day, but for most entities the standard 24-hour calendar day begins at 12:00 a.m. local time. Similar to the gas industry, electric generators in wholesale electric markets bid into the market prior to the given electric day, commonly known as the day-ahead market. For these generators, the time to obtain the best natural gas prices is typically before the Timely Nomination Cycle, because the gas markets would be most liquid at this time.52 However, an electric generator’s day-
ahead electric bids generally are not confirmed by the RTO/ISO until after the Timely Nomination Cycle for pipeline service.53
Various generators participating in the RTO/ISO markets noted that these differing timelines result in significant price and/or supply risk for gas-fired generators because, to obtain the best gas price, the generators would need to nominate pipeline transportation service before they know if their electric bid has been confirmed. Generators also noted that, given the operating day mismatch, a pipeline nomination will cover parts of two electric days and therefore involve multiple iterations of the unit commitment process as day-ahead commitments turn into real time dispatch and the day-ahead commitments for the next electric day.54 Concern also was expressed about whether the standard gas nomination schedule provides sufficient ability for generators to revise their nominations as needed by dispatch requirements, whether located within or outside RTO and ISO markets.
Representatives from the gas and electric industries participating in the conferences offered different perspectives on whether changes need to be made in either industry’s scheduling framework. As several pipeline representatives pointed out, some pipelines offer to shippers more than the NAESB standard four daily nomination cycles. For example, in March of this year, the Commission approved a proposal by Texas Gas Transmission LLC (Texas Gas) to allow firm shippers contracting for Enhanced Nominations Service an additional eleven nomination cycles each gas day.55 Some pipelines offer a firm no-notice service under which firm shippers can receive delivery of gas on demand up to their firm entitlements on a daily basis, without incurring daily scheduling and balancing penalties. The purpose of no-notice service is to enable firm shippers to meet unexpected requirements such as sudden changes in temperature. Some pipelines also offer firm shippers enhanced services that allow for greater flexibility in the rate at which their gas can flow. This service, as well as the no-notice service described above, is provided at a higher rate.
Also, representatives of the NYISO and ISO-NE present at the conferences stated that they have considered ways to change the schedule of the day-ahead unit commitment process to better coincide with the gas timely nomination cycle. For example, ISO-NE is considering moving up the timeline for day-ahead unit commitment and the resource adequacy assessment process in an effort to provide additional time to gas-fired generators to procure gas supplies and transportation services so that adequate generation capacity is available in real time.56 However, it was pointed out by several participants at the conference that one disadvantage of moving the day-ahead unit commitment timeframes closer in time to the gas Timely Nomination Cycle and therefore, further from the real time, is that electric load forecasts become less accurate. Some conference participants also indicated that one reason it has been difficult to change the day-ahead unit commitment process is the absence of a standardized electric schedule across markets, similar to the standardized gas day.
A related scheduling issue raised by conference participants involved the service priorities for transportation services offered by interstate pipelines and the “no-bump” rule.57 As noted above, primary and secondary nominations cannot bump already scheduled interruptible service during the final Intra-day 2 cycle, which is at 5 p.m. CCT.58 Discussion at some of the technical conferences indicated that the general consensus supporting the no-bump rule may no longer exist. Some generators with firm pipeline service stated that they would like to see additional nomination opportunities and in some cases, elimination of the no-bump rule. They contended that the current gas nomination cycles do not provide sufficient flexibility to generators facing weather-driven electric load variations, and the no-bump rule impedes their ability to use their firm service flexibly. However, other firm gas shippers, such as industrial users in the Southeast, argued in favor of retaining the no-bump rule. They stated that elimination of
the no-bump rule could cause fewer shippers to use interruptible transportation, resulting in lower overall utilization of pipeline capacity and a greater share of fixed costs allocated to firm shippers.
As noted by many conference participants, prior efforts of NAESB participants did not reach consensus on the creation of a unified gas and electric timeline,59 revisions to the gas nomination schedule to permit additional intra-day changes, or elimination of the no-bump rule. Several participants maintained that these changes were not a high priority and accordingly, should not be a priority for the Commission. To the extent changes are made, most conference participants agreed that these issues are interrelated and cannot be considered in isolation, and that any changes would need to be implemented in a way that makes sense for both industries from both regional and national perspectives.
Staff believes that further discussion is necessary to explore whether coordinated refinements to gas and electric scheduling rules are appropriate. Existing Commission policies and regulations provide a certain degree of flexibility in the near term for utilities to address coordinated scheduling issues on a regional basis and for pipelines to provide enhanced scheduling. As noted above, several RTOs/ISOs are considering or have refined their market practices and some pipelines have modified services and nomination cycles to meet the needs their customers. These efforts improve operations across both the gas and electric industries and should continue to be pursued. However, they do not address whether industry-wide changes would be appropriate to improve the longer-term harmonization of gas and electric operations. Taking a broader view of gas-electric scheduling issues could lead to greater operational efficiencies in both industries.
To that end, staff will continue to engage industry on gas and electric scheduling issues, including the effect of the Commission’s no-bump rule. During this outreach, staff will monitor the progress being made on the following activities highlighted by conference participants:
ISO-NE’s consideration of moving the timeline for its day-ahead unit commitment and resource adequacy assessment process and allowance of bid adjustments and hourly re-offers;
NYISO’s consideration of moving releasing day-ahead dispatch results to early than 10 AM (EST), when gas markets are more liquid; and,
The ability of natural gas pipelines to offer additional nomination opportunities after 5 PM or provide for electronic scheduling that could be completed faster than the current four hour processing time.
Progress on these nearer-term activities may facilitate greater coordination between the gas and electric markets while longer-term initiatives are being evaluated.
Capacity Release
In many regions, natural gas LDCs contract for firm long-term pipeline service based on their winter peak demand. Consequently, those LDCs generally have excess natural gas transportation capacity in the summer when gas demand is lower. In contrast, gas-fired electric generation in most, but not all, regions experience demand peaks in the summer time when LDC use of pipeline capacity is relatively low.60 As a result, gas-fired generators have generally been able to utilize released pipeline capacity from the LDCs to meet their gas delivery needs.61
As the relative amount of gas-fired generation increases, some contend that in the future these dynamics will no longer hold true. Gas-fired generation has increased to an extent that some pipelines are operating at increasing load factors, with diminishing availability of capacity to serve new gas-fired generation needs. For example, in New England, which experiences relatively high winter electric demand, gas-fired generators are increasingly competing with LDCs for pipeline capacity.
In response to these concerns, participants at every technical conference expressed a desire for more flexible capacity release on pipelines. Issues raised included a desire for more opportunities for intra-day releases and short-term or even hourly releases, enhanced ability to facilitate pre-arranged bilateral release deals, and more streamlined processing of capacity release transactions. In some cases, technical conference participants discussed “gas demand response,” but did not specify what that meant or how it could be implemented on the gas pipelines. In at least one case, a large generator with firm gas contracts suggested that more transparency regarding how pipelines analyze their systems to determine available pipeline capacity would be desirable.
The Commission’s current pipeline capacity release program is designed to permit expeditious and flexible releases.62 A firm shipper (releasing shipper) sells its capacity
by returning its capacity to the pipeline for reassignment to the buyer (replacement shipper).63 Released capacity is offered for bid on the pipeline’s website and awarded to the highest bidder. Firm shippers may also enter into a pre-arranged release directly with a replacement shipper. If the prearranged release is for a term of one month or less it need not be posted for bidding. The replacement shipper may pay less than the pipeline’s maximum tariff rate, but not more for releases that are long term in nature. Short term releases, those for one year or less, are not subject to price limitations tied to a pipeline’s maximum tariff rate.64 Many pipelines also permit replacement shippers to prequalify for releases, which expedites the assignment of capacity.
With respect to the flexibility of releases, the regulations provide that releasing shippers can release capacity at any time and that “pipelines must permit shippers acquiring released capacity to submit a nomination at the earliest available nomination opportunity after the acquisition of capacity.”65 Under the regulations, the pipelines must process these releases in one hour. As a consequence of the Commission’s posting and bidding rules, an LDC and a generator, for example, could negotiate a short term release at a market-determined rate at any nomination cycle permitted by the pipeline, including releases during the intra-day process.66 In addition to capacity release, shippers can make bundled gas sales to third-parties.67
The Commission’s capacity release regulations, including the NAESB WGQ standards, therefore provide shippers with considerable flexibility to acquire released capacity or obtain gas on a timely basis. However, the implementation of a capacity release remains subject to the scheduling opportunities available. As a result, it may be
that the concerns expressed by conference participants are driven more by the desire for greater pipeline scheduling flexibilities, or by an unwillingness of firm transportation contract holders to release capacity, than the Commission’s capacity release rules. Staff notes that no specific reforms in the area of capacity release were suggested by conference participants, nor was the relationship between capacity release and underlying pipeline scheduling opportunities generally discussed. Nonetheless, given the significant number of conference participants that raised capacity release rules as an issue to be address, staff believes is it necessary to continue to engage industry with respect to this issue.
0 comments: