# Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2015-09275 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** April 24, 2015 - **Citation:** 80 FR 23198 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 284 [Docket No. RM14-2-000; Order No. 809] Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities AGENCY: Federal Energy Regulatory Commission. ACTION: Final rule. SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission (Commission) is revising its regulations to better coordinate the scheduling of wholesale natural gas and electricity markets in light of increased reliance on natural gas for electric generation, as well as to provide additional scheduling flexibility to all shippers on interstate natural gas pipelines. The revised regulations in this Final Rule modify the scheduling practices used by interstate pipelines to schedule natural gas transportation service and provide additional contracting flexibility to firm natural gas transportation customers through the use of multi-party transportation contracts. The revisions in this Final Rule, together with the Commission's action in certain related proceedings, will better ensure the reliable and efficient operation of both the interstate natural gas pipeline and electricity systems. DATES: This rule will become effective July 8, 2015. The incorporation by reference of certain publications listed in this rule is approved by the Director of the Federal Register as of July 8, 2015. FOR FURTHER INFORMATION CONTACT: Anna Fernandez (Legal Information), Federal Energy Regulatory Commission, Office of the General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502-6682. Caroline Daly Wozniak (Technical Information), Federal Energy Regulatory Commission, Office of Energy Policy and Innovation, 888 First Street NE., Washington, DC 20426, (202) 502-8931. SUPPLEMENTARY INFORMATION: ORDER NO. 809 FINAL RULE Table Of Contents Paragraph numbers I. Background 4. A. Notice of Proposed Rulemaking 12. B. NAESB 17. C. Subsequent Developments 21. II. Discussion 23. III. Gas Day 26. A. NOPR Proposal 26. B. NOPR Comments 28. C. Data Request and ISO and RTO Responses 49. D. Comments on Data Request 61. E. Commission Determination 62. IV. Natural Gas Transportation Nomination Timeline 71. A. Background 71. B. Natural Gas Transportation Day-Ahead Cycles 75. 1. NOPR Proposal 78. 2. Revised NAESB Day-Ahead Nomination Cycles 82. 3. NOPR Comments 84. 4. Commission Determination 87. C. Intraday Nomination Cycles 89. 1. NOPR Proposal 91. 2. NAESB's Revised Intraday Nomination Cycles 93. 3. Comments 94. 4. Commission Determination 104. V. DSPS Proposal 108. A. Background 108. B. DSPS's Proposed National Changes 111. 1. Comments 112. 2. Commission Determination 121. C. 1-Year Pilot Program 124. 1. Comments 125. 2. Commission Determination 127. VI. Multi-Party Transportation Contracts 128. A. Background 128. B. NOPR Proposal 130. C. Comments 133. D. Commission Determination 142. VII. Notice of Use of Voluntary Consensus Standards 149. VIII. Incorporation By Reference 150. IX. Information Collection Statement 153. X. Environmental Analysis 161. XI. Regulatory Flexibility Act Certification 162. XII. Implementation Schedule 165. A. Comments 165. B. Commission Determination 168. XIII. Document Availability 172. XIV. Effective Date and Congressional Notification 175. 1. In this Final Rule, the Federal Energy Regulatory Commission (Commission) revises Part 284 of the Commission's regulations relating to the scheduling of transportation service on interstate natural gas pipelines to better coordinate the scheduling practices of the wholesale natural gas and electric industries, as well as to provide additional scheduling flexibility to all shippers on interstate natural gas pipelines. The Final Rule changes the nationwide Timely Nomination Cycle nomination deadline for scheduling natural gas transportation from 11:30 a.m. Central Clock Time (CCT) to 1:00 p.m. CCT and revises the intraday nomination timeline, to include adding an additional intraday scheduling opportunity during the gas operating day (Gas Day). The Final Rule effectuates these changes by incorporating by reference into the Commission's regulations the standards developed and filed by the North American Energy Standards Board (NAESB). 1 The revised regulations in this Final Rule also provide additional contracting flexibility to firm natural gas transportation customers through the use of multi-party transportation contracts. 1 NAESB is accredited by the American National Standards Institute (ANSI) as an accredited standards organization. NAESB complies with ANSI's requirements that its procedures are open to materially affected entities and that the standards represent a reasonable consensus of the industry without domination by any single interest or interest category. 2. On March 20, 2014, the Commission instituted proceedings under section 206 of the Federal Power Act (FPA) 2 to ensure that each Independent System Operator's (ISO) and Regional Transmission Organization's (RTO) scheduling, particularly its day-ahead scheduling practices, correlate with any revisions to the natural gas scheduling practices ultimately adopted by the Commission in this Final Rule. The Section 206 Order provides that ninety days after publication of this Final Rule in the Federal Register each ISO and RTO is required to propose tariff revisions to coordinate its day-ahead market with the changes adopted herein or to show cause why its existing scheduling practices need not be changed. This Final Rule—together with actions already undertaken by the Commission in other dockets as discussed below, additional regional efforts underway by market participants and stakeholders, and any actions taken in the section 206 proceeding on ISO and RTO scheduling practices—is designed to better ensure the reliable and efficient operation of both the interstate natural gas pipeline and electricity systems. 2 California Independent System Operator Corp., et al, order initiating investigation into ISO/RTO scheduling practices and establishing paper hearing procedures, 146 FERC ¶ 61,202 (2014) (Section 206 Order). 3. However, for the reasons described below, the Commission declines to adopt the proposal to change the start of the Gas Day. It is not clear that requiring a change in the Gas Day start time would provide sufficient benefits to outweigh the operational and safety impacts and costs of making such a change. While the Commission declines to take action in this proceeding to change the start of the Gas Day on a nation-wide basis, we note that since the issuance of the NOPR in March 2014 both ISO-NE and PJM (the two regions that appear to be of the most concern) have recently undertaken operational and market actions to address the availability and performance of generators, including gas-fired generators, in their footprints. These and other regional efforts to address generator performance may result in natural gas-fired generators and other market participants in these regions taking actions to alleviate some of the electric industry fuel supply concerns underlying the Gas Day proposal in the NOPR. I. Background 4. The Commission's existing regulations incorporate by reference the interstate natural gas pipeline scheduling business practice standards of NAESB's Wholesale Gas Quadrant (WGQ). 3 NAESB is a consensus standards organization composed of representatives of all segments of the natural gas industry and the electric power industry. Since 1996, these standards have established nationwide timelines that the industry and the Commission have determined are necessary to establish a more efficient and integrated pipeline grid. 3 See 18 CFR 284.12(a) and (b) (2014). 5. The existing 24-hour operating day, or Gas Day, for interstate natural gas pipelines begins at 9:00 a.m. CCT and ends at 9:00 a.m. CCT the following day. All nominations for interstate natural gas pipeline transportation service are for a daily quantity to be transported over the 24-hour Gas Day. 4 The rate at which a shipper may use its contracted quantity on a given interstate pipeline, also known as a flow rate, is determined by the individual pipeline's tariff and the flexibility of that pipeline to permit shippers to use gas on other than a uniform hourly basis over the 24-hour Gas Day ( i.e., non-ratable flows). Except for special services, pipeline services are generally based on the assumption of uniform hourly flows over the Gas Day. 5 4 The NAESB WGQ standards refer to CCT which refers to the actual time in the Central Time Zone, reflecting Central Standard Time or Daylight Savings Time, whichever is applicable. 5 During much of the year, most interstate natural gas pipelines can accommodate significant variations in hourly flow rates. However, during high demand periods when pipeline capabilities are being fully utilized to provide firm transportation services, a pipeline may announce a critical notice period, where shippers are expected to stay in balance. Some pipelines also offer enhanced services that permit subscribing shippers more variable hourly flow rates. 6. The current NAESB WGQ standards establish four standard nomination periods ( i.e., periods during which a shipper can request transportation service under its contract) for a Gas Day. As summarized in Table 1 below, shippers have two nomination opportunities prior to the day of gas flow, the Timely Nomination Cycle and the Evening Nomination Cycle, and two opportunities to revise their nominations on the day of gas flow (Intraday 1 and Intraday 2). Individual pipelines may offer additional scheduling opportunities beyond the standard nomination cycles. 6 6 See, e.g., Texas Gas Transmission LLC, 137 FERC ¶ 61,093 (2011), order on compliance, 138 FERC ¶ 61,176 (2013) ( Texas Gas ); and Gulf South Pipeline Company LP, 141 FERC ¶ 61,262 (2012) ( Gulf South ). Table 1—Current NAESB Gas Nomination Cycles Nomination cycle Nomination deadline (CCT) Notification of schedule (CCT) Nomination effective (CCT) Bumping of IT Timely 11:30 a.m. 4:30 p.m. 9:00 a.m. Next Day N/A. Evening 6:00 p.m. 10:00 p.m. 9:00 a.m. Next Day Yes. Intraday 1 10:00 a.m. 2:00 p.m. 5:00 p.m. Current Day Yes. Intraday 2 5:00 p.m. 9:00 p.m. 9:00 p.m. Current Day No. 7. With respect to electric industry scheduling practices, the Commission has accepted regional variation in the development of scheduling practices in ISO and RTO electric markets, each of which has established its own scheduling timelines. For most electric utilities, the 24-hour operating day begins at 12:00 a.m. local time. The ISOs' and RTOs' practice of scheduling resources generally includes the commitment and dispatch of sufficient, deliverable generation to supply load in a reliable least cost manner, all based on generator availability and the transmission facilities that will be in service that day. To perform the unit commitment and dispatch processes used to develop daily resource schedules, each ISO and RTO has its own timeline for collecting supply offers from generators and expected demand from load serving entities on the day prior to the operating day. The ISOs and RTOs then run market algorithms that determine the least cost set of resources that can be used to serve the next day's load. Each ISO and RTO also performs a reliability unit commitment process to procure resources, in addition to those resources committed to serve the load bid into the day-ahead market, as necessary to meet the ISO's or RTO's own forecast of the next day's load or other system needs. Each ISO and RTO establishes its own timing for executing the day-ahead and reliability scheduling processes, including the times of day when bids and offers are due to the system operator, when the market and reliability processes are run, and when the results of the scheduling processes are made available to generators. 7 7 FERC, Operator-Initiated Commitments in RTO and ISO Markets, Docket No. AD14-14-000 (Dec. 2014), available at http://www.ferc.gov/legal/staff-reports/2014/AD14-14-operator-actions.pdf. 8. In non-ISO and RTO systems, the Commission's pro forma OATT specifies that firm interchange schedules need to be submitted by 10:00 a.m. day-ahead or a reasonable time that is generally accepted in the region and is consistently adhered to by the Transmission Provider. 8 8 Pro forma OATT section 13.8. Schedules for Non-Firm Point-To-Point Transmission Service must be submitted to the Transmission Provider no later than 2:00 p.m. of the day prior to commencement of such service. Pro forma OATT section 14.6. 9. Recent developments in the wholesale natural gas and electricity industries—particularly the organized electricity markets—signal that changes to the gas nomination schedule may be needed. 9 Reliance on natural gas as a fuel for electric generation has steadily increased in recent years. 10 This trend is expected to continue, resulting in greater interdependence between the natural gas and electric industries. 11 Several events over the last few years, such as the Southwest Cold Weather Event 12 and the extreme and sustained cold weather events in the eastern U.S. in January 2014, 13 show the crucial interrelationship between natural gas pipelines and electric transmission operators and underscore the need for improvements in the coordination of wholesale natural gas and electric markets. 9 The Commission is directing ISOs and RTOs to make corresponding changes in the Section 206 Order. 10 See, e.g., U.S. Energy Information Administration, Annual Energy Outlook 2014 with projections to 2040 at ES-4 (April 2014); North American Electric Reliability Corporation, 2014 Long-Term Reliability Assessment (November 2014) at 19. 11 See, e.g., U.S. Energy Information Administration, Annual Energy Outlook 2014 with projections to 2040 (April 2014) (Natural gas-fired generation is projected to overtake coal-fired generation for U.S. electricity generation by 2040. Natural gas' share of U.S. electricity generation is projected to increase from 30 percent in 2012 to 35 percent in 2040.); ICF Assessment of New England's Natural Gas Pipeline Capacity to Satisfy Short and Near-Term Electric Generation Needs: Phase II Final Report (November 20, 2014); North American Electric Reliability Corporation, 2014 Long-Term Reliability Assessment (November 2014) at 13. 12 See FERC/NERC, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, 2011 (2011), available at http://www.ferc.gov/legal/staff-reports/08-16-11-report.pdf. 13 The widespread and record low temperatures during January 2014 resulted in coincident record peak demand for natural gas throughout the Midwest, Northeast, Mid-Atlantic, and Southeast regions leading to constrained pipeline capacity and high natural gas prices. In addition, in February 2014, arctic temperatures limited the availability of natural gas to supply New Mexico and Southern California leading CAISO to issue a system alert and a request for consumers to reduce power demand around the system. CAISO invoked increasingly stringent measures throughout the day to move generation off natural gas, reduce demand, and maintain sufficient supply to meet firm load. See FERC Staff Presentation “Recent Weather Impacts on the Bulk Power System,” January 16, 2014, http://www.ferc.gov/CalendarFiles/20140116102908-A-4-Presentation.pdf. 10. Since early 2012, the Commission has conducted multiple technical conferences and requested comment on various aspects of gas-electric interdependence and coordination in order to better understand the interface between the electric and natural gas pipeline industries and identify areas for improved coordination. 14 In a report issued on November 15, 2012, Commission staff noted that natural gas and electric industry participants highlighted the need for greater alignment of natural gas and electric scheduling practices. 15 At the direction of the Commission, staff conducted an additional technical conference in April 2013 to specifically discuss natural gas and electric scheduling practices, including whether and how natural gas and electric industry scheduling practices could be harmonized in order to achieve more efficient scheduling practices for both industries. 16 14 See Coordination Between Natural Gas and Electricity Markets, Docket No. AD12-12-000 (Feb. 15, 2012), available at http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12893828. 15 Staff Report on Gas-Electric Coordination Technical Conferences, Docket No. AD12-12-000 (Nov. 15, 2012) (November Staff Report), available at http://elibrary.ferc.gov/idmws/File_List.asp. 16 Coordination between Natural Gas and Electricity Markets, Docket No. AD12-12-000 (Mar. 5, 2013) (Notice of Technical Conference), available at http://elibrary.ferc.gov/idmws/File_list.asp?document_id=14095482. 11. At the April 2013 conference, participants identified several areas in which the differences between the nationwide natural gas schedule and the regional electric schedules can affect the provision of reliable service and may create inefficiencies in scheduling that result in less cost effective use of resources. The participants identified three major issues. These included: (1) The difference between the standardized operating day of interstate natural gas pipelines and the operating days of electric utilities (including ISOs and RTOs); (2) the lack of coordination between the day-ahead process for nominating interstate natural gas pipeline transportation services and the day-ahead process for scheduling electric generators, particularly those in the ISOs and RTOs; and (3) the lack of intraday nomination opportunities on interstate natural gas pipelines, which limits the ability of gas-fired electric generators, as well as other shippers, to revise their nominations during the operating day. Several conference participants stressed that, due to the difficult policy questions involved, they would need Commission policy guidance before they would be able move forward on coordination of the natural gas and electric industries existing scheduling practices. A. Notice of Proposed Rulemaking 12. Based on the increased reliance on natural gas as a fuel for electric generation and in consideration of the discussions at the 2012-2013 technical conferences and filed comments, the Commission concluded that the concerns identified by the industries warranted further action. On March 20, 2014, the Commission issued the Notice of Proposed Rulemaking (NOPR or Proposed Rule) to address concerns with divergent interstate natural gas pipeline and wholesale electric utility scheduling practices, as well as concerns regarding the flexible and efficient use of pipeline capacity by natural gas-fired generators and other shippers. 17 17 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 79 FR 18223 (Apr. 1, 2014), FERC Stats. & Regs ¶ 32,700 (2014) (cross-referenced at 146 FERC ¶ 61,201 (2014)) (NOPR). 13. The NOPR proposed three changes to the nationwide natural gas scheduling practices: (1) Move the start of the Gas Day from 9:00 a.m. CCT to 4:00 a.m. CCT; (2) move the start of the first day-ahead gas nomination opportunity for pipeline scheduling (Timely Nomination Cycle) from the current 11:30 a.m. CCT to 1:00 p.m. CCT; 18 and (3) modify the current intraday nomination timeline to provide four intraday nomination cycles, instead of the existing two, to provide greater flexibility to all pipeline shippers. 18 The Commission did not propose any changes to the Evening Nomination Cycle. 14. The NOPR also proposed to require interstate natural gas pipelines to offer multi-party transportation contracts to provide multiple shippers the flexibility to share interstate pipeline capacity to serve complementary needs in an efficient manner, and the NOPR provided clarification of the Commission's no-bump policy with respect to any enhanced nomination opportunity proposed by a pipeline (beyond the standard nomination opportunities). 15. Recognizing that the natural gas and electricity industries were best positioned to work out the details of how changes in scheduling practices could most efficiently be made and implemented, the Commission provided the natural gas and electric industries, through NAESB, with a period of 180 days after publication of the NOPR in the Federal Register to reach consensus on any revisions to the Commission's proposals regarding the Gas Day and pipeline nomination timeline and either file consensus standards with the Commission or notify the Commission of the natural gas and electric industries' inability to reach consensus on any revisions to the Commission's proposals. Comments on NAESB's consensus standards, as well as comments on the Commission's proposals, were to be filed 240 days after publication of the NOPR in the Federal Register , or November 28, 2014. In the NOPR, the Commission stated that if the Commission were to adopt regulations that have not been approved by NAESB, it would expect NAESB to integrate the Commission's regulations into its standards within 90 days of the effective date of the final rule and to notify the Commission when the standards have been approved. 16. On the same day the NOPR was issued, the Commission issued two other orders, which, in conjunction with the NOPR, were designed to better ensure the reliable and efficient operation of both the interstate natural gas pipeline and electricity systems. In one order, the Commission instituted proceedings under section 206 of the Federal Power Act (FPA) 19 to ensure that each ISO's and RTO's scheduling practices, particularly its day-ahead scheduling practices, correlate with any revisions to the natural gas scheduling practices ultimately adopted by the Commission in the instant proceeding. 20 In the Section 206 Order, the Commission required each ISO and RTO within ninety days of the publication of a Final Rule in this proceeding to: (1) Make a filing that proposes tariff changes to adjust the time at which the results of its day-ahead energy market and reliability unit commitment process (or equivalent) are posted to a time that is sufficiently in advance of the Timely and Evening Nomination Cycles, respectively, to allow gas-fired generators to procure natural gas supply and pipeline transportation capacity to serve their obligations; or (2) show cause why such changes are not necessary. In the second order, the Commission instituted proceedings, under section 5 of the Natural Gas Act (NGA) 21 to examine whether interstate natural gas pipelines are providing notice of offers to purchase released pipeline capacity in accordance with section 284.8(d) of the Commission's regulations. 22 19 16 U.S.C. 824e (2012). 20 Section 206 Order, 146 FERC ¶ 61,202. 21 15 U.S.C. 717d. 22 Posting of Offers to Purchase Capacity, 146 FERC ¶ 61,203 (2014). See also 18 CFR 284.8(d) (2013). B. NAESB 17. Following issuance of the NOPR, NAESB reconvened the Gas Electric Harmonization (GEH) Forum as the platform for the gas and electric industries to consider the NOPR proposals, as well as to develop any consensus-based alternatives to the NOPR proposals. 23 The GEH Forum was tasked with developing a recommendation for consideration by the NAESB Board of Directors (Board). The GEH Forum and NAESB Board convened several meetings between April and June 2014 with nearly five hundred active participants and over seven-hundred participants monitoring the activity, representing all facets of the wholesale gas and wholesale electric markets. 24 23 The NAESB Board of Directors formally defined consensus of the GEH Forum as 67 percent affirmative vote of each of the wholesale gas and wholesale electric quadrants and 40 percent affirmative vote of each of the segments of the two quadrants. 24 NAESB June 18, 2014 Report at 11. 18. Four alternatives to the NOPR proposal were considered during the final GEH Forum meeting. 25 The day-ahead and intraday nomination cycles in each package were the same, 26 but the start of the Gas Day in each package was different. Disagreement over the start of the Gas Day prevented the GEH Forum from reaching consensus on any of the alternative proposals to the NOPR. 27 The GEH Forum was also unable to reach consensus on an alternative proposal that did not define the Gas Day, but contained the same day-ahead and intraday nomination schedule as the four alternative proposals. Several participants expressed concern that any alternative proposal would be incomplete without a Gas Day start time, and indicated that they could not support a package that did not include the start of the Gas Day. 28 25 Id. at 9. 26 Id. at 8. The nomination deadline for the Timely and Evening Nomination Cycles were the same as those proposed in the NOPR—1:00 p.m. CCT and 6:00 p.m. CCT, respectively. The modified NAESB standards proposed only three intraday nomination opportunities, instead of four as proposed in the NOPR. The nomination deadlines for Intraday 1, Intraday 2 and Intraday 3 would be at 10:00 a.m. (bump), 2:30 p.m. (bump), and 7:00 p.m. (no-bump), all CCT. 27 Id. at 9-10. 28 Id. 19. Despite the inability of the GEH Forum to reach consensus, the NAESB Board directed the WGQ to proceed with the development of standards related to the day-ahead and intraday nomination cycles given the broad agreement among industry participants on those issues. 29 Electric utilities could participate in the WGQ meetings, but only members of the WGQ were eligible to participate in the final vote ( i.e., Wholesale Electric Quadrant (WEQ) members that are not also members of the WGQ, such as the ISO and RTO segment, were ineligible to vote on the standards). 29 Id. at 10. 20. On June 18, 2014, NAESB filed a status report with the Commission. On September 29, 2014, NAESB filed a second report to supplement the June 18 report and to inform the Commission of the modifications to the NAESB WGQ Business Practice Standards that were developed at the direction of the NAESB Board. 30 The modified NAESB WGQ Business Practice Standards revise the nomination timeline to provide for three intraday nomination cycles in addition to the Timely and Evening Nomination Cycles. NAESB stated that nomination cycles are not dependent upon a specific start time to the Gas Day and are implementable with whichever time the Commission chooses as a start of the Gas Day. On November 26, 2014, NAESB filled another report to inform the Commission of the options the organization may pursue to respond to Commission action within the ninety-day deadline provided in the NOPR, if the Commission adopts regulations not approved by NAESB. 30 NAESB reports that, in total, there are modifications to twenty-three NAESB WGQ Business Practice Standards: The NAESB WGQ Nomination Related Standard Nos. 1.1.18, 1.2.4, 1.3.1, 1.3.2, 1.3.3, 1.3.4, 1.3.13, 1.3.14, 1.3.41, 1.3.42, 1.3.51, and 1.3.80, the NAESB WGQ Flowing Gas Related Standard Nos. 2.2.5, 2.3.5, and 2.3.21, the NAESB WGQ Quadrant Electronic Delivery Mechanism Related Standard No. 4.3.90, and the NAESB WGQ Capacity Release Related Standard Nos. 5.3.2, 5.3.44, 5.3.45, 5.3.48, 5.3.49, 5.3.53, and 5.3.54. NAESB states that, pursuant to the direction given by the NAESB Board of Directors, the NAESB WGQ Business Practice Standards are silent as to a start time of the Gas Day. Accordingly, references to the specific start time of the Gas Day in NAESB WGQ Standard No. 1.3.1 have been removed and replaced by the placeholder: [?]. Likewise, NAESB WGQ Standard No. 1.3.41 was revised to contain a generic reference to the start time of the Gas Day. NAESB states that, should the Commission identify a specific start time of the Gas Day, it will revise the language of the NAESB WGQ Business Practice Standards as necessary. NAESB WGQ Annual Plan Item 11c which modified the NAESB standards was approved by the NAESB WGQ Executive Committee and ratified by the NAESB membership on September 22, 2014. In addition, Minor Correction M14018 was applied to these standards effective October 10, 2014. C. Subsequent Developments 21. On October 15, 2014, the Commission issued a notice of NAESB's September 29 report. The notice provided that comments in response to the NOPR should address the alternate proposal submitted to NAESB by the Desert Southwest Pipeline Stakeholders during the formal comment period on the proposed modifications to the NAESB WGQ standards. 31 Comments on the NOPR were due on November 28, 2014. Seventy-five comments were filed. Comments were received from all sectors of both industries, including ISOs and RTOs, electric utilities, interstate natural gas pipelines, local distribution companies (LDC), producers, state regulators, electric generators, and other interested persons. 31 NAESB Sept. 29, 2014 Report at Appendix C. 22. On December 12, 2014, Commission staff requested data from each of the six jurisdictional ISOs and RTOs regarding their experience with the impact on reliable and efficient operations of natural gas-fired generators running out of their daily nomination of natural gas transportation service during the morning electric ramp, to the extent this occurs. California Independent System Operator Corporation (CAISO), ISO New England Inc. (ISO-NE), Midcontinent Independent System Operator, Inc. (MISO), New York Independent System Operator, Inc. (NYISO), PJM Interconnection, L.L.C. (PJM), and Southwest Power Pool, Inc. (SPP) each filed a response to the data request. On February 2, 2015, American Public Gas Association (APGA), Natural Gas Council, New England LDCs, 32 and the Enhanced Reliability Coalition 33 filed comments on the ISO and RTO responses. 32 New England LDCs include the following: Bay State Gas Company d/b/a/Columbia Gas of Massachusetts, The Berkshire Gas Company, Connecticut Natural Gas Corporation, Fitchburg Gas and Electric Light Company, City of Holyoke, Massachusetts Gas and Electric Department, City of Norwich, Department of Public Utilities, Liberty Utilities (EnergyNorth Natural Gas) Corp. d/b/a Liberty Utilities, Middleborough Gas & Electric Department, New England Natural Gas Company d/b/a Liberty Utilities, Northern Utilities, Inc., NSTAR Gas Company, The Southern Connecticut Gas Company, Westfield Gas & Electric Department and Yankee Gas Services Company. 33 The Enhanced Reliability Coalition represents the views of a wide variety of electric and gas industry companies located throughout the United States and Canada that provide services such as natural gas production, interstate and intrastate gas pipeline transportation, natural gas distribution, natural gas procurement for core and industrial customers, natural gas procurement for electric generation, natural gas storage, electric generation, electric transmission, natural gas and electricity marketers, retail electric service, competitive retail electric and natural gas service, and electric procurement for customers. II. Discussion 23. Based on the record developed in this proceeding, the Commission is taking final action to address certain natural gas and electric industry coordination challenges resulting from the divergent interstate natural gas pipeline and electric utility scheduling practices. The Commission is revising its regulations to incorporate by reference the modified NAESB WGQ Business Practice Standards, which revise the standard nomination timeline for interstate natural gas pipelines. 34 These changes will revise the most liquid nomination cycle for scheduling natural gas transportation, the nationwide day-ahead Timely Nomination Cycle, so that the nomination deadline will be 1:00 p.m. CCT rather than 11:30 a.m. CCT, and will include an additional intraday scheduling opportunity, as well as conforming other standards to these revisions. 35 The Commission is also revising its regulations to provide additional contracting flexibility to firm natural gas transportation customers through the use of multi-party transportation contracts. However, the Commission declines to adopt the NOPR proposal to move the start of the Gas Day. 34 NAESB's WGQ Annual Plan Item 11c and Minor Correction MC14018. 35 See Appendix. 24. The Commission expects that these changes will provide significant benefits to both the natural gas and electricity industries, and will improve coordination between the industries. Moving the Timely Nomination Cycle to an hour and a half later will allow electric transmission operators additional time to complete their day-ahead scheduling sufficiently before the Timely Nomination Cycle deadline, so that gas-fired generators receive electric market dispatch instructions prior to the deadline for acquiring pipeline capacity in the Timely Nomination Cycle. The vast majority of commenters from both the gas and electric industries support this change. This change is further complemented by NAESB's revised three intraday nomination cycles that will provide shippers with greater flexibility to revise their nominations to adjust to system conditions and changes to load during the Gas Day. The addition of an afternoon bumpable cycle, together with a later, evening no-bump cycle, should afford firm transportation shippers, particularly those in the western United States, more of an opportunity to revise nominations to take into account weather and load changes. The comments in this proceeding show that these nationwide changes are supported broadly across the natural gas and electric industries. 25. The Commission does not find a sufficient record at this time to revise the nationwide Gas Day start time as proposed in the NOPR. As discussed in more detail below, it is not clear that requiring a change in the Gas Day start time would provide sufficient benefits to outweigh the operational and safety impacts and costs of making such a change. The record developed here—including the comments received on the NOPR proposal and the data responses submitted by the ISOs and RTOs— suggests that the concerns underlying the proposal to change the Gas Day start time, to the extent they exist, are primarily regional in nature. As a result, we find that it is appropriate to allow the changes to the standard natural gas pipeline nomination timelines in this Final Rule, as well as changes to market rules and practices in the electric industry, to be implemented and evaluated without changing the nationwide Gas Day. While we will not revise the nationwide Gas Day in this proceeding, ongoing regional efforts to address electricity market reforms and fuel assurance, and the individual section 206 proceedings initiated by the Commission to review ISO and RTO day-ahead scheduling practices, provide opportunities to seek regional solutions to the concerns underlying the Gas Day proposal in the NOPR. III. Gas Day A. NOPR Proposal 26. In the NOPR, the Commission proposed to move the start of the Gas Day from 9:00 a.m. CCT to 4:00 a.m. CCT. The Commission expressed concern about the potential impact of the difference in start times of the natural gas and electric operating days on the reliable and efficient operation of electric transmission system and interstate natural gas pipelines. Specifically, the Commission identified two problems resulting from the natural gas and electric operating days beginning at different times. First, the electric operating day currently extends over two Gas Days. Therefore, gas-fired generators committed across a single electric operating day must procure gas supply and schedule gas transportation across two Gas Days. Second, the current 9:00 a.m. CCT start of the Gas Day occurs in the middle of the morning electric load ramp in some regions, creating a situation where electric load is increasing at the same time natural gas-fired generators may be running out of their daily nomination of natural gas transportation service. 27. The Commission proposed to move the start of the Gas Day earlier, to 4:00 a.m. CCT, to address concerns expressed by several commenters—such as ISO-NE and NYISO—that the current Gas Day start time presents operational challenges resulting in gas-fired generators running out of scheduled natural gas capacity during the morning electric ramp period, and having to wait until 9:00 a.m. CCT before being able to rely on their next day gas nomination. The Commission stated that this change would mean that generators in all regions would be able to approach the morning electric peak, as well as most of the morning ramp period, with new daily gas nominations and, therefore, the proposal should largely eliminate the concern that some gas-fired generators will be unable to run during a substantial part of the morning electric ramp period because they have burned through their nominated gas before the start of the next Gas Day. B. NOPR Comments 28. Thirteen commenters, particularly electric industry participants, filed comments in support of the Commission's proposal to move the start of the Gas Day to 4:00 a.m. CCT. 36 These commenters argue that, currently, operational problems and logistical challenges result from the electric operating day extending over two Gas Days and the fact that the current 9:00 a.m. CCT Gas Day splits the morning electric load ramp into two Gas Days. 37 Southern Company explains that under the current 9:00 a.m. CCT Gas Day, sharp early morning ramps in the winter take place at the end of the Gas Day resulting in gas-fired generators' hourly gas usage markedly increasing over the last eight hours of the Gas Day. 38 According to Southern Company, because of this timing its system operators' option for ensuring sufficient fuel to meet the requirements of the morning ramp is limited to holding back consumption during the prior evening peak. 39 36 ACES Comments at 7; AECI Comments at 3; Ameren Comments at 2; Calpine Comments at 10; Con Edison Comments at 5; EquiPower Comments at 8; Exelon Comments at 7; First Energy Comments at 3; IRC Comments at 2; ISO-NE Comments at 2; NESCOE Comments at 2; PUCO Comments at 4; Southern Companies at 6. 37 Calpine Comments at 10-11; Essential Power Comments at 3; IRC Comments at 3; ISO-NE Comments at 3-4; PUCO Comments at 4. 38 Southern Company provides as an example a supplier who, on January 7 to January 8, 2014 increased gas use on a major pipeline from less than 40,000 MMBtu in hour 16 to nearly 50,000 MMBtu in hour 23. Southern Company Comments at 7. 39 Southern Company Comments at 7. 29. ISO-NE states that under the current 9:00 a.m. CCT Gas Day, the preceding Gas Day ends—with supplies and daily transportation quantities from that preceding day potentially running short—just when gas-fired generation is critically needed to ensure that electricity supply is available to match demand during the morning electric load ramp. 40 IRC states that generators could exhaust gas supply by incorrectly anticipating their next day electric schedule, or by operating differently in real-time than anticipated when nominating day-ahead gas supplies. 41 40 ISO-NE Comments at 3-4. 41 IRC argues that while earlier postings of ISO and RTO day-ahead market results may help generators know the amount of gas to nominate to meet their electric commitments, posting day-ahead electric market results earlier does not solve the concern about generators nominating gas across two different electric days. IRC Comments at 3. 30. Some commenters state that moving the Gas Day to 4:00 a.m. CCT or earlier would be helpful to owners of gas-fired resources by allowing them to nominate and schedule their fuel and transportation requirements in the day-ahead Timely Nomination Cycle—the most liquid cycle—to cover the morning electric ramp and the evening peak of a single electric day while also being able to make adjustments throughout the day in the intraday cycles. 42 IRC and ISO-NE state that planning for and including the entire morning electric ramp in the initial Gas Day operating plan is inherently more reliable to serve electric load requirements. 43 ISO-NE states that moving the start of the Gas Day earlier should address instances when gas-fired generators find they are running out of scheduled natural gas capacity during the morning ramp period and have to wait until the 9:00 a.m. CCT start of the Gas Day to obtain additional supply or transportation. 44 Equipower and Con Edison state that changing the start of the Gas Day will benefit system reliability in that generators exhausting their gas supply prior to the end of the Gas Day will do so during the middle of the night, when both the gas and electric systems are in a relatively low-load, steady-state condition and electric system operators have more flexibility to increase output from slow-ramping units, instead of during the morning ramping hours. 45 Southern Company explains that with the start of the Gas Day moved to 4:00 a.m. CCT, operators can eliminate five hours of significant gas burn from the latter half of the preceding Gas Day and shift the steepest part of the morning ramp into the beginning of the next Gas Day when operators have the most flexibility to address their needs by adjusting gas scheduling and/or generation for the remaining hours. 46 This shift would eliminate the current problem of system operators holding back gas consumption during the evening peak because of the morning electric ramp. 47 42 ACES Comments at 7; AECI Comments at 3; Ameren Comments at 5; Calpine Comments at 11-12; IRC Comments at 2; ISO-NE Comments at 4. 43 IRC Comments at 3; ISO-NE Comments at 5. 44 ISO-NE Comments Brandien Testimony at 4. 45 Equipower Comments at 8-9; Con Edison Comments at 7. 46 Southern Company Comments at 8. 47 Id. 31. ISO-NE states that the current Gas Day start time also straddles a time of peak gas demand for other pipeline shippers, such as LDCs, which further inhibits the ability to procure gas during the morning ramp. 48 Con Edison asserts that, on the natural gas side, a 4:00 a.m. CCT start of the Gas Day would avoid virtually all of the natural gas ramping period. According to Con Edison, this would allow natural gas system operators time to respond before loads reach their peak by, for example, shifting receipts among gate stations and/or utilizing on-system storage if there is an event on its system. 49 Furthermore, Con Edison states that forecast deviations should also be reduced if a 4:00 a.m. CCT start of the Gas Day is approved because it would minimize the time between when natural gas is purchased and nominated and when it is consumed. 50 48 ISO-NE Comment at 4. 49 Con Edison Comments at 7-8. 50 Id. at 8-9. 32. Thirty-five commenters, particularly natural gas industry participants, support the retention of the current 9:00 a.m. CCT Gas Day and oppose the Commission's proposal to move the start of the Gas Day to 4:00 a.m. CCT. 51 51 AF&PA Comments at 9; AGA Comments at 24; ANGA Comments at 2; American Public Gas Association Comments at 2; BHE Comments at 3; Castex Comments at 5; CenterPoint Energy Comments at 4; CPG Comments at 6; DCP Comments at 2; Direct Energy Comments at 2; Dominion Comments at 3; DTE Gas Comments at 3; Enhanced Reliability Coalition Comments at 5; Gas Processors Association Comments at 1; GRS Comments at 2; INGAA Comments at 13; IOGA Comments at 1; IPAA Comments at 2; Kinder Morgan Comments at 8; MSGC Comments at 11; National Grid Comments at 1; Natural Gas Council Comments at 2; New England LDCs Comments at 3; NiSource Comments at 2; NorthWestern Energy Comments at 3; Northwest Gas Association et al. at 1; NGSA Comments at 4; Northern Municipal Distributors/Midwest Region Gas Task Force Comments at 6; NW Industrial Gas Users Comments at 3; PG&E Comments at 2; Southwest IS Comments at 4; Southern Star Comments at 6; Texas Pipeline Association Comments at 1; WBI Energy Comments at 5; XES Comments at 5. 33. INGAA and Direct Energy contend that generator de-rates may have a number of causes unrelated to the Gas Day start time such as a nomination made based on an estimate of needs or a change in the ISO's or RTO's request for generation. 52 Numerous commenters also argue that it is highly uncertain that a 4:00 a.m. CCT Gas Day would increase electric reliability and that the speculative benefits of such a change appear limited. 53 52 INGAA Comments at 16; Direct Energy Comments at n.10. 53 AGA Comments at 32; BHE Comments at 4; CPG Comments at 8; Dominion Comments at 17; Enhanced Reliability Coalition Comments at 20; Kinder Morgan Comments at 8; MSCG Comments at 11; New England LDCs Comments at 16; NGSA Comments at 5; NW Industrial Gas Users Comments at 6. 34. Many commenters state that an earlier start to the Gas Day will not create additional capacity on pipelines during peak demand conditions to meet large swings in generator demand nor will it solve critical pipeline capacity availability issues that some regions are experiencing, particularly on a long-term basis. 54 Several commenters emphasize that the problems involving gas-electric coordination identified in the NOPR exist primarily in New England, are generally isolated to a single customer class, and, therefore, urge regional changes to be implemented. 55 Dominion and IPAA state that the NOPR appears designed to address the problems identified by the electric market participants in the Northeast, but fails to take into account concerns in other regions of the country or the concerns of the gas industry as a whole. 56 54 BHE Comments at 8; CPG Comments at 8; Enhanced Reliability Coalition Comments at 20; INGAA Comments at 28; National Fuel Comments at 6; NGSA Comments at 5; NiSource Comments at 8; Southern Star Comments at 6; WBI Energy Comments at 7. 55 BHE Comments at 11-12; Dominion Comments at 17; Enhanced Reliability Coalition Comments at 10; IPAA Comments at 3; New England LDCs Comments at 13; NiSource Comments at 8; WBI Energy Comments at 7. 56 Dominion Comments at 24; IPAA Comments at 2-3; MSCG Comments at 11-12; NWIGU Comments at 3. 35. Numerous commenters raise concerns regarding the potential for adverse impacts on reliability and safety and the danger of increased operational risk to the natural gas industry resulting from a 4:00 a.m. CCT Gas Day, particularly in the west. 57 For example, AGA states that the vast natural gas infrastructure is, in many instances, unmanned and not supported electronically, thus often requiring the dispatch of personnel to remote worksites to make the necessary physical changes to maintain services and operations. 58 INGAA and NiSource explain that, despite the industry's move toward the use of automated systems such as supervisory control and data acquisition (SCADA), there are still numerous situations in which a pipeline needs to employ on-site field technicians to staff certain types of equipment to ensure safe and efficient facility operations and to make any necessary manual adjustments. 59 Commenters argue that changing the start of the Gas Day to 4:00 a.m. CCT may create operational and safety risks due to the increased need for field work along the gas supply chain during nighttime hours, particularly during emergency situations when bad weather may exacerbate the effects of darkness. 60 New England LDCs state that while LDCs would take additional precautions to mitigate the risk of employees undertaking tasks when it is fully dark, even with artificial lighting, the total light available is likely to be less than that provided by natural daylight and that electric power is not available in many places. 61 57 See e.g., AGA Comments at 29; American Public Gas Association Comments at 7 and 9; Castex Comments at 7; CPG Comments at 6; Dominion Comments at 22; Enhanced Reliability Coalition Comments at 10; Gas Processors Association Comments at 6; GRS Comments at 2-3; IPAA Comments at 2; National Grid Comments at 3; New England LDCs Comments at 14; Northwest Gas Association et al. Comments at 2; NW Industrial Gas Users Comments at 5; PG&E Comments at 2; Puget Comments at 8; Southern Star Comments at 6; Texas Pipeline Association Comments at 9; WBI Comments at 2. 58 AGA Comments at 31. 59 NiSource Comments at 7. 60 AGA Comments at 29; American Public Gas Association Comments at 7; CPG Comments at 7; GRS Comments at 3; INGAA Comments at 20; IOGA Comments at 4; National Grid Comments at 4; New England LDCs Comments at 4; NiSource Comments at 7; Northwest Gas Association et al. at 2; PG&E Comments at 3; Texas Pipeline Association Comments at 12. 61 New England LDCs further state it would not be economical to provide lighting other than truck lights and flash lights. New England LDCs Comments at 21. 36. Numerous commenters argue that a 4:00 a.m. CCT Gas Day would result in performing certain critical operations, which require complex and risky worker decision making, at a time when many operators may suffer from fatigue or lack of concentration. 62 Commenters state that this change would increase the risk of worker error, impaired reaction time, situational awareness, judgment, attention, memory and resulting accidents and injury to personnel due to fatigue from interrupted sleep cycles. 63 Commenters cite studies identifying serious and substantial pipeline safety risks due to human fatigue in the Control Room and providing recommendations to avoid critical decision making and communication between 2:00 a.m. and 6:00 a.m. local time. 64 62 CenterPoint Comments at 4; Enhanced Reliability Coalition Comments at 15; New England LDCs Comments at 4; NiSource Comments at 6; Northwest Gas Association et al. Comments at 2; PG&E Comments 3-5; Texas Pipeline Association Comments at 12; WBI Comments at 7. 63 Dominion Comments at 22; INGAA Comments at 26-27; New England LDCs Comments at 22; Texas Pipeline Association Comments at 11-12. 64 AGA Comments at 31-32; Dominion Comments at 22; INGAA Comments at 26-27; New England LDCs Comments at 23; PG&E Comments at 3-4; Puget Comments at 8-9; Texas Pipeline Association Comments at 11-12. 37. AGA, New England LDCs, and CenterPoint contend that a flurry of significant activities occur approximately three hours before or at the start of the Gas Day 65 and that these activities would be difficult or costly to do if the Gas Day start time were moved to 4:00 a.m. CCT. 66 Commenters also state that, in providing reliable service, pipelines and LDCs are required to make manual changes to numerous facilities throughout the country prior to the start of every Gas Day to ensure delivery. 67 National Grid states that requiring these changes to occur at 4:00 a.m. CCT would place unnecessary operational and financial burdens on LDCs and could adversely affect their ability to prepare to meet morning natural gas load demands. 68 65 These activities include: Updating weather forecasts, forecasting demand from various customer groups (including gas-fired generators), forecasting interruptible service requirements, verifying volumes from interconnected pipelines, determining operational issues and notifications on interconnected pipelines, evaluating supply options, evaluating balancing needs, coordinating storage injections or withdrawals, planning for intraday gas flow changes, evaluating volume balancing needs of the current day, and adjusting peaking supply. 66 AGA Comments at 29; CenterPoint at n. 7; New England LDCs Comments at 21. 67 AGA states that a survey of LDCs revealed that nineteen out of fifty-three LDCs conduct manual operations hourly, and that another nineteen LDCs conduct manual operations daily. AGA Comments at 29 and 31. PG&E states that it has assessed its daily operations and concluded that annually, a minimum of 2,200 manual and 3,500 automated operating changes will shift to 4:00 a.m. (CCT), and thus during the night, rather than during the daylight hours, if the start of the Gas Day is changed. PG&E Comments at 3. See also DCP Comments at 3; Dominion Comments at 22; Enhanced Reliability Coalition Comments at 16; INGAA Comments at 24; National Grid Comments at 4; WBI Comments at 6. 68 National Grid Comments at 4. 38. Commenters note that requiring workers to travel in the dark is particularly problematic for facilities located in remote areas. 69 Some safety concerns associated with employees on roads in these early hours include: Decreased visibility, roads not yet cleared of ice or snow, decreased mental alertness of employees and other drivers, and increased animal activity on roads. 70 Thus, NGSA states that operational practicalities would create a need to delay field work until daylight hours when conditions are more conducive to a safe working environment. 71 69 Texas Pipeline Association Comments at 12; CPG Comments at 7; INGAA Comments at 22; IOGA Comments at 4; WBI Comments at 6; ERC Comments at 16; DCP Comments at 3; Texas Pipeline Association Comments at 13; NiSource Comments at 10. 70 CPG Comments at 7. 71 NGSA Comments at 12; INGAA Comments at 19. 39. Commenters state that the optimum time for packing the pipeline 72 is when customer demands are low and, therefore, pipelines and LDCs with pipeline operations currently use the late night and early morning hours to pack their systems in anticipation of the morning load. 73 Commenters state that, particularly in the west, the proposed Gas Day change would reduce the number of hours available to pack the pipeline, thus jeopardizing the ability of pipeline operators to pressurize their systems to meet peak morning natural gas demands. 74 72 Enhanced Reliability Coalition explains that pipelines generally accommodate the hourly differences in supply and demand through storage and the build-up of system inventory, that is, system packing, in which gas is accumulated within the pipeline system in order to meet the rapid outflows often needed by customers. Enhanced Reliability Coalition Comments at 7. 73 AGA Comments at 30-31; Dominion Comments at 20; Enhanced Reliability Coalition Comments at 7-8; Northwest Gas Association Comments at 2; PG&E Comments at 6. 74 Dominion Comments at 20; Enhanced Reliability Coalition Comments at 8-9; Northwest Gas Association Comments at 2; Puget Comments at 6. 40. Some commenters assert that moving the Gas Day earlier will also make it more difficult for gas industry participants to coordinate necessary activities. 75 INGAA and NGSA state that, given the number of transactions and operational assets involved in addressing issues that may arise near the beginning of the Gas Day, 76 and given the unbundled nature of the industry, daily coordination among industry participants is required to ensure the uninterrupted delivery of gas to those who need it. 77 75 INGAA Comments at 18-19; Natural Gas Council Comments at 9-10; NGSA Comments at 11-13. 76 For example, (1) there may be mismatches between nominations and actual gas receipts or deliveries, (2) gas may not come on-line as planned or expected, (3) equipment may malfunction, especially in cold weather, (4) not all equipment is automated, (5) gas flows may need to be redirected manually from one pipeline to another, and (6) maintenance projects may affect gas flows. 77 INGAA Comments at 18-19; Natural Gas Council Comments at 9-10. 41. NW Industrial Gas Users and New England LDCs argue that their regions rely on Canadian supplies and, since Canadian pipelines will not necessarily switch their Gas Day start time in response to a Commission ruling, mismatches at U.S./Canadian delivery points into U.S. pipelines could cause delays and/or interruptions in flows as well as operational difficulties for shippers scheduling gas deliveries using pipelines in both countries. 78 78 New England LDCs Comments at 23-24; NW Industrial Gas Users Comments at 4. 42. Enhanced Reliability Coalition and AF&PA state that if a 4:00 a.m. CCT Gas Day start is adopted, all of the hours of flow for gas nominated in the intraday cycles would be reduced by five hours, resulting in approximately a 25 to 45 percent reduction, depending on the cycle. 79 Commenters state that this change would eliminate the flexibility that the current intraday service provides and that shippers would face even greater difficulty in using intraday nomination cycles to adjust to unanticipated changes in demand or other unforeseen events that occurred after the Timely or Evening nomination cycles. 80 79 AF&PA Comments at 9-10; Enhanced Reliability Coalition Comments at 19. 80 AF&PA Comments at 9-10; Enhanced Reliability Coalition Comments at 20; MSCG Comments at 12-13. 43. Several commenters state that, under the current 9:00 a.m. CCT Gas Day, many pipelines provide an opportunity for shippers to submit “clean up” or “retro” nominations in the final hours of the current Gas Day in order to balance loads and reduce potential exposure to imbalance penalties. 81 Commenters assert that an unintended consequence of moving the Gas Day to 4:00 a.m. CCT is that pipelines may not be able to offer these enhanced balancing/clean-up services that provide flexibility to shippers, and these services could be more difficult for shippers to utilize and manage. 82 AGA and INGAA state that under a 4:00 a.m. CCT Gas Day model, it would be exceedingly difficult to replicate this type of business activity, and market liquidity, in the 1:00 a.m. CCT timeframe, since key decision-makers would not be on duty at that hour. 83 81 AGA Comments at 30; Calpine Comments at 14; CenterPoint Comments at n.7, INGAA Comments at 21; Natural Gas Council Comments at 10; NiSource Comments at 6-7; Puget Comments at 8; Spectra Comments at 4. 82 AGA Comments at 30; Calpine Comments at 15; Enhanced Reliability Coalition Comments at 14; INGAA Comments at 21; Natural Gas Council Comments at 10; Spectra Comments at 4. 83 AGA Comments at 30; INGAA Comments at 23. 44. Some commenters state that there is a concern that non-jurisdictional entities may not adjust to a 4:00 a.m. CCT Gas Day and that a lack of action, or timely action, by some operators on the upstream portion of the natural gas delivery chain could occur for various reasons, such as concerns over costs of the change and worker safety at night, particularly during inclement weather. 84 Dominion and Enhanced Reliability Coalition assert that if gas suppliers and producers do not operate on the same Gas Day as pipelines, then pipelines may have difficulty obtaining necessary supplies and will need to manage swings with line pack and storage until producers make necessary changes, decreasing the pipeline's operating flexibility. 85 Texas Pipeline Association, Gas Processors Association, and INGAA state that this change would also require the modification and renegotiation of numerous non-jurisdictional contracts that specify a 9:00 a.m. CCT Gas Day. 86 84 Enhanced Reliability Coalition Comments at 11-12; Gas Processors Association Comments at 6-7; MSCG Comments at 12; NiSource Comments at 7; NW Industrial Gas Users Comments at 3-4; PG&E Comments at 6; Texas Pipeline Association Comments at 9. 85 Dominion Comments at 21; Enhanced Reliability Coalition Comments at 12. 86 Texas Pipeline Association Comments at 11; Gas Processors Association Comments at 9. 45. CenterPoint Energy, Northern Municipal Distributors/Midwest Region Gas Task Force, and New England LDCs assert that a 4:00 a.m. CCT Gas Day would negatively impact interruptible customers served by LDCs, including electric generation customers. 87 CenterPoint and Northern Municipal Distributors/Midwest Region Gas Task Force contend that shifting the Gas Day to 4:00 a.m. CCT would be difficult for these interruptible customers because they do not have employees available for a third overnight shift to accommodate late changes and would therefore have to discontinue use of gas earlier in the day. 88 CenterPoint states that this change may reduce reliability and jeopardize service to firm customers which could include electric generation customers. 89 87 CenterPoint Comments at 4-5; New England LDCs Comments at 19; Northern Municipal Distributors/Midwest Region Gas Task Force Comments at 11-12. 88 CenterPoint Comments at 4-5; Northern Municipal Distributors/Midwest Region Gas Task Force Comments at 11-12. 89 CenterPoint Comments at 4-5. 46. Essential Power urges the Commission to adopt a 12:00 a.m. Eastern Prevailing Time (EPT) Gas Day to align with the electric day and allow a generator to match its gas purchases and electric operation in the dispatch day. 90 If the Commission ultimately determines that an earlier start to the Gas Day is necessary, National Grid recommends moving the start to 12:00 a.m. CCT to align with the electricity operating day for most electric utilities. 91 MSCG, however, proposes that it would be most practical to implement a uniform operating day that requires electric system operators to adapt to the natural gas system's commercial practices and therefore, states the uniform day should start at a time later than 4:00 a.m. CCT. 92 AGA, Con Edison, Dominion, EPSA, ISO-NE., and National Fuel argue that the Commission should not consider other Gas Day start times between 4:00 a.m. and 9:00 a.m. CCT. 93 90 Essential Power Comments at 4. 91 National Grid Comments at 2. 92 MSCG Comments at 7. 93 AGA Comments at 25-26; Con Edison Comment at 9; Dominion Comments at 27-28; EPSA Comments at 8; ISO-NE Comments at 5; National Fuel Comments at 3. 47. Gas industry participants cite high cost as a key reason for opposing the Gas Day proposal. 94 A number of commenters discuss the information technology and staffing costs associated with the proposal including providing overtime compensation, hiring new employees to cover the earlier start to the Gas Day, retraining employees, and reprogramming SCADA systems. 95 Commenters provided a range of cost estimates for SCADA/IT modifications and staffing requirements, with some above $3 million. 96 Several commenters also discuss the costs of mitigating safety issues raised by moving the Gas Day to 4:00 a.m. CCT. 97 Dominion states that approximately $2.5 million will be required to modify tariffs and contracts. 98 MSCG and BHE estimate the overall cost of compliance with the NOPR changes, including the changes to the Gas Day, will be in the $5 million range for one jurisdictional interstate natural gas pipeline, which indicates the cost of compliance for all 166 interstate natural gas pipelines would far exceed the $7.5 million estimated in the NOPR. 99 94 See, e.g., AF&PA Comments at 9-10; AGA Comments at 27-28; American Public Gas Association Comments at 14-15; BHE Comments at 4 & 9-13; Center Point Comments at 4-6; Dominion Comments at 17, 20, 25-27; DTE Comments at 3; Northern Municipal Distributors/Midwest Region Gas Task Force Comments at 6; PG&E Comments at 7-8. 95 AGA Comments at 28; CenterPoint Comments at 4; NiSource Comments at 5; NWGA et al. Comments at 2; MSCG Comments at 16-17. 96 See, e.g., Dominion Comments at 26. Dominion states that a 4:00 a.m. CCT Gas Day will result in an estimated one-time cost of $3.8 million for modifications related to their SCADA system, electronic bulletin board, and information technology management system, and estimated on-going annual costs of $125,000. Dominion anticipates hiring one or two additional transportation analysts, with annual on-going costs of between $85,000 and $170,000. Additionally, Dominion anticipates one-time implementation costs of $2.5 million to modify existing tariffs and contracts, and $1.7 million to reprogram transportation, storage, production, and gathering meters. 97 Enhanced Reliability Coalition at 17. 98 Dominion Comments at 26. 99 BHE Comment at 10-11; MSCG Comments at 16-17. 48. Commenters also address the significant costs entities other than interstate natural gas pipelines will incur as a result of the Proposed Rule. 100 PG&E states that compliance with the Gas Day proposal will result in an estimated one-time implementation cost of between $2 and $3 million for the reprogramming of SCADA systems, metering devices, and information technology management systems, as well as estimated ongoing annual costs of $600,000 for additional nighttime field personnel, traders, schedulers, and other staff-related costs. 101 Puget states that aligning their operations with the Gas Day proposal would have an estimated one-time implementation cost of $300,000 for modifications related to their SCADA system, metering devices, and information technology management systems. 102 Downstream gas industry commenters ( e.g., LDCs) also caution that interstate pipelines will raise rates for pipeline transportation and storage services in order to recover the compliance costs of implementing the Gas Day proposal. 103 100 AGA Comments at 28; American Public Gas Association Comments at 7 and 14; New England LDCs Comments at 21-22; Producer Coalition Comments at 6; Puget Comments at 16-17. 101 PG&E Comments at 7-8. 102 Puget Comments at 8. 103 See, e.g., AF&PA Comments at 9; AGA Comments at 28; American Public Gas Association Comments at 15; BHE Comments at 11; IECA Comments at 5-6; INGAA Comments at 27; New England LDCs Comments at 25; MSCG Comments at 17; NiSource Comments at 5. C. Data Request and ISO and RTO Responses 49. On December 12, 2014, Commission staff requested data, for 2013 and 2014, from each of the six jurisdictional ISOs and RTOs regarding the impact on reliable and efficient operations of natural gas-fired generators running out of their daily nomination of natural gas transportation service during the morning electric ramp, to the extent this occurs. 50. In its response, CAISO states that it believes gas-fired generators in its balancing authority generally do not face problems securing sufficient fuel to meet the morning electric ramp under existing electric and gas market timelines. 104 CAISO was not able to locate any record of a gas-fired generator de-rating a unit during the hours of 3:00 a.m. and 9:00 a.m. CCT due to the generator exhausting its daily nomination of natural gas transportation service prior to the end of the Gas Day. CAISO states that it does not believe it has committed generation out of merit order in anticipation of natural gas-fired generators running out of their nominated gas transportation at the end of the Gas Day. 105 The data submitted by CAISO indicates that in 2013 and 2014 fuel-related gas-fired generator outages and de-rates during the morning electric ramp were about as common on average as fuel-related de-rates during the other hours of the operating day. 106 104 CAISO Data Response at 7-8. 105 Id. at 6. 106 See Tables 1 and 2 CAISO Data Response at 6. In 2013 and 2014, 17 percent to 33 percent of fuel related de-rates and outages occurred during the hours of 3:00 a.m. and 9:00 a.m. 51. MISO states that it has not experienced any significant impacts caused by generators running out of natural gas during the morning ramp. 107 MISO explains that its data of power plants' actual performance and equipment failures does not reflect if fuel-related outages were specifically due to generators having exhausted their daily nomination of natural gas transportation service prior to the end of the Gas Day. 108 MISO submitted data providing the numbers of natural gas-fired units reporting outages and de-rates with a cause related to fuel during each month of 2013 and January through September 2014. 109 In 2013, there were relatively few fuel-related gas-fired generator outages and de-rates. In January and February of 2014, MISO experienced far more fuel-related gas-fired generator outages and de-rates, however, no more than 20 percent of the de-rates occurred during the morning ramp period. In addition, MISO states that it has made many recent enhancements to improve transparency of fuel-related matters in the planning and operating horizons. 110 107 MISO Data Response at 1-3. 108 Id. 109 See Tables MISO Data Response at 2. 110 MISO states that these enhancements and initiatives include: (1) Conducting a Generator Winter Fuel Survey for Winter 2014/2015 to gain more transparency into MISO generators' approaches related to fuel procurement practices; (2) creating (in 2014) additional generator outage cause codes related to fuel in MISO's outage scheduling tool to provide greater operational awareness to MISO operators regarding fuel; (3) expanding the coordination field trial between MISO planning and operations staff and ANR and NNG pipeline staff to other pipelines; (4) a new overhead pipeline operations display in the control room; and (5) a new consolidated pipeline notice Web page. MISO Data Response at 5. 52. In its response, SPP states that it does not require generators to submit information related to their nominated gas transportation, therefore, SPP does not have information responsive to the request regarding de-rates due to gas-fired generators having exhausted their daily nomination of natural gas transportation service prior to the end of the Gas Day. SPP further states that it has not committed generation out of merit order in anticipation of natural gas-fired generators running out of nominated gas transportation. 111 The data submitted by SPP indicates that in 2013 and 2014 fuel related gas-fired generator outages and de-rates during the morning electric ramp were about as common on average as fuel-related de-rates during the other hours of the operating day. 112 111 SPP Data Response at 3. 112 See Tables 1 and 2 SPP January 14, 2015 Comments at Attachment No. 1. In 2013 and 2014, 16 percent to 38 percent of fuel related de-rates and outages occurred during the hours of 3:00 a.m. and 9:00 a.m. 53. ISO-NE., NYISO, and PJM provided supplemental data regarding gas-fired generator de-rates in 2013 and 2014 due to issues related to fuel limitations/availability. PJM and NYISO requested privileged treatment of certain data submitted in response to the data request. 54. ISO-NE provided, among other data, information on time periods when generators reported reductions ( i.e., de-rates) due to fuel limitations. ISO-NE states that during 2013 and 2014 there were 173 reported gas-fired generator de-rates due to fuel limitations and 67 of those were logged between 3:00 a.m. and 9:00 a.m. CCT. The morning de-rates affected forty-nine days. To see if generators were de-rating due to running out of gas, ISO-NE examined the reductions that ended when the new Gas Day began (9:00 a.m. CCT). 113 In 2013 and 2014, twenty gas-fired generator de-rates due to fuel limitations, over 14 days, had an identified ending time that coincided with the start of the next Gas Day at 9:00 a.m. CCT. While ISO-NE states that it does not know whether the de-rates occurred solely due to the exhaustion of natural gas pipeline nominations, given the 9:00 a.m. CCT ending time of the de-rates, ISO-NE believes this is likely the cause. ISO-NE further states that the issues related to the availability of gas-fired resources in New England are even more critical than the data provided shows and that the severity of these issues has been masked because system operators are required to take actions that diminish the frequency of generation outage impacts due to gas reductions. 114 113 While these data do not show specifically whether the generators exceeded their firm gas transportation schedule for the day, ISO-NE states that the data suggests that the de-rates likely resulted from the exhaustion of natural gas transportation service, because the generators were able to come back on line at the start of the new Gas Day. 114 ISO-NE Data Response at 1. Table 2—ISO-NE Gas-Fired Generator De-Rates Due to Fuel Limitations Year De-rates Total Morning ramp (3:00 a.m.-9:00 a.m. CCT) With end time of 9:00 a.m. CCT 2013 97 39 8 2014 76 28 12 Total 173 67 20 Source: ISO-NE Data Response at 2 and Attachment A. 55. PJM provided a summary of the outage notifications due to lack of fuel from natural gas-fired generators in 2013 and 2014 and non-confidential system conditions on the relevant interstate natural gas pipelines and LDCs. 115 According to PJM's data response, in 2013, 62 percent of the unique generators that reported lack of fuel outages are located behind an LDC. 116 PJM also reports that 54 percent of the generators reporting outages due to lack of fuel in 2014 are located behind an LDC. In 2014, 60 percent of the generator-reported lack of fuel outages occurred in January. The confidential data provided by PJM shows that the vast majority of fuel-related gas-fired generator de-rates in 2013, and a majority of the fuel-related gas-fired generator de-rates in 2014, were caused by a limited number of generating units. 115 See Table 3, PJM Data Response at 4. PJM notes that this information may not be complete, as this data is not information required by PJM. PJM collected these data from publicly available information. 116 A gas-fired generator may be limited in its ability to receive or take gas in instances when there are constraints on an LDC system, regardless of whether the gas-fired generator has sufficient remaining nominated quantities of interstate pipeline transportation. 56. NYISO states that it identified 13 generators committed in 2013 and 2014 via Supplemental Resource Evaluation 117 on days with de-rates greater than 225 MW in any given hour. NYISO states that given the times the Supplemental Resource Evaluations occurred, it is not clear that any of the Supplemental Resource Evaluations were issued in response to a generator de-rating due to having exhausted its daily nomination of natural gas transportation service prior to the end of the Gas Day. Instead, NYISO states the de-rates were more likely related to limitations on natural gas customers' ability to receive or take gas, such as Operational Flow Orders (OFO), which require gas customers to operate within tight tolerances, or generator specific issues that may, or may not, be related to the availability of gas supply. 118 117 NYISO Manual 12: Transmission and Dispatching Operations Manual Section 5.7.7 states “SRE shall only be used to address resource deficiencies; it shall not be used to reduce costs.” 118 NYISO Data Response at 6. 57. The confidential data submitted by NYISO shows the number of gas-fired generator de-rates and the amount of energy reduced generally decreased between 3:00 a.m. and 9:00 a.m. CCT. Specifically, over all of 2013 and all of 2014, the total (by hour) number of gas-fired generator de-rates related to fuel availability fell as the morning progressed (between hours ending at 4:00 a.m. CCT and 9:00 a.m. CCT). Similarly, over all of 2013 and all of 2014, the total (by hour) amount of energy reduced later in the morning was less than the early-morning reductions. If fuel related de-rates were caused by exhaustion of nominated natural gas transportation capacity, the impact of the de-rates would likely have been steady or worsening as more generating units ran out of gas as the morning progressed towards 9:00 a.m. CCT. 58. To provide another perspective on the overall impact on reliability of the gas-fired generator de-rates during the morning ramp, the Commission examined the monthly and hourly average values 119 of resulting energy reductions as a percentage of the available operating reserves. Commission staff analysis of the data response indicates that, in ISO-NE during 2013 and 2014, the energy reductions were minimal relative to the operating reserves available to ISO-NE at the time. 119 For example, the average of all of the 6:00 a.m. CCT de-rates in January. Table 3—Gas-Fired Generator Reductions (De-Rates) as a Percent of Available Operating Reserves in ISO-NE Hour beginning (CCT) All 2014 (%) All 2013 (%) Jan 2014 (%) Mar 2014 (%) Nov 14 (%) Jan 2013 (%) Feb 2013 (%) Mar 2013 (%) 3 a.m. 0.47 0.69 0.14 1.08 2.10 0.00 0.90 1.47 4 a.m. 0.39 0.49 0.14 0.69 2.11 0.00 0.53 0.83 5 a.m. 0.26 0.32 0.07 0.01 2.11 0.02 0.91 0.01 6 a.m. 0.29 0.48 0.17 0.18 2.11 0.16 1.38 0.06 7 a.m. 0.43 0.61 0.57 0.31 2.11 0.42 1.25 0.43 8 a.m. 0.55 0.70 0.57 0.47 2.11 0.61 1.00 0.92 59. In NYISO, during certain winter months, 120 Commission staff analysis of the data response indicates that the average hourly reductions were potentially significant relative to the operating reserves available to the NYISO, ranging up to 5.7 percent of reserves. For all other months of 2013 and 2014, the average hourly reductions in NYISO were less than one percent of the available operating reserves. 120 January 2013, December 2013, January 2014, and February 2014. Table 4—Gas-Fired Generator Reductions (De-Rates) as a Percent of Available Operating Reserves in NYISO Hour beginning (CT) All 2014 (%) All 2013 (%) Jan 2014 (%) Feb 2014 (%) Jan 2013 (%) Dec 2013 (%) 3:00 a.m. 1.6 2.1 3.7 1.9 3.4 6.1 4:00 a.m. 1.5 1.9 4.0 1.8 3.2 3.8 5:00 a.m. 1.7 2.1 3.8 2.2 3.5 4.9 6:00 a.m. 2.2 1.9 4.5 2.3 2.7 2.6 7:00 a.m. 3.2 2.0 5.4 2.3 2.7 3.1 8:00 a.m. 3.6 2.3 5.7 1.3 3.1 2.9 60. In PJM in the winter months of 2014, Commission staff analysis of the data response indicates that the average hourly reductions were large relative to the operating reserves available to the ISO at the time, ranging from 16.8 percent to 72.3 percent. The average hourly reductions in the winter months of 2013 were also significant relative to the operating reserves available to PJM, ranging from 5.6 percent to 10.1 percent. Table 5—Gas-Fired Generator Reductions (De-Rates) as a Percent of Available Operating Reserves in PJM Hour beginning (CCT) All 2014 (%) All 2013 (%) Jan 2014 (%) Feb 2014 (%) Mar 2014 (%) Jan 2013 (%) Feb 2013 (%) Mar 2013 (%) 3 a.m. 13.7 5.0 54.7 25.8 17.2 9.3 7.1 5.9 4 a.m. 13.1 5.0 50.5 25.5 16.8 9.5 7.0 5.6 5 a.m. 13.0 4.8 48.9 25.3 17.0 8.7 6.7 5.9 6 a.m. 15.1 5.1 60.6 27.9 19.5 8.9 7.0 6.7 7 a.m. 17.3 5.3 72.3 32.2 21.4 10.1 7.5 6.8 8 a.m. 17.1 5.2 72.1 30.8 21.1 9.7 7.4 6.5 D. Comments on Data Request 61. American Public Gas Association, New England LDCs, the Enhanced Reliability Coalition, and Natural Gas Council filed comments regarding the ISOs' and RTOs' data responses. These commenters argue that the ISOs' and RTOs' responses clearly confirm that there is not a nationwide problem during the morning electric ramp associated with the current start time of the Gas Day. 121 American Public Gas Association and Natural Gas Council contend that the data submitted by the ISOs and RTOs does not support the thesis that there is a causal link between the start of the Gas Day and the reliability of gas-fired generators. 122 The Enhanced Reliability Coalition points out that in 2014, many of the instances in which generators in PJM indicated an outage due to lack of fuel occurred during OFOs issued by pipelines and that, in these circumstances, a change to the start of the Gas Day would not have remedied the generator outages. 123 Natural Gas Council and New England LDCs state that the ISOs' and RTOs' responses fail to provide sufficient record evidence for the Commission to meet its burden under section 5 of the NGA that the current 9:00 a.m. CT Gas Day start time is no longer just and reasonable, and that a 4:00 a.m. CT start of the Gas Day is just and reasonable. 124 121 Natural Gas Council Feb. 2, 2015 Comments at 1-3. 122 American Public Gas Association Feb. 2, 2015 Comments at 3-4; Natural Gas Council Comments at 2. 123 Enhanced Reliability Coalition Feb. 2, 2015 Comments at 5. 124 Natural Gas Council Feb. 2, 2015 Comments at 8; New England LDCs Feb. 2, 2015 Comments at 3. E. Commission Determination 62. While certain efficiencies in scheduling could be achieved through better harmonization of the natural gas and electric operating days, the Commission concludes that the current record does not support changing the start time of the nationwide natural Gas Day at this time. 63. In the NOPR, the Commission expressed concern about the potential impact of the difference in start times of the natural gas and electric operating days on the reliable and efficient operation of electric transmission systems and interstate natural gas pipelines. In the NOPR, the Commission identified two problems resulting from the fact that the natural gas and electric operating days begin at different times. First, the electric operating day currently extends over two Gas Days. Therefore, natural gas-fired generators committed across a single electric operating day must procure gas supply and schedule gas transportation across two Gas Days. Second, the current 9:00 a.m. CCT start of the Gas Day occurs in the middle of the morning electric load ramp in some regions, creating a situation where electric load is increasing at the same time natural gas-fired generators may be running out of their daily nomination of natural gas transportation service. We find, based on the comments and data responses, that there is limited evidence to support the premise in the NOPR that the current start of the Gas Day results in natural gas-fired generators de-rating during the morning ramp due to exhausting nominated natural gas transportation. As described in comments, gas-fired generator de-rates may have a number of causes unrelated to the Gas Day start time, such as a nomination made based on only an estimate of needs (especially where the generator has not received a dispatch schedule from the system operator), an unscheduled change in an ISO's or RTO's real-time dispatch, or limitations on shippers' ability to receive or take gas, among others. 64. In addition, evidence in the record provided through the ISO and RTO data responses did not provide sufficient support for changing the nationwide Gas Day. The responses generally show that, to the extent gas-fired generators de-rating during the morning ramp is a significant problem, it appears to be isolated to the winter months in specific regions. 65. SPP, MISO, and CAISO all reported no issue with gas-fired generator de-rates during the morning ramp. While ISO-NE, PJM, and NYISO provided data suggesting that some de-rates during the morning ramp are due to fuel-related issues, the data did not show whether those de-rates are specifically due to gas-fired generators running out of their daily nomination of natural gas transportation service. None of the ISOs' or RTOs' outage management systems collect data containing the level of detail and specificity to reflect if generator output reductions ( i.e., de-rates) and outages were specifically due to natural gas-fired generators having exhausted their daily nomination of natural gas transportation. Rather, the ISOs and RTOs track de-rates and outages associated with the broad North American Electric Reliability Corporation (NERC) code for fuel-related issues which includes several other causes. Therefore, the Commission had to draw inferences based on the data submitted in the record. 66. The Commission concludes that there is limited evidence to support the NOPR proposal to change the Gas Day. For example, in ISO-NE very few gas-fired generator de-rates due to fuel limitations had an ending time that coincided with the start of the next Gas Day at 9:00 a.m. CCT in 2013 and 2014. In addition, in PJM, a majority of the fuel related gas-fired generator de-rates in 2014 and the vast majority of fuel-related gas-fired generator de-rates in 2013 were caused by a limited number of generating units. The Commission believes any conclusions that can be drawn from the PJM data are weakened by the idiosyncrasies of these units. Therefore, although gas-fired generator de-rates due to fuel limitations appear problematic in certain regions during certain times of the year, on balance, the Commission believes this does not warrant changing the nationwide Gas Day. 67. In addition, several commenters in this proceeding provide compelling arguments indicating that moving the nationwide Gas Day to 4:00 a.m. CCT will result in substantial nationwide costs and potential operational and safety impacts for the entire natural gas industry, including jurisdictional and non-jurisdictional entities. The natural gas industry has identified significant costs attendant on such a change, including the costs of hiring and retraining employees, providing overtime compensation, mitigating safety risks, modifying existing contracts, purchasing new equipment, and reprogramming SCADA systems, nomination software, and metering devices. The identified adverse operational and safety impacts include a potential for reduced nighttime hours to pack the pipeline, diminished opportunity for shippers to balance loads in the final hours of the Gas Day, increased need for field work during nighttime hours, and worker fatigue, among others. 68. Therefore, we find, based on the record, that there has not been a showing that the benefits of changing the nationwide Gas Day from 9:00 a.m. CCT to 4:00 a.m. CCT sufficiently outweigh the potential adverse operational and safety impacts on the natural gas industry to justify action under NGA section 5 to require a change in the start of the Gas Day. 69. While the Commission declines to take action in this proceeding to change the start of the Gas Day on a nation-wide basis, we note that since the issuance of the NOPR in March 2014 both ISO-NE and PJM (the two regions that appear to be of the most concern) have recently undertaken operational and market actions to address the availability and performance of generators, included gas-fired generators, in their footprints. 125 Beyond these measures, ISO-NE argues that the New England region needs its generating resources and other entities to make investments in firm fuel supplies and transportation, maintenance of on-site fuel inventory, and dual fuel capability. 126 ISO-NE states that it is implementing the Pay-for-Performance proposal accepted by the Commission to provide incentives for these investments. 127 Similarly, PJM is focusing on long-term procedural improvements in a recent Commission filing proposing a series of tariff reforms to ensure that resources committed as capacity to meet PJM's reliability needs are obligated to deliver energy and reserves when called upon. 128 These and other regional efforts to address generator performance may result in natural gas-fired generators and other market participants in these regions taking actions to alleviate some of the electric industry fuel supply concerns underlying the Gas Day proposal in the NOPR. 129 In addition, the Commission is taking a range of actions in this Final Rule, as discussed below, to better coordinate the scheduling of the natural gas and wholesale electricity markets as well as to provide additional scheduling flexibility to all shippers on interstate natural gas pipelines. 125 In ISO-NE these measures include changes to the ISO tariff to: (1) Allow for better information sharing with the interstate pipelines; (2) enhance offer flexibility; (3) accelerate the timelines in the Day-Ahead Energy Market; (4) increase the amount of reserves procured in the Forward Reserve Market; (5) enhance Forward Reserve Market incentives; (6) improve generator auditing; and (7) redefine Shortage Events in the Forward Capacity Market. Since January 2014 PJM has put into place a number of improvements to help ensure generator availability this winter including: (1) A process for generators to communicate any long-lead notification time they require to start in order to ensure fuel procurement; (2) a requirement for generators to ensure data accuracy for existing information provided to PJM; (3) a requirement for operational information to be submitted to PJM regarding dual fuel capability, availability, and operational restrictions; and (4) ability for generators, in certain circumstances, to update intraday cost schedules to more accurately reflect real-time the cost of fuel in their energy schedules. 126 ISO-NE Data Response at 7. 127 ISO New England Inc. and New England Power Pool, 147 FERC ¶ 61,172, order on compliance filing, 149 FERC ¶ 61,009 (2014). 128 On March 31, 2015 Commission staff requested additional information from PJM regarding PJM's proposal in Docket No. ER15-623-000. 129 In addition, the Commission recently issued an order directing each RTO and ISO to file reports on the status of its efforts to address fuel assurance issues. The Commission is currently reviewing the RTO and ISO reports and the comments submitted on those reports. Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators and Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations and Independent System Operators, order on technical conferences, 149 FERC ¶ 61,145 (2014). 70. In addition to these ongoing efforts, the individual ISO and RTO section 206 proceedings provide additional opportunities to seek regional solutions. As discussed further below, the 206 Order requires each ISO and RTO to adjust the time at which the results of its day-ahead energy market and reliability unit commitment process (or equivalent) are posted to a time that is sufficiently in advance of the Timely and Evening Nomination Cycles, respectively, to allow gas-fired generators to procure natural gas supply and pipeline transportation capacity to serve their obligations, or show cause why such changes are not necessary. In the Section 206 Order the Commission encouraged each ISO and RTO to consider whether other market reforms would be appropriate. 130 Such regional electric market changes to diminish the misalignment between the Gas Day and regional electric days may be less costly and result in far less negative operational impacts. 130 For example, RTOs and ISOs could consider the potential benefits, cost, and operational burdens of adjusting the timing of their operating day. Section 206 Order, 146 FERC ¶ 61,202 at P 19 & n.14 (“In addition, we encourage RTOs and ISOs to consider whether other market reforms would be appropriate.”). IV. Natural Gas Transportation Nomination Timeline A. Background 71. In addition to the industries having different start times to their operating days, the natural gas and electric industries operate on different schedules within those days. As described above, and as shown in Table 1 above, under the current NAESB WGQ Standard 1.3.2 and the Commission's regulations, 131 natural gas pipelines must offer pipeline shippers a minimum of four nomination opportunities to schedule natural gas transportation. Shippers have two nomination opportunities prior to the day of gas flow, the Timely Nomination Cycle and the Evening Nomination Cycle, and two nomination opportunities on the day of gas flow (Intraday 1 and Intraday 2). Changes to a shipper's nominations are limited by the remainder of a shipper's daily quantity and the remaining hours of the Gas Day. 132 131 18 CFR 284.12 (2014). 132 For example, if a shipper with a contract for 2,400 Dth/day, schedules 1,200 Dth at the Timely Nomination Cycle, and submits an intraday nomination at the Intra-Day 1 Cycle, that shipper can increase its scheduled capacity, assuming capacity availability, by no more than 1,600 Dth, bringing its total scheduled quantity to 2,000 Dth/day. This occurs because the shipper has already operated for eight hours based on a daily nomination of 1,200 Dth (50 Dth/hour). (8 hrs * 50 = 400 Dth). This leaves the shipper only 16 hours to increase its flow rate to 100 Dth/hr, bringing its total daily quantity to 2,000 Dth (400 Dth for the first 8 hours + 1,600 for the remaining 16 hours). 72. Interstate natural gas pipelines schedule their systems based on the priority of the transportation contract held by the shipper. Nominations of firm transportation from a primary receipt point to a primary delivery point (primary firm nominations) have the highest priority, 133 followed by secondary firm, within-the-path 134 nominations, secondary firm, outside of the path nominations, and finally nominations from shippers holding interruptible transportation capacity. Before a pipeline schedules a shipper's requested quantity under these standards, the pipeline confirms the shipper's nomination with upstream and downstream entities to make sure the shipper has contracted for sufficient gas with an upstream supplier to fulfill its nomination and to ensure the downstream entity, such as a LDC, has sufficient capacity to accept that gas. 133 A firm shipper's primary receipt and delivery points are listed in its service agreement and define the guaranteed firm transportation service the pipeline has contracted to provide that shipper. The Commission also requires pipelines to permit shippers to use all other points in the rate zones for which they pay on a secondary firm basis. 134 Secondary firm nominations are firm nominations that include at least one secondary point. Within-the-path nominations are nominations where the nominated secondary receipt and/or delivery point is contained wholly within the primary points listed in the shipper's contract. 73. The Timely Nomination Cycle is the most liquid time to acquire both natural gas supply and transportation capacity. During the Timely Nomination Cycle, all of the pipeline's nomination priorities are in effect: Primary firm nominations have priority over secondary firm nominations, and secondary firm nominations have priority over interruptible transportation. In subsequent nomination cycles, firm service, including secondary firm service, scheduled in an earlier cycle cannot be displaced or bumped by another firm nomination for that Gas Day. 135 In addition, firm intraday nominations, including secondary firm nominations, have priority over, and thus can displace or bump, scheduled and flowing interruptible transportation. 136 This policy recognizes that “firm shippers are paying reservation charges for priority rights and those rights should include the right to have a nomination become effective as early as possible on the Gas Day following the nomination.” 137 However, the final intraday nomination (Intraday 2) cycle is a “no-bump” cycle, meaning that interruptible transportation previously arranged for cannot be displaced or bumped by a firm Intraday 2 nomination. In approving this arrangement (referred to as the “No-Bump Rule”), the Commission found that it would create a fair balance between firm and interruptible shippers and provide necessary stability in the nomination system. 135 Transwestern Pipeline Company, 99 FERC ¶ 61,356, at P 12 (2002) (“the Commission's long standing policy on firm service is that once scheduled, whether at primary or alternate points, the service may not be bumped by a nomination by another firm shipper”). 136 18 CFR 284.12(b)(1)(i) (2014); Standards for Business Practices of Interstate Natural Gas Pipelines, Order No. 587-G, 63 FR 20072 (Apr. 16, 1998), FERC Stats. & Regs., Regulations Preamble 1996-2000 ¶ 31,062, at 30,672 (1998). 137 Id. at 30,671. 74. Individual pipelines may offer additional scheduling opportunities beyond the standard nomination cycles. However, shippers transporting gas over multiple pipeline systems may have limited ability to use these additional scheduling opportunities if the upstream or downstream pipelines cannot confirm those scheduling changes. Currently, several pipelines offer enhanced nomination services 138 and some pipelines permit more frequent nominations than the four required by the current NAESB standards. Even if additional nomination cycles are not detailed in the pipeline's tariff, some pipelines' tariffs provide that the pipeline will make best efforts to accommodate such incremental nominations throughout the day on a best efforts basis. 139 138 See, e.g., Texas Gas, 137 FERC ¶ 61,093, order on compliance, 138 FERC ¶ 61,176; Gulf South, 141 FERC ¶ 61,262. 139 See, e.g., Tennessee Gas Pipeline Company, LLC's Tariff, GT&C Section IV.2(e). B. Natural Gas Transportation Day-Ahead Cycles 75. The most liquid time to acquire natural gas supply for the next day occurs before the 11:30 a.m. CCT deadline for submitting nominations in the Timely Nomination Cycle. As a result, natural gas purchasers may have to pay a premium to obtain supply after the Timely Nomination Cycle, because there are fewer willing sellers later in the day. Also, it may be more difficult to obtain next-day firm transportation capacity after the Timely Nomination Cycle, because firm transactions scheduled in the Timely Nomination Cycle cannot be bumped in later nomination cycles and shippers may have already made capacity release arrangements for the next day. 140 After the Timely Nomination Cycle, the Evening Nomination Cycle, beginning at 6:00 p.m. CCT, offers the only standard opportunity to reschedule gas transportation for the next Gas Day. 140 The Commission's current capacity release program allows a firm shipper to sell (or release) its capacity to another entity when it is not using it. The releasing shipper releases its capacity by returning its capacity to the pipeline for reassignment to the replacement shipper. The pipeline contracts with, and receives payment from, the replacement shipper and then issues a credit to the releasing shipper. The results of all releases are posted by the pipeline on its Internet Web site and made available through standardized, downloadable files. 76. Wholesale electricity markets operated by the ISOs and RTOs also use a day-ahead energy market to set contractual commitments for the next operating day. Market participants place day-ahead offers and bids to sell and purchase, and these participants must make such commitments prior to the close of the market. If the market clearing process accepts these commitments, they become binding for the following day. The following table shows for each ISO and RTO the deadline for submission of generator bids and the time the winning bids are posted by ISOs and RTOs in the day-ahead markets. As demonstrated by Table 6, all ISOs and RTOs (with the exception of NYISO) publicize accepted day-ahead dispatch bids after the current 11:30 a.m. CCT nomination deadline for the Timely Nomination Cycle. Table 6—Electric Commitment Results Publication Timetable ISO/RTO Time for submission of bids (CCT) Time for publication of day-ahead commitment bids (CCT) California Independent System Operator Corporation (CAISO) 12:00 p.m. 3:00 p.m. ISO New England Inc. (ISO-NE) 9:00 a.m. 12:30 p.m. PJM Interconnection, LLC (PJM) 11:00 a.m. 3:00 p.m. Midcontinent Independent System Operator, Inc. (MISO) 10:00 a.m. 2:00 p.m. New York Independent System Operator, Inc. (NYISO) 4:00 a.m. 10:00 a.m. Southwest Power Pool, Inc. (SPP) 11:00 a.m. 4:00 p.m. 77. Because day-ahead electric generation commitments generally occur after the natural gas transportation Timely Nomination Cycle, a natural gas-fired generator must either submit its nomination for natural gas transportation services before it knows when and how much electricity it will be committed to produce the next day, or it must wait until it receives its day-ahead commitment to nominate natural gas transportation services, with the risk that during some periods natural gas supply and transportation capacity may not be available or economical, given the ISO and RTO day-ahead market clearing price. 141 If a gas-fired generator acquires natural gas and transportation prior to learning whether it is dispatched, it runs the risk of having to sell off excess natural gas supply and pipeline transportation capacity during the less liquid Evening or intraday Nomination Cycles to the extent its bid does not clear the day-ahead market. 142 If the gas-fired generator waits to acquire natural gas supply and transportation until its bid clears the day-ahead market, it would be doing so during the less liquid Evening or intraday Nomination Cycles, where the generator may be unable to acquire transportation capacity if the pipeline is fully scheduled. While during many periods of the year, gas-fired generators may be able to obtain natural gas and interstate natural gas capacity throughout the day, their ability to procure natural gas and transportation in the most liquid Timely Nomination Cycle may be critical to their ability to provide service during periods when the pipeline is constrained. 141 A natural gas-fired generator also faces different risks depending on whether it enters into long-term natural gas purchase arrangements or relies on short-term spot market natural gas purchases. 142 See, e.g., Equipower Resources Corp. Comments, Docket No. AD12-12-000, at 3-4 (filed Mar. 30, 2012) (a generator that purchases capacity and gas during the timely cycle and is not dispatched “is forced to sell excess volumes or purchase the volume it is short in the intraday market. But the intraday market is highly illiquid and sometimes nonexistent, resulting in the generator: (1) Being exposed to imbalance penalties on the pipeline if it cannot find a market for excess gas; (2) being unable to operate its generator at expected output; (3) having to purchase additional supplies at a premium; or (4) having to sell excess supply at a discount”). 1. NOPR Proposal 78. The NOPR proposed to move the deadline for submitting nominations in the Timely Nomination Cycle from 11:30 a.m. CCT to 1:00 p.m. CCT to provide sufficient time for electric utilities to complete their processes for selecting day-ahead generating resources before the Timely Nomination Cycle. The NOPR did not propose any other changes to the Timely Nomination Cycle, including the existing 4:30 p.m. CCT deadline for the pipeline to provide notice of scheduled quantities. Thus, the NOPR proposed to shorten the time required to complete the Timely Nomination Cycle from five hours (11:30 a.m. CCT to 4:30 p.m. CCT) to three and one-half hours (1:00 p.m. CCT to 4:30 p.m. CCT). The NOPR did not propose any changes to the existing Evening Nomination Cycle, under which nominations must be submitted by 6:00 p.m. CCT, confirmations are completed by 9:00 p.m. CCT, and the pipeline notifies shippers of their scheduled quantities by 10:00 p.m. CCT. 79. In an order issued contemporaneously with the NOPR, the Commission instituted a proceeding under section 206 of the FPA requiring each ISO and RTO within ninety days after the publication of a Final Rule in this docket to: (1) Make a filing that proposes tariff changes to adjust the time at which the results of its day-ahead energy market and reliability unit commitment process (or equivalent) are posted to a time that is sufficiently in advance of the Timely and Evening Nomination Cycles, respectively, to allow gas-fired generators to procure natural gas supply and pipeline transportation capacity to serve their obligations; or (2) show cause why such changes are not necessary. 143 143 Section 206 Order, 146 FERC ¶ 61,202. 80. The NOPR proposed that moving the Timely Nomination Cycle to 1:00 p.m. CCT, along with examining whether the ISOs and RTOs should modify their day-ahead market processes, could expand the options available to gas-fired generators. Under the NOPR proposal, gas-fired generators would have the option of arranging natural gas supply and pipeline transportation at the Timely Nomination Cycle knowing the results of the day-ahead electric market. This could minimize situations in which gas-fired generators, particularly those that opt to procure natural gas supply and pipeline transportation after the day-ahead electric market results are posted, are unable to procure sufficient resources to fulfill their electric market commitments and to contribute to reliable electric system operation. If gas-fired generators know whether they were committed in the day-ahead electric market prior to the Timely Nomination Cycle, they may have a greater opportunity to procure natural gas transportation in the Timely Nomination Cycle—when there is the greatest opportunity to procure pipeline capacity. This, in turn, could reduce the potential for gas-fired generators to engage in costly actions that raise real-time electric market prices. Thus, electric market outcomes may better reflect expected operating costs if gas-fired generators were provided with day-ahead market results prior to the Timely Nomination Cycle. 81. It was recognized in the NOPR that moving the Timely Nomination Cycle to later in the day may impose systems and administrative costs on other interstate natural gas pipeline shippers. However, the NOPR concluded a 1:00 p.m. CCT start time for the Timely Nomination Cycle would appear to provide a reasonable balance of the electric and natural gas industries' concerns. The NOPR concluded that the long-term benefits of ensuring a better coordinated natural gas and electric industry appear to warrant this change. 2. Revised NAESB Day-Ahead Nomination Cycles 82. Consistent with the NOPR, NAESB revised its standards to move the start of the Timely Nomination Cycle to 1:00 p.m. CCT, with scheduled quantities becoming effective at the start of the next Gas Day. However, unlike the NOPR, NAESB revised its standards to move the deadline for the pipeline to notify shippers of their scheduled quantities from 4:30 p.m. CCT to 5:00 p.m. CCT, stating the pipelines require at least four hours to complete the Timely Nomination Cycle. 83. While the NOPR did not propose any changes to the Evening Nomination Cycle, NAESB revised its standards to provide that that cycle be completed in three hours, rather than the current four hours, with shippers being notified of their scheduled quantities at 9:00 p.m. instead of 10:00 p.m. Under both the NOPR and NAESB's revised standards, bumping of interruptible service is permitted in the Evening Nomination Cycle and, consistent with current Commission policy, already scheduled secondary firm service cannot be bumped. A comparison of the current NAESB day-ahead nomination cycles and the revised NAESB day-ahead nomination cycles are shown in Table 7 below. Table 7—Day-Ahead Nomination Cycles Time Shifts—all times CCT Current NAESB standards Revised NAESB standards Timely: Nomination Deadline 11:30 a.m 1:00 p.m. Schedule Issued 4:30 p.m 5:00 p.m. Start of Gas Flow 9:00 a.m Evening: Nomination Deadline 6:00 p.m 6:00 p.m. Schedule Issued 10:00 p.m 9:00 p.m. Start of Gas Flow 9:00 a.m 3. NOPR Comments 84. The large majority of commenters support moving the start time for the Timely Nomination Cycle from 11:30 a.m. CCT to 1:00 p.m. CCT, including commenters that do not generally support NAESB's intraday nomination timeline. 144 Many of the commenters that support NAESB's nomination timeline state that, consistent with the Commission's proposal, moving the Timely Nomination Cycle nomination deadline to 1:00 p.m. CCT will provide generators more time to acquire natural gas supply and pipeline transportation after learning their electric dispatch obligations, provided changes are made to the ISO and RTO scheduling processes. 145 Several commenters state that moving the Timely Nomination Cycle deadline later will also reduce costs and improve efficiency among gas-fired generation units. 146 144 AGA Comments at 22; Ameren Comments at 1; ANGA Comments at 3; BHE Comments at 16-17; Calpine Comments at 7; Castex (Producer Coalition) Comments at 7; CenterPoint Comments 3-4; Con Edison Companies Comments at 9; CPG Comments at 5; Direct Energy Comments at 2; Dominion Comments at 3; DTE Gas Comments at 3; Duke Energy Comments at 3; EDF et al. Comments at 7-8; Enhanced Reliability Coalition Comments at 29; EPSA Comments at 7; Equipower Comments at 9; ESI Comments at 3-4; Exelon Comments at 6; Gas Processors Association Comments at 1-2; INGAA Comments at 5; IOGA Comments at 5; IPPA Comments at 2; IRC Comments at 3; Kinder Morgan Comments at 6; National Fuel Distribution at 2-3; National Grid Comments at 1-2; Natural Gas Council Comments at 1-2; New England LDCs Comments at 30; NGSA Comments at 1-2; Nisource Comments at 2; Northwest Gas Association Comments at 2-3; Northwest Industrial Gas Users Comments at 5-6; PGC Comments at 4; PUCO Comments at 6-8; Puget Comments at 10; Sequent Comments at 6; Southern Companies Comments at 11; Southern Star Comments at 3; Spectra Comments at 4; Texas Pipeline Association Comments at 9; TVA Comments at 2; WBI Energy Comments at 4. 145 See, e.g., Calpine Comments at 8; CPG Comments at 6; Duke Energy Comments at 2-4; EquiPower Comments at 9; INGAA Comments at 5; National Grid Comments 1-2; New England LDCs Comments at 31; NESCOE Comments at 4-5; PGC Comments at 4-5; PUCO Comments at 5-6. 146 See, e.g., EDF et al. Comments at 7-8; PUCO Comments at 5-6. 85. A few commenters support moving the Timely Nomination Cycle, but believe that the 1:00 p.m. nomination deadline is too early in the day. Xcel Energy and SPP believe that the start time for the Timely Nomination Cycle should be extended to 1:30 p.m. CCT and 2:00 p.m. CCT, respectively, arguing that a 1:00 p.m. CCT nomination deadline would not allow power generators in MISO's and SPP's market sufficient time to secure the gas necessary to support their bids. 147 Similarly, Puget states that ISO and RTO bids will need to be awarded at least 1.5 hours prior to the NAESB Timely Nomination Cycle nomination deadline to allow energy schedulers adequate time to confirm transactions, exchange contracts, and enter nominations on pipelines. 148 147 SPP Comments at 2-3; Xcel Energy Comments at 3-5. 148 Puget Comments at 13. 86. MSCG does not support moving the Timely Nomination Cycle nomination deadline, arguing that the proposed change affects one hundred percent of the gas market while only benefitting about a third of energy markets and without providing additional liquidity in the market for natural gas. 149 149 MSCG Comments at 15-16. 4. Commission Determination 87. The Commission is amending its regulations at Part 284 to incorporate by reference NAESB's revised standards, which provide that the nomination deadline for the Timely Nomination Cycle shall be 1:00 p.m. CCT, with notice to shippers of scheduled quantities at 5:00 p.m. CCT, and the nomination deadline for the Evening Nomination Cycle shall remain at 6:00 p.m. CCT, with notice to shippers of scheduled quantities at 9:00 p.m. CCT. These changes, along with being generally consistent with the NOPR's proposed 1:00 p.m. CCT start time for the Timely Nomination Cycle, are supported by the vast majority of the commenters, from both the gas and electric industries, including commenters that do not generally support NAESB's revised intraday nomination timeline. NAESB's revised 1:00 p.m. CCT start time for the Timely Nomination Cycle, like the NOPR's proposed 1:00 p.m. CCT start time, will provide generators more time to acquire natural gas supply and pipeline transportation after learning their electric dispatch obligations, provided changes are made to the ISO and RTO scheduling processes. NAESB's proposal to provide notice of scheduled quantities at 5:00 p.m. also enables gas industry participants to complete the Timely Nomination Cycle by the end of the business day, while still providing sufficient time for the nomination, confirmation and scheduling process. 88. The Commission declines to extend the deadline for submitting nominations in the Timely Nomination Cycle past 1:00 p.m. CCT, as requested by a few commenters. Such an extension would likely require corresponding changes in the remainder of the Timely Nomination Cycle process, including moving back NAESB's proposed 5:00 p.m. CCT deadline for posting scheduled quantities. However, as many commenters point out, there needs to be sufficient time between the scheduled quantity posting of one cycle and the nomination deadline for the next cycle to enable shippers to review their transportation needs prior to the next nomination deadline. 150 Further extending the Timely Nomination Cycle nomination deadline would reduce or do away completely with the time between when the Timely Nomination Cycle schedule is issued and the 6:00 p.m. deadline for submitting nominations in the Evening Nomination Cycle. Also, commenters in the natural gas industry contend that the further the Timely Nomination Cycle process falls outside of regular business hours, the more likely it is that producers, point operators, and shippers will be harder to reach to resolve nomination, confirmation and scheduling errors. 151 Given the support for the revised NAESB schedule and the problems created in moving the time any later, the concerns of the commenters with the coordination of the current scheduling processes of MISO and SPP relative to natural gas scheduling are best addressed in the section 206 proceedings the Commission instituted for each ISO and RTO. 150 See, e.g., Exelon Comments at 7; NGSA Comments at 16. 151 See, e.g., INGAA Comments at 8. C. Intraday Nomination Cycles 89. In addition to the Timely and Evening Nomination Cycles, pipelines currently must offer shippers at least two opportunities to nominate natural gas during the day that gas is flowing. These nomination opportunities are known as the Intraday 1 and Intraday 2 Nomination Cycles. The current Intraday 1 Nomination Cycle begins at 10:00 a.m. CCT on the day of gas flow, with pipelines issuing scheduled quantities at 2:00 p.m. CCT, and the start of gas flow at 5:00 p.m. CCT. The current Intraday 2 Nomination Cycle begins at 5:00 p.m. CCT on the day of gas flow, with pipelines issuing scheduled quantities at 9:00 p.m. CCT, and gas flow also starting at 9:00 p.m. CCT. As with nominations made at the Timely or Evening Nomination Cycles, nominations for firm service at the Intra-Day 1 Nomination Cycle can “bump” an already scheduled interruptible nomination. Pursuant to the “No-Bump Rule,” however, nominations for firm service made at the Intraday 2 cycle cannot “bump” previously scheduled interruptible service. 90. A number of commenters in response to the technical conferences in Docket No. AD12-12-000 stated that the standard, nation-wide nomination opportunities currently available may not provide gas-fired generators or other shippers with sufficient flexibility to adjust their nominations to respond to real-time changes in their need for natural gas. 152 These commenters requested that the Commission require additional, standardized intraday nomination opportunities on interstate natural gas pipelines. Pipelines and other gas market participants indicated that they were open to the creation of the additional standard nomination cycles. 153 152 NOPR, 146 FERC ¶ 61,201 at P 57. 153 Id. P 62. 1. NOPR Proposal 91. To address concerns that the current standard, nation-wide intraday nomination opportunities do not provide shippers—especially natural gas-fired generators—with sufficient flexibility, the NOPR proposed to modify the current natural gas nomination timeline to add two additional intraday nomination cycles so that shippers would have four intraday cycles to reschedule gas instead of the existing two. The additional intraday nomination cycles would maximize shippers' ability to make significant changes in their intraday nominations, as well as provide firm shippers an additional, bumpable late-afternoon nomination cycle. The proposed revisions would provide gas-fired generators, as well as other pipeline customers, with greater flexibility to revise their nominations to adjust to system conditions and changes to load throughout the Gas Day. 92. The timelines proposed in the NOPR were based on the proposed adoption of 4:00 a.m. CCT as the start of the Gas Day. The NOPR proposed that the Intraday 1 Nomination Cycle begin at 8:00 a.m. CCT, with pipelines issuing scheduled quantities at 11:00 a.m. CCT, and gas flow beginning at 12:00 noon CCT. The Intraday 1 Nomination Cycle would provide an early morning opportunity for shippers to nominate gas. The NOPR proposed that the Intraday 2 Nomination Cycle begin at 10:30 a.m. CCT, with pipelines issuing scheduled quantities at 2:00 p.m. CCT, and gas flow beginning at 4:00 p.m. CCT. The NOPR proposed Intraday 2 cycle would replace the current Intraday 1 mid-morning nomination cycle and permit bumping. The NOPR proposed Intraday 3 Nomination Cycle would begin at 4:00 p.m. CCT with pipelines issuing scheduled quantities at 6:00 p.m. CCT, and gas flow beginning at 7:00 p.m. CCT. The NOPR proposed Intraday 3 Nomination Cycle would provide an additional bumping opportunity for firm shippers. The NOPR proposed Intraday 4 Nomination Cycle would begin at 7:00 p.m. CCT with pipelines issuing scheduled quantities at 9:00 p.m. CCT, and gas flow beginning at 9:00 p.m. CCT. The NOPR Intraday 4 Nomination Cycle would replace the current 5:00 p.m. no-bump cycle. 2. NAESB's Revised Intraday Nomination Cycles 93. NAESB's revised standards provide for three intraday nomination opportunities, rather than the four proposed in the NOPR. In contrast to the NOPR proposal to start the Intraday 1 Nomination Cycle at 8:00 a.m. CCT, NAESB's revised standards start the Intraday 1 Nomination Cycle at the existing 10:00 a.m. CCT time. However, the revised standards move the deadline for pipelines to issue scheduled quantities up to 1:00 p.m. CCT from the existing NAESB standard of 2:00 p.m., and for gas flow to begin at 2:00 p.m. CCT, rather than the existing 5:00 p.m. CCT. NAESB's revised standards provide for the Intraday 2 Nomination Cycle to start at 2:30 p.m. CCT, rather than 5:00 p.m., as it now does. Pipelines would issue scheduled quantities at 5:30 p.m. CCT, rather than the existing 9:00 p.m., and gas flow would begin at 6:00 p.m. CCT, instead of the existing 9:00 p.m. NAESB's new Intraday 3 Nomination Cycle begins at 7:00 p.m. CCT, with scheduled quantities issued at 10:00 p.m. CCT, and gas flow beginning at 10:00 p.m. CCT. NAESB's revised standards provide that bumping of interruptible service will be allowed during the Intraday 2 Nomination Cycle in addition to the Intraday 1 Nomination Cycle. 154 NAESB's revised standards reflect reduced intraday processing times from the current NAESB standards ( i.e., 3 hours instead of the current 4 hours). A comparison of the current NAESB intraday nomination timeline and the revised NAESB intraday nomination timeline is shown in the table below. 154 A comparison of the current NAESB nomination timeline and the revised NAESB nomination timeline is set forth in the Appendix. Table 8—Intraday Nomination Cycles Time shifts—all times CCT Current NAESB standards Revised NAESB standards Intraday 1 Nomination Deadline 10:00 a.m. 10:00 a.m. Schedule Issued 2:00 p.m. 1:00 p.m. Start of Gas Flow 5:00 p.m. 2:00 p.m. IT Bump Rights bumpable bumpable. Intraday 2 Nomination Deadline 5:00 p.m. 2:30 p.m. Schedule Issued 9:00 p.m. 5:30 p.m. Start of Gas Flow 9:00 p.m. 6:00 p.m. IT Bump Rights no bump bumpable. Intraday 3 Nomination Deadline 7:00 p.m. Confirmations 9:30 p.m. Schedule Issued 10:00 p.m. Start of Gas Flow 10:00 p.m. IT Bump Rights no bump. 3. Comments 94. The large majority of comments on this issue support or do not oppose NAESB's revised standards providing for three Intraday Nomination Cycles. 155 Commenters state that, consistent with the NOPR's proposed four intraday nomination cycles, NAESB's modified three intraday nomination cycles will a [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2015-09275. Public record. Not legal advice.