151 FERC ¶ 61,049

UNITED STATES OF AMERICA

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

(Issued April 16, 2015)

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.

DATE: This rule will become effective [Insert_Date 75 days after publication in the 

FEDERAL REGISTER]. The incorporation by reference of certain publications listed 
Docket No. RM14-2-000 - 2 -

in this rule is approved by the Director of the Federal Register as of [insert date 75 days 

after publication in the Federal Register].

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:
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Coordination of the Scheduling Processes of Interstate 

Natural Gas Pipelines and Public Utilities

Docket No. RM14-2-000

ORDER NO. 809

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.
Docket No. RM14-2-000 ii

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.
151 FERC ¶ 61,049

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Philip D. Moeller, Cheryl A. LaFleur,

Tony Clark, and Colette D. Honorable.

Coordination of the Scheduling Processes of Interstate 

Natural Gas Pipelines and Public Utilities

Docket No. RM14-2-000

ORDER NO. 809

FINAL RULE

(Issued April 16, 2015)

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 
Docket No. RM14-2-000 - 2 -

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. 

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. 

 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 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).
Docket No. RM14-2-000 - 3 -

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).
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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 

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 

 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. 
Docket No. RM14-2-000 - 5 -

flow (Intraday 1 and Intraday 2). Individual pipelines may offer additional scheduling 

opportunities beyond the standard nomination cycles.6

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 

 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).
Docket No. RM14-2-000 - 6 -

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 dayahead 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

 

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

9. Recent developments in the wholesale natural gas and electricity industries—

particularly the organized electricity markets—signal that changes to the gas nomination 

 7 FERC, Operator-Initiated Commitments in RTO and ISO Markets, Docket No. 

AD14-14-000 (Dec. 2014), available at http://www.ferc.gov/legal/staffreports/2014/AD14-14-operator-actions.pdf.

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.
Docket No. RM14-2-000 - 7 -

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 Event12 and the extreme and 

sustained cold weather events in the eastern U.S. in January 2014,13 show the crucial 

 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, MidAtlantic, 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.
Docket No. RM14-2-000 - 8 -

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.

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.
Docket No. RM14-2-000 - 9 -

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 
Docket No. RM14-2-000 - 10 -

as concerns regarding the flexible and efficient use of pipeline capacity by natural gasfired generators and other shippers.17 

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. 

CCT18; 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.

14. The NOPR also proposed to require interstate natural gas pipelines to offer multiparty 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 

 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).

18 The Commission did not propose any changes to the Evening Nomination 

Cycle. 
Docket No. RM14-2-000 - 11 -

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 FPA19 to ensure that each ISO’s and RTO’s scheduling practices, particularly its dayahead scheduling practices, correlate with any revisions to the natural gas scheduling 

 19 16 U.S.C. 824e (2012).
Docket No. RM14-2-000 - 12 -

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 gasfired 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

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 

 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).
Docket No. RM14-2-000 - 13 -

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

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. 

 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.

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. 
Docket No. RM14-2-000 - 14 -

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 

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). 

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 

 28 Id.

29 Id. at 10.

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 

(continued...)
Docket No. RM14-2-000 - 15 -

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.

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, 

 

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.

31 NAESB Sept. 29, 2014 Report at Appendix C.
Docket No. RM14-2-000 - 16 -

including ISOs and RTOs, electric utilities, interstate natural gas pipelines, local 

distribution companies (LDC), producers, state regulators, electric generators, and other 

interested persons.

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 Coalition33 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 

(continued...)
Docket No. RM14-2-000 - 17 -

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. 

 

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. 

34 NAESB’s WGQ Annual Plan Item 11c and Minor Correction MC14018.

35 See Appendix.
Docket No. RM14-2-000 - 18 -

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 
Docket No. RM14-2-000 - 19 -

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-
Docket No. RM14-2-000 - 20 -

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 

 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. 
Docket No. RM14-2-000 - 21 -

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

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 

 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.

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 

(continued...)
Docket No. RM14-2-000 - 22 -

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 

 

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.

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.
Docket No. RM14-2-000 - 23 -

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 

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 

 45 Equipower Comments at 8-9; Con Edison Comments at 7.

46 Southern Company Comments at 8.

47 Id.

48 ISO-NE Comment at 4.

49 Con Edison Comments at 7-8.
Docket No. RM14-2-000 - 24 -

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

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

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 

 50 Id. at 8-9.

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.

52 INGAA Comments at 16; Direct Energy Comments at n.10. 
Docket No. RM14-2-000 - 25 -

increase electric reliability and that the speculative benefits of such a change appear 

limited.53 

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 

 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. 

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.
Docket No. RM14-2-000 - 26 -

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 

 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.
Docket No. RM14-2-000 - 27 -

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

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 

 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.

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.
Docket No. RM14-2-000 - 28 -

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 

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 Day65 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

 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.

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.
Docket No. RM14-2-000 - 29 -

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 

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 

39. Commenters state that the optimum time for packing the pipeline72 is when 

customer demands are low and, therefore, pipelines and LDCs with pipeline operations 

 68 National Grid Comments at 4. 

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.

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.
Docket No. RM14-2-000 - 30 -

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 

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 

 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.

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.
Docket No. RM14-2-000 - 31 -

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

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

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 

 78 New England LDCs Comments at 23-24; NW Industrial Gas Users Comments 

at 4.

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.
Docket No. RM14-2-000 - 32 -

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 am CCT 

timeframe, since key decision-makers would not be on duty at that hour.83 

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 

 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.

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.
Docket No. RM14-2-000 - 33 -

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

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 

 85 Dominion Comments at 21; Enhanced Reliability Coalition Comments at 12.

86 Texas Pipeline Association Comments at 11; Gas Processors Association 

Comments at 9.

87 CenterPoint Comments at 4-5; New England LDCs Comments at 19; Northern 

Municipal Distributors/Midwest Region Gas Task Force Comments at 11-12.
Docket No. RM14-2-000 - 34 -

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 

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 

 88 CenterPoint Comments at 4-5; Northern Municipal Distributors/Midwest 

Region Gas Task Force Comments at 11-12.

89 CenterPoint Comments at 4-5.

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.
Docket No. RM14-2-000 - 35 -

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 

 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 AM 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.
Docket No. RM14-2-000 - 36 -

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 

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 

 99 BHE Comment at 10-11; MSCG Comments at 16-17.

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.
Docket No. RM14-2-000 - 37 -

services in order to recover the compliance costs of implementing the Gas Day 

proposal.103

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 

 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.

104 CAISO Data Response at 7-8.

105 Id. at 6.
Docket No. RM14-2-000 - 38 -

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

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 fuelrelated 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 fuelrelated 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 

 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.

107 MISO Data Response at 1-3.

108 Id.

109 See Tables MISO Data Response at 2. 
Docket No. RM14-2-000 - 39 -

made many recent enhancements to improve transparency of fuel-related matters in the 

planning and operating horizons.110

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

 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 

webpage. MISO Data Response at 5.

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.
Docket No. RM14-2-000 - 40 -

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 gasfired 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 

 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.
Docket No. RM14-2-000 - 41 -

take actions that diminish the frequency of generation outage impacts due to gas 

reductions.114

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 

 114 ISO-NE Data Response at 1.

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 gasfired generator has sufficient remaining nominated quantities of interstate pipeline 

transportation.
Docket No. RM14-2-000 - 42 -

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. 

56. NYISO states that it identified 13 generators committed in 2013 and 2014 via 

Supplemental Resource Evaluation117 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 

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

 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.
Docket No. RM14-2-000 - 43 -

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 values119 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. 

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 

 119 For example, the average of all of the 6:00 a.m. CCT de-rates in January.

120 January 2013, December 2013, January 2014, and February 2014.
Docket No. RM14-2-000 - 44 -

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. 

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%
Docket No. RM14-2-000 - 45 -

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.
Docket No. RM14-2-000 - 46 -

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 gasfired 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 
Docket No. RM14-2-000 - 47 -

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. 
Docket No. RM14-2-000 - 48 -

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. 
Docket No. RM14-2-000 - 49 -

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 

 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.
Docket No. RM14-2-000 - 50 -

transportation, maintenance of on-site fuel inventory, and dual fuel capability.126 ISONE 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.

 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).
Docket No. RM14-2-000 - 51 -

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.

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 

 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.").
Docket No. RM14-2-000 - 52 -

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 

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-path134 nominations, 

 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 IntraDay 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).

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 

(continued...)
Docket No. RM14-2-000 - 53 -

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.

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 

 

secondary receipt and/or delivery point is contained wholly within the primary points 

listed in the shipper’s contract.

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, 2998), FERC Stats. & 

Regs., Regulations Preamble 1996-2000 ¶ 31,062, at 30,672 (1998).
Docket No. RM14-2-000 - 54 -

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. 

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 services138 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 

 137 Id. at 30,671.

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).
Docket No. RM14-2-000 - 55 -

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.

76. Wholesale electricity markets operated by the ISOs and RTOs also use a dayahead 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

 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.
Docket No. RM14-2-000 - 56 -

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. (ISONE)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 
Docket No. RM14-2-000 - 57 -

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”).
Docket No. RM14-2-000 - 58 -

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 am CCT to 4:30 pm CCT) to three and one-half hours (1:00 pm CCT to 4:30 pm 

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 
Docket No. RM14-2-000 - 59 -

capacity to serve their obligations; or (2) show cause why such changes are not 

necessary.

143 

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 dayahead 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.

 143 Section 206 Order, 146 FERC ¶ 61,202.
Docket No. RM14-2-000 - 60 -

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 
Docket No. RM14-2-000 - 61 -

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 

 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.
Docket No. RM14-2-000 - 62 -

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 

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 

 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.

147 SPP Comments at 2-3; Xcel Energy Comments at 3-5.
Docket No. RM14-2-000 - 63 -

nomination deadline to allow energy schedulers adequate time to confirm transactions, 

exchange contracts, and enter nominations on pipelines.148

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 

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 

 148 Puget Comments at 13.

149 MSCG Comments at 15-16.
Docket No. RM14-2-000 - 64 -

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 pm 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 

 150 See, e.g., Exelon Comments at 7; NGSA Comments at 16.
Docket No. RM14-2-000 - 65 -

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.

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. 

 151See, e.g., INGAA Comments at 8.
Docket No. RM14-2-000 - 66 -

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 

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 lateafternoon 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. 

 152 NOPR, 146 FERC ¶ 61,201 at P 57.

153 Id. P 62.
Docket No. RM14-2-000 - 67 -

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. 
Docket No. RM14-2-000 - 68 -

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.

 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.

 154 A comparison of the current NAESB nomination timeline and the revised 

NAESB nomination timeline is set forth in the Appendix. 
Docket No. RM14-2-000 - 69 -

Time Shifts -- All times CCT Current NAESB 

Standards

Revised NAESB

Standards

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 allow gas-fired generators, as well as 

 155 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; 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; 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. 
Docket No. RM14-2-000 - 70 -

other pipeline customers, more flexibility to respond to scheduling, operational, or 

weather-related changes throughout the operating day.156 

95. Many commenters state that they do not support an additional fourth intraday 

nomination cycle, as proposed in the NOPR, arguing it would likely result in increased 

costs and overlapping cycles.157 For example, Dominion states that a fourth intraday 

cycle may require a third shift of employees, which will increase costs for pipelines.158

96. Many commenters state that NAESB’s three intraday nomination cycles resolve 

gas industry participants’ concerns with the NOPR’s proposed four intraday nomination 

cycles regarding overlapping cycles, which, left unresolved, could lead to greater 

instances of incorrect shipper nominations and scheduling errors.159 Commenters 

highlight several examples of overlapping cycles under the NOPR’s proposed four 

intraday nomination cycles. First, commenters state that the start of the NOPR’s 

proposed Evening Nomination Cycle is at 6:00 p.m. CCT, which would be the same time 

scheduled quantities are posted for the Intraday 3 Nomination Cycle. Commenters state 

 156See, e.g., AGA Comments at 22-23; Ameren Comments at 5; CPG Comments 

at 5-6; Duke Energy Comments at 2-4; Exelon Comments at 6; INGAA Comments 5-7; 

IOGA Comments at 5

157 See, e.g., Exelon Comments at 7; Kinder Morgan Comments at XX; NGSA 

Comments at 16-17; PGC Comments at 5; Puget Comments at 17; WBI Energy 

Comments at 4-5.

158 Dominion Comments at 11.

159 See, e.g., Dominion Comments at 11; EPSA Comments at 6-7; INGAA 

Comments at 9; PGC Comments at 5; Southern Star Comments at 5. 
Docket No. RM14-2-000 - 71 -

that this would require a shipper to analyze how much of its gas the pipeline scheduled to 

flow for the remainder of the current Gas Day at the same time it must nominate in the 

Evening Nomination Cycle for gas flow the next day. Second, commenters state that the 

NOPR’s proposed 10:30 a.m. CCT start of the Intraday 2 Nomination Cycle would be 

before the 11:00 a.m. CCT posting of scheduled quantities for the Intraday 1 Nomination 

Cycle. Commenters state that under this timeline a customer would have to nominate gas 

in the Intraday 2 Nomination Cycle before learning what quantity of gas the pipeline 

scheduled in the Intraday 1 Nomination Cycle. Third, commenters state that the NOPR’s 

proposed 4:30 p.m. CCT posting of scheduled quantities for the Timely Nomination 

Cycle overlaps with the 4:00 p.m. start of the Intraday 3 Nomination Cycle, which would 

require pipelines to schedule gas for two different cycles at the same time. Commenters 

also point out that NAESB’s three intraday nomination cycles, like its revised Timely 

Nomination Cycle, reflect a shortened processing time (i.e., 3 hours instead of 4 hours). 

Commenters in the natural gas industry claim that these processing times cannot be 

shortened any further.160 

97. Many commenters state that NAESB’s three intraday nomination cycles, unlike 

that of the NOPR’s proposed four intraday nomination cycles, provide sufficient time 

(1.5 hours) between the scheduled quantity posting of one cycle and the nomination 

deadline for the next cycle, so that shippers can review their pipeline transportation needs 

 160 Dominion Comments at 11; Kinder Morgan Comments at 6-8; WBI Comments 

at 4; see also INGAA Comments at 8-9.
Docket No. RM14-2-000 - 72 -

prior to the next nomination deadline.161 Under the NOPR’s proposed four intraday 

nomination cycles, the 10:30 a.m. start of the Intraday 2 Nomination Cycle is before the 

11:00 a.m. posting of scheduled quantities for the Intraday 1 Nomination Cycle and there 

is only 1 hour between the time the schedules are posted for the Intraday 3 Nomination 

Cycle (6:00 p.m.) and the start of the Intraday 4 Nomination Cycle (7:00 p.m.). Many

commenters also point out that NAESB’s nomination timeline, in particular the three 

intraday nomination cycles, allows for the accomplishment of most scheduling work 

during regular business hours, or as close as possible to regular hours.162 

98. AGA, Dominion, and INGAA submit that NAESB’s three intraday nomination 

cycles, in particular the Intraday 2 and Intraday 3 Nomination Cycles, will also address 

the Commission’s concern regarding gas-fired generators’ ability to ensure adequate gas 

supplies for the morning electric ramp by providing sufficient opportunities during the 

operating day to schedule gas to cover that morning period.

163 

99. ACES, AEP, Essential Power, and IRC support the four intraday nomination 

cycles proposed in the NOPR, rather than the three provided by NAESB’s revised 

 161 See, e.g., EPSA Comments 6-7; Exelon Comments at 7; INGAA Comments 

at 8-9, WBI Energy Comments at 4. 

162 See, e.g., Enhanced Reliability Coalition Comments at 31; Northwest Gas 

Association Comments at 2-3; PGC Comments at 4; Southern Companies Comments 

at 10-11.

163 See, e.g., AGA Comments at 23; Dominion Comments at 9-10; INGAA 

Comments at 6-7
Docket No. RM14-2-000 - 73 -

standards.

164 They state that more standardized opportunities for electric generators to 

nominate gas would provide generators additional operational flexibility to respond to 

real-time electric system needs. 

100. While Exelon supports NAESB’s proposed three intraday nomination cycles, it 

cautions that, if the start of the Gas Day remains at 9:00 a.m. CCT, non-bumpable 

interruptible shippers will preempt the rights of firm shippers for almost half of the Gas 

Day, or 11 hours.165 Con Edison point out that, if the start of the Gas Day remains at 

9:00 a.m. CCT, NAESB’s last bumpable intraday cycle (2:30 p.m. CCT) would be more 

than 18 hours before the current start of next Gas Day.166 Con Edison states that electric 

system conditions and load can change dramatically during an 18-hour period. Similarly, 

DSPS states that NAESB’s three intraday nomination cycles makes sense from the 

perspective of a utility that operates in the Eastern-time zone, but notes that utilities, such 

as those in the Desert Southwest, that do not have a late afternoon nomination cycle 

effectively have no tools to ensure the reliability of their natural gas transportation during 

the last 18.5 hours of the Gas Day, assuming a 9:00 a.m. CCT start to the Gas Day.167 

 164 ACES Comments at 9; AEP Comments at 4; Essential Power Comments at 4; 

IRC Comments at 4. IRC notes that CAISO would support three intraday gas nomination 

cycles irrespective of an earlier start of the Gas Day.

165 Exelon Comments at 10-11.

166 Con Edison Comments at 10.

167 DSPS Comments at 19-20.
Docket No. RM14-2-000 - 74 -

101. EDF et al. does not support NAESB’s addition of a single intraday cycle. 

EDF et al. urges the Commission to standardize the voluntary enhanced practices of 

certain pipelines and establish up to twelve intraday nominating and gas capacity trading 

(capacity release) cycles.168 

102. TVA, DSPS, Southern Star, Southern Company, and Michigan PSC encourage the 

Commission to consider modifying or eliminating the No-Bump Rule.169 TVA asserts 

that firm shippers paying demand charges under long-term firm contracts should always 

have priority, as firm capacity is charged and paid for the entire twenty-four hours of the 

Gas Day.170 DSPS states that the No-Bump Rule precludes a firm shipper from calling 

upon the unutilized portion of its firm contract to satisfy the evening peak demands if the 

capacity already has been nominated by and confirmed to an interruptible shipper.171

103. Many commenters argue that the last intraday grid-wide nomination cycle should 

remain a no-bump cycle, as provided by NAESB’s revised standards.

172 Commenters 

note that retaining the no-bump cycle was strongly supported in the NAESB process. 

 168 EDF et al. Comments at 12.

169 DSPS Comments at 19-20; Michigan PSC Comments at 5-6; Southern 

Company Comments at 11-12; Southern Star Comments at 3; TVA Comments at 3.

170 TVA Comments at 3.

171 DSPS Comments at 20.

172 See, e.g., Dominion Comments at 10; Enhanced Reliability Coalition 

Comments at 31; ESPA comments at 3; IECA Comments at 4; National Grid Comments 

at 30; NGSA Comments at 18-19; WBI Comments at 5; PGC Comments at 5-6; Sequent 

Comments at 6. 
Docket No. RM14-2-000 - 75 -

The Enhanced Reliability Coalition states that no-bump plays an important role in 

balancing the flexibility needs for interruptible transmission shippers with available 

capacity while providing priority to firm shippers (who incurred the firm shipping costs) 

over interruptible shippers through the NAESB Intraday 2 Nomination Cycle.

173 

4. Commission Determination

104. The Commission is amending its regulations at Part 284 to incorporate by 

reference NAESB’s revised standards, which provide three intraday nomination cycles. 

Adoption of these standards will provide natural gas-fired generators, as well as other 

pipeline shippers, with increased scheduling flexibility. While the Intraday 1 Nomination 

Cycle will continue to start at 10:00 a.m. CCT, pipelines will issue scheduled quantities 

at 1:00 p.m. CCT, one hour earlier than under the currently effective standards, and gas 

flow will begin at 2:00 p.m. CCT, three hours earlier than under the currently effective 

standards. The new bumpable Intraday 2 Nomination Cycle will start at 2:30 p.m. CCT, 

four and a half hours after the single bumpable intraday nomination opportunity provided 

by the existing Intraday 1 Nomination Cycle, with pipelines issuing scheduled quantities 

at 5:30 p.m. CCT, and gas flow beginning at 6:00 p.m. CCT. By adding an additional 

bumpable nomination cycle later in the day, firm shippers will have greater opportunity 

to utilize the intraday schedules to reflect load and weather changes consistent with the 

higher priority of their service. The later time for the bumpable nomination will help 

shippers in the west, in particular, by allowing them to reflect later changes in weather 

 173 Enhanced Reliability Coalition Comments at 31.
Docket No. RM14-2-000 - 76 -

forecasts into their nominations. The new no-bump Intraday 3 Nomination Cycle will 

start at 7:00 p.m. CCT, two hours later than the current no-bump Intraday 2 Nomination 

Cycle, with gas flow beginning at 10:00 p.m. CCT, one hour later than under the current 

no-bump Intraday 2 Nomination Cycle. The later no-bump nomination cycle will give 

firm shippers a further opportunity to adjust their nominations consistent with their needs, 

while also providing certainty to interruptible transactions, so shippers and pipelines can 

plan for flows during the Gas Day.

105. These revised standards reflect a consensus of the natural gas industry, and the 

changes reflect broad support in both industries. The vast majority of the commenters 

prefer NAESB’s proposed three intraday nomination cycles to the NOPR’s proposed four 

intraday nomination cycles because the NAESB proposal allows sufficient time for 

processing gas nominations, avoids overlapping nomination cycles, and allows for the 

accomplishment of most scheduling work during regular business hours, or reasonably 

close thereto. Further, they meet the goals of the NOPR because they provide additional 

flexibility to gas-fired generators, as well as other pipeline shippers. While some would 

prefer further changes to address their individual or regional needs, we find that, on 

balance, these standards represent a step forward that will benefit all shippers. We also 

note that under Commission policy, pipelines may file enhanced services that provide 
Docket No. RM14-2-000 - 77 -

additional scheduling flexibility for firm shippers by adding additional nomination cycles 

that allow firm shippers to bump interruptible shippers.

174

106. Some commenters suggest that because firm service has a higher priority than 

interruptible service, firm shippers should always be able to bump interruptible service,

and more generally, that all nomination cycles should be bumpable. We find sufficient 

support for retaining a no-bump cycle and respecting the gas industry consensus that was 

achieved.

175 As several commenters maintain, and as the Commission has previously 

recognized, interruptible shippers need some stability in the nomination system. In Order 

No. 587-G, the Commission accepted a consensus of the gas industry, including both firm 

and interruptible shippers, and accepted standards that provide that the last intraday 

nomination opportunity would not permit bumping of interruptible service. In adopting 

this standard, the Commission recognized that making the last intraday nomination 

 174 As clarified in the NOPR, pipelines may offer enhanced nomination 

opportunities that permit bumping of interruptible shippers at least until the time the 

bumping notice under the modified NAESB Intraday 2 Nomination schedule is issued at 

5:30 p.m. CCT. NOPR, 146 FERC ¶ 61,201 at P 73. The modified NAESB Intraday 3 

Nomination Cycle guarantees that any bumped interruptible shipper will have an

opportunity to renominate its bumped volumes at 7:00 p.m. CCT. If a pipeline proposes 

enhanced nomination services that permit bumping of interruptible services after 

5:30 p.m. CCT, the Commission will consider the proposal on a case-by-case basis to 

determine whether such proposal provides an adequate subsequent opportunity to 

renominate any bumped volumes. Id.

175 Standards for Business Practices of Interstate Natural Gas Pipelines, Order 

No. 587, 61 FR 39053 (July 26, 1996), FERC Stats. & Regs., Regulations Preambles 

¶ 31,038 (July 17, 1996) (“Since it is the industry that must operate under these 

standards, deferring to the considered judgment of the consensus of the industry is both 

reasonable and appropriate”).
Docket No. RM14-2-000 - 78 -

opportunity no-bump would provide stability to the nomination system.176 Moving the 

last bump cycle to later in the day helps to accommodate the needs of the firm shippers, 

while maintaining the No-Bump Rule during NAESB’s Intraday 3 Nomination Cycle will 

provide stability for interruptible shippers. As such, we find that it achieves a reasonable 

balance of interests.

107. While NAESB’s modified standards represent an improvement over the currently 

effective standards, we continue to recognize that additional intraday nomination 

opportunities could promote more efficient use of existing pipeline infrastructure and 

provide additional operational flexibility to all pipeline shippers, including gas-fired 

generators. The modified NAESB standards reflect reduced intraday processing times 

from the current NAESB standards (i.e., three hours instead of the current four hours), 

and existing operational limitations, including the manual processes utilized by pipelines 

for processing nominations, may affect the ability of the gas industry to add additional 

standard nomination cycles applicable to all shippers. However, the use of computerized 

scheduling would appear to provide an opportunity for faster and more frequent 

scheduling of intraday nominations for those shippers and their confirming parties willing 

to commit to scheduling electronically. We request that gas and electric industries, 

through NAESB, explore the potential for faster, computerized scheduling when shippers 

and confirming parties all submit electronic nominations and confirmations, including a 

 176 Order No. 587-G, FERC Stats. & Regs., ¶ 31,062, order on reh’g, Order 

No. 587-I, 63 FR 53565, 53569 (Oct. 6, 1998), FERC Stats. & Regs., Regulations 

Preambles 1996 – 2000 ¶ 31,067 (1998).
Docket No. RM14-2-000 - 79 -

streamlined confirmation process if necessary. Providing such an option would enable 

those entities that need greater scheduling flexibility to have their requests processed 

expeditiously. 

V. DSPS Proposal

A. Background

108. In its proposal, DSPS asserts that the fundamental issue in the Desert Southwest is 

that firm transportation shippers do not have the necessary tools to access their firm 

transportation capacity in order to properly respond to operating contingencies, including 

unexpected changes in renewable generation, that occur during their evening peak 

demand period. DSPS suggests that three Commission policies preclude firm shippers in 

the Desert Southwest from accessing their transportation capacity during their evening 

peak demand period. First, DSPS states that the intraday nomination cycles do not align 

with the evening peak periods of demand in the Desert Southwest which occur between 

7:00 p.m. and 9:00 p.m. CCT. Second, DSPS states that the rule that interruptible service 

cannot be bumped in the last intraday nomination cycle precludes firm transportation 

shippers from accessing their transportation capacity during the evening peak period if an 

interruptible shipper is already flowing gas on the system. Finally, DSPS states that the 

Commission’s rule that, once scheduled, secondary firm service cannot be bumped in any 

subsequent nomination cycle,177 also interferes with the ability of firm shippers to 

 177 The Commission's long standing policy on firm service is that once scheduled, 

whether at primary or secondary points, the service may not be bumped by a nomination 

by another firm shipper. 
Docket No. RM14-2-000 - 80 -

schedule primary-firm service after the Timely Nomination Cycle. DSPS states that it is 

concerned that some shippers are contracting for primary firm transportation rights on 

unused pipeline paths and then scheduling secondary firm service on a more heavily used 

path outside their primary path in the Timely or Evening Nomination Cycles. DSPS 

states that this blocks shippers holding primary firm rights to the more heavily used path, 

including DSPS members, from using their primary firm service in subsequent 

nomination cycles.

109. DSPS notes that geographical factors also present unique challenges in the 

Desert Southwest. DSPS indicates that the Desert Southwest does not have local market 

area gas storage which makes it difficult to respond to unexpected changes in demand. 

Further, DSPS contends that the Desert Southwest is the home of a growing percentage 

of renewable energy resources. DSPS claims that electric utilities require both the 

transportation capacity and the natural gas commodity be available to respond to the 

immediate generation demands caused by the drop in renewable energy.

110. Accordingly, DSPS proposes changes on a national basis and on a regional basis, 

as discussed below. 

B. DSPS’s Proposed National Changes

111. On a national basis, DSPS requests that the Commission: (1) start the Evening 

Nomination Cycle at 7:00 p.m. CCT (instead of 6:00 p.m. CCT, as in both the NOPR and 

NAESB’s revised standards); and (2) modify the Commission’s policy on natural gas 

scheduling priority to allow primary-firm shippers to bump secondary firm shippers 

during the Evening Nomination Cycle. DSPS contends that moving the Evening 
Docket No. RM14-2-000 - 81 -

Nomination Cycle to 7:00 p.m. CCT provides a timely opportunity to address operating 

contingencies. DSPS also contends that, unlike the alternative of establishing a bumpable 

7:00 p.m. CCT intraday nomination cycle, this proposal dispenses with the concerns 

surrounding interrupting flowing gas, the need for a subsequent no-bump cycle, and the 

fact such a late intraday nomination cycle would have little value due to the elapsed 

pro-rata flow of the gas. DSPS asserts that its proposal to modify the Commission’s 

policy on secondary firm nominations would increase the value of firm contracts 

involving primary points and encourage long-term contracting, which in turn promotes 

infrastructure development.

1. Comments

112. In its October 15, 2014 notice, the Commission specifically sought comment on 

the DSPS proposals. None of the commenters on DSPS’s proposal support DSPS’s 

proposal to change the Evening Nomination Cycle from 6:00 p.m. to 7:00 p.m. CCT.178 

While most commenters oppose modifying Commission policy to permit primary-firm 

nominations to bump secondary firm nominations in the Evening Nomination Cycle, a 

few commenters support this proposal. 

 178 ACES Comments at 13; AGA Comments at 33; Dominion Comments at 12-13; 

Enhanced Reliability Coalition Comments at 32-33; EPSA Comments at 8; INGAA 

Comments at 9-10; IPAA Comments at 3; Kinder Morgan Comments at 10; National 

Grid Comments at 5; New England LDCs Comments at 32; Natural Gas Council

Comments at 6; NGSA Comments at 22; PGC Comments at 8; Sequent Comments at 6; 

Southwest IS Comments at 2-3; Transwestern Comments at 4; WBI Energy Comments 

at 7.
Docket No. RM14-2-000 - 82 -

113. Many of those commenters opposing the DSPS proposal to change the Evening 

Nomination Cycle contend that the change is contrary to the NAESB efforts to establish a 

coordinated nomination and scheduling timeline.179 PGC states that during the NAESB 

discussion and voting process, a 7:00 p.m. CCT Evening Nomination Cycle was 

thoroughly vetted and ultimately rejected by a majority of the industry participants.180 

Other commenters state that the proposed time would coincide with the start of the 

NAESB Intraday 3 Nomination Cycle.181 Several commenters also state that DSPS has 

not sufficiently explained why its proposed 7:00 p.m. Evening Nomination Cycle would 

address its concerns about operating contingencies occurring in the late afternoon of a 

Gas Day as nominations made during the Evening Nomination Cycle are for gas flow on 

the following Gas Day.182 

114. With respect to DSPS’s proposal to change the scheduling priority of secondary

firm/alternate nominations in the Evening Nomination Cycle, NGSA and PGC contend 

the DSPS proposal would de-value secondary firm service183 and AGA argues that the 

 179 See, e.g., INGAA Comments at 9-10; National Grid Comments at 5; 

New England LDCs Comments at 32; PGC Comments at 8; Transwestern Comments at 

4.

180 PGC Comments at 9.

181 See, e.g., AGA Comments at 33; BHE Comments at 6-7; Dominion Comments 

at 12-13.

182 See, e.g., Dominion Comments at 12-13; PGC Comments at 9; Southwest IS 

Comments at 6.

183 NGSA Comments at 23; PGC Comments at 10.
Docket No. RM14-2-000 - 83 -

DSPS proposal would adversely affect gas customers by reducing revenues from 

secondary market sales that are used to mitigate the costs of holding firm capacity.184 

115. Several pipelines state that the proposal to allow primary-firm nominations to 

bump secondary firm nominations in the Evening Nomination Cycle would also 

negatively affect pipeline operations.185 INGAA states that pipeline operators need 

sufficient time after scheduling nominations, based on priority, to set up the pipeline 

system for the next Gas Day. INGAA contends that the adoption of the DSPS’s proposal 

effectively would shift this work from the period following the Timely Nomination Cycle 

to the period following the Evening Nomination Cycle because firm shippers will have 

little or no reason to submit primary firm nominations prior to the Evening Nomination 

Cycle. WBI and INGAA further note that the DSPS proposal would move the major 

confirmation and scheduling period outside of normal business hours, making it more 

difficult for a pipeline operator to confirm a shipper’s nomination with receipt and 

delivery point operators, producers and shippers.

116. Similarly, PGC and INGAA assert that delaying the posting of scheduled 

quantities until 10:00 p.m. CCT would cause uncertainty among firm shippers until after 

business hours, when few suppliers are staffed sufficiently to reroute or resell gas and the 

 184 AGA Comments at 34.

185 185 INGAA Comments at 11-12; Kinder Morgan Comments at 11; WBI 

Comments at 7.
Docket No. RM14-2-000 - 84 -

commodity market is not liquid, to learn whether the shipper’s gas was scheduled to flow 

the next Gas Day or be bumped.186 

117. Kinder Morgan notes that NAESB has recently developed capacity release 

standards (in conjunction with moving the Timely Nomination Cycle back to 1:00 p.m.) 

that will allow shippers to acquire released capacity in time to be nominated in the 

Timely Nominated Cycle.

187 Kinder Morgan states that the DSPS proposal would negate 

the benefit of this enhancement. 

118. Southern Company supports allowing primary-firm nominations to bump 

secondary firm nominations in the Evening Nomination Cycle.188 Southern Company 

suggests that a critical component of its plans for providing reliable, cost-effective 

electricity supply to customers calls for the maintenance of firm gas transportation and 

storage capacity to serve its gas-fired generators. Southern Company suggests that the 

value of holding firm transportation service to serve gas-fired generators is undermined, 

however, when an electric generator attempts to react to changes in demand only to find 

its contracted firm transportation capacity unavailable as a result of other shippers’ prior, 

secondary firm nominations. Southern Company believes the current policy sends the 

wrong signal to market participants who might otherwise choose to invest in firm service 

if they could be confident of their rights to exercise it as needed.

 186 PGC Comments at 11; INGAA Comments at 11-12.

187 Kinder Morgan Comments at 12.

188 Southern Companies at 11-12.
Docket No. RM14-2-000 - 85 -

119. Along the same lines, TVA argues that secondary out-of-path service should have 

no higher priority than interruptible transportation.189 TVA states that its access to its 

firm, in-path capacity is being jeopardized by shippers contracting for firm transportation 

on pipeline paths that do not deliver to their markets and subsequently nominating 

secondary firm transportation outside their primary path on a perpetual basis. This 

practice limits primary firm shippers’ ability to utilize their capacity after the Timely 

Nomination Cycle. TVA states that capacity is only built to support the primary path of 

firm transportation contracts and will not materialize when a shipper contracts for a 

specified firm transportation path, but chooses to nominate and flow on an entirely 

unrelated path.

120. Many commenters support consideration of the DSPS proposal on a regional basis 

by individual pipelines.190 Transwestern states that the proposal is workable and has 

been adopted on other pipelines.191 

2. Commission Determination 

121. The Commission declines to adopt DSPS’ proposal to move the Evening 

Nomination Cycle to 7:00 p.m. CCT or to modify the Commission’s policy on natural gas 

 189 TVA Comments at 4.

190 See, e.g., Dominion Comments at 13; Enhanced Reliability Coalition at 31-32; 

Sequent Comments at 6; NGSA Comments at 22. 

191 Transwestern Comments at 4-5.
Docket No. RM14-2-000 - 86 -

scheduling priority to require all pipelines to permit primary firm nominations to bump 

secondary firm nominations in the Evening Nomination Cycle. 

122. With respect to the proposed change to the Evening Nomination Cycle, DSPS fails 

to make clear how moving the start time of the Evening Nomination Cycle one hour later 

to 7:00 p.m. CCT provides shippers in its region with a more timely opportunity to 

address operating contingencies that arise fourteen hours later during the Gas Day. 

Starting the Evening Nomination Cycle at 7:00 p.m. CCT does not appear to address 

DSPS’s concerns with demand fluctuations, given that the Evening Nomination Cycle is 

for gas scheduled to flow the next Gas Day, not the current Gas Day. Also, under DSPS’ 

proposal, the Evening Nomination Cycle would occur at the same time as NAESB’s 

Intraday 3 Nomination Cycle. Given the wide support for the revised NAESB Evening 

Nomination Cycle and the largely unexplained benefits of moving the Evening 

Nomination Cycle later, we find that making such a change to the Evening Nomination 

Cycle is unwarranted. 

123. Regarding modifying Commission policy to require all pipelines to permit primary

firm nominations to bump scheduled secondary firm service in the Evening Nomination 

Cycle, the Commission finds that the benefits of that proposal do not outweigh the 

burdens that would be placed on all interstate pipelines and secondary firm shippers as a 

result of such proposal. Based on the comments, allowing primary firm to bump 

secondary firm would move the major confirmation and scheduling period outside of 

normal business hours, making it more difficult for a pipeline operator to confirm a 

shipper’s nomination with point operators, producers and shippers. It could also disrupt 
Docket No. RM14-2-000 - 87 -

the liquid secondary market for capacity by reducing the value of obtaining released 

capacity. For these reasons, the Commission declines to adopt this proposal on a national 

basis. 

C. 1-Year Pilot Program

124. DSPS also requests that Commission require, on a 1-year pilot program basis, the 

pipelines serving the Desert Southwest (i.e., El Paso Natural Gas, Transwestern and 

TransCanada-North Baja Pipelines) to allow firm shippers experiencing an unexpected 

increase in demand during the evening of the current Gas Day to submit a separate 

“retro/make-up” nomination during the Evening Nomination Cycle that would not take 

effect until the start of the next Gas Day but would make up for the unscheduled service 

they take during the current Gas Day. DSPS also proposes that the Pilot Program: 

(a) provide that imbalance charges/penalties only apply to imbalances that are not 

corrected by gas that flows at the start of the Gas Day; and (b) prohibit shippers from 

submitting a combination of a retro/make-up nomination and a daily nomination that 

exceeds the shipper’s Maximum Daily Quantity of its firm contract. DSPS states that, by 

allowing a retro/make up nomination to be submitted in the Evening Nomination Cycle, 

the firm shipper would be ensuring that the gas it uses to address the operating 

contingency would be injected into the pipeline beginning at the start of the next Gas 

Day.
Docket No. RM14-2-000 - 88 -

1. Comments

125. Kinder Morgan states that its pipelines that serve the DSPS stakeholders have been 

engaged in discussions with DSPS regarding their unique issues.

192 Kinder Morgan

states that the regional needs of the DSPS are best addressed on a pipeline-specific basis. 

Kinder Morgan also notes that El Paso has previously added additional nomination 

intraday cycles and offers various types of hourly services. Kinder Morgan states that the 

DSPS pilot program incorrectly assumes that pipelines have available unused capacity or 

other flexibility that would allow a shipper to unilaterally take whatever amount of gas it 

wants at 7:00 p.m. CCT and that the pipeline would entertain a retro or make-up 

nomination recognizing the shipper took the gas and returned it to the pipeline later. 

Kinder Morgan states that this proposal poses substantial problems for a pipeline by 

requiring the pipeline to keep the shipper whole for a good portion of the 24-hour Gas 

Day, placing its other deliveries at risk. Kinder Morgan states that in actuality this type 

of transaction calls for a no-notice type of transportation service and potentially requires 

new facilities, including storage. 

126. Transwestern states that, while further clarification is needed as to exactly what 

DSPS intends, Transwestern is willing to work with DSPS and other regional entities to 

structure retro/make-up nominations and help customers manage their loads in view of 

the unique operating circumstances of the Desert Southwest.193 

 192 Kinder Morgan Comments at 12.

193 Transwestern Comments at 5
Docket No. RM14-2-000 - 89 -

2. Commission Determination

127. As noted elsewhere in this Final Rule, regional solutions may work best to address 

certain needs arising from increased use of natural gas. While the Commission will not 

require the pipelines serving the Desert Southwest (i.e., El Paso Natural Gas, 

Transwestern and TransCanada-North Baja Pipelines) to implement DSPS’s proposed 

1-year pilot program, we encourage continued discussion in the region. The record here 

is insufficient for the Commission to require the pipelines to institute DSPS’ requested

pilot program of make-up nominations. The comments of the pipelines affected by this 

proposal indicate that they are uncertain of the operational feasibility of instituting a 

make-up nomination, but are interested in discussing this issue further with the DSPS 

shippers. Given the comments, we lack any evidence that requiring these pipelines to 

offer make-up nominations during the Evening Nomination Cycle is operationally 

feasible for all the pipelines. However, one or more pipelines appear willing to discuss 

potential service offerings that may help Desert Southwest shippers and we encourage 

those discussions to proceed. 

VI. Multi-Party Transportation Contracts

A. Background

128. The Commission’s regulations require that all transfers of firm pipeline capacity 

from one shipper to another shipper take place pursuant to the capacity release program 

in section 284.8 of our regulations to ensure that such capacity transfers are transparent 
Docket No. RM14-2-000 - 90 -

and not unduly discriminatory.194 Utilizing capacity release to effectuate sharing of 

capacity between entities can make sharing of capacity less efficient due to the need to 

comply with the capacity release posting and bidding requirements, as well as the need 

for the replacement shipper to enter into a contract with the pipeline for each release. In 

recent years, however, the Commission has accepted several pipeline proposals to offer 

multiple shippers the option of entering into a single contract for transportation service, 

with a single agent or asset manager managing the capacity under the contract.195 As 

approved by the Commission, this option permits several shippers to share the subject 

capacity without the need to use the capacity release program to transfer the capacity 

among themselves. In order to satisfy the Commission’s shipper-must-have-title policy, 

 194 See Pipeline Service Obligations and Revisions to Regulations Governing SelfImplementing Transportation and Regulation of Natural Gas Pipeline After Partial 

Wellhead Decontrol, Order No. 636, FERC Stats. & Regs. ¶ 30,939, at 30,416-20, order 

on reh'g, Order No. 636-A, FERC Stats. & Regs. ¶ 30,950, at 30,554 (1992). See also

Regulation of Short-Term Natural Gas Transportation Services and Regulation of 

Interstate Natural Gas Transportation Services, Order No. 637, FERC Stats. & Regs. 

¶ 31,091, at 31,300 (2000).

195 Southern Natural Gas Co., 124 FERC ¶ 61,145 (2008) (Southern) (pipeline 

modified Rate Schedule FT to allow a single contract option for multiple shippers 

affiliated with a single agent or asset manager); Florida Gas Transmission Co., LLC, 

128 FERC ¶ 61,284 (2009), order on compliance filing, Docket No. RP09-922-001 

(Nov. 17, 2009) (delegated letter order) (pipeline modified provisions of Rate Schedules 

FT and IT to allow a single contract option for multiple shippers that have designated a 

single agent on their behalf); Transcontinental Gas Pipe Line Corp., Docket No. RP10-

1099-000 (Sept. 14, 2010) (delegated letter order) (pipeline modified provisions of Rate 

Schedules IT, PAL and Pooling, and ICTS to allow a single contract option for multiple 

shippers that have designated a single agent on their behalf); Tennessee Gas Pipeline Co., 

L.L.C., 142 FERC ¶ 61,200 (2013) (Tennessee) (pipeline modified provisions of Rate 

Schedules FT, IT and PAL to allow a single contract option for multiple shippers that 

have designated a single agent on their behalf). 
Docket No. RM14-2-000 - 91 -

the pipelines proposed, and the Commission accepted, tariff provisions ensuring that each 

shipper under a multi-party transportation contract agree to be jointly and severally liable 

for all obligations of all shippers and the agent under the single service agreement.196 

The Commission has permitted multi-party transactions even when the shippers under 

such an agreement are not affiliated with one another.197 

129. This contracting flexibility has been utilized by entities to meet their collective 

load obligations in a more efficient manner. For example, certain affiliated utilities of 

Southern Company, which have long operated as an integrated public utility electric 

system through the joint commitment and economic dispatch of their gas-fired generating 

resources, have entered into a single interstate natural gas pipeline transportation service 

agreement, with Southern Company Services (their affiliated agent) arranging for the gas 

supplies used in their generating facilities.198 Under this single transportation service 

agreement, on any given day Southern Company Services can use up to its overall 

 196 See, e.g., Southern, 124 FERC ¶ 61,145 at P 12. As the Commission explained, 

multi-party contracts must include joint and several liability to comply with the 

Commission’s shipper-must-have-title policy. Without joint and several liability, 

shippers under the multi-party contracts that are not liable for the total charges under the 

agreement would be in violation of the Commission’s shipper-must-have-title policy to 

the extent they used capacity in excess of that for which they were liable to pay.

197 See, e.g., Florida Gas Transmission Co., LLC, 126 FERC ¶ 61,055 (2009).

198 See, e.g., Southern Natural Gas Co., Transmittal, Docket No. RP01-205-016 

(May 14, 2009); Southern, 124 FERC ¶ 61,145. The affiliates were Alabama Power 

Company, Georgia Power Company, Gulf Power Company, Mississippi Power 

Company, Savannah Electric and Power Company and Southern Power Company.
Docket No. RM14-2-000 - 92 -

contractual entitlement under the service agreement to provide service to any one of its 

affiliated utilities.

B. NOPR Proposal

130. The NOPR proposed to revise Part 284 of the Commission’s regulations to require 

interstate natural gas pipelines that offer firm transportation service under subpart B or G 

of Part 284 to allow multiple shippers associated with a designated agent or asset 

manager to be jointly and severally liable under a single firm transportation service 

agreement, subject to reasonable terms and conditions. Consistent with the multi-party 

contract tariff provisions the Commission previously approved, the NOPR stated that 

such reasonable terms and conditions may include requirements that: (1) the shippers 

and agent demonstrate their agency relationship in writing; and (2) the shippers are 

willing to be treated collectively as one shipper for nomination, allocation, and billing 

purposes under the contract. 

131. As explained in the NOPR, the use of shared capacity can make the purchase of 

firm pipeline capacity more affordable, including for gas-fired generators. For example, 

a gas-fired generator could decide to defray its pipeline capacity costs by sharing capacity 

among a number of generators or by sharing capacity with a LDC that has differing peak 

needs for natural gas transportation service. Similarly, an industrial plant, which has a 

relatively constant need for gas when its plant is operating but which has the flexibility to 

reduce its operations and gas usage on relatively short notice, could arrange to share its 

capacity with another shipper, such as a gas-fired generator, which only needs gas during 

short intervals and which has less control over when it runs. Permitting such entities to 
Docket No. RM14-2-000 - 93 -

enter into a single contract with the pipeline gives those entities the flexibility to choose 

contracting partners with complementary needs for pipeline capacity and to enter into an 

ongoing contractual relationship concerning how they will share the capacity.

132. The Commission’s NOPR proposal would only require pipelines to offer 

multi-party service agreements for firm service because a primary benefit of such service 

agreements is that they permit entities to share firm capacity without the need to engage 

in capacity releases. However, in recognition of the fact that some pipelines currently 

offer multi-party service agreements to interruptible customers as well, the Commission 

requested comment on whether it should also require pipelines to offer multi-party 

service agreements for interruptible transportation service.

C. Comments

133. Ten commenters either support or do not oppose the NOPR proposal.

199 They 

contend that the proposal will provide shippers, including gas-fired generators, with 

greater flexibility and facilitate more efficient use of pipeline capacity. 

134. Many commenters express varying degrees of qualified support for the NOPR 

proposal.

200 IOGA asserts that the concept could be valuable not just for gas-fired 

 199 AGA Comments at 37-38; AGLR LDCs Comments at 3; Duke Comments 

at 4-5; FirstEnergy Comments at 9; MSCG Comments at 18; National Grid Comments 

at 5; New England LDCs at 34; NiSource Comments at 3; PUCO Comments at 8-9; 

Southern Star Comments at 6.

200 AF&PA Comments at 4; BHE Comments at 17-18; EnerVest Comments at 7; 

IECA Comments at 2-4; INGAA Comments at 32-33; IOGA Comments at 5-6; Kinder 

Morgan Comments at 15; NGSA Comments at 24-25; PGC Comments at 7; Spectra 

Comments at 9.
Docket No. RM14-2-000 - 94 -

generators, but also for small producers as an alternative to interruptible transportation 

and a tool to help optimize capacity and ensure that they have a firm outlet for gas.201 

IOGA, along with EnerVest, urges the Commission, however, to grant blanket waivers of 

the shipper-must-have-title policy in order to facilitate multi-party transportation 

agreements.202 Several commenters argue that the Commission should leave it to 

individual pipelines to propose such services in response to customer needs.203 INGAA 

states that even on pipelines that currently allow multi-party contracts, customer response 

has been limited.204 INGAA requests that the Commission either reconsider the addition 

of section 284.12(b)(1)(v) to the Commission’s regulations or modify the regulatory text 

to provide that:

Within 60 days upon a shipper request, a pipeline will file to make

appropriate tariff changes at the Commission to allow multiple shippers

associated with a designated agent or asset manager to be jointly and

severally liable under a single firm transportation service agreement,

subject to reasonable terms and conditions. (emphasis added)

135. AF&PA, IECA, NGSA, and PGC support the concept of making multi-party 

transportation contracts more widely available, provided that the Commission can ensure 

that multi-party contracts are transparent, do not adversely affect existing shippers, 

 201 IOGA Comments at 5-6.

202 EnerVest Comments at 7-8; IOGA Comments at 6.

203 Dominion Comments at 28-29; INGAA Comments at 31-32; Kinder Morgan 

Comments at 14-16; Southern Comments at 13.

204 INGAA Comments at 31.
Docket No. RM14-2-000 - 95 -

comply with all pipeline tariffs, and do not unduly discriminate against other shippers.205 

Along those lines, AF&PA, IECA, and PGC urge the Commission to clarify that 

individual shippers must be publicly disclosed, not just the designated contract agent or 

asset manager under the multi-party transportation contract.206 AF&PA, IECA, and 

NGSA also suggest that the Commission should closely monitor and take action if 

increased utilization of multi-party contracts substantially reduces the competitiveness of 

the secondary market.207

136. Other commenters urge the Commission to require certain provisions that have 

already been approved in other proceedings involving multi-party transportation contracts 

(e.g., shippers and agents must demonstrate their agency relationship in writing).208 BHE 

supports the NOPR proposal, provided the affected interstate natural gas pipelines are 

adequately protected financially by way of creditworthiness terms and conditions.

209

137. Several commenters who support the concept of multi-party transportation 

contracts, nevertheless request a number of clarifications regarding the terms and 

 205 AF&PA Comments at 3-5; IECA Comments at 2-4; NGSA Comments at 24-

26; PGC Comments at 6-8.

206 AF&PA Comments at 3-5; IECA Comments at 2-4; PGC Comments at 6-8.

207 AF&PA Comments at 3-5; IECA Comments at 2-4; NGSA Comments at 24-

26.

208 See, e.g., INGAA Comments at 32-33; Kinder Morgan Comments at 15; 

Spectra Comments at 9.

209 BHE Comments at 18.
Docket No. RM14-2-000 - 96 -

conditions of service for multi-party transportation contracts. MSCG urges the 

Commission to clarify scenarios involving liability, events of default, billing and 

payment, and shipper-must-have-title.210 NGSA requests several clarifications on 

confidentiality and the consolidation of existing agreements into a single multi-party 

transportation contract.211 Puget requests that the Commission clarify how capacity and 

costs are shared amongst the parties under a multi-party transportation agreement.212 

138. Some commenters assert that the Commission should convene technical 

conferences or workshops or perform further evaluation to further explore some of the 

issues discussed above and other implementation issues before adopting the proposed 

regulation.213

139. Idaho Power, Sequent, and Tenaska oppose the NOPR proposal, arguing that 

multi-party transportation contracts will not offer any additional benefits to the reliability 

of gas supply to generators than the Commission’s current capacity release program or 

current pipeline service offerings.

214 For example, Tenaska asserts that the NOPR’s 

proposal would carve out an exception to the capacity release rules for multi-party 

 210 MSCG Comments at 18-19.

211 NGSA Comments at 26.

212 Puget Comments at 31-32.

213 Dominion Comments at 28-29; EEI Comments at 5-6; Exelon Comments at 12; 

Puget Comments at 32; Sequent Comments at 9-10; Southern Comments at 13-14.

214 Idaho Power Comments at 2; Sequent Comments at 8; Tenaska Comments at 5. 
Docket No. RM14-2-000 - 97 -

transportation contracts and would depart from the goals of the program, including those 

regarding transparency, allocation to the party that values the released capacity the most, 

and by allowing private groups to control a certain amount of capacity outside of the 

capacity release process.215 Tenaska also states that the NOPR proposal does not address 

whether or how any amount of the shared capacity, once under a multi-party 

transportation contract, can be re-released, or whether the designated agent or Asset 

Manager may use the capacity. 

140. Sequent is concerned that the parties to a multi-party service agreement could 

receive preferential treatment or status over non-multi-party capacity bidders in terms of 

capacity allocation, posting and bidding rules (including those for affiliates), credit 

requirements, application of shipper-must-have-title policy, prohibition on buy-sell 

arrangements, tying and other capacity release requirements. Sequent also requests 

clarification regarding open seasons and the consolidation of existing transportation 

agreements into a single multi-party transportation contract.216 

141. In response to the NOPR’s question regarding whether the Commission should 

require pipelines to offer multi-party interruptible contracts, AF&PA, Duke, EnerVest, 

NGSA, and PGC support or do not oppose offering multi-party transportation contracts 

 215 Tenaska Comments at 6-7.

216 Sequent Comments at 9.
Docket No. RM14-2-000 - 98 -

for interruptible service.217 However, Dominion, INGAA, and Kinder Morgan argue 

against it.218 EnerVest argues that, in the case of affiliated capacity-sharing shippers, 

allowing a single affiliated agent or asset manager to interface with the pipeline in 

connection with interruptible transportation services would provide potential 

administrative benefits for both shippers and pipelines alike, and would contribute to 

greater efficiency in overall utilization of total interstate natural gas pipeline 

transportation capacity.219 To the contrary, INGAA argues that an interruptible 

transportation multi-party service agreement would not provide generators with any 

additional ability to offset the costs of holding an interruptible transportation contract, 

since there are none, and would not provide any additional incentives for generators to 

enter into an interruptible transportation agreement, since that incentive is there 

already.220 Dominion makes similar arguments.221

D. Commission Determination

142. In this Final Rule, the Commission adopts section 284.12(b)(1)(iii) as proposed in

the NOPR, with the modification requested by INGAA. Instead of requiring all interstate 

 217 AF&PA Comments at 5; Duke Comments at 5; EnerVest Comments at 9; 

NGSA Comments at 26; PGC Comments at 7 & n.7.

218 Dominion Comments at 29; INGAA Comments at 33-34; Kinder Morgan 

Comments at 16.

219 EnerVest Comments at 9.

220 INGAA Comments at 33-34.

221 Dominion Comments at 29.
Docket No. RM14-2-000 - 99 -

pipelines at this time to modify their tariffs to offer multi-party firm transportation 

contracts, the Commission will only require pipelines to offer such an option if requested 

to do so by a shipper. Specifically, section 284.12(b)(1)(iii) as adopted in this Final Rule, 

requires that within 60 days of a shipper request, a pipeline must file to make appropriate 

tariff changes to allow multiple shippers associated with a designated agent or asset 

manager to be jointly and severally liable under a single firm transportation service 

agreement, subject to reasonable terms and conditions.

143. As noted by many commenters, the availability of multi-party firm transportation 

contracts will provide shippers, including gas-fired generators, with greater flexibility and 

facilitate more efficient use of pipeline capacity. In addition, section 284.12(b)(1)(iii) as 

adopted ensures that pipelines are responsive to shipper requests when, and if, a shipper 

is interested in pursuing a multi-party transportation agreement, while not requiring 

pipelines to implement tariff provisions offering that option where there is no shipper 

interest. Postponing implementation in this regard would not appear to unduly delay use 

of multi-party transportation contracts by interested shippers given the time necessarily 

involved in finalizing a multi-party arrangement, 

144. Upon an individual pipeline’s filing to implement multi-party transportation 

contracts, customers and other interested persons will have the opportunity to raise any 

concerns regarding the pipeline’s filing, including any accompanying terms and 

conditions proposed by the individual pipeline. Commenters who have raised questions 

or requested clarifications in this proceeding regarding accompanying terms and 

conditions, such as creditworthiness, capacity release, open seasons, existing agreements, 
Docket No. RM14-2-000 - 100 -

events of default, liability, and billing and payment, will have the opportunity to seek 

such clarifications in the individual pipeline proceedings, thereby giving the individual 

pipeline the first opportunity to address any such concerns.

145. Tenaska and other commenters raise concerns regarding transparency and the 

impact of the multi-party transportation contracts on the capacity release market. In 

recent years, the Commission has accepted several pipeline proposals to offer multiple 

shippers the option of entering into a single contract for transportation service, with a 

single agent or asset manager managing the capacity under the contract.222 The 

Commission has received no indication of any problems surrounding such multi-party 

transportation contracts or of a negative impact on the capacity release market resulting 

from such contracts. Furthermore, as INGAA notes, customer use of such contracts has 

been limited.223 There are also safeguards in the revised regulatory text and under 

existing regulations. The revised regulatory text requires shippers under a multi-party 

contract to be jointly and severally liable in order to satisfy the Commission’s shippermust-have-title policy, thereby limiting the option to shippers who value the capacity 

sufficiently to agree to be liable for all payments under the contract. Commission 

regulations also require that all interstate pipelines must publicly post information 

 222 See, e.g., Southern, 124 FERC ¶ 61,145; Florida Gas, 128 FERC ¶ 61,284,

order on compliance filing, Docket No. RP09-922-001 (Nov. 17, 2009) (delegated letter 

order); Transcontinental Gas Pipe Line Corp., Docket No. RP10-1099-000 (Sept. 14, 

2010) (delegated letter order); Tennessee, 142 FERC ¶ 61,200. 

223 INGAA Comments at 31.
Docket No. RM14-2-000 - 101 -

regarding any contract for firm transportation, or revision thereto, including shipper name 

and the rate charged under the contract.224 Interstate pipelines would continue to have 

this obligation with respect to multi-party transportation contracts, including posting the 

name of each shipper that is a party to the multi-party contract. With respect to concerns 

about undue discrimination or preference, section 4(b) of the NGA prohibits undue 

discrimination or preference by interstate pipelines. On balance, the Commission 

believes that the regulation adopted by this Final Rule, together with existing safeguards, 

strikes a reasonable balance between offering shippers greater contracting flexibility and 

protecting other shippers, as well as the pipeline. The Commission will also continue to 

monitor the use of multi-party transportation contracts.

146. The Commission denies EnerVert and IOGA’s alternative request that the 

Commission grant a blanket waiver of the shipper-must-have-title policy to permit 

shippers to more easily share capacity. As the Commission has previously explained, the 

capacity release program was designed with the shipper-must-have-title rule as its 

foundation. That rule ensures that transfers of capacity among shippers must take place 

through the capacity release program, thus ensuring that such capacity transfers are 

transparent and not unduly discriminatory.225 Therefore, the Commission will not grant a 

generic waiver of the shipper-must-have-title rule in this rulemaking proceeding.

However, the Commission is open to considering requests for waiver of its capacity 

 224 See 18 CFR 284.13 (2014).

225 Order No. 637, FERC Stats & Regs. ¶ 31,091 at 31,300 (2000). 
Docket No. RM14-2-000 - 102 -

release regulations and/or the shipper-must-have-title rule on a case-by-case basis, where 

it is shown that such a waiver would be in the public interest, for example by assisting 

natural gas-fired generators in obtaining access to firm transportation service in a 

transparent and not unduly discriminatory manner.226 

147. Several commenters raise questions regarding the rights and responsibilities of the 

individual parties to a multi-party transportation contract, as well as the responsibilities of 

the agent or asset manager. In general, rights and responsibilities related to the shippers’ 

relationship to the pipeline will be determined by the individual pipeline’s tariff, but 

rights and responsibilities as between the shippers and their agent or asset manager, such 

as how capacity is allocated between the contracting parties on any given day, will be 

determined by the parties and the agent or asset manager to the transportation contract. 

148. The Commission will not require multi-party service contracts for interruptible 

transportation. As INGAA points out, unlike firm shippers, interruptible shippers do not 

have any obligation to pay a monthly reservation charge and only pay transportation 

charges when they utilize the service. Thus, there is no existing financial impediment to 

generators or others entering into interruptible transportation contracts. Unlike multiparty contracts for firm service, an interruptible multi-party transportation contract would 

not provide generators with any additional ability to offset the costs of holding an 

 226 See Georgia Pub. Serv. Comm’n, 107 FERC ¶ 61,024, at P 36 (2004), reh’g 

granted in part, denied in part, 110 FERC ¶ 61,048 (2005), reh’g denied, 111 FERC 

¶ 61,178 (2005), and Promotion of a More Efficient Capacity Release Market, Order 

No. 712-A, FERC Stats. & Regs. ¶ 31,284, at P 146 (2008), order on reh’g and 

clarification, Order No. 712-B, 127 FERC ¶ 671,051 (2009).
Docket No. RM14-2-000 - 103 -

interruptible transportation agreement. The limited administrative benefits identified by 

EnerVest do not appear to warrant requiring interstate pipelines to provide such contracts 

for interruptible transportation. 

VII. Notice of Use of Voluntary Consensus Standards

149. Office of Management and Budget Circular A-119 (§ 11) (February 10, 1998) 

provides that federal agencies issuing or revising regulations with a standard should 

publish a statement in the Final Rule identifying the adopted standard as being a 

voluntary consensus standard or a government-unique standard. In this Final Rule, the 

Commission is incorporating by reference voluntary consensus standards developed by 

the NAESB WGQ. In section 12(d) of NTT&AA, Congress affirmatively requires 

federal agencies to use technical standards developed by voluntary consensus standards 

organizations to carry out policy objectives or activities determined by the agencies 

unless use of such standards would be inconsistent with applicable law or otherwise 

impractical.227

VIII. Incorporation By Reference

150. The Office of the Federal Register requires agencies incorporating material by 

reference in final rules to discuss, in the preamble of the final rule, the ways that the 

materials it incorporates by reference are reasonably available to interested parties and 

 227 Pub L. No. 104-113, 12(d), 110 Stat. 775 (1996), 15 U.S.C. 272 note (1997).
Docket No. RM14-2-000 - 104 -

how interested parties can obtain the materials.228 The regulations also require agencies 

to summarize, in the preamble of the final rule, the material it incorporates by reference.

151. The NAESB standards being incorporated by reference in this Final Rule are 

summarized in P 23, 87, 104. Our regulations provide that copies of the NAESB 

standards incorporated by reference may be obtained from the North American 

Energy Standards Board, 801 Travis Street, Suite 1675, Houston, TX 77002, 

Phone: (713) 356–0060. NAESB’s Web site is at http://www.naesb.org/. Copies may be 

inspected at the Federal Energy Regulatory Commission, Public Reference and 

Files Maintenance Branch, 888 First Street, NE., Washington, DC 20426, 

Phone: (202) 502–8371, http://www.ferc.gov.229

152. NAESB is a private consensus standards developer that develops voluntary 

wholesale and retail standards related to the energy industry. The procedures utilized by 

NAESB make its standards reasonably available to those affected by the Commission 

regulations. Participants can join NAESB, for an annual membership cost of only

$7,000, which entitles them to full participation in NAESB and enables them to obtain 

these standards at no cost.230 Non-members may obtain the Individual Standards Manual 

or Booklets for each standard by email for $250 per manual or booklet, which in the case 

 228 1 CFR 51.5 (2014). See Incorporation by Reference, 79 FR 66267 (Nov. 7, 

2014). 

229 18 CFR 284.12 (2014).

230 North American Energy Standards Board Membership Application, 

https://www.naesb.org/pdf4/naesbapp.pdf.
Docket No. RM14-2-000 - 105 -

of these standards would total $1,000.231 Nonmembers also may obtain the complete set 

of Standards Manuals, Booklets, and Contracts on CD for $2,000. NAESB also provides 

a free electronic read-only version of the standards for a three business day period or, in 

the case of a regulatory comment period, through the end of the comment period.232 In 

addition, NAESB considers requests for waivers of the charges on a case by case basis 

depending on need. The parties affected by these Commission regulations are highly 

sophisticated and have the means to acquire the information they need to effectively 

participate in Commission proceedings.

IX. Information Collection Statement 

153. The collections of information for this Final Rule are being submitted to the Office 

of Management and Budget (OMB) for review under section 3507(d) of the Paperwork 

Reduction Act of 1995233 and OMB’s implementing regulations.234 OMB must approve 

information collection requirements imposed by agency rules. The burden estimates for 

this Final Rule are for one-time implementation of the information collection 

 231 NAESB Materials Order Form, https://www.naesb.org//pdf/ordrform.pdf.

232 Procedures for non-members to evaluate work products before purchasing, 

https://www.naesb.org/misc/NAESB_Nonmember_Evaluation.pdf . See Incorporation 

by Reference, 79 FR at 66271, n. 51 & 53(Nov. 7, 2014) (citing to NAESB’s procedure 

of providing “no-cost, no-print electronic access”, NAESB Comment, at 1, available at 

http://www.regulations.gov/#!documentDetail;D=OFR-2013-0001-0023).

233 44 U.S.C. 3507(d) (2012).

234 5 CFR 1320 (2014).
Docket No. RM14-2-000 - 106 -

requirements of this Final Rule (including tariff filing, documentation of the process and 

procedures, and IT work), and ongoing burden.

154. The Commission solicits comments from the public on the Commission's need for 

this information, whether the information will have practical utility, the accuracy of the 

burden estimates, recommendations to enhance the quality, utility, and clarity of the 

information to be collected, and any suggested methods for minimizing respondents' 

burden, including the use of automated information techniques. The burden estimates are 

for implementing the information collection requirements of this Final Rule. The 

Commission asks that any revised burden estimates submitted by commenters include the 

details and assumptions used to generate the estimates.

155. The collections of information related to this Final Rule fall under FERC–545 

(Gas Pipeline Rates: Rate Change (Non-Formal)) 235 and FERC–549C (Standards for 

Business Practices of Interstate Natural Gas Pipelines).

236 The following estimates of 

reporting burden are related only to this Final Rule and include the costs to pipelines to:

(1) incorporate by reference NAESB’s modified nomination timeline, which includes:

moving the start of the Timely Nomination Cycle from 11:30 a.m. to 1:00 p.m. CCT and 

adding an additional intraday nomination opportunity; and (2) require interstate pipelines 

to file tariff changes with the Commission allowing multiple shippers associated with a 

 235 FERC-545 covers rate change filings made by natural gas pipelines, including 

tariff changes.

236 FERC-549C covers Standards for Business Practices of Interstate Natural Gas 

Pipelines.
Docket No. RM14-2-000 - 107 -

designated agent or asset manager to be jointly and severally liable under a single firm 

transportation service agreement within 60 days of receiving a request from a shipper for 

a multi-party service agreement. 

Public Reporting Burden:

RM14-2 Final Rule

Number of 

Respondents

237

(1)

Number of 

Responses 

per 

Respondent

(2)

Average 

Burden 

Hours Per 

Response

(3)

Total Annual 

Burden 

Hours

(1)x(2)x(3)

Total 

Annual 

Cost ($)238

FERC-545 (OMB Control No. 1902-0154)239

 237 An estimated 165 natural gas pipelines (Part 284 program) are affected by this 

Rulemaking. Although the additional intraday nomination and the revised same-day and 

day-ahead trading schedules may affect electric plant operators, the Commission is not 

imposing the reporting burden of adopting these standards on those entities.

238 The most recent hourly wage figures are published by the Bureau of Labor 

Statistics, U.S. Department of Labor, National Occupational Employment and Wage 

Estimates, United States, Occupation Profiles, May 2013, at 

http://www.bls.gov/oes/home.htm, and the benefits are calculated using BLS information, 

at http://www.bls.gov/news.release/ecec.nr0.htm. Each response to the proposed 

regulation in Column 1 is corresponds to a unique respondent.

239 The average hourly burden cost (salary plus benefits) related to tariff filings is 

$70.58. This represents the average wage (salary and benefits) of the following 

occupational categories: “Lawyers” ($128.94 per hour, top 10 percent of wage earners), 

“Computer Systems Analyst” ($58.77 per hour, average composite hourly wage), and 

“Office and Administrative” ($24.04 per hour, average composite hourly wage). Wage 

data is available from the Bureau of Labor Statistics at http://www.bls.gov/oes/home.htm; 

background on the estimate of the benefits component is at 

http://www.bls.gov/news.release/ecec.nr0.htm.
Docket No. RM14-2-000 - 108 -

Tariff Filing for 

new and revised 

Nomination 

Cycles

(one-time)240 165 1 10 1,650 $116,457241

Tariff Filing for 

Multi-Party 

Service 

Agreements 

(one-time)242 8 1 10 80 $5,646

FERC-549C (OMB Control No. 1902-0174)

Implementation 

of business 

standards, 

including 

process, 

procedures, and 

IT support (onetime)243 165 1 240 39,600 $2,524,500 

 240 Some of the estimated 165 natural gas pipeline companies (Part 284 program) 

may already utilize business practices that satisfy the NAESB proposal elements of this 

Rulemaking (e.g., provide additional nomination opportunities). In these instances the 

full cost of industry compliance is estimated for the total number of potential 

respondents.

241 The average (mean) hourly cost of tariff filings and implementation for 

interstate natural gas pipelines is $70.58. This represents the composite wage (salary and 

benefits) of the following occupational categories: “Lawyers” ($128.94 per hour, top 10 

percent of wage earners), “Computer Systems Analyst” ($58.77 per hour, average 

composite hourly wage), and “Office and Administrative” ($24.04 per hour, average 

composite hourly wage). Wage data is available from the Bureau of Labor Statistics at 

http://www.bls.gov/oes/home.htm; estimate of the benefits component at 

http://www.bls.gov/news.release/ecec.nr0.htm.

242 A majority of the 165 potential respondents operate under tariffs filed with the 

Commission that include provisions for multi-party transportation contracts. The 

Commission expects that approximately 8 of the 165 potential respondents (five percent), 

following an expression of shipper interest, will file tariffs each year with the 

Commission that support multi-party transportation contracts.

243 The average hourly cost is $63.75. This represents the average wage (salary 

and benefits) of the following occupational categories: “Lawyers” ($128.94 per hour, top 

(continued...)
Docket No. RM14-2-000 - 109 -

Annual 

operations, 

including 1 

additional 

intraday 

nomination

(ongoing) 244 165 365 0.5 30,113 $1,535,738

Total one-time

(for FERC-545 

and FERC549C) 39,680 $2,646,603

Total ongoing 

(for FERC549C) 30,113 $1,535,738

Information Collection Costs: The Commission estimates the total costs for all 

respondents to be:

• Year 1 (including the one-time tariff-filing, implementation, and ongoing costs): 

$4,182,341

• Years 2 and 3, each (ongoing costs only): $1,535,738

Title: FERC-545, Gas Pipeline Rates: Rate Change (Non-Formal); and

FERC-549C, Standards for Business Practices of Interstate Natural Gas Pipelines

 

10 percent of wage earners), “Computer Systems Analyst” ($58.77 per hour, average 

composite hourly wage), “Gas Plant Operator” ($43.24 per hour, average composite 

hourly wage), and “Office and Administrative” ($24.04 per hour, average composite 

hourly wage). 

244 For ongoing operations, we estimate 0.5 hours per calendar day per respondent 

(or 182.5 hours annually per respondent). 

The average hourly cost is $51. This represents the average wage (salary and 

benefits) of the following occupational categories: “Computer Systems Analyst” ($58.77 

per hour), and “Gas Plant Operator” ($43.24 per hour).
Docket No. RM14-2-000 - 110 -

Action: Proposed revisions to information collections

OMB Control Nos.: 1902-0154 (FERC-545) and 1902-0174 (FERC-549C). 

Respondents: Business or other for profit enterprise (Natural Gas Pipelines). 

Frequency of Responses: One-time filing and implementation and ongoing.

Necessity of Information: This Final Rule will upgrade the Commission’s current 

business practice and communication standards and supports the availability of multiparty firm contracts for interested shippers. 

156. In incorporating by reference NAESB’s modified nomination timeline, including 

moving the start of the Timely Nomination Cycle from 11:30 a.m. to 1:00 p.m. CCT and

adding an additional intraday nomination opportunity, the Commission intends to provide 

electric generators more time to acquire natural gas pipeline transportation, in order to 

reduce economic and resource supply constraints, additional flexibility to all shippers, 

allows sufficient time for processing, avoids overlapping nomination cycles, and allows 

for the accomplishment of most scheduling work during regular business hours, or 

reasonably close thereto. 

157. Broad industry consensus across the natural gas and electric industries during the 

NAESB deliberations supports the incorporation of the modified nomination timeline. 

The implementation of these standards and regulations will promote additional efficiency 

and reliability of the gas industry’s operations.

158. Finally, wider availability of multi-party firm transportation contracts provides

shippers greater flexibility, including gas-fired generators, and facilitates the efficient use 

of pipeline capacity. The Final Rule ensures that pipelines are responsive to shipper 
Docket No. RM14-2-000 - 111 -

requests when, and if, a shipper is interested in pursuing a multi-party transportation 

contract. As such, this Final Rule does not require pipelines to implement tariff 

provisions offering a multi-party transportation contract option when there is no shipper 

interest. 

Internal Review: The Commission has reviewed the proposed business practice 

standards of natural gas pipelines and has determined that the proposed revisions are 

necessary to establish more efficient coordination between the natural gas and electric 

industries, and to provide additional flexibility for all natural gas pipeline shippers. 

Requiring such information ensures common business practices for participants engaged 

in the sale of electric energy at wholesale and the transportation of natural gas. These 

requirements conform to the Commission's plan for efficient information collection, 

communication, and management within the natural gas pipeline industry. The 

Commission has assured itself, by means of its internal review, that there is specific, 

objective support for the burden estimates associated with the information requirements.

159. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].

160. Comments concerning the collections of information and the associated burden 

estimates should be sent to the Commission and to the Office of Management and 

Budget, Office of Information and Regulatory Affairs, Washington, DC 20503 

[Attention: Desk Officer for the Federal Energy Regulatory Commission, telephone: 
Docket No. RM14-2-000 - 112 -

(202) 395-0710, fax: (202) 395-4718]. For security reasons, comments to OMB should 

be submitted by e-mail to: oira_submission@omb.eop.gov. Comments submitted to 

OMB should include OMB Control Numbers 1902-0154 and 1902-0174.

X. Environmental Analysis

161. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.245 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this Final Rule under 

section 380.4(a) of the Commission’s regulations, which provides a categorical 

exemption for actions that are clarifying, corrective, or procedural, or that do not 

substantively change the effect of legislation or regulations being amended, for 

information gathering, analysis, and dissemination, or for the sale, exchange, or 

transportation of natural gas under sections 4, 5, and 7 of the Natural Gas Act that require 

no construction of facilities.

246

XI. Regulatory Flexibility Act Certification

162. The Regulatory Flexibility Act of 1980 (RFA)247 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

 245 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 

1986-1990 ¶ 30,783 (1987).

246 See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5), 380.4(a)(27) (2014).

247 5 U.S.C. 601-612.
Docket No. RM14-2-000 - 113 -

of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a rule and that minimize any significant economic 

impact on a substantial number of small entities. The Small Business Administration's 

(SBA) Office of Size Standards develops the numerical definition of a small business as 

matched to North American Industry Classification System Codes (NAICS).248 The 

SBA has established a size standard for pipelines transporting natural gas, stating that a 

firm is a small entity if its annual receipts (including those of its affiliates) are $27.5 

million or less.

249

163. This Final Rule applies only to interstate natural gas pipelines. The Commission 

estimates that approximately 165 interstate pipeline entities are potential respondents 

subject to the data reporting requirements of FERC-545. For fiscal year 2013, the 

Commission estimates that 70 pipelines (42.4 percent of 165 potential respondents) not 

affiliated with larger companies had annual revenues less than $27.5 million or less and 

are defined by the SBA as “small entities.”250 The Commission anticipates that the 

 248 13 CFR 121.101.

249 U.S. Small Business Administration, Table of Small Business Size Standards 

for Pipeline Transportation of Natural Gas, NAICS Code 486210, available at

https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf, Subsector 486.

Matched to North American Industry Classification System Codes, Natural Gas 

Pipeline Transportation, NAICS Code 486210, page 27, July 14, 2014, available at

https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf, Subsector 486.

250 Based on 13 CFR 121.201, Sectors 48-49, Subsector 486, NAICS Code 486210

for Pipeline Transportation of Natural Gas, the annual receipts indicate the maximum 

allowed for a concern and its affiliates to be considered “small.”
Docket No. RM14-2-000 - 114 -

estimated compliance cost of this Final Rule is $4,182,341 in Year 1 (an average of 

$25,348 per entity, including both one-time and ongoing costs), and $1,535,738 per year 

in Years 2 and 3 (or an annual average of $9,308 per entity for ongoing cost), regardless 

of entity size. The Commission does not consider the estimated impact per company to 

be significant. Additionally, the incorporation by reference of the revised NAESB 

standards, which reflect broad support from both industries, helps ensure the 

reasonableness of these standards in this Final Rule. Pipelines will need to file new 

tariffs with the Commission only if a) they do not currently offer multi-party 

transportation contracts, and b) shippers request that the pipeline offer such contracts.

164. Accordingly, pursuant to Section 605(b) of the RFA,251 this Final Rule should not 

have a significant economic impact on a substantial number of small entities.

XII. Implementation Schedule

A. Comments

165. Many commenters state that, to the extent the Commission adopts any changes to 

the gas scheduling timeline in this proceeding, the Commission must allow a sufficient 

time for implementation. INGAA, Kinder Morgan, and WBI state that scheduling 

changes would require a minimum of nine months to implement.252 A number of 

commenters also state that it will be important to implement any scheduling changes 

 251 5 U.S.C. 605(b).

252 INGAA Comments at 34-35; Kinder Morgan Comments at 16-17; WBI 

Comments at 8-9. 
Docket No. RM14-2-000 - 115 -

adopted in this proceeding when natural gas demand is low.253 INGAA states that any 

transition should occur outside the winter heating season (November through March) or 

summer peak season (May through August).254 April or October was suggested by 

INGAA.

166. AGA, EEI and Calpine contend that implementation of the changes to the naturalgas system as ordered in the Final Rule should occur concurrently with the 

implementation of the changes to electric system as ordered in the forthcoming ISO and 

RTO filings pursuant to the Section 206 Order.

255 

167. NAESB explains that upon the issuance of a Final Rule, NAESB will respond by 

integrating the Commission’s regulations into its standards within 90 days.256 However, 

NAESB notes that, while it will likely be able to respond to the Final Rule within the 

90 day deadline if it can use the expedited NAESB Minor Correction Process, if the 

NAESB Standards Development Process is used to respond to the Final Rule it may be 

challenging to meet the deadline. NAESB states that under the latter process multiple 

industry and member review periods are required and past expedited efforts have not 

been completed in under 90 days. 

 253 See, e.g., Calpine Comments at 14, Exelon Comments at 12; WBI Comments 

at 8 (citing Section 206 Order, 146 FERC ¶ 61,202). 

254 INGAA Comments at 35.

255 Calpine Comments at 17; EEI Comments at 7; NGSA Comments at 36.

256 NAESB November 26, 2014 Report at 1-2.
Docket No. RM14-2-000 - 116 -

B. Commission Determination 

168. The Commission will require interstate natural gas pipelines to comply with the 

revised NAESB standards that we are incorporating by reference in this Final Rule 

beginning on April 1, 2016. We are requiring this implementation schedule to give the 

interstate natural gas pipelines subject to these standards adequate time to implement 

these changes. In addition, pipelines must file tariff records to reflect the changed 

standards by February 1, 2016. The changes included in this Final Rule should benefit all 

pipeline shippers, including gas-fired generators. Accordingly, we will not require that 

the changes included in this Final Rule be implemented simultaneously with any changes 

resulting from the 206 Proceeding. 

169. In addition, consistent with the requirements in Order No. 587-V,257 the 

Commission is including the following compliance filing requirements to increase the 

transparency of the pipelines’ incorporation by reference of the NAESB WGQ Standards 

so that shippers and the Commission will know which tariff provision(s) implements each 

standard as well as the status of each standard.

(1) The pipelines must designate a single tariff section or tariff sheet(s) under 

which every NAESB standard is listed.258

 257 Standards for Business Practices of Interstate Natural Gas Pipelines, Order 

No. 587-V, FERC Stats. & Regs. ¶ 31,332, at PP 36-37 (2012).

258 This section should be a separate tariff record under the Commission’s 

electronic tariff filing requirements and is to be filed electronically using the eTariff 

portal using the Type of Filing Code 580.
Docket No. RM14-2-000 - 117 -

(2) For each standard, each pipeline must specify in the tariff section or tariff 

sheet(s) listing all the NAESB standards:

(a) whether the standard is incorporated by reference; 

(b) for those standards not incorporated by reference, the tariff provision 

that complies with the standard;259 and

(c) a statement identifying any standards for which the pipeline has been 

granted a waiver, extension of time, or other variance with respect to 

compliance with the standard.260

(3) If the pipeline is requesting a continuation of an existing waiver or 

extension of time, it must include a table in its transmittal letter that states the 

standard for which a waiver or extension of time was granted, and the docket 

number or order citation to the proceeding in which the waiver or extension was 

granted. 

170. This information will give Commission staff and all shippers a common location 

that identifies the manner in which the pipeline is incorporating all the NAESB WGQ 

Standards and the standards with which it is required to comply. The Commission will 

 259 For example, pipelines are required to include the full text of the NAESB 

nomination and capacity release timeline standards (WGQ Standards 1.3.2(i-v) and 5.3.2) 

in their tariffs. Standards for Business Practices of Interstate Natural Gas Pipelines, 

Order No. 587-U, FERC Stats. & Regs. ¶ 31,307, at P 39 & n.42 (2010). The pipeline 

would indicate which tariff provision complies with each of these standards.

260 Shippers can use the Commission’s electronic tariff system to locate the tariff 

record containing the NAESB standards, which will indicate the docket in which any 

waiver or extension of time was granted.
Docket No. RM14-2-000 - 118 -

post on its eLibrary website (under Docket No. RM14-2-000) a sample tariff record, to 

provide filers an illustrative example to aid them in preparing their compliance filings.

171. To reflect our decision in this Final Rule not to change the start of the Gas Day, 

NAESB will need to change its standards to reflect the start of the Gas Day at 9:00 a.m. 

CCT. Once NAESB has informed the Commission that it has revised its standards to 

make this change, we will incorporate these revised NAESB standards by reference into 

our regulations in an instant Final Rule.

XIII. Document Availability

172. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission's Home Page 

(http://www.ferc.gov) and in the Commission's Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

173. From the Commission's Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number excluding the last three digits of this 

document in the docket number field.

174. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from the Commission’s Online Support at (202) 502-6652 (toll 

free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 
Docket No. RM14-2-000 - 119 -

Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room 

at public.referenceroom@ferc.gov.

XIV. Effective Date and Congressional Notification

175. This final rule is effective [INSERT DATE 75 days after publication in the

FEDERAL REGISTER]. The incorporation by reference of certain publications listed 

in this rule is approved by the Director of the Federal Register as of [insert date 75 days 

after publication in the FEDERAL REGISTER]. The Commission has determined, 

with the concurrence of the Administrator of the Office of Information and Regulatory 

Affairs of OMB, that this rule is not a “major rule” as defined in section 351 of the Small 

Business Regulatory Enforcement Fairness Act of 1996.261 This final rule is being 

submitted to the Senate, House, and Government Accountability Office.

List of Subjects in 18 CFR Part 284

Natural gas

Reporting and recordkeeping requirements

Incorporation by Reference

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.

 261 5 U.S.C. 804(2).
Docket No. RM14-2-000 - 120 -

In consideration of the foregoing, the Commission amends Part 284, 

Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 284 – CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS 

UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED 

AUTHORITIES

1. The authority citation for Part 284 continues to read as follows:

Authority: 15 U.S.C. 717-717z, 3301-3432; 42 U.S.C. 7101-7352; 43 U.S.C. 

1331-1356.

2. Amend § 284.12 by revising the introduction to (a)(1) and paragraphs (a)(1)(vi) 

and (vii)and by adding new paragraphs (a)(1)(viii) and (ix) and (b)(1)(iii), to read as 

follows:

§ 284.12 Standards for pipeline business operations and communications.

(a)

(1) An interstate pipeline that transports gas under subparts B or G of this part 

must comply with the business practices and electronic communications standards as 

promulgated by the North American Energy Standards Board, as incorporated herein by 

reference in paragraphs (i) thru (vii) below, and as revised by WGQ 2014 Annual Plan 

Item 11c and Minor Correction MC14018, as incorporated herein by reference in 

paragraphs (viii) and (ix) below.

(i) ***

(ii) ***

(iii) ***

(iv) ***

(v) ***

(vi) Capacity Release Related Standards (Version 2.0, November 30, 2010, with 

Minor Corrections Applied Through January 5, 2012);

(vii) Internet Electronic Transport Related Standards (Version 2.0, November 30, 

2010, with Minor Corrections Applied Through January 2, 2011) with the exception of 

Standard 10.3.2; 

(viii) WGQ 2014 Annual Plan Item 11c, Parts 1 and 2 (September 22, 2014); and
Docket No. RM14-2-000 - 121 -

(ix) Minor Correction/Clarification, Request No. MC14018 Approved September 

10, 2014.

* * * * *

(b) ***

(1) ***

(i) ***

(ii) ***

(iii) Within 60 days after a shipper request, a pipeline must file to make 

appropriate tariff changes at the Commission to allow multiple shippers associated with a 

designated agent or asset manager to be jointly and severally liable under a single firm 

transportation service agreement, subject to reasonable terms and conditions.

* * * * *
Docket No. RM14-2-000 - 122 -

Note: The following appendix will not appear in the Code of Federal Regulations.

APPENDIX

Time Shifts -- All times CCT Current NAESB 

Standards

Revised 

NAESB

Standards

Timely

Timely Day-Ahead Nomination

Deadline 11:30 AM 1:00 PM

Confirmations 4:30 PM

Schedule Issued 4:30 PM 5:00 PM

Start of Gas Flow 9:00 AM

Evening

Evening Day-Ahead Nomination

Deadline 6:00 PM 6:00 PM

Confirmations 9:00 PM 8:30 PM

Schedule Issued 10:00 PM 9:00 PM

Start of Gas Flow 9:00 AM

Intraday 1

ID1 Nomination Deadline 10:00 AM 10:00 AM

Confirmations 1:00 PM 12:30 PM

Schedule Issued 2:00 PM 1:00 PM

Start of Gas Flow 5:00 PM 2:00 PM

IT Bump Rights bumpable bumpable

Intraday 2

ID2 Nomination Deadline 5:00 PM 2:30 PM

Confirmations 8:00 PM 5:00 PM

Schedule Issued 9:00 PM 5:30 PM

Start of Gas Flow 9:00 PM 6:00 PM

IT Bump Rights no bump bumpable

Intraday 3

ID3 Nomination Deadline 7:00 PM

Confirmations 9:30 PM

Schedule Issued 10:00 PM

Start of Gas Flow 10:00 PM

IT Bump Rights no bump