23198 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 284 

[Docket No. RM14–2–000; Order No. 809] 

Coordination of the Scheduling 

Processes of Interstate Natural Gas 

Pipelines and Public Utilities 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Final rule. 

SUMMARY: In this Final Rule, the Federal 

Energy Regulatory Commission 

(Commission) is revising its regulations 

to better coordinate the scheduling of 

wholesale natural gas and electricity 

markets in light of increased reliance on 

natural gas for electric generation, as 

well as to provide additional scheduling 

flexibility to all shippers on interstate 

natural gas pipelines. The revised 

regulations in this Final Rule modify the 

scheduling practices used by interstate 

pipelines to schedule natural gas 

transportation service and provide 

additional contracting flexibility to firm 

natural gas transportation customers 

through the use of multi-party 

transportation contracts. The revisions 

in this Final Rule, together with the 

Commission’s action in certain related 

proceedings, will better ensure the 

reliable and efficient operation of both 

the interstate natural gas pipeline and 

electricity systems. 

DATES: This rule will become effective 

July 8, 2015. The incorporation by 

reference of certain publications listed 

in this rule is approved by the Director 

of the Federal Register as of July 8, 2015. 

FOR FURTHER INFORMATION CONTACT: 

Anna Fernandez (Legal Information), 

Federal Energy Regulatory 

Commission, Office of the General 

Counsel, 888 First Street NE., 

Washington, DC 20426, (202) 502– 

6682. 

Caroline Daly Wozniak (Technical 

Information), Federal Energy 

Regulatory Commission, Office of 

Energy Policy and Innovation, 888 

First Street NE., Washington, DC 

20426, (202) 502–8931. 

SUPPLEMENTARY INFORMATION: 

ORDER NO. 809 

FINAL RULE 

Table Of Contents 

Paragraph 

numbers 

I. Background .......................................................................................................................................................................................... 4. 

A. Notice of Proposed Rulemaking ................................................................................................................................................ 12. 

B. NAESB ......................................................................................................................................................................................... 17. 

C. Subsequent Developments ......................................................................................................................................................... 21. 

II. Discussion .......................................................................................................................................................................................... 23. 

III. Gas Day .............................................................................................................................................................................................. 26. 

A. NOPR Proposal ........................................................................................................................................................................... 26. 

B. NOPR Comments ........................................................................................................................................................................ 28. 

C. Data Request and ISO and RTO Responses .............................................................................................................................. 49. 

D. Comments on Data Request ....................................................................................................................................................... 61. 

E. Commission Determination ........................................................................................................................................................ 62. 

IV. Natural Gas Transportation Nomination Timeline ......................................................................................................................... 71. 

A. Background ................................................................................................................................................................................. 71. 

B. Natural Gas Transportation Day-Ahead Cycles ........................................................................................................................ 75. 

1. NOPR Proposal ..................................................................................................................................................................... 78. 

2. Revised NAESB Day-Ahead Nomination Cycles ............................................................................................................... 82. 

3. NOPR Comments ................................................................................................................................................................. 84. 

4. Commission Determination ................................................................................................................................................. 87. 

C. Intraday Nomination Cycles ...................................................................................................................................................... 89. 

1. NOPR Proposal ..................................................................................................................................................................... 91. 

2. NAESB’s Revised Intraday Nomination Cycles ................................................................................................................. 93. 

3. Comments ............................................................................................................................................................................. 94. 

4. Commission Determination ................................................................................................................................................. 104. 

V. DSPS Proposal ................................................................................................................................................................................... 108. 

A. Background ................................................................................................................................................................................. 108. 

B. DSPS’s Proposed National Changes ........................................................................................................................................... 111. 

1. Comments ............................................................................................................................................................................. 112. 

2. Commission Determination ................................................................................................................................................. 121. 

C. 1-Year Pilot Program .................................................................................................................................................................. 124. 

1. Comments ............................................................................................................................................................................. 125. 

2. Commission Determination ................................................................................................................................................. 127. 

VI. Multi-Party Transportation Contracts .............................................................................................................................................. 128. 

A. Background ................................................................................................................................................................................. 128. 

B. NOPR Proposal ........................................................................................................................................................................... 130. 

C. Comments .................................................................................................................................................................................... 133. 

D. Commission Determination ....................................................................................................................................................... 142. 

VII. Notice of Use of Voluntary Consensus Standards ......................................................................................................................... 149. 

VIII. Incorporation By Reference ........................................................................................................................................................... 150. 

IX. Information Collection Statement ................................................................................................................................................... 153. 

X. Environmental Analysis .................................................................................................................................................................... 161. 

XI. Regulatory Flexibility Act Certification .......................................................................................................................................... 162. 

XII. Implementation Schedule ............................................................................................................................................................... 165. 

A. Comments ................................................................................................................................................................................... 165. 

B. Commission Determination ........................................................................................................................................................ 168. 

XIII. Document Availability ................................................................................................................................................................... 172. 

XIV. Effective Date and Congressional Notification ............................................................................................................................. 175. 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23199 

1NAESB 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. 

2California 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). 3See 18 CFR 284.12(a) and (b) (2014). 4The 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. 

6See, 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). 

1. In this Final Rule, the Federal 

Energy Regulatory Commission 

(Commission) revises Part 284 of the 

Commission’s regulations relating to the 

scheduling of transportation service on 

interstate natural gas pipelines to better 

coordinate the scheduling practices of 

the wholesale natural gas and electric 

industries, as well as to provide 

additional scheduling flexibility to all 

shippers on interstate natural gas 

pipelines. The Final Rule changes the 

nationwide Timely Nomination Cycle 

nomination deadline for scheduling 

natural gas transportation from 11:30 

a.m. Central Clock Time (CCT) to 1:00 

p.m. CCT and revises the intraday 

nomination timeline, to include adding 

an additional intraday scheduling 

opportunity during the gas operating 

day (Gas Day). The Final Rule 

effectuates these changes by 

incorporating by reference into the 

Commission’s regulations the standards 

developed and filed by the North 

American Energy Standards Board 

(NAESB).1 The revised regulations in 

this Final Rule also provide additional 

contracting flexibility to firm natural gas 

transportation customers through the 

use of multi-party transportation 

contracts. 

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. 

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. 

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 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. 

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23200 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

7FERC, 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. 

8Pro 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. 

9The Commission is directing ISOs and RTOs to 

make corresponding changes in the Section 206 

Order. 

10See, 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. 

11See, 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. 

12See 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. 

13The widespread and record low temperatures 

during January 2014 resulted in coincident record 

peak demand for natural gas throughout the 

Midwest, Northeast, Mid-Atlantic, and Southeast 

regions leading to constrained pipeline capacity 

and high natural gas prices. In addition, in February 

2014, arctic temperatures limited the availability of 

natural gas to supply New Mexico and Southern 

California leading CAISO to issue a system alert and 

a request for consumers to reduce power demand 

around the system. CAISO invoked increasingly 

stringent measures throughout the day to move 

generation off natural gas, reduce demand, and 

maintain sufficient supply to meet firm load. See 

FERC Staff Presentation ‘‘Recent Weather Impacts 

on the Bulk Power System,’’ January 16, 2014, 

http://www.ferc.gov/CalendarFiles/

20140116102908-A-4-Presentation.pdf. 

14See 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. 

15Staff 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. 

16Coordination 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. 

7. With respect to electric industry 

scheduling practices, the Commission 

has accepted regional variation in the 

development of scheduling practices in 

ISO and RTO electric markets, each of 

which has established its own 

scheduling timelines. For most electric 

utilities, the 24-hour operating day 

begins at 12:00 a.m. local time. The 

ISOs’ and RTOs’ practice of scheduling 

resources generally includes the 

commitment and dispatch of sufficient, 

deliverable generation to supply load in 

a reliable least cost manner, all based on 

generator availability and the 

transmission facilities that will be in 

service that day. To perform the unit 

commitment and dispatch processes 

used to develop daily resource 

schedules, each ISO and RTO has its 

own timeline for collecting supply 

offers from generators and expected 

demand from load serving entities on 

the day prior to the operating day. The 

ISOs and RTOs then run market 

algorithms that determine the least cost 

set of resources that can be used to serve 

the next day’s load. Each ISO and RTO 

also performs a reliability unit 

commitment process to procure 

resources, in addition to those resources 

committed to serve the load bid into the 

day-ahead market, as necessary to meet 

the ISO’s or RTO’s own forecast of the 

next day’s load or other system needs. 

Each ISO and RTO establishes its own 

timing for executing the day-ahead and 

reliability scheduling processes, 

including the times of day when bids 

and offers are due to the system 

operator, when the market and 

reliability processes are run, and when 

the results of the scheduling processes 

are made available to generators.7

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 schedule may be 

needed.9 Reliance on natural gas as a 

fuel for electric generation has steadily 

increased in recent years.10 This trend is 

expected to continue, resulting in 

greater interdependence between the 

natural gas and electric industries.11

Several events over the last few years, 

such as the Southwest Cold Weather 

Event 12 and the extreme and sustained 

cold weather events in the eastern U.S. 

in January 2014,13 show the crucial 

interrelationship between natural gas 

pipelines and electric transmission 

operators and underscore the need for 

improvements in the coordination of 

wholesale natural gas and electric 

markets. 

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

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 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23201 

17Coordination 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). 

18The Commission did not propose any changes 

to the Evening Nomination Cycle. 

19 16 U.S.C. 824e (2012). 20Section 206 Order, 146 FERC ¶ 61,202. 21 15 U.S.C. 717d. 22Posting of Offers to Purchase Capacity, 146 

FERC ¶ 61,203 (2014). See also 18 CFR 284.8(d) 

(2013). 

23The 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. 

24NAESB 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. 

28 Id. 

29 Id. at 10. 

with divergent interstate natural gas 

pipeline and wholesale electric utility 

scheduling practices, as well as 

concerns regarding the flexible and 

efficient use of pipeline capacity by 

natural gas-fired generators and other 

shippers.17

13. The NOPR proposed three changes 

to the nationwide natural gas 

scheduling practices: (1) Move the start 

of the Gas Day from 9:00 a.m. CCT to 

4:00 a.m. CCT; (2) move the start of the 

first day-ahead gas nomination 

opportunity for pipeline scheduling 

(Timely Nomination Cycle) from the 

current 11:30 a.m. CCT to 1:00 p.m. 

CCT;18 and (3) modify the current 

intraday nomination timeline to provide 

four intraday nomination cycles, instead 

of the existing two, to provide greater 

flexibility to all pipeline shippers. 

14. The NOPR also proposed to 

require interstate natural gas pipelines 

to offer multi-party transportation 

contracts to provide multiple shippers 

the flexibility to share interstate 

pipeline capacity to serve 

complementary needs in an efficient 

manner, and the NOPR provided 

clarification of the Commission’s nobump policy with respect to any 

enhanced nomination opportunity 

proposed by a pipeline (beyond the 

standard nomination opportunities). 

15. Recognizing that the natural gas 

and electricity industries were best 

positioned to work out the details of 

how changes in scheduling practices 

could most efficiently be made and 

implemented, the Commission provided 

the natural gas and electric industries, 

through NAESB, with a period of 180 

days after publication of the NOPR in 

the Federal Register to reach consensus 

on any revisions to the Commission’s 

proposals regarding the Gas Day and 

pipeline nomination timeline and either 

file consensus standards with the 

Commission or notify the Commission 

of the natural gas and electric 

industries’ inability to reach consensus 

on any revisions to the Commission’s 

proposals. Comments on NAESB’s 

consensus standards, as well as 

comments on the Commission’s 

proposals, were to be filed 240 days 

after publication of the NOPR in the 

Federal Register, or November 28, 2014. 

In the NOPR, the Commission stated 

that if the Commission were to adopt 

regulations that have not been approved 

by NAESB, it would expect NAESB to 

integrate the Commission’s regulations 

into its standards within 90 days of the 

effective date of the final rule and to 

notify the Commission when the 

standards have been approved. 

16. On the same day the NOPR was 

issued, the Commission issued two 

other orders, which, in conjunction with 

the NOPR, were designed to better 

ensure the reliable and efficient 

operation of both the interstate natural 

gas pipeline and electricity systems. In 

one order, the Commission instituted 

proceedings under section 206 of the 

Federal Power Act (FPA) 19 to ensure 

that each ISO’s and RTO’s scheduling 

practices, particularly its day-ahead 

scheduling practices, correlate with any 

revisions to the natural gas scheduling 

practices ultimately adopted by the 

Commission in the instant proceeding.20

In the Section 206 Order, the 

Commission required each ISO and RTO 

within ninety days of the publication of 

a Final Rule in this proceeding to: (1) 

Make a filing that proposes tariff 

changes to adjust the time at which the 

results of its day-ahead energy market 

and reliability unit commitment process 

(or equivalent) are posted to a time that 

is sufficiently in advance of the Timely 

and Evening Nomination Cycles, 

respectively, to allow gas-fired 

generators to procure natural gas supply 

and pipeline transportation capacity to 

serve their obligations; or (2) show 

cause why such changes are not 

necessary. In the second order, the 

Commission instituted proceedings, 

under section 5 of the Natural Gas Act 

(NGA) 21 to examine whether interstate 

natural gas pipelines are providing 

notice of offers to purchase released 

pipeline capacity in accordance with 

section 284.8(d) of the Commission’s 

regulations.22

B. NAESB 

17. Following issuance of the NOPR, 

NAESB reconvened the Gas Electric 

Harmonization (GEH) Forum as the 

platform for the gas and electric 

industries to consider the NOPR 

proposals, as well as to develop any 

consensus-based alternatives to the 

NOPR proposals.23 The GEH Forum was 

tasked with developing a 

recommendation for consideration by 

the NAESB Board of Directors (Board). 

The GEH Forum and NAESB Board 

convened several meetings between 

April and June 2014 with nearly five 

hundred active participants and over 

seven-hundred participants monitoring 

the activity, representing all facets of the 

wholesale gas and wholesale electric 

markets.24

18. Four alternatives to the NOPR 

proposal were considered during the 

final GEH Forum meeting.25 The dayahead and intraday nomination cycles 

in each package were the same,26 but 

the start of the Gas Day in each package 

was different. Disagreement over the 

start of the Gas Day prevented the GEH 

Forum from reaching consensus on any 

of the alternative proposals to the 

NOPR.27 The GEH Forum was also 

unable to reach consensus on an 

alternative proposal that did not define 

the Gas Day, but contained the same 

day-ahead and intraday nomination 

schedule as the four alternative 

proposals. Several participants 

expressed concern that any alternative 

proposal would be incomplete without 

a Gas Day start time, and indicated that 

they could not support a package that 

did not include the start of the Gas 

Day.28

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 

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23202 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

30NAESB reports that, in total, there are 

modifications to twenty-three NAESB WGQ 

Business Practice Standards: The NAESB WGQ 

Nomination Related Standard Nos. 1.1.18, 1.2.4, 

1.3.1, 1.3.2, 1.3.3, 1.3.4, 1.3.13, 1.3.14, 1.3.41, 

1.3.42, 1.3.51, and 1.3.80, the NAESB WGQ Flowing 

Gas Related Standard Nos. 2.2.5, 2.3.5, and 2.3.21, 

the NAESB WGQ Quadrant Electronic Delivery 

Mechanism Related Standard No. 4.3.90, and the 

NAESB WGQ Capacity Release Related Standard 

Nos. 5.3.2, 5.3.44, 5.3.45, 5.3.48, 5.3.49, 5.3.53, and 

5.3.54. NAESB states that, pursuant to the direction 

given by the NAESB Board of Directors, the NAESB 

WGQ Business Practice Standards are silent as to 

a start time of the Gas Day. Accordingly, references 

to the specific start time of the Gas Day in NAESB 

WGQ Standard No. 1.3.1 have been removed and 

replaced by the placeholder: [?]. Likewise, NAESB 

WGQ Standard No. 1.3.41 was revised to contain a 

generic reference to the start time of the Gas Day. 

NAESB states that, should the Commission identify 

a specific start time of the Gas Day, it will revise 

the language of the NAESB WGQ Business Practice 

Standards as necessary. NAESB WGQ Annual Plan 

Item 11c which modified the NAESB standards was 

approved by the NAESB WGQ Executive Committee 

and ratified by the NAESB membership on 

September 22, 2014. In addition, Minor Correction 

M14018 was applied to these standards effective 

October 10, 2014. 

31NAESB Sept. 29, 2014 Report at Appendix C. 

32New 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. 

33The Enhanced Reliability Coalition represents 

the views of a wide variety of electric and gas 

industry companies located throughout the United 

States and Canada that provide services such as 

natural gas production, interstate and intrastate gas 

pipeline transportation, natural gas distribution, 

natural gas procurement for core and industrial 

customers, natural gas procurement for electric 

generation, natural gas storage, electric generation, 

electric transmission, natural gas and electricity 

marketers, retail electric service, competitive retail 

electric and natural gas service, and electric 

procurement for customers. 

34NAESB’s WGQ Annual Plan Item 11c and 

Minor Correction MC14018. 35See Appendix. 

developed at the direction of the NAESB 

Board.30 The modified NAESB WGQ 

Business Practice Standards revise the 

nomination timeline to provide for three 

intraday nomination cycles in addition 

to the Timely and Evening Nomination 

Cycles. NAESB stated that nomination 

cycles are not dependent upon a 

specific start time to the Gas Day and 

are implementable with whichever time 

the Commission chooses as a start of the 

Gas Day. On November 26, 2014, 

NAESB filled another report to inform 

the Commission of the options the 

organization may pursue to respond to 

Commission action within the ninetyday 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, 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 Coalition 33 filed 

comments on the ISO and RTO 

responses. 

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. 

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 dayahead 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 nobump cycle, should afford firm 

transportation shippers, particularly 

those in the western United States, more 

of an opportunity to revise nominations 

to take into account weather and load 

changes. The comments in this 

proceeding show that these nationwide 

changes are supported broadly across 

the natural gas and electric industries. 

25. The Commission does not find a 

sufficient record at this time to revise 

the nationwide Gas Day start time as 

proposed in the NOPR. As discussed in 

more detail below, it is not clear that 

requiring a change in the Gas Day start 

time would provide sufficient benefits 

to outweigh the operational and safety 

impacts and costs of making such a 

change. The record developed here— 

including the comments received on the 

NOPR proposal and the data responses 

submitted by the ISOs and RTOs— 

suggests that the concerns underlying 

the proposal to change the Gas Day start 

time, to the extent they exist, are 

primarily regional in nature. As a result, 

we find that it is appropriate to allow 

the changes to the standard natural gas 

pipeline nomination timelines in this 

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36ACES 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. 

37Calpine Comments at 10–11; Essential Power 

Comments at 3; IRC Comments at 3; ISO–NE 

Comments at 3–4; PUCO Comments at 4. 

38Southern 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. 

39Southern 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 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. 

42ACES 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. 

45Equipower Comments at 8–9; Con Edison 

Comments at 7. 

46Southern Company Comments at 8. 

47 Id. 

48 ISO–NE Comment at 4. 

Final Rule, as well as changes to market 

rules and practices in the electric 

industry, to be implemented and 

evaluated without changing the 

nationwide Gas Day. While we will not 

revise the nationwide Gas Day in this 

proceeding, ongoing regional efforts to 

address electricity market reforms and 

fuel assurance, and the individual 

section 206 proceedings initiated by the 

Commission to review ISO and RTO 

day-ahead scheduling practices, provide 

opportunities to seek regional solutions 

to the concerns underlying the Gas Day 

proposal in the NOPR. 

III. Gas Day 

A. NOPR Proposal 

26. In the NOPR, the Commission 

proposed to move the start of the Gas 

Day from 9:00 a.m. CCT to 4:00 a.m. 

CCT. The Commission expressed 

concern about the potential impact of 

the difference in start times of the 

natural gas and electric operating days 

on the reliable and efficient operation of 

electric transmission system and 

interstate natural gas pipelines. 

Specifically, the Commission identified 

two problems resulting from the natural 

gas and electric operating days 

beginning at different times. First, the 

electric operating day currently extends 

over two Gas Days. Therefore, gas-fired 

generators committed across a single 

electric operating day must procure gas 

supply and schedule gas transportation 

across two Gas Days. Second, the 

current 9:00 a.m. CCT start of the Gas 

Day occurs in the middle of the morning 

electric load ramp in some regions, 

creating a situation where electric load 

is increasing at the same time natural 

gas-fired generators may be running out 

of their daily nomination of natural gas 

transportation service. 

27. The Commission proposed to 

move the start of the Gas Day earlier, to 

4:00 a.m. CCT, to address concerns 

expressed by several commenters—such 

as ISO–NE and NYISO—that the current 

Gas Day start time presents operational 

challenges resulting in gas-fired 

generators running out of scheduled 

natural gas capacity during the morning 

electric ramp period, and having to wait 

until 9:00 a.m. CCT before being able to 

rely on their next day gas nomination. 

The Commission stated that this change 

would mean that generators in all 

regions would be able to approach the 

morning electric peak, as well as most 

of the morning ramp period, with new 

daily gas nominations and, therefore, 

the proposal should largely eliminate 

the concern that some gas-fired 

generators will be unable to run during 

a substantial part of the morning electric 

ramp period because they have burned 

through their nominated gas before the 

start of the next Gas Day. 

B. NOPR Comments 

28. Thirteen commenters, particularly 

electric industry participants, filed 

comments in support of the 

Commission’s proposal to move the start 

of the Gas Day to 4:00 a.m. CCT.36 These 

commenters argue that, currently, 

operational problems and logistical 

challenges result from the electric 

operating day extending over two Gas 

Days and the fact that the current 9:00 

a.m. CCT Gas Day splits the morning 

electric load ramp into two Gas Days.37

Southern Company explains that under 

the current 9:00 a.m. CCT Gas Day, 

sharp early morning ramps in the winter 

take place at the end of the Gas Day 

resulting in gas-fired generators’ hourly 

gas usage markedly increasing over the 

last eight hours of the Gas Day.38

According to Southern Company, 

because of this timing its system 

operators’ option for ensuring sufficient 

fuel to meet the requirements of the 

morning ramp is limited to holding back 

consumption during the prior evening 

peak.39

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

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 dayahead Timely Nomination Cycle—the 

most liquid cycle—to cover the morning 

electric ramp and the evening peak of a 

single electric day while also being able 

to make adjustments throughout the day 

in the intraday cycles.42 IRC and ISO– 

NE state that planning for and including 

the entire morning electric ramp in the 

initial Gas Day operating plan is 

inherently more reliable to serve electric 

load requirements.43 ISO–NE states that 

moving the start of the Gas Day earlier 

should address instances when gas-fired 

generators find they are running out of 

scheduled natural gas capacity during 

the morning ramp period and have to 

wait until the 9:00 a.m. CCT start of the 

Gas Day to obtain additional supply or 

transportation.44 Equipower and Con 

Edison state that changing the start of 

the Gas Day will benefit system 

reliability in that generators exhausting 

their gas supply prior to the end of the 

Gas Day will do so during the middle of 

the night, when both the gas and electric 

systems are in a relatively low-load, 

steady-state condition and electric 

system operators have more flexibility 

to increase output from slow-ramping 

units, instead of during the morning 

ramping hours.45 Southern Company 

explains that with the start of the Gas 

Day moved to 4:00 a.m. CCT, operators 

can eliminate five hours of significant 

gas burn from the latter half of the 

preceding Gas Day and shift the steepest 

part of the morning ramp into the 

beginning of the next Gas Day when 

operators have the most flexibility to 

address their needs by adjusting gas 

scheduling and/or generation for the 

remaining hours.46 This shift would 

eliminate the current problem of system 

operators holding back gas consumption 

during the evening peak because of the 

morning electric ramp.47

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 

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49Con Edison Comments at 7–8. 

50 Id. at 8–9. 

51AF&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. 

53AGA 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. 

54BHE 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. 

55BHE 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. 

57See 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. 

58AGA Comments at 31. 

59NiSource Comments at 7. 

60AGA 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. 

61New 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. 

62CenterPoint 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. 

64AGA 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. 

65These 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 

period. According to Con Edison, this 

would allow natural gas system 

operators time to respond before loads 

reach their peak by, for example, 

shifting receipts among gate stations 

and/or utilizing on-system storage if 

there is an event on its system.49

Furthermore, Con Edison states that 

forecast deviations should also be 

reduced if a 4:00 a.m. CCT start of the 

Gas Day is approved because it would 

minimize the time between when 

natural gas is purchased and nominated 

and when it is consumed.50

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 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 longterm 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

35. Numerous commenters raise 

concerns regarding the potential for 

adverse impacts on reliability and safety 

and the danger of increased operational 

risk to the natural gas industry resulting 

from a 4:00 a.m. CCT Gas Day, 

particularly in the west.57 For example, 

AGA states that the vast natural gas 

infrastructure is, in many instances, 

unmanned and not supported 

electronically, thus often requiring the 

dispatch of personnel to remote 

worksites to make the necessary 

physical changes to maintain services 

and operations.58 INGAA and NiSource 

explain that, despite the industry’s 

move toward the use of automated 

systems such as supervisory control and 

data acquisition (SCADA), there are still 

numerous situations in which a pipeline 

needs to employ on-site field 

technicians to staff certain types of 

equipment to ensure safe and efficient 

facility operations and to make any 

necessary manual adjustments.59

Commenters argue that changing the 

start of the Gas Day to 4:00 a.m. CCT 

may create operational and safety risks 

due to the increased need for field work 

along the gas supply chain during 

nighttime hours, particularly during 

emergency situations when bad weather 

may exacerbate the effects of darkness.60

New England LDCs state that while 

LDCs would take additional precautions 

to mitigate the risk of employees 

undertaking tasks when it is fully dark, 

even with artificial lighting, the total 

light available is likely to be less than 

that provided by natural daylight and 

that electric power is not available in 

many places.61

36. Numerous commenters argue that 

a 4:00 a.m. CCT Gas Day would result 

in performing certain critical operations, 

which require complex and risky 

worker decision making, at a time when 

many operators may suffer from fatigue 

or lack of concentration.62 Commenters 

state that this change would increase the 

risk of worker error, impaired reaction 

time, situational awareness, judgment, 

attention, memory and resulting 

accidents and injury to personnel due to 

fatigue from interrupted sleep cycles.63

Commenters cite studies identifying 

serious and substantial pipeline safety 

risks due to human fatigue in the 

Control Room and providing 

recommendations to avoid critical 

decision making and communication 

between 2:00 a.m. and 6:00 a.m. local 

time.64

37. AGA, New England LDCs, and 

CenterPoint contend that a flurry of 

significant activities occur 

approximately three hours before or at 

the start of the Gas Day 65 and that these 

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storage injections or withdrawals, planning for 

intraday gas flow changes, evaluating volume 

balancing needs of the current day, and adjusting 

peaking supply. 

66AGA Comments at 29; CenterPoint at n. 7; New 

England LDCs Comments at 21. 

67AGA 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. 

68National Grid Comments at 4. 

69Texas 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. 

70CPG Comments at 7. 

71NGSA Comments at 12; INGAA Comments at 

19. 

72Enhanced 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. 

73AGA 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. 

76For 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. 

78New England LDCs Comments at 23–24; NW 

Industrial Gas Users Comments at 4. 

79AF&PA Comments at 9–10; Enhanced 

Reliability Coalition Comments at 19. 

80AF&PA Comments at 9–10; Enhanced 

Reliability Coalition Comments at 20; MSCG 

Comments at 12–13. 

81AGA 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. 

82AGA 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. 

83AGA Comments at 30; INGAA Comments at 23. 

84Enhanced Reliability Coalition Comments at 

11–12; Gas Processors Association Comments at 6– 

7; MSCG Comments at 12; NiSource Comments at 

7; NW Industrial Gas Users Comments at 3–4; PG&E 

Comments at 6; Texas Pipeline Association 

Comments at 9. 

85 Dominion Comments at 21; Enhanced 

Reliability Coalition Comments at 12. 

activities would be difficult or costly to 

do if the Gas Day start time were moved 

to 4:00 a.m. CCT.66 Commenters also 

state that, in providing reliable service, 

pipelines and LDCs are required to 

make manual changes to numerous 

facilities throughout the country prior to 

the start of every Gas Day to ensure 

delivery.67 National Grid states that 

requiring these changes to occur at 4:00 

a.m. CCT would place unnecessary 

operational and financial burdens on 

LDCs and could adversely affect their 

ability to prepare to meet morning 

natural gas load demands.68

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 

pipeline 72 is when customer demands 

are low and, therefore, pipelines and 

LDCs with pipeline operations currently 

use the late night and early morning 

hours to pack their systems in 

anticipation of the morning load.73

Commenters state that, particularly in 

the west, the proposed Gas Day change 

would reduce the number of hours 

available to pack the pipeline, thus 

jeopardizing the ability of pipeline 

operators to pressurize their systems to 

meet peak morning natural gas 

demands.74

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

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 exposure to imbalance 

penalties.81 Commenters assert that an 

unintended consequence of moving the 

Gas Day to 4:00 a.m. CCT is that 

pipelines may not be able to offer these 

enhanced balancing/clean-up services 

that provide flexibility to shippers, and 

these services could be more difficult 

for shippers to utilize and manage.82

AGA and INGAA state that under a 4:00 

a.m. CCT Gas Day model, it would be 

exceedingly difficult to replicate this 

type of business activity, and market 

liquidity, in the 1:00 a.m. CCT 

timeframe, since key decision-makers 

would not be on duty at that hour.83

44. Some commenters state that there 

is a concern that non-jurisdictional 

entities may not adjust to a 4:00 a.m. 

CCT Gas Day and that a lack of action, 

or timely action, by some operators on 

the upstream portion of the natural gas 

delivery chain could occur for various 

reasons, such as concerns over costs of 

the change and worker safety at night, 

particularly during inclement 

weather.84 Dominion and Enhanced 

Reliability Coalition assert that if gas 

suppliers and producers do not operate 

on the same Gas Day as pipelines, then 

pipelines may have difficulty obtaining 

necessary supplies and will need to 

manage swings with line pack and 

storage until producers make necessary 

changes, decreasing the pipeline’s 

operating flexibility.85 Texas Pipeline 

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86Texas Pipeline Association Comments at 11; 

Gas Processors Association Comments at 9. 

87CenterPoint Comments at 4–5; New England 

LDCs Comments at 19; Northern Municipal 

Distributors/Midwest Region Gas Task Force 

Comments at 11–12. 

88CenterPoint Comments at 4–5; Northern 

Municipal Distributors/Midwest Region Gas Task 

Force Comments at 11–12. 

89CenterPoint Comments at 4–5. 

90Essential Power Comments at 4. 

91National Grid Comments at 2. 

92MSCG Comments at 7. 

93AGA 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. 

94See, 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. 

95AGA Comments at 28; CenterPoint Comments 

at 4; NiSource Comments at 5; NWGA et al. 

Comments at 2; MSCG Comments at 16–17. 

96See, e.g., Dominion Comments at 26. Dominion 

states that a 4:00 a.m. CCT Gas Day will result in 

an estimated one-time cost of $3.8 million for 

modifications related to their SCADA system, 

electronic bulletin board, and information 

technology management system, and estimated ongoing 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. 

97Enhanced Reliability Coalition at 17. 

98 Dominion Comments at 26. 

99BHE Comment at 10–11; MSCG Comments at 

16–17. 

100AGA 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. 

101PG&E Comments at 7–8. 102Puget Comments at 8. 103See, 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. 104CAISO Data Response at 7–8. 105 Id. at 6. 106See 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. 

Association, Gas Processors Association, 

and INGAA state that this change would 

also require the modification and 

renegotiation of numerous nonjurisdictional 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 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

47. Gas industry participants cite high 

cost as a key reason for opposing the 

Gas Day proposal.94 A number of 

commenters discuss the information 

technology and staffing costs associated 

with the proposal including providing 

overtime compensation, hiring new 

employees to cover the earlier start to 

the Gas Day, retraining employees, and 

reprogramming SCADA systems.95

Commenters provided a range of cost 

estimates for SCADA/IT modifications 

and staffing requirements, with some 

above $3 million.96 Several commenters 

also discuss the costs of mitigating 

safety issues raised by moving the Gas 

Day to 4:00 a.m. CCT.97 Dominion states 

that approximately $2.5 million will be 

required to modify tariffs and 

contracts.98 MSCG and BHE estimate the 

overall cost of compliance with the 

NOPR changes, including the changes to 

the Gas Day, will be in the $5 million 

range for one jurisdictional interstate 

natural gas pipeline, which indicates 

the cost of compliance for all 166 

interstate natural gas pipelines would 

far exceed the $7.5 million estimated in 

the NOPR.99

48. Commenters also address the 

significant costs entities other than 

interstate natural gas pipelines will 

incur as a result of the Proposed 

Rule.100 PG&E states that compliance 

with the Gas Day proposal will result in 

an estimated one-time implementation 

cost of between $2 and $3 million for 

the reprogramming of SCADA systems, 

metering devices, and information 

technology management systems, as 

well as estimated ongoing annual costs 

of $600,000 for additional nighttime 

field personnel, traders, schedulers, and 

other staff-related costs.101 Puget states 

that aligning their operations with the 

Gas Day proposal would have an 

estimated one-time implementation cost 

of $300,000 for modifications related to 

their SCADA system, metering devices, 

and information technology 

management systems.102 Downstream 

gas industry commenters (e.g., LDCs) 

also caution that interstate pipelines 

will raise rates for pipeline 

transportation and storage services in 

order to recover the compliance costs of 

implementing the Gas Day proposal.103

C. Data Request and ISO and RTO 

Responses 

49. On December 12, 2014, 

Commission staff requested data, for 

2013 and 2014, from each of the six 

jurisdictional ISOs and RTOs regarding 

the impact on reliable and efficient 

operations of natural gas-fired 

generators running out of their daily 

nomination of natural gas transportation 

service during the morning electric 

ramp, to the extent this occurs. 

50. In its response, CAISO states that 

it believes gas-fired generators in its 

balancing authority generally do not 

face problems securing sufficient fuel to 

meet the morning electric ramp under 

existing electric and gas market 

timelines.104 CAISO was not able to 

locate any record of a gas-fired generator 

de-rating a unit during the hours of 3:00 

a.m. and 9:00 a.m. CCT due to the 

generator exhausting its daily 

nomination of natural gas transportation 

service prior to the end of the Gas Day. 

CAISO states that it does not believe it 

has committed generation out of merit 

order in anticipation of natural gas-fired 

generators running out of their 

nominated gas transportation at the end 

of the Gas Day.105 The data submitted 

by CAISO indicates that in 2013 and 

2014 fuel-related gas-fired generator 

outages and de-rates during the morning 

electric ramp were about as common on 

average as fuel-related de-rates during 

the other hours of the operating day.106

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107MISO Data Response at 1–3. 

108 Id. 

109See Tables MISO Data Response at 2. 

110MISO states that these enhancements and 

initiatives include: (1) Conducting a Generator 

Winter Fuel Survey for Winter 2014/2015 to gain 

more transparency into MISO generators’ 

approaches related to fuel procurement practices; 

(2) creating (in 2014) additional generator outage 

cause codes related to fuel in MISO’s outage 

scheduling tool to provide greater operational 

awareness to MISO operators regarding fuel; (3) 

expanding the coordination field trial between 

MISO planning and operations staff and ANR and 

NNG pipeline staff to other pipelines; (4) a new 

overhead pipeline operations display in the control 

room; and (5) a new consolidated pipeline notice 

Web page. MISO Data Response at 5. 

111SPP Data Response at 3. 

112See 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. 

113While these data do not show specifically 

whether the generators exceeded their firm gas 

transportation schedule for the day, ISO–NE states 

that the data suggests that the de-rates likely 

resulted from the exhaustion of natural gas 

transportation service, because the generators were 

able to come back on line at the start of the new 

Gas Day. 

114 ISO–NE Data Response at 1. 

115See 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. 

116A gas-fired generator may be limited in its 

ability to receive or take gas in instances when there 

are constraints on an LDC system, regardless of 

whether the gas-fired generator has sufficient 

remaining nominated quantities of interstate 

pipeline transportation. 

51. MISO states that it has not 

experienced any significant impacts 

caused by generators running out of 

natural gas during the morning ramp.107

MISO explains that its data of power 

plants’ actual performance and 

equipment failures does not reflect if 

fuel-related outages were specifically 

due to generators having exhausted their 

daily nomination of natural gas 

transportation service prior to the end of 

the Gas Day.108 MISO submitted data 

providing the numbers of natural gasfired units reporting outages and derates with a cause related to fuel during 

each month of 2013 and January 

through September 2014.109 In 2013, 

there were relatively few fuel-related 

gas-fired generator outages and de-rates. 

In January and February of 2014, MISO 

experienced far more fuel-related gasfired generator outages and de-rates, 

however, no more than 20 percent of the 

de-rates occurred during the morning 

ramp period. In addition, MISO states 

that it has made many recent 

enhancements to improve transparency 

of fuel-related matters in the planning 

and operating horizons.110

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 gasfired 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 derates during the other hours of the 

operating day.112

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., derates) 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 derates 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 derates, 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 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 

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 

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117NYISO 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.’’ 

118NYISO Data Response at 6. 

119For 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. 

via Supplemental Resource 

Evaluation 117 on days with de-rates 

greater than 225 MW in any given hour. 

NYISO states that given the times the 

Supplemental Resource Evaluations 

occurred, it is not clear that any of the 

Supplemental Resource Evaluations 

were issued in response to a generator 

de-rating due to having exhausted its 

daily nomination of natural gas 

transportation service prior to the end of 

the Gas Day. Instead, NYISO states the 

de-rates were more likely related to 

limitations on natural gas customers’ 

ability to receive or take gas, such as 

Operational Flow Orders (OFO), which 

require gas customers to operate within 

tight tolerances, or generator specific 

issues that may, or may not, be related 

to the availability of gas supply.118

57. The confidential data submitted 

by NYISO shows the number of gasfired 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 gasfired generator de-rates related to fuel 

availability fell as the morning 

progressed (between hours ending at 

4:00 a.m. CCT and 9:00 a.m. CCT). 

Similarly, over all of 2013 and all of 

2014, the total (by hour) amount of 

energy reduced later in the morning was 

less than the early-morning reductions. 

If fuel related de-rates were caused by 

exhaustion of nominated natural gas 

transportation capacity, the impact of 

the de-rates would likely have been 

steady or worsening as more generating 

units ran out of gas as the morning 

progressed towards 9:00 a.m. CCT. 

58. To provide another perspective on 

the overall impact on reliability of the 

gas-fired generator de-rates during the 

morning ramp, the Commission 

examined the monthly and hourly 

average values 119 of resulting energy 

reductions as a percentage of the 

available operating reserves. 

Commission staff analysis of the data 

response indicates that, in ISO–NE 

during 2013 and 2014, the energy 

reductions were minimal relative to the 

operating reserves available to ISO–NE 

at the time. 

TABLE 3—GAS-FIRED GENERATOR REDUCTIONS (DE-RATES) AS A PERCENT OF AVAILABLE OPERATING RESERVES IN

ISO–NE 

Hour beginning 

(CCT) 

All 2014 

(%) 

All 2013 

(%) 

Jan 2014 

(%) 

Mar 2014 

(%) 

Nov 14 

(%) 

Jan 2013 

(%) 

Feb 2013 

(%) 

Mar 2013 

(%) 

3 a.m. ............................... 0.47 0.69 0.14 1.08 2.10 0.00 0.90 1.47 

4 a.m. ............................... 0.39 0.49 0.14 0.69 2.11 0.00 0.53 0.83 

5 a.m. ............................... 0.26 0.32 0.07 0.01 2.11 0.02 0.91 0.01 

6 a.m. ............................... 0.29 0.48 0.17 0.18 2.11 0.16 1.38 0.06 

7 a.m. ............................... 0.43 0.61 0.57 0.31 2.11 0.42 1.25 0.43 

8 a.m. ............................... 0.55 0.70 0.57 0.47 2.11 0.61 1.00 0.92 

59. In NYISO, during certain winter 

months,120 Commission staff analysis of 

the data response indicates that the 

average hourly reductions were 

potentially significant relative to the 

operating reserves available to the 

NYISO, ranging up to 5.7 percent of 

reserves. For all other months of 2013 

and 2014, the average hourly reductions 

in NYISO were less than one percent of 

the available operating reserves. 

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. 

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121Natural Gas Council Feb. 2, 2015 Comments 

at 1–3. 

122American Public Gas Association Feb. 2, 2015 

Comments at 3–4; Natural Gas Council Comments 

at 2. 

123Enhanced Reliability Coalition Feb. 2, 2015 

Comments at 5. 

124Natural Gas Council Feb. 2, 2015 Comments 

at 8; New England LDCs Feb. 2, 2015 Comments at 

3. 

TABLE 5—GAS-FIRED GENERATOR REDUCTIONS (DE-RATES) AS A PERCENT OF AVAILABLE OPERATING RESERVES IN

PJM 

Hour beginning 

(CCT) 

All 2014 

(%) 

All 2013 

(%) 

Jan 2014 

(%) 

Feb 2014 

(%) 

Mar 2014 

(%) 

Jan 2013 

(%) 

Feb 2013 

(%) 

Mar 2013 

(%) 

3 a.m. ............................... 13.7 5.0 54.7 25.8 17.2 9.3 7.1 5.9 

4 a.m. ............................... 13.1 5.0 50.5 25.5 16.8 9.5 7.0 5.6 

5 a.m. ............................... 13.0 4.8 48.9 25.3 17.0 8.7 6.7 5.9 

6 a.m. ............................... 15.1 5.1 60.6 27.9 19.5 8.9 7.0 6.7 

7 a.m. ............................... 17.3 5.3 72.3 32.2 21.4 10.1 7.5 6.8 

8 a.m. ............................... 17.1 5.2 72.1 30.8 21.1 9.7 7.4 6.5 

D. Comments on Data Request 

61. American Public Gas Association, 

New England LDCs, the Enhanced 

Reliability Coalition, and Natural Gas 

Council filed comments regarding the 

ISOs’ and RTOs’ data responses. These 

commenters argue that the ISOs’ and 

RTOs’ responses clearly confirm that 

there is not a nationwide problem 

during the morning electric ramp 

associated with the current start time of 

the Gas Day.121 American Public Gas 

Association and Natural Gas Council 

contend that the data submitted by the 

ISOs and RTOs does not support the 

thesis that there is a causal link between 

the start of the Gas Day and the 

reliability of gas-fired generators.122 The 

Enhanced Reliability Coalition points 

out that in 2014, many of the instances 

in which generators in PJM indicated an 

outage due to lack of fuel occurred 

during OFOs issued by pipelines and 

that, in these circumstances, a change to 

the start of the Gas Day would not have 

remedied the generator outages.123

Natural Gas Council and New England 

LDCs state that the ISOs’ and RTOs’ 

responses fail to provide sufficient 

record evidence for the Commission to 

meet its burden under section 5 of the 

NGA that the current 9:00 a.m. CT Gas 

Day start time is no longer just and 

reasonable, and that a 4:00 a.m. CT start 

of the Gas Day is just and reasonable.124

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 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 derates 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 gasfired 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 fuelrelated issues which includes several 

other causes. Therefore, the Commission 

had to draw inferences based on the 

data submitted in the record. 

66. The Commission concludes that 

there is limited evidence to support the 

NOPR proposal to change the Gas Day. 

For example, in ISO–NE very few gasfired 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 fuelrelated 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 

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125 In ISO–NE these measures include changes to 

the ISO tariff to: (1) Allow for better information 

sharing with the interstate pipelines; (2) enhance 

offer flexibility; (3) accelerate the timelines in the 

Day-Ahead Energy Market; (4) increase the amount 

of reserves procured in the Forward Reserve 

Market; (5) enhance Forward Reserve Market 

incentives; (6) improve generator auditing; and (7) 

redefine Shortage Events in the Forward Capacity 

Market. 

Since January 2014 PJM has put into place a 

number of improvements to help ensure generator 

availability this winter including: (1) A process for 

generators to communicate any long-lead 

notification time they require to start in order to 

ensure fuel procurement; (2) a requirement for 

generators to ensure data accuracy for existing 

information provided to PJM; (3) a requirement for 

operational information to be submitted to PJM 

regarding dual fuel capability, availability, and 

operational restrictions; and (4) ability for 

generators, in certain circumstances, to update 

intraday cost schedules to more accurately reflect 

real-time the cost of fuel in their energy schedules. 

126 ISO–NE Data Response at 7. 

127 ISO New England Inc. and New England 

Power Pool, 147 FERC ¶ 61,172, order on 

compliance filing, 149 FERC ¶ 61,009 (2014). 

128On 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). 

130For 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.’’). 

131 18 CFR 284.12 (2014). 

132For example, if a shipper with a contract for 

2,400 Dth/day, schedules 1,200 Dth at the Timely 

Nomination Cycle, and submits an intraday 

nomination at the Intra-Day 1 Cycle, that shipper 

can increase its scheduled capacity, assuming 

capacity availability, by no more than 1,600 Dth, 

bringing its total scheduled quantity to 2,000 Dth/ 

day. This occurs because the shipper has already 

operated for eight hours based on a daily 

nomination of 1,200 Dth (50 Dth/hour). (8 hrs * 50 

= 400 Dth). This leaves the shipper only 16 hours 

to increase its flow rate to 100 Dth/hr, bringing its 

total daily quantity to 2,000 Dth (400 Dth for the 

first 8 hours + 1,600 for the remaining 16 hours). 

133A 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. 

134Secondary firm nominations are firm 

nominations that include at least one secondary 

point. Within-the-path nominations are 

nationwide Gas Day to 4:00 a.m. CCT 

will result in substantial nationwide 

costs and potential operational and 

safety impacts for the entire natural gas 

industry, including jurisdictional and 

non-jurisdictional entities. The natural 

gas industry has identified significant 

costs attendant on such a change, 

including the costs of hiring and 

retraining employees, providing 

overtime compensation, mitigating 

safety risks, modifying existing 

contracts, purchasing new equipment, 

and reprogramming SCADA systems, 

nomination software, and metering 

devices. The identified adverse 

operational and safety impacts include 

a potential for reduced nighttime hours 

to pack the pipeline, diminished 

opportunity for shippers to balance 

loads in the final hours of the Gas Day, 

increased need for field work during 

nighttime hours, and worker fatigue, 

among others. 

68. Therefore, we find, based on the 

record, that there has not been a 

showing that the benefits of changing 

the nationwide Gas Day from 9:00 a.m. 

CCT to 4:00 a.m. CCT sufficiently 

outweigh the potential adverse 

operational and safety impacts on the 

natural gas industry to justify action 

under NGA section 5 to require a change 

in the start of the Gas Day. 

69. While the Commission declines to 

take action in this proceeding to change 

the start of the Gas Day on a nation-wide 

basis, we note that since the issuance of 

the NOPR in March 2014 both ISO–NE 

and PJM (the two regions that appear to 

be of the most concern) have recently 

undertaken operational and market 

actions to address the availability and 

performance of generators, included gasfired generators, in their footprints.125

Beyond these measures, ISO–NE argues 

that the New England region needs its 

generating resources and other entities 

to make investments in firm fuel 

supplies and transportation, 

maintenance of on-site fuel inventory, 

and dual fuel capability.126 ISO–NE 

states that it is implementing the Payfor-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. 

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 

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-path 134

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23211 

nominations where the nominated secondary 

receipt and/or delivery point is contained wholly 

within the primary points listed in the shipper’s 

contract. 135Transwestern Pipeline Company, 99 FERC 

¶ 61,356, at P 12 (2002) (‘‘the Commission’s long 

standing policy on firm service is that once 

scheduled, whether at primary or alternate points, 

the service may not be bumped by a nomination by 

another firm shipper’’). 

136 18 CFR 284.12(b)(1)(i) (2014); Standards for 

Business Practices of Interstate Natural Gas 

Pipelines, Order No. 587–G, 63 FR 20072 (Apr. 16, 

1998), FERC Stats. & Regs., Regulations Preamble 

1996–2000 ¶ 31,062, at 30,672 (1998). 

137 Id. at 30,671. 

138See, e.g., Texas Gas, 137 FERC ¶ 61,093, order 

on compliance, 138 FERC ¶ 61,176; Gulf South, 141 

FERC ¶ 61,262. 

139See, e.g., Tennessee Gas Pipeline Company, 

LLC’s Tariff, GT&C Section IV.2(e). 

140The 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. 

nominations, secondary firm, outside of 

the path nominations, and finally 

nominations from shippers holding 

interruptible transportation capacity. 

Before a pipeline schedules a shipper’s 

requested quantity under these 

standards, the pipeline confirms the 

shipper’s nomination with upstream 

and downstream entities to make sure 

the shipper has contracted for sufficient 

gas with an upstream supplier to fulfill 

its nomination and to ensure the 

downstream entity, such as a LDC, has 

sufficient capacity to accept that gas. 

73. The Timely Nomination Cycle is 

the most liquid time to acquire both 

natural gas supply and transportation 

capacity. During the Timely Nomination 

Cycle, all of the pipeline’s nomination 

priorities are in effect: Primary firm 

nominations have priority over 

secondary firm nominations, and 

secondary firm nominations have 

priority over interruptible 

transportation. In subsequent 

nomination cycles, firm service, 

including secondary firm service, 

scheduled in an earlier cycle cannot be 

displaced or bumped by another firm 

nomination for that Gas Day.135 In 

addition, firm intraday nominations, 

including secondary firm nominations, 

have priority over, and thus can 

displace or bump, scheduled and 

flowing interruptible transportation.136

This policy recognizes that ‘‘firm 

shippers are paying reservation charges 

for priority rights and those rights 

should include the right to have a 

nomination become effective as early as 

possible on the Gas Day following the 

nomination.’’ 137 However, the final 

intraday nomination (Intraday 2) cycle 

is a ‘‘no-bump’’ cycle, meaning that 

interruptible transportation previously 

arranged for cannot be displaced or 

bumped by a firm Intraday 2 

nomination. In approving this 

arrangement (referred to as the ‘‘NoBump 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 services 138

and some pipelines permit more 

frequent nominations than the four 

required by the current NAESB 

standards. Even if additional 

nomination cycles are not detailed in 

the pipeline’s tariff, some pipelines’ 

tariffs provide that the pipeline will 

make best efforts to accommodate such 

incremental nominations throughout the 

day on a best efforts basis.139

B. Natural Gas Transportation DayAhead 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 day-ahead energy market to set 

contractual commitments for the next 

operating day. Market participants place 

day-ahead offers and bids to sell and 

purchase, and these participants must 

make such commitments prior to the 

close of the market. If the market 

clearing process accepts these 

commitments, they become binding for 

the following day. The following table 

shows for each ISO and RTO the 

deadline for submission of generator 

bids and the time the winning bids are 

posted by ISOs and RTOs in the dayahead markets. As demonstrated by 

Table 6, all ISOs and RTOs (with the 

exception of NYISO) publicize accepted 

day-ahead dispatch bids after the 

current 11:30 a.m. CCT nomination 

deadline for the Timely Nomination 

Cycle. 

TABLE 6—ELECTRIC COMMITMENT RESULTS PUBLICATION TIMETABLE

ISO/RTO 

Time for 

submission 

of bids 

(CCT) 

Time for 

publication of 

day-ahead 

commitment 

bids 

(CCT) 

California Independent System Operator Corporation (CAISO) .................................................................................. 12:00 p.m. ... 3:00 p.m. 

ISO New England Inc. (ISO–NE) ................................................................................................................................. 9:00 a.m. ..... 12:30 p.m. 

PJM Interconnection, LLC (PJM) ................................................................................................................................. 11:00 a.m. ... 3:00 p.m. 

Midcontinent Independent System Operator, Inc. (MISO) ........................................................................................... 10:00 a.m. ... 2:00 p.m. 

New York Independent System Operator, Inc. (NYISO) ............................................................................................. 4:00 a.m. ..... 10:00 a.m. 

Southwest Power Pool, Inc. (SPP) .............................................................................................................................. 11:00 a.m. ... 4:00 p.m. 

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23212 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

141A 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. 

142See, 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’’). 

143Section 206 Order, 146 FERC ¶ 61,202. 

77. Because day-ahead electric 

generation commitments generally 

occur after the natural gas transportation 

Timely Nomination Cycle, a natural gasfired 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 dayahead commitment to nominate natural 

gas transportation services, with the risk 

that during some periods natural gas 

supply and transportation capacity may 

not be available or economical, given 

the ISO and RTO day-ahead market 

clearing price.141 If a gas-fired generator 

acquires natural gas and transportation 

prior to learning whether it is 

dispatched, it runs the risk of having to 

sell off excess natural gas supply and 

pipeline transportation capacity during 

the less liquid Evening or intraday 

Nomination Cycles to the extent its bid 

does not clear the day-ahead market.142

If the gas-fired generator waits to 

acquire natural gas supply and 

transportation until its bid clears the 

day-ahead market, it would be doing so 

during the less liquid Evening or 

intraday Nomination Cycles, where the 

generator may be unable to acquire 

transportation capacity if the pipeline is 

fully scheduled. While during many 

periods of the year, gas-fired generators 

may be able to obtain natural gas and 

interstate natural gas capacity 

throughout the day, their ability to 

procure natural gas and transportation 

in the most liquid Timely Nomination 

Cycle may be critical to their ability to 

provide service during periods when the 

pipeline is constrained. 

1. NOPR Proposal 

78. The NOPR proposed to move the 

deadline for submitting nominations in 

the Timely Nomination Cycle from 

11:30 a.m. CCT to 1:00 p.m. CCT to 

provide sufficient time for electric 

utilities to complete their processes for 

selecting day-ahead generating 

resources before the Timely Nomination 

Cycle. The NOPR did not propose any 

other changes to the Timely Nomination 

Cycle, including the existing 4:30 p.m. 

CCT deadline for the pipeline to provide 

notice of scheduled quantities. Thus, 

the NOPR proposed to shorten the time 

required to complete the Timely 

Nomination Cycle from five hours 

(11:30 a.m. CCT to 4:30 p.m. CCT) to 

three and one-half hours (1:00 p.m. CCT 

to 4:30 p.m. CCT). The NOPR did not 

propose any changes to the existing 

Evening Nomination Cycle, under 

which nominations must be submitted 

by 6:00 p.m. CCT, confirmations are 

completed by 9:00 p.m. CCT, and the 

pipeline notifies shippers of their 

scheduled quantities by 10:00 p.m. CCT. 

79. In an order issued 

contemporaneously with the NOPR, the 

Commission instituted a proceeding 

under section 206 of the FPA requiring 

each ISO and RTO within ninety days 

after the publication of a Final Rule in 

this docket to: (1) Make a filing that 

proposes tariff changes to adjust the 

time at which the results of its dayahead energy market and reliability unit 

commitment process (or equivalent) are 

posted to a time that is sufficiently in 

advance of the Timely and Evening 

Nomination Cycles, respectively, to 

allow gas-fired generators to procure 

natural gas supply and pipeline 

transportation capacity to serve their 

obligations; or (2) show cause why such 

changes are not necessary.143

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 dayahead 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 gasfired generators know whether they 

were committed in the day-ahead 

electric market prior to the Timely 

Nomination Cycle, they may have a 

greater opportunity to procure natural 

gas transportation in the Timely 

Nomination Cycle—when there is the 

greatest opportunity to procure pipeline 

capacity. This, in turn, could reduce the 

potential for gas-fired generators to 

engage in costly actions that raise realtime electric market prices. Thus, 

electric market outcomes may better 

reflect expected operating costs if gasfired generators were provided with 

day-ahead market results prior to the 

Timely Nomination Cycle. 

81. It was recognized in the NOPR 

that moving the Timely Nomination 

Cycle to later in the day may impose 

systems and administrative costs on 

other interstate natural gas pipeline 

shippers. However, the NOPR 

concluded a 1:00 p.m. CCT start time for 

the Timely Nomination Cycle would 

appear to provide a reasonable balance 

of the electric and natural gas 

industries’ concerns. The NOPR 

concluded that the long-term benefits of 

ensuring a better coordinated natural 

gas and electric industry appear to 

warrant this change. 

2. Revised NAESB Day-Ahead 

Nomination Cycles 

82. Consistent with the NOPR, 

NAESB revised its standards to move 

the start of the Timely Nomination 

Cycle to 1:00 p.m. CCT, with scheduled 

quantities becoming effective at the start 

of the next Gas Day. However, unlike 

the NOPR, NAESB revised its standards 

to move the deadline for the pipeline to 

notify shippers of their scheduled 

quantities from 4:30 p.m. CCT to 5:00 

p.m. CCT, stating the pipelines require 

at least four hours to complete the 

Timely Nomination Cycle. 

83. While the NOPR did not propose 

any changes to the Evening Nomination 

Cycle, NAESB revised its standards to 

provide that that cycle be completed in 

three hours, rather than the current four 

hours, with shippers being notified of 

their scheduled quantities at 9:00 p.m. 

instead of 10:00 p.m. Under both the 

NOPR and NAESB’s revised standards, 

bumping of interruptible service is 

permitted in the Evening Nomination 

Cycle and, consistent with current 

Commission policy, already scheduled 

secondary firm service cannot be 

bumped. A comparison of the current 

NAESB day-ahead nomination cycles 

and the revised NAESB day-ahead 

nomination cycles are shown in Table 7 

below. 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23213 

144AGA 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. 

145See, 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. 

146See, e.g., EDF et al. Comments at 7–8; PUCO 

Comments at 5–6. 

147SPP Comments at 2–3; Xcel Energy Comments 

at 3–5. 

148Puget Comments at 13. 

149MSCG Comments at 15–16. 

150See, e.g., Exelon Comments at 7; NGSA 

Comments at 16. 

TABLE 7—DAY-AHEAD NOMINATION CYCLES

Time Shifts—all times CCT Current NAESB 

standards 

Revised NAESB 

standards 

Timely: 

Nomination Deadline .................................................................................................................................. 11:30 a.m ......... 1:00 p.m. 

Schedule Issued ......................................................................................................................................... 4:30 p.m ........... 5:00 p.m. 

Start of Gas Flow ....................................................................................................................................... 9:00 a.m.

Evening: 

Nomination Deadline .................................................................................................................................. 6:00 p.m ........... 6:00 p.m. 

Schedule Issued ......................................................................................................................................... 10:00 p.m ......... 9:00 p.m. 

Start of Gas Flow ....................................................................................................................................... 9:00 a.m.

3. NOPR Comments 

84. The large majority of commenters 

support moving the start time for the 

Timely Nomination Cycle from 11:30 

a.m. CCT to 1:00 p.m. CCT, including 

commenters that do not generally 

support NAESB’s intraday nomination 

timeline.144 Many of the commenters 

that support NAESB’s nomination 

timeline state that, consistent with the 

Commission’s proposal, moving the 

Timely Nomination Cycle nomination 

deadline to 1:00 p.m. CCT will provide 

generators more time to acquire natural 

gas supply and pipeline transportation 

after learning their electric dispatch 

obligations, provided changes are made 

to the ISO and RTO scheduling 

processes.145 Several commenters state 

that moving the Timely Nomination 

Cycle deadline later will also reduce 

costs and improve efficiency among gasfired 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 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 obligations, provided 

changes are made to the ISO and RTO 

scheduling processes. NAESB’s 

proposal to provide notice of scheduled 

quantities at 5:00 p.m. also enables gas 

industry participants to complete the 

Timely Nomination Cycle by the end of 

the business day, while still providing 

sufficient time for the nomination, 

confirmation and scheduling process. 

88. The Commission declines to 

extend the deadline for submitting 

nominations in the Timely Nomination 

Cycle past 1:00 p.m. CCT, as requested 

by a few commenters. Such an 

extension would likely require 

corresponding changes in the remainder 

of the Timely Nomination Cycle 

process, including moving back 

NAESB’s proposed 5:00 p.m. CCT 

deadline for posting scheduled 

quantities. However, as many 

commenters point out, there needs to be 

sufficient time between the scheduled 

quantity posting of one cycle and the 

nomination deadline for the next cycle 

to enable shippers to review their 

transportation needs prior to the next 

nomination deadline.150 Further 

extending the Timely Nomination Cycle 

nomination deadline would reduce or 

do away completely with the time 

between when the Timely Nomination 

Cycle schedule is issued and the 6:00 

p.m. deadline for submitting 

nominations in the Evening Nomination 

Cycle. Also, commenters in the natural 

gas industry contend that the further the 

Timely Nomination Cycle process falls 

outside of regular business hours, the 

more likely it is that producers, point 

operators, and shippers will be harder to 

reach to resolve nomination, 

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23214 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

151See, e.g., INGAA Comments at 8. 

152NOPR, 146 FERC ¶ 61,201 at P 57. 

153 Id. P 62. 154A comparison of the current NAESB 

nomination timeline and the revised NAESB 

nomination timeline is set forth in the Appendix. 

confirmation and scheduling errors.151

Given the support for the revised 

NAESB schedule and the problems 

created in moving the time any later, the 

concerns of the commenters with the 

coordination of the current scheduling 

processes of MISO and SPP relative to 

natural gas scheduling are best 

addressed in the section 206 

proceedings the Commission instituted 

for each ISO and RTO. 

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 IntraDay 1 Nomination Cycle can ‘‘bump’’ an 

already scheduled interruptible 

nomination. Pursuant to the ‘‘No-Bump 

Rule,’’ however, nominations for firm 

service made at the Intraday 2 cycle 

cannot ‘‘bump’’ previously scheduled 

interruptible service. 

90. A number of commenters in 

response to the technical conferences in 

Docket No. AD12–12–000 stated that the 

standard, nation-wide nomination 

opportunities currently available may 

not provide gas-fired generators or other 

shippers with sufficient flexibility to 

adjust their nominations to respond to 

real-time changes in their need for 

natural gas.152 These commenters 

requested that the Commission require 

additional, standardized intraday 

nomination opportunities on interstate 

natural gas pipelines. Pipelines and 

other gas market participants indicated 

that they were open to the creation of 

the additional standard nomination 

cycles.153

1. NOPR Proposal 

91. To address concerns that the 

current standard, nation-wide intraday 

nomination opportunities do not 

provide shippers—especially natural 

gas-fired generators—with sufficient 

flexibility, the NOPR proposed to 

modify the current natural gas 

nomination timeline to add two 

additional intraday nomination cycles 

so that shippers would have four 

intraday cycles to reschedule gas 

instead of the existing two. The 

additional intraday nomination cycles 

would maximize shippers’ ability to 

make significant changes in their 

intraday nominations, as well as 

provide firm shippers an additional, 

bumpable late-afternoon nomination 

cycle. The proposed revisions would 

provide gas-fired generators, as well as 

other pipeline customers, with greater 

flexibility to revise their nominations to 

adjust to system conditions and changes 

to load throughout the Gas Day. 

92. The timelines proposed in the 

NOPR were based on the proposed 

adoption of 4:00 a.m. CCT as the start 

of the Gas Day. The NOPR proposed that 

the Intraday 1 Nomination Cycle begin 

at 8:00 a.m. CCT, with pipelines issuing 

scheduled quantities at 11:00 a.m. CCT, 

and gas flow beginning at 12:00 noon 

CCT. The Intraday 1 Nomination Cycle 

would provide an early morning 

opportunity for shippers to nominate 

gas. The NOPR proposed that the 

Intraday 2 Nomination Cycle begin at 

10:30 a.m. CCT, with pipelines issuing 

scheduled quantities at 2:00 p.m. CCT, 

and gas flow beginning at 4:00 p.m. 

CCT. The NOPR proposed Intraday 2 

cycle would replace the current Intraday 

1 mid-morning nomination cycle and 

permit bumping. The NOPR proposed 

Intraday 3 Nomination Cycle would 

begin at 4:00 p.m. CCT with pipelines 

issuing scheduled quantities at 6:00 

p.m. CCT, and gas flow beginning at 

7:00 p.m. CCT. The NOPR proposed 

Intraday 3 Nomination Cycle would 

provide an additional bumping 

opportunity for firm shippers. The 

NOPR proposed Intraday 4 Nomination 

Cycle would begin at 7:00 p.m. CCT 

with pipelines issuing scheduled 

quantities at 9:00 p.m. CCT, and gas 

flow beginning at 9:00 p.m. CCT. The 

NOPR Intraday 4 Nomination Cycle 

would replace the current 5:00 p.m. nobump cycle. 

2. NAESB’s Revised Intraday 

Nomination Cycles 

93. NAESB’s revised standards 

provide for three intraday nomination 

opportunities, rather than the four 

proposed in the NOPR. In contrast to the 

NOPR proposal to start the Intraday 1 

Nomination Cycle at 8:00 a.m. CCT, 

NAESB’s revised standards start the 

Intraday 1 Nomination Cycle at the 

existing 10:00 a.m. CCT time. However, 

the revised standards move the deadline 

for pipelines to issue scheduled 

quantities up to 1:00 p.m. CCT from the 

existing NAESB standard of 2:00 p.m., 

and for gas flow to begin at 2:00 p.m. 

CCT, rather than the existing 5:00 p.m. 

CCT. NAESB’s revised standards 

provide for the Intraday 2 Nomination 

Cycle to start at 2:30 p.m. CCT, rather 

than 5:00 p.m., as it now does. Pipelines 

would issue scheduled quantities at 

5:30 p.m. CCT, rather than the existing 

9:00 p.m., and gas flow would begin at 

6:00 p.m. CCT, instead of the existing 

9:00 p.m. NAESB’s new Intraday 3 

Nomination Cycle begins at 7:00 p.m. 

CCT, with scheduled quantities issued 

at 10:00 p.m. CCT, and gas flow 

beginning at 10:00 p.m. CCT. NAESB’s 

revised standards provide that bumping 

of interruptible service will be allowed 

during the Intraday 2 Nomination Cycle 

in addition to the Intraday 1 

Nomination Cycle.154 NAESB’s revised 

standards reflect reduced intraday 

processing times from the current 

NAESB standards (i.e., 3 hours instead 

of the current 4 hours). A comparison of 

the current NAESB intraday nomination 

timeline and the revised NAESB 

intraday nomination timeline is shown 

in the table below. 

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. 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23215 

155AGA 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. 

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 

157See, 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. 

159See, e.g., Dominion Comments at 11; EPSA 

Comments at 6–7; INGAA Comments at 9; PGC 

Comments at 5; Southern Star Comments at 5. 

160 Dominion Comments at 11; Kinder Morgan 

Comments at 6–8; WBI Comments at 4; see also 

INGAA Comments at 8–9. 

161See, e.g., EPSA Comments 6–7; Exelon 

Comments at 7; INGAA Comments at 8–9, WBI 

Energy Comments at 4. 

162See, 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. 

TABLE 8—INTRADAY NOMINATION CYCLES—Continued 

Time shifts—all times CCT Current NAESB 

standards 

Revised NAESB 

standards 

Intraday 2 

Nomination Deadline .................................................................................................................................. 5:00 p.m. .......... 2:30 p.m. 

Schedule Issued ......................................................................................................................................... 9:00 p.m. .......... 5:30 p.m. 

Start of Gas Flow ....................................................................................................................................... 9:00 p.m. .......... 6:00 p.m. 

IT Bump Rights ........................................................................................................................................... no bump ........... bumpable. 

Intraday 3 

Nomination Deadline .................................................................................................................................. ........................... 7:00 p.m. 

Confirmations .............................................................................................................................................. ........................... 9:30 p.m. 

Schedule Issued ......................................................................................................................................... ........................... 10:00 p.m. 

Start of Gas Flow ....................................................................................................................................... ........................... 10:00 p.m. 

IT Bump Rights ........................................................................................................................................... ........................... no bump. 

3. Comments 

94. The large majority of comments on 

this issue support or do not oppose 

NAESB’s revised standards providing 

for three Intraday Nomination Cycles.155

Commenters state that, consistent with 

the NOPR’s proposed four intraday 

nomination cycles, NAESB’s modified 

three intraday nomination cycles will 

allow gas-fired generators, as well as 

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 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 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 

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23216 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

163See, e.g., AGA Comments at 23; Dominion 

Comments at 9–10; INGAA Comments at 6–7 

164ACES 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. 

165Exelon Comments at 10–11. 

166Con Edison Comments at 10. 

167 DSPS Comments at 19–20. 

168EDF 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. 

170TVA Comments at 3. 

171 DSPS Comments at 20. 

172See, 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. 

173Enhanced Reliability Coalition Comments at 

31. 

174As 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 

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 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, nonbumpable 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

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 NoBump 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. 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 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 

additional scheduling flexibility for firm 

shippers by adding additional 

nomination cycles that allow firm 

shippers to bump interruptible 

shippers.174

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23217 

a case-by-case basis to determine whether such 

proposal provides an adequate subsequent 

opportunity to renominate any bumped volumes. 

Id. 175Standards 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’’). 176Order 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). 

177The 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. 

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 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 NoBump 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 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 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 primaryfirm shippers to bump secondary firm 

shippers during the Evening 

Nomination Cycle. DSPS contends that 

moving the Evening 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 

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23218 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

178ACES 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. 

179See, 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. 

180PGC Comments at 9. 

181See, e.g., AGA Comments at 33; BHE 

Comments at 6–7; Dominion Comments at 12–13. 

182See, e.g., Dominion Comments at 12–13; PGC 

Comments at 9; Southwest IS Comments at 6. 

183NGSA Comments at 23; PGC Comments at 10. 

184AGA Comments at 34. 

185 INGAA Comments at 11–12; Kinder Morgan 

Comments at 11; WBI Comments at 7. 

186PGC Comments at 11; INGAA Comments at 

11–12. 

187 Kinder Morgan Comments at 12. 

188Southern Companies at 11–12. 

189TVA Comments at 4. 

190See, e.g., Dominion Comments at 13; 

Enhanced Reliability Coalition at 31–32; Sequent 

Comments at 6; NGSA Comments at 22. 

191Transwestern Comments at 4–5. 

p.m. to 7:00 p.m. CCT.178 While most 

commenters oppose modifying 

Commission policy to permit primaryfirm nominations to bump secondary 

firm nominations in the Evening 

Nomination Cycle, a few commenters 

support this proposal. 

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 

service 183 and AGA argues that the 

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 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. 

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, inpath 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 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 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23219 

192 Kinder Morgan Comments at 12. 193Transwestern Comments at 5. 

194See Pipeline Service Obligations and Revisions 

to Regulations Governing Self-Implementing 

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). 

195Southern 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). 

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 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 TransCanadaNorth 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. 

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

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 makeup 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 

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 

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23220 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

196See, 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-musthave-title policy to the extent they used capacity in 

excess of that for which they were liable to pay. 

197See, e.g., Florida Gas Transmission Co., LLC, 

126 FERC ¶ 61,055 (2009). 

198See, 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. 

199AGA 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. 

200AF&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. 

201 IOGA Comments at 5–6. 

202EnerVest 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. 

205AF&PA Comments at 3–5; IECA Comments at 

2–4; NGSA Comments at 24–26; PGC Comments at 

6–8. 

206AF&PA Comments at 3–5; IECA Comments at 

2–4; PGC Comments at 6–8. 

release program to transfer the capacity 

among themselves. In order to satisfy 

the Commission’s shipper-must-havetitle policy, 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 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 multiparty 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 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 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 multiparty transportation contracts more 

widely available, provided that the 

Commission can ensure that multi-party 

contracts are transparent, do not 

adversely affect existing shippers, 

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 

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207AF&PA Comments at 3–5; IECA Comments at 

2–4; NGSA Comments at 24–26. 

208See, e.g., INGAA Comments at 32–33; Kinder 

Morgan Comments at 15; Spectra Comments at 9. 

209BHE Comments at 18. 

210MSCG Comments at 18–19. 

211NGSA Comments at 26. 

212Puget 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. 

215Tenaska Comments at 6–7. 

216Sequent Comments at 9. 

217AF&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. 

219EnerVest Comments at 9. 

220 INGAA Comments at 33–34. 

221 Dominion Comments at 29. 

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 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 multiparty 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 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 multiparty transportation contract, can be rereleased, 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 shippermust-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 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 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 multiparty 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, 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 

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23222 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

222See, 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. 

224See 18 CFR 284.13 (2014). 

225Order No. 637, FERC Stats & Regs. ¶ 31,091 at 

31,300 (2000). 

226See 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). 

227Pub. L. No. 104–113, 12(d), 110 Stat. 775 

(1996), 15 U.S.C. 272 note (1997). 

228 1 CFR 51.5 (2014). See Incorporation by 

Reference, 79 FR 66267 (Nov. 7, 2014). 

229 18 CFR 284.12 (2014). 

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 shipper-must-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 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 multiparty 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 shippermust-have-title rule in this rulemaking 

proceeding. However, the Commission 

is open to considering requests for 

waiver of its capacity 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 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 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

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23223 

230North American Energy Standards Board 

Membership Application, https://www.naesb.org/

pdf4/naesbapp.pdf. 231NAESB Materials Order Form, https://

www.naesb.org//pdf/ordrform.pdf. 232Procedures 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=OFR2013-0001-0023). 

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

234 5 CFR 1320 (2014). 

235FERC–545 covers rate change filings made by 

natural gas pipelines, including tariff changes. 

236FERC–549C covers Standards for Business 

Practices of Interstate Natural Gas Pipelines. 

237An 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. 

238The 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. 

239The 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. 

240Some 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. 

241The 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. 

242A 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. 

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 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 

1995 233 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 onetime implementation of the information 

collection 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 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

Number of 

responses per 

respondent 

Average burden 

hours per response 

Total annual 

burden hours 

Total annual cost 

($) 238

(1) (2) (3) (1)×(2)×(3) 

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

Tariff Filing for new and revised Nomination Cycles (one-time) 240 ............. 165 1 10 1,650 241 $116,457 

Tariff Filing for Multi-Party Service 

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

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23224 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

243The 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 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). 

244For 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). 

245Regulations 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). 

RM14–2 FINAL RULE—Continued 

Number of 

respondents 237

Number of 

responses per 

respondent 

Average burden 

hours per response 

Total annual 

burden hours 

Total annual cost 

($) 238

(1) (2) (3) (1)×(2)×(3) 

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

Implementation of business standards, 

including process, procedures, and 

IT support (one-time) 243 .................. 165 1 240 39,600 2,524,500 

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 FERC–549C) ...................... .............................. .............................. ................................ 39,680 2,646,603 

Total ongoing (for FERC–549C) ... .............................. .............................. ................................ 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. 

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 multi-party 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 

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: (202) 395–0710, fax: (202) 

395–4718]. For security reasons, 

comments to OMB should be submitted 

by email 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 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23225 

246See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5), 

380.4(a)(27) (2014). 

247 5 U.S.C. 601–612. 

248 13 CFR 121.101. 

249U.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. 

250Based 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.’’ 

251 5 U.S.C. 605(b). 

252 INGAA Comments at 34–35; Kinder Morgan 

Comments at 16–17; WBI Comments at 8–9. 

253See, 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. 

255Calpine Comments at 17; EEI Comments at 7; 

NGSA Comments at 36. 

256NAESB November 26, 2014 Report at 1–2. 

257Standards for Business Practices of Interstate 

Natural Gas Pipelines, Order No. 587–V, FERC 

Stats. & Regs. ¶ 31,332, at PP 36–37 (2012). 

258This 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. 

259For example, pipelines are required to include 

the full text of the NAESB nomination and capacity 

Continued 

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 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 estimated 

compliance cost of this Final Rule is 

$4,182,341 in Year 1 (an average of 

$25,348 per entity, including both onetime 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 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 natural-gas 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. 

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

(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 

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23226 Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 

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. 

260Shippers 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. 

261 5 U.S.C. 804(2). 

(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 post on its eLibrary 

Web site (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 Web site 

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 Room at (202) 

502–8371, TTY (202) 502–8659. Email 

the Public Reference Room at 

public.referenceroom@ferc.gov. 

XIV. Effective Date and Congressional 

Notification 

175. This final rule is effective July 8, 

2015. The incorporation by reference of 

certain publications listed in this rule is 

approved by the Director of the Federal 

Register as of July 8, 2015. 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. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

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 

paragraphs (a)(1) introductory text and 

(a)(1)(vi) and (vii) and by adding 

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 (a)(1)(i) through (vii) of this 

section, and as revised by WGQ 2014 

Annual Plan Item 11c and Minor 

Correction MC14018, as incorporated 

herein by reference in paragraphs 

(a)(1)(viii) and (ix) of this section. 

* * * * * 

(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 

(ix) Minor Correction/Clarification, 

Request No. MC14018 Approved 

September 10, 2014. 

* * * * * 

(b) * * * 

(1) * * * 

(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. 

* * * * * 

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 

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Federal Register / Vol. 80, No. 79 / Friday, April 24, 2015 / Rules and Regulations 23227 

Time shifts—all times CCT Current NAESB 

standards 

Revised NAESB 

standards 

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. 

[FR Doc. 2015–09275 Filed 4–23–15; 8:45 am] 

BILLING CODE 6717–01–P 

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