Gas-Electric Coordination

Quarterly Report to the Commission

Docket No. AD12-12-000

September 18, 2014

Disclaimer: The matters presented in this staff report do not necessarily represent the views of 

the Federal Energy Regulatory Commission, its Chairman, or individual Commissioners, and are not 

binding on the Commission. 
September 18, 2014

Gas-Electric Coordination 

Quarterly Update

Docket No. AD12-12

This report is Commission staff’s seventh quarterly update on national and regional GasElectric Coordination Activities, as directed by the Commission in its November 15, 2012 order 

in Docket No. AD12-12. This report covers the period June 2014 through September 2014. 

 

This report focuses on significant new national and regional developments since last reported 

in June 2014, highlights the actions taken by the North American Energy Standards Board 

(NAESB) to support the directives in the March 20, 2014 Notice of Proposed Rulemaking 

(NOPR), and briefly summarizes recent industry applications filed with the Commission. 

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National Initiatives

 Natural Gas Pipeline Scheduling

• NAESB Response to NOPR

• DSPS Alternate Proposal

 Natural Gas Trading

• Information & Trading Platform

As noted in our last quarterly report, the North American Energy Standards Board (NAESB) Gas 

Electric Harmonization Forum in June concluded its consideration of the Commission’s March 

20, 2014 proposed rule to reform the scheduling processes of interstate natural gas pipelines 

(Docket No. RM14-2-000). While the Gas Electric Harmonization Forum was unable to achieve 

consensus on a complete package of alternatives to the Commission’s proposals, the NAESB 

Board of Directors (Board) found that there was broad support in both the gas and electric 

industries for changes in the intraday scheduling cycles and day-ahead nomination cycles, and 

directed the Wholesale Gas Quadrant (WGQ) to develop new standards and modify existing 

standards to support these changes. 

On June 18, 2014, NAESB submitted a report to the Commission to inform it of the Board’s 

action and outline the additional steps NAESB intended to take. Since that report, the WGQ 

has developed new and revised standards in support of revised timelines for the timely, 

evening, intraday 1, intraday 2, and intraday 3 nomination cycles that received broad support 

in the Gas Electric Harmonization Forum. Specifically, the nomination deadline for the timely 

and evening cycles are the same as those proposed in the NOPR—1:00 pm Central Clock Time 

(Central) and 6:00 pm Central, respectively. The timelines for intraday 1, intraday 2, and 

intraday 3 vary from those proposed in the NOPR and the nomination deadlines would be at 

10:00 am, 2:30 pm, and 7:00 pm, all Central time. The NAESB standards will not include an 

intraday 4 cycle nor any change to the Gas Day start time. The Gas Electric Harmonization 

Forum did not achieve broad support for such change. 

These standards were posted for industry comment in July and August. On August 21, 2014, 

the WGQ Executive Committee met to consider the revised standards and the comments 

received. The Executive Committee voted on and passed the revised standards with a 

supermajority of both segments of the WGQ in support. On Friday, August 22, 2014 NAESB 

issued the standards for a 30 day period for ratification by the WGQ membership. NAESB is on 

schedule to file the standards with the Commission on September 29, 2014.

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Arizona Public Service Company (APS) and Salt River Project Agricultural Improvement and 

Power District (SRP) voted in opposition to the standards at the NAESB WGQ Executive 

Committee. These entities, along with UNS Gas, Inc. and Tucson Electric Power Company, 

Public Service Company of New Mexico, El Paso Electric Company and the Arizona Corporation 

Commission – all of which are members of the Desert Southwest Pipeline Stakeholders (DSPS) – 

jointly submitted comments and an alternate (minority) proposal for inclusion in the NAESB 

record. DSPS presented a three-part proposal, two of which would apply on a national basis 

and one of which would apply on a regional basis. DSPS contends that this proposal would 

address the unique circumstances of the Desert Southwest (including the lack of storage in 

the region, the large growth in intermittent renewables in the region, and a peak period of 

demand between 5:00 pm and 7:00 pm local time). 

First, DSPS proposes that the Commission would need to act on a national basis to move the 

nomination deadline for the NAESB Evening Cycle from 6:00 pm Central the day before the 

start of the next Gas Day to 7:00 pm Central. DSPS states that this change would provide an 

opportunity for shippers to request changes to their pipeline transportation service to address 

operational contingencies that occur in the period between 7:00 pm to 9:00 pm Central (5:00 

and 7:00 pm local time). Second, DSPS proposes that the Commission act on a national basis 

to modify its policy on bumping during the NAESB Evening Cycle. Interstate natural gas 

pipelines schedule their systems based on the priority of the transportation contract held by 

the shipper. Nominations of capacity under firm transportation contracts from a primary 

receipt point to a primary delivery point (primary firm nominations) have the highest priority 

followed by secondary-firm nominations (which include at least one secondary receipt and/or 

delivery point). Currently, however, firm service (primary or secondary) scheduled in the 

Timely Nomination Cycle cannot be bumped by another firm nomination in subsequent 

nomination cycles. DSPS proposes that, in the NAESB Evening Cycle, primary-firm 

nominations should be permitted to displace or bump secondary-firm nominations previously 

scheduled during the Timely Nomination Cycle. DSPS states that this policy change would 

give primary-firm nominations a higher priority and increase their value, thereby encouraging 

long-term contracting and promoting infrastructure development. 

Third, DSPS proposes that the Commission act on a regional basis to establish a 1-Year Pilot 

Program for pipelines serving the Desert Southwest that allows firm shippers to submit a 

separate retroactive, or make-up nomination during the Evening Cycle—which is currently 

utilized to make nominations for the following Gas Day. This proposal would allow a shipper, 

upon pipeline operator approval, to adjust its natural gas receipts or takes from the pipeline 

for the remainder of the current Gas Day, provided that the shipper submits a retroactive 

nomination during the Evening Cycle for the natural gas variance. Under such proposal, a 

shipper’s retroactive nomination and daily nomination cannot exceed the shipper's Maximum 

Daily Quantity. Furthermore, under the Pilot program, DSPS proposes that pipeline imbalance 

penalties only apply to imbalances that are not corrected at the start of the following Gas 

Day. 

Separately, on August 19, the Commission issued a Notice announcing that Commissioner 

Phillip D. Moeller will convene a meeting on September 18, 2014 to discuss the concept of 

developing an electronic information and trading platform for natural gas. The purpose of 

the meeting is to provide a forum for interested parties to discuss ideas to facilitate and 

improve the way in which natural gas is traded, and explore the concept of establishing a 

centralized electronic trading platform that would include bids and offers for the purchase 

and sale of commodity and capacity for receipt and delivery points on and across multiple 

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pipeline systems. The meeting will also discuss concerns regarding the lack of transparency 

and possible inefficiencies in trading the commodity, particularly during off-hours. The 

meeting will examine the current pipeline confirmation processes and how they might be 

accelerated, streamlined, and better coordinated across pipelines where necessary to support 

trading opportunities. The meeting is open to the public and all interested parties are invited 

to attend.

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Inter-regional Initiatives

 Eastern Interconnection Planning 

Collaborative (EIPC)

 Eastern Interconnection States’ Planning 

Council (EISPC) 

Work continues on interregional natural gas-electric studies conducted collaboratively by the 

ISOs/RTOs and the states.

The Eastern Interconnection Planning Collaborative (EIPC) is now working on the Target 2 

study, which will evaluate the adequacy of the natural gas infrastructure in 2018 and 2023 to 

meet the expected core load and non-core gas-fired generation requirements on a Winter 

Peak Day and a Summer Peak Day. Work is focused on finalizing the second set of natural gas 

and electricity market assumptions on core and non-core demand levels such as infrastructure 

expansions, load growth, LDC expansion, and oil-to-gas conversion for Target 2 model inputs. 

The initial Target 2 draft report was posted on the EIPC website on June 20 and contains the 

methodology, inputs, and draft outline for the analysis of three demand scenarios and policy 

and infrastructure sensitivities. The High Gas Demand Scenario represents a “plausible 

maximum” level and profile of gas requirements driven primarily by increased deactivation or 

retirement of coal plants, lower delivered natural gas prices, and higher electric loads. The 

Low Gas Demand Scenario represents a “plausible minimum” level, driven primarily by the 

renewable resources displacement of gas-fired generation, higher delivered natural gas 

prices, and lower electric loads. The final Target 2 report is due in October 2014 and will 

provide complete analysis of possible infrastructure adequacy issues and propose potential 

mitigation measures. Target 3, on contingency analysis, and Target 4, on dual-fuel 

capability, are ongoing with discussions continuing through the Stakeholder Steering 

Committee. Northeastern ISOs and RTOs continue to work closely with representatives from 

the Planning Authorities in the Eastern Interconnection on the efforts of the EIPC study. 

The ICF-led study on Long-term Electric and Natural Gas Infrastructure Requirements in the 

Eastern Interconnection, prepared for NARUC and the Eastern Interconnection States Planning 

Council (EISPC), examines the potential build-out of natural gas infrastructure required to 

supply power and gas customers to 2030 under three demand and policy scenarios for the 

power sector in the Eastern Interconnect region. The preliminary study results presented in 

September find that the overwhelming factor driving natural gas infrastructure development 

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is the demand for electricity. The first scenario is the business-as-usual forecast for electric 

demand in the Eastern Interconnect from the present-day to 2030 based on existing policies 

and historical load growth. The second scenario forecasts the potential effects of policyinduced reductions in carbon emissions and electric demand from a national price on carbon, 

accelerated energy efficiency targets, and growing demand response options. The third 

scenario covers the potential effects from a renewable energy mandate in the Eastern 

Interconnect to satisfy at least 30 percent of electric load by 2030 with renewable energy 

resources. Findings from the study range from the highest total gas infrastructure costs by 

2030 under the renewable energy scenario ($121.9 billion) to the lowest total costs under the 

policy-induced scenario ($83.3 billion). The ICF study anticipates that a majority of the 

infrastructure build-out will occur between 2014 and 2024, and that much of the capacity 

increases will take place in northeastern and southwestern states due to their proximity to 

large shale plays. Along with exploring costs, reliability, and resource adequacy in relation to 

fuel infrastructure and siting requirements, the study also investigates analytical methods for 

co-optimizing future capacity expansion in both industries, and finds that total infrastructure 

costs are lower when planners in both sectors collaborate, compared to when capacity 

expansion plans are developed separately. The study also provides a blueprint for how to 

account for natural gas and power sector needs together given non-coincident growth in 

demand for both natural gas and electricity. ICF is currently reviewing comment submissions, 

which were due August 15, 2014. The final draft of the ICF study is scheduled for release in 

November 2014. The EISPC will convene a full committee meeting in Washington D.C. on 

October 2-3, 2014. The objective of the two-day meeting is to increase understanding of and 

facilitate compliance in the Eastern Interconnection with the Clean Power Plan (EPA Section 

111(d)).

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Regional Initiatives 

Northeast

 New England States Committee on 

Electricity (NESCOE) 

On June 11, 2014, the New England States Committee on Electricity (NESCOE) issued a 

memorandum summarizing stakeholder input on several potential conceptual means to 

increase natural gas infrastructure in New England, including the Incremental Gas for Electric 

Reliability (IGER) concept reported last quarter. In addition, in the memorandum the New 

England states requested further information, by July 3, 2014, including: 1) expressions of

interest from entities interested in acting as creditworthy counterparties to precedent 

agreements with natural gas pipeline companies, 2) further guidance on issues associated 

with the capacity manager role and/or indications of willingness to serve as a capacity 

manager and 3) input on other approaches and concepts that would increase natural gas 

infrastructure in New England in a way that delivers the highest value to electric customers.

 

On June 20, 2014 NESCOE provided an update to the New England Power Pool (NEPOOL) 

Transmission Committee on the Governor’s Infrastructure Initiative. NESCOE stated that the 

New England states will seek NEPOOL support for two new schedules in the ISO-NE tariff that 

would serve to be the vehicle for billing and collection in support of transmission and natural 

gas pipeline infrastructure to advance power system reliability. NESCOE explained that the 

ISO-NE tariff schedule related to gas infrastructure, called the Regional Gas-Electric 

Reliability Service would not include information regarding the process to select a gas 

pipeline project(s) and that the final project(s) and costs will not be known before ISO-NE 

files this schedule with the Commission. The schedule is intended to be used for this one 

time Infrastructure Initiative only, not for generic or future use. NESCOE also stated that no 

agreement has been finalized by the New England states. 

 

Specific to the IGER concept, NESCOE provided additional details in its update to NEPOOL. 

NESCOE explained that ISO-NE would enter into a Gas Infrastructure Billing and Collection 

Agreement with the entity or entities that act as counterparties with the pipeline(s) separate 

from, but in support of, the ISO-NE tariff schedule. The ISO-NE tariff schedule would allocate 

the costs of regional gas-electric reliability service to Regional Network Load. NESCOE stated 

that the charges would be pipeline and administrative costs less revenues received from 

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capacity release. Since capacity release revenues will vary with market conditions, NESCOE 

expects the Regional Gas-Electric Reliability Service charge to vary over time. Subsequently, 

on July 21, 2014, NESCOE issued for discussion at the July 22, 2014 NEPOOL Transmission 

Committee Meeting, ISO-NE draft tariff language for billing and collection of gas 

infrastructure support charges.

 

While NESCOE expected NEPOOL to vote on the draft tariff language in August and 

September, on August 15, 2014, at the NEPOOL Participants Committee meeting, NESCOE 

requested an extension of the NEPOOL schedule for consideration of proposed tariff language 

in connection with the Governors’ Infrastructure Initiative. 

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Regional Initiatives 

Mid-Atlantic

 NYISO

 PJM

NYISO is continuing to sponsor meetings for discussion of the EIPC study and provides a forum 

for participants to discuss ongoing progress, sensitivity developments, and analysis. 

The PJM Gas Electric Senior Task Force has been suspended until further notice. In 

preparation for winter 2014-2015, PJM determined that gas unit commitment issues are best 

addressed by the Operating Committee, where short-term adjustments to natural gas-fired 

generation scheduling can develop in tandem with cold-weather generation resource 

planning, capacity performance, and other operations-focused issues. The Operating 

Committee is conducting gas unit commitment coordination meetings to educate stakeholders 

on the balance between economic dispatch and reliability, and to achieve consensus on 

solutions to natural gas scheduling issues discovered during the cold weather events of winter 

2013-2014. Some identified components for stakeholder discussion include new data 

collection requirements from generators, such as a “Latest Notification Time,” a deadline for 

gas generator availability, and an associated “Price for the Latest Notification Time,” which 

would inform the system operator of the offers available from gas units on an hourly basis in 

both the day-ahead and real-time market. Since the first gas unit commitment coordination 

meeting on June 23, 2014, the Operating Committee has developed a cold weather 

preparedness work plan, held high-level discussions on refining the PJM capacity performance 

definition, and hosted educational seminars on natural gas scheduling, coordination 

infrastructure, and market fundamentals.

In August, PJM staff began discussions with stakeholders regarding generator performance 

concerns. In a white paper issued on August 1, PJM staff stated that the events of winter 

2014 operations highlighted issues related to generation performance, including a 22 percent 

forced outage rate on January 7, and increasing dependence on natural gas for power 

generation during winter peak conditions. PJM staff stated that the current requirements for 

resources to be considered a capacity resource do not appear to sufficiently address these 

observed generation performance issues, winter peak operations issues and operational 

characteristics that are needed to ensure that system reliability will be maintained going 

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forward. PJM stated that the changing resource mix—due to the retirement of a large number 

of coal-fired resources being replaced by natural gas resources—is creating greater 

operational stress on the power system as the interactions between the commodity gas 

market and interstate pipeline scheduling are not yet harmonized with power market 

operation. In the white paper, PJM staff discussed its analysis to assess the system loss of 

load risk in each of the next two winters. The study results indicate that if Polar Vortex 

conditions occurred in 2015-2016 and outage rates were as high as PJM experienced in 

January, 2014, PJM would almost certainly experience a loss of load event.

Following this white paper, PJM staff issued a “capacity performance” proposal and 

subsequently met with stakeholders to receive feedback on the proposal. PJM is proposing to 

add a new enhanced product—Capacity Performance—to its capacity market to ensure that 

the reliability of the grid will be maintained as the resource mix changes. Under the 

proposal, resources eligible to provide the Capacity Performance product must be capable of 

sustained, predictable operation for 16 hours per day for three consecutive days throughout 

the year when PJM has declared a Hot Weather or Cold Weather Alert and/or declared a 

Maximum Emergency Generation Alert. To be eligible as a Capacity Performance resource, 

PJM is proposing that an officer of the generation resource’s owner would have to certify that 

certain specific requirements—such as on-site or dual-fuel backup capability or a combination 

of firm pipeline transportation, firm commodity and access to storage or equivalent—have 

been met to ensure performance. PJM will not mandate how fuel availability is ensured, the 

decisions will be left to the individual resource owner on how to best manage fuel availability 

risks. PJM is using the Enhanced Liaison Committee Process, as opposed to the normal 

stakeholder process, to allow PJM and its members to develop solutions to this problem in 

time to be able to file its proposal to allow it to be in place by the winter of 2015.

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Regional Initiatives 

Central

 MISO

 SPP

MISO recently announced two initiatives aimed at improving real-time operational awareness 

for its operators and market participants following the experiences of the past winter. MISO 

created a natural gas pipeline notification page on its website, which is currently in the test 

phase and is scheduled to enter production by the end of September 2014. MISO is also 

working to implement a real time display of pipeline conditions in its control room. 

 

In addition, MISO plans to develop a coordination and communication plan with natural gas 

pipelines in its footprint by October that will allow MISO to maintain better situational 

awareness of pipeline delivery capabilities and the operational status of pipelines within its 

region. The coordination and communication plan will include pipeline outage and 

maintenance reviews, a protocol for monthly updates, and a natural gas pipeline operating 

status such as active operational flow orders and non-public pipeline operational information.

 

Finally, MISO's Electric and Natural Gas Coordination Task Force completed an issue paper on 

"Continued Reliability through Market Signals" and made progress on the four issue papers the 

Task Force will pursue this year. Preliminary findings of the 2014 papers suggest MISO could 

have maintained grid reliability during the January 2014 Polar Vortex event without the 

amount of coal generation expected to retire by April 2016, even with substantial natural gas 

restrictions. The papers further find that interruptible natural gas pipeline service 

adequately met the needs of generation owners in the MISO region prior to January 2014, and 

that natural gas pipeline infrastructure in the MISO footprint is sufficient to serve planned 

natural gas-fired generation additions in the next several years. However, the papers state 

that continued reliability beyond the next several years may require generation owners' 

commitment to firm pipeline service contracts now, considering that the process to permit 

and construct new pipeline capacity may take up to three years. 

 

The SPP Gas Electric Coordination Task Force issued a strawman proposal for changes to the 

SPP day-ahead market timeline during their July 31, 2014 meeting, and reviewed comments 

submitted by task force members and associated working groups regarding the proposed 

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changes during their August 25, 2014 meeting. The proposed changes are based upon a 

revised NAESB Timely Nomination Cycle (Timely Cycle) deadline of 1:00 pm Central for 

scheduling interstate natural gas pipeline transportation and are as follows: 1) move the time 

when SPP operating reserve requirements are posted from 7:00 am Central to 5:00 am 

Central, and 2) move the bidding period deadline of the SPP day-ahead market earlier, from 

11:00 am Central to 8:00 am Central. Stakeholders did not express concern with the proposal 

to post operating reserve requirements earlier in the day, but noted potential market and 

operation trade-offs with regard to moving the start of the bidding process of the day-ahead 

electric market before the nomination deadline for Timely Cycle. For example, some 

members were concerned that the compressed one-hour window between the end of the SPP 

day-ahead market bidding period and the deadline for scheduling pipeline transportation in 

the Timely Cycle presented purchasing and procurement difficulties for natural gas unless 

other issues were addressed, such as faster SPP market clearing processes. Other members, 

however, noted that more separation between the market clearing time and the operating 

day increased the potential for forecasting errors. The Gas Electric Coordination Task Force 

plans to continue discussion on comments to the strawman proposal at their next meeting on 

September 17, 2014.

 

SPP is currently developing a winter preparedness plan for winter 2014/15, which SPP 

anticipates implementing by December 1, 2014. This winter, SPP will act as the consolidated 

balancing authority for the region for the first time and will engage generators and pipeline 

operators in multiparty communications to better coordinate system operations and reliability 

during cold weather events. This effort builds upon SPP’s winter 2013/14 role as an 

information coordinator between pipeline companies and power generators, during which SPP 

began developing multi-party communication protocols for sharing non-public information. 

SPP expects to complete these multi-party communication protocols by December 1, 2014. 

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Regional Initiatives

West

 WIEB – SPSC

 PNUCC

 ColumbiaGrid

 CAISO

In the West, there are a number of sub-regional natural gas-electric coordination initiatives. 

In the third quarter, initial findings of Phase 2 of the Western Interstate Energy Board’s 

(WIEB) Natural Gas–Electric and System Flexibility Assessment were released. Phase 2 

evaluates the flexibility of the natural gas system and its ability to meet increased volatility 

in hourly electric demand with the increase of wind and solar resources in the Western 

Interconnection. The study subdivided the Western Interconnection into six sub-regional case 

studies to identify potential challenges. Phase 2 confirmed preliminary findings that physical 

infrastructure is generally adequate, and that such infrastructure is able to meet variable gas 

demands from increased integration of renewable resources comprising up to 26 percent of 

generation. Phase 2 found that increasing the penetration of renewable resources reduces 

the pipelines’ flexibility capability even though the overall level of gas demand growth from 

the power generation sector is lower when renewable resource penetration is higher. In 

addition, the study found that the increase in variability from renewable resources increases 

the frequency and magnitude of imbalances on pipeline systems which could cause 

operational issues on the gas systems. The report finds that the potential challenges can be 

mitigated with more flexible natural gas transportation services that offer similar flexibility 

as is currently provided by natural gas storage and effective management of linepack. 

Members of the Pacific Northwest Utilities Conference Committee (PNUCC) Power and Natural 

Gas Planning Task Force reviewed and provided feedback on the study. 

 

The full report is located on the WIEB website.( http://westernenergyboard.org/wpcontent/uploads/2014/07/E3_WIEB_Ph2_Report_full_7-28-2014.pdf) 

 

ColumbiaGrid will be performing a coal retirement study examining the transmission impacts 

of replacing coal units with natural gas. The study will include multiple scenarios in which 

the replacement gas units are sited in different parts of the Northwest. ColumbiaGrid plans 

to work in close coordination with natural gas entities to identify any interdependency 

concerns. A final study report is scheduled for December 2014. 

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On April 30, 2014 CAISO released an issue paper and straw proposal and initiated a 

stakeholder initiative to explore interim ISO tariff solutions to account for natural gas market 

conditions in minimum load and start-up costs. Currently, CAISO calculates the start-up and 

minimum load costs for resources under either a proxy cost or registered cost option selected 

by the resource. Under the proxy cost option, CAISO is required to rely on at least two 

natural gas price indices published the day prior to running the day-ahead market. CAISO 

proposes to retain the proxy cost option, but modify it to increase the proxy cost option bid 

cap from 100% of the daily calculated cost to 125%. CAISO states that this increase in the bid 

cap will provide flexibility to account for a variety of costs such as normal gas price volatility 

and the one day lag in the gas price indices used in the day-ahead market. 

 

CAISO notes that the increased proxy cap will be effective on most days, but it would not be 

able to capture extreme price spikes. Therefore, CAISO proposes to retain a portion of the 

manual operations utilized last winter to update the natural gas price index using the single 

ICE index, the only one available the morning of the day-ahead market optimization. The 

manual process would be triggered when the natural gas price for any region is more than 

125% of the natural gas price for that region from the previous night, which CAISO expects to 

be rare. CAISO would prefer a non-manual solution to correct for the lag in updating the gas 

price indices used in the optimization, but may not be able to implement one before the next 

winter season.

 

Under the registered cost option, the gas price is based on a monthly forward projection and 

is limited to no more than 150% of the projected proxy costs. Currently, resources selecting 

the registered cost option must remain under that option for at least 30 days. CAISO views 

the registered cost option as largely obsolete given the proposed improvements to the proxy 

cost option and proposes to limit its use. 

 

CAISO anticipates bringing the proposal to the CAISO Board of Governors in mid-September, 

and implementing the proposed solutions prior to the 2014-2015 winter season to address the 

potential for high natural gas price spikes as occurred last winter. For more comprehensive, 

long-term solutions with greater implementation impacts, the CAISO expects to commence a 

bidding rules initiative in the third quarter of 2014. This future initiative will explore a 

broader array of bidding rules in the ISO market, including those for energy and commitment 

costs. 

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Relevant 

Natural Gas Filings

Region Pipeline/Association Capacity/

Initiative

Docket 

No.

Status

Northeast Transco Rock Springs Expansion 

Project

Capacity addition

192 MMcfd

CP14-504-000 Filed 

6/23/2014

Southwest Sierrita Gas Pipeline Capacity addition

200 MMcfd

CP13-73 & 74 Under Construction 

7/1/2014

Southeast Colombia Pipeline Capacity addition

1.12 Bcfd

CP14-513-000 Filed 

7/1/2014

Northeast Algonquin Salem Lateral Project Capacity addition

115 MMcfd

CP14-522-000 Filed 

7/10/2014

Northeast Algonquin Incremental Market 

Project

Capacity addition

342 MMcfd

CP14-65-000 DEIS issued

8/6/2014

Northeast Transco Woodbridge Delivery 

Lateral

Capacity addition 

264 MMcfd

CP14-18-000 Approved 

8/11/2014

Southeast Southeast Supply Header 

Expansion Project

Capacity addition

45 MMcfd

CP14-87-000 Approved

8/14/2014

National 157 interstate natural gas 

pipelines 

Order to Show Cause, 

Posting of Offers to 

Purchase Capacity

RP14-442-000 Pending

West Transwestern Pipeline Company Framing system balancing 

and operational issues

RP13-404-002 Approved

Mid-Atlantic Transcontinental Gas Pipe Line 

Company

Order No. 787 on No-Conduit 

Rule

RP14-623-000 Approved

Northeast National Fuel Gas Supply 

Corporation and Empire Pipeline

Request for Rehearing 

Regarding Limited Waivers 

of No-Conduit Rule adopted 

in Order No. 787

RP14-380-001 Pending

We now provide an update on relevant natural gas and electric filings submitted with or 

pending before the Commission, starting with natural gas pipeline applications. As discussed 

in more detail below, during this quarter the Commission received a new filing to expand 

pipeline capacity serving electric generation, approved two proposed projects, and received 

or acted on additional filings proposing enhanced services or tariff revisions to improve 

natural gas-electric coordination. 

 

In the Northeast, on June 23, 2014, Transcontinental Gas Pipe Line Company, LLC (Transco) 

requested authorization to construct and operate its Rock Springs Expansion Project. This 

project will provide 192 MMcfd of firm transportation capacity to serve Old Dominion Electric 

Cooperative's proposed Wildcat Point Generating facility in Cecil County, Maryland.

 

In the Southeast, on June 6, 2014, Sierrita Gas Pipeline, LLC (Sierrita) received its 

Presidential permit to construct and operate new border crossing facilities for exporting

natural gas to Mexico, and was also certificated to transport approximately 200 MMcfd. After 

receiving its initial construction commencement approval on July 1, Sierrita began 

construction to serve growing natural gas demand from power generation in Mexico and is 

working on its final segment to the pipeline terminus at the border with Mexico. Sierrita 

proposes to place the facilities in service in September 2014. 

 

Additionally, on July 1, 2014, Colombia Pipeline, LLC (Colombia) filed an application for an 

order authorizing the siting, connection, construction, and operation of new border crossing 

pipeline facilities to export up to 1.12 Bcfd of natural gas at the International Boundary 

between the United States and Mexico in Webb County, Texas, and for a Presidential Permit 

for such facilities. At the International Border, a 0.48-mile pipeline on the México side will 

be constructed which will redeliver natural gas supplies into the pipeline system to a 

proposed power plant to be constructed near Colombia, Nuevo León, México.

 

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On July 10, 2014, Algonquin Gas Transmission, LLC (Algonquin) filed an application for 

authority to construct, and operate its Salem Lateral Project located in Salem, Massachusetts. 

The proposed 1.2-mile Salem Lateral would provide 115 MMcfd of firm transportation service 

to the Salem Harbor Station facility being converted from coal to natural gas by June 2016.

 

On August 6, 2014, Algonquin Gas Transmission, LLC (Algonquin) Incremental Market Project 

(AIM Project) received its draft Environmental Impact Statement. The AIM Project will 

provide a total of 342 MMcfd of firm transportation service. Algonquin has executed 

Precedent Agreements for all of the capacity with ten shippers, including eight New England 

local distribution companies (LDCs) and two municipal utilities. The AIM Project, targeted for 

a 2016 in-service date, is expected to alleviate, in part, existing constraints resulting in 

increased commodity price competition and reduced natural gas price volatility in the 

Northeast markets. 

 

On August 11, 2014, Transco was granted a certificate of public convenience and necessity to 

construct and operate approximately 2.4 miles of 20-inch diameter pipeline and associated 

facilities in Middlesex County, New Jersey, the Woodbridge Delivery Lateral Project. The 

Project will enable Transco to provide 264 MMcfd of incremental firm transportation service 

to the Woodbridge Energy Center, an electric generating facility being developed in 

Woodbridge, New Jersey. 

 

On August 14, 2014, Southeast Supply Header, LLC received approval for its Expansion Project 

to increase the design capacity of its mainline to provide an additional 45 MMcfd of firm 

transportation service and to construct and operate a new booster compressor station 

facilities in Copiah County, Mississippi. Southern Company Services, Inc. executed a 

precedent agreement for 25 MMcfd of firm transportation service for a primary term of 

approximately 10 years to serve its natural gas-fired generation needs. 

 

Since last quarter, 10 additional interstate natural gas pipelines, now totaling 157, submitted 

filings to the Commission in response to the Commission’s March 20, 2014 order establishing a 

Natural Gas Act (NGA) section 5 show cause proceeding requiring all interstate natural gas 

pipelines to revise their tariffs to provide for the posting of offers to purchase released 

pipeline capacity in compliance with section 284.8(d) of the Commission’s regulations, or to 

otherwise demonstrate full compliance with the Commission’s regulation. This matter is 

pending before the Commission.

 

On June 23, 2014, the Commission approved a settlement filed by Transwestern Pipeline 

Company, LLC (Transwestern). The settlement includes a Scheduling Protocol providing 

enhanced daily scheduling and gas balancing flexibility for electric generators and other 

shippers on the Transwestern system. The Protocol provides that firm shippers that nominate 

inside the path in the Timely cycle are able to schedule those nominated quantities until the

Evening cycle regardless of whether the full nomination is confirmed or scheduled during the 

Timely cycle. To allow additional time to secure supplies without the risk of losing capacity 

priority at the delivery area, the Protocol allows for firm shippers to nominate during the 

Timely and Evening cycles at five newly created Balancing Receipt Points.

 

On August 18, 2014, the Commission issued an order in Docket No. RP14-623-000 granting 

Transco’s requested waiver to allow employees shared by Transco and its affiliated intrastate 

pipeline to receive non-public, operational information under Order No. 787, subject to 

conditions.

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Following the Commission’s June 19, 2014 order granting in part and denying in part National 

Fuel Pipelines’ request for waivers of Order No. 787 in Docket No. RP14-380-000, on July 21, 

2014, National Fuel Pipelines filed a request for rehearing. Specifically, National Fuel 

Pipelines argue that the Commissions should (1) permit non-shared employees of National 

Fuel Pipelines’ affiliates to receive information about power interruptions to their places of 

work; and (2) permit Midstream employees to receive information about power interruptions 

to Midstream facilities. These filings are pending before the Commission.

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Relevant

Electric Filings

Entity Filing Initiative Docket No.

PJM Pipeline Information-Sharing Changes under Order No. 787 ER14-1469-001

National Fuel Request for Rehearing ER14-1469-002

National Fuel Motion for Clarification RM13-17-002

Old Dominion 

Electric 

Cooperative 

Waiver Request ER14-2242 

ISO-NE and 

NEPOOL

Rule Changes as part of the 2014-2015 Winter Reliability 

Program

ER14-2407-000 

and ER14-2407-

001

Turning to relevant electric filings, as reported last quarter, on May 9, 2014, the Commission 

accepted, subject to conditions, PJM’s proposed tariff revisions to modify the confidentiality 

rules to allow PJM to share non-public, operational information with natural gas pipeline 

operators, consistent with the Commission’s regulations adopted in Order No. 787. However, 

the May 9 Order also required PJM to resubmit tariff records and specify which local 

distribution or intrastate pipeline employees will be prohibited from receiving non-public, 

operational information. On May 27, 2014, PJM filed a revised tariff record in Docket No. 

ER14-1469-001 to require that a recipient LDC or intrastate pipeline operator acknowledge, in 

writing, that it shall not disclose, or use anyone as a conduit for disclosure of, non-public, 

operational information received from PJM to a third party or in an unduly discriminatory or 

preferential manner or to the detriment of any natural gas or electric market. On July 16, 

2014, the proposal was accepted for filing by delegated order, effective March 13, 2014.

 

On August 15, 2014, National Fuel Gas Distribution Corporation (National Fuel) submitted a 

Motion for Clarification or, in the Alternative, Request for Rehearing of the Commission’s May 

9, 2014 and July 16, 2014 Letter Orders in Docket No. ER14-1469 discussed above. National 

Fuel states that PJM’s revised tariff language may inhibit appropriate sharing of operational 

data and discourage LDCs and intrastate pipelines from maximizing use of the data to improve 

reliability. This matter is pending before the Commission. 

 

On August 27, 2014, National Fuel also submitted, in Docket No. RM13-17-002, a Motion for 

Clarification of Order No. 787, the Commission’s Final Rule regarding Communication of 

Operational Information Between Natural Gas Pipelines and Electric Transmission Operators, 

and Order No. 787-A, the Commission’s Order on Rehearing. National Fuel requests the 

clarification to provide further guidance regarding implementation of the Final Rule and 

ensure that the Commission’s stated goals in the Final Rule are uniformly carried out and met 

to the fullest extent. This matter is pending before the Commission.

 

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On June 23, 2014, Old Dominion Electric Cooperative (ODEC) filed a request for waiver of 

certain provisions of PJM’s tariff and Operating Agreement in Docket No. ER14-2242 to make 

ODEC whole for natural gas costs it incurred in January 2014 in its efforts to meet dispatch 

instructions issued by PJM. This matter is pending before the Commission.

 

On July 11, 2014, ISO-NE filed a package of rule changes in Docket Nos. ER14-2407-000 and 

ER14-2407-001 that establish a 2014-2015 Winter Reliability Program. While similar to the 

2013-2014 Winter Reliability Program previously accepted by the Commission, several 

components of the proposed 2014-2015 Program differ. The package is comprised of six 

components, two of which are permanent changes while the other four are temporary 

changes to be in place for this winter. According to ISO-NE, one of the permanent rule 

changes will enhance ISO-NE’s ability to audit dual fuel resources. The second permanent 

rule change will adjust the market monitoring provisions to remove impediments for dual fuel 

resources which have cleared in the day-ahead market based upon one fuel, but may wish to 

burn the other fuel during the operating day. In addition, ISO-NE proposes to include LNG 

supplies in the 2014-2015 Winter Reliability Program, along with oil-fired, dual fuel, and 

demand response resources, all of which were included in the 2013-2014 program. ISO-NE 

also proposes to change the compensation for oil inventory for the 2014-2015 Program from 

last winter’s Reliability Program. In contrast to 2013-2014 program, where ISO-NE 

compensated resources for the fuel inventory procured ahead of the winter, ISO-NE proposes 

to compensate resources this winter for their unused fuel inventory measured at the end of 

the season, March 15, 2015. ISO-NE proposes to allocate the costs of the 2014-2015 program 

to Real Time Load Obligation. On September 9, 2014, the Commission accepted ISO-NE’s 

2014-2015 Winter Reliability Program for filing, with the proposed tariff revisions regarding 

dual fuel capability, unused fuel inventory, market monitoring, and demand response to 

become effective September 9, 2014, as requested, and the tariff revisions regarding market 

monitoring to become effective December 3, 2014 as requested. However, the Commission 

required ISO-NE to initiate a stakeholder process by January 1, 2015 to develop a proposal to 

address reliability concerns for the 2015-2016 winter and future winters, as necessary, and 

submit informational progress reports. The Commission also directed ISO-NE to include 

certain analysis and recommendations as part of the Internal Market Monitor’s Annual Markets 

Report. 

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Staff’s final quarterly report is due in December. 

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