Gas-Electric Coordination

Quarterly Report to the Commission

Docket No. AD12-12-000

September 19, 2013

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. 
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Item No: A-3

September 19, 2013

Gas-Electric Coordination 

Quarterly Update

Docket No. AD12-12

This presentation is Commission staff’s third Quarterly Update on Gas-Electric Coordination Activities, 

as directed by the Commission in its November 15, 2012 order in Docket No. AD12-12, and covers the 

period June 2013 to August 2013. 

National trade organizations or their members continue to discuss gas-electric coordination with the 

RTOs and ISOs. Many of the trade associations’ individual members continue to also be involved in 

regional gas-electric working group efforts and regional studies. This report focuses on significant new 

developments in several regional initiatives that have occurred since our last report, and briefly 

summarizes Commission initiatives as well as recent industry applications filed with the Commission. 
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Regional Initiatives 

Northeast

 NESCOE

 ISO-NE

The following slides provide an update on developments in several regional gas-electric coordination 

initiatives since our last report, and are based on staff outreach and monitoring of the regional gaselectric coordination task force meetings.

We start with New England. According to recent discussions of the New England States Committee on 

Electricity (NESCOE) Gas-Electric Focus Group, the group has largely accomplished its initial objectives 

of information exchange and discussion of potential short-term solutions to supply reliability concerns 

as originally set forth in their Path Forward document. With a short-term winter plan as set forth in 

ISO-NE’s Winter Reliability plan, which is currently pending before the Commission, NESCOE will now 

focus on medium to long-term plans. Going forward, the Focus Group will meet as issues warrant,

rather than on a monthly basis; it plans to convene in October to discuss additional results from Phase 

III of a multi-phase New England pipeline capacity study being conducted by Black & Veatch. As we 

noted in our last quarterly report, Phase II of that study reviewed historical natural gas demand, 

provided an outlook for growth of natural gas by sector over the next 15 years, and estimated costs for 

infrastructure options. The recently finalized Phase III recommends a short-term strategy that includes 

immediate deployment of dual-fuel generation, demand response measures, and the seasonal purchase 

of LNG cargoes. In the long-term, a cross-regional natural gas pipeline solution is recommended, which 

will provide twice the net benefits to New England consumers than would be contributed by the firmbased Canadian energy imports solution. 

ISO-NE continues to consider and file with the Commission changes to its market rules and tariff to 

address gas-electric issues. 
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Regional Initiatives 

Mid-Atlantic

 EIPC 

 PJM

 EISPC

 NYISO

Turning to the Mid-Atlantic, progress continues on the Eastern Interconnection Planning Collaborative 

(EIPC) Study involving ISO-NE, NYISO, PJM, MISO, Ontario IESO and TVA. This study is a multi-regional 

natural gas/electric analysis of major interstate, intrastate, and local natural gas infrastructure serving 

the Eastern Interconnection. Many members of INGAA, NGSA, and AGA continue to be involved in the 

study with PJM leading the study as the principal investigator. 

As noted in the last quarterly report, the primary objectives of the study are to develop a baseline of 

the electric and natural gas systems; evaluate the adequacy of the regional gas systems to supply gasfired generation needs over a 5-10-year horizon; identify contingencies on the natural gas system that 

could adversely affect the electric system and vice versa; and review the benefits and costs of dualfuel capability compared with securing firm gas transportation. A detailed scope of work for the study 

along with the final request for proposals was issued on August 2 with bids due August 30. Final work is 

scheduled to be completed by May 2015. A meeting of the stakeholder steering committee is 

scheduled for October 29-30 in Washington, D.C.

In addition to leading the EIPC study efforts, PJM continues to conduct meetings through its Gas 

Electric Senior Task Force. In upcoming monthly meetings, the Task Force will focus on discussing and 

prioritizing gas electric issues. 

The Eastern Interconnection States’ Planning Council (EISPC) conducted roundtable discussions in 

August with Commissioner Moeller, national electric and natural gas industry associations as well as 

end-user associations participating. The purpose was to elicit from participants the gas-electric issues, 

concerns, and potential solutions that could then be considered by the collaborative and study 

consultants as they begin the long-term Electric and Natural Gas Infrastructure Requirements Study and 

Whitepaper. The Study is intended to produce a long-term analysis of the potential electric and 

natural gas infrastructure requirements in the Eastern Interconnection for the 2011-2030 timeframe 

under three build-out scenarios. The Whitepaper is intended to provide additional focus on natural gas 

and electric system operations and market structure; address issues such as contracting, planning, 

regulatory, and confidentiality procedures; and provide recommendations on potential payment 

options and future actions to improve the coordination between the electric system and the natural gas 

system. The Study and the Whitepaper are expected to be completed in June 2014.
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NYISO staff continues to hold regular meetings of the Electric-Gas Coordination Working Group to foster 

discussion of gas-electric issues. At the June meeting, the final Task 1, and preliminary Task 2 findings 

of the Levitan & Associates Fuel Assurance Study were presented. Task 1 of the Study examined the 

relative cost and benefit of providing fuel assurance through dual-fuel capability against incremental 

cost of obtaining firm transportation entitlement from a liquid sourcing point to the delivery points of a 

gas-fired generator. Task 2 goes into further detail regarding grid security, analyzing historical 

pipeline congestion patterns across the New York Control Area, assessing the impact of new pipeline 

additions on transport deliverability over a five-year study horizon into and across New York, and 

identifying potentially disruptive gas system contingencies across the supply chain from the producing 

area to the NYISO market center. 
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Regional Initiatives 

Central

 MISO

 SPP

 ERCOT

In the Midwest, MISO’s Electric and Natural Gas Coordination Task Force continued to meet 

monthly. At its August meeting, the preliminary results of Phase III of the MISO Gas-Electric 

Interdependency Analysis were presented. Phase III assessed the ability of natural gas infrastructure in 

the MISO footprint to serve growing demand; and identified current and potential areas of pipeline 

congestion and changing flow patterns and development trends. The results showed that recent 

pipeline capacity additions have contributed to a decrease in the number of days in which capacity 

would have been unavailable for the majority of the MISO-region pipelines. The results also suggested 

natural gas supply diversity is expected to increase in the region. Final results are expected to be 

presented at the September 15, 2013 Task Force meeting. 

MISO is also working on a number of whitepapers. For example, MISO stakeholders are in the process of 

finalizing a paper that addresses the potential misalignment of gas and electric schedules. A paper on 

resource adequacy paper will be revised following stakeholder feedback and finalized in September. 

Additionally, a paper on coordinated operations remains under development. It is expected that this 

paper will recommend various communication enhancements and operational awareness 

improvements, and identify key data to be shared between the gas and electric industries. The Task 

Force is also working on a paper that will examine adjustments to the energy and capacity markets to 

provide market signals to incentivize generators to secure an appropriate amount of firm gas supply 

and transportation. 

Turning to SPP, the Gas-Electric Coordination Task Force conducted a natural gas-fired generator 

survey, held training sessions with gas pipeline and marketer personnel, and implemented a visual 

pipeline mapping tool. The Task Force is now working on developing its proposed work plan to be 

presented at its September 6 meeting, and is in discussions regarding a potential study for its region 

similar to the EIPC study described earlier in this report. 

ERCOT continued regional coordination efforts and participated in a Texas Energy Reliability Council 

(TERC) conference call on July 10. Main topics of the call included gas storage status, summer electric 

generation needs affecting gas demand and any planned pipeline maintenance that might affect 

delivery. No problems with gas delivery to electric generation during the summer season were noted. 

ERCOT continued working with gas pipeline companies to determine the electric supply needs of gas 
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facilities critical to providing fuel to black start and next start generating units. According to ERCOT, 

these needs will be integrated into its black start restoration plan for 2014-2015 (described in staff’s 

second quarterly report). ERCOT is also working to finalize a Non-Disclosure Agreement that is 

reported to allow the cross industry sharing of protected or confidential gas infrastructure information 

from gas pipelines and suppliers and detailed electric infrastructure information from ERCOT, 

transmission and distribution companies, and black start resources.
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Regional Initiatives

West

 PNUCC

 WIEB – SPSC

 CAISO

 Desert Southwest Task Force

The West has a number of sub-regional natural gas-electric coordination initiatives. 

In the Pacific Northwest, natural gas pipelines and electric utilities continue to discuss enhanced 

communications and coordination through the Pacific Northwest Utilities Conference Committee 

(PNUCC) Power and Natural Gas Planning Task Force. The Western Gas-Electric Regional Assessment 

Task Force issued an RFP for its Western Natural Gas – Electric and System Flexibility Assessment. 

Phase I of the study will explore adequacy of the natural gas infrastructure to meet the long-term (10 

years) needs of the electric industry in the Western Interconnection. Phase II will drill down on shortterm adequacy of natural gas operational flexibility to meet the Western Interconnection’s operational 

flexibility needs with increasing integration of renewables. All of the gas supply and transportation 

modeling work in Phase II will be performed by the pipeline companies. The two-phase study will be 

led by the Technical Advisory Group (TAG) with representation from industry, regulators, and others 

engaged in examining the interface of the gas and electric sectors in the Western Interconnection. The 

selection of contractors to conduct the study was made on September 6. The initial study results are 

expected to be completed in a 9-month period, three months dedicated to Phase I and six to Phase II, 

with final results due at the end of 2014. 

The PNUCC Power & Natural Gas Planning Taskforce is exploring a second phase I-5 Corridor study 

based on the initial ColumbiaGrid Gas-Electric Interdependencies Study. The initial study generally 

concluded that the current infrastructure is adequate to meet current daily gas demand. Based on 

hourly gas demand, the second phase of the study will explore how the system would respond to 

increased natural gas generation sited in the I-5 corridor, and whether the system would be able to 

handle large swings driven by gas demand from power plants and direct service companies. The Task 

Force hopes to begin the analysis by its October meeting.

The California ISO continued with similar work as reported in prior quarters.

The Desert Southwest Task Force continued to evaluate and narrow potential solutions for addressing 

reliability, market, and long-term capacity needs. Key discussions have focused on whether to: (1) 

remove the no-bump rule related to scheduling interruptible service on pipelines; (2) maintain the 

timing of existing pipeline nomination opportunities to schedule transportation, but move the Intra-Day 
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2 nomination cycle for natural gas transportation later in the day and add a no-bump nomination cycle; 

(3) offer additional Intra-day nomination cycles; (4) move the start of a gas day; and (5) have a new 

daily transportation service reserved for gas-fired power plants providing ancillary 

services/contingency reserves.
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July 18 Communications 

NOPR

 Proposes to authorize the sharing of 

non-public, operational information 

between interstate pipelines and electric 

transmission operators 

 Proposes a No-Conduit Rule to prohibit 

disclosure of non-public, operational 

information to a third party

The Commission, on July 18, issued proposed rules to address information sharing and communications 

issues between the natural gas and electric industries. These proposed rules built on the discussions 

and information learned from conferences and comments filed with the Commission following the 

February 13 technical conference. 

In brief, the proposed rule would revise regulations to authorize expressly the sharing of non-public 

operational information between the interstate natural gas pipelines and electric transmission 

operators – not just during emergencies but also for day-to-day operations, planned outages, and 

scheduled maintenance. It would also adopt a No-Conduit Rule to prohibit recipients of non-public 

operational information from subsequently disclosing, or using anyone as a conduit for the subsequent 

disclosure of that information to a third party.

The Commission received 33 comments in response to the proposed rule.
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Relevant 

Natural Gas Filings

Region Pipeline Capacity/Initiative Docket No.

MidAtlanticEastern Shore Natural 

Gas Company

Capacity expansion ~55,200 Dth/d CP13-498

Southeast Transcontinental Gas 

Pipe Line Company

Capacity expansion ~225,000 Dth/d CP13-523

Southeast Gulf South Pipeline 

Company & Petal Gas 

Storage

Alternative No-Notice Service RP13-1245-

000 & CP13-

532-000

Our last area to cover is applications that have been filed with the Commission. During the third 

quarter, the Commission received two applications to expand pipeline capacity serving electric 

generation and one application to increase operational flexibility. 

Eastern Shore Natural Gas Company filed on June 13, 2013 a proposal to build a 5.5-mile pipeline 

lateral to transport 55,200 Dth per day for Calpine Energy Services, LP for use in the Garrison Energy 

Center, a proposed 309-MW combined cycle power plant under development by a subsidiary of the 

Calpine Corporation (Docket No. CP13-498-000). This matter is pending before the Commission.

Transcontinental Gas Pipe Line Company’s Mobile Bay South III Expansion Project filed on July 18, 2013, 

proposes to add 225,000 Dth per day of firm transportation capacity (Docket No. CP13-523-000). This 

will indirectly serve power generation because the two anchor shippers on the project are Southern 

Company Services, Inc. and PowerSouth Energy Cooperative; both operate a substantial portion of gasfired generation in the Southeast and Florida. This matter is pending before the Commission.

On August 13, 2013 Gulf South Pipeline Company, LP (Gulf South), filed tariff records proposing a new 

Alternative No-Notice Service (NNS-A) designed to meet the requirements of local distribution 

companies, electric generation markets, and other customers that desire a flexible no-notice service 

(Docket No. RP13-1245-000). Gulf South states that the storage component of its proposed NNS-A will 

be provided utilizing firm storage capacity acquired through a lease of storage capacity from Petal Gas 

Storage, L.L.C. (Petal) located in Mississippi, for which a joint certificate application was filed by Gulf 

South and Petal ( Docket No. CP13-532-000). In that docket, the applicants seek an order from the 

Commission authorizing Petal to abandon by lease to Gulf South a Maximum Storage Quantity of 

1,000,000 Dth, a Maximum Daily Withdrawal Quantity of 50,000 Dth per day, and a Maximum Daily 

Injection Quantity of 25,000 Dth per day to support Gulf South’s proposed NNS-A. This matter is 

pending before the Commission.
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Relevant

Electric Filings

Entity Filing Initiative Docket No.

Dominion Energy 

Marketing and ISO-NE

Recover over $336,095 in fuel costs as well as 

regulatory costs, and new cost recovery trigger

ER13-1291 and 

EL13-72

ISO-NE and New 

England Power Pool

Forward reserve market incentives changes ER13-1733

ISO-NE and New 

England Power Pool

Reserve market revisions to more accurately reflect 

ISO-NE initiated reliability actions in market prices

ER13-1736

ISO-NE and New 

England Power Pool

A reliability project for winter 2013-14 ER13-1851

ISO-NE and New 

England Power Pool

Offer flexibility changes ER13-1877

ISO-NE Results of bidding in its Winter 2013-2014 Reliability 

Program

ER13-2266

Recent filings made by the electric industry to address increasing reliance on natural gas-fired 

generators as well as previously-reported filings that have been the subject of recent Commission 

action are highlighted on this slide. 

On April 15, 2013, Dominion Energy Marketing, Inc. (Dominion) filed a request under Section 205 of the 

Federal Power Act seeking recovery of $336,095 in fuel costs (and for regulatory costs) for its 

Manchester Street Station Units under ISO-NE’s Constrained Area Mitigation and Reliability Commitment 

Mitigation processes. The Commission issued an order on June 14, 2013 granting Dominion’s request, 

subject to a compliance filing detailing the actual regulatory costs (June 14 Order). The June 14 Order 

also directed ISO-NE to revise its tariff to provide a mechanism for future recovery of similar costs. On 

August 13, 2013, ISO-NE filed revisions to Appendix A of its tariff to include a non-market opportunity 

for market participants to request additional cost recovery. On August 16, 2013, Dominion filed actual 

regulatory expenses incurred, in response to the June 14 Order. ISO-NE’s compliance filing, and 

Dominion’s request for rehearing and compliance filing are pending before the Commission. (Docket 

Nos. ER13-1291-000 and EL13-72)

On June 20, 2013, ISO New England Inc. and New England Power Pool Participants Committee (ISO-NE 

and NEPOOL) filed market rule changes to adjust the Forward Reserve Failure-to-Reserve Penalty to 

better incent appropriate performance by reserve resources; if approved, these changes would be 

implemented in October 2013. (Docket No. ER13-1733-000) ISO-NE and NEPOOL state that the current 

penalty structure, at times, provides incentives for resources to self-schedule rather than follow 

dispatch instructions to provide reserves. On August 15, 2013, the proposal was accepted for filing by 

delegated order, effective October 1, 2013.

On June 20, 2013, ISO-NE and NEPOOL submitted a filing to better reflect the cost of actions that the 

ISO takes to maintain system reliability in market prices by establishing a replacement reserve 

requirement to procure additional reserves and establishing a Reserve Constraint Penalty Factor (RCPF) 

at $250/MWh, a price cap for real-time reserve clearing prices. On August 15, 2013, the proposal was 

accepted for filing by delegated order, effective October 1, 2013. (Docket No. ER13-1736-000)
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On June 28, 2013, ISO-NE and NEPOOL filed a proposal to acquire “oil inventory” services from oil-fired 

and dual-fuel generators to mitigate risk to the electric system from natural gas supply problems during 

Winter 2013-2014 (Winter Reliability Program) (Docket No. ER13-1851). Under this proposal, oil-fired 

and dual-fuel generators would establish a specified amount of oil inventory for the winter in exchange 

for an “as bid” monthly payment to provide energy in case of a reliability event. ISO-NE would also 

procure demand response services under the Winter Reliability Program. On August 9, 2013, the Filing 

Parties filed amendments to the Winter Reliability Program to encourage increased participation by oilfired generators. This matter is pending before the Commission.

On July 1, 2013, ISO-NE and NEPOOL submitted a filing proposing tariff changes to allow market 

participants to change their energy market offers in real-time during the operating day (Docket No. 

ER13-1877). If approved, these changes would be implemented in December 2014. Currently, 

participants are permitted to modify their supply offers in the day-head market only once, between 

1:30 pm and 2:00 pm. ISO-NE and NEPOOL argue that the re-offer changes they propose will improve 

market participant’s abilities to reflect the cost of obtaining fuel in their energy market offers, and 

allow real-time energy prices to more accurately reflect the marginal cost of energy. This matter is 

pending before the Commission.

On August 26, 2013, ISO-NE submitted the results of bidding in its Winter 2013-2014 Reliability 

Program, including information regarding the bidders that ISO-NE proposes to select to provide demand 

response and oil inventory services under Appendix K of its tariff (Docket No. ER13-2266). ISO-NE 

states that it targeted a procurement of demand response and oil inventory services of 2.4 million MWh 

(4.2 million barrels of oil) and received bids amounting to 2.29 million MWh, or 96% of its target, at a 

total price of $114.3 million. ISO-NE proposes to accept 1.995 million MWh, or 83.1% of its targeted 

MWh at a price of $78.8 million. This matter is pending before the Commission.

Staff’s next quarterly report is due in December. Staff will continue regular outreach with national 

and regional entities and with regulated entities regarding their efforts on gas-electric coordination.