Gas-Electric Coordination

Quarterly Report to the Commission

Docket No. AD12-12-000

December 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. 

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Slide 1

December 18, 2014

Gas-Electric Coordination 

Quarterly Update

Docket No. AD12-12

This report is Commission staff’s eighth and final quarterly update on national and regional 

Gas-Electric Coordination Activities, as directed by the Commission in its November 15, 2012 

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

December 2014. 

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

report in September 2014, highlights comments filed in response to the Commission’s natural 

gas pipeline scheduling Notice of Proposed Rulemaking (NOPR) in Docket No. RM14-2, and 

briefly summarizes recent industry applications filed with the Commission. 
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Slide 2

National Initiatives

 NERC – 2014-2015 Winter Reliability 

Assessment

 Natural Gas Pipeline Scheduling (Docket No. 

RM14-2-000)

• NAESB Response to NOPR

• Industry stakeholder comments filed on 

November 28

• RTO/ISO data request

In November, the North American Electric Reliability Corporation (NERC) published their 2014-

2015 Winter Reliability Assessment. NERC’s assessment of demand and generation projections 

for the 2014/2015 winter season indicate adequate resources under normal winter peak 

demand. However, the assessment states that prolonged and extreme cold weather may 

prove challenging in parts of North America due to natural gas and coal delivery constraints. 

NERC also highlighted regional challenges in areas where power generators rely on 

interruptible gas pipeline transportation, natural gas interstate pipelines are constrained to 

meet demand beyond firm commitments, and gas use for power generation is increasing. 

With increased reliance on natural gas-fired generation, NERC suggests additional revisions to 

assessing reliability in the future. For example, following last winter’s Polar Vortex events, 

NERC developed extreme weather scenarios to assess the potential impacts on reliability. 

Additionally, going forward, NERC recommends including assessment of fuel availability and 

deliverability when conducting resource adequacy assessments. 

With respect to the Commission’s rulemaking on natural gas and electric scheduling practices, 

on September 29, 2014 NAESB filed a report in Docket No. RM14-2-000 notifying the 

Commission of the adoption of consensus Wholesale Gas Quadrant (WGQ) standards modifying 

the nationwide timely and intraday nomination timeline as an alternative to the Commission’s 

proposals in the Notice of Proposed Rulemaking (NOPR) issued March 2014. Under the revised 

standards, the nomination deadline for the Timely and Evening Nomination Cycles are the 

same as those proposed in the NOPR—1:00 pm Central Clock Time (Central) and 6:00 pm 

Central, respectively. The timeline for intraday 1, intraday 2, and intraday 3 varies from that 

proposed in the NOPR and the nomination deadlines are at 10:00 am, 2:30 pm, and 7:00 pm, 
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all Central time. The NAESB-revised timeline does not include an intraday 4 cycle as 

proposed in the NOPR. 

The deadline for parties to file comments was November 28, 2014. The Commission received 

75 comments in response to the NOPR and Commission staff are now reviewing these 

comments.

On December 12, 2014, in Docket No. RM14-2-000, requests for data were issued to ISO-NE, 

NYISO, PJM, MISO, SPP, and CAISO regarding the impact on reliable and efficient operations of 

natural gas-fired generators running out of their daily nomination of natural gas 

transportation during the morning electric ramp. RTO/ISO responses to the data requests are 

due on or before January 12, 2015 and comments on the responses to the data request are 

due on or before January 22, 2015.
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Slide 3

Inter-regional Initiatives

 Eastern Interconnection Planning 

Collaborative (EIPC)

 Eastern Interconnection States’ Planning 

Council (EISPC) 

In the Eastern Interconnection, key stakeholders (including ISOs/RTOs, planning authorities, 

and the states) continue to work collaboratively on an inter-regional basis to study natural 

gas-electric coordination issues and assess infrastructure adequacy.

The final Eastern Interconnection Planning Collaborative (EIPC) Gas-Electric System Interface 

Study Target 2 Draft Report, which was originally targeted for release in October 2014, has 

been delayed. EIPC is continuing to review the draft prior to posting. As previously reported, 

the Target 2 study evaluated the adequacy of natural gas infrastructure in 2018 and 2023 to 

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

Day and a Summer Peak Day. Work on Target 3, a contingency analysis, is ongoing with 

discussions continuing through the Stakeholder Steering Committee. Target 3 is planned for 

completion in the first quarter 2015.

In November, EIPC presented preliminary findings on its Target 4 analysis comparing the 

relative economics of incremental firm pipeline transportation to dual-fuel capability for a 

new combined cycle plant or simple cycle gas turbine unit. Key research goals for the Target 

4 study include analysis of on-site fuel storage capability for simple cycle and combined cycle 

generators; dual-fuel operating characteristics and costs; oil market availability and resupply 

options; fuel switching design and practice; and economic tradeoffs between dual-fuel 

capable generation and firm pipeline transportation capacity. The final Target 4 draft report 

was posted in December. Preliminary results indicate that, with few exceptions, the 

incremental cost of dual-fuel capability for individual generators appears to be much less 

than the incremental cost of firm transportation on natural gas pipelines as a direct cost 

strategy to achieve fuel assurance, as defined by the study, for electric reliability within the 
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Eastern Interconnection. The primary reasons supporting these preliminary study results 

include, among others: 1) existing pipelines in constrained locations are typically fully 

subscribed, thereby requiring a pipeline to add expensive new facilities to serve a gas-fired 

generation plant; 2) generators behind LDC gate stations would be expected to bear the high 

cost of local facility improvements to ensure year-round service in addition to mainline 

improvements from the producing basin to the local system; 3) the avoided cost of non-firm 

transportation is not sufficiently high in most constrained locations to significantly reduce the 

net cost of incremental firm transportation service; 4) the capital charges, inventory carrying 

charges and incremental fixed O&M associated with dual-fuel capability are comparatively 

low; 5) structural change in the distillate oil market has and will continue to simplify the 

logistics of ultra-low sulfur diesel replenishment during cold snaps or other outages or 

contingencies. The final draft report notes that locations in MISO, TVA, and some in PJM 

show relatively low cost for firm pipeline transportation, since recent expansion capacity has 

been constructed at the system rate, or, in some instances, where existing capacity may not 

be fully subscribed due to decontracting. The final draft report concludes that despite the 

ostensible economic superiority of the dual-fuel capable solution to the challenge of 

maintaining fuel assurance, as defined by the study, for electric reliability, there may be 

other commercial reasons that otherwise induce generators to invest in firm pipeline 

transportation. For example, different operating characteristics, margin recoupment from 

the redeployment of firm capacity rights, and the ability to source gas at a lower price and 

more stable trading point under firm pipeline service.

The Eastern Interconnection States Planning Council (EISPC) convened a full committee 

meeting on October 2 and 3, 2014. The objective of the meeting was to examine the impacts 

of compliance with the Environmental Protection Agency’s proposed Clean Power Plan. 

Panelists provided an overview of the proposal and discussed potential impacts from expected 

coal plant retirements. Panelists anticipated that although coordination issues between the 

natural gas and electric industries will be exacerbated as coal plants retire and natural gas 

demand grows, ultimately, increased reliance on natural gas by the electric industry will 

incent improved scheduling practices between the two industries and the construction of 

additional infrastructure. Considering developments into the future, panelists forecasted 

that growth in the electric power industry will increase on par with national economic growth 

between now and 2030. Consequently, they cautioned that as natural gas becomes a larger 

part of the electric generation fuel mix, cold weather impacts will continue to be the 

principal driver of short-term gas price volatility. Discussions at the full committee meeting 

highlighted potential policies to address this concern, including policies to facilitate 

generator owners to recover the cost of firm gas pipeline transportation capacity through the 

electric markets, as well as costs associated with non-ratable takes. The EISPC convened a 

full committee meeting in New Orleans on December 11 and 12, 2014. The meeting sessions 

examined bulk and distribution electric system reliability, transmission security, capacity 

investment, and grid flexibility achieved from fuel diversity, demand response capabilities 

and storage. EISPC staff discussed the council’s mission and work plan in 2015 and beyond. 

The final draft of the ICF-led long-term study of electric and natural gas infrastructure in the 

Eastern Interconnection, prepared for NARUC and the EISPC, was released in December. The 

study examines the potential build-out of natural gas infrastructure required to supply power 

and natural gas customers out to 2030. The final report provides investment expenditure 

analysis for all aspects of the natural gas sector, from production wells to mainline 

transportation pipelines, to laterals for delivery to power plants, processing, and storage 

facilities. The final report concludes that investment in mainline natural gas pipeline is the 
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largest component of infrastructure expenditures, followed by lateral pipelines, processing, 

and storage development. The majority of the infrastructure build-out is driven by rapidly 

expanding production plays in the Northeast (Marcellus and Utica Shales) and the Southwest 

(Eagle Ford and Haynesville Shales), with the largest concentration of infrastructure 

investment needed in Pennsylvania and Louisiana. The study finds that total infrastructure 

costs for the power and natural gas sectors together could be approximately 1.5% lower when 

the two sectors co-optimize on siting and fuel infrastructure expansion, relative to noncollaborative infrastructure development. However, ICF notes that although both sectors 

benefit from cost reductions when they co-optimize planning, capital costs for the power 

sector are slightly higher relative to non-collaborative planning. Going forward, ICF 

recommends the use the EISPC-developed EZ Mapping Tool, to locate optimal siting locations 

in relation to environmental regulations, siting and permitting policies, and safety and 

operational guidelines that pertain to natural gas development.
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Slide 4

Regional Initiatives 

Northeast

 Massachusetts PUC – Massachusetts 

Department of Energy Resources “Low 

Demand Analysis”

 Maine PUC – Energy Cost Reduction Act

 ISO-NE – ICF Phase II Study

Turning to state and regional initiatives, we begin in the Northeast. The New England States 

Committee on Electricity (NESCOE) Incremental Gas for Electric Reliability (IGER) proposal is 

on hold awaiting the completion of study commissioned by the Massachusetts Department of 

Energy Resources (DOER), which is expected to be publicly released on December 23, 2014. 

Specifically, DOER has retained Synapse Energy to conduct a modeling analysis of various gas 

demand scenarios and to evaluate a range of solutions to meet Massachusetts’ short and longterm resource needs, while considering greenhouse gas reductions, economic costs and 

benefits, and system reliability. Since the initial stakeholder meeting to discuss the study in 

October, Synapse has developed base case and sensitivity assumptions and has conducted a 

feasibility study of alternative resources in a low energy demand case. The remaining study 

items include scenario modeling of eight scenario and sensitivity combinations, as well as an 

assessment of natural gas capacity against demand in a winter peak event.

The Maine Public Utility Commission (Maine PUC) has also continued efforts to advance 

natural gas infrastructure expansion in New England. In a November hearing, the Maine PUC 

voted to move forward with a second phase of work under the state’s 2013 Energy Cost 

Reduction Act. The 2013 Act stated that Maine and other New England states could benefit 

from lower electricity prices through expansions of natural gas pipeline capacity into Maine 

and the New England states, which would result in lower natural gas prices. The Act 

authorizes the Maine PUC to execute a contract for up to 200 MMcfd of natural gas capacity, 

or for an amount of capacity that will not exceed $75 million in annual costs. 

As part of this second phase of work, Maine PUC will conduct a cost-benefit analysis of 

pipeline project proposals submitted to address Maine’s needs for additional capacity. The 
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analysis will determine whether sufficient benefits would result to Maine consumers of 

natural gas and electricity. For example, Spectra Energy presented its Access Northeast and 

Atlantic Bridge projects planned to expand capacity along its Algonquin Gas Transmission and 

Maritimes & Northeast Pipeline. Spectra plans to develop the Access Northeast project with 

secured capacity commitments from Northeast Utilities and in collaboration with Iroquois Gas 

Transmission Systems. Kinder Morgan presented its Tennessee Gas Pipeline Northeast Energy 

Direct Project which the company is developing with the support of six local distribution 

companies. Portland Natural Gas Transmission System’s project was a third proposal 

submitted to the Maine PUC. Any interested party may submit testimony until the end of the 

year in response to the proposals for the Maine PUC to consider. The Maine PUC will review 

the proposals and testimony in 2015. While Spectra Energy and Kinder Morgan already have 

firm capacity commitments from LDCs for their projects, additional commitments would be 

necessary, either from shippers or the state, to expand the projects’ planned capacity to 

supply Maine. 

On November 20, 2014, ICF released the Phase II Report on the assessment of New England’s 

natural gas pipeline capacity and its capability to satisfy short and near-term (through 2020) 

generation needs. Similar to the 2011/2012 Phase I study, Phase II analyzed the potential for 

shortfalls in natural gas supply to electric generators through 2020 given currently available 

pipeline capacity and expansion projects likely to come online before 2020. For the Phase II 

study, ICF performed a new review of pipeline contracts, updated the timing and size of 

pipeline expansions in New England, as well as revised LNG availability. On the electric side, 

Phase II provides revised assumptions on power generation retirements and energy efficiency 

under four generation forecasts. Revised Phase II projections for natural gas supplies 

available to electric generation throughout the winter 2014/15 average nearly 500 MMcfd 

lower than projected in Phase I, assuming 2013/14 winter temperatures. In the Phase II 

report, ICF explores gas supply “deficiency” in terms of availability of pipeline transportation 

capacity outside of what is contracted and used by firm shippers. It finds that when firm 

shippers are at or near their full contract limits, there is insufficient interruptible pipeline 

capacity remaining to meet the overall needs of the electric generators in the region. In 

addition, ICF finds significant gas supply deficits remain on peak winter demand days from 

2014 through 2020 with a gas supply “deficiency” ranging from 40 MMcfd to 1 Bcfd.
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Slide 5

Regional Initiatives 

Mid-Atlantic

 NYISO

 PJM

In addition to sponsoring meetings for discussion of the EIPC study, the New York Independent 

System Operator (NYISO) has developed and is now utilizing its Winter Preparedness plan for 

Winter 2014/2015. As part of the plan, NYISO issued fuel surveys to generators to review the 

status of their starting oil inventories, oil replacement arrangements, and gas transportation 

arrangements. NYISO also created a new Control Room gas-electric support position to 

monitor the status of gas pipeline systems, alternative fuel inventory, and potential emissions 

limitations. Additionally, NYISO developed a communications protocol to improve the speed 

and efficiency of submitting generator requests for emissions limit waivers to the New York 

State Department of Environmental Conservation (NYSDEC), if needed for reliability. NYISO 

also established a new system that allows generators to update the fuel costs used in the dayahead reference level calculation, to more accurately reflect market conditions, such as the 

fuel constraints experienced last winter. In addition, NYISO made improvements to formalize 

the daily fuel inventory solicitation process and monitor short-term fuel availability on cold 

days. NYISO also clarified to the stakeholders that natural gas pipeline balancing charges are 

to be included in reference costs only during periods when nominations are unavailable with 

authorized gas balancing charges allowed only in real-time market reference cost levels. No 

gas balancing charges will be allowed in the day-ahead market reference cost levels. 

Furthermore, NYISO will not permit the inclusion in generator reference cost levels of charges 

associated with violations of OFOs or instructions restricting the use of gas imbalance service. 

If an OFO prevents a scheduled generator from securing gas to meet its schedule, and there is 

no available alternative fuel, the NYISO would expect the generator to take a forced outage.

PJM continues to work with its stakeholders to address a variety of gas-electric coordination 

issues. For example, since early September, the PJM Operating Committee has provided 
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education and training sessions to stakeholders on existing business rules for intraday costbased scheduling submissions, procedures for switching between cost and price-based 

schedules, and PJM rules for cost reimbursement. During these sessions stakeholders and PJM 

staff discussed proposed additions to the existing information collected by PJM from 

generation owners, with the goal of providing both dispatch operators and generating units 

with more accurate information beyond day-ahead market postings, as well as allowing 

generation owners more opportunities to submit cost schedules that better reflect the costs 

of cold-weather operations and fuel market volatility. This resulted in proposed new data 

fields for generators to submit to PJM, including dual-fuel capability, availability, and fuelswitching transition times, as well as generators’ operational restrictions. In addition 

stakeholders and PJM staff developed proposed adjustments to existing data parameters that 

would enable generator owners to enter forward data for up to seven days, including as many 

as 79 hourly intraday cost schedules that can be updated until 6:00pm of the day prior to the 

potential run-time. On November 20, 2014, the PJM Markets and Reliability Committee voted 

to endorse all of the proposed changes, which are now incorporated in PJM’s Manual for 

Energy & Ancillary Services Market Operations. These new data collection and cost-schedule 

updating processes will take effect January 1, 2015, with the new software supporting these 

changes scheduled for release in early February 2015. In the interim, PJM has released 

manual directions for members to submit new data and cost-schedule updates.

In addition, PJM has taken a number of key steps to increase winter readiness. In response to 

last year’s Polar Vortex events, PJM has approved Cold Weather Resource Performance 

improvements to increase resource performance during extreme cold weather events via 

performance verification and testing of certain resources during cold weather, including 

testing dual-fuel capability. PJM is also working on improving the tools and processes for twoway communication with the gas industry. PJM has also developed an internal dashboard of 

electrical interconnection areas impacted by pipeline issues such as capacity constraints or 

operational issues. This tool provides critical pipeline notifications in one location to enhance 

PJM’s situational awareness and allow PJM to better evaluate the impact of pipeline issues on 

generators. The dashboard was tested internally at the end of November and is now available 

to PJM’s system operators. Additionally, PJM has instituted weekly system status calls with a 

number of the prominent pipelines in the PJM footprint. 

PJM is also working closely on improving interregional coordination with MISO and NYISO to 

improve situational awareness during emergencies, and held a number of operations 

coordination meetings in October and November. PJM holds daily operations conference calls 

with neighboring ISOs to discuss pressing issues and system status, as well as to share 

information on gas infrastructure conditions that may be regional in nature. 
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Slide 6

Regional Initiatives 

Central

 MISO

 SPP

Moving to the central region, MISO has taken several steps to learn from last winter’s gaselectric coordination challenges and better prepare for winter 2014/2015, including hosting a 

Winter Readiness Workshop with stakeholders. As part of its 2014/15 Winter Resource 

Assessment released in November, MISO found sufficient resources are available to meet 

electricity demand this winter, highlighted by over 46 GW of capacity from all resource types 

in excess of projected peak load, a 45% projected reserve margin. MISO learned that 35 GW 

out of 69 GW of its gas-fired generation lacks firm natural gas transportation service or dualfuel capability. Finally, MISO is directing generation owners to prepare for winter based on 

recommendations from NERC. 

In addition, this winter MISO will expand regular communications with pipelines on real-time 

operating conditions, based on publicly available information, to all pipelines (over 70) 

serving gas-fired generation in MISO’s footprint. Last winter, MISO conducted a field trial of 

such regular communications with two natural gas pipelines (ANR Pipeline and Northern 

Natural Gas Pipeline). MISO has also implemented a real-time mapping tool to show MISO 

system operators all intra- and interstate pipelines in its footprint and the gas-fired units 

connected to them. The tool consolidates available pipeline information, which will help 

MISO better anticipate forced outages. In addition, MISO launched a tool on its website to 

provide information on gas pipelines, including current pipeline conditions and maintenance 

notices, to its members. 

In SPP, the Gas Electric Coordination Task Force (Task Force) is finalizing a proposal to 

amend the SPP day-ahead market timeline to align with the proposed revised NAESB Timely 

Nomination Cycle deadline of 1:00 pm Central for scheduling interstate natural gas pipeline 
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transportation. The proposed changes to the day-ahead market timeline are aimed at 

maintaining reliability during fuel constraints and ensuring that the day-ahead market 

timeline compliments gas markets and dispatch scheduling requirements.

 

SPP completed its 2014/15 winter preparedness plan, and presented the plan to the SPP 

Balancing Authority Operating Committee on December 4, 2014. The 2014/15 winter 

preparedness plan describes emergency operating procedures for coordination and 

communication during critical cold weather events, as well as general best-practices for 

operations during the winter season. In the new 2014/15 winter preparedness plan, if SPP 

declares a severe cold-weather event, it may take steps to optimize fuel supply by, for 

example, 1) appealing to stakeholders to use alternative fuels; 2) conserving fuel in short 

supply by de-committing resources; and 3) coordinating outages. Additionally, in the plan, 

SPP identifies various recommendations for improving cold-weather operations, such as 

winterization, and generation operators notifying SPP of any expected fuel issues during a 

cold-weather event. During more severe conservative operations SPP will institute daily 

outreach and coordination calls to share reliability information with impacted generation 

owners. These multi-party communications protocols of non-public information sharing 

between dispatch operators, generators, and three natural gas pipelines supplying the 

majority of fuel to the RTO were first utilized by SPP to ensure reliability during 2013/14 

cold-weather events and have since been developed and expanded within the framework of 

emergency operations for the 2014/15 winter preparedness plan. 

Finally, on November 25, 2014, stakeholders agreed to petition the SPP Markets and 

Operations Policy Committee to both extend the Task Force’s charter into 2015 and consider 

reclassifying the Gas Electric Coordination Task Force as a Steering Committee.
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Slide 7

Regional Initiatives

West

 WIEB – SPSC

 ColumbiaGrid

 CAISO

Moving to the West, Phase 2 of the Western Interstate Energy Board’s (WIEB) Natural Gas–

Electric and System Flexibility Assessment was finalized last quarter and the Assessment is 

now complete. The State Provincial Steering Committee (SPSC) directed WIEB Staff to further 

develop scopes of work for a potential Phase 3 of the Gas-Electric Interdependency Study, 

focusing on the use of wind and solar forecasts in gas nominations and in communication with 

pipelines. A potential study on distribution system issues has also been proposed. 

ColumbiaGrid is in the process of completing its coal retirement study, which is examining the 

transmission impacts of replacing coal units with natural gas. The final study report is 

scheduled for December 2014. 

On September 16, 2014 CAISO released an issue paper and initiated a new Natural Gas 

Pipeline Penalty Recovery stakeholder process to discuss circumstances under which market 

participants may be able to recover natural gas pipeline penalties through the CAISO bid cost 

recovery mechanism. The proposal was initially discussed in 2012 within the stakeholder 

process, but CAISO did not file a proposal with the Commission at that time. Instead, CAISO 

undertook an outreach effort with intra-state and interstate pipelines to understand and 

address any potential reliability issues such a cost recovery mechanism might cause pipeline 

operators. After conducting outreach, the ISO believes it is not prudent to act now to allow 

recover of natural gas pipeline penalty costs given increased gas and electric coordination 

efforts, as well as Southern California Gas’ filing to implement in the future operational flow 

orders similar to those in place at Pacific Gas and Electric. In 2015, CAISO will monitor 

changes in the gas industry before reconsidering how, or whether, natural gas penalties 
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should be recovered in CAISO markets. CAISO states that it will continue to work with 

stakeholders to explore ways to better reflect natural gas costs.

In addition, CAISO and stakeholders will consider longer-term market design changes for both 

energy and unit commitment cost bids in a more comprehensive bidding rules initiative that 

began in December 2014. That stakeholder initiative will include discussion regarding greater 

bidding flexibility to potentially allow bids to reflect intra-day changes in fuel costs. 
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Slide 8

Relevant 

Natural Gas Filings

Region Pipeline/Association Capacity/

Initiative

Docket No. Status

Southeast Florida Southeast Connection Capacity addition

640 MMcfd

CP15-554-000 Pending 

09/26/2014

Northeast Eastern Shore Natural Gas 

Company (White Oak Lateral 

Project)

Capacity addition

55.2 MMcfd

CP13-498-000 In-service 

09/30/2014

Southeast Southeast Supply Header 

Expansion Project

Capacity addition

45 MMcfd

CP14-87-000 In-Service (In 

Part) 10/1/2014

Southwest Sierrita Gas Pipeline Capacity addition 

200 MMcfd

CP13-73 & 74 In-service 

10/27/2014 

Southeast Florida Gas Transmission Capacity addition 

25 MMcfd

CP14-21-000 Approved 

10/30/2014

Southeast NET Mexico Pipeline Partners 

(Border Crossing Project)

Capacity addition

2.1 Bcfd

CP13-482-000 In-service 

10/30/2014 

Mid-Atlantic Dominion Cove Point LNG 

(St. Charles Transportation 

Project) 

Capacity addition

132 MMcfd

CP15-22-000 Pending

12/3/2014

Mid-Atlantic Dominion Cove Point LNG

(Keys Energy Project)

Capacity addition

107 MMcfd

CP15-24-000 Pending

12/3/2014

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

before the Commission, starting with natural gas pipeline filings. As discussed in more detail 

below, during this quarter the Commission received three new filings to expand pipeline 

capacity serving electric generation, approved one proposed project, approved the start of 

operations of four projects, and acted on numerous compliance filings concerning interstate 

natural gas pipeline compliance with the requirement to post offers to purchase released 

capacity. 

The first new filing proposing to expand pipeline capacity to serve electricity generation was 

made by Florida Southeast Connection (FSC), which requested authorization on September 26, 

2014 to construct facilities spanning from an interconnection with the proposed Sabal Trail 

Transmission (Sabal Trail) pipeline near Intercession City, Florida to a delivery point serving 

the Florida Power & Light Company’s (FPL) 75-MW solar-thermal Martin Clean Energy Center, 

near Indiantown, Florida. FSC will have an initial transportation capacity of 640 MMcfd. 

Turning to Commission approvals, Eastern Shore Natural Gas Company received approval on 

September 30, 2014 to go in-service for its White Oak Lateral Project (first filed on June 13, 

2013). The proposed project will provide 55 MMcfd of firm transportation service for Calpine 

Energy Services, L.P. supporting gas-fired generation in Kent County, Delaware.

On October 1, 2014, Southeast Supply Header pipeline (SESH) received approval to place inservice the 45-MMcfd increase in its design capacity of its mainline system. The added 

capacity will provide firm pipeline transportation capacity from the beginning of SESH’s 

system near Delhi, Louisiana to the end of its system near Coden, Alabama. 
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On October 27, 2014, Sierrita Gas Pipeline received approval to place into service its 200-

MMcfd facilities located in Pima County, Arizona, while on October 30, 2014, NET Mexico 

Pipeline Partners received approval to place into service its 2.1-Bcfd NET Mexico Pipeline 

Project located in Starr County, Texas. 

On October 30, 2014, FGT was granted a certificate of public convenience and necessity to 

increase the maximum delivery quantity by 25 MMcfd to FPL through increased compression 

Broward County, Florida.

On October 30, 2014, NET Mexico Pipeline Partners, LLC (NET Mexico) received approval to 

place into service the NET Mexico Pipeline Project located in Starr County, Texas. The 

facility will have a design capacity of 2.1 Bcfd and will provide supply to the expanding 

natural gas demand from gas-fired power generation in Mexico.

On December 3, 2014, Dominion Cove Point LNG, LP (DCP) filed an application to construct, 

install, own, operate, and maintain the St. Charles Transportation Project located in Fairfax 

County, Virginia and Charles County, Maryland. DCP states that the project will provide 132 

MMcfd of incremental firm transportation service to CPV Maryland, LLC who is proposing to 

build a 725-MW natural gas-fired combined cycle power plant in Charles County, Maryland 

known as the “St. Charles Energy Center”. DCP also filed to provide an incremental 107 

MMcfd of firm transportation to the Keys Energy Project, a proposed 735-MW natural gas-fired 

combined cycle electric generating power plant in Prince George’s County, Maryland known 

as the “Keys Energy Center”.
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Slide 9

Relevant 

Natural Gas Filings cont’d

Region Pipeline/Association Capacity/

Initiative

Docket 

No.

Status

National 157 interstate natural gas 

pipelines 

Order on Filings in 

Compliance with Order 

to Show Cause, Posting 

of Offers to Purchase 

Capacity

RP13-673-

001, et al

Pending

West Cheyenne Plains Gas Pipeline 

Company

Interruptible parking 

and lending service

RP15-134-

000

Approved

10/31/2014

National Kinder Morgan pipelines Petition for Limited 

Waiver of No-Conduit 

Rule adopted in Order 

No. 787

RP15-217-

000

Pending

Addressing compliance, on October 16, 2014, the Commission issued an order on filings in 

compliance with the previously reported Natural Gas Act section 5 show cause proceeding 

requiring all interstate natural gas pipelines to either revise their respective tariffs to provide 

for the posting of offers to purchase released capacity as required by section 284.8(d) of the 

Commission’s regulations, or to demonstrate that their existing tariffs are in full compliance 

with that section (October 16 Order). The October 16 Order found that out of 157 compliance 

filings submitted, 64 pipelines revised their respective tariffs in a manner that complies with 

the Commission’s requirement, 23 pipelines demonstrated that their tariffs are in 

compliance, 1 pipeline requested clarification regarding a previously granted limited waiver, 

and 69 pipelines do not appear to be in full compliance.

Specifically, the October 16 Order found that potential replacement shippers should be 

permitted to have their offers to acquire released capacity posted for whatever period of 

time they desire, subject to a cap of no less than 30 days if the pipeline wishes to impose 

such a cap. Further, the October 16 Order rejected proposals to assess a separate fee 

applicable only to posting offers to purchase released capacity. The October 16 Order also 

clarified a limited waiver for posting website notice of offers to release or purchase capacity, 

and granted extensions of time to complete and implement website changes. All 69 

interstate natural gas pipelines not in compliance have submitted filings to the Commission in 

response to the October 16 Order. This matter is pending before the Commission.

On October 31, 2014, Cheyenne Plains Gas Pipeline Company, L.L.C. filed revised tariff 

records to establish an interruptible parking and lending service under a new Rate Schedule 

PAL. The proposed PAL service will provide shippers a flexible service option to aid in the 
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management of their imbalances and provide them with an additional tool to mitigate 

penalties by affording the shippers the ability to leave gas on Cheyenne’s system (i.e., park) 

or to take gas off the system at certain points (i.e., lend). On November 13, 2014, the 

proposal was accepted for filing by delegated order, effective December 1, 2014

On November 25, 2014, the Kinder Morgan interstate pipelines (KM) requested a limited 

waiver of the No-Conduit Rule with respect to the disclosure of information received under 

the rule to shared operational employees. Specifically, KM requests a limited waiver of the 

No-Conduit Rule adopted in Order No. 787 for operational personnel shared between KM and 

their affiliated Hinshaw, intrastate, and gathering systems. This matter is pending before the 

Commission.
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Slide 10

Relevant

Electric Filings

Region Filing Initiative Docket No.

NYISO Pipeline Information-Sharing Changes under Order No. 787 ER14-2895-000

CAISO Commitment Cost Enhancements ER15-15-000

PJM Capacity Performance Proposal ER15-623-000

PJM Additional Remedies to Capacity Performance ER15-29-000

PJM Request for Temporary Increase of the System Offer Cap 

Rule

ER15-31-000

Since our last report, five electric tariff filings relevant to gas-electric coordination have 

been presented to the Commission. 

On September 17, 2014, the NYISO submitted, in Docket No. ER14-2895-000, proposed tariff 

revisions to allow NYISO to share confidential information concerning natural gas-fired 

generation with the operating personnel of interstate natural gas pipeline companies, 

intrastate natural gas pipeline companies, and LDCs, to conform with the Commission’s 

regulations adopted in Order No. 787. On November 14, 2014, the Commission accepted the 

proposed tariff revisions, effective November 17, 2014, subject to conditions and NYISO 

submitting a compliance filing within 15 days of the date of the order (November 14 Order). 

The Commission found that NYISO’s proposed revisions to allow the sharing of non-public, 

operational information with interstate natural gas pipeline operators for the purpose of 

promoting reliable service and operational planning are consistent with Order No. 787, and 

that its proposal to extend the information sharing provisions to LDCs and intrastate natural 

gas pipeline operators should ensure cooperation and coordination, thus contributing to the 

reliable operation of the transmission system. However, the Commission required NYISO to 

submit a compliance filing to clarify the proposed tariff language prohibiting an LDC or 

intrastate natural gas pipeline from disclosing, or using anyone as a conduit for disclosure of, 

non-public operational information received from NYISO to a third party or any affiliate 

except for the operating personnel of an affiliated interstate pipeline or intrastate pipeline 

which has a non-disclosure agreement with NYISO.

On December 1, 2014, NYISO submitted a filing to the Commission in response to the 

November 14 Order. Specifically, NYISO revised its tariff language to (1) clarify that the 
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operating personnel of interstate pipelines receiving non-public operational information 

originating from the NYISO, from an affiliated LDC or intrastate pipeline, must comply with 

section 284.12(b)(4)(ii) of the Commission’s regulations; and (2) specify which employees of 

an LDC or intrastate pipeline are prohibited from receiving non-public operational information 

from the NYISO. This matter is pending before the Commission.

On October 1, 2014, CAISO filed proposed tariff revisions to allow generators to recover startup and minimum load costs. CAISO proposes tariff revisions that: (1) increase the existing 

proxy cost bid cap from 100 percent of the resource’s calculated proxy cost to 125 percent; 

(2) require CAISO to exclusively use the Intercontinental Exchange (ICE) natural gas price 

index for calculating the natural gas price component if, on the morning of the day-ahead 

market run, the price reported by ICE exceeds 125 percent of the natural gas price index 

calculated under CAISO’s tariff; (3) eliminate the registered cost option for all resources 

except use-limited resources; and (4) allow CAISO to switch use-limited resources temporarily 

from the registered cost option to the proxy cost option whenever the alternative ICE natural 

gas price is triggered. On November 6, 2014, the Commission issued a deficiency letter 

requiring CAISO to submit additional information regarding the unit-specific costs that would 

be included in the calculation of proxy costs. On November 25, 2014, CAISO submitted the 

additional information requested in the November 6, 2014 deficiency letter. This proceeding 

is pending before the Commission.

On December 12, 2014, PJM submitted, in Docket No. ER15-623-000, proposed tariff revisions, 

under section 205 of the Federal Power Act (FPA), to better ensure that committed capacity 

resources will perform when called upon to meet the reliability needs of the PJM Region 

(Capacity Performance Filing). The Capacity Performance Filing makes changes to the design 

of PJM’s capacity market, known as the Reliability Pricing Model (RPM), to ensure it provides 

adequate incentives for resource performance. Specifically, PJM proposes, among other 

reforms, to: (1) include a new capacity product – the Capacity Performance Resource – that 

provides greater assurance of delivery of energy and reserves during emergency conditions; 

(2) redefine its existing capacity product to enhance assurance of delivery of energy and 

reserves during hot weather operations; (3) eliminate the current excuses for Capacity 

Resource non-performance, leaving only certain narrowly drawn exceptions for actions 

specifically approved or directed by PJM; (4) assess charges for poor performance and give 

credits for superior performance, to provide a strong incentive for performance; (5) change 

PJM’s current capacity sell offer rule to recognize the costs and risks of offering Capacity 

Performance Resources by increasing the offer-price cap for such resources to the Net Cost of 

New Entry, while also allowing offers in excess of the Net Cost of New Entry if the seller can 

demonstrate that the costs of improving resource performance, including firm fuel costs and 

documented and verifiable expenses solely attributable to the risks of offering Capacity 

Performance Resources, exceed that value; (6) include a distinct “must offer” requirement 

specifically for resources capable of qualifying as Capacity Performance Resources, to prevent 

physical withholding of such resources; (7) revise Load Serving Entity capacity obligations to 

reflect the reliability value added by resource performance during winter-season 

emergencies; (8) preserve existing capacity products through May 31, 2020, subject to a 

reliability-based cap on the quantity of such products that may clear the capacity auctions, to 

allow market participants time to adapt their resources as necessary to ensure satisfaction of 

the region’s expectation that all committed capacity will deliver energy and reserves during 

emergencies; (9) provide an allowance for differential price clearing during that transition, to 

recognize the higher value of Capacity Performance Resources; (10) eliminate the current 

market rule that intentionally understates the region’s reliability needs in the RPM Base 
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Residual Auction, to eliminate a possible source of under-pricing of any resources in that 

auction; and (11) make conforming changes to various capacity rules. PJM proposes to 

implement these changes for the next Base Residual Auction, which is scheduled for May, 

2015, and which will procure capacity for the 2018/2019 Delivery Year.

Concurrent with its Capacity Performance Filing, PJM submitted, in Docket No. EL15-29-000, 

proposed revisions to its Operating Agreement, and related revisions to its tariff,, to correct 

present deficiencies on matters of resources performance, and excuses for resource 

performance in the PJM markets. Specifically, PJM identified four areas of its current energy 

market rules that enable, or could enable unreasonable excuses for market participant 

performance in PJM’s markets. Therefore, PJM proposes to: (1) revise the procedure for 

determining parameter limits for resources, including clarifying that such limits must be 

based solely on the operating design characteristics of each specific resource (rather than on 

economic or budgetary concerns), and then clarify that units operating outside of those 

parameter limitations for reasons other than at PJM direction are ineligible to be made whole 

through Operating Reserve credits for such operation during specified types of emergencies or 

alerts; (2) reform PJM’s current force majeure rules to recognize that participants in PJM’s 

wholesale power markets should be excused from performance only when catastrophic 

conditions broadly preclude performance by market participants in the PJM Region; (3) 

reduce opportunities to effectively avoid capacity resource performance by submitting 

uneconomic (i.e., Maximum Emergency) offers in the Day-ahead Energy Market; and (4) 

include in the market rules more transparent and rigorous criteria for PJM’s consideration and 

approval of requested planned and maintenance outages, including clarifying PJM’s authority 

to timely rescind a prior approval.

PJM states that while these two concurrent filings provide complementary solutions to the 

same underlying problem and while both seek the same, April 1, 2015 effective date, the FPA 

section 205 filing is not dependent upon Commission acceptance of the FPA section 206 filing. 

These proceedings are pending before the Commission.

On December 15, 2014, PJM submitted, in Docket No. EL15-31-000, proposed revisions to its 

Operating Agreement and tariff, under section 206 of the FPA, to raise the cost-based energy 

offer cap from $1,000 to $1,800/MWh. The $1,800/MWh offer cap would apply temporarily, 

through March 31, 2015, and is intended to address the situation which occurred last year, in 

which a spike in natural gas prices pushed some generators’ costs above $1,000/MWh, 

resulting in PJM requesting temporary waiver of the system offer cap rule in Docket No. ER14-

1145-000. The proposal would also allow for generator compensation for costs incurred above 

$1,800/MWh in the form of after-the-fact make-whole payments. PJM states that the 

market-based offers will remain capped at $1,000/MWh, except that if a Market Seller 

submits a cost-based offer greater than $1,000/MWh (but below $1,800/MWh) the Market 

Seller will be permitted to raise its market-based offer up to a level equal to such cost-based 

offer. PJM requests a shortened 8-day comment period and expedited action by January 9, 

2015, with an effective date of January 9, 2015. This proceeding is pending before the 

Commission.