Gas-Electric Coordination

Quarterly Report to the Commission

Docket No. AD12-12-000

June 19, 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

June 19, 2014

Gas-Electric Coordination 

Quarterly Update

Docket No. AD12-12

This report is Commission staff’s sixth 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 March 2014 through June 2014. 

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

in March 2014, highlights the Commissioner-led Technical Conference on Winter 2013-2014 

Operations and Market Performance in RTOs and ISOs on April 1, 2014, and briefly summarizes 

recent industry applications filed with the Commission. 
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Slide 2

National Initiatives

 NAESB Gas Electric Harmonization 

Forum

 Commission Technical Conference on 

Winter 2013-2014 Operations and 

Market Performance in RTOs and ISOs 

(Docket No. AD14-8)

• Comments: 35 entities

Following the March 20, 2014 issuance of the Commission’s Notice of Proposed Rulemaking 

(NOPR) in Docket No. RM14-2-000 regarding the Coordination of the Scheduling Processes of 

Interstate Natural Gas Pipelines and Public Utilities, NAESB reconvened the Gas Electric 

Harmonization (GEH) Forum as the platform for industry to consider the Commission’s NOPR 

proposals as well as to develop any consensus-based alternatives to the proposals in the 

NOPR. The Forum was tasked with developing a recommendation for the consideration of the 

full Board of Directors. The GEH Forum held two planning conference calls in late March and 

early April, and four two-day meetings throughout April, May, and June. All interested 

parties were invited to participate in the meetings in person or by phone and NAESB 

membership was not a requirement for participating in the GEH Forum. The meetings were 

highly attended, averaging three hundred industry participants.

At the conclusion of the scheduled meetings, the GEH Forum was unable to reach consensus 

on a package of alternatives to the proposals in the Commission’s NOPR. The gas and electric 

industries’ viewpoints on the Gas Day were split with a super-majority of the gas industry 

supporting the current Gas Day start time of 9:00 am Central and a super-majority of the 

electric industry supporting moving the Gas Day to 4:00 am Central. Therefore, the GEH 

Forum did not have a recommendation to the Board. 

However, on June 4, the NAESB Board of Directors met and passed a motion recognizing that 

there appeared to be broad support from interested parties in both the gas and electric 

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

Therefore, the Board directed the Wholesale Gas Quadrant (WGQ) to develop new standards 

and modify existing standards to support the scheduling timelines developed by the GEH 

Forum for the timely, evening, ID1, ID2, and ID3 nomination cycles. The nomination deadline 

for the timely and evening cycles are the same as those proposed in the NOPR—1:00 pm 

Central and 6:00 pm Central, respectively. The timelines for ID1, ID2 and ID3 vary from those 
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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 ID4 cycle as proposed in the 

NOPR. The standards will be neutral on the gas day start times and will essentially be “fill in 

the blank” standards pending a Final Order by the Commission in the RM14-2 docket. Any 

member of the Wholesale Electric Quadrant may participate in the WGQ subcommittee 

meetings, and any non-NAESB member may also participate in the subcommittee meetings for 

a minimal fee. 

NAESB anticipates filing consensus-based standards on the scheduling timeline, without a Gas 

Day start time, with the Commission by September 29, 2014 as directed in the NOPR. As 

announced in the NOPR, comments on NAESB’s consensus standards, as well as comments on 

the Commission’s proposals, are to be filed November 28, 2014, 240 days after publication of 

the Proposed Rule in the Federal Register.

In response to a number of mid-winter cold weather events, the Commission held a Technical 

Conference on April 1, 2014 on Winter 2013-2014 Operations and Market Performance in RTOs 

and ISOs (Docket No. AD14-8). The technical conference explored the impacts of the cold 

weather events on the RTOs/ISOs and discussed actions taken in response to inform the 

Commission of the challenges posed by these events. Post-technical conference comments 

were filed by thirty-five (35) commenters by the required May 15, 2014 due date. The 

Commission is currently analyzing these comments.
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Slide 3

Inter-regional Initiatives

 Eastern Interconnection Planning 

Collaborative (EIPC)

 Eastern Interconnection States’ Planning 

Council (EISPC) 

Interregional studies continue on the ISO and state levels.

Levitan & Associates continues work on the multi-regional Eastern Interconnection Planning 

Collaborative (EIPC) Study involving ISO-NE, NYISO, PJM, MISO, Ontario IESO and TVA. The 

Target 1 Report, which provided a baseline assessment of the existing gas-electric systems, 

was finalized and posted on April 1, 2014 on the Gas-Electric Documents page of the EIPC 

website. Analysis is underway for Target 2 which will evaluate the capability of the natural 

gas system to meet demand in the 5-10 year horizon. The study will use natural gas and 

electric system forecasting tools to explore three reference case scenarios and sensitivities. 

An initial draft report is expected to be posted on June 20. The report will contain the 

methodology, inputs, and analysis of the three scenarios and sensitivities. The initial Target 

2 findings and report is scheduled to be presented on June 25-26 with the final report due in 

October 2014. Target 3 was kicked-off in March with a final draft report expected by the end 

of 2014, while Target 4 methodology was posted on May 30 with work to continue through 

2015.

The Eastern Interconnection States’ Planning Council (EISPC) held a full Council Meeting on 

May 15-16, 2014. The ICF-led long-term Natural Gas/Electric Infrastructure Requirements 

Study mentioned in previous gas-electric quarterly reports is ongoing, with the final results 

for both natural gas and electric systems expected in summer 2014. In May 2014, the EISPC 

and NARUC awarded the contract to Energy Exemplar, tasked to advance resource planning by 

assessing the potential integration of co-optimization tools with other planning analysis. This 

is the first time that these entities will be working together, supported by a funding 

opportunity from the Department of Energy, to evaluate transmission development options 

throughout the Eastern Interconnection. The study will be used to inform states on what they 

can do to enhance planning tools and processes in furtherance of their respective statutory 

authorities. A component of this multi-task study focuses on co-optimization techniques to 
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address electric and natural gas operational and planning issues. EISPC wants to better 

understand the benefit/cost analysis to co-optimization including the public policy 

implications. The final report is expected by November 2014. 
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Slide 4

Regional Initiatives 

Northeast

 New England States Committee on 

Electricity (NESCOE) 

• New England Governors’ energy 

infrastructure initiative

In the Northeast, the New England States Committee on Electricity (NESCOE) circulated a 

proposal to develop and manage incremental gas pipeline capacity for electric generation, 

referred to as the Incremental Gas for Electric Reliability (IGER) concept 

(http://www.nescoe.com/uploads/GasforElectricReliabilityGraphic_April2014.pdf), in 

support of the New England Governors’ energy infrastructure initiative. The IGER concept 

contemplates that a contract entity would enter into long-term contracts with interstate 

natural gas pipeline companies to secure new firm gas transportation capacity. The contract 

entity would be responsible for monthly reservation charges and other payments related to 

the pipeline capacity, subject to the terms of the long-term contract. ISO-NE would collect 

the revenue for these payments under a FERC-approved revision to its tariff, and then 

transfer the revenue to the contract entity that would ultimately compensate the pipeline. 

The costs of the additional pipeline capacity would ultimately be allocated to New England 

retail electric customers. As previously reported, NESCOE is seeking a total of 1,000 MMcfd 

above 2013 levels or, 600 MMcfd beyond what has already been announced for existing 

expansion projects, to be available no later than the winter of 2017/18.

In addition, the IGER concept anticipates the contract entity executing an Asset Manager 

Agreement (AMA) with a capacity manager who would administer the capacity releases from 

the contract entity to gas-fired generators, or other replacement shippers, through the 

pipeline’s secondary market. Gas-fired generators or other shippers purchasing the released 

capacity through the pipeline’s secondary market would make payments for the capacity to 

the pipeline. The pipeline would credit the contract entity for the released capacity 

purchased in the secondary market. The contract entity would in turn recover, through ISONE, the net actual pipeline costs.

NESCOE requested feedback on the IGER concept by May 30, 2014 and subsequently posted 

eighteen stakeholder comments in response to the proposal on its website. NESCOE intends 
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to present a proposal to NEPOOL for discussion in late June 2014, with consideration by the 

NEPOOL Participants Committee in September. 
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Slide 5

Regional Initiatives 

Mid-Atlantic

 NYISO

 PJM

Northeastern ISOs and RTOs continue to work closely with representatives from Planning 

Authorities in the Eastern Interconnection to provide EIPC with sensitivities and scenarios to 

be studied in 2014 in its EIPC Gas-Electric System Interface Study. In addition to reviewing 

winter operations during the 2013-14 Winter cold spells, NYISO continued to provide in-depth 

inputs to scenario developments for both DOE grant and non-grant Eastern Interconnection 

studies along with the EISPC study. 

The PJM Gas Electric Senior Task Force continues its near-term agenda of discussing the 

potential advantages of changing its day-ahead bidding process in response to changes in the 

natural gas nomination schedule, specifically, day-ahead market timing adjustments and bid 

flexibility to facilitate greater generator availability. In addition, PJM members continue to 

explore whether market rules should be changed to better reflect the full cost of firm gas 

transportation and how to improve information sharing between natural gas pipelines and PJM 

system operators. PJM has also identified gas unit commitment coordination as an issue for 

the Operating Committee to address. PJM states that this issue emanates from the 

difficulties experienced in scheduling gas-fired generation during cold weather events and 

expects short term changes implemented prior to the winter of 2014/2015 and longer term 

changes that may require FERC action in early 2015. PJM continues to hold seminars on 

natural gas infrastructure and market fundamentals, as well as the operational uncertainty 

facing natural gas generators in the day-ahead market, to better educate its Gas Electric Task 

Force.
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Slide 6

Regional Initiatives 

Central

 MISO

 SPP

In the Midwest, MISO completed its Electric/Gas Coordination Field Trial with ANR and 

Northern Natural Gas pipelines from October 1, 2013 through March 31, 2014. Field trial 

results indicated that coordinated gas-electric operations improved situational awareness, 

especially around generation unavailability. MISO and the pipelines found benefit in the 

monthly review of planned maintenance and system conditions and found additional 

coordination and information exchange during abnormal/emergency events extremely 

beneficial. MISO plans to formalize the Electric/Gas Coordination Program and establish 

contacts and communication protocols with all pipelines providing natural gas to generators in 

its market footprint. 

MISO's Electric and Natural Gas Coordination Task Force developed outlines of four issue 

summary papers it will pursue this year: 1) 2014 Polar Vortex Experiences: Natural Gas 

Availability & Enhanced RTO/Pipeline Communication; 2) 2016 Retirement Projections 

Overlay onto January 2014 Polar Vortex Cold Weather Event – this will explore 2014 polar 

vortex weather conditions on MISO's expected 2016 fuel mix, which will be more reliant on 

natural gas, to understand potential future operating conditions; 3) Potential Competition 

between Gas Fired Generation and Storage Injection – an analysis of potential competition for 

natural gas between power generation and storage injection and implications for energy and 

natural gas prices; and 4) Process & Timeline for Development of Additional Pipeline 

Infrastructure – background of the process and timeline for the development of additional 

pipeline infrastructure and challenges for infrastructure expansion by 2016. 

The SPP Gas Electric Coordination Task Force is actively pursuing its near-term objective of 

reviewing tariff provisions and business practices for improvements in time for winter 2014-

15. The SPP Task Force is seeking ways to improve transparency in the three-way 

communications between the RTO, natural gas pipelines, and generators, and to refine 

processes for handling non-public information during shortage events. SPP members continue 
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to discuss the appropriate level of headroom to allow—the available capacity above minimum 

energy and operating reserve requirements—during sustained cold weather events, such as 

during winter 2013/14, in order to hedge against forecast uncertainty and ramp shortages. 

The Gas Electric Task Force plans to vote on these issues in the June 26, 2014 MWG meeting. 
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Slide 7

Regional Initiatives

West

 PNUCC

 WIEB – SPSC

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

In the Pacific Northwest, the Pacific Northwest Utilities Conference Committee Power and 

Natural Gas Planning Task Force continues to provide a platform for natural gas pipelines and 

electric utilities to discuss enhanced communications and coordination issues. In the second 

quarter, two short-term studies were released, the PNUCC Northwest Regional Forecast and 

the Northwest Gas Association (NWGA) Natural Gas Outlook Study. The studies highlight a 

trend of decreasing consumption of both power and natural gas on an end user basis and the 

changing nature of power generation due to the increase in intermittent renewable 

generation on the system. 

The Western Interstate Energy Board’s Natural Gas–Electric and System Flexibility Assessment 

is underway. Phase 1 of the Western Gas-Electric Study was released on March 13. Phase 1 

provides insight into the adequacy of available gas supply infrastructure to meet the needs of 

power producers in the Western Interconnection ten years in the future. Phase 1 reached the 

following key conclusions:

1. The natural gas and electric industries are deeply linked such that events and 

conditions in one may have significant impacts on the other.

2. Under the Base Case, existing gas transportation infrastructure will generally be 

adequate to meet the regional needs of the electric sector except under extreme 

winter weather conditions. 

3. Gas generation that does not contract for firm transportation service may be subject 

to interruption during times of high gas demand. 

4. The regions of the Western Interconnection are highly interdependent in their reliance 

on natural gas transportation and generation infrastructure. 
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5. Interregional coordination will play a key role in responding to gas generation 

curtailments during extreme weather.

6. Events that affect multiple regions simultaneously may pose a threat to regional 

reliability.

7. Continued growth of the West’s natural gas generation fleet will require expansion of 

natural gas infrastructure to provide fuel security.

8. The impacts of new large natural gas loads on the adequacy of gas transportation 

infrastructure will depend on the extent to which those loads rely upon incremental 

expansions or existing pipelines.

9. Increased coordination between the gas and electric sectors will facilitate the 

interdependency between the two.

The full report is located on the WIEB website. (http://westernenergyboard.org/naturalgas/study/)

WIEB and the subcontractor, E3, have begun work on Phase 2 of the project, which will 

evaluate short term flexibility of the natural gas system’s ability to meet increased volatility 

in hourly electric industry natural gas demand using hydraulic modeling. Phase 2 will focus on 

two subregions. First, the Pacific NW West will highlight a portion of Williams NW Pipeline in 

the I5 corridor, near a large portion of the region’s power generation. The analysis is focused 

on developing a case that revolves around the interaction of hydro, wind and how an increase 

in wind generation could affect ramping on NW Pipeline during electric peaks. Williams NW 

Pipeline conducted a hydraulic analysis to explore system response to the increase in ramp 

due to wind generation. The analysis indicated that natural gas ramp from increased reliance 

on wind would not pose significant challenges on the pipeline system. The system was mostly 

balanced by natural gas from storage inventories and to a limited extent utilization of 

linepack. Preliminary results indicate that physical infrastructure is generally equipped to 

handle ramps in demand provided shippers maintain balance between receipts and deliveries. 

Electric load forecasting challenges related to renewable generation can lead to imbalances 

in natural gas receipts and deliveries, potentially creating operational challenges for 

pipelines. 

The second subregion is the Pacific NW East, which will focus on Transcanada’s GTN system, 

serving power plants in eastern Washington and Oregon near the pipeline’s interconnect with 

the Williams NW Pipeline system. This area is notable as a potential area of increased gas for 

power generation load in the next 5-10 years. The draft results for the first subregion, the 

Pacific NW and the I5 Corridor, large downward ramp in wind generation results in large 

upward ramp in gas use, but is 

Phase 2 results are expected in mid to late June. 
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Slide 8

Relevant 

Natural Gas Filings

Region Pipeline/Association Capacity/

Initiative

Docket No. Status

Southeast Southern Natural Gas Company Capacity Expansion 

235 MMcfd

CP14-493-000 Filed 5/30/2014

Gulf Coast Gulf Crossing Pipeline Company 

(Phase II facilities of the Panda Power 

Lateral Project )

Capacity addition 

278.4 MMcfd

CP13-64-000 In Service 

5/30/2014

National 149 interstate natural gas pipelines Order to Show Cause, 

Posting of Offers to 

Purchase Capacity

RP14-442-000 Pending

Gulf Coast Enable Gas Transmission and Enable 

Mississippi River Transmission 

(collectively Enable Pipelines)

Order No. 787 RM13-17-001 Issued 6/19/2014

National The Natural Gas Supply Association, 

the Process Gas Consumers Group, 

and the Northwest Industrial Gas 

Users (collectively, NGSA et al.)

Order No. 787 RM13-17-001 Issued 6/19/2014

Northeast National Fuel Gas Supply Corporation 

and Empire Pipeline

Request for Limited 

Waivers of No-Conduit 

Rule adopted in Order 

No. 787 

RP14-380-000 Issued 6/19/2014

Gulf Coast Enable Gas Transmission and Enable 

Mississippi River Transmission 

(collectively Enable Pipelines)

Request for Limited 

Waiver of No-Conduit 

Rule adopted in Order 

No. 787 

RP14-453-000 Issued 6/19/2014

Mid-Atlantic Transcontinental Gas Pipe Line 

Company,

Petition for Limited 

Waiver of No-Conduit 

Rule adopted in Order 

No. 787

RP14-623-000 Pending

Our next area covers relevant natural gas and electric filings submitted with the Commission, 

starting with natural gas pipeline applications. We highlight a new reported filing to expand 

pipeline capacity serving electric generation as well as a status update to a previously cited 

project. 

On May 30, 2014, Southern Natural Gas Company, L.L.C. (SNG) filed an application for a 

certificate authorizing the SNG Zone 3 Expansion Project to add 235 million cubic feet per day 

(MMcfd) of firm transportation capacity to the existing SNG pipeline system through 

modifications to its system across the Southeast. SNG plans to place the SNG Zone 3 

Expansion Project in-service on or about June 1, 2016. The Project is supported by signed 

precedent agreements (PAs) for firm transportation service with ten new and existing 

customers. The customers who have signed PAs include local distribution companies (LDCs), 

power generators, and industrial customers. 

Gulf Crossing Pipeline Company LLC was granted authorization on May 30, 2014 to commence 

service to the Phase II facilities of the Panda Power Lateral Project in Grayson County, Texas. 

This project will be capable of providing up to 278.4 MMcfd of firm transportation service to 

the Panda Sherman Power Electric Power Plant.

During the months of April through May 2014, 149 interstate natural gas pipelines that 

transport natural gas pursuant to subparts B or G of Part 284 of the Commission’s regulations 

submitted filings to the Commission to comply with the previously reported Natural Gas Act 

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 that regulation (March 20 Order). As explained in the 

March 20 Order, the Commission assigned each pipeline’s compliance filing a separate RP 
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docket and provided interested parties an opportunity to intervene in those dockets. This 

matter is pending before the Commission.

In today’s order on rehearing of Order No. 787, the Commission’s final rule on interstate 

pipeline-electric transmission operator communications, the Commission denies Enable 

Pipelines’ request to revise the No-Conduit Rule to allow disclosures to third parties (other 

than marketing function employees). The rehearing order also denies the request of NGSA et 

al. to hold a technical conference after an interim period to assess the effectiveness of the 

new communications standards in Order No. 787. 

Today, the Commission is also issuing an order granting in part and denying in part National 

Fuel Pipelines’ request for waivers of Order No. 787. Specifically, the Commission is granting 

National Fuel Pipelines a limited waiver of Order No. 787 to permit (1) shared employees in 

National Fuel Pipelines’ gas dispatch center to receive non-public, operational information 

from a public utility pursuant under Order No. 787 and to share it with other shared 

employees in the Shared Services Departments, and (2) permit shared employees in the 

Shared Services Departments to receive communications regarding electric service 

interruptions affecting National Fuel Pipelines’ facilities, subject to conditions. The order, 

however, denies National Fuel Pipelines’ requests for waiver of Order No. 787 to permit 

National Fuel Pipelines to communicate information received under the rule regarding 

electric service interruptions or impending power outages to affiliated non-shared employees. 

The Commission is also issuing an order granting Enable Pipelines’ request for waiver of Order 

No. 787 to permit employees shared by Enable Pipelines and their affiliated intrastate and 

gathering systems to receive non-public, operational information provided under Order No. 

787, subject to conditions.

On March 14, 2014, Transcontinental Gas Pipe Line Company, LLC (Transco) requested a 

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

under the rule to an affiliate. Specifically, Transco requests a limited waiver of the NoConduit Rule adopted in Order No. 787 for operational personnel shared between Transco and 

Cardinal Pipeline Company, LLC, its affiliated intrastate pipeline. This matter is pending 

before the Commission.
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Slide 9

Relevant

Electric Filings

Entity Filing Initiative Docket 

No.

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

ISO-NE and 

New England 

Power Pool

Offer Flexibility Changes ER13-1877

NYISO Request for Limited Waiver of the $1,000/MWh Bid Cap ER14-1138

PJM Request for Limited Waiver of the System Offer Cap Rule ER14-1144

PJM Request for Temporary Waiver of the System Offer Cap Rule ER14-1145

CAISO Request for Waiver to Update the Natural Gas Price Index Used 

for Proxy Gas Calculations

ER14-1440

Duke Energy January 2014 Cold Weather Events Related Natural Gas Costs EL14-45

Eagle Point 

Power 

Generation

Request for Waiver to Recover Procured Fuel Cost ER14-2075

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 March 12, 2014, PJM submitted 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 (Docket No. ER14-

1469). On May 9, 2014, the Commission accepted the proposed tariff revisions, effective 

March 13, 2014, as requested, subject to conditions (May 9 Order). The May 9 Order found 

that, with its proposed revision which explicitly permits PJM to share non-public, operational 

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

reliable service and operational planning, PJM will no longer need to seek expedited waiver of 

section 18.17.1 of its Operating Agreement in the event of extreme weather conditions, such 

as the conditions that occurred earlier this year. The May 9 Order, however, required PJM to 

file a revised tariff record within 15 days from the date of the May 9 Order to clarify section 

18.17.1(f) of the Operating Agreement, specifying 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 compliance with the May 9 Order, to be 

effective March 13, 2014, to amend section 18.17.1(f) of the Operating Agreement to require 

that a recipient local distribution company or intrastate pipeline operator acknowledge, in 

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

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

preferential manner or to the detriment of any natural gas or electric market (Docket No. 

ER14-1469-001). This matter is pending before the Commission.

The Commission issued an order on April 29, 2014 accepting ISO-NE and NEPOOL’s filing in 

Docket No. ER13-1877-001 made in compliance with the October 3, 2013 Order to become 
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effective December 3, 2014, as requested (April 29 Order). The April 29 Order found that, 

because there is not sufficient real-time market information available outside normal business 

hours, the Internal Market Monitor would be unable to verify locked-out resources’ requests 

to change reference levels during those hours. The April 29 Order went on to find that by 

changing the deadline from 6:00 p.m. on the day prior to the operating day to anytime 

between 8:00 a.m. and 5:00 p.m. during the operating day and at least one hour prior to the 

close of the next hourly supply offer submittal period, ISO-NE’s Transmission, Markets and 

Services Tariff (Tariff) revisions provide locked-out market participants with significant 

additional flexibility to submit updated fuel price information. Lastly, the April 29 Order 

found that the Tariff revisions, which specifically provide that updated reference levels will 

be made available to resources whenever calculated, as opposed to daily, also comply with 

the October 3, 2013 Order’s requirement.

On March 28, 2014, the NYISO submitted an informational filing Docket No. ER14-1138-000 as 

directed by the Commission in its January 31, 2014 order granting limited waiver of the 

$1,000/MWh Bid Cap. Specifically, the NYISO states that no energy resource received 

compensation pursuant to the terms of the waiver. Further, the NYISO states that the NYISO 

received fewer than five requests for compensation pursuant to the waiver. Moreover, the 

NYISO states that each of the requests was later withdrawn by the submitting Market 

Participant when the Market Participant determined that it was not eligible to receive 

additional Bid Production Cost Guarantee payments under the terms of the waiver because 

the Market Participant recovered the actual costs it incurred without requiring supplemental 

compensation.

On March 26, 2014, the Independent Market Monitor for PJM (IMM) submitted an informational 

filing in Docket No. ER14-1144-000 as directed by the Commission in its January 24, 2014 

order granting limited waiver of PJM’s system offer cap rule. In the filing, the IMM identifyied 

certain aspects of the cost-based offers from Generation Capacity Resources for whom the 

price of natural gas resulted in documented costs that exceeded PJM’s $1,000/MWh offer cap, 

consistent with the January 24 Order. The IMM concluded, among other things, that the high 

natural gas prices observed on January 28, 2014 resulted in units being offered with 

estimated costs that appeared to exceed the $1,000 per MWh offer cap. The IMM further 

concluded that its calculations showed that for the units requesting waivers in this docket, 

there were total uncompensated costs of only $9,118.43. The IMM, however, found that a 

more detailed examination of the facts by the IMM did not support most of the waiver 

requests.

Following the Commission’s February 11, 2014 order granting PJM’s Request for Temporary 

Waiver of the System Offer Cap Rule in Docket No. ER14-1145-000, on March 13, 2014, the 

PJM Industrial Customer Coalition, Consumer Advocate Division of West Virginia, Delaware 

Division of the Public Advocate, Illinois Citizens Utility Board, Indiana Office of Utility 

Consumer Counselor, Maryland Office of People’s Counsel, New Jersey Division of Rate 

Counsel, Office of the People’s Counsel of the District of Columbia, and Pennsylvania Office 

of Consumer Advocate (collectively, Consumer Representatives) filed a request for rehearing 

(Docket No. ER14-1145-001). Specifically, the Consumer Representatives argue that (1) the 

February 11 Order’s acceptance of PJM’s requested waiver of the $1,000/MWh Offer-Price 

Cap constitutes impermissible retroactive ratemaking; and (2) the February 11 Order erred by 

arbitrarily and capriciously deviating from its own standards for the granting of tariff waivers. 

This matter is pending before the Commission.
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Further, on April 30, 2014, the Independent Market Monitor for PJM (IMM) submitted an 

informational filing identifying certain aspects of the cost-based offers from Generation 

Capacity Resources for whom the price of natural gas resulted in documented costs that 

exceeded PJM’s $1,000/MWh offer cap, consistent with the February 11 Order. The IMM 

explains that in PJM, every energy offer includes a start component, a no load component and 

an incremental curve component. The IMM asserts that some units’ energy offers, including 

the no load and incremental curve components, did exceed $1,000/MWh but none of those 

units ran with those offers, and none of these offers directly affected energy market prices or 

resulted in uplift payments. The IMM states that its review of the 49 day period from 

February 11 through March 31, 2014 indicates that there were no energy offers submitted 

with incremental curve offer components above $1,000/MWh. Thus, the IMM concludes that 

there were no Locational Market Prices above $1,000/MWh as a direct result of the waiver 

granted in Docket No. ER14-1145-000. The IMM states that this conclusion is limited to the 

incremental curve component of generator energy offers. Lastly, the IMM states that it is 

investigating the offer behavior of several units and will take appropriate actions consistent 

with Attachment M of PJM’s tariff. This matter is pending before the Commission.

On March 21, 2014, the Commission issued an order in Docket No. ER14-1440-000 granting 

CAISO’s requested waiver through April 30, 2014 to allow CAISO to use updated natural gas 

price data not only for settlement purposes, but also for market execution in the event 

natural gas prices for the affected trading day equal or exceed 150 percent of the natural gas 

price calculated pursuant to CAISO’s tariff (March 21 Order). The March 21 Order found that 

CAISO’s request addressed a concrete problem by allowing natural gas-fired generators the 

opportunity to recover their start-up and minimum load costs based on data that more 

accurately reflects current natural gas pricing. The March 21 Order also found that the 

waiver allows the more accurate natural gas pricing data to be included in the day-ahead 

market runs. The March 21 Order found that this corrects market signals through transparent 

market pricing, improving on the settlement approach approved in the March 14 Order in 

Docket No. ER14-1442-000 that was intended to be a stop-gap mechanism to address nearterm adverse outcomes.

On May 5, 2014, Duke Energy Corporation (Duke Energy) filed a formal complaint in Docket 

No. EL14-45-000 against PJM, or in the alternative a request for waiver of certain OATT 

provisions, in which Duke seeks recovery of natural gas costs incurred in January 2014 in 

anticipation of an extreme weather event. This matter is pending before the Commission.

On May 30, 2014, Eagle Point Power Generation LLC (Eagle Point) requested limited waiver of 

Sections 1.9.7(b)(i) and 1.10.2(d) of Attachment K-Appendix of the PJM Tariff to permit Eagle 

Point to recover the losses it incurred when it procured fuel to comply with a PJM reliability 

instruction and resold the unused portion of that fuel at a loss after PJM canceled its 

instruction. This matter is pending before the Commission.
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Slide 10

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

national and regional entities and with regulated entities regarding their efforts on gaselectric coordination.