1、NREL is a national laboratory of the U.S.Department of Energy Office of Energy Efficiency&Renewable Energy Operated by the Alliance for Sustainable Energy,LLC This report is available at no cost from the National Renewable Energy Laboratory(NREL)at www.nrel.gov/publications.Contract No.DE-AC36-08GO2

2、8308 Technical Report NREL/TP-6A40-89363 June 2024 Barriers and Opportunities To Realize the System Value of Interregional TransmissionChristina E.Simeone and Amy Rose National Renewable Energy Laboratory NREL is a national laboratory of the U.S.Department of Energy Office of Energy Efficiency&Renew

3、able Energy Operated by the Alliance for Sustainable Energy,LLC This report is available at no cost from the National Renewable Energy Laboratory(NREL)at www.nrel.gov/publications.Contract No.DE-AC36-08GO28308 National Renewable Energy Laboratory 15013 Denver West Parkway Golden,CO 80401 303-275-300

4、0 www.nrel.gov Technical Report NREL/TP-6A40-89363 June 2024 Barriers and Opportunities To Realize the System Value of Interregional TransmissionChristina E.Simeone and Amy Rose National Renewable Energy Laboratory Suggested Citation Simeone,Christina E.and Amy Rose.2024.Barriers and Opportunities T

5、o Realize the System Value of Interregional Transmission.Golden,CO:National Renewable Energy Laboratory.NREL/TP-6A40-89363.https:/www.nrel.gov/docs/fy24osti/89363.pdf.NOTICE This work was authored by the National Renewable Energy Laboratory,operated by Alliance for Sustainable Energy,LLC,for the U.S

6、.Department of Energy(DOE)under Contract No.DE-AC36-08GO28308.Funding provided by the U.S.Department of Energy Grid Deployment Office.The views expressed herein do not necessarily represent the views of the DOE or the U.S.Government.This report is available at no cost from the National Renewable Ene

7、rgy Laboratory(NREL)at www.nrel.gov/publications.U.S.Department of Energy(DOE)reports produced after 1991 and a growing number of pre-1991 documents are available free via www.OSTI.gov.Cover Photos by Dennis Schroeder:(clockwise,left to right)NREL 51934,NREL 45897,NREL 42160,NREL 45891,NREL 48097,NR

8、EL 46526.NREL prints on paper that contains recycled content.iii This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Preface This reportBarriers and Opportunities To Realize the System Value of Interregional Transmissionexamines the barriers

9、 and identifies potential opportunities within existing market and operating rules to achieve the benefits of coordinated transmission planning and operations for electric customers.This report is part of the U.S.Department of Energys(DOEs)National Transmission Planning Study(NTP Study),conducted by

10、 the National Renewable Energy Laboratory and Pacific Northwest National Laboratory.The aim of the NTP Study is to identify transmission that will provide broadscale benefits to electric customers,inform regional and interregional transmission planning processes,and identify interregional and nation

11、al strategies to accelerate decarbonization while maintaining system reliability.More information on the NTP Study is available at https:/www.energy.gov/gdo/national-transmission-planning-study.In addition,the NTP Study includes two other complementary reports focused on implementation and action.Th

12、e forthcoming report Regulatory Pathways to New Interregional Transmission:A Landscape Assessment is a companion to this report under the NTP Study umbrella(Homer et al.forthcoming).That report explains the regulatory challenges to building new interregional transmission that have historically preve

13、nted realizing many of the benefits quantified in the NTP Study technical scenario.The report Interregional Renewable Energy Zones uses the national modeling conducted for the NTP Study to identify specific high-value interregional zones for renewable energy development and the coordination steps re

14、quired to realize the benefits of these zones.Together,this report and other volumes in the NTP Study series provide a knowledge base that states,industry,transmission planners,policymakers,and others can use to achieve some of the benefits revealed in the NTP Studys national scenarios.iv This repor

15、t is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Acknowledgments Members of the National Transmission Planning Study(NTP Study)technical review committeewhich included experts representing various system operators,utilities,industry organizations,T

16、ribal nations,state and federal agencies,nongovernmental organizations,and othershelped guide the NTP Study to identify and address relevant questions.The authors would like to thank the individuals from the committee who provided their input on any of the topics discussed in this report.The opinion

17、s contained in this report are those of the authors and do not reflect the specific views or interpretations of specific members of the committee or their institutions.The authors are also greatly indebted to several individuals for their thoughtful feedback and guidance,including Yonghong Chen,Jess

18、 Kuna,David Palchak,Trieu Mai,David Hurlbut,Jaquelin Cochran,Mark Ruth,and Dan Bilello from the National Renewable Energy Laboratory(NREL)and Yamit Lavi,Adria Brooks,Jay Caspary,Rian Sackett,Melissa Birchard,and Patrick Harwood from DOEs Grid Deployment Office.Emily Horvath and Madeline Geocaris(NRE

19、L)provided editing support.Any errors and omissions are solely the responsibility of the authors.This work was funded by DOEs Grid Deployment Office.v This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.List of Acronyms AC alternating curren

20、t ATC available transmission capacity BAA balancing authority area BRA base residual auction CACM Capacity Allocation and Congestion Management CAISO California Independent System Operator CIL capacity import limit CTS coordinated transaction scheduling DOE U.S.Department of Energy DRI demand-at-ris

21、k indicator ENTSO-E European Network of Transmission System Operators for Electricity FERC Federal Energy Regulatory Commission FFE firm flow entitlement GW gigawatt GWh gigawatt-hour HVDC high-voltage direct current IESO independent electricity system operator IMO independent electricity market ope

22、rator ISO independent system operator ISO-NE Independent System Operator of New England JOA joint operating agreement M2M market-to-market MISO Midcontinent Independent System Operator MMU Market Monitoring Unit MRO Midwest Reliability Organization MW megawatt MWh megawatt-hour NEMO nominated electr

23、icity market operator NERC North American Electric Reliability Corporation NAESB North American Energy Standards Board NTP Study National Transmission Planning Study NYISO New York Independent System Operator Ofgem Office of Gas and Electricity Markets PAR phase angle regulator PCI projects of commo

24、n interest PFP pay-for-performance PFV parallel flow visualization PJM PJM Interconnection RC reliability coordinator RTO regional transmission organization SERC Southeastern Reliability Corporation SPP Southwest Power Pool SPTO subscriber participating transmission owner TCR transmission congestion

25、 rights TLR transmission loading relief vi This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.TSO transmission system operator TYNDP 10-year network development plan UFMP Unscheduled Flow Mitigation Plan WECC Western Electricity Coordinatio

26、n Council WEIM Western Energy Imbalance Market WEIS Western Energy Imbalance Services WRAP Western Resource Adequacy Program vii This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Executive Summary This report identifies barriers within rul

27、es and operational practices that may limit the value existing interregional transmission can provide to electric consumers and identifies a suite of options that could enable greater use of and value from interregional transmission.To allow for the variety of power sector structures that exists acr

28、oss the United States,the report divides the evaluation of barriers and opportunities into three sections:common issues found in all regions,barriers between nonmarket or hybrid areas,and barriers between market areas.The report also identifies ambitious,transformative national actions that could un

29、lock transmission value across both market(e.g.,between regional transmission operators)and nonmarket(e.g.,areas that primarily rely upon bilateral transactions)areas.This report provides an overview,rather than a complete or exhaustive list,of barriers and solution options and generally examines hi

30、storic issues rather than reasonably anticipated concerns.In the analysis of barriers and potential opportunities for improvement,we recognize these are technically complex issues with a diverse set of power system stakeholders and factors that must be considered.We further recognize this report doe

31、s not fully explore the complicated issues grid operators face when seeking to address these barriers,such as changing financial outcomes and the potential creation of winners and losers in markets.The aim of this report is not to make recommendations but to identify options to improve the use of in

32、terregional transmission that could be considered alongside other local,state,regional,and stakeholder objectives.While this report is focused on issues that prevent existing transmission facilities from delivering maximum potential value,the findings have important implications for future transmiss

33、ion investments.Barriers To Capturing the Value of Interregional Transmission Capability In both market and nonmarket regions,we find the absence of a framework for resource adequacy sharing may discourage grid operators from relying on external resources for reliability.A second common issue is tra

34、nsmission owners and operators have limited operational awareness to anticipate when large power transfers are needed.This is especially relevant in response to extreme weather events when interregional transmission could enable large power transfers to maintain reliability.Third,planning for within

35、-region transmission networks may not account for large power flows across the network to accommodate increased imports and exports with neighboring regions.Among nonmarket regions or between market-to-nonmarket hybrid regions,we find inconsistent or uncoordinated approaches to scheduling and real-t

36、ime operations may result in the inefficient use of interregional transmission.Uncoordinated bilateral trading has inherent limitations that may not be able to identify lowest-cost resources to meet system needs and may prevent the ability to adjust to real-time operating conditions.In hybrid region

37、s,regional practices to prioritize market transactionseven during emergency conditionscan reduce system reliability.Uncoordinated approaches to congestion management can pose reliability risks across critical transmission corridors and limit the ability to use scarce interregional transmission capac

38、ity for economically efficient power trades.Finally,inconsistent approaches to estimate and communicate available transfer capacity across interregional lines can result in underutilized or oversubscribed transmission lines.viii This report is available at no cost from the National Renewable Energy

39、Laboratory at www.nrel.gov/publications.Most of the market-to-market issues relate to inefficiencies in joint operating agreement programs between market regions.First,inaccurate price forecasts and high transaction fees limit the efficient use of transmission capacity through coordinated transactio

40、n scheduling.In daily operations,issues with interface pricing between regions can lead to operational inefficiencies such as loop flows,economic inefficiencies such as redundant charges,and opportunities for market manipulation through sham scheduling where scheduled flows do not match actual flows

41、.We also find outdated flow limits and inaccurate modeling of interregional lines leads to excessive costs for congestion management that are borne by ratepayers.Finally,we find most regional markets lack the ability to optimize the use of available merchant high-voltage direct current(HVDC)transmis

42、sion capacity,which leads to inefficient use of these grid assets.Opportunities For each of the identified barriers,we describe potential options that policymakers,regulators,and system operators could pursue to improve the efficient use of interregional transmission.These options,summarized in Figu

43、re ES-1,include actions tailored to the specific needs and power sector structures in different planning regionsincluding options for market,nonmarket,or hybrid areasas well as options common to all areas.These reforms could both significantly enhance the value of interregional transmission and deli

44、ver additional within-region benefits not related to interregional transmission.Figure ES-1.Summary of incremental and transformative opportunities to realize the system value of interregional transmission ix This report is available at no cost from the National Renewable Energy Laboratory at www.nr

45、el.gov/publications.This report also identifies transformative opportunities that could be implemented more broadly across the multiple regions to maximize the system benefits of interregional transmission.These options include national transmission and resource planning,multiregion or interconnecti

46、on-wide optimization,and a combination of these responsibilities.Although the total benefits of these opportunities are not directly quantified,we note the portion of total benefits attributed to interregional transmission generally increases as the geographic scope and level of coordination increas

47、es.As the United States seeks to transform its electricity supply with increased shares of clean energy,the electricity grid will need to transform in parallel to accommodate new sources of supply with new output profiles developed across the country.The National Transmission Planning Study(NTP Stud

48、y)identifies a suite of transmission options that will provide broadscale benefits to electric customers,inform regional and interregional transmission planning processes,and identify interregional and national strategies to accelerate decarbonization while maintaining system reliability.The NTP Stu

49、dy demonstrates coordinated planning and operation of the national transmission gridincluding increased development of interregional transmissioncan reduce the cost of meeting energy,reliability,and reserve requirements by hundreds of billions of dollars.Though this report focuses on issues that pre

50、vent existing transmission facilities from delivering maximum potential value,the findings have important implications for future transmission investments.The barriers and opportunities identified in this report can guide the suite of reforms needed to realize these systemwide benefits.x This report

51、 is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Table of Contents Executive Summary.vii Barriers To Capturing the Value of Interregional Transmission Capability.vii Opportunities.viii 1 Introduction.1 2 The Promise and Reality of Transmission Benef

52、its.2 2.1 Benefits of Transmission.2 2.2 Symptoms of Inefficiency.3 2.2.1 Uneconomic Flows and High Price Differentials.3 2.2.2 Underutilized Interchange Capacity.4 2.2.3 Lack of Transparency on Inefficiencies With Bilateral Trading.5 3 Barriers and Opportunities To Realize Transmission Value.8 3.1

53、Common Barriers.8 3.1.1 Absence of Resource Adequacy Sharing Framework.8 3.1.2 Operating Practices During Extreme Weather Events.10 3.1.3 Internal Transmission Capacity To Accommodate Large Transfers.12 3.2 Barriers Between Nonmarket or Hybrid Areas.14 3.2.1 Uncoordinated Bilateral Trading.14 3.2.2

54、Congestion Management.15 3.2.3 Inconsistent Available Transfer Capability Methods and Assumptions.19 3.2.4 Wheel-Through Priority for Reliability Imports.20 3.3 Barriers Between Market Areas.21 3.3.1 Coordinated Transaction Scheduling.21 3.3.2 Market-to-Market Congestion Coordination.24 3.3.3 Interf

55、ace Flows and Pricing.27 3.3.4 Market Co-Optimization of Merchant Interregional HVDC Line.31 3.3.5 RTO-Specific Issues.32 4 Transformative Opportunities.35 4.1 Systemwide Transformation.35 4.1.1 Long-Range,Nationwide Interregional Transmission Planning.35 4.1.2 Intertie Optimization.36 4.1.3 Nationa

56、lly Coordinated System Planning and Operations.39 5 Conclusion.41 References.43 xi This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.List of Figures Figure ES-1.Summary of incremental and transformative opportunities to realize the system

57、value of interregional transmission.viii Figure 1.Potential benefits of electricity transmission.2 Figure 2.Hours with uneconomic power flow across major interregional seams in 2022.4 Figure 3.ISO-NE to NYISO unused coordinated transaction scheduling capacity,2022.5 Figure 4.SERC 2023 Summer Reliabi

58、lity Assessment.11 Figure 5.Total TLRs(Levels 3,4,and 5)by reliability coordinator(20052018).16 Figure 6.Approximate location of current(yellow)and former(green)qualified paths in the Western Interconnection UFMP.17 Figure 7.CTS scheduling and efficiency(20182022).22 Figure 8.PJM/MISO credits for co

59、ordinated congestion management,Jan 2021Dec 2022.25 Figure 9.Summary of incremental and transformative opportunities to realize the system value of interregional transmission.41 List of Tables Table 1.Volatility in CTS Interface Price Differences Between Day-Ahead and Real-Time Scheduling(2022).23 1

60、 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.1 Introduction The National Transmission Planning Study(NTP Study)identifies a suite of transmission options that could provide broadscale benefits to electric customers,inform regional an

61、d interregional transmission planning processes,and identify interregional and national strategies to accelerate decarbonization while maintaining system reliability.Among these options,expanded investments in interregional transmission capability show the greatest potential to meet national imperat

62、ives for reliability,resilience,and reduction in greenhouse gas emissions at the lowest cost and deliver a wide range of system benefits.The NTP Study finds accelerated transmission development could result in hundreds of billions of dollars in systemwide savings under a range of decarbonization sce

63、narios compared to meeting these targets with more limited development of transmission between regions.1 The savings include avoided capital and operating costs to meet system requirements for energy and reliability.In practice,a host of barriers may exist that prevent the realization of these and o

64、ther interregional transmission benefits.This report identifies barriers within existing rules and operational practices that may limit the system value interregional transmission can provide and identifies a suite of options that could enable greater use of and value from interregional transmission

65、.To allow for the variety of power sector structures that exists across the United States,the report divides the evaluation of barriers and opportunities into three sections:common issues found in all regions,barriers between nonmarket or hybrid areas,and barriers between market areas.The report als

66、o identifies ambitious,transformative national actions that could leverage transmission capability to further lower system costs across both market and nonmarket areas.Though this report focuses on issues that prevent existing transmission facilities from delivering maximum potential value,the findi

67、ngs have important implications for future transmission investments.Interim results from the NTP Study estimate significant growth in new transmission capacity,expanding the current grid by about 2 to 4 times by 2050,to achieve a reliable,resilience,and decarbonized power system at the lowest cost b

68、y enabling the interconnection of large amounts of low-cost wind and solar.Given the significant magnitude of electricity transmission investments needed,ensuring these investments are operating efficiently to maximize the value they can provide to the system is increasingly important.This report be

69、gins by identifying the potential benefits of interregional transmission and indicators that interregional transmission benefits may not be fully realized in practice(Section 2).Section 3 identifies barriers to achieving full interregional transmission value and proposes options to realize transmiss

70、ion value.Section 3 is divided into three subsections:barriers common to all areas,barriers between nonmarket or hybrid(trades between market and nonmarket)areas,and barriers between markets.The opportunities in Section 3 are tailored to each barrier,whereas Section 4 identifies transformative optio

71、ns that could allow for interregional transmission value maximization.1 For more information on the NTP Study modeling results,see National Transmission Planning Study(Palchak et al.forthcoming).2 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publi

72、cations.2 The Promise and Reality of Transmission Benefits There is broad recognition that coordinated planning and management of regional and interregional transmission infrastructure can provide a range of system benefits.However,there are signs these benefits are not fully captured for existing t

73、ransmission facilities.2.1 Benefits of Transmission Electricity transmission can provide a wide range of system benefits by increasing the geographic footprint of the system to enable greater use of the most efficient resources.Historically,production cost savings2 has been the primary metric for va

74、luing transmission investments,but transmission can also provide environmental benefits,access to low-cost renewable energy,generation capital cost benefits,risk mitigation benefits,and improvements in reliability and resilience(Chang,Pfeifenberger,and Hagerty 2013)(Figure 1).Figure 1.Potential bene

75、fits of electricity transmission 2 Production cost savings or adjusted(for imports and exports)production cost savings typically consider the avoided electricity production costs associated with accessing lower-cost generation resources through economic dispatch and trades with neighboring systems.A

76、voided generation capacity investments Access to lower-cost generation sites Access to policy incentives for renewable energy investments(e.g.,investment tax credit)Capital Costs Avoided costs for fuel,cycling,and other variable costs Reduced transmission losses Access to policy incentives for renew

77、able energy generation(e.g.,production tax credit)Operating Costs Reduced loss of load probability Reduced cost of meeting requirements for ancillary services and resource adequacyReliability Reduced severity and duration of outages Reduced outages during extreme events Mitigation of weather and loa

78、d uncertaintyResiliency3 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Though the transmission benefits in Figure 1 are listed individually,many are not mutually exclusive.For example,interregional transmission investments that reduce

79、the cost of meeting ancillary service requirements may also reduce capital investments needed to meet these requirements.2.2 Symptoms of Inefficiency For years,market monitors and electricity stakeholders have pointed to signals that transmission capacity and scarce interregional capacity,in particu

80、lar,are not being used efficiently.Efficient use of interregional capacity could maximize the ability of these assets to flow low-cost power from one region to load in a neighboring region,displacing higher-cost power.The following issues can be potential indicators of inefficient use of interregion

81、al transmission:Uneconomic Flows:Power flows in uneconomic directionsmeaning from higher-price areas to lower-price areasprovides clear evidence that something is not working properly.Short periods of uneconomic flows may not be an indicator of inefficiency compared to longer or reoccurring periods.

82、High Price Differentials:The appearance of high price differentials,when there is a significant spread in power prices between regions,indicates an opportunity to lower prices through trade.Persistent high price differentials may indicate beneficial trading is not taking place,representing a missed

83、opportunity to reduce customer costs in the high-priced region.Underutilized Capacity:Underutilized transmission assets may signal these assets are not being used efficiently to bring lower-priced power to higher-priced regions.Underutilized capability may not be an indicator of inefficiency,for exa

84、mple,if there is no available lower-priced power to move to higher-priced areas.Lack of Transparency on Inefficiencies:Other symptoms,such as a lack of transparency in interchange transactions,have more subtle and less direct impacts on the efficient use of electricity transmission.Lack of transpare

85、ncy itself may not be an issue;rather,lack of transparency is an obstacle to identifying inefficienciesand opaqueness is more likely to occur in areas with less market oversight(e.g.,lack of market monitoring).These symptoms of inefficient interregional transmission use are discussed in detail in th

86、e following sections.2.2.1 Uneconomic Flows and High Price Differentials In a well-coordinated system with efficient use of transmission capacity,power is expected to flow from areas of lower price to areas of higher price.However,a large volume of interchange flows occurs in the uneconomic directio

87、n,meaning power is moving from higher-priced areas to lower-priced areas.In addition,high price differentials existed during many hours where uneconomic flows prevailed.This potentially represents an economic inefficiency in the use of interregional transmission.However,some of these high-to-low pri

88、ces flows could be occurring because of bilateral agreements or wheeling transactions that do not depend on market price differentials.4 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Figure 2 shows the percentage of hours with uneconom

89、ic power flows across four major interregional seams in 2022(Monitoring Analytics,LLC 2023;ISO-NE Internal Market Monitor 2023;Potomac Economics 2023c).Figure 2.Hours with uneconomic power flow across major interregional seams in 2022 Price spread means the difference in average hourly locational ma

90、rginal prices between regional interfaces PJM Interconnection(PJM)and Midcontinent Independent System Operator(MISO)experienced the highest percentage(48%)of uneconomic flows in 2022 according to the PJM market monitor(Monitoring Analytics,LLC 2023).Though the MISO market monitor estimates this valu

91、e is closer to 40%,it still represents a large share of the year with uneconomic power flows(Potomac Economics 2023c).In almost 30%of hours,the average locational marginal price difference between the regions was over$5/megawatt-hour(MWh).Across the Independent System Operator of New England(ISO-NE)

92、and New York Independent System Operator(NYISO)interfaces,power flowed in the economic direction for only 57%of hours.Between MISO and Southwest Power Pool(SPP),power flowed in the economic direction for about 60%of hours.PJM and NYISO also experienced high shares of uneconomic transactions,even dur

93、ing periods when the price differences between the markets exceeded$5/MWh.Section 3 explores potential reasons for high shares of uneconomic flows across these different regional pairs and possible options to increase the efficient use of interregional transmission links.2.2.2 Underutilized Intercha

94、nge Capacity As discussed previously,when there is a price differential between transmission systems,interregional transmission can facilitate the transfer of lower-priced available supply areas with higher-priced supplies.In practice,evidence suggests some interregional transmission capacity is bei

95、ng underutilized despite large price differentials.In Figure 3,ISO-NEs internal market monitor identifies the unused but available interface capacity between ISO-NE and NYISO in 5 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.2022 asso

96、ciated with the coordinated transaction scheduling(CTS)mechanism(ISO-NE Internal Market Monitor 2023,162).These data indicate even when price differences were high,there was unused interface capacity available to move lower-priced power to higher-priced areas and these opportunities occurred often t

97、hroughout the year.For example,in 24%of hours in the year when price differentials between ISO-NE and NYISO were between$10 and$25,there was on average 250 megawatts(MW)of unused available interface capacity(ISO-NE Internal Market Monitor 2023).Figure 3.ISO-NE to NYISO unused coordinated transaction

98、 scheduling capacity,2022 The percentages on each bar show the percent of time each price bin occurred during the year.The x-axis is average available but unused CTS interface capacity(ISO-NE Internal Market Monitor 2023,162).2.2.3 Lack of Transparency on Inefficiencies With Bilateral Trading Bilate

99、ral contracting was the predominant form of wholesale transaction until the mid-1990s with the introduction of restructuring(Energy Policy Group,LLC 2016).Bilateral trading relies on negotiated wholesale contracts or agreements between willing buyers and sellers.These transactions are common in both

100、 market and nonmarket regions.Proponents of bilateral trading argue that these agreements have been more effective at catalyzing new capacity investments,reducing risk associated with stranded costs,and,in nonmarket regions,meeting system needs without the cost overlay of operating a centralized mar

101、ket(Energy Policy Group,LLC 2016).Nonmarket settings have less publicly reported data available on outcomes,operations,and efficiency than regional transmission organizations(RTOs)and independent system operator(ISO)markets that have market monitoring and reporting requirements.This absence of avail

102、able data can make it more difficult to detect potential inefficiencies and other market issues.For example,most of the data and information supporting this report was found in RTO/ISO market monitoring reports whereas significantly less information was available for areas outside of RTOs/ISOs.6 Thi

103、s report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.The Federal Energy Regulatory Commission(FERC)promulgated Order No.888 to remedy inefficiencies and undue discrimination observed in bilateral markets at the time(Federal Energy Regulatory Com

104、mission 1996).Order No.888 required all public utilities to have on file at FERC open access transmission tariffs containing minimum terms and conditions for nondiscriminatory access to transmission services and ancillary services,which was meant to address public utility discrimination against comp

105、etitors.The rule also provides guidance on the formation of ISOs,which were meant to promote competition and efficient operationsleading to just and reasonable rates.Although open access is a requirement in the United States,certain issues have existed in purely bilateral markets that provide insigh

106、ts into the efficiency of these nonmarket balancing authority area(BAA)-to-BAA transactions.3,4 Rate Pancaking:Rate pancaking occurs when wheeling energy across multiple transmission systems and incurring multiple fees to move across different service territories.This process increases transaction c

107、osts and can be a barrier to the use of least-cost generation(Mountain West Transmission Group 2017).Brattle performed a study for the Mountain West Group that estimated$14 million in adjusted production cost savings per year associated with moving from the status quo bilateral market(with rate panc

108、aking)to a bilateral market with a joint transmission tariff(Chang,Pfeifenberger,and Tsoukalis 2016).The same study found moving from a bilateral market to an RTO construct would result in$88 million in annual savings.Trade Friction:Bilateral trading has inherent trade friction that causes inefficie

109、ncies.This friction can include the need to pay brokers or administrative charges,manually arranging trades by phone or other means,and coordinating transmission scheduling with the other utility(Tsoukalis et al.2023).The South Carolina General Assembly commissioned a report from Brattle to assess t

110、he benefits of reforming the states existing electricity sector.One option considered was moving from the status quo of bilateral trading with neighbors to a joint dispatch agreement to facilitate trade among all Carolina utilities.The joint dispatch agreement construct would have one utility coordi

111、nating and automating generator dispatch between utilities in real time(5-and 15-minute increments),using any spare supply and transfer capacity between areas to meet load.The study estimates annual net benefits of moving to a joint dispatch agreement to be$6 million to$11 million per year(Tsoukalis

112、 et al.2023).Limited Real-Time Options:Because of trade friction and issues associated with transmission scheduling,a bilateral trading regime may be inherently limited,especially for addressing real-time operational needs(Federal Energy Regulatory Commission Staff 2013).These areas often have limit

113、ed temporal granularity of scheduling and dispatch(e.g.,hourly only,30-minute),which forestalls opportunities for certain balancing 3 Balancing authority areas are control areas over which a balancing authority is responsible for certain grid-balancing activities such as matching supply and load and

114、 maintaining frequency.Often,electric utilities are balancing authorities over their service territory or BAA.4 There may also be similar inefficiencies in hybrid areas(BAA-to-RTO/ISO).However,many hybrid areas have established joint operating agreements(JOAs)to facilitate sharing of resources,typic

115、ally energy in emergency situations but potentially economic energy sharing.A complete review of the scope of hybrid JOAs was not conducted for this report.The authors also note bilateral contracts and self-scheduled generation are common within RTO/ISO areas,complemented by economic dispatch.7 This

116、 report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.services that may be needed closer to real time(e.g.,15-to-5-minute).Western states initially explored an energy imbalance market as a supplement to bilateral markets,which would provide a vari

117、ety of benefits including automated employment of security-constrained economic dispatch for more efficient balancing services in real time(5-minute)(Federal Energy Regulatory Commission Staff 2013).More Expensive Resources:Bilateral trading requires more generators and other resources to meet the s

118、ame level of reliability and other grid services(Tsoukalis et al.2023).Sharing resources can help lower costs for consumers.Resource sharing groups,pooling,energy imbalance markets,and RTO/ISO markets are all tools that facilitate the sharing of certain resources over a wide geographic area.The Brat

119、tle report from South Carolina found the net benefits of joining a Southeast RTO would range from$115 million to$187 million per year whereas the net benefits of joining the existing PJM RTO would range from$281 million to$362 million per year(Tsoukalis et al.2023).These savings would accrue from mo

120、re efficient operationsfor example,through security-constrained economic dispatch and coordinated schedulingbut approximately 63%to 82%of the total Southeast RTO savings and 55%56%of the total PJM RTO savings would accrue from avoided capital investments.These issues may lead to underutilization of

121、existing transmission capacity or uneconomic trading outcomes.8 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3 Barriers and Opportunities To Realize Transmission Value To understand the reported symptoms of inefficient transmission us

122、e and the implications for the value transmission can provide to the system,we analyzed market,regulatory,and operational practices for transmission operation across the United States.The following sections present the barriers to achieving transmission value that are common across all regions and t

123、hose specific to nonmarket,hybrid,and market regions.For each barrier,we identify the potential source of system valuecapital costs,operating costs,reliability,resiliencythat could be impacted as well as potential options to address the barrier(s).The following symbols are used to indicate each type

124、 of transmission value:Avoided Capital Costs Avoided Operating Costs Improved Reliability Improved Resiliency 3.1 Common Barriers Though there exists a variety of power sector structures across the United States,some operational and regulatory barriers to the efficient use of interregional transmiss

125、ion are common to all interregional transactions,including market,nonmarket,and hybrid(market-to-nonmarket)regions.3.1.1 Absence of Resource Adequacy Sharing Framework Interregional transmission can enable neighboring systems(e.g.,BAAs,RTOs/ISOs)to share energy in emergency situations for reliabilit

126、y or in nonemergency situations to lower costs and can facilitate access to lower-cost capacity for resource adequacy.However,a variety of factors may limit or disincentivize the use of interregional transmission to meet resource adequacy requirements.5 Although each region may take a different appr

127、oach,in general,external capacity resources with firm delivery commitments are considered added capacity resources for purposes 5 It is noted FERC has approved both restrictive approaches to transmission deliverability requirements for capacity resources(e.g.,PJMs pseudo-tie requirement in Docket No

128、.EL17-1138-000)and more permissive transmission deliverability requirements for capacity resources(e.g.,the Western Resource Adequacy Program in Docket Nos.ER22-2762-000 and ER22-2762-001).9 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publication

129、s.of calculating a planning reserve margin whereas firm exports are subtracted(National Association of Regulatory Utility Commissioners 2021;Pfeifenberger et al.2013;Caravallo et al.2023).The resource adequacy treatment of nonfirm intertie benefits,which are not guaranteed or obligated to appear,is

130、less uniformly applied(Pfeifenberger et al.2013).For example,the value of interties for reserve margin calculations may be estimated using a variety of methods including maximum intertie ratings,performing a probabilistic assessment of intertie capability,or adjusting intertie capability based on lo

131、ad diversity across neighboring regions or expected external supply availability(Pfeifenberger et al.2013).In general terms,generation resource adequacy planning responsibility can rest with state regulators or RTOs/ISOs,depending on the jurisdiction(National Association of Regulatory Utility Commis

132、sioners 2023).6 FERC and North American Electric Reliability Corporation(NERC)monitor and report on generation resource adequacy requirements for reliability7 along with the adequacy of transmission resources and many other aspects of reliability service functions(e.g.,operations,planning,interchang

133、e,and so on).NERC-registered resource planners develop resource adequacy plans for their planning areas by incorporating plans from state regulators or RTOs/ISOs and assessing commercial opportunities.NERC balancing authorities are tasked with balancing supply from capacity resources with demand whe

134、reas NERC reliability coordinators assist the balancing authorities in real time,including the ability to curtail interchange if needed.In its annual reliability assessments,NERC considers firm and expected imports/exports and operational risks that could impact reliability(North American Electric R

135、eliability Corporation 2018).One of many factors that may prompt regions to take a conservative approach on the role of interregional transmission in providing resource adequacy benefits is the deliverability uncertainty that may arise between generation and transmission resource adequacy planning a

136、nd actual system operations.6 This generalization excludes federal power marketing agencies and municipal or rural cooperatives.7 In general terms,FERC reviews,approves,and enforces reliability standards developed by NERC.NERC does not develop standards for resource adequacy.10 This report is availa

137、ble at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.1.2 Operating Practices During Extreme Weather Events The ability to improve system reliability during nonstandard operating conditions is often cited as a benefit of interregional transmission(Millstein et a

138、l.2022;Chang,Pfeifenberger,and Hagerty 2013).However,many regions lack operational studies and procedures to maximize the benefits of interregional transmission when these conditions arise.NERC regional entities have raised concerns about the need for interregional transfers during extreme weather e

139、vents,the ability of the transmission system to accommodate these transfers,and the need for increased coordination,operational preparedness,and planning.In its 2023 Summer Reliability Assessment Report,the Southeastern Electric Reliability Corporation(SERC)evaluated the adequacy of resources and tr

140、ansmission to meet the 2023 summer peak and found under normal conditions the region could meet demand with an adequate reserve margin and no transmission concerns(SERC Reliability Corporation 2023).OPPORTUNITIES Deliverability uncertainty may discourage the use of capacity sharing through interregi

141、onal transmission for resource adequacy.To explore the conditions under which greater capacity resource sharing through interregional transmission may occur:NERC can consider supplementing its three existing reserve sharing groups in the operations horizon(i.e.,contingency,frequency response,and reg

142、ulation)1which allow balancing authorities to share resources under specific terms and conditions with guidelines and best practices for resource planners and planning coordinators to share capacity for resource adequacy in the planning horizon.In this context,resource adequacy sharing could include

143、 a generation resource being able to provide capacity in more than one area(without double counting).Willing entities could voluntarily establish a resource adequacy sharing framework,such as the developing Western Resource Adequacy Program(WRAP),that addresses capacity and transmission deliverabili

144、ty requirements for sharing resources between BAAs and/or RTOs/ISOs.For example,FERC has approved WRAPs requirement that participants show they have NERC Priority 6 or 7 firm point-to-point or network integration transmission service necessary to deliver 75%of its forward capacity requirement(with c

145、ertain exceptions).The remaining 25%of required transmission service must be obtained prior to serving obligations in an operating day.FERC believes this approach balances the need to ensure deliverability while providing flexibility to participants.However,because this is a new construct,FERC is re

146、quiring rigorous reporting on the implementation of the forward transmission demonstration and exceptions to monitor and determine the performance of this new framework(FERC 2023).1 Examples of existing NERC reserve sharing programs include Western Power Pools contingency reserve sharing program(Wes

147、tern Power Pool 2023a)and frequency response sharing program(Western Power Pool 2023b).11 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.However,under an extreme weather scenario(i.e.,extreme heat)where 6 gigawatts(GW)of nonfirm power t

148、ransfer would occur from MISO to the SERC East subregion,power flow analysis indicated multiple system violations leading to system collapse in SERCs Central,East,and Southeast subregions as well as the MISO-South subregions(see yellow arrows in Figure 4).SERC concluded the extreme weather scenario

149、with high power transfers highlight the importance of planned coordination and communication among reliability coordinators and BAAs to maintain reliability when large,unplanned power transfers are needed.Figure 4.SERC 2023 Summer Reliability Assessment Transfer impacts from MISO to SERC East where

150、yellow arrows indicate areas of potential system collapse(SERC Reliability Corporation 2023)The Midwest Reliability Organizations 2022 Regional Winter Assessment and 2023 Regional Summer Assessment both pointed to the need for increased transfers from neighboring utilities to maintain reliability in

151、 extreme weather conditions.The Winter Assessment found extreme winter conditions may result in insufficient capacity to meet extreme winter peak;the Summer Assessment found above-normal peak load and unplanned outages could result in MISO and SPP being at high risk for implementing emergency action

152、s and relying on demand response programs and short-term power transfers from neighboring utilities(Midwest Reliability Organization 2023).In addition to congestion at border seams,internal congestion within a system can limit power flows from moving through or out of that system or from moving into

153、 a neighboring system(see Section 3.1.3).During the February 2021 cold snap that impacted Texas and the Midwest,PJM notes it engaged in record levels of interchange,exporting power to MISO and other neighbors with reliability needs(PJM Interconnection 2023a).PJM states congestion management along it

154、s border seams played an important role in enabling power transfers.However,PJM had additional energy available for transfer that could not be exported because of internal congestion(PJM Interconnection 2023a).8 8 Some of these internal constraints during the February 2021 cold snap are detailed in

155、the FERC/NERC/Regional Entity cold weather report(FERC-NERC-Regional Entity Staff 2021).12 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.1.3 Internal Transmission Capacity To Accommodate Large Transfers As the contribution of variabl

156、e renewable energy increases,grid operators may need an expanded set of tools to maintain system reliability.These tools include an increased ability to import and export power to maintain supply/demand balance and reduce curtailments.Although interregional transmission capability to enable imports/

157、exports is often the focus,grid operators may increasingly need to consider internal transmission system sufficiency to accommodate external transfers.OPPORTUNITIES The inability to anticipate,operationally adjust,and solve for atypical constraints that may occur from abnormal flows during large tra

158、nsfer events may unnecessarily limit the value of interregional transmission.To enable transmission systems to accommodate large transfers during extreme events:Neighboring reliability coordinators,BAAs,and transmission operators could perform joint studies on how such transfers may occur.This follo

159、ws recommendations from staff members of FERC,NERC,and certain NERC regional entities after a cold-weather-related bulk power system outage in Texas and South Central United States in February 2021(FERC-NERC-Regional Entity Staff 2021).These studies could include seasonal transfer studies and sensit

160、ivity analyses that model large power transfers to determine where constraints exist that cannot be mitigated(FERC-NERC-Regional Entity Staff 2021).These sensitivity scenarios could include import/export limits during stressed conditions and atypical flow patterns that could occur during extreme wea

161、ther events and incorporate current and potential future conditions.Neighboring systems could collaborate to address potential transmission bottlenecks within regions and ensure a level of import/export capability within individual systems to accommodate large transfers during extreme weather condit

162、ions(PJM Interconnection 2023a).Reliability coordinators,BAAs,and transmission operators could perform system studies to determine if internal networks can accommodate anticipated levels of power flows with neighboring systems during extreme weather conditions.These studies could consider input on t

163、he level of imports and exports estimated from neighboring transmission system operators as well as internal estimations.These studies can be used to develop operator simulator training scenarios and new operating procedures for abnormal,high transfer scenarios and can be incorporated into operator

164、drills 13 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.The Western Electricity Coordinating Councils(WECCs)2022 Assessment of Resource Adequacy report found all WECC subregions currently rely on imports for resource adequacy.Over the

165、next 10 years,each WECC subregion is predicted to see an increase in resource adequacy risk and system variability because of increased variability in demand and energy imports(Western Electricity Coordinating Council 2022,4).9 In addition,the need to ensure sufficient internal transfer capacity to

166、facilitate power exchange is expected to increase in WECC.The California Independent System Operator(CAISO)subsequently found supply imports required to serve load may need to be wheeled through other transmission systems before reaching ISO.This is also an issue for external load-serving entities c

167、urrently reliant on CAISO exports to meet demand.Renewable energy curtailment related to internal transmission constraints is another lens through which to understand this issue.In 2022,there were 4.4 million MWh of wind curtailments in MISO,and over 10 million MWh of wind curtailment in SPP,represe

168、nting 9%of total wind generation in SPP(Wilson 2023).Internal congestion may be an issue if interregional transfer capability is available to the destination system,but internal congestion prevents the movement of resource adequacy resources through the original system.9 WECCs assessment report meas

169、ures resource adequacy risk using a demand-at-risk indicator(DRI)that identifies the number of hours in a year where demand is at risk(i.e.,the potential for load shed).System variability is measured with a planning reserve margin indicator that evaluates the planning reserve margin needed for a spe

170、cific resource portfolio to meet a loss of load probability that should not exceed 2.4 hours in a year.OPPORTUNITIES Internal transmission system constraints may inhibit large power transfers from interregional transmission,leading to resource adequacy concerns.To prepare and plan for levels of impo

171、rts and exports:Multiregion areas such as the Western Interconnection could evaluate both resource and transmission adequacy in a coordinated,wide-area fashion to plan a system that can more effectively manage increased variability(WECC 2022).The NERC Interregional Transfer Capability Study and simi

172、lar evaluations could examine 1)how transfer capacity needs may change as the share of variable renewable energy increases and 2)interventions to mitigate barriers to trade identified in its 2023 report(NERC 2023).Nonmarket areas can explore solutions such as the Western Resource Adequacy Program pr

173、oposed by Western Power Pool that aim to facilitate regional sharing of resource adequacy resources while maintaining the existing bilateral trading regime(Western Power Pool 2023d).Interregional initiatives such as the Western Transmission Expansion Coalition and the Western States Transmission Ini

174、tiative can be used to address the slow pace of regional and interregional transmission development(Western Power Pool 2023c;Gridworks 2023).14 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.2 Barriers Between Nonmarket or Hybrid Area

175、s In nonmarket and hybrid areas,the design of interregional transactions and methods to manage congestion and share information present unique challenges to the efficient use of interregional transmission.3.2.1 Uncoordinated Bilateral Trading Uncoordinated bilateral trading between nonmarket and hyb

176、rid areas(e.g.,market to nonmarket)typically occurs through bilateral contracting processes.Although pragmatic for other reasons,these uncoordinated transactions may lead to inefficient use of interregional transmission capacity,as discussed in depth in Section 2.2.3.These inefficiencies result from

177、 reasons including rate pancaking,friction to trading,limited real-time options,higher resource costs from inability to share,and lack of transparency.Absent ameliorating solutions,trading between nonmarket BAAs or trading between nonmarket BAAs and RTOs/ISOs lacks coordination efficiencies on sever

178、al scales:Reserve sharing for reliability(intrahour),for example,sharing of reserves and intrahour and hourly economic dispatch Resource sharing to lower operational costs(hourly,daily),for example,day-ahead unit commitment and real-time security-constrained economic dispatch Long-term planning to l

179、ower capital costs(multiyear),for example,forward capacity procurement and long-range transmission expansion planning.Improving coordination mechanisms that facilitate trading between nonmarket BAAs and between hybrid areas can improve reliability and resilience and lower consumers costs.15 This rep

180、ort is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.2.2 Congestion Management RTOs/ISOs use security constrained economic dispatch to automatically adjust generation output to manage congestion in real-time operations.Across nonmarket and hybrid a

181、reas where security-constrained economic dispatch is not available,imperfect congestion management can reduce the efficient use of interregional transmission to meet electricity demand at lowest cost.Eastern Interconnection Transmission Loading Relief Across the Eastern Interconnection,transmission

182、loading relief(TLR)procedures are called upon in real-time operations to control flows on overloaded transmission lines that move power from one system to another.10,11 In general,a TLR is used to control congestion on lines between nonmarket areas or lines between a nonmarket area and an RTO/ISO.On

183、ly NERC reliability coordinators can implement TLRs,which represent direct measures of interregional transmission constraints in terms of MW overloading(e.g.,system operating limit or interconnection reliability limit violations).There are various levels of TLRs,with Levels 3a and above resulting 10

184、 For more information,see NERC Reliability Standards IRO-006-5 at https:/ and IRO-006-EAST-2 at https:/ This section explores historical issues with TLRs and does not account for potential implementation of parallel flow visualization(PFV)provisions in FERC Order 676-J(May 20,2021)that have the pote

185、ntial to improve the efficiency of Eastern Interconnection congestion management.OPPORTUNITIES Relying upon bilateral trading may lead to inefficient use of generation and transmission resources to meet system needs.To retain the commercial benefits of bilateral contracts while maximizing the effici

186、ent use of generation and transmission infrastructure:Regions could consider adopting a coordinated scheduling platform where information is exchanged and software programs are used to reduce the time and effort it takes to identify trading partners and improve asset utilization.Examples of coordina

187、ted scheduling include energy imbalance markets,facilitated bilateral exchanges,and dynamic scheduling.Examples of real-time energy imbalance markets include the Western Energy Imbalance Market and Western Energy Imbalance Service.Day-ahead coordination platforms are being developed,such as the Exte

188、nded Day-Ahead Market and the SPP Markets Plus.Such a platform should support long-standing principles espoused by FERC,for example,open-access,transparency,cost competition,and protection against market manipulation.Regions could consolidate nonmarket BAA operations to an RTO/ISO to improve real-ti

189、me and day-ahead scheduling.This could also provide wider-area resource adequacy procurement,regional transmission planning,and independent market monitoring.More information on these options can be found in Balancing Area Coordination:Efficiently Integrating Renewable Energy into the Grid(National

190、Renewable Energy Laboratory 2015).16 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.in curtailment(i.e.,a reduction in transmission service)of previously agreed-upon transmission service.As a result of market reforms and transmission in

191、vestments,the level of TLR relief has steadily decreased over time(Figure 5)(U.S.Department of Energy 2020,1314).Figure 5.Total TLRs(Levels 3,4,and 5)by reliability coordinator(20052018)Source:U.S.Department of Energy(2020)For RTOs/ISOs,TLRs are often called to manage flows related to external nonma

192、rket BAAs,where market-to-market coordination and economic redispatch are not used to manage congestion.In 2022,NYISO had 156,209 MWh of curtailments related to TLR Level 3a and above calls,12 MISO had 29,771 MWh,and PJM had only 299 MWh(Monitoring Analytics,LLC 2023,519).The MISO market monitor not

193、es TLRs called by external entities that result in transaction curtailments create price spikes in MISO that are passed on to MISO consumers with no reimbursement(Potomac Economics 2023c,6970;95).Across the Eastern Interconnection,the Tennessee Valley Authority was associated with the greatest numbe

194、r of TLR calls at Level 3a and higher in 2022.The MISO market monitor estimates generation from the Tennessee Valley Authority could have relieved$63 million in congestion costs from TLR constraints,while Associated Electric Cooperative Inc.generation could have relieved$43 million in TLR-related co

195、ngestions costs(Potomac Economics 2021,73).12 This represents less than 0.1%of NYISOs total forecasted volumes of 156,7000,000 MWh for 2023;see https:/ December 7,2023).17 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Western Interconn

196、ection Qualified Paths Portions of the non-RTO/ISO Western Interconnectionoperated by 38 separate BAAsrely on manual coordination with generators,transmission operators,and neighboring BAAs for congestion management(U.S.Department of Energy 2023,36).In 1995,FERC approved the Unscheduled Flow Mitigat

197、ion Plan(UFMP),which has been revised over time,to manage unscheduled flows among and across BAAs in the Western Interconnection.This plan identifies transmission“qualified paths”that have a history of significant congestion bottlenecks.Phase shifters and other devices,as well as curtailments,are us

198、ed on these qualified paths to mitigate the impacts of unscheduled flows(Southwest Power Pool 2019b).Figure 6.Approximate location of current(yellow)and former(green)qualified paths in the Western Interconnection UFMP Source:WECC(2013)As shown in Figure 6,there are four qualified paths and six quali

199、fied controllable devices(all phase shifting transformers)in the Western Interconnection(Western Electricity Coordinating Council 2013).13 The current qualified paths pose a reliability risk across the region if congestion across multiple parallel paths prevents west-east power transfers.Phase shift

200、ers can be useful to create capacity on parallel paths,but these technologies are best suited for congestion relief with low congestion volatility.As the share of variable renewables increases,these technologies may be a less effective congestion management solution(U.S.Department of Energy 2023,36)

201、.Utilities have expressed interest in qualifying new paths into UFMP but note the challenges 13 See a current list of qualified paths and devices on SPPs website at https:/spp.org/documents/58826/current%20list%20of%20qualified%20devices%20&%20paths_062520.pdf(accessed October 11,2023).18 This repor

202、t is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.associated with meeting the data requirements specified in the UFMP tariff.14 In addition,transmission expansion in the western portion of the interconnection may need to be coupled with upgrades on

203、the eastern portion to ensure reliability because of these unscheduled flows(U.S.Department of Energy 2023,36).Coordinated interconnection-wide transmission planning and market integration could help solve these issues.In the interim,subregions of the interconnection have established their own enhan

204、ced congestion management scheme to minimize local congestion impacts.In 2014,CAISO launched its western energy imbalance market(WEIM)that operates parallel to the UFMP.SPPs western energy imbalance service(WEIS)was launched in 2021 to,among other things,manage congestion within its internal footpri

205、nt.Both WEIS and WEIM interact with UFMP facilities.For example,congestion management within WEIS or WEIM can support scheduled flow that might otherwise be curtailed through the UFMP(CAISO 2022,43).However,WEIM and WEIS primarily manage congestion over real-time transactions.Real-time markets gener

206、ally deal with a much smaller volume of transactions(e.g.,5%),whereas day-ahead markets schedule the majority of market volumes(e.g.,95%).The real-time only approach is simpler to implement,but also leaves opportunities to improve upon bulk power system visibility and congestion management.14 For a

207、brief discussion of the challenges with adding a qualified path,see SPPs Unscheduled Flow Committee meeting minutes of August 15,2023 at https:/www.spp.org/documents/69962/ufc%20meeting%20minutes%2020230815.pdf;for a list of the current path qualification and disqualification requirements,see SPPs W

208、IUFMPs administrative procedure manual at https:/www.spp.org/documents/62012/wiufmp%20administrator%20procedure.pdf.OPPORTUNITIES Imperfect congestion management between nonmarket and hybrid regions can pose reliability risks and reduce the efficient use of interregional transmission to meet electri

209、city demand at lowest cost.To improve congestion management in areas where security-constrained economic dispatch is not available:Regions in the Eastern Interconnection can adopt joint operating agreements with neighboring systems that most frequency call TLRs to specify congestion management solut

210、ions that are more economically efficient(Potomac Economics 2023c,70).The Western Interconnection could explore interconnection-wide integration of the UFMP paths and process into the coordinated scheduling process of WEIM and/or WEIS.This could be accompanied by reevaluating program design to allow

211、 for additional path qualification.The UFMP operational process could be accompanied by a transmission planning process that could help ensure balance between eastern and western transmission upgrades to manage unscheduled flows.19 This report is available at no cost from the National Renewable Ener

212、gy Laboratory at www.nrel.gov/publications.3.2.3 Inconsistent Available Transfer Capability Methods and Assumptions Available transfer capability(ATC)is a measure of the transmission transfer capability available for potential commercial transaction after all committed uses are considered.15 FERC Or

213、der No.890 requires public utilities to calculate their ATC and make these values public through its Open Access Same-Time Information System to give potential third-party customers information about available transmission.16 Order No.890 also requires these public utilities to disclose their method

214、ology,inputs,and assumptions for calculating the ATC in their open access transmission tariff.In Order No.890,FERC found a lack of ATC transparency and consistency throughout the industry created opportunities for undue discrimination and directed NERC and the North American Energy Standards Board(N

215、AESB)to work with industry to develop standard ATC calculation methods,definitions,data inputs,assumptions,and information exchanges to be implemented across the industry.17 Order No.890 also requires neighboring public utility transmission providers to coordinate in calculating and posting ATC valu

216、es for facilities along their borders.18 In 2020,FERC Order No.676-I19 adopted NAESBs Wholesale Electric Quadrant Standards for Business Practices and Communication Protocols for Public Utilities,which includes standards for ATC consistency and transparency and is updated occasionally,most recently

217、in June 2021.Despite these efforts,certain transmission-dependent utilitiesall cooperatives that operate in North Carolina,Texas,or Floridafiled comments in response to FERCs April 2022 Notice of Proposed Rulemaking on regional transmission planning and cost allocation,asserting greater transparency

218、 and consistency is still needed for ATC values posted along neighboring transmission system seams.20 These commenters state they have experienced neighboring transmission service providers posting different ATC values for the same intertie,potentially suggesting these providers are using different

219、methods or assumptions in their ATC calculations.21 These utilities note although Order No.890 required coordination between neighboring transmission systems,it did not require the two neighbors to agree on a single set of ATC values.Similarly,FERC Order No.1000 established interregional transmissio

220、n coordination and cost allocation but did not mandate the use of similar models and input data for transactions across seams.These stakeholders suggest consistency has not been achieved through coordination alone,and if consistency is not possible,greater transparency is needed to enable the detect

221、ion of undue discrimination.15 NERC defines ATC as“A measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses.It is defined as Total Transfer Capability less Existing Transmission Commitments(including ret

222、ail customer service),less a Capacity Benefit Margin,less a Transmission Reliability Margin,plus Postbacks,plus counterflows.”16 Order No.729(2009)and subsequent revisions approved several modeling,data,and analysis reliability standards developed by NERC for calculation of ATC on flowgates.17 Order

223、 No.890,118 FERC 61,119,paragraphs 196,207.18 Order No.890,118 FERC 61,119,paragraphs 327,348.19 FERC Order No.676-I,Standards for Business Practices and Communication Protocols for Public Utilities,available at https:/www.ferc.gov/sites/default/files/2020-08/01-23-2020-E-23.pdf.20 See Notice of Pro

224、posed Rulemaking comments from transmission-dependent utilities in Docket RM21-17-000 located at https:/elibrary.ferc.gov/eLibrary/filedownload?fileid=FF30F745-22F3-C3CF-AA63-82ADA3A00000.21 The commenters also note there could be legitimate reasons for differing ATC values.20 This report is availab

225、le at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.2.4 Wheel-Through Priority for Reliability Imports A key potential benefit of interregional transmission is the ability to increase system resiliency through access to more resources able to respond during eme

226、rgency conditions.Though some RTOs/ISOs have mechanisms in place to set aside transmission transfer capacity needed to serve load in emergency conditions or contingencies(e.g.,capacity benefit margin),otherssuch as CAISOdo not.CAISO manages grid schedules through the day-ahead and real-time markets

227、and offers only one classification of transmission service.If there is insufficient transmission capacity to support intertie transactions,CAISO prioritizes market-based transactions and curtails self-scheduled resources in priority order based on preestablished criteria.And CAISOs transmission plan

228、ning processes do not account or plan for wheel-through transactions other than preexisting firm entitlements.22 During the heat wave on August 14 and 15 of 2020,CAISO operators called on load-serving entities to curtail load.One contributor to this load-shedding event was a large volume of exports

229、scheduled in the day-ahead market that were not part of wheel-through transactions or capacity contracts with internal CAISO resources(CAISO Department of Market Monitoring 2020).WECCS 2020 Western Assessment of Resource Adequacy Report noted absent the ability to import supply to meet demand,all WE

230、CC subregions would have some amount of unserved load over the next 10 years(Western Electricity Coordinating Council 2020).CAISO subsequently found supply imports required to serve load may need to be wheeled through other transmission systems before reaching the ISO.This is also an issue for exter

231、nal load-serving entities currently reliant on CAISO exports to meet demand.Recognizing the need to have mechanisms in place to set aside transmission transfer capacity needed to serve load in emergency conditions or 22 See FERCs Order in Docket ER21-1790 related to CAISOS proposed revisions to its

232、open access transmission tariff on wheeling priorities at https:/ December 21,2023).OPPORTUNITIES Inconsistent ATC values can result in underutilized or oversubscribed transmission lines.To improve communication regarding ATC:Regional or national entities could consider action to require or recommen

233、d neighboring providers agree on a single set of ATC values and/or greater transparency and monitoring of ATC calculations.Neighboring transmission operators could perform joint studies on ATC calculation methods to arrive at a mutually agreed-upon method or,at a minimum,be able to recreate the valu

234、es calculated by neighboring regions using their selected method.21 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.contingencies,CAISO is working to develop a long-term framework to support priority wheel-through scheduling.23 3.3 Barri

235、ers Between Market Areas The barriers to realizing interregional transmission value identified in this section occur between RTO/ISO markets.Joint operating agreements between neighboring RTOs/ISOs identify agreed-upon terms,conditions,and programs for various aspects of interregional coordination.T

236、he following sections explore the efficacy of various programs established in RTO/ISO joint operating agreements,including coordinated transaction scheduling for economic trading(Section 3.3.1),market-to-market coordination for congestion management(Section 3.3.2),and interface flows and pricing(Sec

237、tion 3.3.3).The remaining sections explore merchant HVDC operations and other RTO-specific issues.3.3.1 Coordinated Transaction Scheduling Coordinated transaction scheduling(CTS)refers to procedures for neighboring RTOs to exchange market information and schedule interchange transactions primarily f

238、or economic purposes(e.g.,to lower costs).In theory,CTS should enable interfaces to be more efficiently used.In practice,challenges such as inaccurate price forecasting and high transaction fees undermine the effectiveness of the CTS system.PJM,MISO,and ISO-NE have CTS agreements,but only the CTS be

239、tween NYISO and ISO-NE results in significant participation and production cost savings(Figure 7)(Potomac Economics 2023b,9).The MISO Market Monitoring Unit(MMU)asserts high transaction fees and 23 See the“Transmission service and market scheduling priorities”initiative on the CAISO stakeholder webs

240、ite at https:/ October 10,2023).SOLUTION OPTIONS Regional practices to prioritize market transactions,even during emergency conditions,can reduce system reliability.To ensure system reliability while also preparing anticipated increases in power wheeling among regions:CAISO can change the scheduling

241、 priorities placed on native load relative to self-scheduled exports and wheel-through schedules across the ISO BAAs(CAISO Department of Market Monitoring 2020).CAISO can implement its approved solution to establish wheel-through scheduling priority by calculating ATC in monthly and daily increments

242、,establishing a mechanism to access and reserve ATC,a pathway for entities to request transmission expansion studies and upgrades to accommodate long-term wheel through scheduling priority,a curtailment protocol that considers the scheduling priority and load,and a compensation mechanism for wheel-t

243、hrough priority scheduling(CAISO,2023a).22 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.persistent price forecasting errors likely hinder the use of CTS and push traders toward traditional transaction scheduling(Potomac Economics 2023

244、c,90).24 Figure 7.CTS scheduling and efficiency(20182022)(excludes PCS estimate for MISO/PJM because of low participation)Source:Potomac Economics(2023b)The ISO-NE external MMU attributes the low CTS participation in MISO/PJM and PJM/NYISO to high transaction fees at these interfaces.Though there ar

245、e no significant transmission or uplift charges at the ISO-NE/NYISO interface,the NYISO/PJM interface can see charges ranging from$6$8 per MWh whereas the MISO/PJM interface can see$0.75/MWh reservation charges and an additional$1.75/MWh for cleared quantities.The ISO-NE external MMU also notes tran

246、sactions from PJM to MISO or NYISO incur a smaller charge($1$2/MWh)than transactions in the opposite direction,leading to more activity in the PJM export direction(Potomac Economics 2023b,9).The NYISO MMU notes over a 4-year period(20192022),the average number of price-sensitive bids cleared at the

247、NYISO/ISO-NE interface was 4 times greater than the number of cleared bids at the PJM interface,attributed to higher transaction fees with PJM(Potomac Economics 2023a,125).Poor price forecasting poses another challenge to CTS trading.CTS bids are cleared based on the forecast difference in interface

248、 prices.CTS transactions are scheduled based on the RTO/ISO forecasts of real-time prices,the CTS interface price spreads between markets,and the market participants bids.If the market participants bid is lower than the interface price spread,the transaction is cleared.However,as shown in Table 1,re

249、al-time price differences between RTOs/ISOs can be extremely volatilemaking accurate forecasting and scheduling a challenge(Monitoring Analytics,LLC 2023,504).24 For example,hourly scheduling in 60-minute intervals based on locational marginal prices.23 This report is available at no cost from the N

250、ational Renewable Energy Laboratory at www.nrel.gov/publications.Table 1.Volatility in CTS Interface Price Differences Between Day-Ahead and Real-Time Scheduling(2022)Source:Monitoring Analytics,LLC(2023)CTS Interface Average(Absolute Value)Interval Price Differences($/MWh)Number of Times per Day Pr

251、ice Difference Changes Signs Day-Ahead Real-Time Day-Ahead Real-Time PJM/NYISO 12.94 115.36 3.1 47.9 PJM/MISO 9.09 97.64 4.1 62.9 In the day-ahead markets,the average absolute value of the interval price differences between PJM and NYISO was less than$13 and changed signs(i.e.,from positive to negat

252、ive or vice versa)more than 3 times per day.Between PJM and MISO,the difference was more than$9 and changed signs more than 4 times per day.In the real-time market,the average absolute value of the price difference across PJM/NYISO was over$115 and changed signs almost 48 times per day.Between PJM a

253、nd MISO,the price difference was over$97 and changed signs almost 63 times per day.The increased price volatility in real time highlights the challenge of accurate price forecasting.Because CTS participants bear the risks associated with high price forecast errors,this likely discourages participati

254、on.The ISO-NE external MMU attributes better price forecasting as a factor that facilitated greater participation and savings in the ISO-NE/NYISO CTS compared to the other RTO CTSs shown in Figure 8.The ISO-NE external MMU states ISO-NE uses seven interchange levels to forecast its supply curve wher

255、eas PJM uses only one interchange level for its forecasts(Potomac Economics 2023b,10).Despite the seemingly better performance of the ISO-NE/NYISO CTS,the internal ISO-NE MMU noted in 2022 the average absolute forecast error for the ISO-NE/NYISO CTS increased to$23.87/MWh.This was more than double t

256、he 2021 value($10.78/MWh)and indicates the CTS forecasts became less accurate(ISO-NE Internal Market Monitor 2023,163).25 This leads to inefficient hedging day-ahead and real-time strategies from market participants that inhibit the CTS from adjusting to actual price changes that occur in real timef

257、or example,scheduling in the day-ahead market where there is no forecasting error,then offering low-priced,price-insensitive bids in the real-time market.The NYISO market monitor also notes differences in real-time commitment and real-time dispatch prices indicate the commitment scheduling decisions

258、(for external resources and fast-start units with lead times of 15 minutes to 1 hour)may be inefficient(Potomac Economics 2023a,127).In an optimal system,when prices between market areas are different,power would flow from the lower-priced area to the higher-priced area until prices converge or a ph

259、ysical constraint is hit(e.g.,ramp or total transfer capacity limit).As shown in Figure 3(Section 2.2.2),the ISO-25 The ISO-NEs Internal Market Monitor 2021 Annual Markets Report noted the average absolute forecast error for the CTS increased from$6.34/MWh in 2020 to$10.78/MWh in 2021.See the 2021 A

260、nnual Markets Report at https:/www.iso- March 20,2024).24 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.NE/NYISO CTS does not operate optimally.For example,in 6%of the periods when there was a$50$100/MWh price difference,there was on a

261、verage about 200 MW of unused interface capacity between ISO-NE and NYISO(ISO-NE Internal Market Monitor 2023).The CTS processes have been criticized by market monitors for a least a decade,with several calling for the replacement of the CTS with intertie optimization(Johannes Pfeifenberger et al.20

262、23,8).Though existing CTS processes could be improved,the absence of a CTS is suboptimal.Reviewing historical prices differences along the SPP/MISO seam,the SPP MMU estimated intermarket inefficiency to be worth$9.4 million to$11.2 million,and a portion of this could be captured by establishing a CT

263、S along this seam(SPP Market Monitoring Unit 2020).3.3.2 Market-to-Market Congestion Coordination RTOs/ISOs in the Eastern Interconnection generally use TLR and market-to-market(M2M)coordination to manage interregional congestion.26 M2M congestion management programs allow RTOs/ISOs to jointly and c

264、ost-effectively manage transmission interties that can be impacted by the operation of both neighboring systems.This section explores M2M implementation issues between PJM and MISO and between MISO and SPP.26 This section does not explore changes or improvements to congestion management programs tha

265、t could occur through potential implementation of PFV provisions through FERC Order 676-J(May 20,2021).OPPORTUNITIES Uncertain price forecasting,high transaction fees,and other issues have limited the ability of CTS to efficiently use interregional transmission.To improve interregional transaction s

266、cheduling:Regions could reduce or eliminate CTS transaction fees and charges(Potomac Economics 2023b,10).Reducing the time interval for interchange adjustments based on real-time prices could improve price forecasting(Potomac Economics 2023b,10).The MISO MMU estimates moving to a 5-minute CTS with P

267、JM would have achieved over$40 million in production cost savings versus the actual$3 million achieved through the current process and$56 million in production cost savings by switching to a 5-minute CTS with SPP(Potomac Economics 2023c,92).The ISO-NE internal MMU believes price forecasting error is

268、 unlikely to be completely eliminated and therefore changes to the CTS mechanism or settlement process could be pursued to better incentivize cost-based offers(ISO-NE Internal Market Monitor 2023,167).Replacing the CTS with an interchange optimization solution could also be considered(Monitoring Ana

269、lytics,LLC 2023,61).25 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.MISO/PJM M2M:Firm Flow Entitlements Under the PJM/MISO joint operating agreement,the RTOs jointly identify a portfolio of transmission facilities that impact both sys

270、tems,then jointly operate these facilities.These jointly controlled facilities are called M2M flowgates.As of 2022,PJM had 197 flowgates eligible for M2M coordination,and MISO has 144(Monitoring Analytics,LLC 2023,515).PJM and MISO conduct a variety of studies to determine which flowgates they will

271、monitor and control.27 Flows along some of these facilities are limited based on 2004-era historic flows each RTO created on each flowgate,known as firm flow entitlements(FFEs)that are used in the settlement process.The FFE is the amount of flow each RTO is allowed to create on a facility before inc

272、urring redispatch costs based on the M2M process rules.If the RTO monitoring the intertie exceeds FFE flows in the real-time market(plus MW allowances from day-ahead coordination),the monitoring RTO must pay the nonmonitoring RTO and vice versa.One critique of this arrangement is FFEs based on 2004-

273、era flows may not be appropriate for current operating conditions,leading to inefficient limits on M2M flowgates and excess payments from RTOs for violations.Figure 8 shows the management payments of each RTO related to M2M flowgate,with the spike in December 2022 related to Winter Storm Elliot(Moni

274、toring Analytics,LLC 2023,516).The MMU notes the RTOs and stakeholders recognize a modification to the freeze date model is needed and have been working on solutions for many years with no resolution(Monitoring Analytics,LLC 2023).Figure 8.PJM/MISO credits for coordinated congestion management,Jan 2

275、021Dec 2022 Source:Monitoring Analytics,LLC(2023)27 A reciprocal coordinate flowgate is a flowgate that both PJM and MISO systems can impact,is controlled by either PJM or MISO,and is subject to M2M congestion management(e.g.,transmission load relief).26 This report is available at no cost from the

276、National Renewable Energy Laboratory at www.nrel.gov/publications.Similar M2M coordinate flowgate management agreements are in place through the PJM/NYISO joint operating agreement,but this process relies on real-time market coordination and actual flows.This results in a more efficient process and,

277、in 2022,there was no exchange of payments related to congestion management(Monitoring Analytics,LLC 2023,517).28 The PJM/NYISO joint operating agreement also includes an M2M process with entitlements for settlement purposes but,unlike the entitlement between PJM and MISO,these M2M entitlements on fl

278、owgates are calculated and compared at least once per yearunless there is mutual agreement not to recalculate in a given year.29 MISO/SPP M2M:Constraint Modeling Issues The joint operating agreement between MISO and SPP requires each organization to model the others M2M constraints in their day-ahea

279、d markets.In 2020,the MISO and SPP market monitors jointly conducted a series of seams studies for the Organization of MISO States and the SPP Regional State Committee,including a study on M2M coordination(Potomac Economics 2020a).Among other issues identified,the market monitors analysis found SPP

280、was either not modeling MISOs M2M constraints in the day-ahead market or modeling them in a way that prevents them from binding.This would cause SPP to inefficiently commit resources and increase costs to both regions(but more so to SPP)through M2M settlements.The MISO MMU found SPP congestion balan

281、cing costs to be consistently positive and 3 times greater than MISO costs,totaling$180 million over a 2-year period(Potomac Economics 2020a,23).In 2022,SPP began a process to activate MISO M2M constraints in the day-ahead market.30 SPP staff expressed concern that activating the MISO M2M constraint

282、s in the day-ahead market would exacerbate transmission congestion rights(TCR)underfunding(Southwest Power Pool Market Monitoring Unit 2023,246).28 The PJM/NYISO agreement also allows for joint operation of phase angle regulators(PARs)for flowgates at the seams,which in 2022 resulted in some exchang

283、e of PAR credit payments between the RTOs for congestion management.29 See Section 6 of Schedule D(Market-to-Market Coordination Process)of the PJM/NYISO joint operating agreement located on the PJM website at https:/ February 6,2024).30 SIR75 Market-to-Market Improvements https:/spp.org/search?q=%2

284、2SIR75%22&t=Documents(accessed August 11,2023).27 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.3.3 Interface Flows and Pricing This section explores issues related to physical locations where power flows are scheduled and the locati

285、on where power transactions are priced.Flawed interface pricing can lead to operational inefficiencies such as loop flows and economic inefficiencies such as redundant charges.This section will draw from examples in PJM and MISO to illustrate these issues.PJM Physical and Pricing Interfaces A physic

286、al interface is an interconnection point between neighboring BAAs where imports or exports can be scheduled to flow.An interface pricing point determines the price assigned to the import or export transaction and is based on the actual physical path through which the energy flows.Market participants

287、 designate a scheduled path from generator(source)to load(sink)based on transmission reservations(e.g.,considering transmission availability and cost)and identify this path on the NERC electronic tag.31 However,because electricity flows on the path 31 NERCs electronic tagging requirements for interc

288、hange transactions are generally described in standards INT-006-5(Evaluation of Interchange Transactions)https:/ Inefficient congestion management through outdated flow limits or inaccurate modeling can result in inefficient transmission use and excessive congestion balancing costs.To improve interr

289、egional congestion management:The FFEs between MISO and PJM could be updated to reflect the current capability of the system as recommended by the PJM MMU.The PJM MMU asserts FERC could set a deadline for resolution to establish new FFEs if existing stakeholder consultations cannot reach a solution(

290、Monitoring Analytics,LLC 2023,516).MISO and SPP could implement improved testing criteria for identifying M2M constraints for joint management,automate certain manual procedures for identifying and managing constraints,enhance software for short-and long-term relief requests,and model neighboring RT

291、O constraints based on joint recommendations from the MISO and SPP MMUs(Potomac Economics 2020a).The MMUs identified$35 million in reduced annual congestion costs by automating processes to identify and activate constraints.In addition,the MMU-recommended software improvements to optimize the amount

292、 of relief requested on M2M constraints could result in$32 million of annual congestion benefits and$4 million in annual production cost savings.Within SPP,ongoing efforts to align day-ahead and real-time congestion along the SPP/MISO seam along with modifying the transmission congestion rights fund

293、ing model could reduce congestion payments and alleviate concerns about TCR underfunding(Southwest Power Pool Market Monitoring Unit 2023,246).28 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.of least resistance,the designated schedule

294、d path through which the transaction is priced may diverge from the actual flow.According to the PJM MMU,there are several issues with the current interface pricing scheme(Monitoring Analytics,LLC 2023,Sec.9).First,the interfacing pricing points for all transactions with the Western Interconnection

295、are assigned to one of two pricing points(MISO or SOUTH),based on geography rather than electrical impact.The interface prices are supposed to include weighting factors that are dynamically adjusted to reflect systems conditions.However,the weights are in fact static and modified only on occasion.32

296、 Therefore,interface prices do not reflect actual system conditions.A second issue is related to how PJM treats noncontiguous interface pricing points.For example,although there is no physical intertie between PJM and the Ontario Independent Electricity System Operator(IESO),PJM created the Independ

297、ent Electricity Market Operator(IMO)interface pricing point to reflect the fact that transactions to or from the IESO balancing authority result in actual flows split between MISO and NYISO interface pricing points.Issues with interface pricing have led to problems related to loop flows and concerns

298、 over sham scheduling within PJM.Loop flows are the difference between actual and scheduled power flows at an interface point and are a concern because they negatively impact LMP-based market efficiency,financial transmission rights revenue adequacy,and system operations.In 2022,PJM experienced 153

299、gigawatt-hours(GWh)of loop flows,less than 1%of total scheduled flows.However,some individual interfaces experiences very high inadvertent flows.The Northern Indiana Public Service interface experienced flows more than 16 times the scheduled amount(Monitoring Analytics,LLC 2023).NERC tags require ma

300、rket participants to specify the complete transmission path from source to sink for transactions.According to the PJM MMU,market participants do not always include complete path information on the NERC tags.Sham scheduling is a method of scheduling where the market participant breaks a single transa

301、ction into multiple transactions to hide the true generation source for financial gain(Monitoring Analytics,LLC 2023,522).For example,independent of the scheduled path,a transaction sourcing in NYISO and sinking in PJM would be priced in the energy market at the PJM/NYISO interface pricing point.A m

302、arket participant could break the transaction into two segments,one from the NYISO/Ontario path and a second from the Ontario/MISO/PJM path.The origin of the transaction would be concealed,and PJM would price the transaction at the IMO interface pricing point.Sham scheduling could also occur by subm

303、itting transactions in opposing directions for portions of the larger transaction to take advantage of higher prices in a given direction without impacting actual power flows.MISO Interface Pricing Interface pricing in MISO includes a system marginal price,a marginal transmission loss component,and

304、a congestion component.When an M2M constraint binds,both RTOs price and settle with external transactions based on their respective estimates of the entire congestion effects of the transaction,resulting in a rough doubling of the congestion settlement(Potomac 5.pdf and INT-009-3(Implementation of I

305、nterchange)https:/ PJM began applying dynamic weighting factor to the Ontario pricing point in June 2015.29 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.Economics 2023c,94).In response to redundant congestion pricing,MISO and PJM impl

306、emented a“common interface”definition in 2017 that included 10 generator locations near the MISO/PJM seam with 5 in MISO and 5 in PJM.This method assumes power sources and sinks at specific buses along the seam border.In reality,the systems marginal generators are not always located at seam buses bu

307、t are located throughout the RTO area.For example,lower-priced marginal generators can ramp up in the source RTO area and provide power to export whereas higher-priced marginal generators throughout the sink area would ramp down.The MISO MMU found the common interface method exaggerates the effects

308、of import and export flows on constraints at the seam,resulting in larger average price errors and volatility at the interface(Potomac Economics 2023c,93).MISO and SPP do not use the“common interface”definition and are still redundantly pricing congestion(Potomac Economics 2023c,94).The MISO MMU has

309、 estimated this approximately doubles the congestion costs from the efficient level.This results in poor incentives for participants to schedule interchanges when M2M constraints are binding.The MISO MMU estimated of the time periods with M2M binding constraints,60%of the time congestion costs were

310、within$1 of the efficient level(i.e.,the price that does not redundantly price congestion),11%of the time they were overstated by more than$5,and in the remaining 29%of the time the congestion costs were more than$5 above the efficient level(Potomac Economics 2020b,9).This method also raises costs f

311、or the RTOs.Costs increase,for example,when both RTOs are paying$10/MWh for congestion relief($20/MWh in total).The nonmonitoring RTO would receive congestion relief valued at$10/MWh,and the monitoring RTO would revise dispatch and pay generation resources for congestion relief at an expected value

312、of$10/MWh.However,the monitoring RTO has no M2M mechanism to recover these costs and is likely to charge to load as uplift.The MISO MMU estimated the cost of these excess payments and charges was over$7.5 million from 2018 to 2019(Potomac Economics 2020b,11).30 This report is available at no cost fr

313、om the National Renewable Energy Laboratory at www.nrel.gov/publications.OPPORTUNITIES Issues with interface pricing can lead to operational inefficiencies such as loop flows,economic inefficiencies such as redundant charges,and opportunities for market manipulation through sham scheduling.To improv

314、e interface pricing:A validation method for submitted transactions that requires market participants to submit transactions on paths of expected actual power flow to reduce unscheduled loop flows could be implemented(Monitoring Analytics,LLC 2023).To reduce sham scheduling,a validation method for su

315、bmitted transactions that prohibits breaking transactions into smaller segments to conceal the true source or sink alongside after-the-fact market settlement adjustments to identified sham scheduling segments could be implemented(Monitoring Analytics,LLC 2023).Transactions sourcing in the Western In

316、terconnection could be priced at either the MISO or SOUTH interface pricing points based on the locational price impact of the DC tie line flows on the PJM system,not based on geography.For other interfaces,PJM could monitor and adjust weights applied to interface pricing points to reflect ongoing c

317、hanges to system conditions and review the mappings of external balancing authorities to interface pricing points to reflect changes to external power source impacts on PJM intertie lines because of system topology changes(Monitoring Analytics,LLC 2023).PJM could consider eliminating the IMO interfa

318、ce pricing point and instead assign all transactions sourcing or sinking in IESO to the PJM/MISO interface pricing point(Monitoring Analytics,LLC 2023).For interface pricing issues between MISO and PJM,the MISO MMU recommends ending the use of the common interface definition at the MISO/PJM seam(Pot

319、omac Economics 2023c).To prevent redundant congestion pricing,the MISO MMU suggests the M2M constraints modeled by the RTOs(PJM,SPP,MISO)be included only in the monitoring RTOs interface pricing(Potomac Economics 2023c,95).The MISO MMU suggests removing congestion caused by external constraints from

320、 prices at interfaces(Potomac Economics 2023c,95).31 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.3.4 Market Co-Optimization of Merchant Interregional HVDC Line Interregional transmission projects are often privately funded and use

321、controllable HVDC technology.These privately funded merchant transmission lines have FERC-approved market-based rates or negotiated rates recovered from subscribing customers rather than cost-based rates recovered by public utility ratepayers.FERC requires unused capacity on merchant lines to be mad

322、e available to third parties and has encouragedbut does not requireunused capacity to be made available to RTO/ISO market operators for integrating into the operators system and co-optimizing in wholesale markets.Optimizing this interregional transmission capacity could improve the efficiency of int

323、ertie transactions and maximize interregional transmission value.However,market optimization of HVDC lines is not common within markets,let alone between markets.CAISO is the only U.S.RTO/ISO that co-optimizes HVDC transmission and generation dispatch in nodal day-ahead and real-time markets(Pfeifen

324、berger,Bai,and Levitt 2023,132).NYISO is revising energy and capacity market design to implement optimization of these controllable lines,33 while MISO is planning on developing this capability between 2027 and 2031(MISO 2021,29).NTP Study modeling shows investments in HVDC transmission additions ou

325、tpace investments in AC additions to cost-effectively reach national targets.Market reforms to promote the efficient use of these facilities can ensure the benefits of HVDC transmission can be realized.33 See NYISOs“Internal Controllable Lines:2023 Kickoff,”February 21,2023,at https:/ December 28,20

326、23),and“Internal Controllable Lines:Market Design Concept Proposal,”August 4,2022,at https:/ December 28,2023).OPPORTUNITIES Controllable HVDC lines could provide valuable interregional transmission capacity to deliver energy,capacity,and environmental benefits.To maximize the use of these facilitie

327、s:Regions could explore market reforms to allow developers of merchant HVDC lines to place operational control of their lines with regional market operators.CAISOs subscriber participating transmission owner(SPTO)model,recently approved by FERC,could serve as a useful model.Under the SPTO model,CAIS

328、O will be able to use unscheduled merchant transmission capacity for regional and interregional transactions in the day-ahead and real-time regional and interregional markets.CAISO would pay the merchant line owner for any nonsubscriber usage of released unscheduled capacity,collected from the trans

329、mission access charges allocated to load,imports,and exports(CAISO 2023b).See FERCs approving order at 186 FERC 61,177 in Docket No.ER23-2917-001.32 This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.3.3.5 RTO-Specific Issues Some RTOs/ISOs

330、 have implemented specific technologies,practices,and operating rules that limit the efficient use of transmission.This section summarizes these RTO-specific issues.Nonoptimized Phase Angle Regulators Phase angle regulators(PARs)can be used to adjust the phase angle difference between two parallel c

331、onnected electricity transmission systems.This can control the amount of power flowing across these parallel paths,which can help manage congestion.PJM and NYISO have installed PARs on some of their interconnected lines to improve power flows and price signals between their systems.34 In the day-ahe

332、ad time frame,PARs have improved operational efficiency,resulting in$111 million in system savings in 2022(Potomac Economics 2023a).However,operational improvements in real time have been limited because of a lack of coordination between real-time dispatch from the system operator and the PAR adjust

333、ments.The lack of information on expected PAR adjustments can lead to situations where real-time commitments are adjusted to solve congestion issues that were going to be resolved through PAR adjustments at real-time dispatch.Poor PAR coordination is estimated to cause 15%of the price divergence between real-time commitment and dispatch prices(Potomac Economics 2023a).Capacity Pay-for-Performance