Federal Energy Regulatory Commission | October 2017
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2017 Transmission Metrics

STAFF REPORT

Federal Energy Regulatory Commission

October 6, 2017

The opinions and views expressed in this staff report do not necessarily represent those of the 

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

binding on the Commission.
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TABLE OF CONTENTS

Executive Summary ........................................................................................................................ 3

Introduction ................................................................................................................................... 6

I. Metrics to Assess Participation of Nonincumbent Transmission Developers in Regional 

Transmission Planning Processes ................................................................................................ 8

− Percentage of Nonincumbent Transmission Project Bids or Proposals............................. 9

− Number of Unique Developers Submitting Proposals...................................................... 21

− Number and Percentage of Selected Nonincumbent Proposals...................................... 23

− Stakeholder Participation in Regional Transmission Planning Processes......................... 27

II. Metric to Indicate Whether Appropriate Levels of Transmission Infrastructure Exist ............ 34

− RTO/ISO Market Price Differential.................................................................................... 34

III. Metrics to Permit Baseline Analyses of the Impacts of Policy Changes ................................. 42

− Load-Weighted Transmission Investment (Incremental)................................................. 43

− Load-Weighted Circuit-Miles (Incremental) ..................................................................... 47

− Load-Weighted Circuit-Miles per Million Dollars of Investment...................................... 49

IV. Conclusion................................................................................................................................ 52

ACKNOWLEDGEMENTS

Federal Energy Regulatory Commission Staff Team

Rahim Amerkhail

Gregory Price

Danielle Gordon

Jennifer Fletcher

Peter Nagler
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Executive Summary

In 2016, Federal Energy Regulatory Commission (Commission) staff developed several metrics 

that assessed transmission investment patterns to inform whether additional Commission 

action would be necessary to facilitate more efficient or cost-effective transmission development 

in the United States (U.S.) that is sufficient to satisfy the nation’s transmission needs.

Commission staff published its initial report (2016 Report),

1 with the analysis and findings, in 

March 2016 and presented the results at the April 2016 Commission meeting.

In this report (2017 Report), staff presents updated results for all but one2 of the metrics 

included in the 2016 Report, as well as initial results for several new metrics. Like the 2016

Report, this iteration explains the data and methods that staff used to calculate each metric. 

Then, the report presents the results for each metric and staff’s inferences based on the 

calculated metrics. When discussing the metrics to assess the participation of nonincumbent 

transmission developers in the regional transmission planning processes, the 2017 Report 

focuses on only those transmission planning regions that have conducted at least one 

competitive proposal window.

3

 To date, these include only five transmission planning regions, 

all of which are RTOs/ISOs. With the exception of the RTO/ISO market price differential 

metric, all of the other metrics include data from all transmission planning regions. 

 1 See Transmission Metrics: Initial Results, AD15-12-000, Federal Energy Regulatory Commission (March 2016), 

https://www.ferc.gov/legal/staff-reports/2016/03-17-16-report.pdf. 2 The metric on load-weighted curtailment frequency was not included in the 2017 Report, and the reason for this 

omission is discussed below.

3 For convenience, we use the term proposal window to represent the opportunity that a transmission planning 

region provides for transmission developers to submit proposals in response to transmission needs or to be selected 

to use the regional cost allocation method for a specific transmission project.
4

Key new findings in the 2017 Report include:

Transmission Investment Metrics

Metric New Findings in the 2017 Report

Metrics to Assess Participation of Nonincumbent Transmission

Developers in Regional Transmission Planning Processes

Percentage of 

Nonincumbent4

Transmission Project Bids 

or Proposals

• PJM Interconnection, L.L.C. (PJM) held five new competitive 

proposal windows in 2015 and 2016, with nonincumbents 

submitting 46 percent of the proposals received between 2013 

and 2016.

• For its first two proposal windows, New York Independent System 

Operator (NYISO) received more proposals from nonincumbents

than incumbents in 2015, but the reverse was true in 2016.

• Nonincumbents submitted the majority of proposals in response 

to Midcontinent Independent System Operator’s (MISO) first 

proposal window in 2016. 

Number of Unique 

Developers5 Submitting 

Proposals (New Metric 

for 2017 Report)

• The number of unique developers submitting proposals in PJM

was comparatively low compared to the total number of 

proposals received.

• In California Independent System Operator (CAISO), NYISO, and 

MISO, unique developers submitted roughly one proposal each.

Number and Percentage 

of Selected

Nonincumbent Proposals

(New Metric for 2017 

Report)

• For all of the transmission planning regions that had competitive 

proposal windows, the percentage of selected proposals that 

nonincumbents submitted declined from 20 percent in 2013, to 6 

percent in 2014, to 3 percent in 2015, and to zero in 2016.

• CAISO had the largest increase in nonincumbents’ share of 

selected proposals between 2013 and 2015.

 4 Order No. 1000 defines a “nonincumbent transmission developer” as either: (1) a transmission developer that does 

not have a retail distribution service territory or footprint; or (2) a public utility transmission provider that 

proposes a transmission project outside of its existing retail distribution service territory or footprint, where it is 

not the incumbent for purposes of that project. By contrast, an “incumbent transmission developer/provider” is 

defined as an entity that develops a transmission project within its own retail distribution service territory or 

footprint. See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 

Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 225 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, 

order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. 

FERC, 762 F.3d 41 (D.C. Cir. 2014).

5 A unique developer is defined as an entity that is distinct from other transmission developers in terms of the 

proposals submitted to a transmission planning region in a given year. In instances where a transmission developer 

submits multiple proposals in a given year, staff considers that transmission developer only once for that year. A 

unique developer can include an incumbent transmission developer, a nonincumbent transmission developer, a 

consortium (where a group of transmission developers operates as a separate legal entity), or a joint venture where 

two or more legal entities (either incumbent or nonincumbent) work together to develop a proposal while 

maintaining their own legal status. Furthermore, a given transmission developer that submits proposals 

independently is considered distinct from a consortium or joint venture in which that entity is involved. The 

purpose of this metric is to determine how many distinct developers are submitting proposals (i.e., Are a few 

transmission developers submitting most of the proposals in a given transmission planning region or are many 

different transmission developers submitting proposals?).

Chart continued next page
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• PJM selected the largest number of proposals overall compared 

to other transmission planning regions, but it selected only one

nonincumbent proposal over four years.

• Southwest Power Pool (SPP) and MISO each selected an 

incumbent proposal in their single proposal windows in 2015 and 

2016, respectively.

Stakeholder Participation 

in Regional Transmission 

Planning Processes (New 

Metric for 2017 Report)

Stakeholder attendance at regional transmission planning process 

meetings during fiscal year 2015 (FY 2015) and fiscal year 2016 (FY 2016)

was relatively stable in both RTOs and non-RTOs.

Nonincumbents are participating in stakeholder meetings in most 

transmission planning regions, with their participation increasing in four 

of the 12 regions.

Metric to Indicate Whether Appropriate Levels of Transmission Infrastructure Exist

RTO/ISO Market Price 

Differential

Relatively high or low real-time locational marginal prices (LMPs) 

occurred persistently (i.e., for at least two years) at 1,482 generator or 

load points since 2005, a decline from 1,986 points in the 2016 Report.

Many of the high-priced points and low-priced points disappeared in SPP.

Metrics to Permit Baseline Analyses of the Impacts of Policy Changes

Load-weighted 

Transmission Investment 

(Incremental)

Load-weighted transmission investment averaged $2.43 per megawatt 

hour (MWh) of retail load for all North American Electric Reliability 

Corporation (NERC) regions between 2008 and 2015, up from a load 

weighted average of $2.19 per MWh of retail load between 2008 and 

2014 in the 2016 Report.

Load-weighted CircuitMiles (Incremental)Load-weighted circuit-miles remained unchanged from the 2016 Report 

at 1.9 circuit-miles per terawatt hour (TWh) across all NERC regions 

between 2008 and 2015.

Load-Weighted CircuitMiles per Million Dollars 

of Investment 

(Incremental)6

The average load-weighted circuit-miles per million dollars of investment 

decreased slightly between the 2016 Report and the 2017 Report by 0.1

load-weighted circuit-miles per million dollars of transmission investment 

for all NERC regions.

Midwest Reliability Organization (MRO) fell from the NERC region with 

the highest load-weighted circuit-miles per million dollars of investment 

in the 2016 Report to the region with the sixth highest load-weighted 

circuit-miles per million dollars of investment in the 2017 Report. 

 6 The metric addressing load-weighted circuit-miles per million dollars of investment (incremental) aims to provide 

a basis for assessing the cost impact of different policy choices or factual circumstances on transmission investment. 

Weighting the transmission circuit miles by million dollars of investment in each NERC region allows for 

comparison between regions of different sizes.
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Introduction

The Commission has long had the goal of ensuring that its policies help achieve appropriate 

levels of transmission investment to address current and emerging reliability needs, economic 

considerations, and transmission needs driven by public policy requirements while maintaining 

just and reasonable rates, as required under the Federal Power Act. Most recently, the 

Commission reformed its policies regarding transmission planning and cost allocation in Order 

No. 1000, through which it sought to promote more efficient or cost-effective transmission 

development by requiring each public utility to, among other things, (1) participate in regional 

transmission planning processes, (2) provide opportunities for nonincumbent transmission 

developers to propose and develop regional transmission facilities through competitive 

transmission development processes,7 and (3) establish a regional cost allocation method to 

allocate the costs of transmission facilities selected in the regional transmission plan for 

purposes of cost allocation (i.e., regional transmission facilities).

As noted in the 2016 Report, it is difficult to assess whether the electric industry is investing in 

sufficient transmission infrastructure to meet the nation’s needs and whether the investments 

made are more efficient or cost-effective.8 Nevertheless, staff has attempted to develop a range 

of objective and standardized measures of various characteristics of the electric system and its 

performance to help assess the effectiveness of the Commission’s policies in achieving its goals 

regarding transmission investment and to inform potential policy revisions going forward. As in 

the 2016 Report, the metrics in this report fall into three broad categories: (1) metrics designed 

to evaluate key goals of Order No. 1000; (2) metrics designed to indicate whether appropriate 

levels of transmission infrastructure exist in a particular region; and (3) metrics designed to 

permit analysis of the impact of Commission policy changes by comparing key values before and 

after changes take place.

When preparing the 2017 Report, staff considered whether additional metrics could further help 

staff to assess the effectiveness of the Commission’s policies and better inform potential policy 

revisions going forward. As a result of its analysis, staff identified three additional metrics: (1) 

number of unique developers submitting proposals; (2) number and percentage of selected 

nonincumbent proposals; and (3) stakeholder participation in regional transmission planning 

 7 We refer to the process to select transmission facilities in the regional transmission plan for purposes of cost 

allocation and the process to provide a transmission developer of a selected transmission facility with eligibility to 

use the regional cost allocation method collectively as the competitive transmission development process. See

Supplemental Notice of Technical Conference and Request for Speakers, Docket No. AD16-18-000, at 8-9 (May 10, 

2016). 

8 Potential reasons for this difficulty include, but may not be limited to:

• Stakeholders cannot agree on what would constitute an appropriate amount of transmission 

investment. For example, some stakeholders may prefer a system that prioritizes public policy concerns, 

while others may prefer a system that prioritizes reliability. Similarly, some may expect strong load 

growth or the development of distributed generation, while others may not.

• There are alternatives to transmission in some circumstances. Some transmission issues can be 

addressed using alternatives to transmission investments, such as generation or demand-side resources, 

while other issues can only be addressed with transmission investment.
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processes. A unique developer is defined as an entity that is distinct from other transmission 

developers in terms of the proposals submitted to a transmission planning region in a given year. 

In instances where a transmission developer submits multiple proposals in a given year, staff 

considers that transmission developer only once for that year. A unique developer can include 

an incumbent transmission developer; a nonincumbent transmission developer; a consortium 

(where a group of transmission developers operates as a separate legal entity), or a joint venture 

where two or more legal entities (either incumbent or nonincumbent) work together to develop 

a proposal while maintaining their own legal status. Furthermore, a given transmission 

developer that submits proposals independently is considered distinct from a consortium or 

joint venture in which that entity is involved. Staff concludes that these three new metrics will 

help the Commission to evaluate progress in achieving the key goals of Order No. 1000, as they 

assess the level of competition in transmission development processes by measuring

nonincumbent participation, as well as stakeholder engagement in these processes. 

Staff also notes the exclusion of the load-weighted curtailment frequency metric, under the 

second broad category of metrics, from the 2017 Report. Staff initially hoped to use the metric to 

gauge congestion in areas outside of organized wholesale electric markets. However, upon 

further analysis, staff found that the caveats associated with the metric calculation, as detailed 

in the 2016 Report,9 significantly limited the insights that it could provide. In particular, the 

metric applied only to the Eastern Interconnection and served to identify congestion between 

two organized wholesale electric markets or between organized wholesale electric markets and 

neighboring regions rather than identifying congestion within regions outside of the organized 

wholesale electric markets. Staff continues to consider other metrics to include in future reports 

that could better assess congestion outside of organized wholesale electric markets.

Below, staff describes the methodology for calculating each of the three categories of metrics, the 

results of staff’s analyses, and the further research that staff believes is needed to help ensure 

that each metric provides useful insight as to whether transmission investment in the U.S. is 

both more efficient or cost-effective and yields sufficient transmission infrastructure to meet 

future reliability needs, economic considerations, and transmission needs driven by public 

policy requirements.

 9 See Transmission Metrics: Initial Results, AD15-12-000, Federal Energy Regulatory Commission (March 2016), 

https://www.ferc.gov/legal/staff-reports/2016/03-17-16-report.pdf.
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I. Metrics to Assess Participation of Nonincumbent 

Transmission Developers in Regional Transmission Planning 

Processes

Transmission planning regions have adopted one of two types of competitive transmission 

development processes to comply with Order No. 1000’s requirements: a competitive bidding 

model or a sponsorship model.10 Under the competitive bidding model, the transmission 

planning region, with stakeholder input, identifies regional transmission needs and selects the 

more efficient or cost-effective transmission solutions to meet those needs. The transmission 

planning region then solicits proposals from qualified transmission developers (both incumbent 

and nonincumbent) for the transmission solutions it selected that are eligible for the 

competitive bidding process. The transmission planning region chooses from among the 

developers and designates a winning transmission developer as eligible to use the regional cost 

allocation method to develop the selected transmission project. Relevant to this report, CAISO, 

MISO, and SPP have adopted this model.

Under a sponsorship model, the transmission planning region, with stakeholder input, identifies 

regional transmission needs. Then, qualified transmission developers (both incumbent and 

nonincumbent) may propose transmission projects to meet those identified regional 

transmission needs. The transmission planning regions selects the more efficient or costeffective transmission solution to meet each identified regional transmission need, which can be 

a solution proposed by a transmission developer or one that the transmission planning region 

designed itself. If a transmission planning region selects a transmission solution that was 

sponsored by a transmission developer, then the sponsor is eligible to use the regional cost 

allocation method to develop the selected transmission project. Relevant to this report, NYISO 

and PJM have adopted this model, although PJM’s process includes aspects of a competitive 

bidding model in certain situations.

Given that Order No. 1000 requires that both incumbent and nonincumbent transmission 

developers have the same eligibility to use the regional cost allocation method for selected 

transmission projects,11 one question that arises is the success of nonincumbent proposals under 

both competitive bidding models and sponsorship models following the implementation of 

Order No. 1000. There are several ways in which competition between incumbents and 

nonincumbents in competitive transmission development processes can be gauged. This section 

of the report describes staff’s analysis of three measures to assess competition at the 

transmission planning region level: (1) the percentage of proposals submitted by incumbents 

 10 A transmission planning region is made up of the transmission providers that have enrolled in the region, and 

depending on what processes have been adopted, it may be a transmission planning region or the transmission 

providers within that region that administer the competitive transmission development process. For convenience, 

we refer to the transmission planning region and transmission providers enrolled in the region collectively as the 

transmission planning region. 

11 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 332, 339.
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and nonincumbents in a given year, (2) the number of unique developers submitting proposals 

in a given year and their share of the total proposals submitted, and (3) the number and share of 

proposals selected that were nonincumbent proposals. In addition, staff reports its evaluation of 

stakeholder involvement in regional transmission planning processes, another measure of 

engagement in competitive transmission development processes.

As discussed further below, staff notes that a significant number of joint ventures and consortia 

submitted proposals through the competitive proposal windows that were opened during the 

period that staff studied in this report. Many of these joint ventures and consortia included 

nonincumbent transmission developers along with incumbent transmission developers from the 

regions in question. In Order No. 1000, the Commission adopted its nonincumbent 

transmission developer-related requirements to eliminate practices that have the potential to 

undermine the identification and evaluation of more efficient or cost-effective alternatives to 

regional transmission needs, thus helping to ensure just and reasonable rates for transmission 

customers.12 Nonincumbent transmission developers aid this effort by bringing novel 

viewpoints and innovative ideas to the transmission planning process as well as serving as 

entities with which incumbents must compete to be selected as the developer of a given project, 

and this may be true whether they remain independent or enter into joint ventures or consortia 

with incumbent transmission developers. The act of competing and facing competition also 

helps ensure just and reasonable rates. While joint ventures and consortia may bring 

substantial benefits, when nonincumbent transmission developers enter into joint ventures or 

consortia with incumbent transmission developers, it may reduce the total number of 

competitors and ideas presented in the competitive transmission development process, 

potentially reducing some of the benefits from having nonincumbent transmission developers 

participate. Staff plans to explore these developments further in future transmission metrics 

reports. 

PERCENTAGE OF NONINCUMBENT TRANSMISSION PROJECT BIDS 

OR PROPOSALS

Background

This metric measures the percentage of proposals that nonincumbent transmission developers

submitted in competitive transmission development processes. For the purpose of this report 

and to be consistent with Order No. 1000, staff includes as nonincumbents any new consortium

or joint venture as long as the project is located outside of all of the associated entities’ retail 

distribution service territories or footprints.13 Staff notes that this metric addresses only regional 

 12 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 226.

13 A consortium or joint venture may include incumbents, nonincumbents, or some combination of the two. If the 

consortium or joint venture is made up of all nonincumbents, then staff considers the consortium or joint venture to 

be a nonincumbent. If the consortium or joint venture includes an incumbent and a nonincumbent, the project 

must be located outside of the incumbent’s retail distribution service territory or footprint in order for the 
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transmission projects; it does not reflect projects proposed outside of the regional transmission 

planning process or any interregional transmission projects. This metric is intended to measure 

nonincumbent participation in regional transmission planning processes, which the 

Commission concluded in Order No. 1000 was necessary in order to eliminate practices that 

have the potential to undermine the identification and evaluation of more efficient or costeffective alternatives to regional transmission needs, thus helping to ensure just and reasonable 

rates for transmission customers.14

Methodology

Staff gathered data on the proposals that developers submitted in the proposal windows held 

under the competitive transmission development processes in CAISO, PJM, NYISO, MISO, and 

SPP, the five transmission planning regions that have held competitive transmission 

development processes since the implementation of Order No. 1000. In the future, it should be 

possible to perform a similar analysis for other regional transmission planning regions when

they start holding their own competitive transmission development processes.

To calculate this metric, staff gathered data from public documents posted on the websites of

CAISO, PJM, NYISO, SPP, and MISO. For CAISO, proposal data came from documents 

submitted during Phase 3 (the project sponsor selection phase) of the 2012-2013 and 2013-2014 

transmission planning processes, under which CAISO opened nine proposal windows from 2013 

to 2015.

15 CAISO has not had any additional proposal windows since publication of the 2016 

Report. However, the values and percentages for CAISO that are presented in the 2017 Report 

are slightly different due to the reclassification of certain developers.16

For PJM, staff gathered information on numerous proposals from PJM’s Regional Transmission 

Expansion Planning (RTEP) Proposal website17 and from documents posted by the 

Transmission Expansion Advisory Committee (TEAC).

18 PJM opened 14 proposal windows 

 consortium or joint venture to be considered a nonincumbent. If the consortium or joint venture is made up of all 

incumbents, then the project must be outside of all of the incumbents’ retail distribution service territories or 

footprints in order for it to be classified as a nonincumbent. For the purpose of this analysis, a consortium 

represents a combination of transmission developers (either incumbents or nonincumbents) that operate under a 

different firm name and is usually a distinct legal entity. A joint venture, on the other hand, indicates two or more 

transmission developers that choose to work together and submit a single proposal while still maintaining their 

own separate businesses. 

14 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 226.

15 See http://www.caiso.com/planning/Pages/TransmissionPlanning/2012-2013TransmissionPlanningProcess.aspx

and http://www.caiso.com/planning/Pages/TransmissionPlanning/2013-2014TransmissionPlanningProcess.aspx. 

With regard to Order No. 1000 compliance, the Commission approved CAISO’s request for an effective date of 

October 1, 2013, for its filing to allow the compliance tariff provisions to be applied to the 2013-2014 transmission 

planning cycle rather than the 2012-2013 cycle, which was almost complete when CAISO submitted its compliance 

filing. See Cal. Indep. Sys. Operator Corp., 143 FERC ¶ 61,057 at P 28 (2013). 16 Specifically, a few developers that were originally considered to be separate entities in the 2016 Report are now 

identified as joint ventures since the developers subsequently submitted joint proposals.

17 See http://www.pjm.com/planning/rtep-development/expansion-plan-process/ferc-order-1000/rtep-proposalwindows.aspx. 18 See http://pjm.com/committees-and-groups/committees/teac.aspx.
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between 2013 and 2016; however, staff’s analysis of nonincumbents’ share of proposals 

submitted only includes data from the 13 proposal windows for which information was available 

at the time of staff’s analysis. New in the 2017 Report, staff analyzes data from four of the five

additional proposal windows that PJM has opened since publication of the 2016 Report. Staff 

omitted data from the sixth additional proposal window (the 2016/2017 RTEP Long Term 

Proposal window) because PJM had not yet posted the proposals received on its website as of 

the preparation of this report. 

In addition, NYISO, SPP, and MISO opened their first proposal windows after the publication of 

the 2016 Report. Staff includes data on these proposal windows for the first time in its analysis 

in the 2017 Report. Specifically, NYISO has held its first two proposal windows as part of its 

Public Policy Transmission Planning Process. NYISO’s first proposal window, which opened in 

late 2015, focused on relieving transmission congestion in Western New York State (i.e., the 

region surrounding Buffalo).19 In 2016, NYISO’s second proposal window specified two 

different AC transmission projects that affected different sections of the NYISO system.20 

Developers were permitted to address one or both segments in their proposals.

21 Staff used

information regarding NYISO’s proposal windows from final22 and draft23 reports on the 

assessment and selection processes. 

SPP held one proposal window in 2015 for the North Liberal-Walkemeyer 115 kV line. While 

SPP selected a proposal, the transmission planning region cancelled the project in July 2016 due 

to declining load.24 Nonetheless, staff includes data from SPP’s proposal window in its analysis

 19 See

http://www.nyiso.com/public/webdocs/markets_operations/services/planning/Planning_Studies/Public_Policy_Doc

uments/Western_NY/NYISO_WesternNY_PPTN_VSA_2016-05-31.pdf at 7. 20 Segment A included the Edic or Marcy to New Scotland 345 kV line; two Princetown to Rotterdam 345 kV or 

230 kV transmission lines; decommissioning two 230 kV lines from Edic to Rotterdam; and associated switching or 

substation work at Edic or Marcy, Princetown, Rotterdam, and New Scotland. Segment B entails a new double 

circuit 345 kV/115 kV line from Knickerbocker to Churchtown; a new double circuit 345 kV/115 kV line or triple 

circuit 345 kV/115 kV/115 kV line from Churchtown to Pleasant Valley; decommissioning of a double-circuit 115 kV 

line from Knickerbocker to Churchtown; decommissioning of one or two double-circuit 115 kV lines from 

Knickerbocker to Pleasant Valley; construction of a new tap of the New Scotland-Alps 345 kV line and new 

Knickerbocker switching station; and related switching or substation work at Greenbush, Knickerbocker, 

Churchtown and Pleasant Valley substations. In addition, Segment B requires a new double-circuit 138 kV line 

from Shoemaker to Sugarloaf; decommissioning of a double-circuit 69 kV line; related switching or substation work 

at Shoemaker, Hartley, South Goshen, Chester, and Sugarloaf; and upgrades to the Rock Tavern substation.

21 See http://www.nyiso.com/public/webdocs/markets_operations/committees/bic_espwg/meeting_materials/2016-

09-26/NYISO_AC_Transmission_PPTN_VSA_Draft_Report.pdf at 12. 22 See

http://www.nyiso.com/public/webdocs/markets_operations/documents/Legal_and_Regulatory/NY_PSC_Filings/201

6/2016-6-1%20NYISO%20filing%2014-E-0454%20VS%20Assmnt%20Western%20NY%20PPTN.pdf. NYISO 

submitted these reports to the New York Public Service Commission for review.

23 See http://www.nyiso.com/public/webdocs/markets_operations/committees/bic_espwg/meeting_materials/2016-

09-26/NYISO_AC_Transmission_PPTN_VSA_Draft_Report.pdf. 24 See https://www.spp.org/documents/40383/mopc%20report%20to%20bod%2007-25-16%20-%20v1-3.pdf at 53-

58.
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from the initial request for proposals25 and the final selection report.26 Due to SPP’s reporting 

practices, staff found it difficult to analyze developers’ incumbency status and the number of 

submissions per developer. That is, SPP announced only the winner and runner up in its 

competitive transmission development process. 

MISO opened its first proposal window, which was for the Duff-Coleman extra-high-voltage 

345 kV line, in 2016 after the completion of its 2015 MISO Expansion Transmission Plan 

(MTEP). Staff gathered information regarding the project from MISO’s request for proposals on 

its website.27 MISO selected a proposal in late 2016.28 

To determine the incumbency status of developers that submitted proposals, staff applied the 

Order No. 1000 definition of “nonincumbent” and compared the transmission zone in which 

each proposed project would be located to the developer’s retail distribution service territory or 

footprint, where applicable.29 Staff found this step necessary because publicly-available data

regarding proposals generally do not state a particular developer’s incumbency status; they

merely list the names of the entities that submitted proposals. Since incumbent transmission 

owners frequently create subsidiaries, sometimes with unique names, for the sole purpose of 

submitting proposals in one or more particular transmission planning region, staff researched 

the names and footprints of the parent organizations. Despite the lack of explicit information 

about incumbency status in the proposals themselves, staff identified the incumbency status of 

the developers with a high degree of confidence. Joint ventures and consortia as a whole are 

categorized as incumbents if the projects they propose are located in one or more of the 

participating transmission developers’ footprints or retail distribution service territories.

As discussed further in the Results and Analysis section, for purposes of comparison, staff 

grouped proposals by transmission planning region and year in which the proposal window was 

opened.

 25 See https://www.spp.org/documents/28843/spp-rfp000001_website%20watermarked%20posting%20version_regdateupdate080315.pdf. 26 See

https://www.spp.org/documents/37708/iep%20recommendation%20report%20with%20process%20and%20appen

dix%20public%20redacted%20041216_redacted.pdf. 27 See https://www.misoenergy.org/Planning/Pages/TransDevQualSel.aspx. 28 See

https://www.misoenergy.org/Library/Repository/Study/Transmission%20Developer/20161220_FINAL_Selection%2

0Report_SRPT_v1.pdf. 29 Refer to footnotes 3 and 10 for definitions of “nonincumbent” in the context of the 2017 Report.
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Results and Analysis

Figure 1 summarizes the results of staff’s analysis of the proposals that developers submitted in 

the proposal windows from 2013 through 2016 in CAISO, MISO, NYISO, PJM, and SPP (with 

the exception of PJM’s 2016/2017 RTEP Long Term Proposal window). For the purpose of this 

metric, staff analyzed the number of proposals in each window and the incumbency status of the 

entities submitting the proposals. Staff did not gather data on or analyze the costs associated 

with the proposals. 

Specifically, Figure 1 shows the percentages of proposals submitted by incumbents and 

nonincumbents annually to each transmission planning region. The chart also notes the total 

number of proposals received in each region and year.30 Across all five transmission planning 

regions that have held proposal windows, developers submitted a total of 703 proposals.31 Staff 

found that between 2013 and 2016, incumbents and nonincumbents submitted 52 percent and

47 percent of proposals, respectively. Staff could not classify the remaining one percent of 

proposals as submitted by incumbents or nonincumbents.

For CAISO, proposals from nonincumbents accounted for two-thirds to three-quarters of all 

proposals submitted in each of the three years it conducted proposal windows. The percentage 

of nonincumbent proposals in CAISO are based on nine proposals from seven unique developers 

in 2013, 19 proposals from nine unique developers in 2014, and three proposals from three unique 

developers in 2015.32 Overall, there were 31 proposals from 18 unique developers over the three 

years.33 

 30 Staff assigned proposals to a given calendar year based on the opening and closing dates of the associated 

proposal window, not the regional transmission planning cycle.

31 NYISO disqualified three proposals when those developers did not provide additional information upon request. 

Staff did not include these three proposals in the total number of proposals submitted.

32 Staff revised the number of proposals and developers in CAISO for the years 2014 and 2015. In Transmission Metrics: 

Initial Results, staff initially reported 20 proposals and 10 developers in 2014 and four proposals and four developers 

in 2015. A review of CAISO’s public notices regarding the proposals received revealed that in both years, two 

developers independently submitted proposals but then decided to work together and subsequently filed joint 

proposals. Specifically, in 2014, TransCanyon and SoCal Edison submitted individual proposals. See

http://www.caiso.com/Documents/List-QualifiedProjectSponsors-Proposals-Delaney-ColoradoRiverProject.pdf. In 

2015, NEET West and SoCal Edison each submitted a proposal. See

http://www.caiso.com/Docments/UpdatedListofValidatedProjectSponsorApplications-HarryAllenEldoradoProject.pdf. Initially, staff categorized TransCanyon and NEET West as nonincumbents while designating 

SoCal Edison as an incumbent. Considering the joint proposals, staff now categorizes the joint proposals as 

incumbents because the projects were located within SoCal Edison’s retail distribution service territory.

33 Because certain entities changed their individual proposals to joint proposals, the newly classified combined 

developers matched developers in other years, thus causing the number of unique developers to decline.
14

Figure 1

Competitive Proposals by Incumbents vs. Nonincumbents

Percentage of annual proposals in CAISO, PJM, NYISO, SPP, and MISO (2013-2016)

Sources: CAISO’s 2012-2013 and 2013-2014 transmission plans; PJM’s Transmission Expansion Advisory Committee and RTEP proposal websites; NYISO’s transmission 

planning needs reports; SPP’s Integrated Transmission Planning 10-Year Study (ITP10), meeting minutes from the Board of Directors/Members Committee, and 

recommendation report from an industry expert panel; and MISO’s Competitive Transmission Administration website.

22%

32% 33% 33%

63%

42%

54%

42%

56%

9%

27%

78%

68% 67% 67%

37%

58%

46%

58%

44%

9%

73%

82%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2013 2014 2015 2013 2014 2015 2016 2015 2016 2015 2016

CAISO PJM NYISO SPP MISO

Incumbent

Nonincumbent

n=9 n=19 n=3 n=43 n=304 n=128 n=147

n=11

n=12 n=16 n=11

Unknown
15

Seven developers (submitting a total of eight proposals) were unique joint ventures or consortia. 

Staff classified three of these joint ventures and consortia as incumbents34 based on the location 

of the projects, while staff classified the other four as nonincumbents.

35

In PJM, proposals from nonincumbents made up at least 50 percent of all proposals in 2013 and 

2015, but fell to 37 percent in 2014 and 46 percent in 2016. The results for the year 2015 in the 

2017 Report vary from those in the 2016 Report due to the inclusion of data from the 2015 RTEP 

2 proposal window, which added 23 additional proposals to that year’s count. Data from the 

2015 RTEP 2 proposal window was unavailable when staff conducted its analysis for the 2016 

Report. Moreover, the 2017 Report includes new proposal information for 2016, specifically 

proposals from the 2016 RTEP 1, 2016 RTEP 2, 2016 RTEP 3, and 2016 RTEP 3 Addendum

proposal windows. In total, PJM received 622 proposals between 2013 and 2016, not including 

those from the 2016/17 RTEP Long Term Proposal window.

36 In 2013, 10 unique developers 

submitted 43 proposals, with three entities being joint ventures (Duke-ATC, Pepco Holdings, 

Inc. (Pepco)/Exelon Corporation (Exelon),

37 and Transource Energy). PJM received nearly half 

of its total proposal count in 2014. That year, the 2014 RTEP 1 window garnered 106 proposals 

from 13 developers,38 the 2014 RTEP 2 window comprised of 79 proposals from 13 developers,39

 34 The joint ventures and consortia are TransCanyon DCR, LLC (TransCanyon DCR)/Southern California Edison 

Company (SoCal Edison), NextEra Energy Transmission West, LLC (NEET West)/SoCal Edison, and Pacific Gas 

and Electric Company (PG&E)/MidAmerican Transmission, LLC (MidAmerican Transmission. TransCanyon 

DCR is a joint venture between Bright Canyon Energy Corporation, a subsidiary of Pinnacle West Capital 

Corporation, which is the parent company of Arizona Public Service Company, and BHE U.S. Transmission, a 

subsidiary of Berkshire Hathaway Energy Company, which is the parent company of PacifiCorp, NV Energy, Inc., 

and MidAmerican Energy Company.

35 The joint ventures and consortia are (DCR Transmission, LLC (DCR Transmission), Duke-American 

Transmission Company (Duke-ATC), Golden State Transmission, LLC (Golden State Transmission), and Pattern 

Energy Group LP (Pattern Development)/City of Pittsburg, California. DCR Transmission is a joint venture 

between Abengoa Transmission & Infrastructure, LLC, (ATI) and DCR Investor, LLC, an affiliate of Starwood 

Energy Group Global, LLC. ATI is a wholly-owned subsidiary of Abengoa, South America. Golden State

Transmission is a joint venture between Edison Transmission, LLC, and Transource Energy, LLC (Transource 

Energy); it was not noted as joint venture in the 2016 Report.

36 As explained above, staff did not include proposals from the 2016/17 RTEP Long Term Proposal window because 

PJM had not yet posted the proposals from that competitive proposal window on its website at the time of staff’s 

analysis. 

37 The merger between Exelon and Pepco Holdings did not close until March 2016.

38 Staff reduced this number from 15 developers as described in the 2016 Report as Exelon is the parent company of 

Baltimore Gas and Electric Company, Commonwealth Edison Company, and Philadelphia Electric Company. Staff 

misclassified certain proposals in the 2016 Report because it did not account for this corporate relationship and has 

corrected the data in the 2017 Report.

39 Staff reduced this number from 14 developers as described in the 2016 Report as Exelon is the parent company of 

Commonwealth Edison Company and Philadelphia Electric Company. 
16

and the 2014/15 Long Term RTEP window accounted for 119 proposals from 19 developers,40 for a 

total of 304 proposals from 22 unique developers.41

Of this total, six unique joint ventures or consortia submitted 43 proposals (11 from 

nonincumbents and 32 from incumbents). Transource Energy—a joint venture between 

American Electric Power Company, Inc. (AEP) and Great Plains Energy Incorporated, formed to 

pursue new competitive transmission projects—submitted 17 proposals. Of these 17 proposals, 

staff classified the joint venture as a nonincumbent for nine proposals and as an incumbent for 

eight proposals given the location of each proposed project. Of the remaining proposals from 

joint ventures or consortia, Pepco/Exelon submitted 11 proposals, Dominion Resources, Inc. 

(Dominion)/Transource Energy submitted seven proposals, Dominion/First Energy Corporation 

(First Energy) submitted four proposals, Duke-ATC submitted three proposals, and PPL

Electric Utilities Corporation (PPL Electric Utilities)/First Energy submitted one proposal; staff 

determined that these developers were incumbents for all of their proposals.

42

In 2015, PJM received 128 proposals from 11 unique developers, covering four proposal windows: 

2014 RTEP Addendum, 2014 RTEP Addendum 2, 2015 RTEP 1, and 2015 RTEP 2. While the 

results for that calendar year cover two different transmission planning cycles, nearly all of the 

proposals (114 out of 128) were submitted for the 2015 RTEP process. During calendar year 

2015, staff identified three entities as joint ventures (AEP/Duke Energy Corporation (Duke 

Energy), PPL Electric Utilities/First Energy, and Transource Energy). Transource Energy was 

an incumbent for 2 of its 11 proposals. AEP/Duke Energy submitted one proposal, and PPL 

Electric Utilities/First Energy submitted two proposals, all as incumbents. In total, the joint 

ventures submitted 14 proposals.

This report also captures proposal information from PJM’s first four proposal windows in 2016. 

In total, PJM received 147 proposals from 15 unique developers, including one joint venture 

(AEP/Duke Energy) and one consortium (Transource Energy). AEP/Duke Energy submitted one 

proposal, and Transource Energy submitted 15 proposals. Staff identified Transource Energy as

an incumbent for half of its proposals. By proposal window, PJM received 25 proposals in 2016 

RTEP 1, 87 proposals in 2016 RTEP 2, 29 proposals in 2016 RTEP 3, and 6 proposals in 2016 

RTEP 3 Addendum.

In NYISO, nonincumbent proposals accounted for 58 percent and 44 percent of proposals 

received in 2015 and 2016, respectively. Most developers submitted multiple proposals. In 2015, 

NYISO received a total of 15 proposals (12 Public Policy Transmission Projects and 3 Other 

 40 Staff reduced this from 22 developers as described in the 2016 Report as Exelon is the parent company of 

Baltimore Gas and Electric Company, Commonwealth Edison Company, and Philadelphia Electric Company. In 

addition, staff categorized Dominion High Voltage Transmission/Transource Energy the same as 

Dominion/Transource Energy.

41 Staff reduced this from 30 developers in the 2016 Report to reflect the reclassifications described in the preceding 

footnotes.

42 Staff revised the 2014 information from the 2016 Report to reflect that PJM ran proposal windows for the 2014 

RTEP in 2015. PJM opened the 2014 RTEP 2 Addendum proposal period from January, 20, 2015, to February 6, 

2015, and the 2014 RTEP Addendum 2 window from February 24, 2015, to March 12, 2015. In the 2017 Report, staff 

includes proposals from these two proposal windows in the 2015 results for PJM rather than the 2014 results. 
17

Public Policy Projects), but it disqualified three proposals because the developers did not 

provide supporting information upon request.43 The remaining 12 proposals (11 Public Policy 

Transmission Projects and 1 Other Public Policy Project) were submitted by seven unique 

developers, where three were incumbents and four were nonincumbents. One of the developers, 

an incumbent, was a joint venture (New York Power Authority/New York State Electric and 

Gas Corporation).44 After review, NYISO determined that 10 proposals were viable.

45 In 2016, 

NYISO received 16 proposals (15 Public Policy Transmission Projects and 1 Other Public Policy 

Projects) from six unique developers, with 13 proposals identified as viable by NYISO.

46 For 

these proposals, staff identified three incumbents and three nonincumbents, where one joint 

venture (North America Transmission47/New York Power Authority) was an incumbent for one 

proposal and a nonincumbent for another based on the project’s location. In addition, one 

consortium (National Grid/New York Transco) submitted proposals as an incumbent. After 

reviewing the proposals, NYISO found that 13 proposals were viable. 

As stated above, SPP has had one competitive proposal window – its first – which occurred in 

2015. In response, SPP received 11 proposals. As reported in a news release,

48 SPP selected the 

Mid-Kansas Electric Company, a consortium of electric cooperatives, as the winning 

developer.

49 Staff considers Mid-Kansas Electric Company an incumbent due to the location of 

the project relative to the service area of one of the member cooperatives. Oklahoma Gas and 

Electric Company, which staff determined to be a nonincumbent, was reported as the runner up. 

Figure 1 indicates the incumbency status of the nine anonymous proposals as unknown.

Similar to SPP, MISO recently conducted its first proposal window in 2016. Overall, 11 unique 

developers each submitted a single proposal. Nonincumbent proposals accounted for 73 percent 

of the submissions. Five unique joint ventures or consortia submitted one proposal each. Staff 

classified three of these joint ventures and consortia (Duke-ATC; Republic Transmission, LLC

(Republic Transmission);

50 and Southern Indiana Gas and Electric Company doing business as 

Vectren Energy Delivery of Indiana, Inc./Public Service Enterprise Group Incorporated (PSEG)) 

 43 NYISO did not disclose the identities of the developers associated with the disqualified proposals.

44 See

http://www.nyiso.com/public/webdocs/markets_operations/documents/Legal_and_Regulatory/NY_PSC_Filings/201

6/2016-6-1%20NYISO%20filing%2014-E-0454%20VS%20Assmnt%20Western%20NY%20PPTN.pdf. 45 NYISO determined that two developers (NRG Dunkirk Power and ITC New York Development) were 

unqualified.

46 NYISO no longer considered the two projects from AvanGrid, Inc. (parent company of New York State Electric 

and Gas Corporation and Rochester Gas and Electric) and one project from GlidePath Power LLC because the 

projects were not viable. 

47 North American Transmission is a subsidiary of LS Power.

48 See https://www.spp.org/about-us/newsroom/spp-board-votes-to-lower-planning-reserve-margins-award-firstcompetitively-bid-project-approve-363m-in-transmission-upgrades/. 49 The member cooperatives are Lane-Scott Electric Cooperative, Inc., Prairie Land Electric Cooperative, Inc., 

Southern Pioneer Electric Company, The Victory Electric Cooperative Association, Inc., Western Cooperative 

Electric Association, Inc., and Wheatland Electric Cooperative, Inc.

50 The participant associated with this proposal is Big Rivers, which has three member cooperatives: Jackson 

Purchase Energy Corporation; Kenergy Corporation; (Kenergy); and Meade County Rural Electric Cooperative 

Corporation. Kenergy serves the area around the Coleman facility in Handcock County, Kentucky.
18

as incumbents and the two others (Ameren Transmission Company of Illinois/PPL TransLink, 

Inc., and Transource Energy51) as nonincumbents.

In reviewing the results of the competitive transmission development processes in CAISO, 

MISO, NYISO, PJM, and SPP, staff has observed that there is some indication that when a range 

of different solutions located in different transmission zones (i.e., incumbent transmission 

owners’ footprints) can resolve the violations posted as part of a competitive proposal window, 

incumbents submit a greater percentage of the total proposals than when the range of potential 

solutions to a transmission need subject to a proposal window is more geographically limited or, 

in the case of transmission planning regions that have adopted competitive bidding models, 

when the transmission planning region has already identified a transmission solution. For 

example, under CAISO’s competitive bidding model all of the proposal windows involved 

specific transmission lines, substations, or reactive power support in a given area or at a 

particular point, and the share of proposals from nonincumbents ranged from 67 percent (2015) 

to 78 percent (2013). Similarly, the single proposal windows in MISO and SPP both involved 

specific transmission lines and, while staff does not have data for SPP (as described above),

nonincumbents submitted 73 percent of the total proposals submitted in MISO. 

In contrast, PJM’s various proposal windows included violations with a more limited range of 

potential solutions and violations with a wider range of potential solutions. For example, PJM’s 

2015 proposal windows announced violations that could be resolved by a more limited range of 

potential solutions, and the share of proposals from nonincumbents exceeded that from 

incumbents (58 percent versus 42 percent). In 2014, on the other hand, all of PJM’s announced 

violations had a range of potential solutions located in multiple transmission zones,

52 and 

incumbents submitted 63 percent of proposals. The preliminary results for PJM from 2016, in 

which PJM’s proposal windows addressed violations with a similarly wide range of potential 

solutions, are consistent with this hypothesis – incumbents accounted for 54 percent of the 

proposals that year. However, the results from 2013, in which PJM’s proposal windows 

included both violations with a limited range of potential solutions and violations with a wider 

range of potential solutions, is less supportive of staff’s observation. In that year, 

nonincumbents in PJM accounted for 67 percent of the proposals submitted. 

Staff’s observation is further supported by the results of the proposal windows in NYISO. In 

NYISO’s 2015 proposal window, the range of potential solutions was limited to a particular 

transmission zone (Zone A), and nearly 60 percent of the valid proposals that year came from 

nonincumbents. Conversely, in NYISO’s 2016 proposal window, the range of potential solutions

spanned three transmission zones: Mohawk Valley (Zone E), Capital (Zone F), and Hudson 

Valley (Zone G). Incumbents submitted 56 percent of the proposals in response to this proposal 

window. 

 51 Transource Energy is a partnership between American Electric Power and Great Plains Energy. Transource 

Indiana, LLC, and Transource Kentucky, LLC participated in this proposal.

52 The 2014 RTEP 1 and 2014 RTEP 2 proposal windows specified reliability criteria violations at various facilities 

within PJM’s footprint, while the 2014/15 Long Term RTEP considered reliability criteria violations, market 

efficiency congestion, and Reliability Pricing Model (RPM) constraints on facilities.
19

Compared to last year’s analysis, this updated metric is more representative of competitive 

transmission development processes across different transmission planning regions, as it 

includes new competitive proposal windows from PJM, NYISO, SPP, and MISO. However, staff 

cautions that transmission planning regions implemented their competitive transmission 

development processes too recently for staff to describe a “typical” proposal year, expected 

proposals, and resulting selections in this report. First, staff’s analysis continues to be 

geographically limited; ISO New England (ISO-NE) and the non-RTO/ISO transmission 

planning regions have yet to open proposal windows. Second, two regions – SPP and MISO –

have each had only one proposal window. 

In the 2016 Report, staff hypothesized that PJM may open more and larger proposal windows in 

even-numbered years than in odd-numbered years because of the nature of its 24-month 

planning cycle.53 In 2014, PJM opened two short-term windows and one long-term window

with 304 proposals received in response, while in 2015 it opened only two short-term windows 

(2015 RTEP 1 and 2015 RTEP 2) with 128 proposals received in response.

54 Staff points to the 

2016 proposal windows as data supporting this hypothesis, as PJM opened four short-term 

windows (2016 RTEP 1, 2016 RTEP 2, 2016 RTEP 3, and 2016 RTEP 3 Addendum) and one longterm window (2016/17 RTEP Long-Term Proposal) in 2016. While the proposal information for 

the 2016/17 RTEP Long-Term Proposal window has yet to be posted on PJM’s website, PJM has 

already received 147 proposals in the first four windows of 2016, which already exceeds the 

number of proposals received in 2015. Moreover, staff anticipates that PJM will receive a large 

number of proposals in its 2016/17 Long Term Proposal window – as a comparison, submissions 

for the 2014/15 Long Term Proposal window accounted for 39 percent of all proposals PJM 

received in 2014. 

Staff also questioned in the 2016 Report whether PJM’s adoption of the sponsorship model 

resulted in its receipt of more than 10 times the proposals that CAISO, which adopted a 

competitive bidding model, has received. Staff previously found this hypothesis difficult to test

because at that time, no other transmission planning regions had opened proposal windows. 

Now that proposal information from MISO, NYISO, and SPP is available, staff is able to make 

some preliminary observations based on the expanded data. In its two proposal windows, 

NYISO – which uses a sponsorship model like PJM – received a total of 28 proposals (12 in 2015 

and 16 in 2016). These values are more in line with the number of proposals received by CAISO, 

MISO, and SPP, all of which use competitive bidding models. Therefore, staff concludes that 

there may be some other characteristic of PJM’s competitive proposal window process, besides 

the model of competitive transmission development process that it chose to adopt, that explains 

 53 PJM has a 24-month transmission planning process consisting of two 12-month cycles to examine immediate 

needs (fewer than 3 years in the future) and short-term needs (3-5 years in the future), and a 24-month cycle to 

examine long-term needs (15 years in the future). Projects needed in fewer than 3 years are not subject to a proposal 

window, and are therefore not included in this analysis. See http://pjm.com/planning/rtep-development/expansionplan-process/ferc-order-1000/rtep-proposal-windows.aspx, and PJM, 2014 Regional Transmission Expansion Plan: 

Book 2 (Input Data and Process Scope), at 15, http://pjm.com/~/media/documents/reports/2014-rtep/2014-rtepbook-2.ashx. 54 PJM also opened two windows in 2015 that were addenda to the 2014 RTEP 2 proposal window; PJM received 

relatively few proposals in response to both. Those proposals were included as part of staff’s analysis of the 

proposals that PJM received in 2015.
20

the relatively large number of proposals that it receives. One potential explanation is that PJM’s 

proposal windows include numerous reliability standard violations and, consequently, may 

result in the selection of many transmission projects. In contrast, the proposal windows in 

CAISO, MISO, and SPP under the competitive bidding model include only one specific project 

per proposal window. Similarly, while NYISO uses a sponsorship model, its proposal windows 

tend to include a more limited number of violations that lend themselves toward a more limited 

solution, such that NYISO is likely to select fewer proposals per proposal window. As noted 

above, PJM’s proposal windows also tend to include reliability standard violations that could be 

resolved by a wider range of different, geographically disperse transmission solutions than is 

typically the case in the other transmission planning regions. Staff believes that this wider range 

of solutions could also potentially help to explain why PJM receives more proposals.

Staff notes that, on August 26, 2016, the Commission issued an order that permitted PJM to 

revise the tariff rules governing its competitive proposal window process to exclude reliability

violations on transmission facilities operating below 200 kV from that process.

55 Thus, staff

hypothesizes that the number of proposals in PJM post-2016 may fall as fewer violations are 

subject to proposal windows. Staff intends to review the future data to test this hypothesis.

Caveats

Now that another year has passed, this metric provides more useful information about the 

degree of nonincumbent participation in Order No. 1000 regional transmission planning 

processes. However, one should be cautioned from relying too heavily on these results to 

determine degree of nonincumbent participation. As noted above, ISO-NE and the nonRTO/ISO transmission planning regions have yet to hold proposal windows under Order No. 

1000. Moreover, two regions (SPP and MISO) have each held only one proposal window, with 

SPP ultimately cancelling the selected project and making the identity of only the winner and 

runner up available to the public. As a result, staff believes it is still too early to tell whether the 

limited number of proposal windows in CAISO, PJM, NYISO, SPP, and MISO will prove 

representative of future proposal windows. 

The greater number of proposal windows in PJM and the addition of three new transmission 

planning regions in the 2017 Report has indicated that joint ventures and consortia may be 

submitting more proposals in regional transmission planning processes. The current 

methodology of categorizing transmission developers as either incumbents or nonincumbents 

may mask the activity of particular entities that are involved in joint ventures or consortia. 

Specifically, labeling a joint venture that includes an incumbent transmission developer and a 

nonincumbent transmission developer as strictly an incumbent transmission developer does not 

recognize the participation of the nonincumbent transmission developer. As a result, staff 

would like to investigate the prevalence of joint ventures and consortia that involve both 

incumbent and nonincumbent transmission developers. In future reports, staff plans to 

categorize a given transmission developer as either an incumbent transmission developer, a

nonincumbent transmission developer, or a combined developer (i.e., a joint venture or 

 55 See PJM Interconnection, L.L.C. 156 FERC ¶ 61,132 (2016).
21

consortium that includes both an incumbent and nonincumbent transmission developer). 

Under this new categorization system, incumbent transmission developers and nonincumbent

transmission developers could be single entities or they could be either joint ventures or 

consortia that are comprised of strictly incumbent or nonincumbent transmission developers, 

respectively. 

NUMBER OF UNIQUE DEVELOPERS SUBMITTING PROPOSALS

Background

As an additional measure of the competitiveness of Order No. 1000 competitive transmission 

development processes, this metric seeks to measure the number of unique developers that 

participate in transmission planning regions’ competitive transmission development processes

by submitting proposals, regardless of their incumbency status. Staff believes that this metric 

may serve as one indication of how competitive the competitive transmission development 

processes implemented to comply with Order No. 1000 are, as it measures the number of unique 

developers that participate in these processes. As noted above, transmission planning regions 

have adopted either a sponsorship model or a competitive bidding model to comply with Order 

No. 1000. It is possible that one type of model may lend itself to participation by more unique 

developers than the other. Therefore, staff also intends this metric to help provide a better

understanding of whether one model of competitive transmission development process may 

attract more unique developers, and thus potentially more competition, than the other.

Methodology

To calculate this metric, staff used data from the various transmission planning regions’ proposal 

windows that were posted on their respective websites, which are the same sources to calculate 

the nonincumbent percentage of proposals metric above. Staff identified the number of unique 

developers that submitted a proposal in response to a proposal window, tabulating them by 

transmission planning region and by year. Staff defined a unique developer in a given year as

either a particular incumbent, nonincumbent, consortium, or joint venture regardless of their 

incumbency status. For purposes of its analysis, staff considered entities that submitted 

separate proposals but that are owned by a single parent company to be a single, unique

developer. Lastly, staff identified consortia as unique developers, even though members of a 

consortium may be affiliated with other unique developers. This is because staff assumed that 

the process of negotiating among consortium members will result in a unique set of blended 

interests that differs from the particular interests of any individual consortium member. 
22

Results and Analysis

Figure 2 below shows the total number of unique developers that submitted proposals in 

CAISO’s, MISO’s, NYISO’s, PJM’s, and SPP’s competitive transmission development processes 

by year. Between 2013 and 2016, the number of unique developers in a given transmission 

planning region in any year ranged from 3 to 22 entities, while most of the totals hovered 

between 6 and 11 unique developers.

Figure 2

Number of Unique Developers and Average Proposals per Developer by Year and RTO/ISO

2013 2014 2015 2016

RTO/ISO Total 

Submissions

Number of 

Unique 

Developers 

(Average 

Proposals 

per 

Developer)

Total 

Submissions

Number of 

Unique 

Developers

(Average 

Proposals 

per 

Developer)

Total 

Submissions

Number of 

Unique 

Developers

(Average 

Proposals 

per 

Developer)

Total 

Submissions

Number of 

Unique 

Developers

(Average 

Proposals 

per 

Developer)

CAISO 9 7 (1.3) 19 9 (2.1) 3 3 (1.0) --- ---

PJM 43 10 (4.3) 304 22 (13.8) 128 11 (11.6) 147* 16* (9.2)

NYISO --- --- --- --- 12 7 (1.7) 16 6 (2.7)

SPP --- --- --- --- 11 N/A** --- ---

MISO --- --- --- --- --- --- 11 11 (1.0)

* Includes the 2016 RTEP 1, 2016 RTEP 2, 2016 RTEP 3, and 2016 RTEP 3 Addendum proposal windows, but 

excludes the 2016/17 RTEP Long Term Proposal window.

** The total number of unique developers in SPP is not known since the identities of the developers were masked 

in the selection report and SPP announced the names of the winner and runner up in a press release on its 

website.
23

Staff’s analysis did not yield any general observations about the number of unique developers 

compared across years or across transmission planning regions using different models of 

competitive transmission development processes.

On a regional basis, CAISO’s experience with unique developers has varied over time. In 2014, 

nine unique developers submitted a total of 19 proposals (2.1 proposals per developer). In 2013, 

the developers submitted fewer proposals in 2013 (1.3 proposals per developer). In 2015, unique 

developers each submitted one proposal. 

By far, PJM had the most proposals over the four-year period, largely due to the inclusion of 

projects related to reliability violations on transmission facilities operating below 200 kV. 

Because developers devise solutions for transmission planning regions’ needs under the 

sponsorship model, that competitive transmission development process lends itself to multiple 

submissions from any one developer. PJM’s proposal data illustrates this observation – in 2014, 

PJM received 304 proposals that ultimately came from 22 unique developers (13.8 proposals per 

developer), and in 2015, PJM received 128 proposals from 11 unique developers (11.6 proposals 

per developer).

After considering the proposals that NYISO disqualified as incomplete, unique developers in 

NYISO submitted approximately two proposals per developer. In MISO, each proposal came 

from a unique developer. Staff could not determine the number of unique developers in SPP’s 

sole competitive proposal window due to the transmission planning region’s confidentiality 

protocols.

Caveats

This metric provides some insight into the number of unique developers that have participated 

in competitive transmission development processes. However, one should be cautioned from

relying too heavily on these results. As noted above, ISO-NE and the non-RTO/ISO 

transmission planning regions have yet to hold proposal windows under Order No. 1000. 

Moreover, SPP and MISO have each held only one proposal window, with SPP ultimately 

cancelling the selected project. As a result, staff believes it is still too early to tell whether the 

limited number of proposal windows in CAISO, PJM, NYISO, SPP, and MISO will prove 

representative of future proposal windows.

NUMBER AND PERCENTAGE OF SELECTED NONINCUMBENT PROPOSALS

Background

This metric measures the number of nonincumbent proposals that each transmission planning 

region selected in each year for which staff has data. The metric also shows the percentage of 

the total selected proposals that nonincumbents submitted. Staff intends this metric to help 

assess whether nonincumbents are likely to have continued interest in participating in 

competitive transmission development processes going forward. For example, a high selection 
24

rate of nonincumbent proposals would seem to encourage more nonincumbents to submit 

proposals as they may be less likely to view the competitive transmission development process 

as unduly discriminatory towards nonincumbents when a transmission planning region has 

selected nonincumbent proposals in the past

Methodology

To calculate this metric, staff primarily used data from the transmission planning region’s 

websites. For CAISO and MISO, staff used information about their selection decisions that they

posted on their respective websites.

56 In PJM, the Transmission Expansion Advisory Committee 

sends its recommended selections to the PJM Board of Managers in the form of a white paper for 

review. PJM then publishes annual reports on the PJM Board of Managers’ decisions on those 

recommendations. Staff gathered data on selected proposals in PJM from these annual reports,

as well as the Transmission Expansion Advisory Committee’s monthly presentations.57 The 

winner from SPP’s competitive window was announced on the transmission planning region’s 

website.58 While NYISO has opened two proposal windows, as of the preparation of this report, 

it had yet to select any proposals and thus staff had no data from NYISO to include when 

calculating this metric.

Staff identified the total number of proposals selected each year in the four transmission 

planning regions that have made selection decisions (i.e., CAISO, MISO, PJM, and SPP). Staff 

determined whether each selected proposal was submitted by an incumbent or nonincumbent. 

Staff then calculated the percentage of selected proposals that nonincumbents submitted.

 56 See http://www.caiso.com/planning/Pages/TransmissionPlanning/2012-2013TransmissionPlanningProcess.aspx

and http://www.caiso.com/planning/Pages/TransmissionPlanning/2013-2014TransmissionPlanningProcess.aspx for 

CAISO and 

https://www.misoenergy.org/Library/Repository/Study/Transmission%20Developer/20161220_FINAL_Selection%2

0Report_SRPT_v1.pdf for MISO.

57 For preliminary results for 2016 RTEP 1, see “Transmission Expansion Advisory Committee 2016 PJM Board 

Recommendation Webcast” from the Transmission Expansion Advisory Committee (June 23, 2016) at 

http://mediastream.pjm.com/2016/0623/teac/reliability-analysis-update-webcast/index.htm. The recommended 

projects for 2016 RTEP 2 and 2016 RTEP 3 can be found in the TEAC meeting notes at 

http://www.pjm.com/committees-and-groups/committees/teac.aspx. For a summary of the 2014/15 RTEP Long 

Term Proposal, 2015 RTEP 1, and 2015 RTEP 2, see http://www.pjm.com/~/media/documents/reports/2015-

rtep/2015-rtep-book-1.ashx at 8. For detailed information on the 2013 Artificial Island window, 2015 RTEP 1, 2015 

RTEP 2, and 2014 RTEP 2 Addendum 2 see http://www.pjm.com/~/media/documents/reports/2015-rtep/2015-rtepbook-3.ashx at 21-27, 84, 100-105, and 109-110. For a detailed analysis of the Board-recommended bids for 2014 

RTEP 1 and 2014 RTEP 2, see http://www.pjm.com/~/media/documents/reports/2014-rtep/2014-rtep-book-3.ashx at 

39-43 and 58-62. For information about the recommended bid in the 2013 Market Efficiency proposal window, see 

http://www.pjm.com/~/media/documents/reports/2013-rtep/2013-rtep-book-3.ashx at 118-119. 58 See https://www.spp.org/about-us/newsroom/spp-board-votes-to-lower-planning-reserve-margins-award-firstcompetitively-bid-project-approve-363m-in-transmission-upgrades/.
25

Results and Analysis

Figure 3 below shows the total number of proposals that each transmission planning region

selected each year, as well as the number and percentage of selected proposals that 

nonincumbents submitted. Overall, staff observes that, other than in CAISO, most of the 

proposals that the transmission planning regions selected were submitted by incumbents. 

In CAISO, the number and percentage of selected proposals that nonincumbents submitted

appear to have risen over time. In 2013, incumbents submitted both of the proposals that 

CAISO selected. However, in 2014, nonincumbents submitted four of the six proposals (67 

percent) that CAISO selected and in 2015, a nonincumbent submitted the single proposal that 

CAISO selected (out of three proposals submitted).

The three other transmission planning regions that have selected proposals in their competitive 

transmission development processes have selected fewer nonincumbent proposals. PJM did not 

select any nonincumbent proposals between 2014 through the third competitive window of 

2016. PJM also selected an incumbent proposal as a result of the 2013 Market Efficiency 

Proposal Window. PJM co-selected a nonincumbent proposal for the 2013 Artificial Island 

project – the PJM Board of Directors recommended using part of the nonincumbent’s proposal

and combined it with work that would be done by an incumbent. Thus, of the three proposals 

(or parts of proposals) that PJM selected as a result of its 2013 proposal windows, only one was 

a nonincumbent proposal. SPP and MISO have only had one proposal window each, and both 

selected proposals that incumbents submitted.

59

 59 In MISO, the selected developer, Republic Transmission, wholly owned by LS Power Associates, L.P. (LS Power), 

partnered with Big Rivers, which has three member cooperatives – Jackson Purchase Energy Corporation, Kenergy 

Corporation, (Kenergy), and Meade County Rural Electric Cooperative Corporation. Kenergy serves the area 

around the Coleman facility in Handcock County, Kentucky. Moreover, LS Power entered into an agreement with 

Hoosier Energy to acquire a percentage ownership of Republic Transmission. Hoosier Energy’s service area 

includes Dubois County, Indiana, the same county where the Duff substation is located. Thus, staff classified 

Republic Transmission as an incumbent, given its joint proposal with Big Rivers; however, Republic Transmission, 

a nonincumbent, is solely responsible for developing the Duff-Coleman project. SPP selected Mid-Kansas Electric 

Company, which is a consortium of electric cooperatives operated by Sunflower Electric Power Corporation. The 

North Liberal-Walkemeyer 115 kV transmission line project notes that the North Liberal substation is owned by 

Mid-Kansas Electric Company, while the Walkemeyer substation is owned by Sunflower Electric Power 

Corporation. Thus, staff classified Mid-Kansas Electric Company as an incumbent.
26

Figure 3

Number and Percentage of Awards Made to Nonincumbents by Year and RTO/ISO

* Only Market Efficiency Proposals in PJM were selected in 2013. While the review of Artificial Island proposals continued into 2015, the final selections 

associated with that project were counted under the 2013 proposal window year.

** Covers PJM’s 2016 RTEP 1, 2016 RTEP 2, and 2016 RTEP 3 and are only TEAC recommendations to the PJM Board. Thus, the selections for the 2016 year are 

not final.

*** NYISO has yet to select a proposal from its two solicitations.

100%

33%

67%

100% 100% 100% 100% 100%

67%

100%

33%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2013 2014 2015 2013 2014 2015 2016 2015 2016

CAISO PJM SPP MISO

Nonincumbent

n=2 n=6 n=1 n=3

n=66 n=27 n=23 n=11 n=11

Incumbent
27

Caveats

While this metric sheds some light on nonincumbents’ success in competitive transmission 

development processes, staff finds that several caveats are warranted. As noted above, staff 

identified nonincumbents as either stand-alone entities, consortia, or joint ventures, so long as 

the project falls outside of the company’s (companies’) retail distribution service territory 

(territories) or footprint(s). Staff categorized joint ventures and consortia that include 

incumbents and nonincumbents as incumbents if the project was located in the incumbent’s 

retail distribution service territory or footprint. Therefore, this metric does not capture the fact 

that in some cases, the joint venture associated with a selected proposal may include a 

nonincumbent (e.g., MISO’s selection of a proposal submitted by both Republic Transmission, a 

nonincumbent, and Big Rivers Electric Corporation, an incumbent). This shortcoming will be 

alleviated in future reports when staff categorizes transmission developers as incumbent 

transmission developers, nonincumbent transmission developers, or combined developers. 

With this revised methodology, staff will better recognize the participation of nonincumbent 

transmission developers that partner with incumbent transmission developers to submit 

proposals. In addition, the number of transmission planning regions that have held proposal 

windows, and the number of proposal windows that they have held, is limited, making it 

difficult to draw any conclusions from the data at this time.
28

STAKEHOLDER PARTICIPATION IN REGIONAL TRANSMISSION 

PLANNING PROCESSES

Background

The metric, included as a new metric for the 2017 Report, measures stakeholder participation in 

regional transmission planning processes. In the past, this metric was reported separately. 

Specifically, the Commission’s Strategic Plan for fiscal years 2014-2018 requires staff from the 

Office of Energy Market Regulation (OEMR) to assess the potential effectiveness of Order No. 

1000 in encouraging greater participation in the regional transmission planning processes, thus 

promoting more efficient and cost-effective transmission solutions.60

Methodology 

To collect data for this metric, OEMR staff attended and monitored stakeholder participation in 

at least three to four regional transmission planning meetings held by each of the 12 Order No. 

1000 transmission planning regions61 during FY 2015 and FY 2016.62 OEMR staff recorded the 

stakeholders that participated in these meetings by phone and reviewed participation lists that 

the meeting organizers provided to staff. Staff measured the level of participation by counting 

the total number of participants attending the meetings.63 In addition, staff measured the 

number of participants in three categories: (1) public utility transmission providers; (2) 

transmission customers;64 and (3) nonincumbent transmission developers. Staff then computed 

the averages for each category of stakeholder for each region by adding up the total number of 

attendees in each category of stakeholder (or in the case of Figure 4, the total number of 

attendees in all three categories of stakeholders) and then divided by the number of meetings 

monitored for a particular region.65 Staff believes averaging the attendance numbers for the 

various meetings staff monitored provides a more accurate reflection of attendance than a simple 

 60 See https://www.ferc.gov/about/strat-docs/FY-2014-FY-2018-strat-plan.pdf at 10-11. 61 The Order No. 1000 transmission planning regions are: CAISO; ColumbiaGrid; Northern Tier Transmission 

Group (NTTG); WestConnect, MISO; SPP; Florida Reliability Coordinating Council (FRCC); ISO-NE; NYISO; 

PJM; Southeastern Regional Transmission Planning (SERTP); and South Carolina Regional Transmission Planning 

(SCRTP).

62 The authors of this report would like to acknowledge the OEMR staff who collected and compiled the 

stakeholder attendance data for FY 2015 and FY 2016. They include: Gabriel Aguilera; Adam Bednarczyk; James 

Brennan; Nicole Buell; Michael Cackoski; Patrick Clarey; Nicole Cramer; James Eason; Saeed Farrokhpay; Jonathan 

Fernandez; Alina Halay; Franklin Jackson; Eric Jacobi; Rhonda Jones; Michael Lee; Christopher Mahon; Valerie 

Martin; Matthew McWhorter; Christopher Miller; Peter Nagler; Al Padron; Penny Payne; Natalie Propst; Rajiv 

Raja; Navin Shekar; Jay Sher; Jason Strong; and Gary Will. 

63 Staff counted representatives from the same entity as one participant regardless of the number of individuals that 

the entity may send to a meeting.

64 Transmission customers include demand-side stakeholders (such as load, state commissions, and consumer 

advocacy groups) and supply-side stakeholders (such as generators). 65 The sum of the averages for the three stakeholder categories does not equal the total number of attendees 

reported in Figure 4 due to several factors, including: (1) rounding; (2) the lack of attendee lists for NYISO’s 

meetings (discussed in footnote 66 below); and a change in the coding of the nonincumbent attendees at the MISO 

meetings (discussed below with Figure 7). 
29

count because stakeholder participation fluctuates between meetings held at different times in 

the transmission planning cycles.

Results and Analysis 

Figures 4 through 7 below show the average attendance figures for all stakeholders and for each 

of the three categories of stakeholders for each transmission planning region for FY 2015, the 

first year that staff began collecting the data for all 12 regions, and for FY 2016. 

Figure 4 shows that the average attendance by all stakeholders dropped off slightly in most 

transmission planning regions from FY 2015 to FY 2016. This pattern holds among both 

RTOs/ISOs and non-RTO/ISO transmission planning regions although some regions –

NTTG, FRCC, SERTP, and SCRTP – showed increases.66

Figure 4

Average Number of Participants Attending

Regional Transmission Planning Meetings during FY 2015 and FY 2016

Average Number of Participants in Attendance

Region FY 2015 FY 2016 Difference

CAISO 57 55 -2

ColumbiaGrid 20 16 -4

NTTG 24 29 5

WestConnect 33 32 -1

MISO 90 89 -1

SPP 43 35 -8

NYISO 44 39 -5

ISO-NE 28 30 2

PJM 85 80 -5

FRCC 11 14 3

SERTP 26 29 3

SCRTP 8 10 2

Total 469 458 -11

 66 Staff has requested NYISO to provide a list of attendees for each regional transmission planning meeting so that 

staff can separate participants into the three categories required by the Strategic Plan. However, NYISO only 

reports overall attendance numbers and thus far has not provided the requested lists. 
30

Figure 5 shows that the average attendance by public utility transmission providers remained

stable in all transmission planning regions, with only minor increases or decreases between FY

2015 and FY 2016. 

Figure 5

Average Number of Public Utility Transmission Providers

Attending Regional Transmission Planning Meetings during FY 2015 and FY 2016

Average Number of Public Utility Transmission 

Providers in Attendance

Region FY 2015 FY 2016 Difference

CAISO 6 4 -2

ColumbiaGrid 14 13 -1

NTTG 6 6 0

WestConnect 12 12 0

MISO 22 25 3

SPP 16 14 -2

NYISO Unavailable Unavailable n/a

ISO-NE 11 8 -3

PJM 28 29 1

FRCC 3 4 1

SERTP 12 14 2

SCRTP 3 3 0

Total 133 132 -1
31

Figure 6 shows that transmission customers’ attendance decreased significantly in SPP, 

increased moderately in ISO-NE, and held steady in the remaining transmission planning 

regions.

Figure 6

Average Number of Transmission Customers

Attending Regional Transmission Planning Meetings during FY 2015 and FY 2016

Average Number of Transmission Customers

in Attendance

Region FY 2015 FY 2016 Difference

CAISO 41 40 -1

ColumbiaGrid 2 2 0

NTTG 18 20 2

WestConnect 15 14 -1

MISO 60 57 -3

SPP 29 15 -14

NYISO Unavailable Unavailable n/a

ISO-NE 15 22 7

PJM 50 47 -3

FRCC 5 6 1

SERTP 13 13 0

SCRTP 5 6 1

Total 253 242 -11
32

Figure 7 shows that meeting participation rates by nonincumbents were stable from FY 2015 to 

FY 2016. Staff identified a major drop in nonincumbent attendance in MISO, but staff believes a 

difference in the method of coding attending parties in FY 2015, by coding parties in more than 

one category, may have led to this difference. Staff also found no significant drop in meeting 

participation by nonincumbents over the two fiscal years in other transmission planning 

regions, and identified increases in nonincumbent participation in four regions. Additionally,

nonincumbents are active in practically every transmission planning region, with the exception 

of ISO-NE and SCRTP.

Figure 7

Average Number of Nonincumbents

Attending Regional Transmission Planning Meetings during FY 2015 and FY 2016

Average Number of Nonincumbents in 

Attendance

Region FY 2015 FY 2016 Difference

CAISO 11 11 0

ColumbiaGrid 4 1 -3

NTTG 1 2 1

WestConnect 6 6 0

MISO 19 7 -12

SPP 4 6 2

NYISO Unavailable Unavailable n/a

ISO-NE 0 0 0

PJM 4 4 0

FRCC 3 4 1

SERTP 1 2 1

SCRTP 0 0 0

Total 53 43 -10

The major finding from this overview of stakeholder attendance at regional transmission 

planning meetings during FY 2015 and FY 2016 is one of stability in stakeholder participation in 

the transmission planning process in both RTOs/ISOs and non-RTO/ISO transmission planning 

regions. Most of the increases or decreases staff observed during this time were not dramatic. 

The decrease in nonincumbent participation in MISO’s regional transmission planning meetings 

appears to be tied to a coding issue and not an actual drop in nonincumbent participation. Staff 

notes that as the Commission sought to facilitate in Order No. 1000, nonincumbent

transmission developers are engaged in the stakeholder process in regional transmission 
33

planning in most transmission planning regions, with increases in participation found in four 

regions.

Caveats

Overall, the stakeholder participation data indicate that the average numbers of total 

participants, Public Utility Transmission Providers, transmission customers, and 

nonincumbents were relatively stable between FY 2015 and FY 2016. It is important to note that 

this metric only considers two years of data. As a result, the findings may not be representative 

of a longer time period. Moreover, the regional transmission planning processes are relatively 

new, and participation may increase over time as stakeholders become more comfortable with 

the process. 
34

II. Metric to Indicate Whether Appropriate Levels of 

Transmission Infrastructure Exist

This category of metrics attempts to use price data to assess whether transmission investment in 

the RTOs/ISOs is adequate. Price differentials between areas within an RTO/ISO may be the 

result of inadequate transmission capacity, capacity that is necessary to deliver power from 

areas with lower prices to those with higher prices. However, not all price differentials can be 

addressed economically; in some cases, the costs associated with the transmission infrastructure 

necessary to reduce a price differential may exceed the benefits that alleviating that congestion 

could provide. In such cases, persistent price differentials do not necessarily indicate 

insufficient transmission investment. 

RTO/ISO MARKET PRICE DIFFERENTIAL 

Background

As discussed in more detail in the 2016 Report, staff reasons that multiple consecutive years of 

significant price differences could indicate insufficient transmission infrastructure, while 

bearing in mind that additional investment in transmission infrastructure to reduce those 

differences may not be economic in all cases.

Methodology

Staff focused on individual points or areas where historical electricity prices or locational 

marginal prices (LMPs) were significantly different from the average of the LMPs in the 

surrounding areas. 

In RTO/ISO markets, where prices reflect congestion costs, a point where anomalous LMPs 

occur persistently should indicate congestion on the transmission interfaces linking the point 

with other parts of the transmission system. In contrast, in an area without congestion, LMPs 

should all be essentially the same, differing perhaps only by virtue of the varying marginal losses 

at each point. Thus, the persistent occurrence of high or low prices at a given point relative to 

the rest of the market suggests transmission investment could be needed, at least where such 

investment is economic.
35

To calculate this metric, staff used real-time LMPs at load and generator points from ABB 

Velocity Suite and other sources.67 The data covered the period January 1, 2000, to December 31, 

2015. To avoid placing excessive weight on highly unusual prices, staff used the 95th and 5th

percentiles of prices, rather than maximum or minimum prices, at each load and generator point. 

Staff then calculated the average 95th and 5th percentiles of prices at all of the points in the 

market to identify a market-wide average 95th percentile price and a market-wide average 5th

percentile price for each RTO/ISO. Using this information, staff identified those points whose 

95th or 5th percentile price were, compared to the market-wide averages, either significantly high 

or significantly low.

To determine whether a price was significantly high or low compared to the market-wide 

averages, staff relied on a common statistical concept, the standard deviation. Staff considered a 

location “high-priced” in a year if the 95th percentile of prices at that point was more than one 

standard deviation above the average of the 95th percentiles of all points in the market. 

Similarly, staff considered a location to be “low-priced” in a year if the 5th percentile of prices at 

that point was more than one standard deviation below the average of the 5th percentiles of all 

points in the market. This approach finds points where the high prices in a year were high 

relative to the average of the high prices in the same year for the entire market the points are in, 

as well as points where the low prices in a year were low relative to the average of the low prices 

in the same year for the entire market the points are in. For example, if the average of the 95th

percentile of real-time LMPs is $150/MWh in an RTO/ISO (for generator price points) and the 

standard deviation of the 95th percentile of real-time LMPs is $300/MWh, the threshold for 

counting generator price points as high-priced would be $450/MWh. Thus, the 95th percentile 

of the real-time LMPs at a point would have to be at least $450/MWh for the point to be 

characterized as high-priced.

Staff identified points with high or low prices in 2012 through 2015 to determine the points at 

which price separation occurred persistently and likely has not yet been resolved. To focus on 

the persistence of price separations, staff then tallied the number of years in which the current 

run of high or low prices began. Finally, staff identified areas within each RTO/ISO that 

encompassed multiple neighboring points with persistent price separations in the same 

direction, identified for each area the longest period of price separation experienced by a pricing 

point included in that area, and used that number of years as the RTO/ISO Price Differential 

metric for that region.

Results and Analysis

Using ABB Velocity Suite data through 2015 and price information from SPP from 2014 through

2015, staff found 1,482 generator or load points in Commission-jurisdictional RTOs/ISOs where 

relatively high or low real-time LMPs occurred persistently.

 67 Following the implementation of SPP’s Integrated Marketplace, ABB Velocity Suite no longer provides yearly 

pricing data for SPP, so staff aggregated real-time price data directly from SPP. See

ftp://pubftp.spp.org/Markets/RTBM/LMP_By_BUS/.
36

Staff found 13 areas within RTOs/ISOs in the U.S. where either persistently high and/or low 

prices existed. For each area, Figure 8 lists the price direction, year in which the price 

separation began, and the number of years the price separation has persisted. Many of the areas 

identified have experienced either low or high relative prices for a substantial period of time. Of 

additional note, staff identified continued areas of low- and high-priced points from the 2016 

Report in the North-Central MISO, Greater Chicago, North Dakota-South Dakota-Minnesota 

Border, West-Central North Dakota, Upper Peninsula, New York-Canada Border, Northern 

New York, Long Island, Baltimore, and Delmarva areas, which may suggest very localized 

constrained facilities.

Figures 9 through 12 below show the areas with more than one high-priced or low-priced point, 

as defined, and the points themselves. Specifically, Figure 9 shows the 13 areas in which staff 

found instances of persistent high or low prices. Figure 10 indicates the low-price points in the

various regions. Generator points are represented by solid squares and load points by hollow 

squares; different colors represent the number of years that price differentials persisted.68 As 

Figure 10 shows, staff found a large number of low-priced points in the middle of the country, 

particularly North-Central MISO, the Greater Chicago area, and Western Texas, as well as in 

the New York-Canada Border Region, Northern New York, West-Central North Dakota, and 

the North Dakota-South Dakota-Minnesota Border Region.

Similarly, Figure 11 shows high-priced points, with generator points represented by solid stars 

and load points by hollow stars. Again, the colors represent the number of years the price

differentials persisted.69 As shown in Figure 11, staff identified eight areas with high-priced 

points, including Baltimore, the Upper Peninsula, North-Central MISO, Delmarva, 

Northwestern New Jersey, the Greater Chicago Area, Long Island, Western Texas, and Central 

California. Figure 12 combines the low and high-price maps.

 68 The years in which the persistently low prices began to were grouped into three categories: 2005 to 2007, 2008 to 

2010, and 2012 to 2013. 69 As with Figure 10, the years in which persistently high prices began were grouped into the same three categories.
37

Figure 8

Summary of RTO Market Price Differential Metric for Select Areas

Area Identified by Staff RTO/ISO Price 

Direction

Start of Area’s 

Longest Occurrence 

of Ongoing Price 

Differentials70

Metric

(Years of 

persistence 

through 2015)

Baltimore PJM High 2005 11

Upper Peninsula MISO High 2005 11

North-Central MISO MISO Low 2005 11

High 2005 11

Delmarva PJM High 2006 10

New York-Canada Border Region NYISO Low 2006 10

Northern New York NYISO Low 2006 10

Northwestern New Jersey PJM High 2007 9

Greater Chicago PJM Low 2007 9

High 2012 4

Long Island NYISO High 2009 7

Western Texas SPP Low 2010 6

High 2010 6

West-Central North Dakota MISO Low 2010 6

ND-SD-MN Border Region MISO Low 2010 6

Central California CAISO High 2013 3

Source: Staff analysis of ABB Velocity Suite price data from 2000 through 2015 and SPP price data between 2014 

and 2015.

 70 Not all points in each area have experienced the persistent occurrence of high or low prices for the same period of 

time; this column shows the initial years of persistent price differences based on the longest-standing, persistent 

occurrence of high or low prices in the area.
38

Figure 9

Regions with High-Priced or Low-Priced Points

Sources: Staff analysis of ABB Velocity Suite and SPP price data.
39

Figure 1071

Low-Priced Points

Sources: Staff analysis of ABB Velocity Suite and SPP price data.

 71 The years in which the persistently low prices began were grouped into three categories: 2005 to 2007, 2008 to 2010, and 2011 to 2013.
40

Figure 1172

High-Priced Points

Sources: Staff analysis of ABB Velocity Suite and SPP price data.

 72 The years in which the persistently high prices began were grouped into three categories: 2005 to 2007, 2008 to 2010, and 2011 to 2013.
41

Figure 12

High-Priced and Low-Priced Points

Sources: Staff analysis of ABB Velocity Suite and SPP price data.
42

Of note, in reviewing the 2015 data, staff found that SPP is experiencing fewer persistent price 

differentials than staff observed in the past. In the 2016 Report, staff identified a large number of 

low-price points in an area called Western SPP, which included central to western Iowa, 

Kansas, and Oklahoma, as well as the northern Texas Panhandle. Many of those low-price 

points disappeared when staff calculated the metric for the 2017 Report, falling from 554 points 

in the 2016 Report to two points in the 2017 Report. Staff credits the decrease in low-price 

points to several changes impacting the region, including significant transmission investment in 

the region in 2014 (as indicated in the section below on the Baseline Metric), SPP’s 

implementation of the Integrated Marketplace in March 2014, and SPP’s consolidation of its 

former 16 balancing authorities into one consolidated balancing authority in 2014. 

The difference between the total number of high- and low-price points in the 2016 Report 

(1,986) and the 2017 Report (1,482) does not exactly equal the change in the number of points in 

SPP (552 points), as some new points outside of SPP were designated as high- or low-price 

points, thus pushing the total number of points higher.

Caveats

While staff found its analysis of persistent price differentials informative, there are limitations to 

this analysis. First, there may be reasons other than insufficient transmission capacity why high 

or low prices persistently occur in a particular case. For example, a state may have a renewable 

portfolio standard that only counts in-state resources toward compliance, thus requiring the use 

of potentially more expensive local resources no matter how much transmission capacity may be 

available to access lower cost resources elsewhere. Second, even if more transmission capacity 

could reduce the deviation of price from the market average in a particular case, if the cost of the 

needed transmission upgrade would exceed this benefit, it might not be beneficial to undertake 

such an upgrade. Finally, lines connecting points where high prices occurred to points where 

low prices occurred might not help equilibrate prices as much as might be expected based only 

on this analysis. For example, the high prices and the low prices may not occur at the same time 

of the year.
43

III. Metrics to Permit Baseline Analyses of the Impacts of 

Policy Changes

The third category of metrics includes three interrelated metrics: (1) load-weighted 

transmission investment; (2) load-weighted circuit-miles; and (3) load-weighted circuit-miles 

per million dollars of investment. Given the caveats associated with each metric, as discussed 

below, they are best analyzed as a group to provide an indication as to whether transmission 

investment is both sufficient and cost-effective. In combination, these three metrics allow for a 

comparison of how much transmission infrastructure has been developed in each North 

American Electric Reliability Corporation (NERC) region of the U.S. and the relative cost of 

that investment.73

LOAD-WEIGHTED TRANSMISSION INVESTMENT (INCREMENTAL)

Background

This metric describes the load-weighted dollar value of transmission facilities added (i.e., that 

went into operation) each year between 2008 and 2015 in the eight NERC regions of the 

contiguous U.S.74 Weighting transmission investment dollars by the associated retail load 

allows for comparisons between entities of different sizes (as measured by the amount of retail 

load).75 While more load-weighted investment may not always be better than less loadweighted investment, tracking how these values adjust to changes in Commission policy may be 

informative.

Methodology

Staff used transmission project data broken out by NERC region from the C Three Group’s 

North American Electric Transmission Projects database.76 Investment dollars represent the 

nominal cost or reported budget for each project. To aid comparison across years, staff 

 73 The metrics in this section of the 2017 Report focus on NERC regions instead of transmission planning regions 

because staff’s data source, C Three Group, reports transmission investment by NERC region rather than 

transmission planning region Moreover, staff utilizes NERC net energy for load values to weight the transmission 

investment and circuit-miles data, and NERC reports such net energy for load data based on its eight regions. 74 The eight NERC regions include FRCC; MRO; Northeast Power Coordinating Council (NPCC); Reliability First 

Corporation (RFC); SERC Reliability Corporation (SERC); SPP; Texas Regional Entity (TRE); and Western 

Electricity Coordinating Council (WECC). 

75 As with other load-weighted metrics in this paper, staff uses NERC “net energy for load” data for retail load. 76 C Three Group reports continuously updated information on more than 17,000 69 kilovolt (kV) through 765 kV 

transmission projects in the U.S., Canada, and Mexico. See 

https://www.cthree.net/transmission/database/default.aspx.
44

converted the values to 2015 dollars using the annual average of the consumer price index for all 

urban consumers (CPI-U).77 To calculate the final, load-weighted metric, staff divided the 

normalized investment figures for each NERC region for each year by the net energy for load in 

each year, as reported in NERC’s 2015 Electricity Supply & Demand (ES&D) database. 

Staff chose 2008 as the first year of the analysis due to a lack of robust project data across all 

NERC regions prior to that year. Staff excluded a limited number of projects without a NERC 

region designation or with multiple designations.

Figure 13 shows the footprints of the eight NERC regions.

Figure 13

NERC Regions Map

Source: NERC.

 77 In the absence of an industry standard for calculating changes in the prices of goods associated with transmission 

investment, CPI-U was chosen as a broad measure of changes in prices over time. See Bureau of Labor Statistics 

(BLS), CPI Detailed Report – August 2016, Table 24 (annual average), http://www.bls.gov/cpi/cpid1508.pdf.
45

Results and Analysis

Staff identified 9,754 projects that went into operation between 2008 and 2015, representing 

approximately $77 billion (in 2015 dollars) of incremental transmission investment. 

Approximately three-quarters of this total ($58 billion) was invested in projects primarily 

involving new and upgraded transmission lines, with the remaining quarter ($18.7 billion) 

invested in projects involving substations and other non-line facilities.78

Figure 14 shows the load-weighted incremental transmission investment (in dollars per MWh) 

in the eight NERC regions of the contiguous U.S. from 2008 to 2015. The values in red represent 

the regional average load-weighted investment across all eight years, while the values in black 

refer to the highest load-weighted dollar investment in each region over the time period.

Figure 14

Incremental Load-Weighted Transmission Investment in the U.S., 2008-2015

All New and Upgraded Projects in Operation, $/MWh

Sources: C Three Group, NERC, and BLS.

Overall, the average load-weighted transmission investment for all regions over all eight years is 

$2.43 per MWh of load, although staff found investments “lumpy” in most regions, as is typical 

for large infrastructure projects. Due to a major spike in transmission investment in 2013, the 

average load-weighted investment in TRE over all of the years exceeds $4.00 per MWh. Six of 

 78 The project types in the C Three Group database are not completely binary (i.e., line vs. non-line projects); some

projects involve both new or upgraded lines and associated new or upgraded substations. For the purpose of this 

metric, if a project involved a line component, then staff categorized it as a line project. Thus, staff included 

upgrades to address sag, clearance, or thermal issues as line projects. If no line-related component existed in a given 

project, then staff categorized the project as a non-line project.

$19.61 

$8.22 

$5.48 

$6.93 

$4.84 $4.38 $4.97 

$2.55 

$0.88 

$4.48 $3.98 $3.16 $3.00 $2.43 $2.43 $2.09 $1.07 $0.55 $0

$4

$8

$12

$16

$20

09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15

TRE SPP NPCC RFC WECC All Regions MRO SERC FRCC

TRE 2013 without CREZ
46

the eight NERC regions (SPP, NPCC, RFC, WECC, MRO and SERC) are in the range of 

approximately $1.00 per MWh to $4.00 per MWh on average over the period, while one region

without an organized market (i.e., FRCC) fell below $1.00 per MWh on average over the period. 

On a regional level, the metric shows an uneven trend of load-weighted investment over the time 

period.

Compared to the 2016 Report, the average load-weighted investment per MWh over all of the 

NERC regions in the 2017 Report rose $0.24 per MWh. With another year of data, RFC has a 

higher average load-weighted investment per MWh than WECC in the 2017 Report, but 

otherwise, the relative positions of the regions remain the same. In the 2016 Report, WECC and 

RFC had an average load-weighted investment per MWh of $2.61 and $2.34, respectively,

between the years 2008 and 2014. In the 2017 Report, RFC and WECC had an average loadweighted investment of $3.00 and $2.43, respectively, between the years 2008 and 2015. 

Compared to some other NERC regions, RFC had large absolute and load-weighted investments 

in 2013 and 2014, which then jumped to $6.93 per MWh in 2015—a total of approximately $8.8 

billion over the three years—due to several large projects that came into operation. Those 

projects included the merchant-owned Hudson Transmission Project, an underground and 

underwater HVDC line from New Jersey to Manhattan,79 and a number of projects in PSEG’s 

service territory.

As described in the 2016 Report, staff lists here the projects that contributed to the peak years of 

investment in certain NERC regions. TRE had the highest all-year average load-weighted 

investment over the period ($4.48 per MWh) and highest single-year metric ($19.61 per MWh 

in 2013) due to the approximately $6.5 billion of projects — the largest single-year investment of 

any region — that went into operation in 2013. Of the $6.5 billion, approximately $5.7 billion 

was under Texas’ Competitive Renewable Energy Zone (CREZ) initiative, which aimed to 

alleviate congestion and integrate wind capacity into the electric grid.80 In SPP, the relatively 

large investment in 2014 represents the completion of several balanced portfolio projects and 

priority projects proposed under the region’s highway/byway initiative. The first phase of 

priority projects under this initiative was estimated to cost $1.14 billion; several of the projects 

went into operation in 2014,81 as did several of the balanced portfolio projects.82 In NPCC, the 

Greater Springfield Reliability Project and Rhode Island Reliability Projects—both portions of 

the New England East-West Solution group of projects83—began operating in 2013. In WECC, 

portions of the Tehachapi Renewable Transmission Project and Energy Gateway Transmission 

Expansion Project were completed in 2013, and the Sunrise Powerlink — a $1.9 billion project 

 79 See http://hudsonproject.com/project/. 80 The Competitive Renewable Energy Zone initiative was established by Texas State legislation in 2005. All 

initiative projects were complete by January 30, 2014, at a total cost of $6.9 billion. See Lasher (ERCOT), “The 

Competitive Renewable Energy Zone Process,” presentation to DOE’s Quadrennial Energy Task Force, August 11, 

2014, http://energy.gov/sites/prod/files/2014/08/f18/c_lasher_qer_santafe_presentation.pdf. 81 SPP, “SPP Approves Construction of New Electric Transmission Infrastructure to Bring $3.7 Billion in Regional 

Benefits,” (April 27, 2010 Press Release), http://www.spp.org/publications/Priority_Projects_Approved_4-27-10.pdf. 82 SPP, “Balanced Portfolio,” http://www.spp.org/engineering/transmission-planning/balanced-portfolio/. 83 Northeast Utilities, “New England East-West Solution (NEEWS),” http://www.transmissionnu.com/residential/projects/neews/.
47

designed to, among other things, deliver renewable energy from the Imperial Valley to maintain 

reliability and meet state and federal energy policy goals84 — was completed in 2012. MRO had 

its largest absolute transmission investment of $1.7 billion in 2014, when several portions of the 

CAPX2020 projects85 came into operation. 

Caveats

Staff notes that there are important caveats with respect to the implications of this metric. 

First, as mentioned above, more investment in transmission is not necessarily better in all cases. 

For example, entities whose loads are located near their generation resources may be able to 

serve load with less transmission investment than similarly sized entities with more dispersed 

loads. Second, the costs of constructing transmission facilities may vary by region such that a 

project meant to address an identified need may cost more in one region than it would in 

another. In such case, the total transmission investment in the higher-cost region will be higher, 

but not because that region has constructed more transmission infrastructure.

LOAD-WEIGHTED CIRCUIT-MILES (INCREMENTAL)

Background

This metric describes the load-weighted circuit-miles of transmission lines added between 2008 

and 2015 in the eight NERC regions. As with the earlier metric, weighting transmission circuitmiles by the associated retail load allows for comparisons between entities of different sizes.

Methodology

For this metric, staff filtered the C Three Group database by project type and status, removing 

those projects that do not include a line component (e.g., that involve only a substation upgrade) 

and those that were not operating during the seven-year period from 2008 to 2015.86 Staff 

excluded a limited number of projects without a NERC region designation or with multiple 

regional designations.

To determine the number of circuit-miles for each project, staff multiplied the reported line 

miles by the number of reported circuits. In cases where the number of circuits was not 

reported, staff assumed that the line has only one circuit. While this may underestimate the 

 84 CPUC, Decision Granting A Certificate of Public Convenience and Necessity for the Sunrise Powerlink Transmission Project, 

Application 06-08-010, http://docs.cpuc.ca.gov/PUBLISHED/AGENDA_DECISION/95357.htm. 85 See http://www.capx2020.com/index.html. These projects were undertaken to ensure the electricity reliability of 

Minnesota and the surrounding region – North Dakota (ND), South Dakota (SD), and Wisconsin (WI). The 

individual projects included several 345 kV transmission lines (all points are in Minnesota, unless otherwise noted): 

Bemidji-Grand Rapids; Big Stone South (SD)-Brookings County (SD); Brookings County (SD)-Hampton; Fargo 

(ND)-St Cloud; Hampton-Rochester-La Crosse (WI); and Monticello-St. Cloud. 86 Based on projects in the C Three Group North American Electric Transmission Project Database as of August 20, 

2016.
48

number of actual number of circuit-miles for those particular projects, staff believes this is an 

appropriately conservative assumption. Staff then summed the circuit-miles of all of the 

projects reported in each NERC region to determine the total number of circuit-miles added in 

each region in each of the years in question. 

To arrive at the final load-weighted circuit-miles metric for a given NERC region, staff divided 

the annual circuit-miles value for the NERC region by the corresponding net energy for load in 

that region in the same year.

Results and Analysis

Figure 15 shows the load-weighted transmission line additions (in circuit-miles per TWh) in the 

eight NERC regions of the contiguous U.S. from 2008 to 2015. The values in red represent the 

eight-year regional average, while the values in black refer to the highest load-weighted circuitmiles in each region. The 4,788 projects in the sample represent a total of 62,789 circuit-miles of 

transmission facilities added over the period from 2008 to 2015.

Figure 15

Load-Weighted Circuit-Miles of Transmission Added in U.S., 2008-2015

New and Upgraded Lines in Operation, Circuit-Miles/TWh

Sources: C Three Group and NERC.

Overall, the results for this metric are similar to those presented in the 2016 Report. TRE and 

SPP lead while SERC and FRCC lag behind the other regions in terms of load-weighted circuitmiles added, with five regions (WECC, NPCC, RFC, SERC, and FRCC) below the all-region 

average of 1.9 load-weighted circuit-miles per TWh. In the 2017 Report, however, the average 

number of load-weighted circuit-miles per TWh is slightly higher for TRE and MRO (between 

18.4

9.5

5.1

3.3

2.3 2.6 2.5 2.0 1.1

5.8

4.6

2.9

1.9 1.5 1.3 1.1 1.1 0.8

0

4

8

12

16

20

09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15

TRE SPP MRO All Regions WECC NPCC RFC SERC FRCC

TRE 2013 without CREZ
49

0.1 and 0.3 circuit-miles per TWh) than in the 2016 Report. The period average for SPP rose 

substantially from 3.4 load-weighted circuit-miles per TWh in the 2016 report to 4.6 circuitmiles per TWh in the 2017 Report. Load-weighted circuit-mile investment in WECC fell 0.3 

circuit-miles per TWh between the 2016 Report and the 2017 Report.87

As noted in the 2016 Report, the relative positions of some of the regions differ from those 

reported in the overall investment metric because of regional differences in investments in 

projects with long line components versus shorter line projects or projects without line 

components. 

Caveats

This metric helps to address some of the concerns with the Load-Weighted Transmission 

Investment metric because it does not consider the cost of transmission infrastructure, which, as 

explained above, may differ by region. However, the usefulness of this metric also is limited in 

that it does not account for geographic variations among the regions. For example, in regions 

where loads are located far away from generation points, there may be a greater need for 

transmission investment in those regions as compared to regions where loads are located 

relatively close to generation points.

LOAD-WEIGHTED CIRCUIT-MILES PER MILLION DOLLARS OF 

INVESTMENT

Methodology

This metric is designed to provide a basis for assessing the cost impact of different policy choices 

or factual circumstances on transmission investment. Specifically, this metric divides the loadweighted circuit-miles of transmission lines added in the U.S. between 2008 and 2015 by the 

amount of money invested over the same time period (in million dollars of investment

normalized to 2015 dollars). Staff also took the data for this metric from NERC’s database and C 

Three Group’s transmission database. Staff used the sample of 4,788 projects that have line 

components and filtered the data, as described in the previous metric.

Results and Analysis

Figure 16 shows the number of load-weighted circuit-miles per million dollars of transmission 

investment (in 2015 dollars) in the eight NERC regions of the contiguous U.S. from 2008 to 

2015. The values in red represent the eight-year regional average, while the values in black refer 

to the highest circuit-miles per million dollars of investment in each region.

 87 The variations in the results between the 2016 and 2017 Reports for the NERC regions are due to corrections in 

the data – in the 2016 Report, staff inadvertently matched the circuit-miles data for a given year with the forecasted 

NERC net energy for load data instead of the actual values.
50

Figure 16

Load-Weighted Circuit-Miles

Added per Million Dollars of Investment, 2008-2015

New and Upgraded Lines in Operation, Circuit-Miles/$ Million

Sources: C Three Group, NERC, and BLS.

Regions with higher values represent areas with greater numbers of load-weighted circuit-miles 

added per million dollars invested. By this measure, TRE and FRCC, on average, built the most 

load-weighted circuit-miles per million dollars of investment across all of the years (at least 1.5

load-weighted circuit-miles per million dollars), compared to an average of 1.0 load-weighted 

circuit miles per million dollars of investment for all regions combined. RFC built the fewest 

load-weighted circuit-miles per million dollars across all years – approximately 0.5 loadweighted circuit-miles for every million dollars invested. The difference in load-weighted 

circuit-miles per million dollars invested may be due to a range of factors, including terrain, 

population density, and state policy choices, among others, though staff notes that regions 

investing in more substation projects or other project types with zero to no circuit miles have 

lower load-weighted circuit miles added per million dollars invested. 

The results shown here are dramatically different from those reported in the 2016 Report. For 

example, for the years 2008 to 2014, as reported in the 2016 Report, MRO built, on average, the 

most load-weighted circuit-miles per million dollars of investment at 1.7, followed by FRCC at 

1.6. The average load-weighted circuit-miles per million dollars of investment across all regions 

during that period was similar to the value reported in the 2017 Report. However, during that 

time period, NPCC, WECC, and RFC had even lower average load-weighted circuit-miles per 

million dollars of investment at 0.8 or less. 

The relative load-weighted circuit-miles added per million dollars of investment in the various 

regions changed in the 2017 Report, in part, based on the share of investment that is attributed 

9.2

2.9

5.7

2.4

1.9 1.8 2.0 1.9 1.8 2.1

1.5 1.3 1.2 1.1 1.0 1.0 1.0 0.5

0

2

4

6

8

10

12

09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15 09 11 13 15

TRE FRCC SERC SPP WECC MRO NPCC All Regions RFC
51

to projects without line components. For example, MRO allocated 25 percent to 45 percent of 

its investment dollars to projects without a line component between 2008 and 2014. In 2015, the 

most recent year for which data is available, 50 percent of MRO’s transmission infrastructure 

investment was on projects without a line component. That higher spending on non-line 

projects caused MRO’s circuit-miles added per million dollars of investment to be lower than in 

some other regions in 2015. TRE, in contrast, allocated more investment dollars to projects with 

a line component in 2015, thus causing its load-weighted circuit-miles added per million dollars 

of investment relative to that of other regions to jump. Another reason that may explain the 

change in the relative load-weighted circuit-miles added per million dollars of investment for the 

various NERC regions from the 2016 Report to the 2017 Report is that both C Three and NERC 

occasionally revise their historical data. Staff highlights the case of MRO, because it went from 

having the highest average load-weighted circuit-miles added per million dollars of investment

in the 2016 Report to having the third lowest average load-weighted circuit-miles added per 

million dollars of investment in the 2017 Report. A major change in MRO was the circuit-miles 

per million dollars of investment in 2013. For the 2016 Report, the analysis included C Three’s 

count of 280 projects that went into service in MRO in 2013. As of the preparation of the 2017 

Report, C Three had revised this count down to only 214 projects in MRO that went into service 

in 2013, while the corresponding NERC net energy for load figure increased substantially from 

584,125 gigawatt hours (GWh) to 692,434 GWh. Those two differences likely explain much of 

the large drop in MRO’s load-weighted circuit-miles per million dollars of investment in 2013 –

2.9 in the 2016 Report to about 1.5 in the 2017 Report. The large change, combined with the 

bigger investment in non-line projects in 2015, lowered MRO’s average load-weighted circuitmiles per million dollars of investment between 2008 and 2015.

Caveats

Gauging the cost-effectiveness of different transmission investments may be difficult because 

much of the cost of a project is driven by the highly variable physical and regulatory challenges 

particular to each region, project, and/or developer. For example, an upgrade to an existing 

transmission facility is likely to cost less than a greenfield facility. Likewise, a transmission 

facility that is to be located in a population-dense or environmentally-sensitive area may involve 

higher costs per circuit-mile. To the extent that these challenges are more prevalent in some 

regions than others, they are likely to affect the cost-effectiveness analysis.

To at least partially address these concerns while aiding comparison, staff grouped the eight

years of data by region and calculated an average across the years. Staff grouped by NERC 

region under the assumption that most of these regions are large enough to encompass both 

areas where transmission investment would be expensive on a per-mile basis as well as areas 

where such investment would be relatively cheaper on a per-mile basis.
52

IV. Conclusion

In updating the 2016 Report, staff has gained more knowledge of the state of transmission 

investment in the U.S. With respect to the first category of metrics, which assess nonincumbent 

participation in competitive transmission development processes, staff concludes that in those 

transmission planning regions that have held competitive proposal windows, nonincumbent 

participation has generally been robust. With respect to the second category of metrics, which 

evaluate whether appropriate levels of transmission infrastructure exist, staff concludes that, at 

least in certain areas of the U.S., transmission investment is reducing persistent congestion. 

Finally, with respect to the third category of metrics, which allow for the analysis of the impact 

of policy changes, staff finds that the results did not change significantly from the 2016 Report. 

Staff summarizes its observations in greater detail below.

Transmission Investment Metrics

Metric New Findings in the 2017 Report

Metrics to Assess Participation of Nonincumbent Transmission

Developers in Regional Transmission Planning Processes

Percentage of 

Nonincumbent

Transmission Project 

Bids or Proposals

Nonincumbent proposals accounted for 47 percent of all proposals 

submitted in CAISO’s, PJM’s, NYISO’s, and MISO’s competitive transmission 

development processes between 2013 and 2016. In CAISO and MISO, 

nonincumbent proposals accounted for the majority of proposals 

submitted. In PJM, nonincumbents submitted more proposals than 

incumbents in three out of four years. In 2015, NYISO received more 

proposals from nonincumbents, but the reverse was true in 2016. Staff 

could not discern the share of incumbent versus nonincumbent proposals 

in SPP in 2015 because SPP masked the identities of the transmission 

developers that submitted proposals.

Number of Unique 

Developers Submitting 

Proposals (New Metric 

for 2017 Report)

While PJM received a high number of proposals each year, the number of 

unique developers was comparatively low (7 to 22 entities annually). The 

other transmission planning regions (CASIO, NYISO, and MISO) had 

numbers of unique developers that were roughly equivalent to the number 

of proposals received. Due to the masking of developers’ identities in SPP, 

staff could not determine the number of unique developers in that 

transmission planning region.

Number and 

Percentage of Selected 

Nonincumbent 

Proposals (New Metric 

for 2017 Report)

Overall, 20 percent of the proposals selected in 2013 were nonincumbent 

proposals, 6 percent of the proposals selected in 2014 were nonincumbent 

proposals, 3 percent of the proposals selected in 2015 were nonincumbent 

proposals, and none of the proposals selected in 2016 were nonincumbent 

proposals. CAISO had the largest increase in nonincumbents’ share of 

selected proposals, increasing from zero percent in 2013 to 100 percent in 

2015. PJM selected the largest number of proposals, but it selected only 

one nonincumbent proposal over four years. MISO and SPP each selected 

an incumbent proposal in their single competitive transmission 
53

development process. As of the preparation of this report, NYISO has yet to 

select a proposal.

Stakeholder 

Participation in 

Regional Transmission 

Planning Processes

(New Metric for 2017 

Report)

Stakeholder attendance at regional transmission planning meetings during 

FY2015 and FY2016 was relatively stable in both RTOs and non-RTOs. Most 

of the increases or decreases that staff found during this time were not 

dramatic. An encouraging finding is that, as envisioned by Order No. 1000, 

nonincumbents are participating in stakeholder meetings, with staff finding 

increases in nonincumbents’ levels of participation in four of the twelve 

transmission planning regions.

Metric to Indicate Whether Appropriate Levels of Transmission Infrastructure Exist

RTO/ISO Market Price 

Differential

Relatively high or low real-time LMPs (relative to high or low prices that 

prevailed in the Commission-jurisdictional RTO/ISO market) occurred 

persistently (i.e., for at least two years) at 1,482 generator or load points

since 2005.

Metrics to Permit Baseline Analyses of the Impacts of Policy Changes

Load-weighted 

Transmission 

Investment 

(Incremental)

Load-weighted transmission investment averages over all NERC regions for 

all years was over $2.00 per MWh of retail load, although investments are 

“lumpy” for most regions, as is typical for large infrastructure projects. 

Staff identified the largest load-weighted investments in TRE, exceeding 

$4.00 per MWh of retail load across all years. Staff found the smallest loadweighted investments (below $1.00 per MWh of retail load over all years) 

in FRCC.

Load-weighted Circuitmiles (Incremental)The findings are similar to the load-weighted transmission investment 

metric.

Load-Weighted Circuitmiles per Million 

Dollars of Investment 

(Incremental)

TRE has the highest load-weighted circuit-miles per million dollars of 

transmission investment across all years (2.1), compared to an average of 

1.0 load-weighted circuit-miles per million dollars of transmission 

investment for all NERC regions. RFC has the lowest load-weighted circuitmiles per million dollars of transmission investment across all years – 0.5

circuit-miles for every million dollars of transmission investment.