163 FERC ¶ 61,043

DEPARTMENT OF ENERGY

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 37

[Docket No. RM17-8-000; Order No. 845]

Reform of Generator Interconnection Procedures and Agreements

(Issued April 19, 2018)

AGENCY: Federal Energy Regulatory Commission

ACTION: Final rule.

SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission 

(Commission) is amending the pro forma Large Generator Interconnection Procedures

and the pro forma Large Generator Interconnection Agreement to improve certainty,

promote more informed interconnection, and enhance interconnection processes. The 

reforms are intended to ensure that the generator interconnection process is just and 

reasonable and not unduly discriminatory or preferential.

EFFECTIVE DATE: This rule will become effective 75 [Insert_Date days after 

publication in the FEDERAL REGISTER]

FOR FURTHER INFORMATION CONTACT:

Tony Dobbins (Technical Information)

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6630

Tony.Dobbins@ferc.gov

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 ii

Kathleen Ratcliff (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8018

Kathleen.Ratcliff@ferc.gov

Adam Pan (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6023

Adam.Pan@ferc.gov

SUPPLEMENTARY INFORMATION:

20180419-3062 FERC PDF (Unofficial) 04/19/2018
163 FERC ¶ 61,043

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Kevin J. McIntyre, Chairman;

 Cheryl A. LaFleur, Neil Chatterjee,

 Robert F. Powelson, and Richard Glick.

Reform of Generator Interconnection Procedures and 

Agreements

Docket No. RM17-8-000

ORDER NO. 845

FINAL RULE

(Issued April 19, 2018)

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction .................................................................................................................... 1.

II. Background ................................................................................................................... 9.

A. Order No. 2003......................................................................................................... 9.

B. 2008 Order on Interconnection Queuing Practices ................................................ 12.

C. 2015 American Wind Energy Association Petition and 2016 Technical Conference15.

D. Notice of Proposed Rulemaking ............................................................................ 18.

III. Overview and Need for Reform ................................................................................ 23.

A. Comments on Overall Approach............................................................................ 26.

B. Commission Determination ................................................................................... 36.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 2 -

IV. Proposed Reforms .................................................................................................... 45.

A. Improving Certainty for Interconnection Customers ............................................. 45.

1. Scheduled Periodic Restudies............................................................................. 46.

2. The Interconnection Customer’s Option to Build .............................................. 73.

3. Self-Funding by the Transmission Owner........................................................ 114.

4. Dispute Resolution............................................................................................ 123.

5. Capping Costs for Network Upgrades ............................................................. 172.

B. Promoting More Informed Interconnection ......................................................... 191.

1. Identification and Definition of Contingent Facilities ..................................... 192.

2. Transparency Regarding Study Models and Assumptions............................... 221.

3. Congestion and Curtailment Information ........................................................ 247.

4. Definition of Generating Facility in the Pro Forma LGIP and Pro Forma LGIA

............................................................................................................................... 273.

5. Interconnection Study Deadlines ..................................................................... 290.

6. Improving Coordination with Affected Systems.............................................. 335.

C. Enhancing Interconnection Processes .................................................................. 342.

1. Requesting Interconnection Service below Generating Facility Capacity....... 343.

2. Provisional Interconnection Service................................................................. 424.

3. Utilization of Surplus Interconnection Service ................................................ 453.

4. Material Modification and Incorporation of Advanced Technologies ............ 510.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 3 -

5. Modeling of Electric Storage Resources for Interconnection Studies 

............................................................................................................................... 537.

D. Other Issues .......................................................................................................... 545.

1. Whether Proposed Reforms Should Be Applied to Small Generation

............................................................................................................................... 545.

2. Issues Not Raised in the NOPR........................................................................ 550.

3. Process Considerations ................................................................................... 552.

4. Compliance and Implementation .................................................................... 554.

V. Information Collection Statement ............................................................................ 557.

VI. Environmental Analysis .......................................................................................... 563.

VII. Regulatory Flexibility Act ..................................................................................... 564.

VIII. Document Availability ......................................................................................... 566.

IX. Effective Date and Congressional Notification....................................................... 569.

Appendix A: List of Short Names of Commenters on the NOPR.................................... __

Appendix B: Compilation of Final Rule changes to the pro forma LGIP ....................... __

Appendix C: Compilation of Final Rule changes to the pro forma LGIA....................... __

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 4 -

I. Introduction

1. In this Final Rule, the Commission revises its pro forma Large Generator 

Interconnection Procedures (LGIP) and the pro forma Large Generator Interconnection 

Agreement (LGIA) to implement ten specific reforms. 

2. This Final Rule adopts reforms that are designed to improve certainty for 

interconnection customers, promote more informed interconnection decisions, and 

enhance the interconnection process. We believe the reforms adopted in this Final Rule

will benefit both interconnection customers and transmission providers. 1

 Specifically, 

we expect these reforms to provide interconnection customers with better information 

and more options for obtaining interconnection service such that there are fewer 

interconnection requests overall and fewer interconnection requests that are unlikely to 

reach commercial operation. As a result, we expect transmission providers will be able to 

focus on those requests that are most likely to reach commercial operation. 

3. First, in order to improve certainty for interconnection customers, this Final Rule: 

(1) removes the limitation that interconnection customers may only exercise the option to 

 1 Transmission provider:

shall mean the public utility (or its designated agent) that owns, controls, or 

operates transmission or distribution facilities used for the transmission of 

electricity in interstate commerce and provides transmission service under 

the Tariff. The term Transmission Provider should be read to include the 

Transmission Owner when the Transmission Owner is separate from the 

Transmission Provider.

Pro forma LGIP Section 1 (Definitions); pro forma LGIA Art. 1 (Definitions).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 5 -

build a transmission provider’s interconnection facilities and stand alone network 

upgrades in instances when the transmission provider cannot meet the dates proposed by 

the interconnection customer; and (2) requires that transmission providers establish 

interconnection dispute resolution procedures that allow a disputing party to unilaterally 

seek non-binding dispute resolution.

4. Second, to promote more informed interconnection decisions, this Final Rule: 

(1) requires transmission providers to outline and make public a method for determining 

contingent facilities; (2) requires transmission providers to list the specific study 

processes and assumptions for forming the network models used for interconnection 

studies; (3) revises the definition of “Generating Facility” to explicitly include electric 

storage resources; and (4) establishes reporting requirements for aggregate 

interconnection study performance.

5. The third area of reforms aims to enhance the interconnection process. To 

effectuate this goal, this Final Rule: (1) allows interconnection customers to request a 

level of interconnection service that is lower than their generating facility capacity; 

(2) requires transmission providers to allow for provisional interconnection agreements 

that provide for limited operation of a generating facility prior to completion of the full 

interconnection process; (3) requires transmission providers to create a process for 

interconnection customers to use surplus interconnection service at existing points of 

interconnection; and (4) requires transmission providers to set forth a procedure to allow 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 6 -

transmission providers to assess and, if necessary, study an interconnection customer’s 

technology changes without affecting the interconnection customer’s queued position. 

6. The pro forma LGIP and pro forma LGIA establish the terms and conditions 

under which public utilities that own, control, or operate facilities for transmitting electric 

energy in interstate commerce2 must provide interconnection service to large generating 

facilities.3

 Based on the record in this proceeding, we find it necessary under section 206 

of the Federal Power Act (FPA)4 to revise the pro forma LGIP and the pro forma LGIA 

to ensure that the rates, terms, and conditions pursuant to which public utilities provide 

interconnection service to large generating facilities are just and reasonable and not 

unduly discriminatory or preferential. 

 2 A public utility is a utility that owns, controls, or operates facilities used for 

transmitting electric energy in interstate commerce, as defined by the Federal Power Act 

(FPA). See 16 U.S.C. 824(e) (2012). A non-public utility that seeks voluntary 

compliance with the reciprocity condition of an Open Access Transmission Tariff 

(OATT) may satisfy that condition by filing an OATT, which includes the pro forma

LGIP and the pro forma LGIA. See Standardization of Generator Interconnection 

Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003) 

(Order No. 2003), order on reh’g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160, at 

P 774 (Order No. 2003-A), order on reh’g, Order No. 2003-B, FERC Stats. & Regs. 

¶ 31,171 (2004) (Order No. 2003-B), order on reh’g, Order No. 2003-C, FERC Stats. & 

Regs. ¶ 31,190 (2005) (Order No. 2003-C), aff'd sub nom. Nat’l Ass’n of Regulatory Util. 

Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008).

3 A large generating facility is “a Generating Facility having a Generating Facility 

Capacity of more than 20 [megawatts].” Pro forma LGIA Art. 1.

4 16 U.S.C. 824e (2012).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 7 -

7. Although the implementation of Order No. 2003 reduced undue discrimination in 

the generator interconnection process, some interconnection customers argue that they 

have continued to observe systemic inefficiencies and discriminatory practices.5

 In 

addition, there have been a number of developments that affect generator interconnection, 

including a changing resource mix driven by market forces and state and federal policies, 

and by the emergence of new technologies. At the same time, transmission providers 

have expressed concern that the interconnection study process can be difficult to manage 

because some interconnection customers submit requests for interconnection service 

associated with new generating facilities that the transmission providers maintain have 

little chance of reaching commercial operation. Consequently, we conclude that it is 

appropriate to adopt the revisions to the pro forma LGIP and the pro forma LGIA 

described in this Final Rule to mitigate existing concerns and to ensure that the pro forma

LGIP and pro forma LGIA are just and reasonable and not unduly discriminatory or 

preferential.

8. The reforms we adopt track many of the proposals set forth in the Notice of 

Proposed Rulemaking (NOPR) issued in this proceeding on December 15, 2016,6 with 

certain modifications. Among other things, we have revised aspects of the reforms 

pertaining to dispute resolution, contingent facilities, model and assumption transparency, 

 5 See, e.g., AWEA June 19, 2015 Petition at 2 (Petition).

6 Reform of Generator Interconnection Procedures and Agreements, 82 FR 4,464 

(Jan. 13, 2017), FERC Stats. & Regs. ¶ 32,719 (2017) (NOPR).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 8 -

study deadline metrics, provisional interconnection service, utilization of surplus 

interconnection service, and material modification.7

 Additionally, in this Final Rule, as 

discussed more fully below, we withdraw or decline to move forward with the NOPR 

proposals pertaining to scheduled periodic restudies, self-funding by the transmission 

owner, congestion and curtailment information, and modeling electric storage resources. 

The Commission also held a technical conference on April 3 and 4, 2018 to gather 

additional information regarding transmission providers’ and interconnection customers’ 

coordination with affected systems.8

 We conclude that the reforms adopted in this Final 

Rule will help improve the efficiency of processing interconnection requests for both 

transmission providers and interconnection customers, maintain reliability, balance the 

needs of interconnection customers and transmission owners, and remove barriers to 

resource development. 

 7 The pro forma LGIP defines Material Modification as “those modifications that 

have a material impact on the cost or timing of any Interconnection Request with a later 

queue priority date.” See pro forma LGIP Section 1.

8 Reform of Affected System Coordination in the Generator Interconnection 

Process, Docket No. AD18-8-000 and EDF Renewable Energy, Inc. v. Midcontinent 

Independent System Operator, Inc., Southwest Power Pool, Inc., and PJM 

Interconnection, L.L.C., Docket No. EL18-26-000, Notice of Technical Conference 

(Feb. 2, 2018).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 9 -

II. Background

A. Order No. 2003

9. In Order No. 2003, the Commission recognized a “pressing need for a single set of 

procedures for jurisdictional Transmission Providers and a single, uniformly applicable 

interconnection agreement for Large Generators.”9

 Prior to the issuance of Order 

No. 2003, the Commission addressed interconnection issues on a case-by-case basis 

through, for example, filings under section 205 of the FPA.10 

10. In Order No. 2003, the Commission noted that it had previously found that 

interconnection is a “critical component of open access transmission service and thus is 

subject to the requirement that utilities offer comparable service under the OATT.”11 The 

Commission found that a standard set of procedures “will minimize opportunities for 

undue discrimination and expedite the development of new generation, while protecting 

reliability and ensuring that rates are just and reasonable.”12 

11. Consequently, in Order No. 2003, the Commission required public utilities that 

own, control, or operate transmission facilities to file standard generator interconnection 

procedures and a standard agreement to provide interconnection service to generating 

 9 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 11.

10 See Id. P 10.

11 Id. P 9 (citing Tennessee Power Co., 90 FERC ¶ 61,238 (2000)).

12 Id. P 11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 10 -

facilities with a capacity greater than 20 megawatts (MW). To this end, the Commission 

adopted the pro forma LGIP and pro forma LGIA and required all public utilities subject 

to Order No. 2003 to modify their OATTs to incorporate the pro forma LGIP and pro 

forma LGIA. 

B. 2008 Order on Interconnection Queuing Practices

12. Although the issuance of Order No. 2003 was a significant step in minimizing 

undue discrimination in the generator interconnection process, some concerns with the 

process persisted, while some new concerns came to light. In response to concerns 

voiced to the Commission about interconnection queue management by regional 

transmission organizations and independent system operators (RTOs/ISOs) as well as 

other entities, the Commission held a technical conference on December 17, 2007, and 

issued a notice inviting further comments in response to such concerns.13 

13. The Commission issued an order on March 20, 2008 addressing interconnection 

queue issues based on the December 2007 technical conference and subsequent 

comments.14 The Commission acknowledged that delays in processing interconnection 

queues were more pronounced in RTOs/ISOs that were attracting significant new entry. 

 13 Interconnection Queuing Practices, Docket No. AD08-2-000, Notice of 

Technical Conference (Nov. 2, 2007).

14 Interconnection Queuing Practices, 122 FERC ¶ 61,252, at PP 16-18 (2008) 

(2008 Order).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 11 -

14. The Commission declined to impose generally applicable solutions, given the 

regional nature of some interconnection queue issues. However, the Commission 

provided guidance to assist RTOs/ISOs and their stakeholders in their efforts to improve 

the processing of interconnection queues.15 The Commission further stated that, although

it “may need to [impose solutions] if the RTOs and ISOs do not act themselves,” each 

region would have an opportunity to work with stakeholders to develop its own solutions 

through “consensus proposals.”16 Following the 2008 Order, RTOs/ISOs submitted 

multiple queue reform proposals to the Commission, some of which were intended to 

move away from a “first-come, first-served” approach to a “first-ready, first-served” 

approach.

C. 2015 American Wind Energy Association Petition and 2016 Technical 

Conference

15. On June 19, 2015, AWEA filed a petition in Docket No. RM15-21-000 requesting 

that the Commission revise the pro forma LGIP and pro forma LGIA. On July 7, 2015, 

the Commission issued a Notice of Petition for Rulemaking in that docket to seek public 

comment on the petition. The Commission received thirty-five comments and three 

answers and reply comments.

16. On May 13, 2016, Commission staff convened a technical conference (2016 

Technical Conference). The 2016 Technical Conference featured five panels on “The 

 15 2008 Order, 122 FERC ¶ 61,252 at PP 16-18.

16 Id. P 8.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 12 -

Current State of Generator Interconnection Queues,” “Transparency and Timing in the 

Interconnection Study Process,” “Certainty in Cost Estimates and Construction Time,” 

“Other Queue Coordination and Management Issues,” and “Interconnection of Electric 

Storage Resources.” The panels featured representatives from RTOs/ISOs, transmission 

owners from both RTO/ISO and non-RTO/ISO regions, renewable generation 

developers, electric storage resource developers, and other stakeholders.

17. On June 3, 2016, the Commission issued a Notice Inviting Post-Technical 

Conference Comments. The Commission received twenty-four post-technical conference 

comments.

D. Notice of Proposed Rulemaking

18. On December 15, 2016, the Commission issued the NOPR, proposing fourteen 

reforms focused on improving aspects of the pro forma LGIP and pro forma LGIA, the 

pro forma OATT, and the Commission’s regulations. The Commission also sought 

comment on, but did not propose, tariff or regulatory revisions on other issues. 

19. First, the Commission proposed four reforms to improve certainty by affording 

interconnection customers more predictability in the interconnection process. To 

accomplish this goal, the Commission proposed to: (1) revise the pro forma LGIP to 

require transmission providers that conduct cluster studies to move toward a scheduled, 

periodic restudy process; (2) remove from the pro forma LGIA the limitation that 

interconnection customers may only exercise the option to build transmission provider’s 

interconnection facilities and stand alone network upgrades if the transmission provider 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 13 -

cannot meet the dates proposed by the interconnection customer; (3) modify the pro 

forma LGIA to require mutual agreement between the transmission owner and 

interconnection customer for the transmission owner to opt to initially self-fund the costs 

of the construction of network upgrades; and (4) require that RTOs/ISOs establish dispute 

resolution procedures for interconnection disputes. The Commission also sought

comment on the extent to which a cap on the network upgrade costs for which 

interconnection customers are responsible can mitigate the potential for serial restudies 

without inappropriately shifting cost responsibility.

20. Second, the Commission proposed five reforms to improve transparency by 

providing more detailed information for the benefit of all participants in the 

interconnection process. The Commission proposed to: (1) require transmission 

providers to outline and make public a method for determining contingent facilities in 

their LGIPs and LGIAs based upon guiding principles in the NOPR; (2) require 

transmission providers to list in their LGIPs and on their Open Access Same-Time 

Information System (OASIS) sites the specific study processes and assumptions for 

forming the networking models used for interconnection studies; (3) require congestion 

and curtailment information to be posted in one location on each transmission provider’s 

OASIS site; (4) revise the definition of “Generating Facility” in the pro forma LGIP and 

pro forma LGIA to explicitly include electric storage resources; and (5) create a system 

of reporting requirements for aggregate interconnection study performance. The 

Commission also sought comment on proposals or additional steps that the Commission 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 14 -

could take to improve the resolution of issues that arise when a proposed interconnection 

impacts affected systems.17

21. Third, the Commission proposed five reforms to enhance interconnection 

processes by making use of underutilized existing interconnections, providing 

interconnection service earlier, or accommodating changes in the development process. 

In this area, the Commission proposed to: (1) allow interconnection customers to limit 

their requested level of interconnection service below their generating facility capacity; 

(2) require transmission providers to allow for provisional agreements so that 

interconnection customers can operate on a limited basis prior to completion of the full 

interconnection process; (3) require transmission providers to create a process for 

interconnection customers to utilize surplus interconnection service at existing 

interconnection points; (4) require transmission providers to set forth a separate 

procedure to allow transmission providers to assess and, if necessary, study an 

interconnection customer’s technology changes (e.g., incorporation of a newer turbine 

model) without a change to the interconnection customer’s queue position; and 

(5) require transmission providers to evaluate their methods for modeling electric storage 

resources for interconnection studies and report to the Commission why and how their 

existing practices are or are not sufficient.

 17 Affected system “shall mean an electric system other than the Transmission 

Provider’s Transmission System that may be affected by the proposed interconnect.” Pro 

forma LGIP Section 1 (Definitions); pro forma LGIA Art. 1 (Definitions).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 15 -

22. In response to the NOPR, sixty-three comments were filed.18 These comments 

have informed our determinations in this Final Rule. 

III. Overview and Need for Reform

23. In the NOPR, the Commission noted that the electric power industry has 

undergone numerous changes since Order No. 2003’s issuance. These changes are due to 

a variety of factors, such as the economics of new power generation being driven by 

sustained low natural gas prices, technological advances, and federal and state policies.

In the NOPR, the Commission found that such changes have implications for the 

interconnection process, for both interconnection customers and transmission providers.19

24. As a result of such changes and despite Commission efforts to improve the 

interconnection process, aspects of the generator interconnection process still provide 

cause for concern.20 For example, the Commission noted that many interconnection 

customers experience delays, and some interconnection queues have significant backlogs 

and long timelines.21 The Commission also recognized the recurring problem of latestage interconnection request withdrawals that lead to interconnection restudies and 

 18 Appendix A lists the entities that submitted comments on the NOPR and the 

shortened names used through this Final Rule to describe those entities. 

19 NOPR, FERC Stats. & Regs. ¶ 32,719 at PP 24-25.

20 Id. P 26.

21 Id. (citing, e.g., 2016 Technical Conference Tr. 210: 1-10 (discussion of delays 

up to a year)).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 16 -

consequent delays for lower-queued interconnection customers.22 The Commission 

further recognized that interconnection request withdrawals can lead to increased network 

upgrade cost responsibility for lower-queued interconnection customers, which, in turn, 

could result in cascading withdrawals. Moreover, the Commission stated that the lack of 

cost and timing certainty can hinder interconnection customers from obtaining financing, 

and that cost uncertainty is a significant obstacle, as some interconnection customers are 

less able to absorb unexpected and potentially higher costs.

25. In light of the changing industry and the aforementioned concerns, the 

Commission preliminarily found that the current interconnection process may hinder the 

timely development of new generation and, thereby, stifle competition in the wholesale 

markets, resulting in rates, terms, and conditions that are not just and reasonable or are 

unduly discriminatory or preferential. Additionally, the Commission preliminarily found 

that the interconnection study process may result in uncertainty and inaccurate 

information. Finally, the Commission preliminarily found that the potential for 

discriminatory interconnection processes exists as new technologies enter the power 

generation sphere.

 22 Id. (citing, e.g., 2016 Technical Conference Tr. 20:15-23 (discussion regarding 

MISO experiencing 50 percent withdrawal rates in many parts of the queue)).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 17 -

A. Comments on Overall Approach

26. A number of parties express support for the proposals in the NOPR.23 For 

example, TAPS “generally support[s] the proposed reforms” and states that the NOPR 

proposals “reasonably balance the needs of interconnection customers with the needs of 

load and transmission providers.”24 Generation Developers agree with the Commission’s 

preliminary findings and argue that the NOPR “addresses critical items that directly 

impact: (i) the development of new generation; (ii) the rates; terms and conditions of 

interconnection service; and (iii) the rates to customers for wholesale electric products.”25 

Joint Renewable Parties and ESA ask the Commission to quickly proceed with a final 

rulemaking.26 ESA states that Order No. 2003’s issuances predate the deployment of 

electric storage resources on the transmission system and that existing interconnection 

agreements and processes do not consider electric storage resources’ attributes.27 ESA

also states that the resulting undue uncertainty limits grid access for electric storage 

 23 See e.g., Community Renewable Energy Association 2017 Comments at 1-2; 

Joint Renewable Commenters 2017 Comments at 1; Generation Developers 2017 

Comments at 2; Renewable Energy Coalition 2017 Comments at 2; Renewable and 

Storage Associations 2017 Comments at 1-2; TAPS 2017 Comments at 1; TDU Systems 

2017 Comments at 3-13, 16-30 .

24 TAPS 2017 Comments at 1.

25 Generation Developers 2017 Comments at 2.

26 Joint Renewable Commenters 2017 Comments at 1; ESA 2017 Comments at 19.

27 Id. at 5-6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 18 -

resources and prevents them from providing low cost reliability services.28 ESA asserts, 

however, that the Commission’s NOPR proposals strike an effective balance between 

transmission provider flexibility and interconnection customer certainty.29

27. IECA supports the majority of the Commission’s proposed reforms.30 Invenergy 

supports many of the Commission’s proposed reforms but states that the NOPR “leaves 

fundamental causes of these [interconnection] delays unaddressed.”31 NEPOOL states 

that the proposed reforms could: (1) address the time ISO-NE takes to evaluate, study,

and approve new interconnections; and (2) facilitate market entry through more 

transparent and useful information regarding capacity and energy deliverability of 

potential new ISO-NE resources.32 Joint Renewable Parties contend that, despite existing 

rules, abusive interconnection practices impede the development of competitively 

supplied generation from renewable resources – particularly where the transmission 

 28 Id. at 6.

29 Id. at 19.

30 IECA 2017 Comments at 2.

31 Invenergy 2017 Comments at 1.

32 NEPOOL 2017 Comments at 5.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 19 -

provider is a vertically integrated utility.33 CAISO recognizes the need to nationalize 

many of the practices proposed in the NOPR.34

28. Other parties express some support for the NOPR proposals but object to specific 

reforms. For example, the Non-Public Utility Trade Associations “believe that certain of 

the NOPR’s proposed changes . . . hold the potential for improving transparency and 

process in a manner that may enhance cost certainty and predictability.”35 They object, 

however, to any changes that would impose cost caps for network upgrades and certain of 

the NOPR’s proposed reforms.36 Additionally, California Energy Storage Alliance 

commends CAISO for the reforms already implemented in that region and suggests that 

other RTOs/ISOs should adopt these reforms.37 However, California Energy Storage 

Alliance also suggests that each RTO/ISO should decide upon the proposed solutions for 

themselves rather than through the establishment of new national policy.38 

 33 Joint Renewable Parties 2017 Comments at 1-2.

34 CAISO 2017 Comments at 37.

35 Non-Profit Utility Trade Associations 2017 Comments at 4. 

36 Non-Profit Utility Trade Associations 2017 Comments at 4. These include the 

proposal for transparency regarding study models and assumptions, the proposal to allow 

interconnection customers to request interconnection service below generating facility 

capacity, and the proposal regarding the utilization of surplus interconnection service.

37 California Energy Storage Alliance 2017 Comments at 1-2.

38 Id. at 13.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 20 -

29. Other parties oppose some or all aspects of the NOPR. EEI argues that improving 

certainty is a responsibility shared by interconnection customers and transmission 

providers.39 It states that the volume of interconnection requests and the inherently 

speculative nature of generation development lead to queue delays, suspensions, and 

withdrawals.40 Imperial states that the NOPR could alter transmission owners’ rights and 

raises concerns regarding the feasibility of processing interconnection requests.41 ISONE states that several of the proposed reforms may be overly prescriptive and may have 

unintended negative consequences.42 Southern argues that the NOPR fails to address 

problems or delays caused or exacerbated by interconnection customers.43 

30. A number of parties object to proposals that they contend could compromise 

system reliability or shift risk and costs to transmission providers for factors beyond the 

transmission providers’ control.44 EEI requests that the Commission not deviate from its 

longstanding policy “that risks and costs associated with an interconnection request be 

 39 EEI 2017 Comments at 9. AEP and Duke support the comments being filed by 

EEI in this proceeding. AEP 2017 Comments at 1; Duke 2017 Comments at 2.

40 EEI 2017 Comments at 9.

41 Imperial 2017 Comments at 1.

42 ISO-NE 2017 Comments at 2.

43 Southern 2017 Comments at 4-5.

44 Non-Profit Utility Trade Associations 2017 Comments at 3; EEI 2017 

Comments at 9-10; Salt River 2017 Comments at 1-2; Southern 2017 Comments at 4; 

Xcel 2017 Comments at 3-4; APS 2017 Comments at 5.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 21 -

borne by the interconnection customer.”45 Similarly, Salt River states that the NOPR 

could undermine the Commission’s non-discrimination policy as well as the cost 

causation principle.46 Southern asks the Commission to reconsider those proposals that 

“lack balance and would shift risks and add bureaucratic responsibilities to” transmission 

providers.47 

31. APS states that it reviewed the NOPR against its current LGIP and LGIA and 

identified various revisions, in addition to those proposed in the NOPR, that would need 

to be made to comply with the proposals in the NOPR.48 APS suggests that the 

Commission re-evaluate its revisions and additions to ensure that there are not potentially 

conflicting or otherwise limiting provisions elsewhere in the pro forma LGIP and pro 

forma LGIA.49

32. Duke, ISO-NE, and Southern support the NOPR to the extent that it allows 

procedures to vary according to differing regional needs.50 Similarly, MISO TOs state 

that each RTO/ISO’s LGIP or LGIA is not simply a set of procedures tied to a pro forma

 45 EEI 2017 Comments at 9.

46 Salt River 2017 Comments at 1-2.

47 Southern 2017 Comments at 4.

48 APS 2017 Comments at 5-6.

49 Id. at 7.

50 Duke 2017 Comments at 29; ISO-NE 2017 Comments at 3; Southern 2017 

Comments at 3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 22 -

agreement that is amenable to generic modifications but is instead a complex series of 

arrangements, accepted by the Commission, developed in consultation with stakeholders, 

and designed to meet the RTO/ISO’s particular needs and circumstances.51

33. NEPOOL states that a Final Rule should allow for significant regional flexibility, 

especially for regions such as ISO-NE that have continued to improve their

interconnection processes and incorporated region-specific features into interconnection 

rules, such as ISO-NE’s Forward Capacity Market (FCM) and Elective Transmission 

Upgrade provisions. NEPOOL notes that, especially where interconnection provisions 

intersect with the FCM qualification process, the Commission should allow maximum 

flexibility to deviate from pro forma rules to avoid unintended disruptions to market 

participants. NEPOOL states that, to the extent that the proposals would disrupt the 

integrated interconnection and FCM process in New England, they would not support the 

adoption of the NOPR in New England.52 Similarly, because of the unique 

interconnection issues in each region and significant regional variations, NYISO asks the 

Commission to allow parties to tailor appropriate tariff revisions and demonstrate how 

they are addressing, or plan to address, the Commission’s concerns in a manner 

consistent with or superior to the NOPR’s proposed revisions.53

 51 MISO TOs 2017 Comments at 4. 

52 NEPOOL 2017 Comments at 6.

53 NYISO 2017 Comments at 1.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 23 -

34. Southern recommends that the Commission issue a revised notice of proposed 

rulemaking to allow for another round of notice and comment.54 EEI asks the 

Commission to convene technical conferences to seek feedback on the portions of the 

LGIA and LGIP that require review and revision to ensure consistency, completeness, 

and applicability.55 

35. Duke states that, to fulfill their obligations to ensure reliability service, 

“transmission providers must be afforded the time needed to: (i) carefully evaluate the 

potential reliability impact on [their] system[s] of proposed interconnections; and 

(ii) provide generators with reasonable estimates within the time needed to effectuate 

interconnection and necessary supporting upgrades.”56 

B. Commission Determination

36. After consideration of the NOPR comments, we conclude that certain revisions to 

interconnection processes are necessary and that the record supports the need for reform. 

Therefore, with the exception of the withdrawal of some reforms proposed in the NOPR 

and the modification of others, which are discussed in further detail below, we adopt the 

majority of the proposed revisions to the pro forma LGIP and the pro forma LGIA.57

 54 Southern 2017 Comments a 6.

55 EEI 2017 Comments at 76.

56 Duke 2017 Comments at 3.

57 The Final Rule revises the pro forma LGIP and pro forma LGIA in accordance 

with section 35.28(f)(1) of the Commission’s regulations, which provides: 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 24 -

37. Based on our analysis of the record, we adopt the NOPR’s preliminary findings.58 

We find that the record in this proceeding provides support for our findings that, without 

the reforms adopted here, the current interconnection process may hinder timely 

development of new generation,59 stifle competition,60 result in uncertainty61 and 

 

Every public utility that is required to have on file a non-discriminatory 

open access transmission tariff under this section must amend such tariff by 

adding the standard interconnection procedures and agreement and the 

standard small generator interconnection procedures and agreement 

required by Commission rulemaking proceedings promulgating and 

amending such interconnection procedures and agreements, or such other 

interconnection procedures and agreements as may be required by 

Commission rulemaking proceedings promulgating and amending the 

standard interconnection procedures and agreement and the standard small 

generator interconnection procedures and agreement. 

18 CFR 35.28(f)(1) (2017). See Reactive Power Requirements for Non-Synchronous 

Generation, Order No. 827, FERC Stats. & Regs. ¶ 31,385 (cross-referenced at 155 

FERC ¶ 61,277), order on clarification and reh'g, 157 FERC ¶ 61,003 (2016)

(Order No. 827). 

58 See supra P 26.

59 See, e.g., Invenergy 2017 Comments at 1 (stating that “many of the 

Commission’s proposed reforms. . . . are small steps in the right direction toward 

reducing the current chronic queue delays); FTC 2017 Comments at 2 (stating that it 

supports the Commission’s proposals “to facilitate generation interconnections to the 

grid).

60 See, e.g., FTC 2017 Comments at 2, 5 (stating that the NOPR “is a logical next 

step in [a] procompetitive process” and citing existing concerns about “anticompetitive 

behavior” in the interconnection process); 

61 See, e.g., AFPA 2017 Comments at 6 (stating that the option to build proposal 

“should increase cost certainty”). 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 25 -

inaccurate information,62 or potentially unduly discriminate against new technologies.63

Further, we find that, absent the reforms adopted in this Final Rule, the existing defects 

and inefficiencies in generator interconnection processes that we have described could 

become exacerbated, resulting in longer delays in generation development, higher costs 

to customers, more uncertainty in the process, and less competition in the market. For 

these reasons, we conclude that these reforms are necessary to ensure that rates, terms, 

and conditions of service are just and reasonable and are not unduly discriminatory or 

preferential. 

38. We disagree with commenters that take issue with the proposals to impose new 

requirements and responsibilities on transmission providers. For example, although EEI 

is correct that interconnection customers and transmission providers share responsibility 

to improve certainty and that generator interconnection, by its nature, involves some 

uncertainty, we find that current interconnection processes and agreements can create

unnecessary levels of uncertainty as discussed in more detail below. 

 62 See, e.g., id. at 4 (stating that the provisional interconnection service, utilization 

of surplus interconnection service, and material modification reforms “have the potential

to . . . improve the accuracy and reliability of interconnection studies”).

63 See, e.g. AWEA 2017 Comments at 4 (stating that “the current process . . . 

creates the potential for discriminatory interconnection processes as new technologies 

enter the generation sphere”); Public Interest Organizations 2017 Comments at 17 

(stating that they agree that “[i]nterconnection customers involving ‘new technologies 

may be affected more by process and information uncertainty than incumbents’”).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 26 -

39. Additionally, in response to Imperial’s concerns that the NOPR could alter

transmission owners’ rights, we note that, although the Final Rule creates new obligations 

and responsibilities for transmission providers and transmission owners, these changes 

are likely to improve the generator interconnection process for all involved parties. Also, 

we emphasize that the Final Rule does not relieve interconnection customers of their 

existing responsibilities. Nor does it alter the ownership structure established in Order 

No. 2003 for interconnection facilities or network upgrades. Although some commenters 

argue that the NOPR’s proposed reforms do not increase the responsibilities of, or 

directly address delays created by, interconnection customers, we believe that the reforms 

adopted in this Final Rule should help improve the efficiency of processing 

interconnection requests for both transmission providers and interconnection customers. 

40. We also disagree with arguments that the NOPR will compromise system 

reliability. We find that, for those reforms for which commenters have expressed 

reliability concerns, the Commission has either maintained existing safeguards or 

provided transmission providers with sufficient discretion to ensure that the reforms will

not interfere with system reliability. For example, as discussed more fully below, the 

option to build, as modified by this Final Rule, does not relax any of the safeguards that 

the Commission first established in Order No. 2003. Additionally with regard to the 

reforms that allow interconnection customers to request interconnection service below 

generating facility capacity and to utilize surplus interconnection service, transmission 

providers have the ability to require control technologies or to establish conditions 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 27 -

necessary for interconnection customers to exercise these options without compromising 

reliability. 

41. In response to comments by EEI and Salt River, among others, that the NOPR will 

shift costs traditionally borne by the interconnection customer, we note that this Final 

Rule makes no changes with regard to interconnection customers’ cost responsibilities for 

network upgrades and that the Commission is taking no further action on the issue of cost 

caps. Additionally, in response to Southern’s concerns that the NOPR proposals lack 

balance, it is our belief that improved generator interconnection processes will benefit 

both transmission providers and interconnection customers.

42. Although APS argues that the NOPR necessitates additional pro forma LGIP and 

pro forma LGIA revisions, it neglects to further describe or explain the particulars of 

such revisions. The revisions to the pro forma LGIP and the pro forma LGIA adopted 

here are intended to effectuate the reforms discussed in this Final Rule and to integrate 

the adopted reforms so that they do not unintentionally conflict with other portions of the 

pro forma LGIP and the pro forma LGIA. Nonetheless, to the extent that a particular 

transmission provider believes that additional revisions to its LGIP or LGIA are 

necessary, it may propose such revisions in a filing pursuant to section 205 of the FPA. 

43. Finally, we note that a number of commenters seek regional flexibility in 

complying with the rule to accommodate regional needs. In Order No. 2003, the 

Commission stated that if, on compliance, a non-RTO/ISO transmission provider “offers 

a variation from the Final Rule LGIP and Final Rule LGIA and the variation is in 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 28 -

response to established . . . reliability requirements, then it may seek to justify its 

variation using the regional difference rationale.”64 However, if a non-RTO/ISO seeks a 

variation “for any other reason,” it must present its justification for the variation as 

“consistent with or superior to” the pro forma LGIA or pro forma LGIP.65 The 

Commission went on to say that, for RTOs/ISOs, it would allow independent entity 

variations for pricing and non-pricing provisions, and that RTOs/ISOs “shall have greater 

flexibility to customize [their] interconnection procedures and agreements to fit regional 

needs.”66 In this Final Rule, we make no changes to the variations allowed by Order No. 

2003. Therefore, on compliance, transmission providers may argue that they qualify for 

the above-mentioned variations from the requirements of this Final Rule.

44. We decline to adopt Southern’s recommendation that we issue a revised notice of

proposed rulemaking, as well as EEI’s proposal to convene general generator 

interconnection technical conferences, apart from the technical conference concerning

affected systems discussed further below. We note that the process used in this 

proceeding has included a number of opportunities to narrow the issues for discussion 

and to provide comments. As stated, the Commission noticed AWEA’s original 2015 

petition for comment, held a technical conference in May 2016, and issued subsequent 

 64 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 826. 

65 Id.

66 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 29 -

questions for which it requested comment, and sought comments on the NOPR. 

Therefore, we do not think additional steps are necessary in this proceeding at this time. 

In response to Duke’s requests that transmission providers need to have adequate time to 

evaluate reliability impacts and to provide generators “with reasonable estimates within 

the time needed to effectuate interconnection and necessary supporting upgrades,” we 

point out that this Final Rule neither changes the deadlines for interconnection studies nor 

eliminates the reasonable efforts standard or the deadlines for construction of facilities 

necessary to interconnect a particular large generating facility.67

IV. Proposed Reforms

A. Improving Certainty for Interconnection Customers

45. The Commission proposed reforms intended to improve certainty by providing 

interconnection customers more predictability in the interconnection process, including 

more predictability regarding the costs and the timing of interconnecting to the 

transmission system. In addition to the proposed reforms, the Commission sought

comment on the extent to which capping interconnection customer cost responsibility for 

actual network upgrade costs to some margin above estimated network upgrade costs 

could mitigate the potential for serial restudies without inappropriately shifting cost 

responsibility.

 67 Duke 2017 Comments at 3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 30 -

1. Scheduled Periodic Restudies

a. NOPR Proposal 

46. The Commission proposed to revise the pro forma LGIP to require transmission 

providers that conduct cluster studies68 to conduct restudies on a scheduled, periodic 

basis (e.g., annually, semi-annually, quarterly, or a set number of days after the 

completion of the cluster study).69 Specifically, the Commission proposed to require 

each transmission provider that conducts cluster studies to revise Sections 6.4, 7.6, and 

8.5 of the pro forma LGIP with time frames for periodic restudies.70 The Commission 

also sought comment on: (1) if the Commission’s proposal were adopted, whether 

transmission providers that conduct cluster studies should be allowed to retain some 

discretion to conduct a restudy outside of the established schedule at the request of 

interconnection customers or under specific circumstances that make such schedule 

deviations necessary; and (2) when this discretion should be restricted and the 

circumstances under which such schedule deviations should be allowed.71 The 

 68 Clustering allows transmission providers to simultaneously study all 

interconnection requests received during a specified period. See Order No. 2003, FERC 

Stats. & Regs. ¶ 31,146 at PP 149-156.

69 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 46.

70 Id. PP 48-49.

71 Id. P 50.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 31 -

Commission also sought comment on whether there are improvements to the pro forma

LGIP necessary to clarify events that would trigger a restudy (restudy triggers).72 

b. Comments

47. Several commenters argue that, although restudies are often necessary, repeated 

restudies conducted at irregular intervals create cost and timing uncertainty for 

interconnection customers, impose delays on the process, and put development of new 

generation at risk, despite reductions in some RTOs/ISOs’ interconnection requests and 

the use of cluster studies.73 Some of these commenters assert that, because the 

withdrawal of higher-queued interconnection requests can create cascading restudies of 

lower-queued interconnection requests, regularly scheduled restudies would help 

alleviate the need for multiple ad hoc restudies, thereby helping to reduce uncertainty and 

delays.74 

48. Some commenters note that the unpredictable start and stop of the generation 

interconnection study process has caused project cancellations because delays in 

obtaining an LGIA or small generator interconnection agreement (SGIA) can affect

 72 Id. P 51.

73 AFPA 2017 Comments at 5; AVANGRID 2017 Comments at 5-6; AWEA 2017 

Comments at 8-9; Generation Developers 2017 Comments at 6; NextEra 2017 Comments 

at 6; IECA 2017 Comments at 2.

74 AFPA 2017 Comments at 5; AVANGRID 2017 Comments at 5-6; AWEA 2017 

Comments at 8-9; Generation Developers 2017 Comments at 6; NextEra 2017 Comments 

at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 32 -

project financing.75 NextEra explains that, in some cases, restudies have taken years to 

complete due to projects withdrawing from the queue, transmission project changes, 

inadequate transmission provider resources, and other factors.76 NextEra further notes 

that transmission providers then have to restart the study with the remaining members of 

the interconnection customer study group. NextEra contends that this occurrence can 

delay the interconnection customer’s receipt of its study results and finalized GIA, which 

could prevent it from accurately evaluating the timing and costs of necessary network 

upgrades.77 NextEra suggests that a regularly scheduled restudy process will allow 

transmission providers to consider relevant changes on a set timetable and reduce the

need for ad hoc restudies. NextEra also argues that, by ensuring that studies are 

completed, an interconnection customer will receive some network upgrade information 

that it would not receive if studies are restarted or delayed.78

49. AWEA states that requiring transmission providers to identify the frequency of 

restudies of a cluster study and post the dates of these scheduled restudies on OASIS will 

increase certainty and give transmission providers flexibility.79 NextEra suggests that 

 75 Generation Developers 2017 Comments at 6; NextEra 2017 Comments at 6.

76 NextEra 2017 Comments at 6.

77 Id.

78 Id. at 6 -7.

79 AWEA 2017 Comments at 9-10. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 33 -

periodic restudies should be conducted every six months, noting that, with that frequency,

there should be little need for intervening studies, and yearly studies would be frequent 

enough.80 

50. Xcel supports the Commission’s proposal but requests that the Commission clarify 

that restudies will commence within a specified time period (e.g., ninety days) of a 

triggering event, instead of after the completion of the cluster study. Xcel suggests that 

explicitly defining triggering events is not necessary and notes that determination of 

triggering events tends to vary between regions.81 

51. AVANGRID recommends that transmission providers provide cost estimates for 

the proposed scheduled periodic restudies for interconnection customers with 

interconnection requests included in a group or cluster, instead of providing 

interconnection customers estimates for the initial study only.82 AFPA supports regular 

cluster studies but believes that RTOs/ISOs should have the ability to avoid restudies and 

the associated costs where they can demonstrate no material change in relevant 

assumptions or inputs.83

 80 NextEra 2017 Comments at 7.

81 Xcel 2017 Comments at 7.

82 AVANGRID 2017 comments at 5-6.

83 AFPA 2017 Comments at 3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 34 -

52. APPA/LPPC states that a schedule detailing periodic restudies may provide added 

predictability that could be valuable to project developers.84 However, it argues that, 

where interconnection queues are short, there may be no need to await specified dates to 

perform restudies, and in those circumstances, a fixed schedule may hamper the 

interconnection process.85

53. Duke states that it does not regularly conduct cluster studies, but it supports the 

proposal and the flexibility provided for transmission providers that do conduct cluster 

studies.86 Southern agrees with the Commission that transmission providers that do not 

conduct interconnection studies in clusters should not have to perform periodic 

restudies.87

54. CAISO cautions that periodic restudies are effective in CAISO because it uses a 

cluster study approach with firm cost caps, and transmission owners finance network 

upgrade costs beyond these cost caps.88 CAISO asserts that only with both of these 

mechanisms is it reasonable for interconnection customers to wait for an annual restudy 

to find out how their projects may have been affected by project withdrawals over the 

 84 APPA/LPPC 2017 Comments at 5.

85 Id. 

86 Duke 2017 Comments at 4.

87 Southern 2017 Comments at 9.

88 CAISO 2017 Comments at 7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 35 -

course of the prior year.89 CAISO states that, with the transmission owners picking up 

any costs above the cost cap, withdrawals can decrease or increase interconnection 

customers’ network upgrade costs depending upon whether the upgrade is still necessary

for other interconnection customers.90 CAISO states that costs decrease when sufficient 

interconnection customers withdraw and obviate the need for a network upgrade. 

However, CAISO states that costs may increase if the network upgrade is still necessary 

but fewer interconnection customers remain to finance it.91

55. CAISO asserts that imposing scheduled periodic restudies in other RTOs/ISOs that 

do not share CAISO’s market features may be problematic.92 CAISO states that, as ISONE and others pointed out in response to the AWEA petition, an interconnection 

customer must wait for a periodic restudy to find out that its project costs have increased 

dramatically.93 

56. CAISO cautions that the Commission should consider the various proposed 

reforms in concert with each other, including changes to schedules in periodic studies,

 89 Id. 

90 Id. at 7-8.

91 Id. at 8.

92 Id.

93 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 36 -

because cost caps and the definition of contingent facilities also have a significant impact 

on the efficacy of periodic restudies.94 

57. SoCal Edison and PG&E state that scheduled periodic annual restudies are the 

standard practice for CAISO and that they appreciate the predictability of CAISO’s 

restudy process.95

58. Generation Developers support the Commission’s proposal, but they assert that 

semi-annual or quarterly restudies could be problematic and unpredictable, especially if 

the RTO/ISO has missed the study completion deadline listed in its tariff.96 Similarly,

EDP indicates that, although each transmission provider should be able to establish its 

own unique schedule, a pro forma restudy schedule should be developed that serves as

the default schedule unless a transmission provider demonstrates the need for an 

alternative schedule.97 

59. Invenergy states that restudies can be useful but should not add unnecessary time 

and expense, citing the substantial time differences for restudies within several 

RTOs/ISOs.98 According to Invenergy, an important missing element in the restudy 

 94 Id.

95 PG&E 2017 Comments at 3 (citing CAISO, eTariff, FERC Electric Tariff, 

OATT, app. DD Section 7.4 (6.0.0)).

96 Generation Developers 2017 Comments at 6-7.

97 EDP 2017 Comments at 3.

98 Invenergy 2017 Comments at 5

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 37 -

process is transparency for the interconnection customer. Invenergy suggests a 

requirement that RTOs/ISOs inform the customer of the restudy prior to its initiation. 

Invenergy suggests that the transmission provider should provide information in 

sufficient detail so that the customer can understand the need for restudy, including 

whether there is an addition or change to the necessary network upgrades.99 

60. Several commenters oppose the Commission’s proposed revisions to require 

transmission providers that conduct cluster studies to conduct restudies on a scheduled, 

periodic basis. As discussed further below, commenters state that the Commission’s 

proposal may cause unnecessary delays, may not be appropriate in each region, and may

unduly burden smaller transmission providers.

61. PJM contends that the NOPR may have the opposite effect from what is intended 

by causing unnecessary delays.100 PJM argues that, in a situation where a project 

withdraws during the system impact study, or prior to the completion of the facilities 

study, and restudy is necessary, the NOPR proposal would harm all subsequently queued

projects. PJM explains that these projects would remain in a “holding pattern” until the 

 99 Id.

100 PJM 2017 Comments at 5.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 38 -

scheduled, periodic restudy is complete.101 PJM states that improvements in transparency 

can achieve the intended goals of the NOPR proposal without the drawbacks.102

62. PJM explains that although it performs cluster studies at the feasibility and system 

impact study stages, it does not conduct restudies at the feasibility study stage because of 

the broad scope of the feasibility study and because the system impact study can account 

for withdrawals.103 However, PJM states that it does not oppose conducting periodic 

restudies within a cluster after the issuance of a system impact study report and receipt of 

an executed facilities study agreement from the projects that need to be restudied.104 PJM 

states that it could commit to post such restudy dates on its website.105 

63. PJM asserts that the pro forma LGIP appropriately requires restudied 

interconnection customers to bear the cost of restudy.106 PJM also states that, at the 

facilities study stage, interconnection customers should bear all costs, including any 

impacts caused to lower-queued projects by changes made to a higher-queued project.107

 101 Id. at 4-5.

102 Id. at 5.

103 Id. at 3-4.

104 Id. at 4.

105 Id.

106 Id. at 6 (citing pro forma LGIP Sections 6.4, 7.6, and 8.5).

107 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 39 -

64. PJM opposes the NOPR’s 45/60 day restudy timeframe because restudies “come 

in all sizes and complexities.”108 PJM states that committing to a strict timeframe would 

then necessitate granting the transmission provider the flexibility to extend the timeframe 

beyond the study period found in the tariff, regardless of whether a transmission provider 

is serially processing a restudy or restudying a cluster.109 PJM maintains that reporting 

and sharing of status information with the affected parties is more effective than 

inflexible restudy deadlines.110

65. NYISO and Indicated NYTOs state that NYISO does not perform restudies in its

Standard Large Facility Interconnection Procedures to modify the upgrades required for 

projects or their cost estimates based on changes to higher-queued projects or system 

conditions.111 

66. ISO-NE and NEPOOL state that the Commission should not adopt the NOPR 

proposal because it may not be appropriate in each region.112 As an example, ISO-NE 

states that the recent revisions to its interconnection procedures incorporate a clustering 

 108 Id. at 5.

109 Id.

110 Id. at 5-6.

111 NYISO 2017 Comments at 13; Indicated NYTOs 2017 Comments at 4-5.

112 ISO-NE 2017 Comments at 15-16.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 40 -

approach that does not include scheduled restudies.113 ISO-NE argues that a scheduled 

restudy would result in less certainty for interconnection customers because it would 

delay the study outcome. On the other hand, ISO-NE states that its clustering approach 

would still meet the objectives of the NOPR by establishing milestones that can serve as 

decision points for interconnection customers.114 

67. Specifically, ISO-NE states that its proposed two-phased cluster study structure is 

designed to provide interconnection customers with information regarding the likely 

outcome of the cluster study in the first phase. ISO-NE states that interconnection 

customers could then determine whether they would like to proceed to the second-phase, 

move to the end of the interconnection queue, or withdraw from the interconnection 

queue.115 ISO-NE states that its cluster study approach minimizes the need for restudy 

through provisions that allow for the participation of lower-queued requests in the event 

of withdrawals.116

68. MISO, MISO TOs, ITC, and MidAmerican state that MISO’s 2016 queue reform 

proposal addressed unstructured and repeated restudies. MISO asserts that, consistent 

with the independent entity variation standard, its revised procedures are now in effect 

 113 Id. at 16.

114 Id. at 16-17.

115 Id.

116 Id. at 17.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 41 -

and should be implemented.117 MISO states that the Commission should not deviate 

from its current requirement that allows transmission providers to use reasonable efforts. 

It also contends that the Commission should not impose inflexible timeframes on 

restudies, and asserts that a one-size-fits-all approach would not be appropriate here. 

MISO notes that in RTOs/ISOs, the interconnection process involves many parties, and 

imposing inflexible restudy deadlines would be counter-productive, particularly where 

delays are caused by third parties or by factors outside of the RTO/ISO’s control.118 ITC 

urges the Commission to accept MISO’s Definitive Planning Phase119 process, which 

addresses restudies, as consistent with or superior to the revisions made to the pro forma

LGIP in this proceeding.120

69. Imperial states that the Commission’s proposal to require scheduled, periodic 

restudies for cluster studies would unduly burden smaller transmission providers.121 

Imperial states that transmission providers may not be willing to memorialize an 

aggressive restudy commitment if they expect to experience variations in the number of 

 117 MISO 2017 Comments at 12-13.

118 Id. at 13-14.

119 Under MISO’s Definitive Planning Phase process, MISO performs three 

sequential system impact studies after successive milestone payments to account for 

queue withdrawals.

120 ITC 2017 Comments at 6.

121 Imperial 2017 Comments at 15.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 42 -

interconnection requests that would be appropriate for cluster studies or restudies over a 

period of time.122 Additionally, for smaller transmission providers that conduct few

restudies, such a proposal may be less efficient than studying each project individually as 

the need to restudy arises.123 Therefore, Imperial requests that the Commission allow 

transmission providers, particularly smaller transmission providers, the discretion to 

conduct periodic cluster restudies within their selected timeframes.124

c. Commission Determination

70. We decline to adopt the proposal in the NOPR to require transmission providers 

that conduct cluster studies to conduct scheduled periodic restudies. We find that the 

record does not support a finding that cascading restudies are an issue that the Final Rule 

should address by adopting the proposal on scheduled periodic restudies. We recognize 

that scheduled periodic restudies may provide timing certainty for interconnection queues 

that experience cascading restudies, but the record does not suggest that this is a 

significant problem in all or many regions’ interconnection queues where cluster studies 

are used. We agree with the commenters’ concern that requiring scheduled periodic 

restudies would unnecessarily constrain the restudy process for transmission providers 

that are not experiencing cascading restudies. As explained in the RTO/ISO comments 

 122 Id. at 16.

123 Id.

124 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 43 -

on this issue, existing variations in interconnection processes suggest that a one-size-fitsall approach is not appropriate at this time. For example, CAISO’s firm cost caps allow 

customers to know in advance that network upgrade costs will not exceed the cost cap, 

even if a restudy occurs. In other RTOs/ISOs, however, adopting CAISO’s annual 

restudy approach would require interconnection customers to wait for a scheduled 

periodic restudy to learn of cost changes. 

71. We note that restudies are sometimes necessary due to a number of factors, 

including project withdrawals, modifications of higher-queued projects subject to section 

4.4 of the LGIP, and/or a change to a project’s point of interconnection.125 We agree with

the comments that, regardless of the restudy schedule, restudies that result from such

actions by a higher-queued interconnection customer may not be foreseeable or 

preventable. Implementing a scheduled periodic restudy process may reduce timing 

uncertainty by creating decision points, but it would not eliminate the cost uncertainty 

created by the withdrawal or modification of a higher-queued project. In that case, 

restudy would be necessary to recalculate network upgrade cost distribution among the 

remaining customers, and restricting the timing of these restudies may cause, rather than

prevent, unnecessary delays. 

72. Accordingly, we decline to adopt revisions to the pro forma LGIP that would 

require transmission providers that conduct cluster studies to establish a schedule for 

 125 Pro forma LGIP Sections 6.4, 7.6, and 8.5

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 44 -

conducting periodic restudies. We also decline to adopt revisions to the pro forma LGIP 

to address the transmission provider’s discretion to conduct restudies outside of an 

established schedule, and decline to propose revisions to the restudy triggers in the pro 

forma LGIP. 

2. The Interconnection Customer’s Option to Build

a. NOPR Proposal 

73. In the NOPR, the Commission proposed modifications to the pro forma LGIA to 

allow interconnection customers to exercise the option to build regardless of whether the 

transmission provider can meet the interconnection customer’s proposed dates.126 

74. Generally, in the interconnection process, the transmission provider is responsible 

for the construction of all network upgrades and the transmission provider’s 

interconnection facilities. Under article 5.1.3 of the current pro forma LGIA, however,

the interconnection customer has the option to build the transmission provider’s 

interconnection facilities127 and stand alone network upgrades,128 but only if the 

 126 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 52.

127 According to the pro forma LGIA:

Transmission Provider's Interconnection Facilities shall mean all 

facilities and equipment owned, controlled or operated by the 

Transmission Provider from the Point of Change of Ownership to 

the Point of Interconnection as identified in Appendix A to the 

Standard Large Generator Interconnection Agreement, including any 

modifications, additions or upgrades to such facilities and 

equipment. Transmission Provider's Interconnection Facilities are 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 45 -

transmission provider notifies the interconnection customer that the transmission provider 

cannot complete construction of such facilities by the interconnection customer’s 

proposed in-service date, initial synchronization date, or commercial operation date; this 

is termed the “option to build.” To expand the opportunity for interconnection customers 

to exercise the option to build to reduce costs or complete construction more quickly, the 

Commission proposed in the NOPR to allow the interconnection customer to exercise the 

option to build regardless of whether the transmission provider finds the interconnection 

customer’s selected in-service date, initial synchronization date, and commercial 

operation date acceptable. 

75. Under the current pro forma LGIA, unless otherwise mutually agreed to by the 

parties, the interconnection customer selects the “In-Service Date, Initial Synchronization 

 

sole use facilities and shall not include Distribution Upgrades, Stand 

Alone Network Upgrades or Network Upgrades.

Pro forma LGIA Art. 1.

128 Stand alone network upgrades:

shall mean Network Upgrades that an Interconnection Customer 

may construct without affecting day-to-day operations of the 

Transmission System during their construction. Both the 

Transmission Provider and the Interconnection Customer must agree 

as to what constitutes Stand Alone Network Upgrades and identify 

them in Appendix A to the Standard Large Generator 

Interconnection Agreement.

Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 46 -

Date, and Commercial Date”129 and “either the Standard Option or Alternative 

Option.”130 Under both of these options, the transmission provider is responsible for 

construction of the transmission provider’s interconnection facilities and all network 

upgrades.

76. Under the “standard option,” the transmission provider “shall construct the 

Transmission Provider’s Interconnection Facilities and Network Upgrades using 

Reasonable Efforts to complete the construction by the dates designated by the 

Interconnection Customer.”131 Under the “alternate option,” the transmission provider 

may be liable for liquidated damages if it does not construct the transmission provider’s 

interconnection facilities and “Network Upgrades according to the construction 

completion dates established by the Interconnection Customer.”132 

 129 The In-Service Date is “the date upon which the Interconnection Customer 

reasonably expects it will be ready to begin use of the Transmission Provider's 

Interconnection Facilities to obtain back feed power.” Id. The Initial Synchronization 

Date is “the date upon which the Generating Facility is initially synchronized and upon 

which Trial Operation begins.” Id. The Commercial Operation Date is “the date on 

which the Generating Facility commences Commercial Operation as agreed to by the 

Parties pursuant to Appendix E to the Standard Large Generator Interconnection 

Agreement.” Id.

130 Pro forma LGIA Art. 5.1.

131 Pro forma LGIA Art. 5.1.1.

132 The transmission provider has the ability to decline this option within 30 days 

of the LGIA’s execution.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 47 -

77. Under the current pro forma LGIA, there are two additional options for assuming 

responsibility for constructing certain facilities, which are available if the transmission 

provider informs the interconnection customer that it cannot meet proposed construction 

completion dates: the option to build, described above, and the “negotiated option.”133 

The negotiated option, described in article 5.1.4 of the pro forma LGIA, applies if the 

transmission provider cannot meet the interconnection customer’s proposed dates but the 

interconnection customer does not want to assume responsibility for construction of the 

transmission provider’s interconnection facilities and stand alone network upgrades. In 

this case, the transmission provider would construct the transmission provider’s 

interconnection facilities and all network upgrades.

78. In the NOPR, the Commission proposed modifications to articles 5.1, 5.1.3, and 

5.1.4 of the pro forma LGIA to allow interconnection customers to exercise the option to 

build with respect to the transmission provider’s interconnection facilities and stand alone 

network upgrades regardless of whether the transmission provider can meet the 

interconnection customer’s proposed dates. Specifically, the Commission proposed to 

modify the language in article 5.1 of the pro forma LGIA as follows (with proposed 

deletions in brackets and proposed additions in italics):

Options. Unless otherwise mutually agreed to between the Parties, 

Interconnection Customer shall select the In-Service Date, Initial 

Synchronization Date, and Commercial Operation Date; and either the 

 133 Pro forma LGIA Art. 5.1.4.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 48 -

Standard Option or Alternate Option set forth below [for completion of 

Transmission Provider's Interconnection Facilities and Network Upgrades, 

as set forth in Appendix A, Interconnection Facilities and Network 

Upgrades,] and such dates and selected option shall be set forth in 

Appendix B, Milestones. At the same time, Interconnection Customer shall 

indicate whether it elects to exercise the Option to Build set forth in article 

5.1.3 below. If the dates designated by Interconnection Customer are not 

acceptable to Transmission Provider, Transmission Provider shall so notify 

Interconnection Customer within thirty (30) Calendar Days. Upon receipt 

of the notification that Interconnection Customer’s designated dates are not 

acceptable to Transmission Provider, the Interconnection Customer shall 

notify the Transmission Provider within thirty (30) Calendar Days whether 

it elects to exercise the Option to Build if it has not already elected to 

exercise the Option to Build.134

79. The Commission also proposed to modify the language in article 5.1.3 of the pro 

forma LGIA as follows (with proposed deletions in brackets):

Option to Build. [If the dates designated by Interconnection Customer are 

not acceptable to Transmission Provider, Transmission Provider shall so 

notify Interconnection Customer within thirty (30) Calendar Days and 

unless the Parties agree otherwise,] Interconnection Customer shall have 

the option to assume responsibility for the design, procurement and 

construction of Transmission Provider's Interconnection Facilities and 

Stand Alone Network Upgrades on the dates specified in article 5.1.2. 

Transmission Provider and Interconnection Customer must agree as to what 

constitutes Stand Alone Network Upgrades and identify such Stand Alone 

Network Upgrades in Appendix A. Except for Stand Alone Network 

Upgrades, Interconnection Customer shall have no right to construct 

Network Upgrades under this option.

80. The Commission stated that, given the changes proposed above, revisions to the 

negotiated option were necessary because the negotiated option references the current 

 134 In this Final Rule, the adopted language differs slightly from the NOPR 

language because we remove the word “the” before “Transmission Provider” in the final 

sentence of this article.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 49 -

limitations on the option to build.135 For this reason, it proposed to revise the negotiated 

option to remove references to limitations on the option to build, to address scenarios in 

which an interconnection customer exercises the option to build and still wishes to 

negotiate completion times for network upgrades that are not stand alone network 

upgrades, and to address circumstances in which the interconnection customer does not 

wish to exercise the option to build. The Commission asserted that such revisions are 

necessary because the ability to exercise the option to build would no longer be 

contingent upon a transmission provider’s inability to meet the interconnection 

customer’s proposed dates. However, the Commission noted that the negotiated option 

must also contemplate the possibility that the transmission provider does not agree to the 

interconnection customer’s proposed dates as to network upgrades that are not stand 

alone. That is, even if the interconnection customer elects to exercise the option to build, 

the transmission provider would still be responsible for the design, procurement, and 

construction of network upgrades that are not stand alone network upgrades. 

81. Therefore, the Commission also proposed to modify the language in article 5.1.4 

of the pro forma LGIA as follows (with proposed deletions in brackets and proposed 

additions in italics): 

Negotiated Option. [If Interconnection Customer elects not to exercise its 

option under Article 5.1.3, Option to Build, Interconnection Customer shall 

so notify Transmission Provider within thirty (30) Calendar Days, and] If 

 135 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 62.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 50 -

the dates designated by Interconnection Customer are not acceptable to 

Transmission Provider, the Parties shall in good faith attempt to negotiate 

terms and conditions (including revision of the specified dates and 

liquidated damages, the provision of incentives, or the procurement and 

construction of [a portion of Transmission Provider's Interconnection 

Facilities and Stand Alone Network Upgrades by Interconnection 

Customer] all facilities other than Transmission Provider’s Interconnection 

Facilities and Stand Alone Network Upgrades if the Interconnection 

Customer elects to exercise the Option to Build under article 5.1.3)

[pursuant to which Transmission Provider is responsible for the design, 

procurement and construction of Transmission Provider’s Interconnection 

Facilities and Network Upgrades]. If the Parties are unable to reach 

agreement on such terms and conditions, then, pursuant to article 5.1.1 

(Standard Option), Transmission Provider shall assume responsibility for 

the design, procurement and construction of [Transmission Provider's 

Interconnection Facilities and Network Upgrades] all facilities other than 

Transmission Provider’s Interconnection Facilities and Stand Alone 

Network Upgrades if the Interconnection Customer elects to exercise the 

Option to Build [pursuant to article 5.1.1, Standard Option]. 

82. Consistent with article 5.2 of the current pro forma LGIA, the interconnection 

customer and transmission provider (and transmission owner, if applicable) would 

continue to reach agreement on the design and construction of the transmission provider’s 

interconnection facilities and stand alone network upgrades; the Commission proposed no 

changes to article 5.2 in the NOPR.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 51 -

b. General

i. Comments

83. Many commenters support this proposal.136 AWEA states that the current 

restriction on when the option to build can be exercised is unnecessary, unjust, and 

unreasonable because it restricts an interconnection customer’s ability to build 

interconnection facilities and stand alone network upgrades cost-effectively.137 Several 

commenters contend that the proposal will reduce costs and improve construction 

timelines.138 NextEra states that, in late 2016, one of its subsidiaries in SPP exercised the 

option to build and completed construction of facilities for a cost of approximately $12 

million, even though the relevant transmission owner asserted that it could not complete 

such facilities until late 2017 for an estimated cost of $18 million. NextEra argues that if 

the Commission expanded interconnection customers’ ability to exercise the option to 

build, there would be more instances where an interconnection customer constructs more 

efficiently than the transmission owner.139 AFPA asserts that the proposal will provide 

 136 AFPA; AVANGRID; AWEA; Bonneville; CAISO; Joint Renewable Parties;

Duke; Generation Developers; EDP; ELCON; Competitive Suppliers; FTC; IECA; 

NEPOOL; NextEra; PJM; Public Interest Organizations; SEIA; TDU Systems; TVA. 

137 AWEA 2017 Comments at 12-13.

138 Id. at 13; EDP 2017 Comments at 3-4; ELCON 2017 Comments at 3; Public 

Interest Organizations 2017 Comments at 5-8; Competitive Suppliers 2017 Comments 

at 4.

139 NextEra 2017 Comments at 9.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 52 -

competitive and commercial discipline to utility cost estimates, construction timelines, 

and negotiating strategies.140 Competitive Suppliers and NEPOOL state that the proposal 

provides more flexibility to market participants and has the potential to increase 

efficiency.141 AFPA argues that the market for engineering and construction contractors 

is sufficiently robust that interconnection customers can often find cheaper and more 

efficient alternatives to utility construction.142 CAISO and PJM comment that they each 

currently allow this option to some degree.143 MISO and NYISO take no position on the 

proposal.144

84. A number of commenters also oppose the proposal.145 EEI, and MISO TOs argue 

that there has been no demonstration that the options under the existing pro forma LGIA 

result in unjust and unreasonable rates, undue discrimination, or preferential treatment.146 

Both Imperial and MISO TOs question whether exercising the option to build would 

 140 AFPA 2017 Comments at 4.

141 Competitive Suppliers 2017 Comments at 4; NEPOOL 2017 Comments at 7. 

142 AFPA 2017 Comments at 6.

143 CAISO 2017 Comments at 9; PJM 2017 Comments at 7 (citing PJM, Intra-PJM 

Tariffs, OATT, Attachment P, app. 2, Section 3.2.3 (3.0.0)).

144 MISO 2017 Comments at 15; NYISO 2017 Comments at 14.

145 AEP; AES; APPA/LPPC; EEI; Eversource; Imperial; Indicated NYTOs; ITC; 

MidAmerican; MISO TOs; National Grid; PG&E; NorthWestern; SoCal Edison; 

Southern; Xcel; Sunflower.

146 EEI 2017 Comments at 17; MISO TOs 2017 Comments at 13.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 53 -

result in significant decreases in cost or construction time.147 AEP, Xcel, and National 

Grid argue that only transmission owners have the required knowledge, processes, and 

access to suppliers and contractors to properly construct network upgrades.148 Several

commenters state that the additional coordination needed between transmission owners 

and interconnection customers may undercut the interconnection customer’s ability to 

achieve lower costs or quicker construction.149 AEP contends that the Commission has 

“appropriately recognized [that] the expansion of an existing station should be treated 

differently than a green field construction project, and this is precisely why the 

Commission should not broaden the Option-to-Build.”150

ii. Commission Determination 

85. In this Final Rule, we adopt the NOPR proposal to modify articles 5.1, 5.1.3, and 

5.1.4 of the pro forma LGIA to allow interconnection customers to exercise the option to 

build with respect to the transmission provider’s interconnection facilities and stand alone 

network upgrades regardless of whether the transmission provider can meet the 

interconnection customer’s proposed dates. We conclude that this reform will benefit the 

 147 Imperial 2017 Comments at 17; MISO TOs 2017 Comments at 13.

148 AEP 2017 Comments at 6; Xcel 2017 Comments at 8-10; National Grid 2017 

Comments at 6-7.

149 Duke 2017 Comments at 6; TVA 2017 Comments at 4; ITC 2017 Comments 

at 7; MidAmerican 2017 Comments at 9-10; NorthWestern 2017 Comments at 3; 

Southern 2017 Comments at 10-11; Xcel 2017 Comments at 8-9.

150 AEP 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 54 -

interconnection process by providing interconnection customers more control and 

certainty during the design and construction phases of the interconnection process.151 

Further, we find that limiting exercise of the option to build to circumstances where the 

transmission provider cannot meet the interconnection customer’s requested dates is not 

just and reasonable. The limitation restricts an interconnection customer’s ability to 

efficiently build the transmission provider’s interconnection facilities and stand alone 

network upgrades in a cost-effective manner, which could result in higher costs for 

interconnection customers. 

86. In response to EEI’s and MISO TOs’ contention that there has been no 

demonstration that the options under the existing pro forma LGIA result in unjust and 

unreasonable rates, undue discrimination, or preferential treatment, we find that in 

circumstances where an interconnection customer cannot exercise the option to build, it 

may pay more and/or wait longer for the construction of the transmission provider’s 

interconnection facilities and stand alone network upgrades. With regard to Imperial and 

MISO TOs’ skepticism regarding the potential cost and construction efficiencies gained 

by exercising the option to build, the record suggests that such savings can occur and 

have already occurred. For example, NextEra states that its subsidiary exercised the 

option to build in SPP in 2016 and was able to complete the project one year sooner and 

for $6 million less than estimated by the transmission provider. NextEra also notes that 

 151 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 58.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 55 -

its subsidiary used approved subcontractors, built to the transmission owner’s 

specifications, and purchased components from vendors approved by the transmission 

owner.152

87. Although AEP, Xcel, and National Grid question interconnection customers’ 

abilities to properly construct stand alone network upgrades, we note that the NOPR 

proposal makes no changes to the transmission provider’s right to approve the 

engineering design, the equipment tests, and the construction of its interconnection 

facilities and stand alone network upgrades. In response to AEP, we note that the Final 

Rule does not change the type of facilities for which the option to build is available, and 

neither the Final Rule nor the NOPR discuss the applicability of the option to build to an 

“existing station” versus a “green field construction project.”

c. Reliability Concerns

i. Comments

88. APPA/LPPC, MidAmerican, EEI, ITC, National Grid, and Southern contend that 

this proposal could compromise grid reliability.153 EEI, ITC, MidAmerican, National 

Grid, and Southern argue that the proposal favors granting interconnection customers the 

potential for quicker or less costly construction over potential degradation of safety and 

 152 See, e.g., NextEra 2017 Comments at 9.

153 APPA/LPPC 2017 Comments at 4; MidAmerican 2017 Comments at 9-10; EEI 

2017 Comments at 17; ITC 2017 Comments at 7; National Grid 2017 Comments at 6-7; 

Southern 2017 Comments at 10.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 56 -

reliability.154 APPA/LPPC state that the existing option to build provision sufficiently 

balances the needs of interconnection customers with best utility practice and reliability 

concerns.155 They argue that the NOPR proposal, however, will “alter dramatically” the 

risk to long-term reliability of transmission providers’ systems and that the safeguards in

article 5.2 of the pro forma LGIA lack a grasp of the “short- and long-term reliability 

implications associated with construction, interconnection and operation of 

interconnection facilities and network upgrades.”156 

89. Three commenters state that article 5.2 of the pro forma LGIA does not fully 

cover the ongoing system operations, planning, and reliability requirements that are

inherent in interconnection and network upgrades.157 CAISO asserts that interconnection 

customers must follow the transmission owners’ existing standards as well as meet grid 

engineering and reliability standards.158 EEI requests that the Commission ensure that 

any facilities constructed by the interconnection customer that are transferred to the 

 154 EEI 2017 Comments at 17; ITC 2017 Comments at 7; MidAmerican 2017 

Comments at 9-10; National Grid 2017 Comments at 6-7; Southern 2017 Comments at 

10.

155 APPA/LPPC 2017 Comments at 2.

156 Id. at 3.

157 Id. at 4; MISO TOs 2017 Comments at 15; National Grid 2017 Comments 

at 6-7.

158 CAISO 2017 Comments at 10.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 57 -

transmission provider comply with any applicable North American Electric Reliability 

Corporation (NERC) reliability standards.159

90. Other commenters disagree and argue that the expanded option to build would not

affect system reliability.160 NextEra, for example, states that there is little evidence that 

the NOPR proposal would compromise grid reliability, and any contrary arguments 

ignore the fact that this proposal only loosens the conditions for exercising this right with 

regard to the option to build.161 AWEA asserts that expanding the option to build should 

not increase reliability concerns because it does not change existing approval 

requirements.162

ii. Commission Determination 

91. Concerns that the option to build, as revised by the Final Rule, will compromise 

system reliability are misplaced because they ignore the safeguards for reliability already 

in place for the existing option to build. We note that a number of commenters expressed 

similar concerns in the Order No. 2003 proceeding.163 There, in response to such 

 159 EEI 2017 Comments at 20.

160 AWEA 2017 Comments at 14; Generation Developers 2017 Comments at 12; 

NextEra 2017 Comments at 10. 

161 Id.

162 AWEA 2017 Comments at 14.

163 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 341.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 58 -

concerns, the Commission established several safeguards.164 These safeguards, embodied 

in article 5.2 of the pro forma LGIA, require, among other things, that the interconnection 

customer exercise good utility practice and adhere to the standards and specifications 

provided in advance by the transmission providers. Further, these safeguards give the 

transmission provider the right to approve the engineering design, equipment acceptance 

tests, and the construction itself. In Order No. 2003-A, the Commission stated that vague 

reliability concerns about the option to build are misplaced, and that articles 5.2.1, 5.2.3, 

5.2.5, and 5.2.6 of the pro forma LGIA are sufficient to guarantee the reliability of the 

facilities in question.165 In this Final Rule, we make no changes to the requirements in 

article 5.2. Furthermore, we note that because article 5.2 already gives the transmission 

provider a significant role with regard to the option to build and provides sufficient

safeguards to ensure reliable operations, we see no reason why the expanded option to 

build should cause a new reliability concern.

92. In response to EEI’s and CAISO’s concerns about whether any facilities 

constructed pursuant to the option to build comply with applicable NERC reliability 

standards, we note that article 5.2 already addresses this concern. For example, article 

5.2(2) states that the interconnection customer “shall comply with all requirements of law 

to which Transmission Provider would be subject.”

 164 Id. PP 356-357.

165 Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 at P 232.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 59 -

d. Liability and Cost Responsibility Concerns

i. Comments

93. EEI, Xcel, and National Grid ask the Commission to ensure that interconnection 

customers indemnify the transmission owner or provider from any damages that result 

from facilities built pursuant to the option to build, including damages to adjacent 

facilities.166 Six commenters maintain that interconnection customers should assume all 

additional costs that may result from this proposal without cash, transmission credit, or 

congestion revenue right reimbursement.167 CAISO, NextEra, PG&E, and SoCal Edison 

also argue that the Commission should require that interconnection customers not receive 

such reimbursements to the extent that stand alone network upgrade costs exceed a 

specified cap.168

ii. Commission Determination

94. In response to EEI’s, Xcel’s, and National Grid’s comments, we note that article 

5.2(7) of the pro forma LGIA requires the interconnection customer to “indemnify the 

Transmission Provider for claims arising from Interconnection Customer’s construction 

 166 EEI 2017 Comments at 23; Xcel 2017 Comments at 10; National Grid 2017 

Comments at 8-11.

167 CAISO 2017 Comments at 10; Bonneville 2017 Comments at 2-3; EEI 2017 

Comments at 23-24; MISO TOs 2017 Comments at 16; Southern 2017 Comments at 12; 

SoCal Edison 2017 Comments at 5.

168 CAISO 2017 Comments at 10; NextEra 2017 Comments at 11; PG&E 2017 

Comments at 4; SoCal Edison 2017 Comments at 5.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 60 -

of Transmission Provider’s Interconnection Facilities and Stand Alone Upgrades.” We 

consider this provision sufficiently broad to address EEI’s, Xcel’s, and National Grid’s 

concerns.169 

95. In response to arguments that interconnection customers should assume all 

additional costs that result from exercise of the option to build, we note that the Final 

Rule makes no changes with regard to cost assignment for transmission provider’s 

interconnection facilities and stand alone network upgrades. Additionally, apart from the

modifications to articles 5.1, 5.1.3, and 5.1.4 of the pro forma LGIA to allow 

interconnection customers to exercise the option to build regardless of whether the 

transmission provider can meet the interconnection customer’s proposed dates, this Final 

Rule makes no changes to the option to build process. In response to CAISO, NextEra, 

PG&E, and SoCal Edison, we note that the issue of cost caps is currently unique to

CAISO; therefore, issues regarding the interaction of the option to build and the CAISO 

network upgrade cost cap would be better addressed when CAISO submits its compliance 

filing to this Final Rule. 

 169 We note that the pro forma LGIA states that the term transmission provider 

“should be read to include the Transmission Owner when the Transmission Owner is 

separate from the Transmission Provider.” Pro forma LGIA Art.1 (Definitions).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 61 -

e. Other

i. Comments

96. AES claims that the proposal increases the transmission provider’s risk regarding 

security compliance and project management.170 APPA/LPPC, MISO TOs, and National 

Grid express concern that transmission owners will have to expend significant resources 

to perform the oversight functions in article 5.2 of the pro forma LGIA.171

97. Multiple commenters also identify barriers that will continue to exist under the 

current proposal. AWEA worries that requirements to adhere to jurisdictional 

transmission owner guidelines may remain a barrier to exercising the option to build 

under existing tariffs.172 APPA/LPPC note that interconnection customers may be 

constrained by state laws affecting the ability of non-utilities to exercise eminent domain 

to construct facilities and upgrades.173 CAISO states that later-queued projects may rely 

on network upgrades being built by interconnection customers and could be adversely 

affected if the customer withdraws from the queue or delays construction.174

 170 AES 2017 Comments at 7.

171 ITC 2017 Comments at 7; MISO TOs 2017 Comments at 14; AES 2017 

Comments at 7.

172 AWEA 2017 Comments at 15.

173 APPA/LPPC 2017 Comments at 4.

174 CAISO 2017 Comments at 9.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 62 -

98. Some commenters recommend that additional, specific options and regulatory 

language be added to the proposal. AVANGRID and AWEA recommend that the 

Commission ensure the expanded option to build would apply to identified transmission 

provider interconnection facilities and stand alone network upgrades identified through 

cluster studies.175 To ensure that transmission providers cannot refuse to build facilities 

and force interconnection customers to do so, EDP recommends that the Commission 

clarify that a transmission provider retains the obligation to build unless and until an 

interconnection customer exercises its option to build.176 

99. AVANGRID also recommends that the Commission provide two additional

options for interconnection customers. Under the first, the transmission provider would 

construct, and the interconnection customer would pay the costs of, the transmission 

provider’s interconnection facilities and stand alone network upgrades upfront, including 

an opportunity cost capped at 10 percent. Second, for all other network upgrades, the 

transmission provider, with the agreement of the interconnection customer, would 

construct and fund network upgrades, with charges to the interconnection customer 

made over time or the interconnection customer paying the costs up front, which would

not include any margin.177 Bonneville recommends the option to build only be available 

 175 AVANGRID 2017 Comments at 14-15; AWEA 2017 Comments at 14.

176 EDP 2017 Comments at 4.

177 AVANGRID 2017 Comments at 14-15.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 63 -

if the customer can demonstrate it can build the facilities more cost-effectively than the 

transmission provider or improve the timeline for construction.178 

100. Duke and EEI recommend that the Commission revise article 9.7.1 of the LGIA to 

require that parties coordinate actions regarding stand alone network upgrades that may 

impact other parties’ facilities during outages needed for maintenance, testing, or 

installation.179 Duke recommends revising article 11.5 of the pro forma LGIA (Provision 

of Security) to include stand alone network upgrades, as well as article 26.1 of the pro 

forma LGIA to clarify that the transmission provider is not prevented from using 

subcontractors to perform its obligations under the LGIA. Duke also recommends adding

language to require the transmission provider’s approval of subcontractors.180 EEI 

requests that articles 5.1, 5.1.3, and 5.1.4 of the pro forma LGIA be revised to note that, 

if during the study process it is determined that upgrades and facilities need to be 

expedited, the option to build will be superseded. 

101. National Grid recommends that the Commission revise article 5.2 of the pro forma

LGIA to require: (1) transmission owner’s prior written approval of all contractors and 

any information requested to evaluate the creditworthiness and technical capabilities of 

proposed contractors; (2) prior written transmission owner approval of agreements 

 178 Bonneville 2017 Comments at 2-3.

179 Duke 2017 Comments at 5; EEI 2017 Comments at 22.

180 Duke 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 64 -

between interconnection customers and contractors and provisions that allow

transmission owners to directly enforce the agreement against the contractor; and (3) that 

the interconnection customer and transmission owner enter into a written transfer 

agreement regarding the transfer of ownership of facilities built by the interconnection 

customer.181 Similarly, Eversource suggests that the Commission grant blanket 

authorization for the transfer of these facilities.182

102. TVA and EEI suggest that interconnection customers should meet standards 

similar to those required under Order No. 1000 for transmission construction 

qualification.183 Generation Developers, NextEra, and EEI support transmission owners 

maintaining a list of pre-approved contractors.184 Some commenters suggest that the 

Commission require the transmission provider to post the standards and specifications 

used for the transmission provider’s interconnection facilities and stand alone network 

upgrades on the transmission provider’s website.185 Generation Developers state that 

there is a need for the transmission provider or interconnecting transmission owner to 

 181 National Grid 2017 Comments at 8-11.

182 Eversource 2017 Comments at 17.

183 TVA 2017 Comments at 4; EEI 2017 Comments at 18.

184 Generation Developers 2017 Comments at 11; NextEra 2017 Comments at 11; 

EEI 2017 Comments at 21.

185 Generation Developers 2017 Comments at 11; EDP 2017 Comments at 4; 

SEIA 2017 Comments at 14.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 65 -

agree as to what constitutes a stand alone network upgrade.186 Generation Developers 

also request that transmission providers be required to provide written documentation and 

post on their website the reasons why they disagree that a facility is considered a stand 

alone network upgrade, in order to prevent undue discrimination.187 Eversource asks the 

Commission to require the interconnection customer to obtain transmission owner 

approval before ordering electrical material and equipment.188 Eversource and MISO 

recommend requiring that interconnection customers provide sufficient land rights for the 

transmission owners to access, operate, and maintain the transmission facilities and that 

the Commission terminate the interconnection customer’s authority to construct during

emergency situations.189

ii. Commission Determination

103. In response to AES’s concern that the proposal increases transmission providers’ 

risk regarding security compliance and project management, we again note that the Final 

Rule does not relax the established safeguards in article 5.2 of the pro forma LGIA. In 

response to concerns raised by APPA/LPPC, MISO TOs, and National Grid that 

transmission owners will have to expend significant resources to perform oversight 

 186 Generation Developers 2017 Comments at 9-10.

187 Id. at 10.

188 Eversource 2017 Comments at 9-11.

189 Id. at 1; MISO TOs 2017 Comments at 15-16.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 66 -

functions, we note that the Final Rule does not alter the role that the transmission 

provider would play in overseeing the option to build process. However, it may result in 

more interconnection customers exercising the expanded option to build. 

104. In response to AWEA’s and APPA/LPPC’s assertions about jurisdictional barriers, 

states laws, and eminent domain, we note that the specific purpose of this proposal is 

only to eliminate the pro forma LGIP’s existing limitation on the option to build. It is not 

to ensure that there are no jurisdictional or other legal barriers to construction by 

interconnection customers. Although more interconnection customers are likely to 

exercise the option to build as a result of the Final Rule, there are still situations where an 

interconnection customer may not be able to do so due to jurisdictional or legal 

constraints. In those situations, we would not expect the interconnection customer to 

exercise its option to build if it could not do so effectively due to jurisdictional or legal 

constraints, such as limitations imposed by state law. Additionally, an interconnection 

customer might find that that there may be interconnection requests for which the option 

to build is unlikely to result in cost or time savings. Consequently, we believe that 

interconnection customers are in the best position to determine whether they will realize 

any cost or time savings from exercising the option to build for a particular 

interconnection request. Finally, the fact that this reform will not necessarily be useful to 

all interconnection requests does not mean that this reform will not afford an opportunity 

to some interconnection customers.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 67 -

105. In response to CAISO’s comment that later-queued projects may be adversely 

affected if a higher-queued customer withdraws from the queue or delays construction, 

we see no reason to believe that an interconnection customer that exercises the option to 

build is more likely to adversely affect a later-queued project than would a delay caused 

by a transmission provider. In fact, it is our expectation that customers that exercise the 

option to build are likely only to do so if they believe they can construct the facilities 

faster than the transmission provider. Additionally, we agree with AVANGRID and 

AWEA that the expanded option to build would apply to identified transmission provider 

interconnection facilities and stand alone network upgrades regardless of whether those 

facilities were identified through clustering, serial, or another study method. This is 

consistent with the current option to build, which does not restrict the study method.

106. In response to EDP, we note that the pro forma LGIA, as modified by the Final 

Rule, makes clear that the interconnection customer may exercise the option to build at 

its discretion with regard to transmission provider’s interconnection facilities and stand 

alone network upgrades. If the interconnection customer does not exercise this 

discretion, pursuant to articles 5.1.1, 5.1.2, and 5.1.4, the transmission provider would be

responsible for the construction of transmission provider’s interconnection facilities and 

stand alone network upgrades. 

107. We choose not to adopt AVANGRID’s two additional proposals and find that the 

revisions adopted by the Final Rule strike the appropriate balance. Additionally, we 

disagree with Bonneville’s recommendation that we allow the interconnection customer 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 68 -

to exercise the option to build only if it can demonstrate its ability to construct the subject 

facilities cost-effectively. It is unnecessary to impose such a requirement for 

interconnection customers because they will ultimately bear the costs of the transmission 

provider’s interconnection facilities and the stand alone network upgrades; thus, they 

have more incentive than transmission providers to select the most cost effective option. 

108. We disagree with Duke and EEI regarding the need to revise article 9.7.1 of the 

pro forma LGIA to require parties to coordinate maintenance, testing, or installation 

actions for stand alone upgrades. Article 5.2 provides sufficient safeguards to ensure 

coordination of maintenance, testing, and installation by providing for transmission 

provider access and requiring the ultimate transfer of ownership. We also disagree with 

National Grid’s and Eversource’s proposals regarding the transfer of ownership because 

articles 5.2(8) and (9) already require the transfer of control and ownership to the 

transmission provider.

109. Furthermore, we disagree with Duke’s proposal to revise article 11.5 of the pro 

forma LGIA to include stand alone upgrades. Duke provides no reason why such 

revision is necessary. Additionally, we read the phrase “applicable portion” in article 

11.5 to exclude facilities that an interconnection customer would construct pursuant to 

the option to build. Since the purpose of article 11.5 is for the interconnection customer 

to provide funds to the transmission provider for construction costs, there would be no 

need for the interconnection customer to provide security to the transmission provider for 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 69 -

facilities the transmission provider will not construct (because the interconnection 

customer is exercising the option to build). 

110. We also see no need to revise article 26.1 of the pro forma LGIA, as Duke 

proposed, to limit the interconnection customer’s ability to use subcontractors. Similarly, 

while we agree with Generation Developers, NextEra, and EEI that it could be helpful for 

transmission owners to maintain a list of contractors available to interconnection 

customers for the option to build, given the adequacy of the safeguards in article 5.2, we 

find that it is not necessary to require transmission owners to do so. We find the 

safeguards in article 5.2 to be sufficient because they give the transmission provider 

significant oversight authority to review and approve the design, equipment testing, and 

construction, “unrestricted access” to inspect the construction, and the ability to require 

the interconnection customer to remedy deficiencies that may arise at “any time during 

construction.”190 Similarly, we do not agree with Duke’s and National Grid’s suggestion 

that the transmission provider should have the right to approve subcontractors because of

the multiple preexisting protections in article 5.2. Further, we are not persuaded by EEI’s 

contention that revisions are necessary to supersede the option to build if facilities need to 

be expedited. First, article 5.2 already obligates the interconnection customer to “remedy 

deficiencies” should “any phase of the engineering, equipment procurement, or 

construction . . . not meet the standards and specifications provided by Transmission 

 190 Pro forma LGIA Articles 5.2 (3), (5), & (6)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 70 -

Provider.”191 Second, the option to build is limited to the construction of transmission 

provider’s interconnection facilities and stand alone network upgrades, the latter of which 

the pro forma LGIA defines as those network upgrades that the interconnection customer 

“may construct without affecting day-to-day operations of the Transmission System 

during their construction.”192 Together, these provisions minimize the likelihood that any 

delays in construction will adversely affect reliability. 

111. In response to TVA and EEI, we find that article 5.2 already provides sufficient 

safeguards regarding transmission construction qualifications because it requires, for 

example, that interconnection customers use good utility practice and follow the 

standards and specifications outlined by the transmission provider. Additionally, while 

Generation Developers, EDP, and SEIA advocate that transmission providers post the 

standards and specifications for interconnection facilities and stand alone network 

upgrades on their websites, we will not require them to do so. Although posting such 

standards and specifications on a website could be useful, we do not think it appropriate 

to impose this requirement on transmission providers in this Final Rule given the 

questionable usefulness of this information. 

112. In response to Generation Developers’ request that transmission providers be 

required to provide an explanation when they disagree that a facility is a stand alone 

 191 Pro forma LGIA Art. 5.2(6).

192 Pro forma LGIA Art. 1 (Definitions).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 71 -

network upgrade, we find that it would be difficult for a transmission provider to 

determine whether or not a facility would be considered a stand alone network upgrade 

until it is presented with the results of a system impact study. While we recognize that 

questions regarding what constitutes a stand alone network upgrade could lead to 

disputes, interconnection customers are free to seek dispute resolution on such questions 

and/or pursue a complaint under section 206 of the FPA.

113. We disagree with Eversource’s request to require that interconnection customers 

receive transmission owner approval before ordering electrical materials and equipment. 

Article 5.2 already provides sufficient responsibilities to interconnection customers to 

mitigate the concerns Eversource raised through, for example, the requirements that the 

interconnection customer use good utility practice and abide by the transmission 

provider’s standards and specifications, and the requirement that the transmission 

provider approve the design, equipment acceptance tests, and construction. We also 

disagree with Eversource’s and MISO’s recommendations to require that interconnection 

customers provide sufficient land rights to allow transmission provider access to 

transmission facilities and to terminate interconnection customers’ authority to construct 

during emergency situations. We do not see the need to impose a further requirement on 

the interconnection customer, especially because the revisions adopted in this Final Rule

do not relax the existing requirements.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 72 -

3. Self-Funding by the Transmission Owner

a. NOPR Proposal 

114. In the NOPR, the Commission proposed to require agreement between a 

transmission owner or provider and interconnection customer before the transmission 

owner or provider may elect to initially fund network upgrades.193

115. Prior to the revisions proposed in the NOPR, article 11.3 in the pro forma LGIA 

stated that “[u]nless Transmission Provider or Transmission Owner elects to fund the 

capital for the Network Upgrades, they shall be solely funded by Interconnection 

Customer.” This provision allowed the transmission provider or owner to unilaterally 

elect to “self-fund” network upgrades. 

116. In 2013, MISO proposed allowing a transmission owner to elect to directly assign 

costs associated with self-funded network upgrades to the interconnection customer.194 

In that proceeding, the Commission accepted MISO’s proposal for a transmission owner 

that elects to initially fund network upgrades under MISO’s pro forma GIA to recover the 

capital costs for network upgrades through a network upgrade charge assessed to the 

interconnection customer.195 

 193 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 64.

194 Midcontinent Indep. Sys. Operator, Inc., 145 FERC ¶ 61,111 (2013) 

(Hoopeston).

195 Hoopeston, 145 FERC ¶ 61,111 at P 41.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 73 -

117. The Commission revisited that approach in the Otter Tail proceedings.196 In those 

proceedings, the Commission found that article 11.3 in MISO’s pro forma GIA, which 

allows a transmission owner to self-fund network upgrades, to be unjust, unreasonable, 

and unduly discriminatory or preferential. Consequently, the Commission directed MISO 

to revise article 11.3 to require mutual agreement with the interconnection customer for 

the transmission owner to elect to initially fund network upgrades. Ameren Services 

Company, a transmission owner in MISO, challenged this order in the United States

Court of Appeals for the District of Columbia Circuit (D.C. Circuit). 

118. In the NOPR in this proceeding, the Commission proposed to revise article 11.3 of 

the pro forma LGIA to require mutual agreement between the interconnection customer 

and the transmission owner for the transmission owner to initially fund the cost of 

network upgrades. Specifically, the Commission proposed in the NOPR to modify the 

language in article 11.3 of the pro forma LGIA as follows (with proposed additions in

italics):

Transmission Provider or Transmission Owner shall design, procure, 

construct, install, and own the Network Upgrades and Distribution 

Upgrades described in Appendix A, Interconnection Facilities, Network 

Upgrades and Distribution Upgrades. The Interconnection Customer shall 

be responsible for all costs related to Distribution Upgrades. Unless 

Transmission Provider or Transmission Owner elects to fund the capital for 

the Network Upgrades, which election shall only be available upon mutual 

 196 Midcontinent Indep. Sys. Operator, Inc., 151 FERC ¶ 61,220 (2015); Otter Tail 

Power Co. v. Midcontinent Indep. Sys. Operator, Inc., 153 FERC ¶ 61,352, at P 14

(2015); Otter Tail Power Co. v. Midcontinent Indep. Sys. Operator, Inc., 156 FERC 

¶ 61,099 (2016) (collectively, the Otter Tail proceedings).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 74 -

agreement of Interconnection Customer and Transmission Owner or 

Transmission Provider, they shall be solely funded by Interconnection 

Customer.

119. The Commission also sought comment on whether to limit the proposal to 

RTOs/ISOs or to apply it to all transmission providers.

b. Comments

120. A number of commenters support the proposal.197 A group of five commenters, 

predominantly from MISO, oppose the proposal and state that any action would be 

premature, given that, at the time that they filed their comments, the D.C. Circuit had not 

issued a decision in the Otter Tail proceedings. They ask the Commission to refrain from 

implementing this reform until the appellate decision is issued.198 

121. Regarding whether the Commission should extend the requirement for mutual 

agreement beyond RTOs/ISOs, AWEA, Joint Renewable Parties, TDU Systems, and 

AFPA all argue that the proposal should apply generically.199 On the other hand, 

 197 Non-Profit Utility Trade Associations; AFPA; AWEA; CAISO; Joint 

Renewable parties; Generation Developers; EDP; ELCON; FTC; IECA; NEPOOL; 

NextEra; PG&E; SEIA; TDU Systems.

198 Duke 2017 Comments at 6-7; EEI 2017 Comments at n.20; ITC 2017 

Comments at 8; MidAmerican 2017 Comments at 11; MISO TOs 2017 Comments at 17.

199 AWEA 2017 Comments at 19; Joint Renewable Parties 2017 Comments 

at 9-10; TDU Systems 2017 Comments at 7; AFPA Comments at 7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 75 -

Southern, TVA, Generation Developers, and Xcel state that self-funding by the 

transmission owner is not applicable to the pro forma OATT.200 

c. Commission Determination 

122. We withdraw the NOPR’s proposal to extend the approach to self-funding that the 

Commission approved in MISO to all regions. On January 26, 2018, the D.C. Circuit

issued a decision vacating the Commission’s orders in the Otter Tail proceedings.201 In

this decision, the court noted, among other things, that the Commission did not 

adequately respond to the argument that “involuntary generator funding compels 

[transmission owners] to . . . accept additional risk without corresponding return.”202 The 

court further stated that the Commission’s approved changes to the MISO tariff “open[ ] 

the floodgates to involuntary generator-funded interconnection projects.”203 The court 

also referenced this proceeding, stating that the fact that the Commission “plans a 

rulemaking to consider interconnection problems and costs . . . suggests that it should 

approach those issues on a clean slate.”204 In light of the D.C. Circuit’s decision, we will 

 200 Southern 2017 Comments at 13-14; TVA 2017 Comments at 5; Generation 

Developers 2017 Comments at 15; Xcel 2017 Comments at 10-11.

201 Ameren Servs. Co. v. FERC, 880 F.3d 571 (D.C. Cir. 2018).

202 Id. at 573-74.

203 Id. at 584.

204 Id. at 585.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 76 -

not move forward with the proposal pertaining to self-funding at this time. We will, 

however, continue to evaluate the issue. 

4. Dispute Resolution

a. NOPR Proposal

123. In the NOPR, the Commission proposed that RTOs/ISOs establish interconnection 

dispute resolution procedures that allow a disputing party to unilaterally seek dispute 

resolution in RTO/ISO regions.205 

124. Order No. 2003 created an arbitration process through the adoption of section 13.5 

of the pro forma LGIP, which allows disputing parties to agree to arbitration “upon 

mutual agreement of the Parties” to the dispute.206 Pursuant to this process, arbitrators 

may interpret and apply the provisions of the LGIA and LGIP but have no power to 

modify those provisions.207 At the completion of this process, the arbitrator’s decision is 

“final and binding upon the Parties, and judgment on the award may be entered in any 

court having jurisdiction.” Additionally, the decision may only “be appealed . . . on the 

grounds that the conduct of the arbitrator(s), or the decision itself, violated the standards 

set forth in the Federal Arbitration Act or the Administrative Dispute Resolution Act.”208 

 205 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 78.

206 Pro forma LGIP Section 13.5.1. 

207 Pro forma LGIP Section 13.5

208 Pro forma LGIP Section 13.5.3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 77 -

While the arbitrator’s decision is binding, “the final decision must still be filed with [the 

Commission] if it affects jurisdictional rates, terms and conditions of service, 

Interconnection Facilities, or Network Upgrades,”209 and the Commission “retains the 

authority to review the arbitrator’s decision.”210 Participation in the section 13.5 

arbitration process does not limit the ability of either party to bring a complaint about the 

same issues.211 

125. In the NOPR, the Commission proposed to revise the Code of Federal Regulations 

to require RTOs/ISOs to establish interconnection dispute resolution procedures that 

would allow a disputing party to unilaterally seek dispute resolution. In particular, the 

Commission proposed to revise section 35.28(g) of the Commission’s regulations to add

a new subparagraph (9), as follows: 

(9) Generator Interconnection Dispute Resolution Procedures. Every 

Commission-approved independent system operator or regional 

transmission organization tariff must contain provisions governing 

generator interconnection dispute resolution procedures to allow a disputing 

party to unilaterally initiate dispute resolution procedures under the 

respective tariff. Such provisions must provide for independent system 

operator or regional transmission organization staff member(s) or utilize 

 209 Id. 

210 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 290.

211 Specifically, it states that section 13.5 arbitration does not “circumscribe[ ] the 

Parties’ right to avail themselves of the Commission’s complaint process because under 

section 13.5.1, a party that does not agree to arbitration may exercise its rights, including 

its right to bring a complaint to the Commission.” Order No. 2003, FERC Stats. & Regs. 

¶ 31,146 at P 290. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 78 -

subcontractor(s) to serve as the neutral decision-maker(s) or presiding staff 

member(s) or subcontractor(s) to the dispute resolution procedures. Such 

staff participating in dispute resolution procedures shall not have any 

current or past substantial business or financial relationships with any party. 

Additionally, such dispute resolution procedures must account for the time 

sensitivity of the generator interconnection process. 

126. The Commission limited the proposed requirements in this draft text to 

RTOs/ISOs because the Commission had only received comments regarding the need for 

dispute resolution reform in RTOs/ISOs. However, given the lack of a record on this 

issue, the Commission also sought comment on the need for reform outside the 

RTOs/ISOs.212 The Commission also sought comment on the appropriateness of 

adopting procedures similar to section 4.2 of the pro forma SGIP, which allows parties to 

contact the Commission’s Dispute Resolution Service (DRS) for assistance in resolving 

an interconnection dispute.213

127. The NOPR proposal represented a potential alternative to, and not a replacement 

of, section 13.5 of the pro forma LGIP.214 The Commission crafted its proposal in 

response to its observation that the arbitration process embodied in section 13.5 is 

 212 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 86.

213 Section 4.2.4 of the pro forma SGIP states that DRS will assist in resolving a 

dispute or in selecting an appropriate dispute resolution venue. Additionally, section 

4.2.6 states that if neither party elects to contact DRS or if the attempted dispute 

resolution fails, “either Party may exercise whatever rights and remedies it may have in 

equity or law consistent with the terms of these procedures.” 

214 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 79 -

effectively unavailable to an interconnection customer if a transmission owner opposes 

this arbitration process.215 

b. General 

i. Comments

128. Multiple commenters support the proposal.216 The Non-Profit Utility Trade 

Associations state that they do not object to this proposal.217 Salt River states that the 

proposal is reasonable with regard to disputes between interconnection customers and 

RTOs/ISOs, RTO/ISO transmission owners, or affected system operators that are also 

RTO/ISO transmission owners.218 However, Salt River argues that if the dispute is with 

an autonomous neighboring affected system operator that is a non-RTO/ISO member, 

then the dispute resolution procedures in the affected system operator’s OATT should 

apply.219

 215 Id. P 85.

216 AWEA 2017 Comments at 21; Joint Renewable Parties 2017 Comments at 2-3; 

IECA 2017 Comments at 3; Invenergy 2017 Comments at 15-16; AFPA 2017 Comments 

at 8; CAISO 2017 Comments at 11-12; SEIA 2017 Comments at 14-15; TDU Systems 

2017 Comments at 11; AVANGRID 2017 Comments at 18. 

217 Non-Profit Utility Trade Associations 2017 Comments at 6.

218 Salt River 2017 Comments at 8.

219 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 80 -

129. AES asserts that RTOs/ISOs, not the Commission, should reexamine their existing 

dispute resolution procedures.220 Indicated NYTOs oppose the dispute resolution 

proposal, arguing that NYISO’s existing dispute resolution provisions are adequate.221 

NYISO also opposes the proposed revisions, stating that they would duplicate existing 

dispute resolution opportunities.222 ISO-NE and CAISO similarly argue that their current 

dispute resolution procedures are adequate.223 CAISO also notes that its tariff includes a 

dedicated dispute committee for generator interconnection issues.224 MidAmerican 

argues that the existing MISO tariff addresses the Commission’s concerns about the 

ability of a party to unilaterally request dispute resolution.225 

130. MISO requests a clarification that RTOs/ISOs do not need to create separate 

dispute resolution procedures for generator interconnection disputes and may continue to 

rely on their general dispute resolution procedures as long as they permit parties to 

unilaterally initiate the resolution process.226 MISO TOs ask the Commission to clarify 

 220 AES 2017 Comments at 7-8.

221 Indicated NYTOs 2017 Comments at 12-14.

222 NYISO 2017 Comments at 17.

223 ISO-NE 2017 Comments at 18; CAISO 2017 Comments at 12.

224 Id. (citing CAISO, eTariff, FERC Electric Tariff, OATT, Section 13 (0.0.0) & 

app. DD, Section 15.5 (1.0.0)).

225 MidAmerican 2017 Comments at 7; see also MISO TOs 2017 Comments at 24.

226 MISO 2017 Comments at 17-18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 81 -

that the dispute resolution procedures are for genuine disputes only and should not be 

used to gain additional time to meet LGIP or LGIA obligations.227 PJM agrees with the 

dispute resolution proposal and believes that its dispute resolution procedures generally 

conform to it.228

131. Generation Developers request that the Final Rule state that the dispute resolution 

mechanism that an RTO/ISO adopts should trump the existing provisions in section 13.5 

of the LGIP. Generation Developers state that, unless this is made clear, the parties will 

argue about which dispute resolution provision applies.229

ii. Commission Determination

132. In this Final Rule, we revise the pro forma LGIP to add new section 13.5.5, as 

discussed further below. We are taking this step because the record in this proceeding 

indicates that existing dispute resolution procedures may not be just and reasonable and 

may be unduly discriminatory or preferential because one disputing party may effectively 

prevent the other disputing party from pursuing dispute resolution.230 We thus disagree 

with those commenters that argue that transmission providers should simply reexamine 

their dispute resolution procedures. The reason is that, if the status quo provides little 

 227 MISO TOs 2017 Comments at 24.

228 PJM 2017 Comments at 8.

229 General Developers 2017 Comments at 19.

230 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 84.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 82 -

recourse for interconnection customers when a transmission provider does not agree to 

dispute resolution, then it would not be sufficient for transmission providers to merely 

reexamine their dispute resolution procedures with no guarantee that they would address 

this concern. Additionally, as discussed further below, we find that the record developed 

here demonstrates the need for generic dispute resolution reform, both inside and outside 

RTOs/ISOs. To avoid having dispute resolution requirements in multiple places, we are 

effectuating this reform through revisions to the pro forma LGIP as part of the existing 

dispute resolution provisions, rather than through changes to the Code of Federal 

Regulations. 

133. Therefore, this Final Rule revises the pro forma LGIP by adding new section 

13.5.5, which will read as follows:

Non-binding dispute resolution procedures. If a Party has submitted a 

Notice of Dispute pursuant to section 13.5.1, and the Parties are unable to 

resolve the claim or dispute through unassisted or assisted negotiations 

within the thirty (30) Calendar Days provided in that section, and the 

Parties cannot reach mutual agreement to pursue the section 13.5 arbitration 

process, a Party may request that Transmission Provider engage in Nonbinding Dispute Resolution pursuant to this section by providing written 

notice to Transmission Provider (“Request for Non-binding Dispute 

Resolution”). Conversely, either Party may file a Request for Non-binding 

Dispute Resolution pursuant to this section without first seeking mutual 

agreement to pursue the section 13.5 arbitration process. The process in 

section 13.5.5 shall serve as an alternative to, and not a replacement of, the 

section 13.5 arbitration process. Pursuant to this process, a transmission 

provider must within 30 days of receipt of the Request for Non-binding 

Dispute Resolution appoint a neutral decision-maker that is an independent 

subcontractor that shall not have any current or past substantial business or 

financial relationships with either Party. Unless otherwise agreed by the 

Parties, the decision-maker shall render a decision within sixty (60) 

Calendar Days of appointment and shall notify the Parties in writing of 

such decision and reasons therefore. This decision-maker shall be 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 83 -

authorized only to interpret and apply the provisions of the LGIP and LGIA

and shall have no power to modify or change any provision of the LGIP

and LGIA in any manner. The result reached in this process is not binding, 

but, unless otherwise agreed, the Parties may cite the record and decision in 

the non-binding dispute resolution process in future dispute resolution

processes, including in a section 13.5 arbitration, or in a Federal Power Act

section 206 complaint. Each Party shall be responsible for its own costs 

incurred during the process and the cost of the decision-maker shall be 

divided equally among each Party to the dispute.

134. The provision retains the central principles of the NOPR proposal but extends its 

application to all transmission providers, including non-RTOs/ISOs. We have revised the 

provision to also provide necessary clarification in response to the comments received in 

this proceeding, as discussed further below. 

135. We note that numerous parties have expressed a need for dispute resolution reform 

and support for the principles embodied in the NOPR proposal. While this Final Rule

establishes the core requirement that transmission providers adopt a new non-binding 

dispute resolution process, each transmission provider must develop and establish the 

additional specifics of a just and reasonable process that allows disputing parties to 

unilaterally seek non-binding dispute resolution.

136. In response to Salt River’s argument regarding the applicability of the proposed 

revisions to an autonomous neighboring affected system operator, as explained more 

fully below, on April 3-4, 2018, the Commission convened a technical conference in 

Docket No. AD18-8-000 for industry representatives and others to discuss issues related 

to affected systems. Given that the discussion here pertains to disputes within a 

transmission provider’s region (such as a dispute between an interconnection customer 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 84 -

and a transmission provider) and not to disputes with a party external to the region of the 

interconnection request, we find that Salt River’s concerns are better addressed in a 

proceeding dedicated to issues involving affected systems, such as the aforementioned 

technical conference.231

137. In response to Indicated NYTOs’, ISO-NE’s, NYISO’s, PJM’s, MISO’s, 

MidAmerican’s, and CAISO’s contentions about the existing dispute resolution 

procedures in their specific regions, we remind these parties that we will not evaluate a 

particular transmission provider’s tariff provisions until it submits its compliance filing. 

We note, however, that a transmission provider that has only adopted the generator 

interconnection dispute resolution procedures imposed by Order No. 2003, namely the 

section 13.5 arbitration process, would not comply with the non-binding dispute 

resolution requirements of this Final Rule, as set forth in the new section 13.5.5 above. 

138. In response to MISO’s request for clarifications, we find that a transmission 

provider does not need to create dispute resolution procedures that only apply to 

generator interconnection disputes, so long as the transmission provider provides a 

dispute resolution process that a party, including the interconnection customer, may seek 

unilaterally. In response to the MISO TOs’ request for clarification, we find that their 

concern that a party will use the dispute resolution process to gain additional time to meet 

 231 Initial and reply comments on the technical conference in Docket No. AD18-8-

000 are due within 30 days and 45 days, respectively, from the date of the issuance of the 

Notice Inviting Post-Technical Conference Comments in that proceeding, which issued 

concurrently with this Final Rule. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 85 -

LGIP or LGIA obligations to be speculative, and, to the extent that this is a valid concern, 

it would apply equally to disputing interconnection customers and transmission providers 

or owners. In addition, both the dispute resolution process created here and the section 

13.5 arbitration process impose costs on the disputing parties, which should mitigate 

concerns about potential misuse of the process.

139. We find that the new dispute resolution provisions in section 13.5.5 of the pro 

forma LGIP adopted by this Final Rule do not trump the existing language in section 13.5 

of the pro forma LGIP. We establish the new non-binding dispute resolution process 

here primarily to address the concern that dispute resolution is unavailable where there is 

no mutual agreement to pursue a section 13.5 arbitration. This Final Rule thus provides a 

dispute resolution avenue that one party may seek unilaterally. Disputing parties are free 

to determine which process they prefer, and disputing parties may pursue the non-binding 

process even if they have not previously sought a section 13.5 arbitration. Additionally, 

participation in the new section 13.5.5 process does not preclude the parties from 

pursuing arbitration after the conclusion of another process if they seek a binding result. 

Also, pursuing either process does not prevent either party from availing itself of the 

complaint process pursuant to section 206 of the FPA. Furthermore, we note that we do 

not restrict a party’s ability to cite the record developed in the arbitration process 

described in section 13.5 of the pro forma LGIP in a complaint proceeding pursuant to 

section 206 of the FPA, and we see no reason to impose such a restriction for the nonbinding dispute resolution provisions adopted in this Final Rule. We note, however, that 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 86 -

parties may mutually agree to restrict the use of the record created in a non-binding 

dispute resolution process.

c. Extending the Dispute Resolution Proposal beyond

RTOs/ISOs 

i. Comments

140. Generation Developers, IECA, Competitive Suppliers, and TDU Systems argue 

that the Commission should also reform dispute resolution procedures outside of 

RTOs/ISOs.232 For example, Generation Developers state that problems that 

interconnection customers encounter pertaining to dispute resolution “are also 

encountered with a Transmission Provider outside of [an RTO/ISO].”233 TDU Systems 

state that they have “found the current dispute resolution processes [outside of 

RTOs/ISOs] to be inadequate,” because, for example, in regions that lack an RTO/ISOlike entity “to assist in resolving disputes, the waiting period to access dispute resolutions 

is too long, and parties to disputes should have options beyond mutually-agreed upon 

arbitration.”234 In non-RTO/ISO regions, AFPA recommends the establishment of a 

separate Commission dispute resolution service with expertise on these matters.235 

 232 Generation Developers 2017 Comments at 18-20; IECA 2017 Comments at 3; 

Competitive Suppliers 2017 Comments at 6; TDU Systems 2017 Comments at 11.

233 Generation Developers 2017 Comment at 20.

234 TDU Systems 2017 Comments at 12.

235 AFPA 2017 Comments at 8.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 87 -

Competitive Suppliers believe that the rules and protocols in organized markets are 

superior to those outside organized markets and encourage the Commission to uphold 

consistency and comparability unless there is an adequate reason to allow regional 

variation.236 MISO asserts that there is no basis to conclude that the procedures currently 

used in RTOs/ISOs are inferior to the procedures used by other transmission providers.237 

141. TVA believes that the current dispute resolution process for non-RTOs/ISOs is 

sufficient, under both the pro forma LGIP and the pro forma SGIP.238 If the Commission 

decides that any Final Rule should align more closely to the parameters of the NOPR, 

Competitive Suppliers argue that the proposed revisions to the dispute resolution changes

should apply to all transmission owners and providers offering interconnection service.239 

ii. Commission Determination

142. In this Final Rule, we adopt the aforementioned pro forma LGIP language, which 

imposes the revised dispute resolution requirements on both RTOs/ISOs and nonRTOs/ISOs. As noted above, the Commission sought comment on the need for dispute 

resolution reform outside of RTOs/ISOs. We agree with commenters that there is a need 

 236 Competitive Suppliers 2017 Comments at 5.

237 MISO 2017 Comments at 17.

238 TVA 2017 Comments at 6.

239 Competitive Suppliers 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 88 -

for dispute resolution reform outside of RTO/ISOs.240 Outside of the RTOs/ISOs, the 

transmission provider and transmission owner are the same entity. Consequently, outside 

of RTOs/ISOs and without the presence of an independent RTO/ISO as a third party, it 

may be more difficult for the transmission provider and the interconnection customer to 

reach mutual agreement to seek dispute resolution. Under such circumstances, when a 

dispute arises, the process would benefit from a neutral decision-maker that can evaluate 

the dispute without an interest in the outcome. For this reason, the procedures adopted 

here apply generically, in both RTO/ISO regions and non-RTO/ISO regions. Finally, we 

have opted to include new pro forma LGIP section 13.5.5 in the pro forma LGIP instead 

of the Code of Federal Regulations, so that all generically applicable generator 

interconnection dispute resolution requirements are in the same place. 

d. RTO/ISO Neutrality 

i. Comments

143. Multiple commenters question the neutrality of RTO/ISO staff or oppose allowing 

RTO/ISO staff as dispute resolution neutral decision-makers.241 AWEA, for instance, 

notes that RTOs/ISOs rely upon transmission owner assistance (for modeling and design 

information) and transmission owner membership (for financial support) and that, on 

 240 Competitive Suppliers 2017 Comments at 5; MISO 2017 Comments at 17.

241 FTC 2017 Comments at 11; AWEA 2017 Comments at 23-24; Generation 

Developers 2017 Comments at 18; EDP 2017 Comments at 5; NextEra 2017 Comments 

at 15; AVANGRID 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 89 -

occasion, RTOs/ISOs have refused to participate in dispute resolution.242 Another option 

that AWEA and NextEra suggest is for RTOs/ISOs to contract for staff from a 

disinterested RTO/ISO to oversee their dispute resolution.243 NextEra suggests adding a 

draft tariff provision that would allow for this arrangement.244

144. AWEA also states that market monitors have the necessary independence to 

oversee dispute resolution, but they already have significant responsibilities and may lack 

relevant interconnection process experience.245 EEI argues that having an RTO/ISO 

serve as a decision-maker in a dispute could potentially challenge its independence and 

neutrality.246 Similarly, Indicated NYTOs argue that entities like NYISO would be 

reluctant to resolve such disputes by making judgments in favor of either the developer or 

the transmission owner.247 ISO-NE and NEPOOL explain that ISO-NE fulfills the role of 

transmission provider for many functions but that participating transmission owners serve 

in this role when providing cost estimates for network upgrades.248 ISO-NE and 

 242 AWEA 2017 Comments at 22-23.

243 Id. at 23; NextEra 2017 Comments at 20.

244 Id. at 17.

245 AWEA 2017 Comments at 24.

246 EEI 2017 Comments at 28.

247 Indicated NYTOs 2017 Comments at 14.

248 ISO-NE 2017 Comments at 18-19; NEPOOL 2017 Comments at 8.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 90 -

NEPOOL also state that, given ISO-NE’s transmission provider role, disputes can arise 

between ISO-NE and the interconnection customer or the transmission owner, and it 

would therefore be inappropriate to require ISO-NE to decide these disputes.249 

NEPOOL also argues that having RTO/ISO staff resolve disputes could impair the 

RTO’s/ISO’s performance of its core duties.250 NextEra suggests that RTO/ISO staff 

serving in this role would need comparable status to the RTO’s/ISO’s independent 

market monitoring staff.251 TDU Systems state that RTO/ISO staff are likely adequately 

independent from all market participants and able to serve as a useful resource for 

resolving disputes.252 AVANGRID states that, while RTO/ISO staff are often “very 

good” at preventing and resolving disputes as they arise, they should not “be put in the 

position of determining the outcome of formal dispute resolution processes.”253

145. Generation Developers and NextEra argue that subcontractors could serve as 

neutral parties.254 AWEA also argues that the NOPR’s neutrality standard may be too 

 249 ISO-NE 2017 Comments at 19.

250 NEPOOL 2017 Comments at 8.

251 NextEra 2017 Comments at 15. 

252 TDU Systems 2017 Comments at 11.

253 AVANGRID 2017 Comments at 18.

254 Generation Developers 2017 Comments at 18; NextEra 2017 Comments at 15-

16; see also AVANGRID 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 91 -

vague and that subcontractor vetting may resolve this concern.255 Generation Developers 

state that the RTO/ISO should maintain a long-term contract for dispute services to 

ensure that the subcontractor is neutral and not beholden to the RTO/ISO. Generation 

Developers propose that the RTO/ISO should have a list of subcontractors with 

substantial experience in interconnection and modeling matters that are available to serve 

as neutral third-parties, and that all RTO/ISO members should be allowed to propose to 

use the listed subcontractors. Generation Developers propose that subcontractor fees 

should be borne by interconnection customers to ensure that there is no tendency for a 

subcontractor to be beholden to the RTO/ISO. 

146. Conversely, MISO contends that there is no need for independent staff or 

subcontractors and that the proposed requirements could increase RTO/ISO 

bureaucratization and impose additional costs.256 MISO states that the proposed 

independence requirements are unnecessary, as RTOs/ISOs are already subject to 

stringent independence requirements. MISO asserts that there has been no showing that 

the existing conflict of interest requirements are inadequate for purposes of dispute 

resolution. MISO proposes that the Commission permit RTOs/ISOs to rely on their 

 255 AWEA 2017 Comments at 23.

256 MISO 2017 Comments at 19.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 92 -

existing standards of conduct and similar requirements for their dispute resolution 

staff.257

147. MISO states that the requirement that RTO/ISO dispute resolution staff not have 

current or past substantial business or financial relationships with any disputing party is 

too broad and burdensome and that the pool of suitable candidates to perform these tasks 

is limited. If the Commission adopts this requirement, MISO asks the Commission to

limit the prohibition to a reasonable time period (e.g., three years).258

148. NYISO is concerned about instituting a framework that would outsource 

responsibility to subcontractors.259 It states that section 30.13.2 of its LGIP provides that, 

even when NYISO uses subcontractors, it must comply with the tariff’s requirements. 

Therefore, NYISO objects to any process that would allow a subcontractor’s 

determination—for example, regarding appropriate network upgrades—to override 

NYISO’s judgment concerning tariff requirements and applicable reliability standards.260

ii. Commission Determination 

149. With few exceptions, the commenters voice strong opposition to having RTO/ISO 

staff serve as decision-makers in dispute resolution proceedings. Some commenters 

 257 Id. at 18-19.

258 Id. at 19.

259 NYISO 2017 Comments at 18.

260 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 93 -

argue that RTO/ISO staff may be unable to demonstrate independence in such a process. 

Conversely, Indicated NYTOs argue that requiring RTO/ISO staff to act as decisionmakers would compromise their independence. In response to these concerns, and to 

address the issue where the transmission owner is the transmission provider outside of 

RTOs/ISOs, the LGIP provision adopted in this Final Rule requires transmission 

providers to appoint an independent third party to preside over dispute resolution 

proceedings. 

150. In response to Generation Developers’ contention that interconnection customers 

should bear the fees for the decision-maker, we find that it makes little sense to have one 

disputing party bear all costs when there are multiple parties involved in the dispute. For 

this reason, the newly adopted provision in section 13.5.5 of the pro forma LGIP requires 

the same cost division as that established for the arbitration process described in section 

13.5 of the pro forma LGIP. Thus, the cost of the decision-maker shall be divided 

equally among each party to the dispute. Each individual party to a dispute will be 

responsible for its own costs incurred during the process.

151. The Final Rule requires that the assigned decision-maker have no “current or past 

substantial business or financial relationships with either party.” We note that this

standard is identical to the neutrality standard proposed in the NOPR and to the one 

established for arbitrators in section 13.5 of the pro forma LGIP. While MISO argues 

that this standard would limit the pool of eligible participants, we read MISO’s comments 

to pertain to the NOPR proposal, which required RTOs/ISOs to have RTO/ISO staff 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 94 -

serve as decision-makers. For this reason, the neutrality standard adopted in this Final 

Rule will not be too burdensome, in light of the changes from the NOPR.

152. With regard to NYISO’s concern about “outsourcing” responsibility to 

subcontractors, we note that the newly created process, like the arbitration process 

described in section 13.5 of the pro forma LGIP, limits a decision-maker’s authority so 

that it may only “interpret and apply the provisions of the LGIA and LGIP.” The 

subcontractor would therefore have no ability to alter NYISO’s existing responsibilities.

e. Binding Nature of the Proposal

i. Comments

153. AWEA indicates that, due to neutrality issues that are likely to remain, dispute 

resolution should be non-binding.261 Similarly, NextEra argues that it would not be 

appropriate for this “expeditious input” to be binding on the parties and cause them to 

lose rights under sections 205 or 206 of the FPA.262 NextEra also asserts that if the 

expedited dispute resolution were binding, there would be too much risk involved.263 

NextEra views the process as similar to “input from a subject matter expert” rather than 

any form of litigation.264 

 261 AWEA 2017 Comments at 24.

262 NextEra 2017 Comments at 16.

263 Id.

264 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 95 -

ii. Commission Determination

154. In this Final Rule, we adopt a non-binding dispute resolution process. The pro 

forma LGIP provisions adopted in this Final Rule will be an alternative to, and not a 

replacement of, the existing arbitration process described in section 13.5 of the pro forma

LGIP, which is a binding process. Specifically, section 13.5.3 of the pro forma LGIP 

states that “the decision of the arbitrator(s) shall be final and binding upon the Parties, 

and judgment on the award may be entered in any court having jurisdiction.”265 Because 

the new process adopted in this Final Rule does not require mutual agreement, we agree 

with AWEA and NextEra that this new process should be non-binding.266 Although the 

non-binding nature of the process could dampen its appeal, the process would still require 

disputing parties to participate in a process presided over by a neutral party. To this 

point, we agree with NextEra that the process would be beneficial because it would offer 

an opportunity for “input from a subject matter expert.” Additionally, we find that it 

would be inappropriate for the new, non-binding dispute resolution process to limit a 

party’s ability to pursue a complaint pursuant to section 206 of the FPA. 

 265 Pro forma LGIP Section 13.5.3 (emphasis added).

266 No other commenters discussed this issue. Although we are adopting a nonbinding process in the pro forma LGIP, transmission providers that have binding dispute 

resolution processes that, on compliance, are able to demonstrate that their processes 

otherwise satisfactorily adhere to the tenets of this Final Rule (i.e., that they do not 

require mutual agreement) may qualify for a variation from the pro forma LGIP 

provision adopted in this Final Rule.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 96 -

f. Timing 

i. Comments

155. AWEA strongly supports the Commission’s proposal to require the RTO/ISOdevised dispute resolution procedures to account for the interconnection process’s time 

sensitivity.267 Generation Developers argue that the proposed regulation fails to 

meaningfully address time sensitivity and contends that the process could be resolved 

within 30 days of initiation.268 FTC argues that the proposed requirement that 

RTOs/ISOs account for the time sensitivity of the generator interconnection process is 

likely to reduce a transmission provider’s ability to delay interconnection dispute 

resolution.269 AVANGRID comments that any dispute resolution procedures must not 

result in “significant delay” of the generator interconnection process.270

156. TDU Systems state that, for non-RTO/ISO regions, it would be appropriate to 

reduce to two weeks the thirty-day period for parties to resolve disputes once a formal 

notice of the dispute has been provided. TDU Systems argue that nothing prevents the 

parties from continuing to attempt to resolve the dispute informally once other procedures 

 267 AWEA 2017 Comments at 24-25.

268 General Developers 2017 Comments at 19.

269 FTC 2017 Comments at 10. See NOPR, FERC Stats. & Regs. ¶ 32,719 at P 87.

270 AVANGRID 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 97 -

are initiated, and given the time sensitivity of these issues, a shorter timeframe would be 

less prejudicial to the interconnection customer.271

157. TDU Systems state that the rules in section 13.5 of the pro forma LGIP and 

article 27 of the pro forma LGIA provide for a thirty-day period in which the parties will 

attempt to resolve a dispute, followed by the right for the parties to mutually agree to 

submit the dispute to arbitration; however, TDU Systems contend that the selection of the 

arbitrator can take up to thirty days, with the arbitration decision to be rendered within 

ninety days of appointment. TDU Systems note that, in contrast, article 10 of the SGIA 

and section 4.2 of the SGIP provide that if a dispute has not been resolved within two 

business days after receipt of a notice of the dispute, either party may contact FERC’s 

Dispute Resolution Service for assistance in resolving the dispute. 

158. TDU Systems ask the Commission to adopt fast-track complaint procedures for 

complaints that parties cannot resolve or do not mutually agree to arbitrate. It 

recommends a fixed period of time (for example, sixty days) from complaint filing to 

Commission order issuance. TDU Systems recognizes that even fast-track procedures, 

which it estimates could result in order issuance twenty days from the filing of an answer, 

might still be too long for interconnection disputes and that there is no guarantee of fasttrack procedures. TDU Systems ask the Commission to specify that interconnection 

 271 TDU Systems 2017 Comments at 12.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 98 -

complaints are entitled to fast-track complaint procedures if the Commission does not 

adopt a separate streamlined interconnection process.272

ii. Commission Determination

159. The pro forma LGIP provision adopted in this Final Rule requires the appointment 

of a decision-maker within thirty days of the receipt of a request for non-binding dispute 

resolution and requires a decision within sixty days of the decision-maker’s appointment. 

We note that this process would require a decision thirty days sooner than the arbitration 

process described in section 13.5 of the pro forma LGIP would require. While the 

Commission did not propose such a timeline in the NOPR, the Commission did express 

the view that any new dispute resolution process should “account for the time sensitivity 

of the generator interconnection process.”273 The timeline adopted here is consistent with 

this position. 

160. We disagree with TDU Systems’ position that we should adopt different timing 

requirements inside and outside RTOs/ISOs, and we instead apply this rule generically. 

Additionally, while TDU Systems point to the timing requirements in the pro forma SGIP 

dispute resolution process, we note that, as discussed more fully below, we decline to

adopt the timing requirements in the pro forma SGIP dispute resolution process for the 

pro forma LGIP. Finally, we disagree with TDU Systems’ request that we should require 

 272 Id. at 13.

273 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 84.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 99 -

fast-track complaint procedures for generator interconnection disputes. Because of the 

fact-specific nature of every complaint, we do not support the request to have fast-track 

complaint procedure for one category of disputes.

g. Mutual Agreement

i. Comments

161. Multiple commenters support the elimination of the mutual agreement 

requirement.274 MISO states that, while it does not oppose this requirement, in MISO,

parties to a generator interconnection dispute can already commence dispute resolution 

unilaterally. MISO further notes that, while a disputing party may exit its procedures at 

certain designated points to pursue the Commission complaint process or other remedies, 

no party can veto another party’s ability to pursue dispute resolution under the 

procedures.275 Similarly, PG&E believes this reform is not applicable to CAISO because

CAISO allows any disputing party to trigger dispute resolution and does not require 

agreement from a transmission owner or CAISO.276

 274 Generation Developers 2017 Comments at 16; EDP 2017 Comments at 5; 

Invenergy 2017 Comments at 15-16; FTC 2017 Comments at 10; NEPOOL 2017 

Comments at 8; NextEra 2017 Comments at 15; TDU Systems 2017 Comments at 11; 

AVANGRID 2017 Comments at 18.

275 MISO 2017 Comments at 17-18.

276 PG&E 2017 Comments at 5 (citing CAISO Tariff, eTariff, FERC Electric 

Tariff, OATT, app. DD, Section 15.5 (1.0.0)). 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 100 -

162. EEI questions who should bear the costs for such unilateral activity or how such 

costs would be recovered.277 EEI states that the Commission has not explained how 

unilateral dispute resolution would work because it implies a non-consensual process, 

which is more akin to an adjudication.278 EEI is uncertain as to what authority an 

RTO/ISO would or should have in this process and whether this proposal is intended to 

limit a transmission provider’s or interconnection customer’s right to seek judicial 

relief.279

163. ISO-NE and EEI contend that, if the requirement for mutual agreement for 

alternative resolution methods is removed, unnecessary delays and uncertainties may 

result.280 ISO-NE argues that its current dispute resolution process provides a disputing 

party with recourse and minimizes the potential for unnecessary delays and uncertainty 

by allowing for dispute resolution through a section 206 complaint filed with the 

Commission.281 As a result, ISO-NE states that the current pro forma construct avoids 

 277 EEI 2017 Comments at 28.

278 Id. at 27. 

279 Id.

280 ISO-NE 2017 Comments at 19; EEI 2017 Comments at 27.

281 ISO-NE 2017 Comments at 19-20.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 101 -

disagreements being submitted to arbitration, which would consume significant ISO-NE 

resources.282

ii. Commission Determination

164. The provision adopted in this Final Rule requires that transmission providers allow 

disputing parties to unilaterally seek dispute resolution procedures. In response to MISO

and PG&E, we again note that, to the extent MISO and CAISO believe that they comply

with the adopted pro forma LGIP provisions, they may explain their positions in their

compliance filings. 

165. We also clarify for EEI that, although each party will bear its own costs to 

participate in the dispute resolution process, the cost of the decision-maker will be split 

equally among the disputing parties. Furthermore, we clarify for EEI that the process 

adopted by this Final Rule, unlike the arbitration process described in section 13.5 of the 

pro forma LGIP, is non-binding and thus does not limit a party’s right to seek judicial 

relief. 

166. In response to ISO-NE, we note that its concerns about delays and uncertainty 

would still be present if disputing participants choose to participate in the existing 

arbitration process described in section 13.5 of the pro forma LGIP. If transmission

providers have agreed to participate in an arbitration process pursuant to section 13.5, 

other interconnection customers, including those in the same cluster as the disputing 

 282 Id. at 20-21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 102 -

interconnection customer would experience a delay. Furthermore, as discussed above, 

multiple generation developers have alleged that the section 13.5 arbitration process is 

effectively unavailable to interconnection customers because transmission providers are 

disinclined to participate. It will benefit the interconnection process for there to be an 

available avenue of dispute resolution to resolve a genuine matter of dispute. 

167. Additionally, in response to ISO-NE’s argument that it avoids delay by “allowing 

for” a section 206 complaint, we answer that the pro forma LGIP already allows parties 

to file a complaint pursuant to section 206 of the FPA, and this option is still available 

even if the disputing parties mutually agree to the arbitration process described in section 

13.5 of the pro forma LGIP.283 Thus, we disagree with ISO-NE that “allowing for” the 

process pursuant to section 206 is sufficient to address our concerns with the status quo. 

The dispute resolution provisions adopted in this Final Rule serve as an alternative to 

both the section 13.5 arbitration process and the FPA section 206 process. With regard to 

ISO-NE’s suggestion that the NOPR proposal would consume significant ISO-NE 

resources, we note that the Final Rule distributes the costs of the decision-maker 

overseeing the dispute resolution process equally among the parties to the dispute. Thus, 

even though transmission providers must allow for a dispute resolution process that a 

party may seek unilaterally, a transmission provider would only be responsible for costs 

 283 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 290 (stating that invocation 

of the arbitration process does not “circumscribe[] the Parties’ right to avail themselves 

of the Commission’s complaint process”).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 103 -

if it is a party to the dispute. In such a scenario, the transmission provider would be 

responsible “for its own costs incurred” during the process (i.e., the cost to represent its 

position in the section 13.5.5 dispute resolution process) and the cost of the decisionmaker “divided equally among each Party to the dispute.” Thus, if a transmission 

provider is not a party to a dispute, it would not be ultimately responsible for any costs 

related to the dispute resolution process. If the transmission provider is a party to a three 

party dispute, it would be responsible for “its own costs incurred” and one-third of the 

cost of the decision-maker.

h. SGIP DRS Process 

i. Comments

168. Competitive Suppliers argue that the Commission should generically adopt the 

dispute resolution provisions of the pro forma SGIP, which allow disputing parties to 

contact DRS.284 Similarly, ISO-NE contends that, if the Commission determines that 

there is a need to revise the existing pro forma LGIP and pro forma LGIA dispute 

resolution provisions, then the Commission should adopt the same approach provided for 

in the pro forma SGIP.285 TDU Systems also contend that parties in non-RTO/ISO 

regions with disputes arising under the LGIP and LGIA, like parties to the pro forma 

 284 Competitive Suppliers 2017 Comments at 6.

285 ISO-NE 2017 Comments at 19.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 104 -

SGIA and pro forma SGIP, should have the unilateral ability to seek DRS’ assistance.286 

For non-RTO/ISO regions, SEIA requests that the Commission clarify that DRS is

available to resolve interconnection disputes and will abide by the same general 

structures as those proposed in the NOPR.287 

ii. Commission Determination 

169. In the NOPR, the Commission sought comment on “the appropriateness of 

adopting procedures similar to those outlined in the pro forma SGIP.”288 The process

described in section 4.2 of the pro forma SGIP allows parties to contact DRS for 

assistance in resolving an interconnection dispute. Section 4.2.4 of the pro forma SGIP 

states that DRS will assist in resolving a dispute or in selecting an appropriate dispute 

resolution venue. Additionally, section 4.2.6 of the pro forma SGIP states that if neither 

party elects to contact DRS or if the attempted dispute resolution fails, “either Party may 

exercise whatever rights and remedies it may have in equity or law consistent with the 

terms of these procedures.” 

170. In response to the Commission’s request for comments, only Competitive 

Suppliers and ISO-NE commented favorably in response to this suggestion. For this 

reason, we decline to take action to adopt dispute resolution procedures similar to those 

 286 TDU Systems 2017 Comments at 11-13.

287 SEIA 2017 Comments at 14-15. We assume SEIA is referring to DRS.

288 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 86.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 105 -

in the pro forma SGIP. Nonetheless, nothing in this Final Rule precludes disputing 

parties from contacting DRS if they wish to participate in dispute resolution through that 

avenue.

171. In response to SEIA, we note that, consistent with Order No. 2003, DRS is always 

available to assist parties in resolving generator interconnection disputes. We note, 

however, that the new requirements imposed by this Final Rule apply only to the nonbinding dispute resolution process established through new section 13.5.5 in the pro 

forma LGIP, which is a non-DRS process.

5. Capping Costs for Network Upgrades 

a. NOPR Request for Comments 

172. As part of the interconnection feasibility study and system impact study, the pro 

forma LGIP requires that transmission providers provide a good faith estimate of the cost 

of interconnection facilities and network upgrades needed to accommodate an 

interconnection customer’s requested level of interconnection service.289 The 

transmission provider includes this cost estimate with the facilities study results, typically 

with a stated accuracy margin within 10 to 20 percent of the estimate.290 After 

completion of the construction of the transmission provider’s interconnection facilities 

and network upgrades needed to interconnect a generating facility, the transmission 

 289 See, e.g., pro forma LGIP Sections 6.2 and 7.3. 

290 Pro forma LGIP Section 8.3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 106 -

provider conducts a true-up to assess the final cost of construction to the interconnection 

customer. The transmission provider provides a final invoice to the interconnection 

customer that details variations between actual and estimated costs. Overpayment by the 

interconnection customer results in a refund to the interconnection customer, or a 

surcharge in case of an underpayment.291

173. The Commission sought comment on whether it should revise the pro forma LGIP 

and pro forma LGIA to provide for a cost cap that would limit an interconnection 

customer’s network upgrade costs at the higher bound of a transmission provider’s cost 

estimate plus a stated accuracy margin following a certain stage in the interconnection 

study process. Such a cap could permit the interconnection customer to assume costs that 

exceed the cap under limited circumstances, such as where there is demonstrable proof 

that the cause of a cost increase is beyond the transmission provider’s control.292 The 

cost cap could also specify which party or parties would assume network upgrade costs in 

excess of the cap. The Commission further sought comment on how to minimize 

potential cost shifts to other parties if such a cost cap is imposed. The Commission also 

sought comments on alternative proposals, or additional steps that the Commission could 

 291 Pro forma LGIA Art. 12.

292 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 95.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 107 -

take, to provide more cost certainty to interconnection customers during the 

interconnection study process.293

b. Comments 

174. A minority of commenters,294 primarily renewable generation developers and

transmission owners in CAISO, support the idea of network upgrade cost caps. AWEA 

notes that interconnection customers often pay costs that exceed the upper bound of a 

transmission provider’s estimates, and this can significantly disrupt an interconnection 

customer’s business model.295 AWEA argues that a cost cap would protect 

interconnection customers from cost overruns, allow them to accurately assess risk, and 

reduce the number of late-stage withdrawals due to increased cost certainty, which in turn 

would produce more accurate cost estimates.296 AWEA, Generation Developers, and 

NextEra assert that the imposition of a cost cap should incentivize more accurate cost 

 293 Id.

294 These commenters include: AWEA 2017 Comments at 26; CAISO 2017 

Comments at 13; First Solar 2017 Comments at 4; Joint Renewable Parties 2017 

Comments at 3; Generation Developers 2017 Comments at 22-23; EDP 2017 Comments 

at 5-6; NextEra 2017 Comments at 17’ and PG&E 2017 Comments at 5. 

295 AWEA 2017 Comments at 25.

296 Id. at 25-26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 108 -

estimates, and AWEA contends that cost shifts should be minimal if the transmission 

provider estimates costs more accurately.297

175. Generation Developers argue that if there is an overage from the cost estimate, it is 

just and reasonable to socialize that overage. Generation Developers acknowledge that 

this is a variation from strict “but for” interconnection policy but assert that the variation 

is justified because all users of the transmission network receive benefits from the 

interconnection customer’s network upgrades. 

176. APS, AVANGRID, Bonneville, EDP, Generation Developers, Invenergy, MISO 

TOs, NextEra, NorthWestern, and Tri-State contend that cost caps could lead to inflated 

cost estimates for network upgrades.298 On the other hand, commenters that support cost 

caps argue that increased cost estimates can either be addressed or are a reasonable tradeoff for implementing a cost cap.299 

177. CAISO states that, while cost caps come with some risk, they allow generators to 

have clear demarcations for their financial responsibilities going forward, which CAISO 

 297 Id. at 27; Generation Developers 2017 Comments at 23-24; NextEra 2017 

Comments at 17-19.

298 APS 2017 Comments at 3; AVANGRID 2017 Comments at 20; Bonneville 

2017 Comments at 3; EDP 2017 Comments at 5; Generation Developers 2017 Comments 

at 24; Invenergy 2017 Comments at 9; MISO TOs 2017 Comments at 10-11; NextEra 

2017 Comments at 17; NorthWestern 2017 Comments at 4; Tri-State 2017 Comments 

at 5.

299 Generation Developers 2017 Comments at 24, AWEA 2017 Comments at 27, 

and NextEra 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 109 -

believes mitigates risk and financial uncertainty when generators submit proposals to 

provide capacity and later seek financing for construction.300 

178. Most responsive commenters301 oppose revising the pro forma LGIP and pro 

forma LGIA to impose network upgrade cost caps. Several opposing commenters argue 

that cost caps would unfairly shift network upgrade costs from interconnection customers 

to load, transmission customers, or other interconnection customers that neither benefit 

from the generation nor caused the need for the upgrades.302 Several commenters also 

 300 CAISO 2017 Comments at 13.

301 Alliant 2017 Comments at 5; AEP 2017 Comments at 3; AFPA 2017 

Comments at 5; AVANGRID 2017 Comments at 19; Bonneville 2017 Comments at 3; 

Competitive Suppliers 2017 Comments at 7; Duke 2017 Comments at 7; EEI 2017 

Comments at 28; ELCON 2017 Comments at 2; Eversource 2017 Comments at 12; 

Imperial 2017 Comments at 18; IECA2017 Comments at 2; ISO-NE 2017 Comments 

at 21; ITC 2017 Comments at 12-13; MidAmerican 2017 Comments at 11-12; MISO 

2017 Comments at 21; MISO TOs 2017 Comments at 7; Modesto 2017 Comments at 18; 

NEPOOL 2017 Comments at 9; Non-Profit Utility Trade Associations 2017 Comments at 

6; NorthWestern 2017 Comments at 4; NYISO 2017 Comments at 19; PJM 2017 

Comments at 9; PSEG/PPL 2017 Comments at 3; Salt River 2017 Comments at 9; 

Southern 2017 Comments at 15-16; TAPS 2017 Comments at 3; TDU Systems 2017 

Comments at 14-16; Tri-State 2017 Comments at 5; TVA 2017 Comments at 6-7; Xcel 

2017 Comments at 11. 

302 Alliant 2017 Comments at 6; AEP 2017 Comments at 3; Duke 2017 Comments 

at 7; EEI 2017 Comments at 29; ELCON 2017 Comments at 2,5; Idaho Power 2017 

Comments at 2-3; Imperial 2017 Comments at 19; IECA 2017 Comments at 2; ISO-NE 

2017 Comments at 22; MidAmerican 2017 Comments at 11-12; MISO 2017 Comments 

at 21; MISO TOs 2017 Comments at 7; Modesto 2017 Comments at 19; Non-Profit 

Utility Trade Associations 2017 Comments at 6; NorthWestern 2017 Comments at 4; 

PJM 2017 Comments at 10; PSEG/PPL 2017 Comments at 5; Salt River 2017 Comments 

at 9; Southern 2017 Comments at 15-16; TAPS 2017 Comments at 5; TDU Systems 2017 

Comments at 14-16; TVA 2017 Comments at 6-7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 110 -

assert that cost caps would violate the Commission’s “but for” and cost causation policies 

for the assignment of interconnection network upgrade costs.303 Duke, EEI, and 

NorthWestern contend that if the Commission establishes a cost cap and requires that 

transmission providers assume any excess costs, transmission providers could face 

challenges of whether such costs are prudent transmission investments.304 EEI, NonProfit Utility Trade Associations, and TAPS argue that implementing cost caps will likely 

result in more frequent and contentious litigation.305

179. Modesto argues that because smaller entities do not frequently estimate 

interconnection facility and network upgrade costs, their cost estimates are likely 

susceptible to greater variability, which could lead to a greater inaccuracy. Modesto 

asserts that smaller entities essentially would be penalized through cost caps on network 

upgrades.306 

 303 AEP 2017 Comments at 5; AVANGRID 2017 Comments at 20; EEI 2017 

Comments at 28-29; ITC 2017 Comments at 12-13; MISO 2017 Comments at 21; MISO 

TOs 2017 Comments at 7; PJM 2017 Comments at 9-10; PSEG/PPL 2017 Comments 

at 5; Salt River 2017 Comments at 9; Southern 2017 Comments at 15-16; TAPS 2017 

Comments at 6; TDU Systems 2017 Comments at 14-16; TVA 2017 Comments at 6-7.

304 Duke 2017 Comments at 7-8; EEI 2017 Comments at 29-30; NorthWestern 

2017 Comments at 4.

305 EEI 2017 Comments at 33-34; Non-Profit Utility Trade Associations 2017 

Comments at 11; TAPS 2017 Comments at 7.

306 Modesto 2017 Comments at 19-20.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 111 -

180. Several commenters contend that cost caps are unwarranted because many of the 

variables that affect cost estimates are outside the transmission provider’s control and are 

based on the best data available at the time.307 AFPA argues that cost caps remove risk 

from interconnection customers and may remove the incentive for interconnection 

customers to mitigate cost overruns in network upgrades.308 IECA expresses concern that 

industrial consumers will have to pay for cost overruns resulting from a cost cap and that 

cost caps would encourage developers and utilities to be equally complacent about cost 

overruns.309

181. ITC, MISO, Non-Profit Utility Trade Associations, and Xcel state that welldefined milestones and milestone payments are preferable to a cost cap.310 

182. NYISO and Indicated NYTOs state that NYISO already has a process in place in 

its tariff to allocate actual costs that exceed cost estimates.311 Indicated NYTOs contend 

that NYISO’s provisions encourage interconnection customers to efficiently locate their 

 307 AEP 2017 Comments at 3; Duke 2017 Comments at 7; EEI 2017 Comments at 

30-32; ITC 2017 Comments at 14-15; MidAmerican 2017 Comments at 12; MISO 2017 

Comments at 21; MISO TOs 2017 Comments at 10-11; PSEG/PPL 2017 Comments at 5; 

Salt River 2017 Comments at 9; Southern 2017 Comments at 16; Tri-State 2017 

Comments at 5.

308 AFPA 2017 Comments at 9.

309 IECA 2017 Comments at 2.

310 ITC 2017 Comments at 15; MISO 2017 Comments at 22-23; Non-Profit Utility 

Trade Associations 2017 Comments at 1-2, 4, 10-11; Xcel 2017 Comments at 12.

311 NYISO 2017 Comments at 19; Indicated NYTOs 2017 Comments at 5.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 112 -

generating facility and strike a reasonable balance between providing certainty to 

interconnection customers and minimizing the imposition of unnecessary costs to load.312 

NYISO asserts that adoption of bright line cost caps would likely require more detailed 

studies, cost estimates, and increased cost and time, contrary to the stated principles of 

the NOPR.313 NEPOOL notes that New England resolved its disputes over cost 

allocation for interconnections and regional transmission upgrades well over a decade 

ago through the interconnection cost allocation method in the ISO-NE OATT.314

183. Salt River and TVA believe that it would be inappropriate for the Commission to 

attempt to impose a cap on the costs that can be collected by a not-for-profit 

governmental utility, via the reciprocity condition or otherwise.315

184. CAISO states that its system of cost caps may be more difficult to implement 

outside of regions where ratepayers ultimately pay for generator interconnection-driven 

network upgrades.316 CAISO notes that, in CAISO, the interconnection customer only 

provides the initial financing for its network upgrades.317 CAISO states that, upon 

 312 Indicated NYTOs 2017 Comments at 6.

313 NYISO 2017 Comments at 19.

314 NEPOOL 2017 Comments at 9.

315 Salt River 2017 Comments at 10; TVA 2017 Comments at 6-7.

316 CAISO 2017 Comments at 14.

317 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 113 -

reaching commercial operation, those costs are reimbursed by the transmission owner and 

included in that transmission owner’s transmission revenue requirement paid by 

ratepayers.318

185. AFPA, ELCON, ITC, SEIA, and Invenergy assert that policies other than cost 

caps will provide greater downward pressure on network upgrade costs including 

improving cost transparency, transmission planning that anticipates future generation 

needs, and aligning interconnection procedures with resource procurement processes.319

186. Eversource suggests that the Commission instead explore the transmission 

provider’s cost estimation process.320 Eversource suggests that, to improve cost 

estimates, the Commission should require interconnection customers to use the currently 

optional facilities study in the LGIP.321

187. Xcel recommends that, instead of imposing cost caps, the Commission should 

reevaluate its policy discussed in Order No. 2003 and implement regional variations that 

allow transmission costs to be assigned to the interconnection customer after the 

 318 Id.

319 AFPA 2017 Comments at 5; ELCON 2017 Comments at 5; ELCON 2017 

Comments at 5; ITC 2017 Comments at 15; SEIA 2017 Comments at 15; Invenergy 2017 

Comments at 9-10.

320 Eversource 2017 Comments at 13-14.

321 Id. at 15.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 114 -

execution of an LGIA.322 Xcel further recommends limiting the interconnection 

customer’s cost responsibility to the specific facilities identified in the signed LGIA, 

rather than allowing the RTO/ISO, as transmission provider, to later modify the list of 

required facilities. Xcel asserts that if facilities are identified after the interconnection 

customer and transmission provider sign an LGIA, the costs of those facilities should be 

recovered from transmission customers through the transmission expansion cost 

allocation processes in the RTO/ISO tariff. Xcel believes that the Commission should 

allow regions to determine if or when such costs are allocated either locally or regionally 

to transmission customers.323

188. TAPS opposes a generic rule establishing a cost cap and also opposes a generic 

rule that bars all cost caps.324 Duke states that transmission providers should be able to 

voluntarily adopt cost caps if done so through stakeholder processes.325

c. Commission Determination

189. In this Final Rule, we decline to take any action related to capping costs for 

network upgrades. We find that there is insufficient evidence in the record to support

cost caps as a preferred solution to reducing variances from cost estimates and providing

 322 Xcel 2017 Comment at 12.

323 Id. at 12-13.

324 TAPS 2017 Comments at 8.

325 Duke 2017 Comments at 8.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 115 -

greater cost certainty to interconnection customers. Therefore, we decline to propose

revisions to the pro forma LGIP and pro forma LGIA to institute a cap on the cost of 

network upgrades required for interconnection. However, as suggested by Duke, we will 

not bar a transmission provider from proposing to establish cost caps for network upgrade 

costs within its footprint by submitting a separate filing pursuant to section 205 of the 

FPA. 

190. We recognize the value of providing more accurate cost estimates to 

interconnection customers of the network upgrades needed to interconnect their 

generating facilities. Smaller deviations between the cost estimate and the final costs of 

the network upgrades would reduce risk and uncertainty faced by the interconnection 

customer. We note that other actions in this Final Rule, including the reforms on 

transparency regarding study models and assumptions and identification and definition of 

contingent facilities, could contribute to improved accuracy of cost estimates for network 

upgrades. Additionally, we understand that greater cost certainty, where reasonably 

achievable without creating overly onerous requirements, could reduce queue 

withdrawals and their cascading effects on other projects within the queue. We 

encourage transmission providers and stakeholders to continue to work together to 

improve the cost estimation process.

B. Promoting More Informed Interconnection

191. In the NOPR, the Commission proposed reforms designed to improve 

interconnection process transparency and provide improved information to benefit all 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 116 -

participants in the interconnection process. In addition to the proposed reforms, the 

Commission sought comment on proposals or additional steps that the Commission could 

take to improve the resolution of issues that arise when affected systems are impacted by 

a proposed interconnection.

1. Identification and Definition of Contingent Facilities

a. NOPR Proposal

192. The Commission currently requires transmission providers to identify for 

interconnection customers contingencies affecting interconnection studies326 and list 

applicable contingent facilities in interconnection agreements.327 In the NOPR, the 

Commission proposed to revise the pro forma LGIP to require transmission providers to 

detail the methods they use to determine which facilities are contingent facilities. The 

Commission proposed that a method be transparent and sufficiently detailed to allow 

interconnection customers to determine why a specific contingent facility is included and 

how it impacts the interconnection request. The Commission also proposed that 

transmission providers provide the contingent facility list at the conclusion of the system 

impact study. The Commission further proposed that the transmission provider should, 

 326 Pro forma LGIP Section 2.3.

327 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 409 (“[i]f it is apparent to 

the Parties . . . that contingencies (such as other Interconnection Customers terminating 

their LGIAs) might affect the financial arrangements, the Parties should include such 

contingencies in their LGIA and address the effect of such contingencies on their 

financial obligations”).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 117 -

upon request, provide the estimated network upgrade costs and in-service completion 

time associated with each identified contingent facility when this information is not 

commercially sensitive. In particular, the Commission proposed to add a new section 3.8 

to the pro forma LGIP as follows (with proposed additions in italics):

3.8 Identification of Contingent Facilities

Transmission Provider shall post in this section a method for identifying 

the Contingent Facilities to be provided to Interconnection Customer at the 

conclusion of the System Impact Study and included in Interconnection 

Customer’s GIA. The method shall be sufficiently transparent to determine 

why a specific Contingent Facility was identified and how it relates to the 

interconnection request. Transmission Provider shall also provide, upon 

request of the Interconnection Customer, the estimated interconnection 

facility and/or network upgrade costs and estimated in-service completion 

time of each identified Contingent Facility when this information is not 

commercially sensitive.

193. In addition, the Commission proposed to add the following new definition to 

section 1 of the pro forma LGIP (with proposed additions in italics): 

Contingent Facilities shall mean those unbuilt interconnection facilities 

and network upgrades upon which the interconnection request’s costs, 

timing, and study findings are dependent, and if not built, could cause a 

need for interconnection restudies or reassessments of the network 

upgrades, costs, or timing. 

194. The Commission also sought further comment on how transmission providers 

currently identify contingent facilities, as well as additional recommendations to improve 

the existing approach. Finally, the Commission sought comment on whether the method 

for determining contingent facilities should be harmonized as much as possible. To this 

end, the Commission sought comment on the usefulness of requiring transmission 

providers to include a distribution factor analysis in their methodologies for identifying 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 118 -

contingent facilities, and if so, whether a specific distribution factor should be 

implemented in the pro forma LGIP (e.g., a five percent distribution factor).

b. General 

i. Comments

195. Most responsive commenters support328 or do not oppose329 the proposal to require 

transmission providers to publish a method for identifying contingent facilities in the 

LGIP. Several commenters state that the proposal will better inform the interconnection 

process and may lead to lower costs and fewer withdrawals.330 AWEA, Invenergy, and 

EDP cite inconsistent or non-transparent treatment of contingent facilities across 

 328 Alevo 2017 Comments at 5-6; AFPA 2017 Comments at 10; Non-Profit Utility 

Trade Associations 2017 Comments at 12-13; AWEA 2017 Comments at 30; Bonneville 

2017 Comments at 4; Joint Renewable Parties 2017 Comments at 10; Generation 

Developers at 25; SEIA 2017 Comments at 7; Portland 2017 Comments at 2; NEPOOL 

2017 Comments at 9-10; NextEra 2017 Comments at 20; ITC 2017 Comments at 16; 

Invenergy 2017 Comments at 11.

329 MISO TOs 2017 Comments at 26; Non-Profit Utility Trade Associations 2017 

Comments at 12.

330 AFPA 2017 Comments at 10; AWEA 2017 Comments at 30; NEPOOL 2017 

Comments at 10; NextEra 2017 Comments at 20; Invenergy 2017 Comments at 12; EDP 

2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 119 -

regions.331 Several commenters assert that the proposal will reduce opportunities for 

undue discrimination and disputes.332 

196. AWEA and NextEra contend that the proposal will place a minimal burden on 

transmission providers.333 ISO-NE comments that the proposal appropriately balances 

the need for regional flexibility to maintain the existing methods with the need to 

improve transparency regarding the interconnection process.334 CAISO states that 

information on contingent facilities is important to inform an interconnection customer 

about potential delays that might necessitate renegotiation of the interconnection 

customer’s power purchase agreement. NextEra supports the Commission’s guidance 

that a transmission provider’s method to determine contingent facilities be detailed and 

states that an unverified list of contingent facilities creates uncertainty regarding potential 

restudies and revised cost responsibility for the interconnection customer.335

197. AWEA comments that the interconnection customer should not be financially 

responsible for any facilities that are not listed among the contingent facilities and that 

 331 EDP 2017 Comments at 6; AWEA 2017 Comments at 29; Invenergy 2017 

Comments at 11.

332 AFPA 2017 Comments at 10; EDP 2017 Comments at 6; AWEA 2017 

Comments at 31; Invenergy 2017 Comments at 11.

333 AWEA 2017 Comments at 31; NextEra 2017 Comments at 21.

334 ISO-NE 2017 Comments at 25.

335 NextEra 2017 Comments at 20.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 120 -

even contingent facilities omitted in error should not be the financial responsibility of the 

interconnection customer.336

198. A minority of responsive commenters oppose the proposal.337 MISO and Southern

request that the Commission permit transmission providers to post the proposed 

information in their business practice manuals or OASIS-posted business practices rather 

than in the LGIP, as this information is technical and more suitable for a business practice 

manual and may need frequent changes to address characteristics of new technologies.338 

Several commenters state that no new procedures are necessary to identify and define

contingent facilities.339

ii. Commission Determination

199. We adopt the NOPR proposal to add a new section 3.8 to the pro forma LGIP

requiring transmission providers to publish a method for identifying contingent facilities 

in their LGIPs subject to clarification as outlined below. Specifically, the Commission 

adds section 3.8 to the pro forma LGIP as follows (with clarifying additions to the 

language originally proposed in the NOPR in italics):

3.8 Identification of Contingent Facilities

 336 AWEA 2017 Comments at 34

337 Modesto 2017 Comments at 21; Southern 2017 Comments at 19; EEI 2017 

Comments at 38.

338 MISO 2017 Comments at 24-25; Southern 2017 Comments at 19.

339 AES 2017 Comments at 8-9; Southern 2017 Comments at 19.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 121 -

Transmission Provider shall post in this section a method for identifying the 

Contingent Facilities to be provided to Interconnection Customer at the 

conclusion of the System Impact Study and included in Interconnection 

Customer’s GIA. The method shall be sufficiently transparent to determine 

why a specific Contingent Facility was identified and how it relates to the 

interconnection request. Transmission Provider shall also provide, upon 

request of the Interconnection Customer, the estimated interconnection 

facility and/or network upgrade costs and estimated in-service completion 

time of each identified Contingent Facility when this information is readily 

available and not commercially sensitive.

200. We note that commenters widely support the adoption of this requirement. We 

agree with commenters that this requirement will increase transparency in the 

interconnection process, better inform interconnection customers, and, consequently,

result in fewer interconnection disputes and withdrawals. The Commission notes that,

while some transmission providers may provide information on contingent facilities, the 

record indicates that this information may not be available from all transmission 

providers. We find that requiring transmission providers to publish a method for 

determining contingent facilities in the LGIP will ensure that there will be a transparent 

method applied on a non-discriminatory basis across all regions. We also disagree with 

MISO’s and Southern’s arguments that it would be more appropriate to publish methods 

for identifying contingent facilities in business practice manuals or on OASIS. The 

Commission’s “rule of reason” policy340 requires provisions that significantly affect rates, 

 340 See Pacificorp, 127 FERC ¶ 61,144, at P 11 (2009); City of Cleveland, Ohio v. 

FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985) (finding that utilities must file “only those 

practices that affect rates and service significantly, that are reasonably susceptible of 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 122 -

terms, and conditions should be in the filed tariff.341 The Commission finds, based on the 

record above, that information on contingent facilities materially affects rates, terms, and 

conditions, and therefore, needs to be part of the tariff. However, while transmission 

providers will have to publish their methods in the LGIP, certain technical 

implementation details relating to the methods that, consistent with the rule of reason, 

have less direct effect on rates, terms and conditions, may be published in a business 

practice manual. 

201. We disagree with AWEA’s argument that the Final Rule should exempt the

interconnection customer from financial responsibility for any facilities that are not 

identified as contingent facilities, because changes in the interconnection queue may 

require changes to or subtractions from the list of contingent facilities. Thus, we find that 

the Final Rule strikes the right balance to accomplish our goal of increasing transparency.

 

specification, and that are not so generally understood in any contractual arrangement as 

to render recitation superfluous”); Public Serv. Comm’n of N.Y. v. FERC, 813 F.2d 448, 

454 (D.C. Cir. 1987) (holding that the Commission properly excused utilities from filing 

policies or practices that dealt with only matters of “practical insignificance” to serving 

customers). 

341 Cal. Indep. Sys. Operator Corp. 119 FERC ¶ 61,076, at P 656 (2007) (citing 

ANP Funding I, LLC v. ISO-NE, Inc., 110 FERC ¶ 61,040, at P 22 (2005); Prior Notice 

and Filing Requirements Under Part II of the Federal Power Act, 64 FERC ¶ 61,139, 

at 61,986-89, order on reh’g, 65 FERC ¶ 61,081 (1993)).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 123 -

c. Timing

i. Comments

202. Several commenters support the proposal that transmission providers provide the 

list of contingent facilities applicable to an interconnection request at the close of the 

system impact study phase.342 AWEA comments that the timing for the identification of 

contingent facilities has been a major issue for interconnection customers. It argues that, 

currently, interconnection customers only receive relevant contingent facility information 

after signing an LGIA. AWEA asserts that the timing requirements in this proposal 

remove risk for the interconnection customer.343 

203. MISO requests that the Commission clarify that, in the context of MISO’s phased 

system impact study process, the requirement would apply only after the final system 

impact study.344 

ii. Commission Determination

204. We adopt the NOPR proposal to require transmission providers to provide the list 

of contingent facilities applicable to an interconnection request at the close of the system 

impact study phase. The system impact study considers generating facilities and 

 342 AWEA 2017 Comments at 31; Duke 2017 Comments at 8; Generation 

Developers 2017 Comments at 25; MISO 2017 Comments at 25-26; TDU Systems 2017 

Comments at 26.

343 AWEA 2017 Comments at 31.

344 MISO 2017 Comments at 26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 124 -

identified network upgrades associated with higher-queued interconnection requests, and 

an accompanying list of contingent facilities can contextualize these results. We find that 

this timing allows interconnection customers to access contingent facility information 

early enough to better understand their potential risk exposure and to expedite decisions 

on queue withdrawal, resulting in a more efficient interconnection process. We note that 

the majority of responsive commenters support the requirement to provide contingent 

facility information at the conclusion of the system impact study phase. In response to 

MISO’s request that we address how the Final Rule applies to its system impact study 

process, we will evaluate each transmission provider’s tariff provisions at the time that it 

submits its compliance filing. In that filing, MISO can explain how its compliance 

proposal allows for the interconnection customer to use contingent facilities information 

to understand risk exposure and expedite decisions on queue withdrawal. 

d. Requirements for Estimated Network Upgrade Costs and 

In-Service Completion Times

i. Comments

205. A majority of responsive commenters support the proposed requirement to provide 

the costs and in-service completion time for each identified contingent facility.345 AWEA 

states that interconnection customers use information about potential cost increases, as 

 345 AWEA 2017 Comments at 32; Alevo 2017 Comments at 5-6; Forecasting 

Coalition 2017 Comments at 4; Generation Developers 2017 Comments at 26; TDU 

Systems 2017 Comments at 16-17; NEPOOL 2017 Comments at 10; NextEra 2017 

Comments at 20; SEIA 2017 Comments at 7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 125 -

well as timing of necessary upgrades, to make business decisions and assess risk.346 

Generation Developers explain that there is little value in identifying a contingent facility

if the interconnection customer still has no information about its associated costs and 

timing.347 AWEA contends that non-disclosure agreements can address commercial 

sensitivities related to contingent facilities.348 Invenergy states that PJM, MISO, and SPP 

already provide this information in some form and that it is unaware of any commercially 

sensitive information that would need to be revealed in this process.349 Other 

commenters state that the burden on transmission providers would be minimal.350

206. Duke, MidAmerican, and EEI oppose the proposed requirement to provide 

estimated network upgrade costs and in-service completion times for each identified 

contingent facility.351 EEI argues that the Commission should address concerns related to 

potential commercially-sensitive information and Critical Energy/Electric Infrastructure 

Information (CEII). It asks the Commission to clarify that transmission providers need 

not disclose proprietary, commercially-sensitive, or CEII information without the 

 346 AWEA 2017 Comments at 32.

347 Generation Developers 2017 Comments at 26.

348 AWEA 2017 Comments at 32.

349 Invenergy 2017 Comments at 12.

350 NextEra 2017 Comments at 20; AWEA 2017 Comments at 32.

351 Duke 2017 Comments at 9-10; MidAmerican 2017 Comments at 8; EEI 2017 

Comments at 38.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 126 -

appropriate consent and/or non-disclosure protections.352 EEI also has concerns about the 

proposal’s costs and the appropriate recovery mechanisms.353 Duke states that schedules

and cost estimates for milestones are available on OASIS via links to completed 

generator interconnection studies.354 

207. A number of commenters state that some or all of the information referenced in 

the proposal is already made available in their region. ISO-NE states that estimated costs 

and in-service completion times associated with contingent facilities are available in the 

interconnection study reports for the higher-queued projects that are primarily responsible 

for the cost of the contingent facility, and those reports are available to interconnection 

customers on the ISO-NE website.355 Bonneville states that it provides general estimates 

and schedules associated with contingent facilities in its study reports.356 MISO states 

that it already provides the estimated network upgrade costs and in-service completion 

time of each identified contingent facility via its MISO Transmission Expansion Plan 

process, updated quarterly and posted publicly.357 MidAmerican comments that it sees no 

 352 EEI 2017 Comments at 39.

353 Id.

354 Duke 2017 Comments at 8.

355 ISO-NE 2017 Comments at 24.

356 Bonneville 2017 Comments at 4.

357 MISO 2017 Comments at 25.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 127 -

value in providing this information and expresses concern about the potential 

administrative burden.358

208. TVA comments that it is difficult to estimate the in-service timing of contingent 

facilities in the system impact study phase, as often the full scope of work is not known 

until the facilities study.359 TVA adds that to provide this information at the system 

impact study phase would increase the cost and duration of all system impact study 

efforts.360

209. Several commenters suggest that the Commission modify or clarify this aspect of 

the proposal. NextEra suggests clarifying the proposal to limit the information the 

transmission provider provides to the interconnection customer based on what the 

transmission provider could reasonably access so that transmission providers need not 

obtain information that they may not readily have available.361 Similarly, while Portland 

does not object to this aspect of the proposal, it argues that such information would be 

limited to the best information that the transmission provider has access to at the time.362 

 358 MidAmerican 2017 Comments at 8.

359 TVA 2017 Comments at 8.

360 Id.

361 NextEra 2017 Comments at 20.

362 Portland 2017 Comments at 3. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 128 -

210. Forecasting Coalition and Alevo suggest that the transmission provider provide 

additional information to the interconnection customer. Alevo suggests that transmission 

providers also provide “a detailed list of the symptoms that the transmission 

owner/operator is trying to cure.”363 Alevo comments that this information may allow the 

interconnection customer to offer a more cost-effective solution (e.g., installing electric 

storage rather than building a new substation).364 Forecasting Coalition requests that the 

transmission provider identify the facility’s limiting element along with the details on the 

electrical limiting element’s rating.365 

211. AWEA and Generation Developers argue that the transmission provider should 

have to provide information on each identified contingent facility’s estimated costs and

timing even if the interconnection customer has not explicitly requested it.366 

ii. Commission Determination

212. We adopt the NOPR proposal, subject to modification, and require the

transmission provider to provide, upon request of the interconnection customer, the 

estimated network upgrade costs and estimated in-service completion time associated 

 363 Alevo 2017 Comments at 5-6.

364 Id.

365 Forecasting Coalition 2017 Comments at 4.

366 AWEA 2017 Comments at 31-32; Generation Developers 2017 Comments 

at 25-26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 129 -

with each identified contingent facility when this information is readily available367 and 

not commercially sensitive. We are persuaded by comments that contend that this

information helps interconnection customers to better assess the business risks associated 

with contingent facilities and may prevent instances of late-stage withdrawal. We find 

that these benefits, in turn, lead to a more efficient and informed interconnection process. 

213. In response to comments on the administrative burden created by this proposal, we

find NextEra’s and Portland’s comments persuasive. We therefore modify the proposal 

to clarify that transmission providers must provide information regarding costs and inservice completion times only if such information is “readily available.” This will also 

address TVA’s concerns about increasing the costs of the system impact study phase. 

This clarification strikes a balance between providing more information for the 

interconnection customer and limiting the scope of what the transmission provider must

do. 

214. In response to EEI’s concern about commercially-sensitive information and CEII, 

we clarify that the Final Rule does not require the transmission provider to disclose any 

such information without appropriate non-disclosure protections.

 367 In Order No. 792, the Commission defined “readily available” information as 

“information that the [t]ransmission [p]rovider currently has on hand,” which does not 

require that the transmission provider create new data. Small Generator Interconnection 

Agreements and Procedures, Order No. 792, 145 FERC ¶ 61,159, at PP 63-64 (2013), 

clarified, Order No. 792-A, 146 FERC ¶ 61,214 (2014) (Order No. 792-A).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 130 -

215. In response to comments from AWEA and Generation Developers requesting that 

transmission providers provide information regarding costs and in-service completion 

times regardless of whether the interconnection customer requests it, we disagree. We

note, consistent with comments from MidAmerican, that not all interconnection 

customers may need access to this information.368 The aim of the requirements adopted 

here is to improve transparency and better inform interconnection customer decisionmaking. Thus, if the interconnection customer does not request cost or in-service 

completion date information, we find it unnecessary to require the transmission provider

to produce this information.

216. In response to comments from Alevo and Forecasting Coalition requesting that the 

transmission provider provide additional information related to line ratings and

underlying symptoms, we find that such information is outside the scope of the NOPR 

proposal, which focuses on contingent facilities. 

e. Definition of Contingent Facility

i. Comments

217. AWEA and Generation Developers support the proposed definition of contingent 

facilities.369 MISO does not oppose the proposed definition.370 Southern suggests 

 368 MidAmerican 2017 Comments at 8.

369 AWEA 2017 Comments at 30; Generation Developers 2017 Comments at 25.

370 MISO 2017 Comments at 24.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 131 -

revising the definition to include a reference to the effect of delayed contingent facilities 

on an interconnection request.371

ii. Commission Determination

218. We adopt the proposed definition in the NOPR for contingent facilities, with a 

minor modification to reflect Southern’s comments. Specifically, we adopt the following 

definition of contingent facilities (with clarifying additions to the language originally 

proposed in the NOPR in italics): 

Contingent Facilities shall mean those unbuilt interconnection facilities 

and network upgrades upon which the interconnection request’s costs, 

timing, and study findings are dependent, and if delayed or not built, could 

cause a need for restudies of the interconnection request or a reassessment 

of the interconnection facilities and/or network upgrades and/or costs and 

timing.

f. Harmonization 

i. Comments

219. Most responsive commenters oppose harmonization.372 AWEA supports a 

harmonized requirement but explains that it is more critical that each transmission 

provider detail the method it will use to determine contingent facilities.373 AWEA asserts 

that, if a three to five percent distribution factor test increases the availability of 

 371 Southern 2017 Comments at 20.

372 See, e.g., Bonneville 2017 Comments at 5; Duke 2017 Comments at 10; 

Modesto 2017 Comments at 22; Non-Profit Utility Trade Associations 2017 Comments 

at 12-13; PJM 2017 Comments at 14.

373 AWEA 2017 Comments at 32.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 132 -

interconnection service, then it is a just and reasonable standard.374 Some commenters 

support a distribution factor test, similar to MISO’s test.375 AFPA states that consistent 

standards across regions will reduce discrimination and disputes and supports a lower 

bound on the distribution factor where a facility would not be considered contingent (e.g., 

if a facility has a distribution factor below three percent, it will not be considered 

contingent).376 Portland supports the use of a standardized percentage power transfer 

distribution factor but comments that this measure is not typically used for this purpose. 

Portland opposes a specific percentage threshold, arguing that such a threshold could 

potentially be used to manipulate the interconnection process.377

ii. Commission Determination

220. Based on the comments submitted, it is clear that transmission providers have 

different approaches for identifying contingent facilities. We find that the present record 

does not support the use of a distribution factor test or another standard method for 

identifying contingent facilities across all regions because it is not clear a single method 

 374 Id. at 34-35.

375 ITC 2017 Comments at 17; AFPA 2017 Comments at 10; AWEA 2017 

Comments at 33; Generation Developers 2017 Comments at 26; Portland 2017 

Comments at 3.

376 AFPA 2017 Comments at 10.

377 Portland 2017 Comments at 3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 133 -

would apply across different queue types and footprints. Therefore, we find that 

harmonization is not appropriate at this time.

2. Transparency Regarding Study Models and Assumptions

a. NOPR Proposal

221. To increase transparency and ensure consistency in the analysis of interconnection 

requests, the Commission proposed a requirement that transmission providers detail all 

the network models and underlying assumptions used for interconnection studies in their 

pro forma LGIPs and on OASIS.378 The Commission also proposed to require that 

transmission providers include a non-confidential network model supporting data on 

OASIS, including, but not limited to, shift factors, dispatch assumptions, load power 

factors, and power flows.379 To implement this, the Commission proposed to modify 

section 2.3 of the pro forma LGIP as follows (with proposed additions in italics):

Base Case Data. Transmission Provider shall provide base power flow, 

short circuit and stability databases, including all underlying assumptions, 

and contingency list upon request subject to confidentiality provisions in 

LGIP Section 13.1. Additionally, Transmission Provider will maintain 

network models and underlying assumptions on its OASIS site for access by 

OASIS users. Transmission Provider is permitted to require that 

Interconnection Customer and OASIS site users sign a confidentiality 

agreement before the release of commercially sensitive information or 

Critical Energy Infrastructure Information in the Base Case data. Such 

databases and lists, hereinafter referred to as Base Cases, shall include all 

(1) generation projects and (ii) transmission projects, including merchant 

transmission projects that are proposed for the Transmission System for 

 378 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 118.

379 Id. P 119.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 134 -

which a transmission expansion plan has been submitted and approved by 

the applicable authority.

222. The Commission sought comment on whether transmission providers should post 

other specific network model details and underlying assumptions on OASIS and should 

describe in the pro forma LGIP.380 The Commission also sought comment on whether 

and how transmission providers should provide notice of any variation from posted 

network model assumptions for a specific study, including whether the Commission 

should require notice of any variation to be submitted to the Commission.381 In addition, 

the Commission sought comment on any confidentiality or security concerns regarding 

the posting of specific model assumptions on OASIS or describing them in the pro forma

LGIP.382 While the Commission recognized transmission providers’ confidentiality and 

data security concerns, the Commission stated that there are likely safeguards that can 

satisfactorily address these concerns. The Commission also requested that commenters 

specify any data elements that should be subject to confidentiality or non-disclosure 

agreements.

 380 Id. P 120.

381 Id.

382 Id. P 121.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 135 -

b. General

i. Comments

223. Numerous commenters express support for the proposal to require transmission 

providers to list all the network models and underlying assumptions used for 

interconnection studies.383 Joint Renewable Parties, AFPA, and IECA believe that the 

proposal decreases opportunities for discrimination.384 AFPA also states that the 

proposal will provide important information and analytical tools for interconnection 

customers to identify potential risks and benefits of project technologies, size, timing, and 

interconnection points.385 EDP states that information access improves the 

interconnection process and that an interconnection customer should not have to make

major decisions without understanding how the transmission provider will evaluate its 

interconnection request.386 EDP notes that tariffs and business practice manuals often do 

 383 Alevo 2017 Comments at 6; Alliant 2017 Comments at 11; AFPA 2017 

Comments at 11; AWEA 2017 Comments 36-37; CAISO 2017 Comments at 17; Joint 

Renewable Parties 2017 Comments at 10; Generation Developers 2017 Comments at 27; 

EDP 2017 Comments at 6; Forecasting Coalition 2017 Comments at 4; IECA 2017 

Comments at 2; ITC 2017 Comments at 17; MidAmerican 2017 Comments at 13-14; 

NEPOOL 2017 Comments at 10; NextEra 2017 Comments at 22; SEIA 2017 Comments 

at 18; TDU Systems 2017 Comments at 18; Xcel 2017 Comment at 13-14.

384 Joint Renewable Parties 2017 Comments at 11; AFPA 2017 Comments at 11; 

IECA 2017 Comments at 2.

385 AFPA 2017 Comments at 11.

386 EDP 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 136 -

not contain evaluation and information production practices utilized by transmission 

providers.387 

224. MidAmerican asserts that the proposed reforms would assist customers in helping 

to verify the accuracy of required interconnection facilities and network upgrades.388 

NextEra also notes that receiving the models could help to verify study results with 

unexpectedly high upgrade costs. NextEra argues that better information about models 

will lead to a greater ability to determine whether a site is appropriate for interconnection 

and thus will help reduce the number of “less favorable” interconnection requests.389 

SEIA states that providing the interconnection customer directly with data will 

significantly reduce the need for study discussion and could eliminate several disputes.390

225. Xcel supports adding a description of the network model and assumptions in the 

pro forma attachments of the feasibility study agreement and the system impact study 

agreement. Xcel states that, if network model descriptions and assumptions and the study 

agreements are posted publicly, then interested interconnection customers can review 

those agreements to find how similarly situated generators were previously studied.391

 387 Id.

388 MidAmerican 2017 Comments at 13-14.

389 NextEra 2017 Comments at 22.

390 SEIA 2017 Comments at 18.

391 Xcel 2017 Comment at 13-14.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 137 -

226. Many commenters voice concerns regarding the proposed requirement that 

transmission providers post this information on OASIS.392 CAISO and NYISO state that 

they already provide network model and study assumptions on their respective 

websites.393

227. NYISO notes that, rather than posting such data on the non-password protected 

portion of NYISO’s OASIS, NYISO posts interconnection studies to the passwordprotected portion of its website because the studies contain CEII.394 

228. MISO states that it posts its network models for all MISO market participants, 

members, and interconnection customers that have signed non-disclosure agreements. 

MISO requests clarification that, if the Commission adopts its proposal, it will not require 

OASIS posting if this information is available elsewhere.395 

229. EEI argues that transmission providers should have discretion as to where to post 

this information and that interconnection customers can already request certain 

information covered by this proposal under existing CEII processes; it asserts that other 

 392 CAISO 2017 Comments at 17; NYISO 2017 Comments at 22; TDU Systems 

2017 Comments at 18-19; Xcel 2017 Comment at 14; Duke 2017 Comments at 11-12; 

EEI 2017 Comments at 40; NEPOOL 2017 Comments at 10; Non-Profit Utility Trade 

Associations 2017 Comments at 14–15; OATI 2017 Comments at 4; Salt River 2017 

Comments at 12; Southern 2017 Comments at 20; TVA 2017 Comments at 9.

393 CAISO 2017 Comments at 17; NYISO 2017 Comments at 22.

394 Id.

395 MISO 2017 Comments at 27.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 138 -

information, such as dispatch information, how transmission providers build their 

models, and how contingency files are developed, may include proprietary, confidential, 

and commercially sensitive information or intellectual property.396

230. TDU Systems state that the Commission’s pro forma CEII non-disclosure 

agreement would be appropriate and sufficient to protect against disclosure of CEII.397 

Duke suggests that transmission providers’ power flow models that have been filed with 

the Commission and identified as CEII be obtained through the Commission’s CEII 

processes.398

231. Several commenters oppose the proposal and argue that current posting procedures 

are sufficient.399 For example, Duke suggests that interconnection customers request a 

study review to discuss the underlying study assumptions with the transmission 

provider.400 In addition, ISO-NE states that its website provides base cases and study 

assumptions, subject to CEII protections.401 MISO TOs state that, to the extent that 

 396 EEI 2017 Comments at 40-41.

397 TDU Systems 2017 Comments at 18-19.

398 Duke 2017 Comments at 12.

399 AES 2017 Comments at 8-9; Duke 2017 Comments at 11; ISO-NE 2017 

Comments at 26; MISO TOs 2017 Comments at 27; PG&E 2017 Comments at 5; PJM 

2017 Comments at 14; Southern 2017 Comments at 20; TVA 2017 Comments at 9.

400 Duke 2017 Comments at11.

401 ISO-NE 2017 Comments at 26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 139 -

additional information is necessary, the best way to accomplish this is through improved 

communications between the transmission provider, the transmission owner, and the 

interconnection customer.402 PG&E states that, although an interconnection customer 

may need to execute a non-disclosure agreement prior to obtaining this information, it is 

already generally available to them.403

232. Commenters that oppose the proposal argue that it may be administratively 

burdensome.404 Duke argues, moreover, that the Commission should instead require 

transmission providers to review the information they already post on OASIS that 

provides a summary of the transmission planning processes. Then, if necessary, the 

Commission could augment that description with a high-level description of how 

transmission providers conduct interconnection studies.405 Similarly, EEI requests that 

the Commission only require transmission providers to furnish high-level descriptions on 

 402 MISO TOs 2017 Comments at 27-28.

403 PG&E 2017 Comments at 6.

404 Duke 2017 Comments at 11; EEI 2017 Comments at 40; NorthWestern 2017 

Comments at 4-6; NYISO 2017 Comments at 23; PG&E 2017 Comments at 5; Salt River 

2017 Comments at 12; Tri-State 2017 Comments at 6-7.

405 Duke 2017 Comments at 11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 140 -

model development.406 EEI also argues that transmission providers should only have to 

post updates if there are material changes in the generally applied assumptions.407

233. NorthWestern expresses concern that the proposal would be unnecessary and 

cumbersome given base case changes and asserts that a complete list of models would not 

benefit an interconnection customer.408 Further, NorthWestern states that requiring a 

non-disclosure agreement from each potential interconnection customer prior to the 

feasibility study would administratively burden transmission providers. It also argues 

that, in the West, interconnection customers seeking additional information about study 

benefits and assumptions currently have the ability to request model details from the 

Western Electricity Coordinating Council.409

234. NYISO opposes the provision of shift factors, which, it argues, only pertain to 

power flow and thermal analyses, which are more applicable to interconnections in 

RTOs/ISOs that offer physical transmission rights.410 Tri-State argues that large-scale 

system planning is dynamic and often requires changes to in-service dates, identification 

 406 EEI 2017 Comments at 40.

407 Id. at 43.

408 NorthWestern 2017 Comments at 5.

409 Id. at 6.

410 NYISO 2017 Comments at 23.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 141 -

of new delivery points, project cancellations, generation assumptions, and assumed 

demand levels.411

235. Xcel notes that, because each interconnection request is unique, the specific 

network model assumptions used are also usually distinctive. Xcel argues that the 

Commission should grant transmission providers flexibility to provide the detailed, 

unique specifics of the network models in individual study agreements.412 Xcel also 

proposes that interconnection customers review the general process, as described in the 

LGIP or a business practice manual, as well as published study agreements to gain 

insights into expectations for modeling. Xcel states that the customer can discuss the 

specific modeling process and assumptions for its request with the transmission provider, 

and the agreement to be modeled would be memorialized in the agreements posted on 

OASIS. Xcel asserts that this process would provide significant transparency while 

allowing the use of the most appropriate studies and up-to-date assumptions for 

interconnection requests.413

ii. Commission Determination

236. We adopt the NOPR proposal, with modifications. Specifically, this Final Rule 

revises section 2.3 of the pro forma LGIP to read as follows (the bracketed text reflects 

 411 Tri-State 2017 Comments at 6.

412 Xcel 2017 Comments at 13.

413 Id. at 14.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 142 -

deletions from, and the italicized text reflects additions to, the language proposed in the 

NOPR):

Base Case Data. Transmission Provider shall maintain [provide] base 

power flow, short circuit and stability databases, including all underlying 

assumptions, and contingency list on either its OASIS site or a passwordprotected website, [upon request] subject to confidentiality provisions in 

LGIP Section 13.1. [Additionally]In addition, Transmission Provider shall

[will] maintain network models and underlying assumptions on either its 

OASIS site or a password-protected website [for access by OASIS users]. 

Such network models and underlying assumptions should reasonably 

represent those used during the most recent interconnection study and be 

representative of current system conditions. If Transmission Provider posts 

this information on a password-protected website, a link to the information 

must be provided on Transmission Provider’s OASIS site. Transmission 

Provider is permitted to require that Interconnection Customers [and], 

OASIS site users, and password-protected website users sign a 

confidentiality agreement before the release of commercially sensitive 

information or Critical Energy Infrastructure Information in the Base Case 

data. Such databases and lists, hereinafter referred to as Base Cases, shall 

include all (1) generation projects and (2[ii])[414] transmission projects, 

including merchant transmission projects that are proposed for the 

Transmission System for which a transmission expansion plan has been 

submitted and approved by the applicable authority.

237. Most responsive commenters note that the proposal could significantly increase 

transparency in the study process. We disagree with commenters that argue that current 

posting procedures are sufficient. The record before us demonstrates that transmission 

providers do not consistently make their network models and assumptions available, and 

access to information regarding the assumptions used is often inconsistent across 

 414 In this Final Rule, we correct a typographical error in the pro forma LGIP.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 143 -

regions.415 We believe the revisions to section 2.3 of the pro forma LGIP will reduce the 

possibility that some interconnection customers will have unduly discriminatory access to 

relevant information and will generally increase transparency for interconnection 

customers by requiring that network models and assumptions used by transmission 

providers be made available, subject to the appropriate confidentiality and information 

requirements. We expect that these revisions will allow interconnection customers to 

make more informed interconnection decisions while also holding transmission providers 

accountable as to which network models and assumptions they use to assess 

interconnection requests. 

238. However, we find persuasive concerns voiced by several commenters regarding 

the proposal’s requirement to post the network model and assumption information on 

OASIS. Specifically, we recognize that a requirement to move information onto OASIS 

could burden transmission providers that currently make this information available to 

interconnection customers elsewhere. Therefore, we believe a transmission provider 

should be able to decide to maintain the required information on its website as long as it 

has a link to the location of the information on OASIS, as OASIS is the central location 

for all the information needed to request interconnection service. Accordingly, the 

revisions to section 2.3 of the pro forma LGIP require transmission providers to post 

network models and assumptions, subject to the appropriate confidentiality and 

 415 NOPR, FERC Stats. & Regs. ¶ 32,719 at PP 111-112; see also NextEra 2017 

Comments at 22; Alliant 2017 Comments at 11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 144 -

information requirements, on OASIS and/or on a password-protected website. These 

revisions strike an appropriate balance by increasing transparency while also limiting the 

burden on transmission providers. 

239. In response to those arguments alleging that maintaining network models and 

underlying assumptions on OASIS or a password-protected website may be 

administratively burdensome, we find the benefits of increased transparency resulting 

from the revisions to section 2.3 of the pro forma LGIP will outweigh the burden placed 

on transmission providers to post and maintain up-to-date network models and 

underlying assumptions. Instead, we note that increasing transparency of network 

models and assumptions will allow interconnection customers to make informed 

interconnection decisions, which could potentially help interconnection customers avoid 

entering the queue with non-viable interconnection requests. Informed interconnection 

decisions will also allow transmission providers to improve queue management. 

Improved queue management, in turn, should aid in decreasing the administrative burden 

on transmission providers. In addition, increased transparency will also mitigate the 

potential for study disputes, re-studies and late-stage withdrawals, thus increasing the 

efficiency of the interconnection process. 

240. In response to confidentiality and data security concerns associated with providing 

certain information and system access, we reaffirm that there are safeguards that can be 

put in place to satisfactorily address these concerns. With the revisions in this Final Rule, 

section 2.3 of the pro forma LGIP allows the transmission provider to require that the 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 145 -

interconnection customer sign a confidentiality agreement before the release of 

commercially sensitive information. We agree with commenters that transmission 

providers should only provide commercially-sensitive information, such as contingency 

files and specific dispatch information, under a non-disclosure agreement. We note that 

the information that this Final Rule requires transmission providers to post will be 

available on a password-protected website or on the transmission provider’s OASIS site. 

241. With regard to CEII, we note that the Commission’s CEII regulations in 18 CFR 

section 388.113 only govern “the procedures for submitting, designating, handling, 

sharing, and disseminating [CEII] submitted to or generated by the Commission.”416 

However, to the extent that certain information that is currently designated by the 

Commission as CEII is implicated by this portion of the Final Rule, this Final Rule makes 

no changes to that information’s CEII designation or to the Commission’s existing CEII

requirements. Additionally, even if the information has been designated as CEII, section 

388.113 of the Commission’s regulations does not govern the transmission provider’s 

handling, sharing, and disseminating of information that the transmission provider 

submitted for CEII designation, including how it disseminates that information on its 

OASIS site or password-protected website. We note, however, that nothing in section 

388.113 of the Commission’s regulations precludes a transmission provider from taking 

necessary steps to protect information within its custody or control to ensure the safety 

 416 18 CFR 388.113 (2017) (emphasis added).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 146 -

and security of the electric grid. Specifically, we note that pro forma LGIP section 2.3

permits transmission providers to require a confidentiality agreement for anyone that 

wishes to access “commercially sensitive information or [information that has been 

designated as CEII]” that may be posted in the base case data on the transmission 

provider’s OASIS site or password-protected website. 

242. Upon consideration of the comments, we withdraw the NOPR proposal to require 

transmission providers to post information “including, but not limited to, shift factors, 

dispatch assumptions, load power factors, and power flows.”417 Such a requirement 

could result in transmission providers posting certain information that is not informative 

to interconnection customers and which could delay or otherwise burden the 

interconnection study process. For example, NYISO states that shift factors generally 

only pertain to power flow and thermal analyses, which are more applicable to 

interconnections in RTOs/ISOs that offer physical transmission rights.418

 417 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 119.

418 NYISO 2017 Comments at 23.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 147 -

c. Suggested Modifications to Transparency Regarding 

Study Models and Assumptions Proposal

i. Comments

243. Multiple commenters support the proposal but offer suggestions to increase 

transparency.419 For example, AWEA suggests that transmission providers should have 

to review interconnection study models and assumptions every two years and submit a 

filing pursuant to section 205 of the FPA justifying the model and assumptions to ensure 

that study models and assumptions are non-discriminatory, realistic, appropriate for 

generation or regional characteristics, and accountable.420 

244. Generation Developers request that the modeling provision specify the minimum 

model assumptions that must be posted, including: (1) shift factors used by region, subregion, and even utility area; (2) generation dispatch assumptions by fuel-type of resource 

by region and sub-region for off-peak and peak hours; (3) load power factors; (4) power 

flows; (5) whether violations of NERC Category A (TPL-001), Category B (TPL-002), 

and Category C (TPL-003) require network upgrades and contingent facilities in all or 

some instances; (6) treatment of currently overloaded facilities; (7) the extent to which 

 419 AWEA 2017 Comments at 37; Generation Developers 2017 Comments at 28; 

NEPOOL 2017 Comments at 10; NextEra 2017 Comments at 22; TDU Systems 2017 

Comments at 18; Xcel 2017 Comments at 13.

420 AWEA 2017 Comments at 37; see also Generation Developers 2017 

Comments at 31.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 148 -

Network Resource Interconnection Service (NRIS) is hard-coded in the base model; and 

(8) contingency files.421 

245. NextEra notes that, in addition to models, interconnection customers would benefit 

from two best practices: (1) providing information about other interconnection requests 

“in the same location by point on the transmission grid,” instead of county-level data;422 

and (2) providing information about lower voltage facilities (e.g., those below 100 kV) 

and higher voltage facilities.423

ii. Commission Determination

246. While we appreciate the additional suggestions on what types of information 

transmission providers should post, the information requested by the commenters is 

outside of the scope of the proposal as set forth in the NOPR. In response to AWEA’s 

requests, we note that when the Commission acts pursuant to FPA section 206, it “must 

show that [a] utility’s existing rate is unjust and unreasonable and . . . that [the 

Commission’s] replacement rate is just and reasonable.” Thus, the Commission would 

have to meet the requirements of FPA section 206 to make changes to a currently 

effective tariff provision.424 We find that the current record does not support such a 

 421 Generation Developers 2017 Comments at 28.

422 NextEra 2017 Comments at 23.

423 Id.

424 Ark. Elec. Coop. Corp. v. ALLETE, Inc., 156 FERC ¶ 61,061, at P 18 (2016). 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 149 -

finding. With respect to Generation Developers’, NextEra’s, and TDU Systems’ 

suggestions that transmission providers should have to post more information on OASIS, 

we clarify that the Final Rule does not mandate an exhaustive list of minimum model 

assumptions. We find that the record before us does not support mandating that each 

region post the same set of information in the analysis of interconnection requests.

3. Congestion and Curtailment Information 

a. NOPR Proposal 

247. In response to developer requests for increased transparency of congestion and 

curtailment information, the Commission proposed to require that transmission providers 

post congestion and curtailment information in one location on their OASIS sites so that 

interconnection customers can more easily access information that may aid in their

decision-making.425 The Commission proposed to require that transmission providers 

post specific congestion and curtailment information that is disaggregated, or more 

granular (e.g., hourly and locational data) than the information that some transmission 

providers currently provide.426 To effectuate this requirement, the Commission proposed 

to add a new section (l) to 18 CFR 37.6 that reads:

(l) Posting of congestion and curtailment data. The Transmission Provider 

must post on OASIS information as to congestion data representing (i) total 

hours of curtailment on all interfaces, (ii) total hours of Transmission 

Provider-ordered generation curtailment and transmission service 

 425 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 128.

426 Id. P 130. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 150 -

curtailment due to congestion on that facility or interface, (iii) the cause of 

the congestion (e.g., a contingency or an outage), and (iv) total megawatt 

hours of curtailment due to lack of transmission for that month. This data 

shall be posted on a monthly basis by the 15th day of the following month 

and shall be posted in one location on the OASIS. The Transmission 

Provider should maintain this data for a minimum of three years.

248. The Commission also sought comment on whether transmission providers should 

provide interconnection-request-specific congestion and curtailment information and 

whether transmission providers should be required to provide this information to 

interconnection customers during the interconnection study process (e.g., at the scoping 

meeting).427 

249. The Commission also sought comment on the level of information to be provided, 

the frequency at which the information should be provided, and how many months/years 

the provided information should cover.428 The Commission sought further comment on 

the value of requiring transmission providers to post flow duration curves on the major 

transmission interfaces based on hourly flow data on OASIS.429 Finally, the Commission 

sought comment on changes to section 3.3.4 of the pro forma LGIP requiring 

transmission providers or transmission owners to provide curtailment and congestion 

information at the scoping meeting.430

 427 Id. P 128.

428 Id. P 131.

429 Id.

430 Id. P 133.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 151 -

b. Comments

250. Some responsive commenters support the proposed requirement for congestion 

and curtailment information to be posted in one location on each transmission provider’s 

OASIS site.431 AFPA asserts that the proposal will allow interconnection customers to 

better use existing transmission infrastructure.432 Public Interest Organizations and IECA 

contend that the proposal will help interconnection customers better understand 

investment risks, which could result in more efficient markets and lower costs.433 IECA, 

SEIA, and Joint Renewable Parties indicate that the added transparency will improve 

access to information, increase efficiency, and reduce discrimination.434 

251. Joint Renewable Parties, Alliant, Generation Developers, and ITC state that access 

to the information will improve interconnection customers’ ability to appropriately site 

projects and will reduce queue withdrawals, which occur due to high interconnection 

 431 AFPA 2017 Comments at 11; Public Interest Organizations 2017 Comments at 

5-8; IECA 2017 Comments at 2; SEIA 2017 Comments at 19; Joint Renewable Parties 

2017 Comments at 11; Alevo 2017 Comments at 6; NEPOOL 2017 Comments at 11; 

Alliant 2017 Comments at 12.

432 AFPA 2017 Comments at 11.

433 Public Interest Organizations 2017 Comments at 5-8; IECA 2017 Comments 

at 2.

434 Id.; SEIA 2017 Comments at 19; Joint Renewable Parties 2017 Comments 

at 11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 152 -

facility and network upgrade costs.435 AWEA asserts that it is crucial for interconnection 

customers to have access to historical local congestion information, noting that study 

results do not provide this information and that transmission providers frequently do not 

make it available. AWEA also states that there is a lack of uniformity in the type and 

location of information that transmission providers post.436 AWEA states that nondisclosure agreements can prevent disclosure of commercially sensitive information to 

the general public.437

252. In support of the proposal, NEPOOL and Alevo both argue that transmission 

owners, transmission providers, and system operators should post data that are as 

granular as possible. They argue that readily available transmission capacity data at the 

front end will enable market participants to size their projects appropriately and to 

anticipate network upgrade costs.438 AWEA contends that the burden on transmission 

providers to post this type of information is minimal, as the information is readily 

available and does not require significant additional studies.439 TDU Systems also 

supports the proposal and urges the Commission to clarify that transmission providers 

 435 Id.; Alliant 2017 Comments at 12; Generation Developers 2017 Comments 

at 31-32; ITC 2017 Comments at 17; see also AWEA 2017 Comments at 40.

436 Id. at 39.

437 Id. at 41.

438 Alevo 2017 Comments at 6; NEPOOL 2017 Comments at 11.

439 AWEA 2017 Comments at 42.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 153 -

should report on congestion that is avoided by dispatching generation out of merit 

order.440

253. Several commenters argue that sufficient procedures already exist for 

interconnection customers. TVA, EEI, and Xcel contend that the Commission should 

make existing data collection resources available to potential interconnection customers, 

rather than requiring transmission providers to create redundant new ones.441 TVA 

argues that the information that NERC stores via Transmission Loading Relief (TLR) 

logs provides enough information to allow the interconnection customer to evaluate its 

selected location.442 TVA also contends that the time and expense of analyzing potential 

interconnection locations should be the interconnection customer’s responsibility.443 

Xcel argues that, to the extent stakeholder needs are not met by posting the proposed 

information, RTO/ISO stakeholder processes should address these issues.444 Non-Profit 

Utility Trade Associations ask the Commission to convene a technical conference to 

determine what congestion and constraint information utilities should maintain, the 

 440 TDU Systems 2017 Comments at 19-20.

441 EEI 2017 Comments at 45; TVA 2017 Comments at 10-11; Xcel 2017 

Comments at 15-16.

442 TVA 2017 Comments at 10.

443 Id. at 10-11.

444 Xcel 2017 Comments at 15-16.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 154 -

format of that information, and what information would benefit interconnection 

customers.445

254. CAISO and PG&E note that the requested information is largely already available

on CAISO’s website.446 CAISO explains that transmission providers publish dispatch 

reports, congestion data, and locational marginal price (LMP) data so that potential 

interconnection customers can understand where there is available capacity.447 CAISO 

also states that it already provides interconnection customers with as much information as 

can be predicted, bearing in mind that economic curtailment protects the grid from events 

that are difficult or impossible to predict, such as outages, overloads due to oversupply, 

and contingency events. 448

255. MISO argues that the sort of granular information the Commission has proposed 

to be posted will not significantly resolve issues with queue processing.449 MISO TOs 

state that MISO posts market reports that contain LMP data and the marginal congestion 

component for every commercial pricing node, which can be used to develop information 

 445 Non-Profit Utility Trade Associations 2017 Comments at 17.

446 CAISO 2017 Comments at 20; PG&E 2017 Comments at 6 (citing 

http://www.caiso.com/market/Pages/OutageManagement/CurtailedOperationalGeneratorReport Glossary.aspx). 

447 CAISO 2017 Comments at 19.

448 Id.

449 MISO 2017 Comments at 28.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 155 -

on congestion. MISO TOs state that it would be redundant (and burdensome) to require 

MISO to publish this information on OASIS as well as on its web site, where it currently 

resides.450 

256. NextEra notes that operational snapshots of the transmission provider’s system are 

more useful than statistics of total hours or MW of curtailment.451 NextEra notes that 

MISO and SPP already provide state estimator snapshots from the prior two weeks, 

which include generator dispatch, system congestion, and power flow information, 

among other things. NextEra recommends that all RTOs/ISOs adopt this practice and 

provide snapshots of their systems from different times of the day to show system 

conditions.452 

257. PJM agrees with the proposal to require transmission providers to post congestion 

data representing total hours of curtailment on all interfaces and asserts that it currently 

posts these data publicly on its website.453 PJM states that, along with LMP pricing 

information, these data are adequate to allow an interconnection customer to make 

informed business decisions relative to their interconnection project.454 

 450 MISO TOs 2017 Comments at 30.

451 NextEra 2017 Comments at 25.

452 Id.

453 PJM 2017 Comments at 16.

454 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 156 -

258. However, PJM states that it opposes the NOPR’s proposal to require transmission 

providers to post total hours of transmission provider-ordered generation curtailment and 

transmission service curtailment due to congestion on a facility or interface, the cause of 

the congestion, and total megawatt hours (MWh) of curtailment due to lack of 

transmission for that month.455 PJM states that posting information regarding unitspecific and constraint-specific generator curtailment information would allow other 

market participants to replicate market-sensitive data, such as unit offers, and would 

require significant effort.456 PJM contends that publicly posting the cause of congestion 

would improperly disclose commercially sensitive information and require difficult and 

time-consuming power flow analysis and market re-runs. PJM notes that it does not have 

the software capability to determine causes of congestion.457 PJM states that posting the 

total monthly MWh of curtailment due to lack of transmission could result in misleading 

information, as curtailment may be caused by multiple factors.458 

259. EEI, Six Cities, MISO TOs, CAISO, and Xcel assert that historical congestion and 

curtailment information may have no bearing on future congestion or curtailment at any 

specific location, and the posting of this information should not be considered a 

 455 Id.

456 Id.

457 Id. at 17.

458 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 157 -

commitment by the transmission provider to guarantee the availability of additional 

capacity or expose the transmission provider to damages or other remedies should 

interconnection customers’ expectations regarding curtailment risk not materialize.459 

Duke states that historic congestion and curtailment information might only be useful if 

the generating facility’s location and the area of congestion coincided.460 Duke and 

MISO TOs further state that system changes including interconnection and transmission 

upgrades, large generators going on- or off-line, or a transmission system topology 

change could render historical congestion information meaningless.461 Xcel states that 

future generation impacts future congestion, and that knowledge of where other 

generation will locate is likely of more value to the interconnecting generators.462

260. Xcel notes that the impact of congestion and curtailment varies by region, mostly 

due to the existence of regional markets, different scheduling practices, and the treatment 

of firm transmission service.463 ISO-NE argues that regional flexibility is warranted to 

allow RTOs/ISOs to identify the relevant congestion and curtailment information in their 

region and the information that is already available to interconnection customers that 

 459 EEI 2017 Comments at 45; Six Cities 2017 Comments at 3-4; MISO TOs 2017 

Comments at 29; CAISO 2017 Comments at 19; Xcel 2017 Comments at 14-15.

460 Duke 2017 Comments at 12.

461 Id. at 13; MISO TOs 2017 Comments at 29.

462 Xcel 2017 Comments at 14-15.

463 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 158 -

meets the NOPR’s objective.464 ISO-NE states that the congestion and curtailment 

information identified in the NOPR is not relevant in New England because this 

information relates to availability of pro forma transmission service and internal flow 

gates, neither of which is applicable in New England.465 

261. NYISO states that it has historically published significant system information on 

its public website, including congestion and curtailment information.466 NYISO argues 

that additional operational data posted to NYISO’s public website would not provide the 

information the NOPR anticipates would be useful to interconnection customers.467

NYISO further states that the curtailment data requested by AWEA and proposed in the 

NOPR would not be useful data to NYISO interconnection customers and explains that it 

may not even have the capability to provide certain data proposed by the NOPR.468 

 464 ISO-NE 2017 Comments at 27-28.

465 Id. n.65.

466 NYISO 2017 Comments at 24. 

467 Id. at 28.

468 Id. at 26 (citing, e.g., N.Y. Indep. Sys. Operator, Inc., 123 FERC ¶ 61,134, at 

PP 8-13 (2008); N.Y. Indep. Sys. Operator, Inc., Docket No. OA08-13-003 (Nov. 12, 

2008) (delegated letter order)). 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 159 -

NYISO contends that it need not maintain and post the same OASIS-related information 

as RTOs/ISOs with a physical reservation transmission system.469 

262. MISO asserts that queue congestion is a sub-region-wide issue and not an issue of 

locating around more granular points of congestion, which the proposed requirements 

would illuminate. MISO contends that for optimally locating around localized points of 

congestion, the initial scoping meetings are sufficient to advise customers regarding less 

congested points of interconnection within an interconnection customer’s general 

preferred area.470

263. PG&E questions whether this information should be posted on OASIS, instead of 

on CAISO’s website, since an interconnection customer will not necessarily have access 

to OASIS until it becomes a transmission customer.471 PG&E expresses concern about 

making much of this information public, including but not limited to CEII, since CAISO 

has a process that provides much of this information to interconnection customers that

have executed non-disclosure agreements.472 MISO TOs state that RTOs/ISOs should 

develop a method to ensure privileged and/or confidential information is shared only with 

 469 Id. (citing, e.g., N.Y. Indep. Sys. Operator, Inc., Docket Nos. ER11-2048-003 & 

ER11-2048-004 (June 6, 2011) (delegated letter order); N.Y. Indep. Sys. Operator, Inc., 

133 FERC ¶ 61,208, at PP 12-13 (2010)). 

470 MISO 2017 Comments at 28.

471 PG&E 2017 Comments at 6.

472 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 160 -

interconnection customers and is not available to market participants or others without

authorization to receive CEII information, in order to prevent market manipulation and 

potential harm.473

264. Duke, NorthWestern, Southern, Xcel, and Non-Profit Utility Trade Associations 

argue that the proposal should not extend to transmission providers that operate outside 

of RTOs/ISOs because the information is neither available nor relevant.474 Duke states 

that the transmission system outside RTOs/ISOs is planned, designed, and operated so 

that generating resources with firm bilateral contracts to serve load are not constrained.475 

Xcel notes that, in non-market areas, firm transmission service mitigates congestion and 

curtailment risk. Xcel and Southern contend that congestion and curtailment information

is more relevant for RTOs/ISOs that have locational marginal pricing, and because 

regional markets usually dispatch generation according to price, curtailment is generally 

based on price and not a lack of transmission capacity.476 Southern points out that it 

 473 MISO TOs 2017 Comments at 30.

474 Duke 2017 Comments at 13; NorthWestern 2017 Comments at 6; Southern 

2017 Comments at 21-22; Xcel 2017 Comments at 15; Non-Profit Utility Trade 

Associations 2017 Comments at 15-16. 

475 Duke 2017 Comments at 13.

476 Xcel 2017 Comments at 15; Southern 2017 Comments at 21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 161 -

provides congestion/curtailment screens specific to each interconnection request in each 

interconnection study report.477

265. NorthWestern and Non-Profit Utility Trade Associations state that the definition 

of “congestion” is unclear in non-RTOs/ISOs.478 NorthWestern argues that posting 

congestion could be duplicative because, in contract-path balancing authority areas that 

operate outside of organized markets, “congestion” is synonymous with “available 

transfer capability,” which is already posted on OASIS in real time.479

266. Duke, EEI, and OATI assert that the Commission should consult with NAESB 

regarding standards for making congestion and curtailment information accessible on 

OASIS.480 OATI states that it is critical that access to all of these postings require secure 

and controlled access through a registered OASIS user account per existing OASIS 

standards.481 Duke states that NAESB is already working on this issue, as evidenced by 

its 2017 Wholesale Electric Quadrant Annual Plan item 2.a.ii.1, and should consider 

designing queries for interconnection customers to use to obtain congestion and 

 477 Id. at 21-22.

478 NorthWestern 2017 Comments at 6; Non-Profit Utility Trade Associations 

2017 Comments at 15 -16.

479 NorthWestern 2017 Comments at 6.

480 Duke 2017 Comments at 13; EEI 2017 Comments at 47-48; OATI 2017 

Comments at 2. 

481 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 162 -

curtailment information specific to their interconnection requests.482 TVA suggests that 

adding these data to data that NERC already tracks appears a more appropriate regulatory 

implementation path.483

267. NYISO suggests that instead of the proposed OASIS postings, the Commission 

should consider adding the option of a pre-application report for large facilities, similar to 

that required to be offered for small facilities under Order No. 792 and the pro forma

SGIP.484 NYISO urges the Commission to consider such an approach as an alternative to 

requiring cumbersome posting requirements that are not applicable in all regions and that

can only provide historical data – data that are of little use to an interconnection customer

and indeed may be misleading compared to data that could be provided through an 

interconnection study or in response to a pre-application report request.485

c. Commission Determination

268. In this Final Rule, we decline to adopt the proposal in the NOPR to require 

transmission providers to post certain specified congestion and curtailment information, 

as described further below. 

 482 Duke 2017 Comments at 13.

483 TVA 2017 Comments at 10-11.

484 NYISO 2017 Comments at 29.

485 Id. at 29-30.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 163 -

269. We agree with commenters that access to congestion and curtailment data could 

better inform the decision-making of interconnection customers and allow them to more 

appropriately size and site projects, resulting in more efficient use of the transmission 

system and fewer late stage queue withdrawals. Accordingly, we encourage all 

transmission providers that already make such information available to continue to do so.

270. However, upon consideration of the comments in this proceeding, we decline to 

require transmission providers to post the specific information that the Commission 

originally proposed in the NOPR. We find persuasive those comments that assert that, in 

some instances, generating information on the causes of congestion or on unit-specific or 

constraint-specific curtailment information is technically infeasible or would require 

significant additional effort.486 

271. In addition, as several commenters argue, many transmission providers already 

publish congestion and curtailment data such as LMP data and dispatch reports on their 

public websites.487 Further, the NERC Transmission Loading Relief (TLR) Logs make 

publicly available information on the duration, direction, and MW total of curtailments in

the Eastern Interconnection.488 We also note that some commenters question the 

usefulness of some of the data contemplated by the NOPR proposal to prospective 

 486 PJM 2017 Comments at 16-17; NYISO 2017 Comments at 29-30. 

487 See e.g., CAISO 2017 Comments at 20; NYISO 2017 Comments at 24; PJM 

2017 Comments at 16.

488 NERC TLR Logs, http://nerc.com/pa/rrm/TLR/Pages/TLR-Logs.aspx.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 164 -

interconnection customers and that others argue that some of this data is not available 

outside of RTOs/ISOs.

272. Accordingly, we decline to adopt the proposed revisions to add a new section (l) to 

18 CFR section 37.6 that would require transmission providers to post specific 

congestion and curtailment information in one location on OASIS. 

4. Definition of Generating Facility in the Pro Forma LGIP and 

Pro Forma LGIA

a. NOPR Proposal

273. The Commission proposed to revise the definition of “Generating Facility” in the 

pro forma LGIP and the pro forma LGIA to include electric storage resources, similar to 

how it revised the definition of a “Small Generating Facility” in the pro forma SGIP and 

the pro forma SGIA in Order No. 792.489 Specifically, the Commission proposed to 

amend the definition of a Generating Facility in the pro forma LGIP and the pro forma 

LGIA as follows (with proposed additions in italics): “Generating Facility shall mean 

Interconnection Customer’s device for the production and/or storage for later injection

of electricity identified in the Interconnection Request, but shall not include the 

interconnection customer’s Interconnection Facilities.”490

 489 NOPR, FERC Stats. & Regs. ¶ 32,719 at PP 134, 136 (citing Order No. 792, 

145 FERC ¶ 61,159 at P 228 (emphasis in original)).

490 Id. PP 138-139.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 165 -

b. General

i. Comments

274. A majority of responsive commenters, including utilities, RTOs/ISOs, and 

renewable interests, support the proposal.491 MISO and NYISO state that they already 

account for electric storage resources in their definitions.492 CAISO states that it has 

clarified that electric storage resources can participate as generators to “provide supply” 

and ancillary services. CAISO further states that it studies the reliability impacts of an 

electric storage resource’s charging, but not as firm load.493 To the extent that an electric 

storage resource requires firm load treatment, CAISO states that it can apply to the local 

distribution company.494

 491 AFPA 2017 Comments at 12; AWEA 2017 Comments at 55; Bonneville 2017 

Comments at 5; CAISO 2017 Comments at 20; California Energy Storage Alliance 2017 

Comments at 4; Duke 2017 Comments at 15; EDP 2017 Comments at 6; ESA 2017 

Comments at 6; IECA 2017 Comments at 3; ISO-NE 2017 Comments at 32-33; Joint 

Renewable Parties 2017 Comments at 10-11; MISO 2017 Comments at 29; MISO TOs 

2017 Comments at 32; Modesto 2017 Comments at 22; NEPOOL 2017 Comments at 12-

13; NextEra 2017 Comments at 26; Non-Profit Utility Trade Associations 2017 

Comments at 17; PG&E 2017 Comments at 6; PJM 2017 Comments at 19-20; Public 

Interest Organizations 2017 Comments at 7-8; TDU Systems 2017 Comments at 20; 

TVA 2017 Comments at 11. 

492 MISO 2017 Comments at 29; NYISO 2017 Comments at 30.

493 CAISO 2017 Comments at 20.

494 CAISO 2017 Comments at 20. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 166 -

ii. Commission Determination

275. In this Final Rule, we adopt the NOPR proposal to modify the definition of 

“Generating Facility” in the pro forma LGIP and pro forma LGIA to include “and/or 

storage for later injection.” We find that this definitional change will reduce a potential 

barrier to large electric storage resources with a generating facility capacity above 20 

MW that wish to interconnect pursuant to the terms in the pro forma LGIP and pro forma

LGIA. Additionally, this finding and definitional change are consistent with provisions 

already implemented in the pro forma SGIP and the pro forma SGIA.495

c. Electric Storage Resources as Transmission Assets

i. Comments

276. ESA and California Energy Storage Alliance, both of which support the proposal, 

raise concerns that the proposal may inadvertently prohibit the deployment of electric 

storage resources as transmission assets.496 ESA recommends that the Commission state 

that neither a SGIA nor an LGIA is necessary for electric storage resources to be 

employed as transmission assets and that electric storage resources providing 

transmission services should not be excluded from seeking an LGIA or SGIA to provide 

 495 Pro forma SGIP at Attachment 1 (Glossary of Terms); Pro forma SGIA at 

Attachment 1 (Glossary of Terms).

496 ESA 2017 Comments at 6; California Energy Storage Alliance 2017 Comments 

at 4.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 167 -

wholesale generator services.497 Public Interest Organization generally supports the 

proposal but opposes requiring all electric storage resources, including those intended to 

serve as transmission assets, to go through the formal large generator interconnection 

process.498

277. AES and Alevo both oppose the change of definition, arguing that electric storage 

resources can also act as transmission assets instead of, or in addition to, participating in 

the markets and that the proposal may prohibit the deployment of electric storage 

resources as transmission assets.499

ii. Commission Determination

278. We find that there is no need to further revise the definition of Generating Facility 

to address these concerns because the definition, as revised here, would not affect 

whether electric storage resources operate as transmission assets. The Commission 

previously has found that, in certain situations, electric storage resources can function as 

a generating facility, a transmission asset,500 or both.501

 497 ESA 2017 Comments at 7 (citing Utilization of Electric Storage Resources for 

Multiple Services When Receiving Cost-Based Rate Recovery, 158 FERC ¶ 61,051

(2017)).

498 Public Interest Organizations 2017 Comments at 7-8.

499 AES 2017 Comments at 9-11; Alevo 2017 Comments at 2-4.

500 See, e.g., Western Grid Dev., LLC, 130 FERC ¶ 61,056 (Western Grid), reh’g 

denied, 133 FERC ¶ 61,029 (2010). 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 168 -

279. The purpose of this definition change is to make clear that electric storage 

resources with a capacity of more than 20 MW may interconnect pursuant to the pro 

forma LGIP and pro forma LGIA. These Final Rule revisions are meant to clarify that 

new technologies may avail themselves of the existing pro forma interconnection 

process, so long as they meet the threshold requirements as stated in those documents. 

d. Characteristics of Electric Storage Resources

i. Comments

280. ESA asserts that the proposal does not address the differences between electric 

storage resources and traditional generators.502 ESA recommends that the Commission 

require RTOs/ISOs to develop Electric Storage Interconnection Agreements and 

Processes that account for the unique characteristics of electric storage resources.503 In 

addition, ESA recommends that the Commission revise tariffs and modify the pro forma 

LGIP and the pro forma LGIA into a pro forma Large Facility Interconnection 

Agreement and Process, in which facilities are defined to consist of only a generating 

 

501 See Utilization of Electric Storage Resources for Multiple Services When 

Receiving Cost-Based Rate Recovery, 158 FERC ¶ 61,051.

502 ESA 2017 Comments at 6.

503 Id. at 7 (citing, e.g., ISO New England, Inc., 151 FERC ¶ 61,024 (2015)).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 169 -

unit, only an electric storage unit, or a combination of generating units and electric 

storage units.504

281. Alevo and AES state that the proposal does not account for the full capability of 

electric storage resources.505 Alevo states that a new definition should be made 

separately for electric storage resources, while AES suggests that the development of a 

new interconnection agreement specific to electric storage resources.506

282. EEI and Portland request that the Commission hold a technical conference on this 

proposal.507 EEI states that it is unclear how existing interconnection agreements and 

processes would account for the generation and load characteristics of electric storage 

resources.508 Portland states that further discussions are necessary to address the unique 

characteristics of electric storage resources and that a new definition for storage facilities 

may be appropriate.509

 504 Id. at 8.

505 AES 2017 Comments at 9-11; Alevo 2017 Comments at 2-4.

506 AES 2017 Comments at 10-11; Alevo 2017 Comments at 2-4.

507 EEI 2017 Comments at 48; Portland 2017 Comments at 3-4.

508 EEI 2017 Comments at 48.

509 Portland 2017 Comments at 4.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 170 -

283. Southern argues that redefining Generating Facility to include electric storage 

resources would complicate the pro forma LGIP and pro forma LGIA.510 Southern states 

that electric storage resources could be considered generation or load, and this could

cause problems when discussing reactive power in article 9.6 of the pro forma LGIA, 

which references the generating facility capacity rather than the load.511

284. NYISO, while stating that it does not take a position, suggests that any revisions 

should also reflect that the facility may store energy for withdrawal, as energy storage 

facilities typically both inject and withdraw energy to the grid.512 Indicated NYTOs, who

support the proposal, agree with NYISO on the addition of the term “withdrawal” to the 

definition.513 MidAmerican states that the Commission should clarify that the proposal 

does not permit transmission providers to impose restrictions on withdrawals by storage 

resources in excess of restrictions imposed on any other load.514

ii. Commission Determination

285. We disagree with EEI’s and Southern’s arguments that the pro forma LGIP and 

pro forma LGIA may be unable to accommodate the load characteristics of an electric 

 510 Southern 2017 Comments at 22.

511 Id.

512 NYISO 2017 Comments at 30.

513 Indicated NYTOs 2017 Comments at 14.

514 MidAmerican 2017 Comments at 21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 171 -

storage resource. We note that studies under the pro forma LGIP already provide 

transmission providers with the flexibility to address the load characteristics of electric 

storage resources, and that electric storage resources have already successfully 

interconnected pursuant to a Commission-jurisdictional LGIP and LGIA.515 EEI and 

Southern provide no evidence that the requirements of the LGIP and LGIA cannot 

accommodate the load characteristics of electric storage resources. We note that, if a 

transmission provider finds a particular resource to be outside the scope of its existing 

LGIA, the LGIP permits a transmission provider to enter into non-conforming LGIAs 

when necessary.

286. We find that ESA’s suggestion that we remove the term “generator” from the pro 

forma LGIA and the pro forma LGIP in favor of interconnection agreements based on a 

facility’s technical and operational characteristics is beyond the scope of this proposal. 

We find that AES’s and Alevo’s assertions are beyond the scope of this rulemaking 

because, as previously noted, the Final Rule revisions are meant to clarify that new 

technologies with a capacity of more than 20 MW may avail themselves of the existing 

pro forma generator interconnection process and interconnection agreement rather than 

defining an electric storage resource. In response to NYISO’s suggestion to add 

“withdrawal” to the definition, we do not believe it is necessary to accept this suggestion. 

 515 See, e.g., AES New Creek, Docket No. ER12-1100-000 (Apr. 10, 2012) 

(delegated letter order) (accepting a non-conforming interconnection agreement between 

PJM, Virginia Electric Power, and a combined solar and electric storage resource).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 172 -

While the meaning of NYISO’s comment is unclear, to the extent that it refers to an 

electric storage resource’s ability to charge, our adopted definition already accounts for 

this ability through the inclusion of the word “storage.” Anything beyond this 

interpretation is beyond the scope of this proceeding. 

e. Other

i. Comments

287. EEI seeks clarification on whether the proposed change will affect tax treatment of 

generators.516 In addition, EEI states that the Commission should clarify the applicability 

of wholesale distribution charges to electric storage resources using distribution facilities 

and that the inclusion of electric storage resources in the definition does not affect the 

jurisdiction of interconnection studies.517

ii. Commission Determination

288. In response to EEI’s concern that the proposed change to the pro forma LGIP and 

pro forma LGIA definition of generating facility might affect tax treatment of generators, 

we note that the purpose of this proposal is only to allow electric storage resource’s with 

a capacity above 20 MW to interconnect pursuant to the pro forma LGIP and pro forma 

LGIA. It should not affect tax treatment of electric storage resources. 

 516 EEI 2017 Comments at 49.

517 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 173 -

289. We find that this definitional change will not affect the jurisdictional issues EEI 

raises. The pro forma LGIP is the process provided for Commission-jurisdictional 

interconnections by resources above 20 MW, and this definition change ensures that 

electric storage resources above 20 MW that seek a Commission-jurisdictional 

interconnection can access that interconnection process. All relevant jurisdictional 

delineations and precedent remain unchanged. This definition change also does not 

affect the Commission’s precedent on wholesale distribution charges when distributed 

resources use the distribution system to reach the wholesale market. 

5. Interconnection Study Deadlines

a. NOPR Proposal

290. The pro forma LGIP requires that transmission providers use “reasonable 

efforts”518 to complete feasibility studies in 45 days, system impact studies in 90 days, 

and facilities studies within 90 or 180 days.519 The Commission proposed to require that 

transmission providers post on their OASIS on a quarterly basis summary statistics 

indicating the number of interconnection requests withdrawn and interconnection studies 

completed and delayed, the proportion of studies completed within tariff timeframes, and 

 518 The pro forma LGIP states that reasonable efforts “shall mean, with respect to 

an action required to be attempted or taken by a Party under the Standard Large 

Generator Interconnection Agreement, efforts that are timely and consistent with Good 

Utility Practice and are otherwise substantially equivalent to those a Party would use to 

protect its own interests.” Pro forma LGIP Section 1 (Definitions).

519 Pro forma LGIP Sections 6.3, 7.4, and 8.3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 174 -

the average time to complete a study. Additionally, the Commission proposed to require 

that a transmission provider that exceeds study deadlines for more than 25 percent of any 

study type for two consecutive quarters must file informational reports at the Commission 

for the four calendar quarters (Filed Report Requirement). If during this period, the 

transmission provider exceeds more than 25 percent of study deadlines for any study type 

for two consecutive quarters, the reporting requirement would be retriggered for another 

four consecutive quarters from the date of the last consecutive quarter to exceed the 25 

percent threshold.520

291. To implement this proposal, the Commission proposed to modify section 3.4 of 

the pro forma LGIP521 to institute quarterly reporting requirements for transmission 

providers to report interconnection study performance on their OASIS. The Commission 

also proposed reporting requirements and justifications that would be triggered if a 

 520 In this Final Rule, we are modifying the calculation for determining whether a 

transmission provider has triggered the Filed Report Requirement so that it reads more 

simply. For example, for the calculation in 35.2.2(E), the new calculation will be the sum 

of 35.2.2(B) plus 35.2.2(C) divided by the sum of 35.2.2(A) plus 35.2.2(C). For ease of 

readership, we abbreviate here as (B + C)/(A + C). This calculation would represent the 

quarterly total of late studies, i.e., completed late studies plus uncompleted late studies, 

divided by the number of studies that should have been completed, i.e., completed studies 

plus uncompleted late studies. Although this is a simpler calculation, we note that it is 

mathematically equivalent to the calculation proposed in the NOPR, which we abbreviate

here as 1 – (A – B)/(A + C).

521 In the “Utilization of Surplus Interconnection Service” section, the Commission 

proposed revisions to the pro forma LGIP that result in renumbering of several existing 

sections. One section that the Commission proposed to be renumbered is section 3.4. 

For this reason, the proposed revisions to the “OASIS Posting” section (current section 

3.4) will begin at section 3.5.1.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 175 -

transmission provider exceeds study deadlines for more than 25 percent of any study type 

for two consecutive calendar quarters.

292. The Commission also sought comment on whether: (1) to require different 

interconnection processing statistics to be posted on OASIS by the transmission provider;

(2) the Commission has proposed the appropriate summary data requirements to enhance 

transparency and what customizations of these requirements should be made to adjust for 

different regional processes; (3) interconnection customers have sufficient information 

regarding the cause of study delays; (4) transmission providers should have to provide a 

more detailed explanation to interconnection customers regarding the cause(s) of study 

delays; (5) a transmission provider should have to inform interconnection customers 

regarding its process for revising study timelines once a delay occurs; and (6) the 

transmission provider should also describe in sufficient detail any relevant issues that 

could further affect the revised timeline for a particular interconnection customer.

b. Interconnection Study Metrics Reporting

i. Comments

293. Numerous commenters support a requirement for transmission providers to report 

on their interconnection study performance.522 AWEA states that many transmission 

 522 Alevo 2017 Comments at 7-8; Alliance for Clean Energy 2017 Comments at 1; 

AWEA 2017 Comments at 43; Competitive Suppliers 2017 Comments at 9; EDP 2017 

Comments at 7; Joint Renewable Parties 2017 Comments at 11; NEPOOL 2017 

Comments at 13; NextEra 2017 Comments at 27; PJM 2017 Comments at 20-21; 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 176 -

providers consistently experience interconnection study delays due to factors completely 

within their control.523 NEPOOL states that reporting requirements will provide greater 

transmission provider accountability, thereby tending to improve transmission provider 

performance and facilitating market entry.524 NextEra notes that, while it would prefer to 

eliminate the reasonable efforts standard, the NOPR proposal will improve transparency 

into study delay causes and frequency, and this transparency could lead to appropriate 

solutions.525

294. Some commenters support requiring transmission providers to provide additional 

or even more detailed statistics than the Commission proposed526 or argue that the 

Commission should lower the hurdle for triggering the Filed Report Requirement (e.g., 

lowering the 25 percent hurdle to 10 percent).527

 

Portland 2017 Comments at 5-6; SEIA 2017 Comments at 19; TDU Systems 2017 

Comments at 21-22. 

523 AWEA 2017 Comments at 43-44.

524 NEPOOL 2017 Comments at 13.

525 NextEra 2017 Comments at 27.

526 Alliance for Clean Energy 2017 Comments at 1-2; AWEA 2017 Comments at 

45; EDP 2017 Comments at 7; Generation Developers 2017 Comments at 34-36; NextEra 

2017 Comments at 28.

527 AWEA 2017 Comments at 44-45; Competitive Suppliers 2017 Comments 

at 10; Generation Developers 2017 Comments at 35-36.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 177 -

295. Some supporting commenters would prefer scaling back or eliminating specific 

aspects of the NOPR proposal. PJM opposes the Filed Report Requirement; it argues that 

this requirement would not increase efficiency and that the ability to meet study deadlines 

is often outside the transmission provider’s control.528 Portland also opposes the Filed 

Report Requirement, stating that this proposal could disproportionately affect utilities 

with small queues or those that jointly own, but do not operate, transmission facilities. 

Portland suggests that the Commission apply a minimum threshold of delayed 

interconnection studies for triggering justifications and that the Commission not impose 

these requirements if the reasons for missing deadlines are outside the transmission 

provider’s control.529

296. Alevo and Invenergy favor financial incentives or penalties over reporting 

requirements to encourage timely study completion.530 Relatedly, AWEA states that a 

Final Rule should include remedies for interconnection customers affected by 

transmission providers’ failures to complete studies accurately and in a timely fashion.531 

AWEA suggests that the Commission require transmission providers to specify remedies

 528 PJM 2017 Comments at 20.

529 Portland 2017 Comments at 5-6.

530 Alevo 2017 Comments at 7-8; Invenergy 2017 Comments at 8.

531 AWEA 2017 Comments at 46.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 178 -

in their study services agreements for failure to comply with timeline provisions.532 

While it concedes that the NOPR proposal increases transparency, Invenergy likewise 

argues that concrete incentives and penalties would result in more timely interconnection 

study performance.533 Generation Developers assert that the proposal does not respond to 

the issue of consistently delinquent transmission providers. They argue that, as a 

consequence, such transmission providers will have no motivation to improve.534

297. Some commenters express concerns regarding the potential administrative burden 

imposed by the proposal.535 Bonneville, PG&E, and Alevo argue that the proposal could 

divert transmission providers’ planning resources from conducting studies to meeting 

administrative burdens with no improvement on the underlying causes of delays.536 EEI 

states that posting the aggregate number of employee hours and third party consultant 

hours expended toward interconnection studies is overly burdensome, is not helpful in 

evaluating performance, and raises customer costs.537 TVA notes that the process and 

tracking burden would need to be borne continually by transmission providers, without 

 532 Id.

533 Invenergy 2017 Comments at 3, 7.

534 Generation Developers 2017 Comments at 34.

535 See, e.g., Xcel 2017 Comments at 16.

536 Bonneville 2017 Comments at 6; PG&E 2017 Comments at 6; Alevo 2017 

Comments at 7-8.

537 EEI 2017 Comments at 51.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 179 -

regard to whether a reporting trigger is met.538 In contrast, NextEra believes that the 

proposal would not impose a material burden on transmission providers because they 

already know the status of their studies.539 

298. APS states that the proposal compromises transmission provider flexibility to 

complete studies and argues that the time required to properly assess an interconnection 

request may vary significantly.540 APS states that the addition of metrics would constrain 

the interconnection process while providing minimal benefits to the interconnection 

customer.541

299. A few commenters state that they do not object to the NOPR’s proposed reporting 

requirement.542 MidAmerican nonetheless would prefer that transmission providers

reform the queue process itself, rather than reporting on existing processes.543 MISO TOs 

also do not oppose the additional study reporting requirements, but they point out that 

they are already subject to extensive reporting requirements.544 For this reason, they ask 

 538 TVA 2017 Comments at 12.

539 NextEra 2017 Comments at 27.

540 APS 2017 Comments at 4.

541 Id.

542 MidAmerican 2017 Comments at 14; MISO TOs 2017 Comments at 34; NonProfit Utility Trade Associations 2017 Comments at 17.

543 MidAmerican 2017 Comments at 14.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 180 -

the Commission to allow MISO to retain its existing reporting requirements, subject to 

modification as needed to include the types of information required by the Final Rule.545 

300. Other commenters expressly oppose the proposal to require the posting of 

interconnection study statistics.546 Duke states that the primary reasons for delays are 

queue withdrawals and material modifications.547 EEI argues that the proposal fails to 

consider circumstances outside the transmission provider’s control, and that without 

additional context, this information will not benefit interconnection customers.548 

NYISO indicates that the 25 percent missed deadline requirements are unnecessarily 

punitive and would jeopardize NYISO’s ability to be flexible as needed during the 

interconnection process.549 NYISO also argues that additional administrative 

requirements to track study statistics will not expedite the study process.550

 

544 MISO TOs 2017 Comments at 33 (citing Midcontinent Indep. Sys. Operators, 

Inc., 158 FERC ¶ 61,003, at P 108 (2017)).

545 Id.

546 Duke 2017 Comments at 15-16; EEI 2017 Comments at 50; ISO-NE 2017 

Comments at 33-35; NYISO 2017 Comments at 32-34; Xcel 2017 Comments at 16.

547 Duke 2017 Comments at 16.

548 EEI 2017 Comments at 50-51.

549 NYISO 2017 Comments at 34.

550 Id. at 32.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 181 -

301. Xcel states that delays are often caused by interconnection customer actions and 

minor disputes between interconnection customers and transmission providers, but there 

is no evidence that transmission providers are being opaque or have not provided

sufficient justifications for delays. Xcel notes that interconnection customers can 

challenge unreasonable delays through a variety of means—including the Commission’s 

Enforcement hotline and the FPA section 206 process—and that Commission audits 

review the interconnection process.551 Xcel also argues that the NOPR proposal does not 

account for regions with fewer requests or delays caused by changes in study 

assumptions, negotiation of contractual language, or interpretation of technical study 

results. Xcel states that, if the Commission proceeds with this proposal, it should limit 

the LGIP requirements to providing a written description of the cause of the delay.552

302. Some commenters consider currently available information to be sufficient for 

interconnection customers.553 Duke asserts that the LGIP already requires transmission 

providers to inform interconnection customers about the causes of study delays and 

schedule revisions.554 Indicated NYTOs state that NYISO currently provides sufficient 

interconnection study information on its public website and to interconnection customers,

 551 Xcel 2017 Comments at 16.

552 Id.

553 See, e.g., EEI 2017 Comments at 51 (citing pro forma LGIP Sections 6.3, 7.4, 

and 8.3).

554 Duke 2017 Comments at 16; see also Xcel 2017 Comments at 16.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 182 -

and NYISO updates its Transmission Planning Advisory Committee on the status of all 

pending large generator facility interconnections.555 Indicated NYTOs also state that 

NYISO updates its OASIS with additional information as to where an interconnection 

request is situated in the study process and which studies have been completed.556 

Additionally, Indicated NYTOs state that interconnection customers receive more 

detailed information directly throughout the study process.557 Xcel indicates 

interconnection customers currently have sufficient transparency regarding the causes of 

delays and that any delays are discussed directly with the customer. Xcel states that if the 

customer does not understand the cause of a delay, it can ask the transmission provider 

for clarification.558

303. NYISO states that it currently maintains on its OASIS a list of all valid 

interconnection requests, together with the status of the interconnection request including, 

for example, where the project is in the study process and what studies have been 

completed.559 NYISO asserts that adding additional detail regarding the status of a 

particular study is not informative to the specific interconnection customer, which already 

 555 Indicated NYTOs 2017 Comments at 11; see also NYISO 2017 Comments 

at 30.

556 Indicated NYTOs 2017 Comments at 11.

557 Id.

558 Xcel 2017 Comments at 16.

559 NYISO 2017 Comments at 30.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 183 -

knows its status. Moreover, NYISO argues that additional administrative requirements to 

track study statistics will not expedite the study process.560 NYISO contends that the best 

way to expedite interconnection studies is through targeted process improvements, such 

as those NYISO has proposed to its stakeholders;561 NYISO states that it has a number of 

proposals that would improve study processing efficiency.562 Similarly, MISO 

recommends allowing existing stakeholder processes to accomplish the objectives of the 

proposed reporting requirements and notes that it is currently working to increase study 

timing visibility.563 

304. NYISO urges the Commission to allow it to tailor appropriate process 

improvements with the goal of expediting the studies rather than merely tracking their 

status.564 NYISO contends that posting the requested information is only informative if a

transmission provider reveals additional details that may require disclosure of 

confidential information. NYISO also argues that such detailed information regarding 

 560 Id. at 32.

561 Id. at 30-32.

562 Id. at 32.

563 MISO 2017 Comments at 30.

564 NYISO 2017 Comments at 32.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 184 -

the status of a particular study is appropriately shared only with the interconnection 

customer, not all projects in the interconnection queue.565

ii. Commission Determination 

305. In this Final Rule, we adopt the NOPR proposal modifying the pro forma LGIP 

section on OASIS Posting566 to require transmission providers to post interconnection 

study metrics to increase the transparency of interconnection study completion 

timeframes. We note, however, that we are modifying the posting location requirement, 

as discussed further below in the subsection “Requirement to Post Interconnection Study 

Metrics on OASIS” of this Final Rule. As proposed in the NOPR, transmission providers 

shall post this interconnection study metric information on a quarterly basis. We also 

adopt the Filed Report Requirement.567 The revisions to the pro forma LGIP adopted in

this Final Rule are provided in Appendix B. 

306. The current requirement that transmission providers complete interconnection 

studies on a timely basis is based on a “reasonable efforts”568 standard. This standard can 

 565 Id. at 33.

566 This has been renumbered to pro forma LGIP section 3.5 through this Final 

Rule. 

567 Any informational reports that transmission providers file at the Commission 

are for informational purposes and will not be formally noticed nor require additional 

action by the Commission. See Grid Assurance LLC ̧ 154 FERC ¶ 61,244, at n.106, 

order on clarification, 156 FERC ¶ 61,027 (2016).

568 “Reasonable Efforts” in Pro forma LGIP Section 1 (Definitions).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 185 -

be challenging to apply in the absence of information required in this Final Rule, 

including information about how long it takes transmission providers to complete studies 

and the resources a transmission provider uses to complete interconnection studies. 

Information on interconnection study metrics should provide needed transparency to 

allow interconnection customers to assess whether a transmission provider is using 

“reasonable efforts.” This information should also allow interconnection customers to 

develop informed expectations about how long the interconnection study portion of the 

process actually takes. 

307. Many commenters that oppose this proposal cite concerns about the potential 

administrative burden. We find unpersuasive comments that these requirements will be 

administratively burdensome for transmission providers in general, to those with small 

queues, or those that jointly own, but do not operate, their transmission assets. We find 

that the reporting requirement we adopt strikes a reasonable balance between providing 

increased transparency and information to interconnection customers while not unduly 

burdening transmission providers. We find that the increased transparency resulting from 

these new requirements should provide for improved queue management and better 

informed interconnection customer planning – results that may be important enough to 

support some corresponding burden on transmission providers. Further, as noted by 

NextEra, transmission providers already know the status of their studies, which suggests

that the reporting requirement should impose minimal, additional administrative burdens

on transmission providers. With regard to the assertion that the reporting requirement 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 186 -

will unduly burden transmission providers with smaller interconnection queues, we find it 

reasonable for a transmission provider with a small volume interconnection queue to 

detail the reasons for the delay of a lone study or a small number of studies, information 

that is still beneficial to interconnection customers. In these instances, the reporting 

requirement would not be more burdensome than for transmission providers with high 

volume queues that must provide this information for a greater number of studies, if 

additional reporting requirements are triggered. With regard to Portland’s contention that 

the reporting requirement will disproportionately burden transmission providers that 

jointly own, but do not operate, their transmission assets, we find little evidence in the 

record to support this assertion. We note that a transmission owner’s assignment of 

operational responsibility to a joint owner does not necessarily relieve it of its 

responsibilities or performance obligations.

308. Multiple commenters argue that interconnection customers are often the cause of 

interconnection study delays. Others question the usefulness of the information to be 

posted for interconnection customers or other stakeholders. We find that the detailed 

information provided to the Commission through the Filed Report Requirement should be 

particularly beneficial in identifying process deficiencies and the causes of delays in 

regions that experience significant delays in interconnection study processing. 

Additionally, this requirement complements the requirement that the causes of study 

delays be provided to interconnection customers upon request and does not duplicate the 

requirement in sections 6.3, 7.4, and 8.3 of the pro forma LGIP related to informing 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 187 -

interconnection customers about the causes of study delays. While those provisions 

require transmission providers to provide the reasons for study delays to individual

interconnection customers, these newly adopted provisions require the transmission 

provider to submit study delay information to the Commission. 

309. Some commenters encourage consideration of modifications and alternatives to 

the Commission’s proposal. We find that the reporting requirements we adopt in this 

Final Rule strike a reasonable balance between transparency into the timing and 

processing of interconnection requests while maintaining a transmission provider’s 

schedule flexibility to process complex and interdependent interconnection requests. As 

noted in the NOPR and supporting comments, the requirements should identify the 

geographical locations where interconnection study delays occur most often and will 

document the delays’ causes. We recognize that often a delay will not be the result of the 

transmission provider having acted inappropriately; therefore, we do not propose 

implementing automatic penalties for delayed studies, in recognition of this possibility. 

Nonetheless, we believe that adopting pro forma LGIP provisions will improve 

transparency by highlighting where interconnection study delays are most common and 

the causes of delays in these regions. Such information could highlight systemic 

problems for individual transmission providers and interconnection customers. This 

information could also be useful to the Commission in determining if additional action is 

required to address interconnection study delays. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 188 -

310. In response to commenters that seek to eliminate the Filed Report Requirement, 

we reiterate that this information should be useful for identifying the causes of delays in 

regions that experience a significant number of study delays. A number of entities should 

find the publication of this information useful, including stakeholders active in or 

considering entrance into a regional interconnection queue, the Commission, and 

transmission providers as they actively monitor their queue management efforts. We 

reiterate that we do not expect this information to be overly burdensome, as it should 

largely consist of information already tracked by the transmission provider. In response 

to commenters that propose alternative metrics to trigger reporting requirements, the 

Commission notes that the timeframes stated in the tariff are clear and defined and thus

should be familiar to the transmission provider and appropriate to use for measuring 

transmission provider performance. 

311. In response to commenters that advocate development of solutions and 

requirements through the regional stakeholder process, we find that the information 

required through interconnection study metrics should better inform stakeholder 

discussions, including discussions about need for further action. Further, many 

interconnection customers develop generation projects in multiple regions. Therefore,

having a minimum set of information that is comparable across regions would allow for 

quicker and more useful assessment by interconnection customers of the viability of 

potential projects. Furthermore, this reform is not intended to disrupt stakeholder 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 189 -

processes. We note that, on compliance, each transmission provider may explain how it 

will comply with the requirements adopted in this Final Rule. 

c. Requirement to Post Interconnection Study Metrics on 

OASIS

i. Comments

312. CAISO objects to the requirement to post interconnection study information on

OASIS.569 CAISO contends that using existing public websites, portals, and reports 

should satisfy any publication requirement and would save ratepayers from the expense 

of moving data onto OASIS.570 Additionally, CAISO argues that using existing public 

websites, portals, and reports would allow the critical assets to remain confidential.571 

OATI states that the metrics proposed are in line with similar requirements for 

transmission request studies but asks the Commission to direct this posting requirement 

to NAESB to establish a uniform location for the posting of these metrics on OASIS.572

ii. Commission Determination

313. In this Final Rule, we are modifying the location requirement for the quarterly 

posted summary interconnection study metrics. In the NOPR proposal, the quarterly 

summary statistic information required posting on OASIS. However, we agree with

 569 CAISO 2017 Comments at 22.

570 Id.

571 Id.

572 OATI 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 190 -

CAISO’s comments that transmission providers should have the flexibility to post this 

information on their OASIS sites or on a public website. If the transmission provider 

posts on its website, however, it must provide a clear link to the information on OASIS.

314. In response to OATI’s request, we decline to specifically require that 

transmissions providers work through NAESB to develop a uniform posting location for 

these requirements. Transmission providers may, of course, coordinate as they determine 

appropriate to implement the Commission’s requirements and to develop any relevant 

posting protocols.

d. Reasonable Efforts Standard and Firm Study Deadlines

i. Comments

315. Generation Developers and NextEra advocate elimination of the “reasonable 

efforts” standard as a way to improve study timeliness,573 the result of which would be to 

impose firm study deadlines Generation Developers state that, even with the new 

reporting requirement, transmission providers still have no obligation or incentives to 

meet the study deadline in their LGIPs.574

 573 Generation Developers 2017 Comments at 33-34; NextEra 2017 Comments 

at 27.

574 Generation Developers 2017 Comments at 33-34.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 191 -

316. Several commenters prefer to retain the ability of transmission providers to use 

“reasonable efforts” to complete interconnection studies.575 According to Imperial,

numerous factors affect timely study completion, and preserving the reasonable efforts

standard, while imposing these new reporting requirements, will afford transmission 

providers the requisite flexibility to account for study delays beyond their control.576 

NYISO states that, in its experience, interconnection customer non-responsiveness and 

inaccuracy interferes with its ability to perform timely interconnection studies. NYISO 

also notes that it must coordinate with all affected systems. NYISO states that, given 

these factors and other unique project complexities, the Commission should continue to 

evaluate interconnection study completion in accordance with the reasonable efforts 

standard.577

317. TVA expresses concern that the transmission provider efforts needed to meet all 

deadlines would reduce the current flexibility that benefits both interconnection 

customers and transmission providers.578 PG&E and Indicated NYTOs oppose 

establishment of fixed study deadlines.579 Indicated NYTOs argue that imposing 

 575 Bonneville 2017 Comments at 6; Duke 2017 Comments at 15-16; Imperial 

2017 Comments at 19; NYISO 2017 Comments at 33-34. 

576 Imperial 2017 Comments at 20.

577 NYISO 2017 Comments at 33-34.

578 TVA 2017 Comments at 12.

579 Indicated NYTOs 2017 Comments at 10-11; PG&E 2017 Comments at 6-7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 192 -

artificial deadlines can lead to prematurely completed studies that do not fully investigate 

all reliability issues, which could result in transmission owners having to pay for lateridentified upgrades.580

318. TDU Systems urge the Commission to consider adding a tolling provision to 

relevant provisions of the pro forma OATT because hard deadlines can be a “two-edged 

sword” for interconnection customers. Thus, they urge the Commission to toll the 

deadlines during periods when the transmission provider is responding to questions from 

the interconnection customer concerning study methods or results. TDU Systems 

contend that this will ensure that the deadline does not serve as a reason for the 

transmission provider to refuse to respond to legitimate questions from the 

interconnection customer.581

319. Rather than set study timeframes, APS and Bonneville believe that interconnection 

customers would benefit more from discussion and establishment of realistic study 

timeframes than from the reporting requirements.582 APS suggests that the Commission 

could better address queue delays by empowering transmission providers to set a default 

timeframe for study completion that is tiered based on specific factors, such as size, 

 580 Indicated NYTOs 2017 Comments at 11.

581 TDU Systems 2017 Comments at 21-22.

582 APS 2017 Comments at 5; Bonneville 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 193 -

location, presence of affected systems, or expected amount of upgrades.583 APS asserts 

that, if the Commission determines that an interconnection customer needs additional 

details about a request’s study progress, the best solution is a requirement that the 

transmission provider coordinate more closely with the interconnection customer.584

320. If the Commission adopts the NOPR proposal, ISO-NE asks that the Commission 

revise the reporting construct so that performance is evaluated in accordance with the 

reasonable efforts standard and not the timeframes established in the pro forma LGIP.585 

ISO-NE states that, alternatively, the Commission should allow regional flexibility for 

ISO-NE to evaluate and revise the timeframes to more realistically reflect the time that it 

takes to complete interconnection studies.586

321. CAISO opposes the interconnection study reporting requirement proposal as 

applied to CAISO and other transmission providers with firm study deadlines.587 CAISO 

states that its interconnection procedures and transmission planning process are 

coordinated such that one process informs the other and that this linkage necessitates 

 583 APS 2017 Comments at 4.

584 APS 2017 Comments at 4-5. 

585 ISO-NE Comments at 35.

586 Id. at 36.

587 CAISO 2017 Comments at 21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 194 -

timely interconnection study completion.588 As such, CAISO asserts, its transmission 

owners complete studies on a timely basis, and it already publishes detailed study process 

schedules for each queue cluster on its public website.589 CAISO requests that the 

Commission clarify that this proposal is limited to those transmission providers and 

owners whose tariffs do not have firm study deadlines.590

ii. Commission Determination

322. In response to concerns that the Commission is implementing firm interconnection 

study deadlines, we clarify that the NOPR did not propose, and the Final Rule declines to

adopt, firm deadlines for completing interconnection studies. Further, the NOPR did not 

propose to, and this Final Rule does not eliminate, the reasonable efforts standard or 

reduce transmission provider flexibility. Many commenters seem to equate measurement 

of a transmission provider’s ability to meet the study timeframes in their tariffs as the 

equivalent of establishing firm study deadlines. Many commenters argue against firm 

study deadlines and against elimination of the reasonable efforts standard. 

323. We do not believe the current record supports elimination of the “reasonable 

efforts” standard to meet study deadlines and to instead impose firm deadlines. At this 

time, we believe the reasonable efforts standard continues to be the appropriate approach 

 588 Id. at 22.

589 Id. (citing 

https://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx).

590 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 195 -

to interconnection study processing. We find that reliance on improved reporting is a 

preferable approach to encourage timely processing of interconnection studies, rather

than moving to a regime of firm study deadlines. Such reporting should also help inform 

the Commission if any future action should be considered. 

324. We disagree with ISO-NE’s argument that interconnection study metrics should be

calculated to reflect compliance with the reasonable efforts standard rather than tariff 

deadlines. The reasonable efforts standard is not meant to specify a timeframe but rather 

to impose a performance standard on the transmission provider. If ISO-NE’s request591 is 

that each interconnection study conducted per an interconnection request have a specific 

amount of time determined as appropriate for completion under the reasonable efforts 

standard, we note that ISO-NE has tariff-prescribed timeframes that are designed to apply 

to most interconnection requests. 

325. APS, Bonneville and ISO-NE contend that the Commission should allow 

transmission providers to establish interconnection study timeframes that more 

realistically reflect the time that it takes to complete interconnection studies. This request 

is outside the scope of this proceeding because the Final Rule is not proposing to modify 

the study timeframes currently memorialized in transmission providers’ LGIP.

326. We disagree with CAISO’s contention that transmission providers with firm 

deadlines should not be subject to the reporting requirements of this Final Rule. 

 591 ISO-NE 2017 Comments at 35.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 196 -

Interconnection customers and the queue management process would still benefit from 

posting relevant metrics regarding study completion in prescribed timeframes. We also 

note that, if a transmission provider has firm study deadlines that it always meets, then it 

would not trigger the Filed Report Requirement.

e. Challenges in Calculating Reported Metrics

i. Comments

327. Southern states that there are too many potential clock resets and restudies to 

result in any meaningful metrics.592 It does not see the value of using withdrawal metrics 

and considers average study cost to be a more meaningful metric than aggregating the 

total number of employee and third-party consultant hours.593 TVA asserts that, for the 

proposed metrics to be useful, there would need to be consistent definitions of start and 

stop times for each study phase and ways to adjust for customer‐caused delays.594

328. Consistent with Order No. 890, ISO-NE requests that the Commission clarify that 

the starting point for interconnection study metrics can be the date when the study begins 

or some other agreed upon date instead of the date the study agreement is signed.595

 592 Southern 2017 Comments at 23.

593 Id.

594 TVA 2017 Comments at 12-13.

595 ISO-NE 2017 Comments at 36 (citing Preventing Undue Discrimination and 

Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, at 

P 747, order on reh’g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on 

reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C,

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 197 -

329. Additionally, ISO-NE requests that the Commission extend the period for posting 

the information from 30 to 60 days to allow sufficient time for the transmission provider 

to collect the information, such as from third-party consultant invoices.596

330. PG&E requests clarification as to the application of the Commission’s proposed 

metrics.597 PG&E states that it is unclear whether they would apply to material 

modification applications, to cluster studies only, or also to Fast Track, repowering, and 

in-service date studies.598 

ii. Commission Determination

331. In response to Southern’s and TVA’s comments, we clarify that the start date for 

each study included in the performance reporting metrics is the date that the transmission 

provider receives a fully executed study agreement. If multiple study agreements have 

been executed for an interconnection request, or interconnection studies have been 

completed, delayed, or are ongoing, then the metric reporting period should begin the 

 

126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009)

(clarifying that the 60-day due diligence period starts on the date the transmission study 

agreement is executed, unless the transmission provider and the customer agree on an 

alternative day for the transmission provider to begin the study, and explaining that, 

while the transmission provider and customer may not alter the length of the study 

period, they can mutually agree as to the day on which the study begins)).

596 Id. at 39.

597 PG&E 2017 Comments at 7.

598 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 198 -

date that the transmission provider received the last executed study agreement and be 

measured to the most recent relevant study conducted or planned for that study 

agreement. In response to TVA’s comment about adjusting the performance metrics for 

interconnection customer-caused delays, we note that one of the objectives of the 

quarterly metrics is to identify regions where the transmission provider consistently 

completes interconnection studies on a delayed basis. The metric is not intended to 

identify the causes of those delays. This information is potentially useful to existing 

stakeholders as well as generation developers considering pursuing projects in that region

and the lack of metric adjustment for delaying factors provides for easier comparability 

of interconnection study completion timeframes across regions. The Commission 

believes that stakeholders will be most interested in explanations for missed deadlines in 

queue backlogged regions and an informational report to the Commission from such 

regions will be useful for identifying the delay causes. 

332. We disagree with ISO-NE that the starting point for interconnection study metrics 

should be a date other than the date the transmission provider receives a fully executed 

study agreement. The metrics adopted in this Final Rule provide information on the 

transmission provider’s ability to meet the timeframes described in the pro forma tariff. 

These date ranges are clearly defined, and the period between the executed study 

agreement and the study completion date reflects the amount of time to complete a study 

after the study’s terms are formally agreed upon. Some regions may experience 

significant delays in beginning a study after study agreements are signed; in these 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 199 -

instances, metrics based on a transmission provider’s performance once a study is 

begun—which could be long after executing the study agreement—would not be as 

informative and useful as the Commission’s adopted metrics. 

333. We also disagree with ISO-NE that we should extend the posting time period from 

30 to 60 days. Interconnection customers make decisions with information as it becomes 

available, and we believe that 30 days allows sufficient time for the transmission provider 

to post the required information.

334. In response to PG&E’s question about the application of the proposed metrics, we 

clarify that these metrics apply to interconnection requests within the queue, including 

clustering and fast-track projects. We expect that a change to a project that triggers

material modification provisions, though it will lose its queue position, would be in the 

queue as would repowering projects. Thus, the study performance metric calculations 

must include such projects.

6. Improving Coordination with Affected Systems

a. NOPR Request for Comments

335. The interconnection of a new generating facility to a transmission system may 

affect the reliability of a neighboring, or affected, transmission system. Currently, 

section 3.5 of the pro forma LGIP requires the transmission provider to coordinate the 

conduct of any studies required to determine the impact of an interconnection request on 

affected systems with the affected system operators. The transmission provider should 

also, if possible, include those results in the applicable interconnection study. Because 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 200 -

the affected system operator is not bound by the terms of the interconnection 

transmission provider’s LGIP, its process and schedule may differ from the transmission 

provider’s processing of the interconnection request. In Order No. 2003, the Commission 

explained that: 

[a]lthough the owner or operator of an Affected System is not bound by the 

provisions of the . . . LGIP or LGIA, the Transmission Provider must allow 

any Affected System to participate in the process when conducting the 

Interconnection Studies, and incorporate the legitimate safety and reliability 

needs of the Affected System.599

336. Order No. 2003 further explained that, if the affected system operator does not 

provide information in a timely manner, a transmission provider may proceed without

accounting for any information the affected system could have provided.600 Often,

however, transmission providers will not proceed without receiving reliability-related 

analysis from any affected systems. AWEA raised the issue of affected system impacts 

in its petition,601 and the Commission discussed the issue at the 2016 Technical 

Conference. 

 599 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 121.

600 Id. On rehearing, the Commission clarified that delays by an affected system in 

performing interconnection studies or providing information for such studies is not an 

acceptable reason to deviate from the timetables established in Order No. 2003 unless the 

interconnection itself (as distinct from any future delivery service) will endanger 

reliability. See Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 at P 114.

601 Petition at 31.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 201 -

337. Order No. 2003 does not require that transmission providers publish their affected 

system coordination process. During the Order No. 2003 proceeding, the Commission 

declined Duke’s request to require affected systems to participate in the interconnection 

process with interconnection customers.602 The Commission reiterated, however, that a 

transmission provider must allow any affected system to participate in the 

interconnection study process and must incorporate the affected system’s legitimate 

safety and reliability needs.603

338. The Commission stated in the NOPR that providing affected system coordination

guidelines and timeframes could better inform interconnection customers and could result 

in fewer late-stage withdrawals due to the unforeseen cost of affected system network 

upgrades.604 The Commission further posited that clear procedures and timelines 

regarding the affected system’s study of a proposed interconnection memorialized in a 

Commission-approved affected systems analysis agreement could ameliorate delays 

caused by the affected systems coordination process.

339. In the NOPR, the Commission sought comment on the following: prescribing 

guidelines for affected systems coordination; imposing study requirements and associated 

timelines on affected systems that are also public utility transmission providers; 

 602 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 121.

603 Id. PP 120-121.

604 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 158.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 202 -

standardizing the process for coordinating with an affected system during the 

interconnection process; developing a standard affected system study agreement; and 

additional steps (e.g., conducting a technical conference or workshop focused on 

improving issues that arise when affected systems are impacted).

b. Comments

340. Multiple commenters responded to the questions posed by the NOPR. We have 

not included a summary of the comments pertaining to affected systems coordination

because the Commission did not propose any specific reforms pertaining to affected 

systems in the NOPR and is considering these issues in another proceeding, as discussed 

below. However, these comments informed that discussion.

c. Commission Determination

341. On April 3 and 4, 2018, Commission staff convened a technical conference in 

Docket No. AD18-8-000 to explore issues related to the coordination of affected systems 

raised in this proceeding. The technical conference also explored issues related to the 

coordination of affected systems raised in the complaint filed by EDF Renewable Energy, 

Inc. against Midcontinent Independent System Operator, Inc., Southwest Power Pool, 

Inc., and PJM Interconnection, L.L.C. in Docket No. EL18-26-000. The Notice Inviting 

Post-Technical Conference Comments, which issued concurrently with this Final Rule, 

states that initial and reply comments are due within 30 days and 45 days, respectively, 

from the date of the notice’s issuance. The Commission is considering next steps in light 

of the technical conference held in Docket Nos. AD18-8-000 and EL18-26-000. We

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 203 -

decline to take further action in this rulemaking proceeding. Any further action on this 

issue would reference Docket No. AD18-8-000.

C. Enhancing Interconnection Processes

342. In the NOPR, the Commission proposed reforms designed to enhance 

interconnection processes by making use of underutilized interconnection service, 

providing interconnection service earlier, and accommodating changes in the 

development process. 

1. Requesting Interconnection Service below Generating Facility 

Capacity

a. NOPR Proposal

343. The Commission proposed to modify the pro forma LGIP to allow interconnection 

customers to request interconnection service that is lower than full generating facility 

capacity,605 recognizing the need for proper control technologies and penalties to ensure 

that the generation facility does not inject energy above the requested level of service.606 

The Commission also requested comment on whether, instead of such pro forma LGIP 

revisions, such interconnection requests should be processed on an ad hoc basis.607 

 605 The term generating facility capacity means “the net capacity of the Generating 

Facility and the aggregate net capacity of the Generating Facility where it includes 

multiple energy production devices.” Pro forma LGIA Art.1.

606 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 167-68.

607 Id. P 173.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 204 -

344. The Commission proposed that an interconnection customer that seeks 

interconnection service below its generating facility capacity should be subject to 

reasonable provisions that enforce a maximum export limit and a process for notifying an 

interconnection customer that it has exceeded such limit. 

345. The Commission also specifically proposed that interconnection customers be 

subject to reasonable penalties if they exceed their requested service levels, and that such 

penalties could be discrete financial penalties, a requirement to pay the cost of additional 

interconnection facilities or network upgrades, or the loss of interconnection rights. The 

Commission sought comment on the potential penalties that may be imposed if an 

interconnection customer exceeds its service level.608 

346. The Commission also specifically sought comment on the types and availability of 

control technologies and protective equipment to ensure that a generating facility does 

not exceed its level of interconnection service.609 Finally, the Commission proposed

changes to the definitions of “Large Generating Facility” and “Small Generating Facility” 

in the pro forma LGIP and pro forma LGIA so that they are based on the level of 

interconnection service for the generating facility rather than the generating facility 

capacity.610 

 608 Id. P 168.

609 Id. P 169.

610 Id. P 172.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 205 -

347. Consistent with the proposals above, the NOPR proposed to add the following 

new paragraph at the end of section 3.1 of the pro forma LGIP (with proposed new text in 

italics):

The Transmission Provider shall have a process in place to consider 

requests for Interconnection Service below the Generating Facility 

Capacity. These requests for Interconnection Service shall be studied at 

the level of Interconnection Service requested for purposes of 

Interconnection Facilities, Network Upgrades, and associated costs, but 

may be subject to other studies at the full Generating Facility Capacity to 

ensure safety and reliability of the system, with the study costs borne by the 

Interconnection Customer. Any Interconnection Facility and/or Network 

Upgrade costs required for safety and reliability also would be borne by 

the Interconnection Customer. Interconnection Customers may be subject 

to additional control technologies as well as testing and validation of those 

technologies consistent with article 6 of the LGIA. The necessary control 

technologies and protection systems as well as any potential penalties for 

exceeding the level of Interconnection Service established in the executed, 

or requested to be filed unexecuted, LGIA shall be established in Appendix 

C of that executed, or requested to be filed unexecuted, LGIA.611

348. The NOPR proposed to add the following language to the end of section 6.3 of the 

pro forma LGIP (with proposed new text in italics):

Transmission Provider shall study the interconnection request at the level 

of service requested by the interconnection customer, unless otherwise 

required to study the full Generating Facility Capacity due to safety or 

reliability concerns.

612 

349. The NOPR proposed to insert the following language in section 7.3 of the 

pro forma LGIP in line 8 of the second paragraph (with proposed new text in italics):

 611 Id. P 174. In this Final Rule, the adopted language differs slightly from the 

NOPR language because we remove the word “the” before “Transmission Provider.”

612 Id. P 175.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 206 -

For purposes of determining necessary interconnection facilities and 

network upgrades, the System Impact Study shall consider the level of 

interconnection service requested by the Interconnection Customer, unless 

otherwise required to study the full Generating Facility Capacity due to 

safety or reliability concerns.613

350. The NOPR proposed to add the following language to the end of section 8.2 of the 

pro forma LGIP (with proposed new text in italics):

The Facilities Study will also identify any potential control equipment for 

requests for Interconnection Service that are lower than the Generating 

Facility Capacity.614

351. The NOPR proposed to add the following language to Appendix 1, Item 5, of the 

pro forma LGIP, as sub-item h (with proposed new text in italics: 

Requested capacity (in MW) of Interconnection Service (if lower than the 

Generating Facility Capacity).615 

352. Lastly, the NOPR proposed to change the definition of “Large Generating 

Facility” and “Small Generating Facility” in section 1 of the pro forma LGIP and article 

1 of the pro forma LGIA as follows (proposed to delete the bracketed text and add the 

italicized text): 

Large Generating Facility shall mean a Generating Facility for which an 

Interconnection Customer has [having a Generating Facility Capacity]

requested Interconnection Service of more than 20 MW.

 613 Id. P 176.

614 Id. P 177.

615 Id. P 178.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 207 -

Small Generating Facility shall mean a Generating Facility for which an 

Interconnection Customer has requested Interconnection Service [that has a 

Generating Capacity]of no more than 20 MW.616

b. General

i. Comments

353. Most responsive commenters support the proposal.617 Alevo states that electric 

storage facilities may not plan to use the maximum power rating of their facilities; 

therefore, they should have the ability to request interconnection service at the power 

rating of their choice.618 NextEra also argues that rejecting requests for interconnection 

below full generating facility capacity can result in paying for unneeded interconnection 

facilities and network upgrades.619 

354. A number of commenters see benefits to the proposal. Several commenters see 

the potential for lower costs.620 AFPA and the Public Interest Organizations assert that 

 616 Id. P 179.

617 Alevo 2017 Comments at 8; AFPA 2017 Comments at 3; AWEA 2017 

Comments at 52; Bonneville 2017 Comments at 7; CAISO 2017 Comments at 27; 

California Energy Storage Alliance 2017 Comments at 6; Joint Renewable Parties 2017 

Comments at 12; ELCON 2017 Comments at 7; ESA 2017 Comments at 8.

618 Alevo 2017 Comments at 8.

619 NextEra 2017 Comments at 34-35 (citing NOPR, FERC Stats. & Regs. 

¶ 32,719 at P 167).

620 AFPA 2017 Comments at 14; Public Interest Organizations 2017 Comments 

at 5-8; ELCON 2017 Comments at 7; ESA 2017 Comments at 8; IECA 2017 Comments 

at 3.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 208 -

allowing for interconnection service below capacity will improve the efficiency and 

fairness of the interconnection process and enhance reliability.621 ESA agrees, adding

that the proposal will allow interconnection customers to request service that reflects a 

given resource’s intended operation.622 ESA and AFPA contend that the proposal will 

remove undue discrimination toward highly controllable or unique resources, such as 

electric storage resources or combined heat and power, in interconnection processes.623 

ESA further argues that the proposal will facilitate market entry of electric storage 

resources by eliminating excessive costs and will allow electric storage resources to use 

spare interconnection service to repower existing conventional generators or firm the 

deliveries of variable generators.624

355. AWEA states that developers of new technologies have an interest in requesting 

interconnection service at levels below generating facility capacity.625 It notes that wind 

turbine manufacturers often make minor upgrades to equipment or software to increase

capacity, and these upgrades sometimes occur during the pendency of an interconnection 

request. As a result, the final generating facility capacity may be greater than what was 

 621 AFPA 2017 Comments at 14; Public Interest Organizations 2017 Comments 

at 5-8; MidAmerican 2017 Comments at 17.

622 ESA 2017 Comments at 8.

623 Id.; AFPA 2017 Comments at 14.

624 ESA 2017 Comments at 10.

625 AWEA 2017 Comments at 52.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 209 -

originally specified in the interconnection request. AWEA argues that in such cases, the 

interconnection customer may prefer to avoid seeking an increase in interconnection 

service because increasing the generating facility capacity may constitute a material 

modification that triggers the need for a restudy.626 AWEA further argues that allowing 

an interconnection customer to increase its capacity without increasing its requested level 

of interconnection service and without it being considered a material modification would 

promote more efficient operation of wind plants.627 AWEA states that allowing 

interconnection service at levels below generating facility capacity would benefit wind 

facilities due to the collector system losses that occur, as the output of the multiple 

turbines at a wind farm are aggregated before injection to the grid. According to AWEA, 

these losses result in the maximum real power output at the point of interconnection 

being measurably lower than the combined generating facility capacity of the individual

units.628 

356. ESA and NextEra also point out that, in Order No. 792, the Commission revised 

the pro forma SGIP to allow small generating facilities to attain interconnection service 

below installed capacity, if the interconnection customer installs acceptable control 

 626 Id. at 52-53.

627 Id. at 52-53.

628 Id. at 53-54.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 210 -

technologies to avoid violating injection limits; thus, it would be inconsistent to not allow 

the same for large generating facilities.629

357. ELCON, ESA, and NextEra also note that the proposal will reduce the 

overbuilding of interconnection facilities and network upgrades.630 According to 

Industrial Energy Consumers of America, this reform should also increase existing asset 

utilization and improve the accuracy and reliability of interconnection studies.631 

MidAmerican argues that the proposal may reduce late-stage withdrawals from the queue 

by allowing interconnection customers to operate at reduced output levels rather than 

requiring network upgrades that would otherwise render them non-viable.632 NEPOOL 

suggests that the proposal provides options and flexibility for market participants and 

could facilitate market entry of new resources.633

358. CAISO notes that the flexibility afforded by the proposal can benefit 

interconnection customers – especially for newer resources that combine storage, 

 629 ESA 2017 Comments at 11 (citing Order No. 792, 145 FERC ¶ 61,159 at 

P 230); NextEra 2017 Comments at 37.

630 ESA 2017 Comments at 8; ELCON 2017 Comments at 7; NextEra 2017 

Comments at 35.

631 IECA 2017 Comments at 3.

632 MidAmerican 2017 Comments at 17.

633 NEPOOL 2017 Comments at 14-15.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 211 -

conventional generation, high auxiliary load, and/or onsite demand-side management.634 

It further argues that the transmission operator is unaffected so long as the 

interconnection request studies the correct capacity and the generating facility never 

exceeds that capacity.635 ELCON also notes that the proposal would provide benefits for 

industrial co-generators or other behind-the-meter industrial generation.636 

359. Multiple commenters note that similar programs are already in place in some 

RTOs/ISOs, either on a formal or informal basis, including CAISO, MISO, PJM, and 

ISO-NE.637 ESA and NextEra offer examples of where interconnection service lower 

than installed capacity is already occurring without reliability problems.638 ESA provides 

examples in CAISO, MISO, and PJM, where it believes projects have been sized to allow 

greater generation deliveries over time, but where the facilities (including one that 

combines solar and storage) never deliver at maximum output.639

360. CAISO and PG&E state that CAISO allows interconnection requests for less than 

generating facility capacity, as long as the interconnection customer installs appropriate 

 634 CAISO 2017 Comments at 27.

635 Id.

636 ELCON 2017 Comments at 7.

637 CAISO 2017 Comments at 27; MISO 2017 Comments at 33; PJM 2017 

Comments at 23-24; NEPOOL 2017 Comments at 14-15.

638 ESA 2017 Comments at 10-11; NextEra 2017 Comments at 36.

639 ESA 2017 Comments at 10-11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 212 -

monitoring and control technologies to enforce the maximum export limit.640 PG&E 

notes that various projects have made such requests, particularly solar resources.641 

361. PG&E notes that CAISO also allows interconnection projects to downsize their 

capacity, which is functionally equivalent to limiting a project with excess capacity.642 

362. MISO notes that its generator interconnection agreement allows interconnection 

customers to request interconnection service below the capacity of the proposed 

generating facility and limits the net injection to the allowed interconnection service 

level.643 MISO notes that the additional limiting language gives the transmission owner 

and MISO the right to enforce the limit.644 Similarly, NextEra explains that MISO has 

allowed it to amend an existing interconnection agreement to reflect an increase in the 

rating of a wind generation project without an increase in the level of interconnection 

service provided.645

363. PJM states that it currently allows interconnection customers to limit injection 

rights subject to additional studies at both the requested level of interconnection service 

 640 CAISO 2017 Comments at 27; PG&E 2017 Comments at 7 (citing CAISO 

Business Practice Manual for Generator Management, Section 6.5.4.1). 

641 PG&E 2017 Comments at 7.

642 Id.

643 MISO 2017 Comments at 33.

644 Id.

645 NextEra 2017 Comments at 36-37.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 213 -

to identify required network upgrades, as well as at the generating facility’s full 

capacity.646 PJM explains that these studies allow PJM to specify the system protections 

necessary in the event of system contingencies.647 NextEra states that PJM has allowed a 

wind generator to install capacity in excess of the level of interconnection service in the 

agreement.648

364. ISO-NE states that it supports the proposal and has already implemented a similar 

process under its existing interconnection procedures.649 Similarly, NEPOOL states that 

interconnection customers in ISO-NE can already request an amount of interconnection 

service less than generating facility capacity at the time of the interconnection request or 

before beginning the system impact study.650 NEPOOL notes that if a generating facility 

consists of multiple generating units, ISO-NE would need to study a number of possible 

output combinations, which could increase study costs and timelines but could also

potentially reduce upgrade requirements.651 NEPOOL states that ISO-NE studies such 

requests at the requested below-generating facility capacity amount, and the 

 646 PJM 2017 Comments at 24.

647 Id.

648 NextEra 2017 Comments at 36-37.

649 ISO-NE 2017 Comments at 40.

650 NEPOOL 2017 Comments at 15.

651 NEPOOL 2017 Comments at 15.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 214 -

interconnection customer must explain how it will limit output of its facility to that 

level.652

365. Non-Profit Utility Trade Associations, NYISO, and SEIA do not object to the 

proposal.653 Portland generally supports this proposal, but states that there are potential 

queue and reliability impacts.654 TVA argues that the proposal imposes an undesirable 

monitoring and mitigation burden on transmission system operators, and that the 

necessary protective systems introduce undesirable reliability challenges.655 Southern 

expresses concern that interconnection customers could take advantage of this proposal to 

avoid costly network upgrades.656 EEI requests that the Commission ensure that any 

revisions to the pro forma LGIA or LGIP provide clear requirements for interconnection 

customers.657 Non-Profit Utility Trade Associations recommend establishing NERC 

reliability standards for interconnection customers operating at levels below their rated 

 652 Id.

653 Non-Profit Utility Trade Associations 2017 Comments at 4, 21-22; NYISO 

2017 Comments at 36; SEIA 2017 Comments at 21.

654 Portland 2017 Comments at 6.

655 TVA 2017 Comments at 14-16.

656 Southern 2017 Comments at 25.

657 EEI 2017 Comments at 54; NYISO 2017 Comments at 36.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 215 -

capacity, which would constrain them to the rating at which their generation was 

studied.658

366. In response to the Commission’s question in the NOPR regarding whether, instead 

of revising the pro forma LGIP, such interconnection requests should be processed on an 

ad hoc basis,659 ESA states that an ad hoc basis for considering interconnection requests 

below cumulative installed capacity does not provide sufficient certainty to 

interconnection customers seeking interconnection service below a resource’s installed 

capacity.660 NextEra agrees, arguing that an ad hoc approach could lead to arbitrary and 

potentially unduly discriminatory results.661

ii. Commission Determination

367. In this Final Rule, we adopt the NOPR proposal to modify sections 3.1, 6.3, 7.3, 

8.2, and Appendix 1 of the pro forma LGIP to allow interconnection customers to request 

interconnection service that is lower than full generating facility capacity, recognizing the 

need for proper control technologies and penalties to ensure that the generating facility 

 658 Non-Profit Utility Trade Associations 2017 Comments at 24.

659 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 173.

660 ESA 2017 Comments at 11.

661 NextEra 2017 Comments at 37-38.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 216 -

does not inject energy above the requested level of service.662 We also withdraw the 

proposal to revise the definitions of “Large Generating Facility” and “Small Generating 

Facility” in the pro forma LGIA so that they are based on the level of interconnection 

service for the generating facility rather than the generating facility capacity, and make 

certain clarifications, as discussed further below. 

368. The majority of responsive comments either support the NOPR proposals outright 

or emphasize the importance of allowing transmission providers to retain the tools 

necessary to continue to ensure reliable operations. Furthermore, as noted by some 

commenters, some RTOs/ISOs have already permitted such flexibility in the generator 

interconnection process without causing reliability issues. 

369. We find that the reforms and clarifications made in this Final Rule, coupled with

existing provisions in the pro forma LGIA, provide the desired flexibility for 

interconnection customers while allowing transmission providers to ensure reliability. 

370. The reforms adopted here are consistent with existing provisions of the pro forma 

LGIA. Article 6 of the pro forma LGIA provides transmission providers with broad 

ability to test and inspect or require the testing and inspection of interconnection facilities

and network upgrades. Articles 7 and 8 of the pro forma LGIA provide a similarly broad 

ability to transmission providers with respect to metering and communications

 662 We are therefore not pursuing the alternative, ad hoc approach to 

interconnections below generating facility capacity, about which the NOPR sought 

comment.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 217 -

requirements relevant to interconnection. All of these existing provisions would apply to 

interconnection requests that are below generating facility capacity, just as they do to 

other interconnection requests, and they would thus help ensure that the necessary control 

technologies for limiting injection adhere to transmission provider requirements. 

371. Most importantly, article 9 of the pro forma LGIA describes both the transmission 

provider’s and the interconnection customer’s obligations with respect to operations of 

the interconnection facilities and network upgrades and, in particular, defines system 

protection facilities to include “the equipment, including necessary protection signal 

communications equipment, required to protect the transmission provider's transmission 

system from faults or other electrical disturbances occurring at the generating 

facility.”663 Article 9.7.4.1 of the pro forma LGIA requires the interconnection customer 

to pay for the installation, operation, and maintenance of system protection facilities 

associated with its interconnecting generating facility. We find that the necessary control 

technologies for limiting injection discussed in the NOPR are a subset of the system 

protection facilities that transmission providers are empowered to require and all 

interconnection customers are required to pay for under article 9.7.4.1 of the pro forma 

LGIA. 

372. We note that nothing in article 9.7.4.1 of the pro forma LGIA prevents

interconnection customers from proposing system protection facilities to limit their

 663 LGIA Art. 1 (Definitions) (emphasis added).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 218 -

injection rights to meet the transmission provider’s requirements. Therefore, this aspect 

of the Final Rule makes those interconnection customer rights explicit, while still 

preserving the transmission provider’s ability to ensure system protection under the 

existing pro forma LGIA provisions. Commenters have not argued that these broad, 

existing authorities are insufficient in the context of interconnection requests operating 

below full generating facility capacity.

373. Furthermore, article 5.9 of the pro forma LGIA permits an interconnection 

customer to request the study and, if appropriate, subsequent use of, a lower level of 

interconnection service, termed “limited operation,” in cases where the transmission 

provider's interconnection facilities or network upgrades are not reasonably expected to 

be completed prior to the commercial operation date of the generating facility. While this 

existing LGIA provision is intended to permit temporary operation at below generating 

facility capacity, the fact that entities have successfully made use of this provision 

demonstrates that there should not be anything inherently unworkable about the concept

of interconnection below generating facility capacity. Therefore, we find that this Final 

Rule does not adversely impact transmission providers’ ability to ensure reliable 

interconnection consistent with good utility practice.

374. Finally, with respect to the Non-Profit Utility Trade Associations’ suggestion that 

a NERC reliability standard be considered that would constrain interconnection 

customers operating at levels below their rated generating facility capacity to the rating at 

which the facilities are studied, we find that suggestion to be outside the scope of this 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 219 -

rulemaking proceeding. As discussed above, the existing system protection facility 

provisions of the pro forma LGIA, which apply to all interconnection customers, 

adequately ensure that below-generating facility capacity interconnection customers do

not exceed the limits for which they are studied.

c. Study Assumptions and Modeling

i. Comments

375. Commenters disagree on the appropriate way to model and conduct studies of 

resources that seek to interconnect below their capacity. Some commenters argue that the 

studies should focus solely on the reduced generating facility capacity. For example, 

AWEA, ESA, and NextEra assert that transmission providers should not be able to study 

interconnection requests at full generating facility capacity. They argue that the 

interconnection customer should be able to determine operational assumptions and 

limitations, especially given the sophisticated and reliable characteristics of available

monitoring and control technologies.664

376. ESA argues that, if a transmission provider is skeptical that proposed control 

systems are adequate, it should identify the shortcomings of the proposed control scheme 

to the customer and suggest what modifications address these shortcomings.665 NextEra 

 664 AWEA 2017 Comments at 54; ESA 2017 Comments at 12; NextEra 2017 

Comments at 40-41.

665 ESA 2017 Comments at 12.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 220 -

argues that requiring studies at full generating facility capacity would “undermine the 

very goal of the Commission’s proposed reforms.”666 

377. On the other hand, NYISO contends that, to ensure reliability, short circuit 

analysis of the full generating facility capability and steady-state and dynamic study 

evaluations of the specific mechanism, which would serve to enforce this limit, are 

necessary.667 NYISO asserts that these evaluations are necessary to ensure that the 

mechanism does not impact the resource’s ability to reliably interconnect to the New 

York state transmission system or distribution system and that, in the event that the 

mechanism fails, there are no adverse short circuit impacts.668 

378. Similarly, ESA and NextEra suggest that short circuit and stability studies should 

be performed using full generating facility capacity, whereas thermal studies should be at 

the level of interconnection requested.669 However, if a transmission provider decides to 

perform thermal studies at the full generating facility capacity rating, then NextEra 

suggests tariff language stating that those study costs should be borne by the transmission 

provider and be outside the normal queue timeframe.670 NextEra adds that a transmission 

 666 NextEra 2017 Comments at 39.

667 NYISO 2017 Comments at 36.

668 Id.

669 ESA 2017 Comments at 12-13; NextEra 2017 Comments at 40.

670 Id. at 41.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 221 -

provider should be able to refuse to grant the requested lower level of interconnection 

service just as it could refuse to proceed with an interconnection request, subject to 

dispute resolution, if a customer objects to a system protection facility proposed by the 

transmission provider.671

379. Bonneville and Non-Profit Utility Trade Associations emphasize that transmission 

providers should be able to study at full generating facility capacity in cases where safety 

or reliability concerns may arise.672 Duke goes further, stating that system impact studies 

and facilities studies should use full generating facility capacity for reliability reasons.673 

380. On the other hand, TDU Systems contends that, to ensure transparency, the 

transmission provider must be able to document the need for a study at full generating 

facility capacity.674 EEI is not aware of any protection system that would eliminate the 

need to study the full generating facility capacity and therefore doubts that the proposal 

would reduce costs.675

 671 Id. at 41.

672 Bonneville 2017 Comments at 7; Non-Profit Utility Trade Associations 2017 

Comments at 4, 21-22. 

673 Duke 2017 Comments at 19.

674 TDU Systems 2017 Comments at 27-28.

675 EEI 2017 Comments at 55.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 222 -

381. ITC and Six Cities support the NOPR proposal that the costs of all additional 

studies should be borne by the interconnection customer.676 

382. SoCal Edison takes a middle view, stating that the necessary studies would depend 

on the specifics of each interconnecting project.677 It states that, based on its experience, 

the cost to study a generating facility at less than its full capacity is either the same as or 

higher than a regular process.678 SoCal Edison suggests that dual technologies (e.g., solar 

coupled with energy storage) will require more study time than normal,679 and would 

actually have higher study costs, despite the fact that the output is limited, as two or three 

different scenarios would need to be evaluated for stability and post-transient voltage 

performance.680 

ii. Commission Determination

383. We adopt the NOPR proposal that the transmission provider will study requests 

for interconnection service at the level of interconnection service requested by the 

interconnection customer for purposes of interconnection facilities, network upgrades, 

and associated costs, but may, at the transmission provider’s discretion as clarified below,

 676 ITC 2017 Comments at 18, Six Cities 2017 Comments at 5.

677 SoCal Edison 2017 Comments at 7.

678 Id.

679 Id.

680 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 223 -

also perform other studies at the full generating facility capacity to ensure safety and 

reliability of the transmission system, with the study costs borne by the interconnection 

customer. 

384. We clarify that, if the transmission provider determines, based on good utility 

practice and related engineering considerations and after accounting for the proposed 

control technology, that studies at the full generating facility capacity are necessary to 

ensure safety and reliability of the transmission system when an interconnection customer 

requests interconnection service that is lower than full generating facility capacity, then it

must provide a detailed explanation for such a determination in writing to the 

interconnection customer. For example, some interconnection customers may have 

proposed generating facilities that may raise short-circuit/fault-duty concerns that require 

certain studies to be performed at full generating facility capacity, even if the generating 

facilities will normally be limited to operation below full generating facility capacity. If 

the transmission provider determines in accordance with good utility practice and related 

engineering considerations after accounting for the proposed control technology that 

additional network upgrades are needed based on these studies, the transmission provider 

must: (1) specify which additional network upgrade costs are based on which studies; 

and (2) provide a detailed explanation why the additional network upgrades are needed. 

385. In response to Duke’s comment that transmission providers should always perform 

system impact studies and facilities studies at full generating facility capacity for 

reliability reasons, we reiterate that, if the transmission provider either accepts the 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 224 -

interconnection customer’s proposed control technology or designs its own control 

technology as part of the system protection facilities for the interconnection, then the 

transmission provider should, subject to the limited exception discussed above, perform 

the necessary studies to ensure safety and reliability of the transmission system and 

evaluate system performance to interconnect the generating facility at the requested 

generating facility capacity level. In addition, to improve transparency, we clarify that 

the transmission provider must inform the interconnection customer, after the feasibility 

study phase regarding which studies (e.g., steady-state, short circuit/fault duty, and 

dynamic stability analysis) will be performed at which generating facility capacity level. 

386. We further clarify that, if disputes related to the transmission provider’s use of 

discretion while processing interconnection requests for interconnection service that is 

lower than full generating facility capacity cannot be resolved, the parties may seek 

dispute resolution through any process that may be available in the relevant LGIP, LGIA

or through DRS, and/or may bring the dispute to the Commission under a FPA section 

206 complaint or, if appropriate, as part of the transmission provider’s filing of an 

unexecuted LGIA. 

d. Limits on Energy Injection/Monitoring/Control

i. Comments

387. Many commenters focus on ways to ensure that generating facilities do not exceed 

the energy injection limits in the interconnection agreement. Almost all agree that 

appropriate control technology is necessary to prevent interconnection customers from 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 225 -

exceeding the approved interconnection service limit.681 Most agree that such tools are 

available, though there is wide variation in suggested implementation. For example, 

Portland agrees that sufficient mechanical and electronic tools exist that can restrain an 

interconnection customer from operating above its allowed service level, and also that 

transmission providers should establish such arrangements.682

388. AWEA notes that programmable meters and other technologies that allow plant 

operators to self-curtail are widely available,683 and ESA and NextEra state that wind and 

solar projects already use software control systems and inverters to modulate their output,

and that equipment failure is rare.684 

389. CAISO states that exceeding studied interconnection capacity can result in serious 

safety and reliability risks to the grid and the generator itself.685 It argues that it is more 

critical to have tested and well-maintained protection schemes that enforce these limits 

and operate circuit breakers to disconnect the generator from the transmission system

 681 AFPA 2017 Comments at 14; ESA 2017 Comments at 12; AWEA 2017 

Comment at 54; California Energy Storage Alliance 2017 Comments at 5-6; PJM 2017 

Comments at 24; Duke 2017 Comments at 18-19; EEI 2017 Comments 2017 at 54; TDU 

Systems 2017 Comments at 27-28.

682 Portland 2017 Comments at 7.

683 AWEA 2017 Comments at 54.

684 ESA 2017 Comments at 12, NextEra 2017 Comments at 39.

685 CAISO 2017 Comments at 27.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 226 -

than an interconnection customer’s contractual commitment to do so.686 CAISO supports 

strict enforcement of interconnection capacity limits, including opening breakers as 

enforcement and, if needed, terminating LGIAs.687 NYISO also states that it and the 

connecting transmission owner should be able to take action as necessary to maintain 

reliability—e.g., the ability to curtail the resource.688 Non-Profit Utility Trade 

Associations note that control equipment ensuring appropriate power flows is a critical 

reliability feature.689

390. PJM explains that it currently requires that interconnection customers install 

appropriate power flow monitoring and control technologies at their generating facilities

to limit the facilities’ allowable injection on to the transmission system.690 ISO-NE 

argues that any control equipment proposed to restrict the generating facility’s output to

the requested interconnection service levels must be identified in the project description 

at the beginning of the study process.691

 686 Id.

687 Id.

688 NYISO 2017 Comments at 36-37.

689 Non-Profit Utility Trade Associations 2017 Comments at 22.

690 PJM 2017 Comments at 24-25.

691 ISO-NE 2017 Comments at 41-42.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 227 -

391. SoCal Edison states that, to mitigate the risk of exceeding an interconnection 

service limit, the interconnection customer should have to install a control system that 

meters total output at the high side of the main transformer banks.692 

392. The Non-Profit Utility Trade Associations also argue that interconnection 

customers should bear the costs of control technologies and protection system costs 

because such equipment is not useful to other customers.693 MISO TOs, Duke and TDU 

Systems state that the interconnection customer should be obliged to install or pay for the 

necessary control technologies.694 

393. NextEra further explains that an over-delivery would only result from a failure of 

the generation control system or inverter controls, akin to a computer malfunction, which 

NextEra notes is theoretically possible, but very rare.695 NextEra also argues that, if a 

malfunction were to occur, protective relay controls could be installed that manually trip 

breakers when output levels exceed specified levels at the point of interconnection, 

establishing a secondary and redundant control mechanism.696 

 692 SoCal Edison 2017 Comments at 6.

693 Non-Profit Utility Trade Associations 2017 Comments at 4, 21–22.

694 MISO TOs 2017 Comments at 36; Duke 2017 Comments at 18-19; TDU 

Systems 2017 Comments at 27-28.

695 NextEra 2017 Comments at 40.

696 Id. n.26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 228 -

394. In contrast, while MidAmerican agrees that the generating facility output must not 

exceed the level of interconnection service, it does not support a universal requirement 

for special hardware or software systems.697 MidAmerican sees no clear reason why 

resources having interconnection service at levels below their full output should be 

singled out for special hardware or software requirements. Further, it argues that the 

Commission’s proposal for “provisional” service appears functionally equivalent to 

operating a generating facility for a period of time below its rated generating facility

capacity, yet the proposal for provisional service makes no mention of special hardware 

or software schemes.698

395. Xcel also advises the Commission to not regulate specific technical processes used 

to limit dispatch as technology may evolve and each region’s processes are unique. Xcel 

notes that it uses a manual process for its net-zero facility in MISO, and believes its 

process is sufficient.699 Similarly, for inverter-based resources, California Energy 

Storage Alliance asks the Commission not to impose a requirement for burdensome and 

expensive protection equipment that may duplicate similar utility equipment.700

 697 MidAmerican 2017 Comments at 18.

698 Id.

699 Xcel 2017 Comments at 17.

700 California Energy Storage Alliance 2017 Comments at 5-6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 229 -

ii. Commission Determination

396. As discussed above, we find that the revisions and clarifications in this rulemaking 

coupled with existing provisions of the pro forma LGIA adequately address the 

Commission’s proposal to require that any interconnection customer that seeks 

interconnection service below its generating facility capacity install appropriate 

monitoring and control technologies at its generating facility. We agree with ISO-NE’s 

argument that any control technologies proposed by the interconnection customer to 

restrict the generating facility’s output to the requested interconnection service levels 

must be identified in the project description at the beginning of the study process. We 

clarify that we see no reason to preclude a customer from relying on the transmission 

provider to identify protection and control technologies in the first instance. Indeed, as 

discussed earlier, the existing system protection facilities provisions in the pro forma 

LGIA already allow the transmission provider to identify and require the installation of 

appropriate system protection facilities.701

397. With respect to SoCal Edison’s argument that the interconnection customer’s 

control technologies should have to meter total output at the high side of the main 

transformer banks, we see no need for this requirement because the pro forma LGIP and 

 701 As discussed earlier, any protection and control technologies necessary to 

restrict the generating facility’s output to the requested interconnection service levels 

would be components of the system protection facilities associated with that generating 

facility’s interconnection.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 230 -

pro forma LGIA require transmission providers to make such engineering judgments 

consistent with good utility practice.

398. With respect to the Non-Profit Utility Trade Associations’ argument that control 

technologies and protection system costs should be treated as directly assigned costs, as 

discussed earlier, we find that these control and protection technologies are system 

protection facilities as defined in existing pro forma LGIA article 9.7.4.1, which already 

directly assigns these costs to the interconnection customer.

399. MidAmerican and NextEra argue that facilities without special control systems are 

no more likely to over-deliver than generators that have not requested interconnection 

service below their facility capacity. As an example, MidAmerican points out the case of 

a generator operating under provisional interconnection service, which has the ability to 

over-generate if it does not adhere to its interconnection service request level. NextEra 

makes a similar observation with respect to thermal generation generally.702 We 

appreciate these points, and note further that many generators of various types 

interconnected under ERIS may have the technical capability to generate beyond the level 

to which they are limited by the terms of their LGIAs providing for ERIS. However, we 

note that article 9.7.4.1 of the pro forma LGIA already generally allows a transmission 

provider to require appropriate control technologies for limiting injection from 

interconnection customers. The revisions to sections 3.1 and 8.2 of the pro forma LGIP 

 702 NextEra 2017 Comments at 45.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 231 -

that we adopt here with regard to control technologies serve to make such provisions 

explicit in the pro forma LGIP in the case where interconnection service is requested 

below generating facility capacity, in recognition of the fact that, in such instances, the 

generating facility may be coordinating output from multiple generating facilities, and 

may therefore have unique control characteristics and challenges.

400. With regard to the type of control strategy/design that NextEra proposed, we 

expect a transmission provider to find such a control system, or a control system of equal 

dependability, acceptable for the purposes of evaluating interconnection requests for 

interconnection service that is lower than full generating facility capacity. There may be 

circumstances in which a transmission provider could reasonably find that additional 

back-ups or other functions are necessary for a control system to be acceptable. We 

stress that the transmission provider should identify such circumstances based on relevant 

technical details, reliability requirements, and good utility practice, and that it should 

make such determinations in a manner that is not unduly discriminatory or preferential. 

e. Process for Changing an Interconnection Request

i. Comments

401. As discussed further below, in the pro forma LGIP, interconnection customers are 

allowed to reduce the level of their generating facility capacity at two points: prior to the 

system impact study and prior to the facilities study. Commenters suggest that the 

Commission should consider provisions to allow customers to also request reduced 

interconnection service at varying points through the interconnection process, though 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 232 -

they do not necessarily agree on the details. For example, AWEA and EEI argue that, if 

an interconnection customer wishes to change service levels at a later time, the 

interconnection customer should be required to submit an additional interconnection 

request for the new level of service unless the new level of service was previously 

studied.703 

402. Similarly, Idaho Power, Portland, and Southern assert that, if the customer has a 

future request to operate at a higher MW level, a new system impact study should be 

required.704 Southern further states that an interconnection customer’s request to modify 

the interconnection service amount to less than the generating facility capacity should 

constitute a material modification to its interconnection request.705 In a related vein, 

NEPOOL states that some of its participants want flexibility for the interconnection 

customer. They request that the customer be able to base necessary upgrades on either a 

smaller generating facility that has been approved as non-material or based on an 

agreement to limit the generating facility output below the originally requested service. 

They argue that the customer should be able to do this once studies have started or after 

studies are completed and the transmission provider has provided estimates regarding 

 703 AWEA 2017 Comments at 54-55; EEI 2017 Comments at 54.

704 Idaho Power 2017 Comments at 5; Portland 2017 Comments at 6; Southern 

2017 Comments at 25. 

705 Id. at 25-26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 233 -

upgrade costs, all without losing queue position.706 NEPOOL contends that some 

developers might consider particularly high upgrade costs unacceptable, which could 

result in more queue withdrawals if interconnection customers cannot reduce their 

requested generating facility capacity without losing their queue position.707 NEPOOL 

states that, in some cases even a small reduction in the requested amount of 

interconnection service can significantly reduce interconnection upgrade costs and make 

projects viable.708 NEPOOL requests that the Final Rule clarify when interconnection 

customers can reduce their requested level of interconnection service and provide

guidance on the appropriateness of affording any flexibility to reduce capacity for 

purposes of determining upgrades after interconnection studies have started or are 

complete.709

403. Similarly, Idaho Power argues that the NOPR fails to address a situation where a 

customer agrees to accept a lower level of service to shift network upgrade costs to other 

interconnection customers behind in the queue that may be vying for limited capacity 

(i.e., by delaying operation to the higher capacity until network upgrades have been 

 706 NEPOOL 2017 Comments at 15.

707 Id.

708 Id. at 15-16.

709 Id. at 16.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 234 -

funded by these projects).710 ITC goes further, arguing that, where a generator has 

already executed an LGIA, a request for reduced generating facility capacity could 

undermine the study assumptions for lower-queued projects, and therefore, the 

Commission should permit transmission providers to deny requests for reduced service 

where granting such a request would cause cascading adverse impacts.711 

404. Non-Profit Utility Trade Associations argue that the Commission should allow for 

cost-sharing of upgraded systems funded by subsequent interconnecting customers if the 

generation-limited entity chooses to take advantage of that additional investment by 

subsequently increasing output.712 They state that there could be instances where a 

generation-limited entity may wish to increase its output as a result of subsequent 

interconnection customers that fund network upgrades that increase system capabilities. 

They indicate that, in such instances, the upgrade users, including the generation-limited 

entity, should share the costs to guard against gaming by entities that would attempt to 

“foist upgrade costs upon subsequent interconnecting entities.”713

 710 Idaho Power 2017 Comments at 5.

711 ITC 2017 Comments at 18-19.

712 Non-Profit Utility Trade Associations 2017 Comments at 4, 21-22.

713 Id. at 23.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 235 -

ii. Commission Determination

405. The Commission agrees with those commenters that suggest that interconnection 

customers should be able to request reduced interconnection service after submitting an

interconnection request. However, we do not believe this flexibility can be without limit, 

or it could adversely impact the interconnection process. As will be explained further 

below, interconnection customers already have the right to reduce the generating facility 

capacity at certain points in the interconnection process, even though such reductions 

may impact interconnection requests later in the queue. The provisions that allow an 

interconnection customer to reduce its requested generating facility capacity do not 

currently allow an interconnection customer to reduce its requested level of 

interconnection service at the same points. Therefore, in this Final Rule, we are revising 

the pro forma LGIP to allow an interconnection customer to either request 

interconnection service below generating facility capacity at the outset or reduce its level 

of requested interconnection service at the same two points in the interconnection

process, as set forth below. An interconnection customer may choose to do so if doing so

is, in its business judgment, advantageous and if it is willing to abide by the limitations of 

interconnection service below generating facility capacity. Accordingly, as described 

further below, the Commission revises pro forma LGIP sections 4.4.1 and 4.4.2 to permit 

interconnection customers to reduce their requested level of interconnection service at the 

same points in the interconnection process as they are currently able to reduce their 

generating facility capacity. Specifically, this Final Rule requires that interconnection 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 236 -

customers can submit a request for interconnection service below generating facility 

capacity as its initial interconnection request, or may submit a request to reduce 

interconnection service below generating facility capacity at two points after the 

interconnection process has begun: (1) as a revision of its interconnection request prior 

to when the interconnection customer returns an executed system impact study agreement 

to the transmission provider; and (2) as a revision of its interconnection request prior to 

when the interconnection customer returns an executed facility study agreement to the 

transmission provider. These decision points are based on existing sections 4.4.1 and 

4.4.2 of the pro forma LGIP. 

406. Section 4.4.1 of the pro forma LGIP allows interconnection customers to decrease 

the electrical output of the proposed project by up to 60 percent before the 

interconnection customer returns an executed system impact study agreement to the 

transmission provider.714 Additionally, section 4.4.2 of the pro forma LGIP allows 

customers to decrease the plant size by an additional 15 percent prior to the return of an 

 714 Pro forma LGIP Section 4.4.1. Prior to the return of the executed 

Interconnection System Impact Study Agreement to the Transmission Provider, 

modifications permitted under this Section shall include specifically: (a) a reduction up 

to 60 percent (MW) of electrical output of the proposed project; (b) modifying the 

technical parameters associated with the Large Generating Facility technology or 

the Large Generating Facility step-up transformer impedance characteristics; and 

(c) modifying the interconnection configuration. For plant increases, the incremental 

increase in plant output will go to the end of the queue for the purposes of cost allocation 

and study analysis.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 237 -

executed facility study agreement.715 As originally written, these sections allow 

interconnection customers to reduce the generating facility capacity from that proposed in 

the original interconnection request (i.e., interconnection customers may request to build 

a smaller plant). In other words, as originally written, these sections do not allow for 

reductions in interconnection service (i.e., for interconnection customers to lower 

interconnection service levels without altering the size of the generating facility). 

However, with the appropriate transmission provider-approved control technologies in 

place, we see no reason why interconnection customers should not also have the option of 

reducing the level of interconnection service at these two stages of the interconnection 

process. Therefore, we revise pro forma LGIP sections 4.4.1 and 4.4.2 as follows (with 

new text in italics):

4.4.1. Prior to the return of the executed Interconnection System Impact 

Study Agreement to the Transmission Provider, modifications permitted 

under this Section shall include specifically: (a) a reduction up to 60 

percent (MW) of electrical output of the proposed project, through either 

(1) a decrease in plant size or (2) a decrease in interconnection service 

level (consistent with the process described in Section 3.1) accomplished by 

applying transmission provider-approved injection-limiting equipment; (b) 

modifying the technical parameters associated with the Large Generating 

Facility technology or the Large Generating Facility step-up transformer 

impedance characteristics; and (c) modifying the interconnection 

 715 Pro forma LGIP Section 4.4.2. Prior to the return of the executed 

Interconnection Facility Study Agreement to the Transmission Provider, the 

modifications permitted under this Section shall include specifically: (a) additional 15 

percent decrease in plant size (MW), and (b) Large Generating Facility technical 

parameters associated with modifications to Large Generating Facility technology and 

transformer impedances; provided, however, the incremental costs associated with those 

modifications are the responsibility of the requesting Interconnection Customer.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 238 -

configuration. For plant increases, the incremental increase in plant output 

will go to the end of the queue for the purposes of cost allocation and study 

analysis.

4.4.2. Prior to the return of the executed Interconnection Facility Study 

Agreement to the Transmission Provider, the modifications permitted under 

this Section shall include specifically: (a) additional 15 percent decrease of 

electrical output of the proposed project through either (1) a decrease in 

plant size (MW) or (2) a decrease in interconnection service level 

(consistent with the process described in Section 3.1) accomplished by 

applying transmission provider-approved injection-limiting equipment, and 

(b) Large Generating Facility technical parameters associated with 

modifications to Large Generating Facility technology and transformer 

impedances; provided, however, the incremental costs associated with those 

modifications are the responsibility of the requesting Interconnection 

Customer.

407. We disagree with Southern’s contention that an interconnection customer’s 

request to modify the interconnection service amount to less than the generating facility 

capacity should always constitute a material modification of its interconnection request. 

A request to reduce the interconnection service amount is similar in many respects to a 

request to reduce generating facility capacity. Because the pro forma LGIP already 

permits reductions in generating facility capacity at certain points in the interconnection 

process without triggering material modification provisions, the Commission finds that

requests to reduce the interconnection service amount at those same points within the 

interconnection process should also not trigger material modification provisions. We also 

note that the phrase “additional 15 percent” is meant to allow a total of up to a 75 percent 

reduction (60 percent plus 15 percent) from the original interconnection request.

408. ITC argues that transmission providers should be able to deny requests to reduce 

interconnection service where such a request would adversely affect lower-queued 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 239 -

interconnection requests. Similarly, Idaho Power and Non-Profit Utility Trade 

Associations argue that the Commission has either failed to address the situation where a

request to reduce interconnection service would adversely affect lower-queued 

interconnection requests or that appropriate cost-sharing provisions should apply if a 

below-generating facility capacity interconnection customer later requests an increase in 

interconnection service to take advantage of upgraded systems funded by subsequent 

interconnection requests. We find that no additional LGIP or LGIA revisions are 

necessary to address these scenarios because reductions in interconnection service level 

are similar in their queue-related impacts to reductions in generating facility capacity, 

which the existing pro forma LGIP already permits. 

409. Furthermore, lower-queued interconnection requests have always faced potential 

impacts from the decisions of higher-queued interconnection requests. For example, 

lower-queued interconnection requests are frequently impacted by the withdrawal of 

higher-queued interconnection requests. The impact on lower-queued interconnection 

requests from a withdrawal higher in the queue is similar to what would happen when a 

higher-queued interconnection customer requests a reduction in interconnection service 

level. In both cases, the higher-queued interconnection request could avoid paying for 

some level of network upgrades (if such upgrades are required), and lower-queued 

interconnection requests could be impacted as a result. Furthermore, if an 

interconnection customer limited in output to below generating facility capacity later

seeks an increase in interconnection service, this will be a new interconnection request 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 240 -

with a new position at the end of the interconnection queue, very similar to the situation 

where a higher-queued interconnection request withdraws and later re-enters the queue. 

While we recognize that these two scenarios are not identical in all respects, we 

nevertheless believe that they are similar enough that the normal queue management and 

interconnection processes, including being subject to the full slate of interconnection 

studies and being potentially responsible for the cost of new network upgrades, can 

adequately address the issues raised by commenters.

f. Penalties 

i. Comments

410. Commenters disagree regarding penalties for over-generation. Some argue that no 

additional penalties are necessary. NextEra, NYISO, ESA, and MidAmerican argue that 

existing provisions in the pro forma LGIA are sufficient.716 NextEra explains that in 

CAISO, their combined solar/battery storage project relies solely on the remedies 

provided for in the existing LGIA. According to NextEra, one other LGIA for a project 

in CAISO includes additional language about the ability to curtail, but it does not provide 

for penalties. NextEra notes that MISO has also taken a similar approach. NextEra states 

that PJM has added significant language to its interconnection agreements below full 

generating capacity but notes that this language repeats the pro forma indemnification 

responsibilities. NextEra and ESA also argue that any other financial penalties would be 

 716 NextEra 2017 Comments at 43; NYISO 2017 Comments at 36-37; ESA 2017 

Comments at 13; MidAmerican 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 241 -

punitive and inconsistent with existing and reasonable practices in CAISO, MISO and 

PJM.717

411. NextEra also notes that thermal generation may be able to produce higher levels of 

output under certain conditions and does not have any additional requirements, nor are 

there special requirements for the operation of System Protection Facilities.718 NextEra 

argues that, if the Commission creates any additional penalties, it would need to do so 

equally to all generation under all circumstances to avoid undue discrimination.719 

412. Xcel states that, although penalties may sometimes be appropriate, if the system 

can reliably accept the energy, over-generation may sometimes be beneficial or may not 

be a significant reliability or free rider issue.720 

413. Some commenters see the value of additional penalties. For instance, Bonneville, 

ITC, TDU Systems, Six Cities, SoCal Edison, Xcel, Portland, and Duke support both 

financial and non-financial penalties, including curtailment, if an interconnection 

customer exceeds its service limit to maintain reliability.721 MISO TOs support 

 717 NextEra 2017 Comments at 43; ESA 2017 Comments at 13.

718 NextEra 2017 Comments at 45.

719 Id.

720 Xcel 2017 Comments at 17-18.

721 Bonneville 2017 Comments at 7; ITC 2017 Comments at 18; Duke 2017 

Comments at 18; TDU Systems 2017 Comments at 27-28; Six Cities 2017 Comments 

at 5; SoCal Edison 2017 Comments at 6; Xcel 2017 Comment at 17; Portland 2017 

Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 242 -

imposition of penalties for exceeding authorized levels of service but defer to RTOs/ISOs 

to develop the specifics of such penalties.722

414. Six Cities observes that a requirement to pay incremental network upgrade costs 

may be most appropriate in circumstances where an interconnection customer has 

consistently exceeded its specified level of interconnection service over some period of 

time, while a monetary penalty may be most appropriate to address isolated exceedances. 

Six Cities argues that RTOs/ISOs are in the best position to develop appropriate penalty 

proposals for application in their respective regions.723

415. SoCal Edison requests that the Commission clarify that penalties apply to 

interconnection customers whose agreed-upon interconnection service level is for the full 

generating facility capacity, not just those whose agreed-upon interconnection service 

levels are below the full generating facility capacity.724 SoCal Edison suggests that 

penalties should range from temporary disruption of service to permanent termination of 

service.725 

 722 MISO TOs 2017 Comments at 36.

723 Six Cities 2017 Comments at 5.

724 SoCal Edison 2017 Comments at 6.

725 Id. at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 243 -

ii. Commission Determination

416. With respect to penalties, based on the record here, we find that current provisions 

in the pro forma LGIA, which allow a transmission provider to curtail service or 

terminate an LGIA, are sufficient to ensure proper behavior by interconnection 

customers. As noted by NextEra, thermal generation may be able to produce higher 

levels of output than the interconnection service level under certain conditions, such as 

lower than benchmark ambient air temperature, and does not face any additional penalty 

requirements beyond curtailment of service or termination of its LGIA for breach if a

party defaults and fails to cure that default.726 The Commission agrees that this is an 

analogous situation to interconnection below generating facility capacity, and therefore 

the same treatment with respect to penalties should apply. Furthermore, as NextEra also 

notes, there are no special penalty requirements beyond these for the operation of system 

protection facilities. As discussed earlier, this Final Rule finds that the control 

technologies at issue are system protection facilities. Based on these facts, we decline to 

generically adopt into the pro forma LGIP any additional financial penalties for 

exceeding the limitations for interconnection service established in the interconnection 

agreements. However, if a transmission provider can justify a need for additional 

penalties, it may propose such penalties in a section 205 filing. 

 726 NextEra 2017 Comments at 45.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 244 -

417. As mentioned above, article 17 of the pro forma LGIA provides a process for 

termination of an LGIA if a party defaults727 on its obligations and fails to cure such 

defaults. Given the potential reliability and operational ramifications, failure to adhere to 

the injection limits included in a below-generating facility capacity LGIA could rise to 

the level of default, and termination of the LGIA would be a serious consequence for an 

interconnection customer, as the resulting disconnection and idling of the generating 

facility could cause significant economic losses. Furthermore, existing article 9.7.2 of the 

LGIA allows the transmission provider to reduce deliveries from (i.e., curtail) an 

interconnection customer if required by good utility practice. Because of these existing 

provisions, and the fact that no other consequences currently apply in the analogous 

situations described above, we see no need to devise new penalties at this time. 

g. Changes to the Definitions of Large and Small Generating 

Facilities

i. Comments

418. TDU Systems conditionally support the Commission’s proposal to change the 

definitions of Large Generating Facility and Small Generating Facility in the pro forma

LGIP and pro forma LGIA to base them on the level of interconnection service actually 

provided, rather than on the generating facility’s capacity, subject to the transmission 

provider being able to study the full generating facility capacity if it believes there is a 

 727 The pro forma LGIA defines default as “the failure of a Breaching Party to cure 

its Breach in accordance with Article 17.” Pro forma LGIA Art. 1 (Definitions). A 

breach is “the failure of a Party to perform or observe any material condition” of the 

pro forma LGIA. Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 245 -

need to do so at the cost of the interconnection customer.728 However, TDU Systems 

urge the Commission to ensure that the interconnection customer (or potential 

interconnection customer) knows what upgrade costs it may incur if seeks to use the 

generating facility’s full capacity.729 

419. Similarly, IECA argues that industrial combined heat and power and waste heat 

recovery facilities with net generating capacities in excess of 20 MW can export far less 

total electricity to the grid than a wind or solar facility with similar or less generating 

facility capacity.730 IECA indicates that a generator’s size classification should be based 

on the maximum amount of power that could be exported to the grid under normal 

manufacturing operations at the combined heat and power and waste heat recovery 

facility location, rather than being based on net generation.731

420. On the other hand, Portland opposes the proposal to redefine the term generating 

facility based on the level of interconnection service. Instead, Portland argues that 

generating facility definitions should be based on nameplate capacity.732 TVA thinks that 

the Commission should define generating facility capacity more specifically, particularly 

 728 TDU Systems 2017 Comments at 27.

729 Id.

730 IECA 2017 Comments at 3.

731 Id. at 3-4.

732 Portland 2017 Comments at 7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 246 -

with regard to certain parameters such as what power factor is measured and whether it is 

gross or net of station service load.733 It also notes that many transmission owners and 

providers have MW thresholds that trigger more robust interconnection facility 

requirements, and states that interconnection for less than the full generator output should 

not be allowed to circumvent these thresholds.734

421. Six Cities states it is not sure what the Commission means by the statement that 

these definition changes “are not intended to conflict with any applicable [NERC] 

Reliability Standards or NERC’s compliance registration process.”735 Six Cities seeks 

clarity as to whether the current NERC compliance registration criteria for generating 

facilities will continue to be based on nameplate ratings irrespective of the requested 

level of interconnection service, or if the Commission intends for the registration criteria 

to be revised based upon the level of interconnection service that is requested and 

implemented.736

ii. Commission Determination

422. Upon consideration of the comments, we withdraw the NOPR proposal to change 

the definitions of large and small generating facilities so that they are based on the level 

 733 TVA 2017 Comments at 15.

734 Id. at 15-16.

735 Six City 2017 Comments at 7 (citing NOPR, FERC Stats. & Regs. ¶ 32,719 

at P 180).

736 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 247 -

of interconnection service for the generating facility rather than the generating facility 

capacity.737 Our particular concern is the possibility of unintended and unforeseen 

consequences with respect to the interconnection study process and NERC compliance 

registration process. 

423. As we have withdrawn this proposal, there is no need to address comments on the 

proposal or to address IECA’s argument that a transmission provider should base a 

combined heat and power and waste heat recovery facility’s size classification on the 

maximum amount of power that could be exported to the grid under normal 

manufacturing operations. 

2. Provisional Interconnection Service

a. NOPR Proposal

424. The Commission proposed to allow interconnection customers to enter into 

provisional agreements for limited interconnection service prior to the completion of the 

full interconnection process. Under this proposal, interconnection customers with 

provisional agreements would be able to begin operation up to the MW level permitted 

by a previously conducted, readily available interconnection study (available study), 

additional studies as necessary, and regularly updated studies. In the NOPR, the 

Commission noted that the transmission provider may require milestone payments prior 

 737 As a result of the withdrawal of this proposal, the determination of whether a 

generator is large or small, including for purposes of whether it qualifies for the LGIP or 

SGIP, will continue to be based on the generating facility capacity.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 248 -

to submission of the provisional agreement. The provisional agreement would be in 

effect while awaiting the final results of the interconnection studies, the execution of a 

LGIA, and the construction of any additional interconnection facilities and/or network 

upgrades that may result from the full interconnection process. The Commission also 

proposed that provisional large generator interconnection agreements and the associated 

provisional interconnection service would terminate upon completion of construction of 

network upgrades required for the interconnection customer’s full level of service.738

425. The Commission proposed that interconnection customers with provisional 

agreements must still assume all risk and liabilities associated with the required 

interconnection facilities and network upgrades for their interconnection that are 

identified pursuant to the full set of interconnection studies for the requested 

interconnection service.739

426. The Commission therefore proposed to require that transmission providers allow 

interconnection customers to request provisional interconnection service and operate 

under provisional interconnection agreements based on available or additional studies as 

necessary and regularly updated studies that demonstrate that necessary interconnection 

facilities and network upgrades are in place to meet applicable NERC or other regional 

reliability requirements for new, modified, and/or expanded generating facilities. If 

 738 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 186.

739 Id. P 187.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 249 -

available studies do not demonstrate whether the transmission provider can reliably 

accommodate provisional interconnection service, the transmission provider would 

perform additional studies as necessary. An evaluation of provisional service by the 

transmission provider would determine whether stability, short circuit, and/or voltage 

issues would arise if the interconnection customer seeking provisional interconnection 

service interconnects without modifications to the generating facility or the transmission

provider’s system. The Commission also proposed that transmission providers must 

assess any safety or reliability concerns posed by provisional agreements, and establish a 

process for the interconnection customer to mitigate any reliability risks associated with 

operation pursuant to provisional agreements.740 

427. The Commission sought additional comment on the proposal and the means by 

which transmission providers and interconnection customers could mitigate any risks 

and/or liabilities for provisional interconnection service. The Commission, 

acknowledging that transmission providers have limited resources to conduct studies, 

also sought comment on the circumstances under which provisional interconnection 

service would be beneficial and how common such circumstances would be for potential 

interconnection customers.741

 740 Id. P 188.

741 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 250 -

428. The Commission proposed to add the following new definitions to Section 1 of the 

pro forma LGIP, and to article 1 of the pro forma LGIA (with proposed additions in 

italics):

Provisional Interconnection Service shall mean interconnection service 

provided by the Transmission Provider associated with interconnecting the 

Interconnection Customer’s Generating Facility to the Transmission 

Provider’s Transmission System and enabling that Transmission System to 

receive electric energy and capacity from the Generating Facility at the 

Point of Interconnection, pursuant to the terms of the Provisional Large 

Generator Interconnection Agreement and, if applicable, the Tariff.742

Provisional Large Generator Interconnection Agreement shall mean the 

interconnection agreement for Provisional Interconnection Service 

established between the Transmission Provider and/or the Transmission 

Owner and the Interconnection Customer. This agreement shall take the 

form of the Large Generator Interconnection Agreement, modified for 

provisional purposes.743

429. Additionally, the Commission proposed a new article 5.10 for the pro forma LGIA 

that defines the requirements for transmission providers to provide provisional 

interconnection service and the responsibilities of the interconnection customer. The 

Commission did not propose a pro forma Provisional Large Generator Interconnection 

Agreement, reasoning that parties could develop such agreements on an ad hoc basis or 

transmission providers could establish their own pro forma agreements. Nonetheless, the 

Commission sought comment on the need to establish a pro forma Provisional Large 

 742 In this Final Rule, the adopted language differs slightly from the NOPR 

language because we remove the word “the” before “Transmission Provider.”

743 Id. P 189. In this Final Rule, the adopted language differs slightly from the 

NOPR language because we remove the word “the” before “Transmission Provider.”

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 251 -

Generator Interconnection Agreement as well as any details related to interconnection 

service. The proposed new article 5.10 to the pro forma LGIA reads as follows (with 

proposed text in italics):

5.10 Provisional Interconnection Service. 

Upon the request of Interconnection Customer, and prior to completion of 

requisite Network Upgrades, the Transmission Provider may execute a 

Provisional Large Generator Interconnection Agreement or 

Interconnection Customer may request the filing of an unexecuted 

Provisional Large Generator Interconnection Agreement with the 

Interconnection Customer for limited interconnection service at the 

discretion of Transmission Provider based upon an evaluation that will 

consider the results of available studies. Transmission Provider shall 

determine, through available studies or additional studies as necessary, 

whether stability, short circuit, thermal, and/or voltage issues would arise 

if Interconnection Customer interconnects without modifications to the 

Generating Facility or Transmission Provider’s system. Transmission 

Provider shall determine whether any Network Upgrades, Interconnection 

Facilities, Distribution Upgrades, or System Protection Facilities that are 

necessary to meet the requirements of NERC, or any applicable Regional 

Entity for the interconnection of a new, modified and/or expanded 

Generating Facility are in place prior to the commencement of 

interconnection service from the Generating Facility. Where available 

studies indicate that such Network Upgrades, Interconnection Facilities, 

Distribution Upgrades, and/or System Protection Facilities that are 

required for the interconnection of a new, modified and/or expanded 

Generating Facility are not currently in place, Transmission Provider will 

perform a study, at the Interconnection Customer’s expense, to confirm the 

facilities that are required for provisional interconnection service. The 

maximum permissible output of the Generating Facility in the Provisional 

Large Generator Interconnection Agreement shall be studied and updated 

on a quarterly basis. Interconnection Customer assumes all risk and 

liabilities with respect to changes between the Provisional Large Generator 

Interconnection Agreement and the Large Generator Interconnection 

Agreement, including changes in output limits and Network Upgrades, 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 252 -

Interconnection Facilities, Distribution Upgrades, and/or System 

Protection Facilities cost responsibilities.744

b. General

i. Comments

430. Most responsive commenters either support the proposal745 or do not oppose it.746 

ISO-NE, Tri-State, and TVA oppose the proposal.747 NEPOOL takes no position, but 

states that it would oppose the proposal if it raises system reliability concerns, introduces 

interconnection study delays, or degrades ISO-NE’s interconnection/forward capacity 

market processes.748 

431. Alevo, ITC, MISO TOs, NextEra, and Six Cities agree that the interconnection 

customers should assume all associated risks and liabilities with regard to provisional 

 744 Id. P 190.

745 AES 2017 Comments at 11; Alevo 2017 Comments at 9; AFPA 2017 

Comments at 15; AWEA 2017 Comments at 56; Bonneville 2017 Comments at 8; 

California Energy Storage Alliance 2017 Comments at 13; Duke 2017 Comments at 20; 

Forecasting Coalition 2017 Comments at 4; EDP 2017 Comments at 8; ELCON 2017 

Comments at 7; ESA 2017 Comments at 15; Idaho Power 2017 Comments at 6; IECA 

2017 Comments at 3; ITC 2017 Comments at 19; Joint Renewable Parties 2017 

Comments at 12; MidAmerican 2017 Comments at 18-19; NextEra 2017 Comments at 

46; Public Interest Organizations 2017 Comments at 6; TDU Systems 2017 Comments 

at 28-29; Xcel 2017 Comments at 18. 

746 Non-Profit Utility Trade Associations 2017 Comments at 24; NYISO 2017 

Comments at 37; PJM 2017 Comments at 25. 

747 ISO-NE 2017 Comments at 43-44; Tri-State 2017 Comments at 9; TVA 2017 

Comments at 16.

748 NEPOOL 2017 Comments at 16-17.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 253 -

interconnection service.749 Alevo asks for clarification on whether a provisional 

interconnection can become permanent at the provisional MW level.750

432. As noted in the NOPR, certain regions already include some form of provisional 

interconnection service.751 Bonneville states that it already allows limited facility 

operation using existing interconnection capacity prior to the completion of upgrades 

needed for the full interconnection request.752 MISO states that its GIP includes a process 

for obtaining a provisional GIA that is subject to study and the maximum permissible 

output of the facility is updated on a quarterly basis. MISO notes that the provisional 

GIA is replaced by a “permanent” GIA upon the completion of the interconnection 

customer’s assigned network upgrades.753 NYISO states that it already provides 

provisional interconnection service under the limited operation provision of NYISO’s 

LGIA.754 However, Indicated NYTOs state that the Commission must ensure that any 

 749 Alevo 2017 Comments at 9; ITC 2017 Comments at 19; MISO TOs 2017 

Comments at 37-38; NextEra 2017 Comments at 46; PJM 2017 Comments at 25-26; and 

Six Cities 2017 Comments at 6.

750 Alevo 2017 Comments at 9.

751 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 183.

752 Bonneville 2017 Comments at 8.

753 MISO 2017 Comments at 34-35.

754 NYISO 2017 Comments at 37.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 254 -

Final Rule to accommodate provisional interconnection service does not diminish the 

superior interconnection standards in regions like NYISO.755

433. CAISO provides different avenues for “provisional” interconnection service.756 

However, CAISO requests clarification regarding the NOPR statement that “in some 

cases, there is a certain amount of interconnection capacity that has already been 

studied.”757 It argues that the only interconnection capacity that it has studied is already 

in use or planned to be in use soon. CAISO supports the proposal to the extent that the 

NOPR is consistent with this understanding.758 PG&E states that interconnection 

customers are able to obtain limited interconnection service prior to the completion of the 

full interconnection process in some circumstances, and CAISO conducts a limited 

operation study six months ahead of a project’s in-service date and allows phased 

projects and energy-only projects to interconnect before certain upgrades or studies are 

completed.759

 755 Indicated NYTOs 2017 Comments at 9.

756 CAISO 2017 Comments at 28.

757 Id. (citing NOPR, FERC Stats. & Regs. ¶ 32,719 at P 181).

758 Id.

759 PG&E 2017 Comments at 8.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 255 -

434. SoCal Edison supports the existing CAISO process but argues that the NOPR

proposal may unintentionally degrade safety and reliability.760 SoCal Edison states that, 

while interconnection capacity may be temporarily available due to construction delay, 

there is no assurance that short-circuit duty levels will be within allowable limits or that 

overall system performance would meet all NERC reliability criteria.761

435. Eversource states that transmission providers should have discretion to determine 

whether there is capacity available to accommodate provisional interconnection 

service.762 It also states that any provisional process should be tailored, adapted to, and 

consistent with each region’s existing interconnection and market rules.763

436. EEI states that an interconnection customer should only be able to use provisional 

interconnection service when: (1) studies indicate that there is a level of interconnection 

that can occur without any additional upgrades and the interconnection customer wishes 

to make use of that level of interconnection while the upgrades required for its full 

interconnection request are completed; and (2) where a previously completed study 

indicates there is a level of interconnection that can occur without any additional 

 760 SoCal Edison 2017 Comments at 8.

761 Id.

762 Eversource 2017 Comments at 16.

763 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 256 -

upgrades while such study is updated.764 Southern agrees that all provisional service 

should be limited to the amount of service that can be provided until all required network 

upgrades identified by interconnection studies are in service.765

437. ISO-NE opposes the establishment of provisional interconnection service, arguing 

that it would unnecessarily increase uncertainty and create difficult obligations for system 

operators.766 ISO-NE further argues that the proposal would allow an interconnection 

customer requesting provisional interconnection service to jump ahead of a higherqueued interconnection request and would require the transmission provider to conduct 

studies for the provisional interconnection request before completing a higher-queued 

project’s studies.767 It states that, if the proposal is adopted, the Commission should 

provide regional flexibility for ISO-NE to deviate from the Final Rule.768

ii. Commission Determination

438. In this Final Rule, we adopt the NOPR proposal to define Provisional 

Interconnection Service and Provisional Large Generator Interconnection Agreement in

section 1 of the pro forma LGIP and article 1 of the pro forma LGIA; and add article

 764 EEI 2017 Comments at 57.

765 Southern 2017 Comments at 26.

766 ISO-NE 2017 Comments at 43-44.

767 Id. at 45-46.

768 Id. at 47.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 257 -

5.9.2769 to the pro forma LGIA, as modified below. We require transmission providers to 

make the changes to their LGIPs and LGIAs so that all interconnection customers may 

request provisional interconnection service, but we modify the proposed pro forma LGIA

provisions to allow transmission providers to determine the frequency for updating 

provisional interconnection studies, and to clarify the cost responsibilities of the 

interconnection customer. 

439. In response to Alevo’s question regarding whether provisional interconnection 

service could become permanent, we clarify that provisional interconnection service 

could not become permanent because it is only available to interconnection customers 

awaiting the completion of the full interconnection process and will terminate upon 

completion of construction of interconnection facilities and network upgrades.

440. In response to CAISO, we clarify that “a certain amount of capacity already 

studied”770 refers to situations where, for example, available studies or additional studies 

as necessary indicate that there is a certain amount of interconnection service available 

without the need for additional network upgrades and the transmission provider can 

reliably accommodate the interconnection service. In such cases, an interconnection 

 769 To avoid extensive renumbering of the article 5 of the pro forma LGIA, the 

Commission is re-titling article 5.9 “Other Interconnection Options.” Existing article 5.9 

Limited Operation will now be article “5.9.1 Limited Operation,” and the newly adopted 

Provisional Interconnection Service provision will be article 5.9.2 instead of 5.10. 

770 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 181.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 258 -

customer may use the identified interconnection service while it awaits the completion of 

the full interconnection process. 

441. In response to requests for clarification of the conditions for requesting provisional 

interconnection service, we clarify that interconnection customers may seek provisional 

interconnection service when available studies or additional studies as necessary indicate 

that there is a level of interconnection that can occur without any additional 

interconnection facilities and/or network upgrades and the interconnection customer 

wishes to make use of that level of interconnection service while the facilities required 

for its full interconnection request are completed.

442. In response to ISO-NE’s objection that the provisional interconnection service 

proposal could cause lower-queued projects to “leapfrog” higher-queued interconnection 

customers, we acknowledge that there may be instances when a lower-queued project 

may interconnect and receive provisional interconnection service before a higher-queued 

project completes the full interconnection process. It is possible that the resources 

needed to complete the transmission provider’s interconnection studies may be required 

to perform provisional studies for a lower-queued interconnection customer. But, a 

higher-queued interconnection customer should have the opportunity to request 

provisional service prior to a lower-queued interconnection customer. The availability of 

this service would not unduly disadvantage higher-queued interconnection customers, 

which would have the first chance to use any available provisional service, but may have 

been unable or uninterested in doing so. In addition, the availability of provisional 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 259 -

service should not advantage lower-queued interconnection customers in the processing 

of their full interconnection service request. We emphasize that provisional 

interconnection service may not provide an interconnection customer its full requested 

level of interconnection service. We further note that any interconnection customer, 

regardless of queue position, may request provisional interconnection service.

c. Pro Forma Provisional Interconnection Agreement

i. Comments

443. Duke, Xcel, and Southern see no need for the Commission to develop a pro forma 

provisional interconnection service agreement at this time.771 MISO agrees because its 

GIP includes a process for obtaining a provisional GIA and because MISO already 

conducts quarterly provisional interconnection service studies.772 NYISO states that a 

separate provisional interconnection agreement would unnecessarily complicate and 

prolong the interconnection agreement negotiations.773 PJM opposes the creation of a 

separate provisional interconnection agreement because PJM’s current interconnection 

agreement already provides for the service.774 

 771 Duke 2017 Comments at 21; Xcel 2017 Comment at 18; Southern 2017 

Comments at 26.

772 MISO 2017 Comments at 34-35.

773 NYISO 2017 Comments at 38.

774 PJM 2017 Comments at 26.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 260 -

ii. Commission Determination

444. In this Final Rule, we agree with commenters and decline to adopt a separate 

pro forma Provisional Large Generator Interconnection Agreement. 

d. Additional Studies

i. Comments

445. EEI argues that a transmission provider should not have to perform additional 

studies to offer provisional interconnection service and should not have to perform 

periodic studies to update the level of maximum permissible provisional interconnection 

service.775 Southern agrees and also argues that transmission providers should have 

discretion over granting provisional interconnection service based on standard 

interconnection studies or any other applicable and valid studies.776

446. Duke and NYISO oppose the requirement to conduct quarterly restudies.777

Instead, NYISO proposes to define a timeframe for which provisional service will be 

provided, and study the proposed project to determine the permissible output level of the 

project over the entire defined provisional timeframe. NYISO further proposes to retain 

the discretion to update its analysis as necessary based on system changes.778 

 775 EEI 2017 Comments at 58.

776 Southern 2017 Comments at 26.

777 Duke 2017 Comments at 21; NYISO 2017 Comments at 38.

778 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 261 -

447. Eversource argues that additional studies could turn the interconnection process 

into a protracted iterative design process while the interconnection customer determines 

its cheapest option for network upgrades.779 Six Cities also has concerns that additional 

studies may prolong the interconnection process.780 Tri-State and TVA argue that the 

proposal burdens transmission providers because it requires regularly-updated or 

additional studies,781 or imposes distracting monitoring and/or mitigation burdens.782

ii. Commission Determination

448. In this Final Rule, we modify the NOPR proposal and article 5.9.2 of the pro 

forma LGIA, Provisional Interconnection Service, to allow transmission providers to 

determine the frequency for updating provisional interconnection studies. This flexibility 

will allow transmission providers to determine a study frequency that best suits their 

individual needs. However, the determined frequency should be consistent across all 

interconnection customers seeking provisional interconnection service. In addition, we 

modify the NOPR proposal, and add article 5.9.2 of the pro forma LGIA, to clarify that 

any study performed by the transmission provider to update the available maximum 

provisional interconnection service will be at the expense of the interconnection 

 779 Eversource 2017 Comments at 17.

780 Six Cities 2017 Comments at 6.

781 Tri-State 2017 Comments at 9.

782 TVA 2017 Comments at 16.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 262 -

customer. To effectuate this change, we renumber existing article 5.9 as follows 

(deleting bracketed text and adding the italicized text):

5.9 [Limited Operation] Other Interconnection Options

5.9.1 Limited Operation

* * * * *

449. We also revise article 5.9.2 of the LGIA from the version proposed in the NOPR

as follows (deleting bracketed, un-italicized text and adding the italicized text):

5.9.[1]2[0] Provisional Interconnection Service. 

Upon the request of Interconnection Customer, and prior to completion of 

requisite Interconnection Facilities, Network Upgrades, Distribution 

Upgrades, or System Protection Facilities [the ]Transmission Provider may 

execute a Provisional Large Generator Interconnection Agreement or 

Interconnection Customer may request the filing of an unexecuted 

Provisional Large Generator Interconnection Agreement with the 

Interconnection Customer for limited interconnection service at the 

discretion of Transmission Provider based upon an evaluation that will 

consider the results of available studies. Transmission Provider shall 

determine, through available studies or additional studies as necessary, 

whether stability, short circuit, thermal, and/or voltage issues would arise if 

Interconnection Customer interconnects without modifications to the 

Generating Facility or Transmission Provider’s system. Transmission 

Provider shall determine whether any [Network Upgrades,] Interconnection 

Facilities, Network Upgrades, Distribution Upgrades, or System Protection 

Facilities that are necessary to meet the requirements of NERC, or any 

applicable Regional Entity for the interconnection of a new, modified 

and/or expanded Generating Facility are in place prior to the 

commencement of interconnection service from the Generating Facility. 

Where available studies indicate that such [Network Upgrades,]

Interconnection Facilities, Network Upgrades, Distribution Upgrades, 

and/or System Protection Facilities that are required for the interconnection 

of a new, modified and/or expanded Generating Facility are not currently in 

place, Transmission Provider will perform a study, at the Interconnection 

Customer’s expense, to confirm the facilities that are required for 

Provisional Interconnection Service. The maximum permissible output of 

the Generating Facility in the Provisional Large Generator Interconnection 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 263 -

Agreement shall be studied and updated [on a frequency determined by 

Transmission Provider and at the Interconnection Customer’s expense.]

[on a quarterly basis]. Interconnection Customer assumes all risk and 

liabilities with respect to changes between the Provisional Large Generator 

Interconnection Agreement and the Large Generator Interconnection 

Agreement, including changes in output limits and [Network Upgrades,]

Interconnection Facilities, Network Upgrades, Distribution Upgrades, 

and/or System Protection Facilities cost responsibilities.783

450. In response to Tri-State’s and TVA’s concern about the additional burden 

associated with providing provisional interconnection service, and Eversource’s and Six 

Cities’ concern that provisional interconnection service will prolong the interconnection 

process, we acknowledge that providing provisional interconnection service may require 

additional studies, which could prolong the interconnection process for some 

interconnection customers. However, because provisional interconnection service is

partly based on the results of available studies, and the studies to confirm that provisional 

service continues to be available are less intensive than full interconnection studies, 

interconnection customers in the queue that do not select provisional interconnection 

service should not experience additional significant delay. In the regions where 

provisional interconnection service is currently available, the Commission is unaware of 

any delays to the interconnection process due to transmission provider processing of 

provisional studies. Furthermore, as stated above, we recognize the individual needs of 

the transmission providers, and the modification from the NOPR proposal to allow 

transmission providers the flexibility to determine the frequency to study and update the 

 783 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 190.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 264 -

maximum permissible output of the generating facility should further minimize delays 

and lessen any burden.

e. Other

i. Comments

451. Imperial and Modesto ask the Commission to clarify how the provisional service 

would be subject to section 3.5 of the pro forma LGIP, which provides for coordination 

of any study required to determine the interconnection request’s impact on affected 

systems, and how the transmission provider would conduct the studies for provisional 

interconnection service in conjunction with affected systems.784

ii. Commission Determination

452. In response to concerns about negative effects to other systems or system

reliability, we emphasize that available studies or additional studies as necessary

performed by transmission providers at the interconnection customer’s expense, should 

identify any associated negative effects on system reliability. We also reiterate that 

Commission staff convened a technical conference in Docket No. AD18-8-000 to explore 

issues related to the coordination of affected systems raised in this proceeding and from a 

complaint filed in Docket No. EL18-26-000. Thus, while the Commission is not taking 

action on affected systems issues in this rulemaking, the Commission is considering these 

kinds of issues. As a reminder, the Notice Inviting Post-Technical Conference 

 784 Imperial 2017 Comments at 13; Modesto 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 265 -

Comments in Docket No. AD18-8-000, which issued concurrently with this Final Rule, 

states that initial and reply comments are due within 30 days and 45 days, respectively, 

from the date of the notice’s issuance. 

3. Utilization of Surplus Interconnection Service

a. NOPR Proposal

453. In the NOPR, the Commission proposed to add a new definition for Surplus 

Interconnection Service to section 1 of the pro forma LGIP and to article 1 of the pro 

forma LGIA, and a requirement that transmission providers provide an expedited process 

for interconnection customers to utilize or transfer surplus interconnection service at 

existing generating facilities.785 The intent of this proposal was to allow another 

interconnecting resource owned by an existing generating facility owner or an affiliated 

owner the ability to use any surplus interconnection service associated with the existing 

generating facility. The Commission also proposed that transmission providers establish

open and transparent processes for generating facilities that wish to transfer that surplus 

interconnection service to others if the generating facility owner and its affiliates elect not 

to use it.786

454. In the NOPR, the Commission pointed to MISO’s Net Zero Interconnection 

Service, which is offered under MISO’s tariff. MISO designed this service “to allow an 

 785 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 201.

786 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 266 -

existing interconnection customer to increase the gross generating capacity at the point of 

interconnection of an existing generating facility without increasing the total 

interconnection service at the point of interconnection.”787 In its order accepting MISO’s 

proposal for Net Zero Interconnection Service, the Commission directed MISO to submit 

a compliance filing to ensure that MISO offered Net Zero Interconnection Service “on a 

fair, transparent, and non-discriminatory basis.”788 

455. To ensure system reliability, the Commission proposed to require reactive power, 

short circuit/fault duty, and stability analyses studies for this service, and that

transmission providers perform steady-state (thermal/voltage) analyses as necessary to 

ensure evaluation of all required reliability conditions.789 The Commission also proposed

that, if the transmission provider does not study surplus interconnection service under 

off-peak conditions, it would perform off-peak steady state analyses to the level 

necessary to demonstrate reliability.790 The Commission further proposed that, if the 

 787 Id. P 193 (citing MISO FERC Electric Tariff, Attachment X, Section 1 

(Definitions) (47.0.0) (“Net Zero Interconnection Service shall mean a form of Energy 

Resource Interconnection Service that allows an interconnection customer to alter the 

characteristics of an existing generating facility, with the consent of the existing 

generating facility, at the same [point of interconnection] such that the Interconnection 

Service limit remains the same”)).

788 Midwest Indep. Transmission Sys. Operator, Inc., 138 FERC ¶ 61,233, at P 302

(2012).

789 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 202.

790 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 267 -

original system impact study is not available while the surplus interconnection service is 

going through the study process, both off-peak and peak analyses may be necessary for 

the existing generating facility associated with the request for surplus interconnection 

service.791 Additionally, the Commission proposed that a process for the use or transfer 

of surplus interconnection service be available for any quantity of surplus interconnection 

service that currently exists.792 

456. The Commission proposed to require that the transmission provider, transmission 

owner (as applicable), and the surplus interconnection service customer execute, or file 

unexecuted, a new agreement for surplus interconnection service. The Commission 

noted that the surplus interconnection customer could be the interconnection customer for 

the existing generating facility, one of its affiliates, or a new interconnection customer 

selected through an open and transparent solicitation process.793 In addition to the new 

interconnection agreement for surplus interconnection service, the Commission

recognized that other contractual arrangements may be necessary.794 

457. While the Commission did not propose specific contractual arrangements with 

respect to surplus interconnection service in the NOPR, the Commission sought comment 

 791 Id.

792 Id.

793 Id. P 203.

794 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 268 -

on how these arrangements should work and on whether requirements for such 

arrangements should be established in the Commission’s pro forma LGIP and pro forma 

LGIA.795 The Commission also sought comment on whether the interconnection 

agreement for surplus interconnection service should terminate upon the retirement of the 

existing generating facility, or whether there are circumstances under which the surplus 

interconnection service customer may operate its generating facility under the terms of 

the surplus interconnection service agreement after the retirement of the existing 

generating facility.796 

458. Under the NOPR proposal, an existing generating facility owner or its affiliate 

would have priority to use any surplus interconnection service and would be able to 

execute or request the filing of an unexecuted surplus interconnection service agreement 

without posting that service to OASIS or going through an open solicitation process.797 

However, if an existing generating facility owner that has surplus interconnection service 

wished to transfer it but did not wish to use the surplus interconnection service itself or to 

transfer it to one of its affiliates, the existing generator would conduct an open and 

transparent solicitation process for that surplus interconnection service.798 While the 

 795 Id. P 204.

796 Id.

797 Id. P 206.

798 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 269 -

Commission proposed that priority be given to the existing generating facility owner of 

the surplus interconnection service or its affiliates, the Commission sought comment on 

the need for further limitations on the entities with priority use of that surplus 

interconnection service.799

459. With regard to specific requirements, the Commission proposed to add the 

following new definition to section 1 of the pro forma LGIP and to article 1 of the pro 

forma LGIA (with proposed text in italics): 

Surplus Interconnection Service shall mean any unused portion of 

Interconnection Service established in a Large Generator Interconnection 

Agreement, such that if Surplus Interconnection Service is utilized the 

Interconnection Service limit at the Point of Interconnection would remain 

the same.800

460. The Commission proposed to add a new section 3.3 to the pro forma LGIP that 

requires the transmission provider to establish a process for the use of surplus 

interconnection service as follows (with proposed text in italics): 

Utilization of Surplus Interconnection Service. The Transmission 

Provider must provide a process that allows an Interconnection Customer 

to utilize or transfer Surplus Interconnection Service at an existing 

Generating Facility. The original Interconnection Customer or one of its 

affiliates shall have priority to utilize Surplus Interconnection Service. If 

the existing Interconnection Customer or one of its affiliates does not 

 799 Id.

800 Id. P 208. With respect to these new additions to the pro forma LGIP and pro 

forma LGIA, we make minor clarifying edits to the pro forma tariff language originally 

proposed in the NOPR, as shown in Appendices B and C. Specifically, the term 

“unused” is replaced with the term “unneeded,” and the term “Interconnection Service 

limit” is replaced with “total amount of Interconnection Service.”

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 270 -

exercise its priority, then that service may be made available to other 

potential interconnection customers through an open and transparent 

solicitation process.801

461. The Commission proposed to add a new section 3.3.1 to the pro forma LGIP that 

describes the process for using surplus interconnection service (with proposed text in 

italics):

Surplus Interconnection Service Requests. Surplus Interconnection 

Service requests may be made by the existing Generating Facility or one of 

its affiliates. Surplus Interconnection Service requests also may be made 

by another Interconnection Customer selected through an open and 

transparent solicitation process. The Transmission Provider shall provide 

a process for evaluating interconnection requests for Surplus 

Interconnection Service. Studies for Surplus Interconnection Service shall 

consist of reactive power, short circuit/fault duty, stability analyses, and 

any other appropriate studies. Steady-state (thermal/voltage) analyses may 

be performed as necessary to ensure that all required reliability conditions 

are studied. If the Surplus Interconnection Service was not studied under 

off-peak conditions, off-peak steady state analyses shall be performed to the 

required level necessary to demonstrate reliable operation of the Surplus 

Interconnection Service. If the original System Impact Study is not 

available for the Surplus Interconnection Service, both off-peak and peak 

analysis may need to be performed for the existing Generating Facility 

associated with the request for Surplus Interconnection Service. The 

reactive power, short circuit/fault duty, stability, and steady-state analyses 

for Surplus Interconnection Service will identify any additional 

Interconnection Facilities and/or Network Upgrades necessary.802

 801 Id. P 209. With respect to these new additions to the pro forma LGIP, we make 

minor clarifying edits to the pro forma tariff language originally proposed in the NOPR, 

as shown in Appendix B. Specifically, in the first sentence, the words “Generating 

Facility” are replaced with the words “Point of Interconnection” and in the last sentence, 

the words “through an open and transparent solicitation process” are struck.

802 Id. P 210. With respect to these new additions to the pro forma LGIP, we make 

minor clarifying edits to the pro forma tariff language originally proposed in the NOPR, 

as shown in Appendix B. Specifically, the first sentence is modified as follows (with 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 271 -

462. Finally, the Commission proposed to add a new section 3.3.2 to the pro forma

LGIP that establishes the open and transparent solicitation process for surplus 

interconnection service (with proposed text in italics):

Solicitation Process for Surplus Interconnection Service. If the existing

Generating Facility owner elects to transfer rights for Surplus 

Interconnection Service to an unaffiliated Interconnection Customer, it 

must do so through an open and transparent solicitation process. The 

existing Generating Facility owner must first request that the Transmission 

Provider post on its website that it is willing to accept requests for Surplus 

Interconnection Service at the existing Point of Interconnection. Such 

posting will include the name of the existing Generating Facility, the exact 

electrical location of the physical termination point of the Surplus 

Interconnection Service, including proposed breaker position(s) within its 

substation, the state and county of the existing Generating Facility, and a 

valid email address and phone number to contact the representative of the 

existing Generating Facility. The existing Generating Facility owner must 

provide the Transmission Provider with the System Impact Study performed 

for the existing Generating Facility with its request for posting Surplus 

Interconnection Service or indicate that such study is not available. 

After the existing Generating Facility owner requests that the Transmission 

Provider post the availability of Surplus Interconnection Service, the 

Transmission Provider will also post on its website a description of the 

selection process for transferring rights to the Surplus Interconnection 

Service that will include a timeline and the selection criteria developed by 

the existing Generating Facility owner. The selection process may vary 

among existing Generating Facility owners but the existing Generating 

Facility owner will choose the winning request after all necessary studies 

have been performed by the Transmission Provider. The existing 

Generating Facility owner will submit to the Transmission Provider, for 

 

additions made in italics): “Surplus Interconnection Service requests may be made by the 

existing Interconnection Customer whose Generating Facility is already interconnected 

or one of its affiliates.” Additionally, the second sentence is modified by striking the 

words “selected through an open and transparent solicitation process.” We also remove 

the word “the” before “Transmission Provider.”

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 272 -

posting on the Transmission Provider’s website, the results of the selection 

process and will include a description of whose proposal for the Surplus 

Interconnection Service was selected and why. After an Interconnection 

Customer has been chosen, the new Interconnection Customer will execute, 

or request the filing of an unexecuted, interconnection agreement with the 

Transmission Provider and Transmission Owner (as applicable) upon 

completion of all necessary studies for its new Generating Facility.803

b. General

i. Comments

463. Several commenters support this proposal. ESA supports the proposal and the 

ability to transfer interconnection capacity between parties because it may encourage colocation of storage and generation. It also states that the net-zero model developed by 

MISO, following the Commission’s guidance in that proceeding, does not meet the

objective of encouraging the use of surplus interconnection service and that a separate, 

faster process to transfer surplus is necessary.804 AWEA states that better use of 

interconnection capacity would reduce system costs and improve competition. AWEA

argues that an interconnection customer would benefit from being able to split its GIA 

into multiple GIAs when it is a party to a Power Purchase Agreement that does not 

account for all of the capacity under the customer’s interconnection agreement.805 Xcel 

supports a "net-zero-like" interconnection service and argues that existing interconnection 

 803 Id. P 211.

804 ESA 2017 Comments at 13-14.

805 AWEA 2017 Comments at 58.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 273 -

customers or affiliates should have priority to use any available surplus interconnection 

service.806 Duke supports the proposal if it is like MISO’s net-zero program and suggests 

that MISO’s interconnection agreement is a good model for such transactions.807 FTC 

states that transferred interconnection capacity rights can play a significant role in 

providing transmission capacity for use by generation entrants quickly and at low cost.808 

TDU Systems argue that the transmission provider must give comparable service to nonaffiliates as they do to their own affiliates.809 MISO generally supports the Commission’s 

proposal, as do Alliant, ITC, MidAmerican, MISO TOs, and TDU Systems.810 

464. Several commenters express concerns with some aspects of, but do not completely 

oppose, the Commission’s proposal. For example, EEI states that the concept is 

reasonable but would burden transmission providers and should thus be optional.811 

NYISO opposes simple transfer of capacity from an interconnection customer to another 

party because more than just MW capacity is needed for safe and reliable interconnection 

 806 Xcel 2017 Comments at 19.

807 Duke 2017 Comments at 22.

808 FTC 2017 Comments at 10.

809 TDU Systems 2017 Comments at 19-20.

810 MISO 2017 Comments at 5; Alliant 2017 Comments at 8; ITC 2017 Comments 

at 121; MidAmerican 2017 Comments at 19; MISO TOs 2017 Comments at 40; TDU 

Systems 2017 Comments at 19-20.

811 EEI 2017 Comments at 59.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 274 -

(for example, evaluation of short circuit issues). If the new interconnection customer is 

under 20 MW, NYISO suggests that it might be easier to use the SGIP and SGIA where it 

is easier to waive certain studies.812 PJM does not support the proposed open solicitation 

for transfer of any surplus interconnection service. PJM contends that there are no 

surplus capacity rights on its system because capacity is based on tested output. PJM 

asserts that it would have to create some form of energy rights that could be transferred. 

PJM prefers to continue using the transfer process contained in its tariffs and manuals.813

465. Other commenters, including several RTOs/ISOs, oppose the proposal entirely. 

For example, ISO-NE states that its markets are already managing surplus transfers 

through its process that integrates its forward capacity market with its interconnection 

queue. ISO-NE argues that the Commission proposal would significantly disrupt or 

misalign this process.814 CAISO appeals to the Commission to “not sacrifice reliability 

studies on the altar of convenience.”815 CAISO questions the need for this proposal, 

stating that interconnection customers can already retire/replace, repower, or assign 

available capacity through bilateral transactions, which according to CAISO work better 

 812 NYISO 2017 Comments at 39.

813 PJM 2017 Comments at 27-28.

814 ISO-NE 2017 Comments at 48.

815 CAISO 2017 Comments at 32.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 275 -

than the administrative process in the NOPR.816 SoCal Edison supports the 

Commission’s goal but does not support the NOPR due to the expedited process and 

concerns that the expedited NOPR process: (1) may be inferior to current processes like 

CAISO’s Material Modification Assessment; (2) may encourage interconnection 

customers to request more interconnection service than they intend to use; and (3) should 

not enable a surplus interconnection customer to avoid the installation of necessary 

facilities to enable a safe and reliable interconnection.817 SEIA does not support the 

creation of a process to reassign surplus interconnection capacity.818 NYISO asserts that 

the NOPR may conflict with the principle of open access and might allow for undue 

discrimination by establishing a process that favors affiliates of an existing 

interconnection customer over other interconnection customers.819 AES states that this 

proposal could reduce flexibility to the transmission provider or reliability coordinator, 

and they would prefer that RTOs/ISOs determine for themselves how to address the topic

of transferring surplus capacity.820

 816 Id. at 34.

817 SoCal Edison 2017 Comments at 9-13.

818 SEIA 2017 Comments at 21.

819 NYISO 2017 Comments at 39-40 (citing Midwest Indep. Transmission Sys. 

Operator, Inc., 140 FERC ¶ 61,237, at PP 50-51 (2012), and Midwest Indep. 

Transmission Sys. Operator, Inc., 155 FERC ¶ 61,274, at P 19 (2016)).

820 AES 2017 Comments at 11-12.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 276 -

466. Several commenters state that either there is no surplus on their systems or that it 

is unclear what “surplus” means. For example, CAISO questions how to define surplus 

interconnection capacity and states that it assigns interconnection capacity by the actual 

size of the generator; thus, there is no surplus service in its region.821 Similarly, PJM 

states that it does not permit excess capacity to be obtained through the initial request. 

PJM rates interconnection capacity at the tested output of the generator after 

installation.822 Southern questions whether capacity being “surplus” should refer to its 

lack of use in operation, in the interconnection study, or in the interconnection request.823 

NYISO's LGIA requires interconnection customers to inform NYISO if the built 

generating facility is smaller than what had been proposed, which initiates a process to 

consider amending the interconnection agreement, or requires a new interconnection 

request if the interconnection customer proposes to expand its facility.824 NYISO allows 

interconnection customers to pay for larger network upgrades than required for the initial 

project, as long as they are reasonably related to the interconnection of the proposed 

project.825 According to NYISO, another later interconnection customer can also use 

 821 CAISO 2017 Comments at 31-32.

822 PJM 2017 Comments at 27.

823 Southern 2017 Comments at 28.

824 NYISO 2017 Comments at 40.

825 Id. at 42.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 277 -

these network upgrades, so long as it reimburses the earlier interconnection customer that 

paid for them.826

ii. Commission Determination

467. In this Final Rule, we adopt, with certain modifications and clarifications, the 

NOPR proposals to: (1) add a definition for “Surplus Interconnection Service” to section 

1 of the pro forma LGIP and to article 1 of the pro forma LGIA; (2) add a new section 

3.3 to the pro forma LGIP that requires the transmission provider to establish a process 

for the use of surplus interconnection service; and (3) add a new section 3.3.1 to the pro 

forma LGIP that describes the process for using surplus interconnection service.827 As 

described in more detail below, we will withdraw the NOPR proposal to add a new 

section 3.3.2 to the pro forma LGIP that establishes an open and transparent solicitation 

process for surplus interconnection service. We affirm that requiring transmission 

providers to establish an expedited process, separate from the interconnection queue, for 

the use of surplus interconnection service could reduce costs for interconnection 

customers by increasing the utilization of existing interconnection facilities and network 

upgrades rather than requiring new ones, improve wholesale market competition by 

enabling more entities to compete through the more efficient use of surplus existing

 826 Id.

827 With respect to these new additions to the pro forma LGIP and pro forma 

LGIA, we make minor clarifying edits to the pro forma tariff language originally 

proposed in the NOPR, as shown in Appendix B and C. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 278 -

interconnection capacity, and remove economic barriers to the development of 

complementary technologies such as electric storage resources that may be able to easily 

tailor their use of interconnection service to adhere to the limitations of the surplus 

interconnection service that may exist. Further, we find that facilitating the use of surplus 

interconnection service could improve capabilities at existing generating facilities, 

prevent stranded costs, and improve access to the transmission system. 

468. We clarify that surplus interconnection service is created because generating 

facilities may not operate at full capacity at all times. Consistent with the requirements of 

Order No. 2003, transmission providers assume that each interconnection customer is 

fully utilizing its interconnection service when studying other requests for new 

interconnections. Thus, currently, even if a generating facility only operates a few days a 

year, or routinely operates at a level below its maximum capacity, the remaining, unused 

interconnection service is assumed to be unavailable to other prospective interconnection 

customers.

469. As noted above, Order No. 2003 mandates that transmission providers assume that 

generating facilities operate at their full capacity. To illustrate this, we note that Order 

No. 2003 listed, as separate services, Energy Resource Interconnection Service (ERIS),828

 828 Energy Resource Interconnection Service: 

shall mean an Interconnection Service that allows the Interconnection 

Customer to connect its Generating Facility to the Transmission Provider's 

Transmission System to be eligible to deliver the Generating Facility's 

electric output using the existing firm or nonfirm capacity of the 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 279 -

a “basic or minimum interconnection service,”829 and Network Resource Interconnection 

Service (NRIS),830 a “more flexible and comprehensive service.”831 In Order No. 2003, 

the Commission stated that, for a generating facility with ERIS, “[t]he Interconnection 

Studies to be performed . . . would identify the Interconnection Facilities required as well 

as the Network Upgrades needed to allow the proposed Generating Facility to operate at 

full output” and “the maximum allowed output of the Generating Facility without 

Network Upgrades.”832 

 

Transmission Provider's Transmission System on an as available basis. 

Energy Resource Interconnection Service in and of itself does not convey 

transmission service.

Pro forma LGIP Section 1 (Definitions).

829 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 752.

830 Network Resource Interconnection Service:

shall mean an Interconnection Service that allows the Interconnection 

Customer to integrate its Large Generating Facility with the Transmission 

Provider's Transmission System (1) in a manner comparable to that in 

which the Transmission Provider integrates its generating facilities to serve 

native load customers; or (2) in an RTO or ISO with market based 

congestion management, in the same manner as all other Network 

Resources. Network Resource Interconnection Service in and of itself does 

not convey transmission service. 

Pro forma LGIP Section 1 (Definitions).

831 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 752.

832 Id. P 753 (emphasis added).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 280 -

470. Similarly, Order No. 2003 stated that NRIS “provides for all of the Network 

Upgrades that would be needed to allow the Interconnection Customer to designate its 

Generating Facility as a Network Resource and obtain Network Integration Transmission 

Service” so that for “an Interconnection Customer [that] has obtained Network Resource 

Interconnection Service, any future transmission service request for delivery from the 

Generating Facility would not require additional studies or Network Upgrades.”833 To 

allow for this, “[t]he Transmission Provider would study the Transmission System at 

peak load, under a variety of severely stressed conditions, to determine whether, with the 

Generating Facility at full output, the aggregate of generation in the local area can be 

delivered to the aggregate of load, consistent with the Transmission Provider's reliability 

criteria and procedures” and “would assume that some portion of the capacity of existing 

Network Resources is displaced by the output of the new Generating Facility.”834

471. Thus, to provide interconnection service to an original interconnection customer at 

a particular point of interconnection, the transmission provider must conduct a study that 

assumes that the generating facility will produce at its full output and that the 

interconnection customer will fully utilize the amount of interconnection service

requested. Consequently, it is possible for an original interconnection customer to have

surplus interconnection service at a particular interconnection point because the 

 833 Id.

834 Id. P 755 (emphasis added).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 281 -

generating facility capacity that the transmission provider originally studied pursuant to 

the pro forma LGIP may be in excess of the actual interconnection service required by 

the generating facility, at least during some periods. For these reasons, we find that, 

where proper precautions are taken to ensure system reliability, it would be unjust and 

unreasonable to deny an original interconnection customer the ability either to transfer or

use for another resource surplus interconnection service.

472. As established in this Final Rule and explained further below, surplus 

interconnection service cannot exceed the total interconnection service already provided 

by the original interconnection customer’s LGIA. Furthermore, if the original LGIA is 

for ERIS, any surplus interconnection customer associated with the original LGIA at the 

same point of interconnection would also need to be an ERIS customer in order to avoid 

the potential need for new network upgrades. If the original LGIA is for NRIS, then 

either ERIS or NRIS service could be offered to the surplus interconnection service 

customer. The provisions addressed in this Final Rule will allow an existing 

interconnection customer to make a specified and limited amount of surplus 

interconnection service available at a particular interconnection point under a variety of 

circumstances, including, for example, on a continuous basis (i.e., a certain number of 

MW of surplus interconnection service always available for use by a co-located 

generating facility), or on a scheduled, periodic basis (i.e., a specified number of MW 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 282 -

available intermittently).835 In contrast, an interconnection customer making a new 

interconnection request can request any level of interconnection service at or below its

resource’s generating facility capacity, and ERIS, NRIS, or provisional interconnection 

service. 

473. We note that, to avoid abuse of this reform, which is intended to increase 

utilization of existing, underutilized interconnection service provided at a particular point 

of interconnection, we are restricting surplus interconnection service when new 

interconnection service would be more appropriate. Specifically, surplus interconnection 

service cannot be offered if the original interconnection customer’s generating facility is 

scheduled to retire and permanently cease commercial operation before the surplus 

interconnection service customer’s generating facility begin commercial operation. This 

restriction is consistent with the Commission’s statement in Order No. 2003 that

interconnection service is “associated with interconnecting the Interconnection 

Customer's Generating Facility to the Transmission Provider's Transmission System.”836

474. As this statement demonstrates, the interconnection service provided under an

original interconnection customer’s LGIA is associated with interconnecting that 

interconnection customer’s generating facility. Once that original generating facility 

 835 This would include situations where existing generating facilities operate 

infrequently, such as peaker units, or operate often below their full generating facility 

capacity, such as variable generation. 

836 Pro forma LGIP Secction 1 (Definitions); pro forma LGIA Art. 1 (Definitions).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 283 -

retires and ceases commercial operation, whether that retirement was scheduled or caused 

prematurely by unexpected circumstances, there is no longer any interconnection service 

being provided under the original interconnection customer’s LGIA. Because surplus 

interconnection service is inherently derived from an original interconnection customer’s 

interconnection service under its LGIA, retirement and permanent cessation of

commercial operation of the original interconnection customer’s generating facility 

would eliminate any potential surplus interconnection service that might otherwise have 

been available. 

475. We note that this Final Rule makes it possible for a surplus interconnection service 

customer to increase the total generating facility capacity at a point of interconnection, 

provided that the total combined generating output at the point of interconnection for 

both the original and surplus interconnection customer is limited to and shall not exceed 

the maximum level allowed under the original interconnection customer’s LGIA. 

476. Comments on the NOPR reveal substantial regional variation in the potential 

availability of surplus interconnection service and existing or prospective processes that 

would facilitate its use. To the extent that a transmission provider believes that it already 

complies with the surplus interconnection service requirements of this Final Rule, it may 

include an explanation in its compliance filing in response to this Final Rule. 

477. We clarify that, for a process to be consistent with or superior to, or an 

independent entity variation from, the Final Rule’s surplus interconnection service 

requirements, the transmission provider must demonstrate, at a minimum, that its tariff:

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 284 -

(1) includes a definition of surplus interconnection service consistent with the Final Rule; 

(2) provides an expedited interconnection process outside of the interconnection queue

for surplus interconnection service, consistent with the Final Rule; (3) allows affiliates of 

the original interconnection customers to use surplus interconnection service for another 

interconnecting generating facility consistent with the Final Rule; (4) allows for the 

transfer of surplus interconnection service that the original interconnection customer or 

one of its affiliates does not intend to use; and (5) specifies what reliability-related studies 

and approvals are necessary to provide surplus interconnection service and to ensure the 

reliable use of surplus interconnection service.

478. As a threshold consideration, we respond to NYISO’s concern regarding whether 

the NOPR proposal on surplus interconnection service is consistent with the principles of 

open access. 

479. While open access principles are fundamental to the Commission’s regulation of 

transmission in interstate commerce,837 we find that, in light of the substantial potential

benefits of and inherent practical limitations on the use of surplus interconnection 

 837 See Promoting Wholesale Competition Through Open Access NonDiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by 

Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 

(1996), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, 

Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC 

¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study 

Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 

535 U.S. 1 (2002).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 285 -

service, open access requirements such as those the Commission previously imposed 

upon MISO’s Net Zero Interconnection Service are not currently necessary to achieve the 

Commission’s open access goals. This finding is consistent with the perspective that the 

Commission adopted in Order No. 807, where the Commission amended:

its regulations to waive the Open Access Transmission Tariff (OATT) 

requirements of 18 CFR 35.28, the Open Access Same-Time Information 

System (OASIS) requirements of 18 CFR 37, and the Standards of Conduct 

requirements 18 CFR 358, under certain conditions, for the ownership, 

control, or operation of Interconnection Customer’s Interconnection 

Facilities (ICIF).838 

In Order No. 807, the Commission concluded that the waived requirements were not 

“necessary to achieve the Commission’s open access goals.”839 In coming to this 

conclusion, the Commission stated, among other things, that given the limited nature of 

the ICIF and practical benefits provided by Order No. 807, the waived requirements were 

not necessary to achieve open access. 840

480. We find that policy considerations comparable to those that the Commission relied 

upon to support Order No. 807 are present here. Surplus interconnection service is not 

available to third parties absent some process for allowing the use or transfer of the 

 838 Open Access and Priority Rights on Interconnection Customer's 

Interconnection Facilities, Order No. 807, FERC Stats. & Regs. ¶ 31,367, at P 1 (Order 

No. 807), order on reh'g, Order No. 807-A, 153 FERC ¶ 61,047 (2015).

839 Id. P 18.

840 Id. PP 38, 55.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 286 -

surplus interconnection service to another interconnection customer. As described above, 

some original interconnection customers do not use the full generating facility capacity of 

their interconnection service due to the nature of their operations. In these circumstances, 

no other interconnection customer would be able to obtain interconnection service 

associated with the network upgrades funded by the original interconnection customer. 

Creation of a surplus interconnection service that allows another interconnection 

customer to make use of surplus interconnection service will enhance access to the 

transmission system at the point of interconnection. 

481. The question is then how to align the process for determining which resources 

may access surplus interconnection service with the Commission's goals to promote 

transparent and nondiscriminatory practices. We are convinced, as we were in Order No. 

807, that certain requirements and processes—in this instance, a competitive 

solicitation—are not necessary to achieve our overall open access goals. As a general 

matter, we note that surplus interconnection service is, by definition, limited in nature. 

This is because: (1) the total output of the original interconnection customer plus the 

surplus interconnection service customer behind the same point of interconnection shall 

be limited to the maximum total amount of interconnection service granted to the original

interconnection customer; (2) the original interconnection customer must be able to 

stipulate the amount of surplus interconnection service that is available, to designate

when that service is available, and to describe any other conditions under which surplus 

interconnection service at the point of interconnection may be used; and (3) surplus 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 287 -

interconnection service shall only be available at the preexisting point of interconnection

of the original interconnection customer.

482. Furthermore, we note that the Commission is making no changes to the open 

access nature of the generator interconnection process established by Order No. 2003. 

This Final Rule requirement does not restrict a new interconnection customer’s ability to 

submit an interconnection request for any requested point of interconnection directly with 

the transmission provider, rather than seeking surplus interconnection service with 

respect to an original interconnection customer’s point of interconnection. Therefore, an 

original interconnection customer with surplus interconnection service shall not be 

capable of preventing a new interconnection customer from exercising its open access 

rights to the transmission grid. 

483. In order to realize the benefits of an efficiently-used transmission system, the Final 

Rule adopts the NOPR proposal to allow an original interconnection customer or its 

affiliate to use any surplus interconnection service. Additionally, we withdraw the NOPR 

proposal to require an open and transparent solicitation process if an original

interconnection customer that has surplus interconnection service wishes to transfer this 

surplus interconnection service to a non-affiliated third party. Consequently, we will 

revise proposed pro forma section 3.3 as follows (deleting the bracketed text from, and 

adding the italicized text to, proposed language): 

Utilization of Surplus Interconnection Service. [The ]Transmission 

Provider must provide a process that allows an Interconnection Customer to 

utilize or transfer Surplus Interconnection Service at an existing 

[Generating Facility] Point of Interconnection. The original 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 288 -

Interconnection Customer or one of its affiliates shall have priority to 

utilize Surplus Interconnection Service. If the existing Interconnection 

Customer or one of its affiliates does not exercise its priority, then that 

service may be made available to other potential interconnection customers

[through an open and transparent solicitation process].841

484. We acknowledge that the requirements adopted here reflect a change in 

Commission policy with respect to some of the requirements previously imposed on 

MISO’s Net Zero Interconnection Service.842 Because of the history of that service 

(namely the fact that only one party has sought MISO’s Net Zero Interconnection 

Service), and in light of the record and discussion above, we find it appropriate to revisit 

and modify our position on the topic of surplus interconnection service.

c. Expedited Process

i. Comments

485. Commenters disagree on whether there should be an expedited process for 

transferring surplus interconnection capacity. For example, California Energy Storage 

Alliance supports a faster process that does not require additional interconnection 

studies.843 Xcel and AWEA argue for a new process outside the LGIP that would handle 

all transfers of interconnection capacity.844 On the other hand, some transmission 

 841 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 209.

842 See, e.g., Midwest Indep. Transmission Sys. Operator, 138 FERC ¶ 61,233 at 

P 302.

843 California Energy Storage Alliance 2017 Comments at 7.

844 Xcel 2017 Comments at 19; AWEA 2017 Comments at 59.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 289 -

providers oppose any expedited process that departs from the interconnection queue 

order. SoCal Edison states that, in order to properly identify required upgrades and 

define proper cost assignment, technical studies need to follow a rational order that must 

be predicated on relative queue position.845 Southern opposes an expedited process that 

allows a new interconnection customer to "jump up" in the queue, as this would be unfair 

to others in the queue.846 

ii. Commission Determination

486. As described earlier, we adopt the NOPR proposal to add a new definition for 

“Surplus Interconnection Service” to section 1 of the pro forma LGIP and to article 1 of 

the pro forma LGIA that requires transmission providers to provide an expedited process 

for interconnection customers to utilize or transfer surplus interconnection service at a 

particular point of interconnection. This process would be expedited in the sense that it 

would take place outside of the interconnection queue. Some commenters argue that this 

would result in inappropriate queue jumping. 

487. In response to those comments, we clarify that the use or transfer of surplus 

interconnection service does not entail queue jumping because surplus interconnection 

service does not compete for the same potential network upgrades that may be at issue in 

the normal interconnection queue. Surplus interconnection service is more limited

 845 SoCal Edison 2017 Comments at 2.

846 Southern 2017 Comments at 31.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 290 -

interconnection service because it can only be located at the original interconnection 

customer’s previously studied and approved point of interconnection. The requirements 

for the use of surplus interconnection service: (1) provide efficient use of the 

transmission system; (2) ensure that the use of surplus interconnection service is safe and 

reliable; and (3) help mitigate the possibility of unduly discriminatory treatment. 

Because the necessary studies for surplus interconnection service shall confirm that the 

combination of the surplus interconnection customer’s generating facility with the 

original interconnection customer’s generating facility does not result in a need for new 

network upgrades, it would be inefficient to put surplus interconnection customers into 

the interconnection queue. 

488. Furthermore, transmission providers in some regions routinely conduct similar 

studies outside of the interconnection process. For example, MISO frequently conducts 

Quarterly Operating Limits studies, which are similar in nature to the studies required for 

surplus interconnection service, and the Commission is unaware of any delays to other 

customers related to the processing of these studies.847 We also clarify that original 

interconnection customers are not required to make surplus interconnection service 

available to potential customers. If they do make it available, transmission providers are 

not required to execute an interconnection agreement for surplus interconnection service 

if arrangements do not meet the definition set forth in their tariff or if the customer does 

 847 See, e.g., MISO, FERC Electric Tariff, Attachment X (76.0.0), Section 11.5. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 291 -

not agree to the terms of such service, including any requirements that may be identified 

by the transmission provider in the studies for surplus interconnection service. If the 

surplus interconnection service customer disputes an issue in the interconnection 

agreement for surplus interconnection service, the transmission provider must file the 

unexecuted surplus interconnection service agreement with the Commission if requested 

to do so by the surplus interconnection service customer.

d. Interconnection Capacity Hoarding or Squatting

i. Comments

489. SoCal Edison expresses concern that the proposal might encourage 

interconnection customers to request more interconnection capacity than they intend to 

use, in order to create a surplus that they might sell later.848 Southern agrees and adds

that this could create costs for later-queued customers that they otherwise would not have 

to pay.849 Xcel expresses concerns that such practices could lead to capacity “squatting 

(i.e., hoarding).”850 However, Competitive Suppliers oppose these positions and state 

that reductions in interconnection service to eliminate surplus by transmission providers 

amounts to confiscation of the rights of the interconnection customers.851

 848 SoCal Edison 2017 Comments at 10.

849 Southern 2017 Comments at 29-30.

850 Xcel 2017 Comments at 21.

851 Competitive Suppliers 2017 Comments at 8.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 292 -

ii. Commission Determination

490. As discussed earlier, the interconnection service provided under any LGIA is 

associated with interconnecting that interconnection customer’s generating facility to the 

transmission provider’s system, with a maximum level equal to the generating facility 

capacity. Accordingly, an interconnection customer cannot amass large excesses of 

interconnection service beyond its own needs. Furthermore, as discussed earlier, 

interconnection customers are free to seek interconnection service through the nonsurplus interconnection process of the transmission provider. While an original 

interconnection customer could maintain control over a certain amount of interconnection 

service, that service will be limited to the original interconnection customer’s generating 

facility capacity (which is based on the size of the generating facility it constructs and 

continues to operate). If the original interconnection customer does not construct the 

facility it has represented to the transmission provider, or retires that facility, the 

transmission provider may terminate the customer’s LGIA in accordance with applicable

provisions in its tariff. Accordingly, we see no significant concern with hoarding 

interconnection service. 

e. Property Rights

i. Comments

491. As further described below, some commenters assert that the NOPR’s surplus 

interconnection proposals treat interconnection service as a property right of the 

interconnection customer even though they may not have been so treated in the past. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 293 -

CAISO states that Commission precedent holds that the interconnection capacity does not 

confer a property right, and that where an interconnection customer builds less generating 

facility capacity than that for which it requested interconnection service, it does not retain 

that interconnection capacity indefinitely, and transmission providers like CAISO may 

subsequently remove it from their base case.852 NYISO asserts that the NOPR would 

expand what is currently a contractual right, namely the right to a particular point of 

interconnection, into a property right by allowing a generator to transfer interconnection 

service to a third party.853 SoCal Edison states that the NOPR assumes that 

interconnection capacity is a property right, but that in many cases the interconnection 

customer did not pay for the "surplus."854 

492. On the other hand, some interconnection customers assert that contracted 

interconnection service is indeed a property right. Generation Developers support 

recognizing that surplus capacity is a property right and asset of the existing 

interconnection customer.855 Cogeneration Association argues that transfer of capacity 

cannot be done without the consent of the existing interconnection customer, and that the 

 852 CAISO 2017 Comments at 32 (citing CalWind Resources Inc. v. California 

Independent System Operator Corp., 146 FERC ¶ 61,121, at PP 33 et seq. (2014)).

853 NYISO 2017 Comments at 41.

854 SoCal Edison 2017 Comments at 9.

855 Generation Developers 2017 Comments at 41.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 294 -

existing interconnection customer should be able to negotiate the terms and compensation 

for the transfer of capacity.856 

ii. Commission Determination

493. We are, in this final rule, adopting a requirement that transmission providers 

establish a process for the use or transfer of surplus interconnection service, and we do 

not view that policy as establishing a new property right to interconnection service. 

Rather, as NYISO contends, interconnection service is a contractual right provided by an 

LGIA. We also agree with CAISO that where the original interconnection customer, for 

example, reduces the generating facility capacity of its facility from what was originally 

proposed for interconnection, it would not retain rights indefinitely to any excess

interconnection capacity thus created. 

f. Original Interconnection Customer’s Priority

i. Comments

494. Some commenters argue that the proposed priority for original interconnection 

customers and their affiliates should have a limited term. MidAmerican857 and CAISO858

support a limit of three years from when the original generation facility last produced 

energy. EDP proposes a minimum of five years. EDP cites compatibility with the five-

 856 Cogeneration Association 2017 Comments at 3.

857 MidAmerican 2017 Comments at 20. 

858 CAISO 2017 Comments at 33.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 295 -

year safe harbor granted to interconnection customer interconnection facilities in Order 

No. 807 as support for a five year priority here.859 MISO TOs,860 PJM,861 and TDU 

Systems862 support a time limit, either after the original commercial operations date if the 

interconnection customer has failed to achieve commercial operations, or for some period 

after it has ceased commercial operations, but do not specify a duration, preferring to 

leave each RTO or ISO with discretion to determine appropriate duration. 

ii. Commission Determination

495. While the Commission sought comment in the NOPR on whether any limitations 

should be placed on the original interconnection customer’s priority use of its 

interconnection service, we find that the original interconnection customer, through its 

LGIA, may use or transfer any surplus interconnection service until it retires the 

generating facility that is the subject of the LGIA. We see no reason to modify that 

ability. Accordingly, original interconnection customers will retain the ability to use, 

either for themselves, for an affiliate, or for sale to a third party of their choosing, any 

surplus interconnection service that may exist under their LGIAs, until their original 

generating facility retires. However, as described more fully in subsection (h) below, this 

 859 EDP 2017 Comments at 8.

860 MISO TOs 2017 Comments at 40.

861 PJM 2017 Comments at 26.

862 TDU Systems 2017 Comments at 29-30.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 296 -

right becomes more limited once the original interconnection customer schedules the 

retirement of its original generating facility.

g. Contractual Arrangements

i. Comments

496. Commenters that were responsive to the Commission’s questions regarding

contractual arrangements generally agree that contractual arrangements are necessary 

between the surplus interconnection customer and the original interconnection customer, 

as well as with the transmission owner.863 Specifically, Cogeneration Association states 

that collateral agreements between the interconnection customers are necessary, as 

dealing with rights and obligations between the original interconnection customer and 

new interconnection customer may not be included in the LGIA.864 Similarly, AWEA 

supports the idea of the original and new interconnection customers each having a 

separate LGIA.865

497. ITC argues that the Commission should specify in the pro forma LGIA that the 

original interconnection customer will serve as the single point of contact for operational 

directives and outage coordination by the transmission provider and/or transmission 

owner. According to ITC, transmission providers/owners should not be required to 

 863 Cogeneration Association 2017 Comments at 5; ITC 2017 Comments at 20; 

Generation Developers 2017 Comments at 41; Duke 2017 Comments at 22.

864 Cogeneration Association 2017 Comments at 5.

865 AWEA 2017 Comments at 59.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 297 -

coordinate these operational issues with multiple, potentially-unaffiliated parties. Rather, 

ITC argues, it is appropriate that the original interconnection customer that elects to make 

surplus capacity available assume the obligation of coordinating with surplus 

customers.866 

498. Generation Developers argue that the Commission should require a transmission 

provider to have a pro forma surplus interconnection agreement.867 Duke agrees with the 

NOPR proposal that a new interconnection agreement for surplus interconnection service 

must be executed, or filed unexecuted, by the transmission provider, transmission owner 

(as applicable), and the surplus interconnection service customer and suggests that the 

MISO LGIA template provides a framework for such agreements between the 

interconnection customers and transmission providers.868

ii. Commission Determination

499. We agree with commenters that agreements between the original interconnection 

customer, the surplus interconnection service customer (whether affiliated or not), and 

the transmission provider are necessary to establish conditions such as the term of 

operation, the interconnection service limit, and the mode of operation for energy 

production (i.e., common or singular operation) and to establish the roles and 

 866 ITC 2017 Comments at 20.

867 Generation Developers 2017 Comments at 41.

868 Duke 2017 Comments at 22.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 298 -

responsibilities of the parties for maintaining the operation of the facility within the 

parameters of the surplus interconnection service agreement. Therefore, we require that 

the original interconnection customer, the surplus interconnection service customer, and 

the transmission provider enter into such agreements for surplus interconnection service 

and that they be filed by the transmission provider with the Commission, because any 

surplus interconnection service agreement will be an agreement under the transmission 

provider’s OATT.

500. However, we decline to establish these agreements as part of the pro forma LGIA 

or prescribe their terms and conditions. This will give transmission providers flexibility 

to establish agreements appropriate for their region (e.g., they may be different for 

RTO/ISO and non-RTO/ISO regions) and the unique conditions of each agreement for 

surplus interconnection service. It will also alleviate some potential burden by allowing 

transmission providers to either file pro forma versions of these agreements with the 

Commission, as was done in MISO, or execute them as needed and file them with the 

Commission on an ad hoc basis.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 299 -

h. Retirement, Repowering and Continuation of Surplus 

Interconnection Service after the Original Interconnection 

Customer’s Generating Facility Retires

i. Comments

501. Some commenters discuss the NOPR as it might relate to retirement of generators 

and replacement or repowering.869 Xcel argues that the retention of rights by the 

interconnection customer or its affiliates may be helpful at the current time when many 

utilities are going through retirement and replacement or repowering.870 Xcel argues that 

using this approach for repowering leads to efficiency because re-using brownfield sites 

is the most cost-effective approach to repowering, and suggests that the Commission 

should encourage this practice.871 CAISO states that it allows repowering, and notes that,

in some cases, this process has led to the replacement of conventional generation by 

electric storage.872 PG&E supports the CAISO repowering process for allowing new 

generation on the grid while potentially minimizing interconnection and network upgrade 

 869 For purposes of this Final Rule, we adopt CAISO’s definition of “repowering,” 

which defines repowering as a modification of existing generating units that does not: 

(i) increase the total capability of the plant; or (ii) substantially change its electrical 

characteristics such that original reliability studies would be affected. See Section 25.1.2 

of the CAISO tariff; Section 12 of the business practice manuals for Generator

Management, 

https://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Generator%20Management.

870 Xcel 2017 Comments at 19.

871 Id. at 20.

872 CAISO 2017 Comments at 33.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 300 -

costs.873 ISO-NE states that its forward capacity market can accommodate repowering by 

maintaining the interconnection service while the interconnection customer builds a new 

generating facility that can take the place of a retiring unit.874

502. Other commenters discuss whether surplus interconnection service should 

terminate at the same time the original interconnection customer’s generating facility 

retires. Cogeneration Association argues that this matter should be stated in the LGIA or 

collateral agreement, but that the default position should be that the termination of rights 

of the surplus interconnection customer should occur simultaneously with the termination 

of rights of the original interconnection customer.875 Generation Developers argue for the 

survivorship of the surplus interconnection service when the original interconnection 

customer’s generating facility retires, on the basis that the surplus interconnection 

customer would have paid the original interconnection customer for the interconnection 

rights.876 Xcel supports survivorship because of greater commercial attractiveness and 

helping the new interconnection customers to get financing.877 

 873 PG&E 2017 Comments at 9.

874 ISO-NE 2017 Comments at 50.

875 Cogeneration Association 2017 Comments at 5-6.

876 Generation Developers 2017 Comments at 42.

877 Xcel 2017 Comments at 21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 301 -

ii. Commission Determination

503. The purpose of this reform is to enable the efficient use of any surplus 

interconnection service that may exist in connection with an original interconnection 

customer’s use of its generating facility. The retirement or repowering of that original 

interconnection customer’s generating facility would represent activities outside the 

normal use of that generating facility. Accordingly, we find that, with one exception 

discussed below, retirement and repowering issues are outside the scope of this 

rulemaking, and should instead be addressed elsewhere (e.g., through the existing 

processes discussed by some commenters).

504. With respect to continuation of surplus interconnection service after the retirement 

of the original interconnection customer’s generating facility, we find that surplus 

interconnection service is, by definition, tied to the continued existence of the original 

interconnection customer’s interconnection service. There must be some existing 

interconnection service from which the ability to provide surplus interconnection service

has been identified. As described above, once the original interconnection service 

terminates, there is no longer an original interconnection service from which the ability to 

provide surplus interconnection service could be identified. Therefore, surplus 

interconnection service shall not be available when the original interconnection customer 

retires and permanently ceases commercial operation. 

505. However, we believe it is appropriate to permit a limited continuation of surplus 

interconnection service following the retirement and permanent cessation of commercial 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 302 -

operation of the original interconnection customer’s generating facility to ameliorate the 

business and financial risk to the surplus interconnection service customer if the original 

interconnection customer retires unexpectedly, when two conditions are met. First, the 

surplus service interconnection customer’s generation facility must have been studied by 

the transmission provider for sole operation at the point of interconnection at the time of 

the interconnection of the surplus service interconnection customer. Second, the original

interconnection customer (and now retiring) must have agreed in writing that the surplus 

interconnection service customer may continue to operate at either its limited share of the 

original interconnection customer’s generating facility capacity in the original 

interconnection customer’s LGIA, as reflected in its surplus interconnection service 

agreement, or at any level below such limit upon the retirement and permanent cessation

of commercial operation of the original interconnection customer’s generating facility. 

506. If these conditions are met, then the transmission provider must permit the surplus 

interconnection service customer to continue the surplus interconnection service for a 

limited period not to exceed one year. To prevent gaming and abuse of the continuation 

of surplus interconnection service, such service shall be limited to no more than one year 

after the date of retirement and permanent cessation of commercial operation of the 

original interconnection customer. If these conditions are not met, then those agreements 

regarding the surplus interconnection service must be drafted to, and must, terminate 

simultaneously with the termination of the original interconnection agreement from 

which surplus interconnection service was provided.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 303 -

507. We note again that interconnection customers are under no obligation to choose 

surplus interconnection service rather than seeking their own stand-alone interconnection 

service directly from the transmission provider. Therefore, any interconnection 

customers that require greater assurance up front that their interconnection service will 

not be affected by the retirement of another generating facility should carefully consider 

whether surplus interconnection service is the right match for their particular needs. 

i. Relationship to MISO Net Zero Interconnection Service

i. Comments

508. MISO argues that, as a part of the Final Rule, the Commission should allow MISO 

to remove certain restrictions on its existing Net Zero Interconnection Service that it 

argues exceed the restrictions proposed for the surplus interconnection service.878

ii. Commission Determination

509. We agree with MISO that this Final Rule includes fewer restrictions on the use of 

surplus interconnection service than what the Commission imposed on MISO’s Net Zero 

Interconnection Service, which has a similar goal. As noted above, the requirements we

enact in this Final Rule for surplus interconnection service depart in some respects from 

our precedent regarding MISO’s Net Zero Interconnection Service. This Final Rule 

reflects a shift in the Commission’s view of these issues as described in earlier 

subsections of this Final Rule. To the extent that MISO wishes to modify the procedures 

 878 MISO 2017 Comments at 36.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 304 -

surrounding its Net Zero Interconnection Service, MISO may propose to do so on 

compliance in this proceeding, and the Commission will evaluate that proposal to 

determine if it complies with the requirements of the Final Rule. 

4. Material Modification and Incorporation of Advanced 

Technologies

a. NOPR Proposal

510. Under the pro forma LGIP, an interconnection customer can modify its 

interconnection request and still retain its queue position if the modifications are either 

explicitly allowed under the pro forma LGIP or if the transmission provider determines 

that the modifications are not material. The pro forma LGIA defines material 

modifications as “those modifications that have a material impact on the cost or timing of 

any Interconnection Request with a later queue priority date.”879 Under the pro forma 

LGIP, an interconnection customer must submit to the transmission provider, in writing, 

modifications to any information provided in the interconnection request.880 The pro 

forma LGIP directs transmission providers to commence any necessary additional studies 

related to the interconnection customer’s modification request no later than 30 calendar 

days after receiving notice of the request.881 If the transmission provider determines that 

 879 Pro forma LGIA Art. 1.

880 See pro forma LGIP Section 4.4.

881 See pro forma LGIP Section 4.4.4.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 305 -

the proposed modification is material, the interconnection customer can choose to 

abandon the proposed modification or proceed and lose its queue position.

511. In the NOPR, the Commission explained that the pro forma LGIP does not contain 

guidance regarding analysis and modeling for the incorporation of technological 

advancements into an existing interconnection request. The Commission preliminarily 

found that the discretion resulting from this lack of guidance can lead to unjust and 

unreasonable rates, terms, and conditions, and unduly discriminatory or preferential 

practices, especially for technological advancements.882 The Commission thus proposed

to require transmission providers to establish a technological change procedure in their

LGIPs to assess and, if necessary, study whether they can accommodate a technological 

advancement without the change being considered material.883 The Commission stated 

that such a procedure would allow an interconnection customer to provide an analysis of 

how its proposed technological advancement would result in electrical performance that 

is equal to or better than the electrical performance expected prior to the change.884 

Using such a procedure, a transmission provider would determine whether a 

technological advancement is a material modification. If it was not a material 

 882 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 216.

883 Id. P 217.

884 Id. PP 217-18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 306 -

modification, the interconnection customer could incorporate the technological 

advancement without losing its queue position. 

512. In the NOPR, the Commission also proposed to require transmission providers to 

develop a definition of permissible technological advancements that the interconnection 

process can accommodate without the change being considered a material 

modification.885 Thus, pursuant to this proposal, a permissible technological 

advancement is a technological advancement that, by definition, does not constitute a 

material modification. Further, the Commission proposed that this definition should 

contemplate advancements that provide cost efficiency and/or electrical performance

benefits.886 The Commission proposed that in the scenario where a transmission provider 

requires a study for a proposed technological advancement to not be considered a 

material modification, the interconnection customer should tender an appropriate study 

deposit and provide the necessary modeling data that sufficiently models the behavior of 

the new equipment and any other required data about the technological advancement to 

the transmission provider.887 

513. To implement the technological change procedure, the Commission also proposed

to require transmission providers to define technological advancements in their LGIPs. 

 885 Id. P 217.

886 Id. P 212.

887 Id. P 219.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 307 -

The Commission stated that the definition should consider technological advancements to 

equipment that may achieve cost and grid performance efficiencies.888 Finally, the 

Commission proposed to permit interconnection customers to submit technological 

advancement requests for incorporation any time before the execution of the facilities 

study agreement.889

514. Accordingly, the Commission proposed to revise section 4.4.2 of the pro forma

LGIP as follows (with proposed deletions in brackets and with proposed additions in 

italics):

4.4.2 Prior to the return of the executed Interconnection Facility Study 

Agreement to the Transmission Provider, the modifications permitted under 

this Section shall include specifically: (a) additional 15 percent decrease in 

plant size (MW), [and] (b) Large Generating Facility technical parameters 

associated with modifications to Large Generating Facility technology and 

transformer impedances; provided, however, the incremental costs 

associated with those modifications are the responsibility of the requesting 

Interconnection Customer; and (c) a technological advancement for the 

Large Generating Facility after the submission of the interconnection 

request. Section 4.4.4 specifies a separate Technological Change 

Procedure including the requisite information and process that will be 

followed to assess whether the Interconnection Customer’s proposed 

technological advancement under Section 4.4.2(c) is a Material 

Modification. Section 1 contains a definition of Technological 

Advancement.

890

 888 Id. P 222.

889 Id. P 223.

890 With respect to this new provisions to the pro forma LGIP, we make minor 

clarifying edits to the pro forma tariff language originally proposed in the NOPR, as 

shown in Appendix B. Specifically, the comma after section 4.4.2(a)(2) will be replaced 

with a semicolon, and pro forma section 4.4.2 will no longer capitalize “Technological 

Change Procedure.” Additionally, in the last sentence of pro forma section 4.4.2, 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 308 -

b. Technological Change Procedure 

i. Comments

515. The majority of commenters support891 or do not object892 to the proposal. AFPA 

and ELCON cite the proposal’s potential to lower interconnection costs and avoid costly 

delays in commercial operation.893 AWEA comments that the proposal will provide 

transparency and certainty to both the transmission provider and the interconnection 

customer, and will remove a barrier to the use of the most modern, cost effective 

technology.894 NextEra states that transmission providers are inconsistent in considering 

potential changes to the equipment being installed under an interconnection agreement.895

 

“technological advancement” will now say “Permissible Technological Advancement.” 

Also, section 1 of the pro forma LGIP will contain a placeholder for the definition of 

“Permissible Technological Advancement, and there is now a placeholder for each 

transmission provider’s technological change procedure in pro forma LGIP section 4.4.4.

891 Alliant 2017 Comments at 13; AFPA 2017 Comments at 16; AWEA 2017 

Comments at 60; CAISO 2017 Comments at 35; Joint Renewable Parties 2017 

Comments at 12; ELCON 2017 Comments at 7; Idaho Power 2017 Comments at 6; IECA 

Comments at 3; ISO-NE 2017 Comments at 51; MISO 2017 Comments at 5; NEPOOL 

2017 Comments at 18; NextEra 2017 Comments at 52; TDU Systems 2017 Comments at 

30-31; PJM 2017 Comments at 30.

892 APPA/LPPC 2017 Comments at 26; NYISO 2017 Comments at 43; SEIA 

2017 Comments at 21.

893 AFPA 2017 Comments at 4; ELCON 2017 Comments at 7.

894 AWEA 2017 Comments at 60.

895 NextEra 2017 Comments at 52.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 309 -

Alliant asserts that the current definition of material modification is unclear and that more 

guidance is needed from the Commission in terms of what would trigger a material 

modification study.896 Idaho Power agrees with the proposal provided that an

interconnection customer will be responsible for any necessary network upgrades that are 

identified and for which the transmission provider committed expenses before the 

technological advancement request.897 TDU Systems supports the flexibility built into 

the proposal and adds that, if technological advancements include changes to the

equipment’s electrical characteristics, then the models require modification, the 

simulations must be re-run, and the results require reevaluation.898

516. Multiple RTOs/ISOs support or do not oppose the NOPR’s technological 

advancement proposal, while some do not necessarily believe that the NOPR proposal is 

necessary. For example, CAISO states that it supports the proposal.899 MISO also 

supports the proposal, and comments that interconnection customers should not forfeit 

interconnection rights simply because the technology of their generating facility has 

become outdated.900 ISO-NE and NEPOOL state that ISO-NE’s 2016 revisions to its 

 896 Alliant 2017 Comments at 13.

897 Idaho Power 2017 Comments at 6.

898 TDU Systems 2017 Comments at 30-31.

899 CAISO 2017 Comments at 35.

900 MISO 2017 Comments at 5.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 310 -

interconnection procedures already establish clear rules to consistently and expeditiously 

determine whether a proposed modification is material.901 ISO-NE states that it

developed its rules to respond to continuous requests for technical changes, which were

one contributing factor to the Maine queue backlog.902 ISO-NE states that its recent tariff

changes have addressed these issues. NYISO asserts that it does not oppose the NOPR 

proposal if it is limited to assessing the materiality and consideration of whether the 

transmission provider can accommodate a modification to the specific technology type

initially proposed (as opposed to changing from gas to wind, for example).903 PJM states 

that it is not opposed to accounting for technological changes during the study process.904 

However, PJM cites to its current practice of incorporating technological changes and

states that a separate “technological change procedure” is not necessary to determine 

whether such a modification is material.905

 901 ISO-NE 2017 Comments at 52; NEPOOL 2017 Comments at 18.

902 ISO-NE 2017 Comments at 52-53. ISO-NE noted that the revisions were 

developed with stakeholders to address interconnection challenges that have led to a 

backlog of interconnection requests for 4,000 MW of primarily wind generation in 

Maine. See ISO New England Inc. and Participating Transmission Owners Admin.

Comm., 155 FERC ¶ 61,031, at P 2 (2016).

903 NYISO 2017 Comments at 43.

904 PJM 2017 Comments at 30.

905 PJM 2017 Comments at 30.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 311 -

517. Other commenters do not support the NOPR proposal or believe that the proposed 

changes are unnecessary. For example, EEI and some public utility transmission 

providers outside the RTOs/ISOs comment that current material modification provisions 

are adequate.906EEI asserts that the Commission has not clearly explained the difference 

between a technological advancement and a material modification and that the proposal 

unreasonably limits a transmission provider’s ability to evaluate reliability impacts.907

EEI states that, if the Commission decides to establish more granular procedures for 

technological advancements, it should not duplicate the material modification 

requirements. Instead, EEI suggests that the Commission could require transmission 

providers to explain whenever a change that is not explicitly listed in the pro forma LGIP 

constitutes a material modification.908 EEI also states that it is reasonable to leave 

significant discretion to sound engineering judgment in order to balance the need to 

implement technological advancements, improve performance and efficiencies, and to 

maintain safe, reliable service.909 Southern adds that the concern should not be about

developing types of advanced technologies, but how that technology impacts already 

 906 AES 2017 Comments at 8-9; Duke 2017 Comments at 24; EEI 2017 Comments 

at 67; PG&E 2017 Comments at 9 (citing CAISO Business Practice Manual for 

Generator Management Section 6); Southern 2017 Comments at 32; TVA 2017 

Comments at 18; Xcel 2017 Comment at 22.

907 EEI 2017 Comments at 5, 67, 68-69.

908 Id. at 69, 73.

909 Id. at 73.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 312 -

queued requests.910 TVA suggests that, rather than identifying specific pre-qualified

technical advancements, interconnection customers should update their model data before 

starting the system impact study.911 Xcel notes that the types and impacts of changes 

evolve as technology advances, and while it does not consider a pro forma LGIP change 

necessary, it encourages customers to provide studies and evidence that any change is 

immaterial.912 Xcel also recommends that the Commission hold a technical conference or 

workshop to discuss material modification issues, which it anticipates will show the

variation and difficulty involved in evaluating such modifications.913

ii. Commission Determination

518. We adopt the NOPR proposal subject to certain clarifications. We require 

transmission providers to include in their pro forma LGIP a technological change 

procedure. They must also assess, and if necessary, study whether proposed 

technological advancements can be incorporated into interconnection requests without 

triggering the material modification provisions of the pro forma LGIP. Furthermore, 

transmission providers must, consistent with the guidance provided in this Final Rule, 

 910 Southern 2017 Comments at 32.

911 TVA 2017 Comments at 18.

912 Xcel 2017 Comment at 22.

913 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 313 -

develop a definition of permissible technological advancement. Such permissible 

technological advancements would, by definition, not constitute material modifications. 

519. The technological change procedure must specify what technological 

advancements can be incorporated at various stages of the interconnection process, and 

the procedure must clearly identify which requirements apply to the interconnection 

customer and which apply to the transmission provider. The procedure should state that,

if an interconnection customer seeks to incorporate technological advancements into its 

generating facility, it should submit a technological advancement request. For the 

transmission provider to determine that a proposed technological advancement is not a 

material modification, the procedure must specify the information that the 

interconnection customer must submit as part of a technological advancement request. 

The procedure must also specify the conditions under which a study will or will not be 

necessary to determine whether a proposed technological advancement is a material 

modification. 

520. For a transmission provider to be able to determine whether a proposed 

technological advancement is not a material modification, the interconnection customer’s 

technological advancement request must demonstrate that the proposed incorporation of 

the technological advancement would result in electrical performance that is equal to or 

better than the electrical performance expected prior to the technology change and not 

cause any reliability concerns (i.e., materially impact the transmission system with regard 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 314 -

to short circuit capability limits, steady-state thermal and voltage limits, or dynamic 

system stability and response).914

521. The transmission provider must determine whether a requested technological 

advancement is a material modification and whether or not a study is necessary to 

complete the analysis of whether the technological advancement is a material 

modification. The procedure must state that, if a study is necessary to evaluate whether a 

particular technological advancement is a material modification, the transmission 

provider must clearly indicate to the interconnection customer the types of information 

and/or study inputs that the interconnection customer must provide to the transmission 

provider, including for example, study scenarios, modeling data, and any other 

assumptions. The procedure should also explain how the transmission provider will 

evaluate the technological advancement request to determine whether it is a material 

modification.

522. If the transmission provider cannot accommodate a proposed technological 

advancement without triggering the material modification provision of the pro forma

LGIP, the transmission provider shall provide an explanation to the interconnection 

customer regarding why the technological advancement is a material modification. 

 914 In the next section, we respond to EEI’s comment as to what was meant by 

“performance that is equal or better than the electrical performance expected prior to the 

technology change.”

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 315 -

523. We find that the current definition of material modification may create uncertainty 

about whether a transmission provider must consider a technological advancement to be a 

material modification, and we agree with commenters that the requirement that we adopt 

in this Final Rule will increase transparency, create process efficiencies, and encourage 

technological innovation that could lower consumer costs.915 We find that, contrary to 

the assertions that the existing material modification procedures are adequate, the 

proposed reforms are necessary to improve certainty and transparency. 

524. Some transmission providers, such as PJM, believe that a technological change 

procedure is unnecessary because their tariffs already include a method to determine 

whether a change to an interconnection request is a material modification. In response to 

these comments, if a transmission provider believes its existing interconnection 

procedures regarding the incorporation of technological advancements would qualify for 

a variation from the Final Rule requirements or that it already complies with the

requirements adopted in this Final Rule, it may provide such an explanation in its 

compliance filing.

525. EEI, Duke, Southern, TVA, and Xcel assert that the existing material modification 

procedures are adequate to incorporate technological advancements. However, they do 

not dispute our concern that transmission providers have significant discretion over what 

equipment changes constitute material modifications. EEI takes issue with the proposal 

 915 See AFPA 2017 Comments at 16; AWEA 2017 Comments at 60–61; ELCON 

2017 Comments at 7; NextEra 2017 Comments at 52.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 316 -

for transmission providers to specify in the technological change procedure the 

conditions when a study is necessary.916 EEI further asserts that the Commission has not 

clearly explained the difference between a technological advancement and a material 

modification and that the proposal unreasonably limits a transmission provider’s ability 

to evaluate reliability impacts.917 In response to these concerns, we note that the purpose 

of the technological change procedure is to allow for equipment changes resulting in 

electrical performance that is equal to or better than an interconnection request’s

previously projected electrical performance and not cause any reliability concerns.918 We 

have designed the technological change procedure to allow transmission providers to 

evaluate whether equipment changes in an interconnection request should trigger the 

material modification provisions. This new requirement increases transparency in the 

interconnection process and allows transmission providers to evaluate the impact of a 

proposed technological advancement to determine whether it qualifies as a material 

modification, and, thus will result in the interconnection customer losing its queue 

position.

 916 EEI 2017 Comments at 69-70.

917 Id. at 5, 67, 68-69.

918 For example, an interconnection customer may elect to incorporate a smart 

inverter that is capable of sensing and autonomously reacting to changes on the grid.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 317 -

526. Regarding Xcel’s request for a technical conference, we believe our determination 

here is supported by the record evidence and therefore do not believe that a technical 

conference on this issue is necessary.

c. Definition of Permissible Technological Advancements

i. Comments

527. A handful of commenters offer suggestions regarding the definition of permissible 

technological advancements. Some caution against an overly prescriptive definition to 

account for the unpredictability of technology evolution.919 Alliant and AWEA support 

an inclusive definition of technological advancement that accounts for changes that 

already exist.920 Alliant states that while a “loose” definition of material modification 

creates uncertainty and additional risk associated with replacing equipment or completing 

normal unit maintenance, an overly rigid definition could burden generator owners with 

unnecessary costs and the system operator with a longer backlog or strained resources.921 

Other commenters assert that the rate of technological advancement makes it difficult to 

speculate which technologies to include.922 MISO TOs request clearer Commission 

 919 AWEA 2017 Comments at 62; Alliant 2017 Comments at 13-14; Duke 2017 

Comments at 25; EEI 2017 Comments at 6.

920 Alliant 2017 Comments at 13-14; AWEA 2017 Comments at 62.

921 Alliant 201 Comments at 13-14.

922 Duke 2017 Comments at 25; EEI 2017 Comments at 69.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 318 -

direction to develop clear material modification guidelines.923 They also state that 

RTO/ISO guidelines should specify that a change that does not exceed the 

interconnection customer’s interconnection rights or materially impact short circuit 

capability limits, steady-state thermal and voltage limits, or dynamic system stability and 

response is not a material modification.924

528. EDP argues that changes between wind and solar technologies should be treated as 

non-material modifications.925 Other commenters disagree and request that the 

Commission make clear that permissible technological advancements exclude changes in 

generation technology type.926 NextEra argues that an incremental change within the 

same technology class, e.g., substituting a newer model of solar panel than originally 

planned, is not material.927 NYISO states that it opposes any tariff changes that would 

consider changes “to the technology type that would essentially constitute a new facility 

as non-material modifications – e.g., the addition of a battery element to a wind project or 

the addition of a solar element to a wind project.”928 NextEra submits that transmission 

 923 MISO TOs 2017 Comments at 41.

924 MISO TOs 2017 Comments at 42.

925 EDP 2017 Comments at 9.

926 EEI 2017 Comments at 71; NYISO Comments at 43.

927 NextEra 2017 Comments at 52.

928 NYISO 2017 Comments at 43.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 319 -

providers should be able to define a category of permissible technological advancements 

that will not need extensive studies.929 EEI supports leaving the definition to the 

transmission provider’s discretion.930 

529. EEI requests further clarification of what is meant by “performance that is equal or 

better than the electrical performance expected prior to the technology change.”931 EEI 

also states that some material considerations such as electrical characteristics (e.g., 

reactive power), capacity factor, and time of use should be studied holistically.932

ii. Commission Determination

530. We adopt the NOPR proposal and require transmission providers to develop a 

definition of permissible technological advancements that the interconnection process can 

accommodate without triggering the material modification provision of the pro forma

LGIP. We are providing transmission providers with the flexibility to propose a unique

definition for permissible technological advancements in their compliance filings. Some 

commenters caution against an overly prescriptive definition to account for the 

unpredictability of technology evolution.933 We agree that transmission providers should 

 929 NextEra 2017 Comments at 52.

930 EEI 2017 Comments at 70.

931 Id.

932 Id.

933 AWEA 2017 Comments at 62; Alliant 2017 Comments at 13-14; Duke 2017 

Comments at 25; EEI 2017 Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 320 -

have the flexibility to account for the rapid pace of innovation when developing the 

definition. The definition must make clear what category of technological advancements 

can be accommodated that do not require extensive or additional studies to determine 

whether a proposed technological advancement is a material modification.934 As noted in 

the NOPR, such permissible changes may include, for example, advancements to 

turbines, inverters, plant supervisory controls, or other technological advancements that 

may affect a generating facility’s ability to provide ancillary services.935 We clarify that 

the assessment of whether a technological advancement is permissible is limited to 

assessing the materiality of the change and consideration of whether the transmission 

provider can accommodate a modification to the specific technology type initially 

proposed in the interconnection request. Although some commenters argue that changes 

between wind and solar technologies should be treated as non-material modifications,936

we disagree since such changes involve a change in the electrical characteristics of an 

interconnection request, and the transmission provider would likely need to evaluate the 

impacts of such changes. We also agree that the definition of permissible technological 

advancements must not include changes in generation technology or fuel type937 (e.g., 

 934 See e.g., NextEra 2017 Comments at 52.

935 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 212.

936 See e.g., EDP 2017 Comments at 9.

937 EEI 2017 Comments at 71; NYISO Comments at 43.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 321 -

from gas to wind) because they involve a change in the electrical characteristics of an 

interconnection request.

531. MISO TOs request clearer Commission direction to develop material modification 

guidelines. They state that RTO/ISO guidelines should clarify that a change that does not 

exceed the interconnection customer’s interconnection rights or materially impact short 

circuit capability limits, steady-state thermal and voltage limits, or dynamic system 

stability and response, is not a material modification.938 Responding to comments 

questioning whether certain technological advancements can be accommodated without 

materially affecting other interconnection customers in the queue as well as EEI’s 

comment as to what was meant by “performance that is equal or better than the electrical 

performance expected prior to the technology change,” we find that a technological 

advancement that does not increase the interconnection customer’s requested

interconnection service or cause any reliability concerns (i.e., materially impact the 

transmission system with regard to short circuit capability limits, steady-state thermal and 

voltage limits, or dynamic system stability and response), is generally not a material 

modification. Further, we clarify that technological advancements that do not degrade 

the electrical characteristics of the generating equipment (e.g., the ratings, impedances, 

efficiencies, capabilities, and performance of the equipment under steady state and 

 938 MISO TOs 2017 Comments at 42.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 322 -

dynamic conditions) qualify as performance that is “equal to or better than the 

performance expected prior to the change.”939

d. Timing and Deposits

i. Comments

532. With regard to timing, EEI supports a 30-day study result deadline from

commencement and a deposit of at least $10,000 per material modification proposal and 

clarification that the interconnection customer is financially responsible for necessary 

additional studies.940 NYISO supports only allowing modifications early in the 

interconnection study process.941 EEI requests clarification on when an interconnection 

customer should be able to request the incorporation of advanced technology; it is unsure

if the Commission proposes to allow different technological advancements to trigger the 

procedure at different points or a single set of technological advancements prior to the 

facilities study agreement’s execution.942 It further argues that technology changes

without a change of queue position could result in additional studies and delays, 

particularly if the change is material or if the process to study the technological 

 939 We note that TDU Systems argue for a similar interpretation of permissible 

technological advancement. TDU Systems 2017 Comments at 30-31.

940 EEI 2017 Comments at 72-73.

941 NYISO 2017 Comments at 44.

942 EEI 2017 Comments at 71.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 323 -

advancement negatively impacts the overall interconnection study process.943 EEI states 

that any Final Rule should provide the flexibility for a transmission provider to evaluate 

the impact of a proposed technological advancement, relative to allowing it in the current 

study or requiring the generator to reenter the queue.944

533. AWEA supports allowing technological advancements at any point including after 

an interconnection agreement is executed and a generating unit is online.945 Generation 

Developers argue that transmission providers should have to respond to technological 

advancement analyses within 15 days.946 Conversely, Bonneville opposes a specific 

study completion timeframe, and suggests that a transmission provider would meet its 

obligation if it uses reasonable efforts.947 

ii. Commission Determination

534. We adopt the NOPR proposal to require the interconnection customer to tender a

deposit if the transmission provider determines that additional studies are needed to 

evaluate whether a technological advancement is a material modification. We find that 

the amount of the deposit should be specified in the transmission provider’s technological

 943 Id. at 71-72.

944 Id. at 72.

945 AWEA 2017 Comments at 62.

946 Generation Developers 2017 Comments at 44.

947 Bonneville 2017 Comments at 11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 324 -

change procedure. Requiring such a deposit is just and reasonable because a deposit will 

reimburse the transmission provider for the time and effort needed to complete the 

technological advancement study as well as minimize the submission of frequent and/or 

frivolous technological advancement requests. The transmission provider shall describe

for the interconnection customer any costs incurred to conduct any necessary additional 

studies, provide its costs to the interconnection customer, and either refund any overage 

or charge for any shortage for costs that exceed the deposit amount. We are setting the 

default deposit amount at $10,000. However, to the extent that a transmission provider 

considers a $10,000 deposit to be too high or low, it may propose a reasonable alternative 

amount in its compliance filing and include justification supporting this alternative 

amount. We agree with EEI that the interconnection customer should bear financial 

responsibility for any necessary additional studies that may need to be performed to 

determine whether a technological advancement is a material modification.948

535. Each transmission provider’s technological change procedure must also include 

the timeframe for the transmission provider to perform the study it needs to determine 

whether the proposed technological advancement is a material modification and return 

the results to the interconnection customer. We note that some commenters suggested a 

30-day study result deadline to determine whether a proposed technological advancement 

 948 See EEI 2017 Comments at 72-73.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 325 -

is material.949 After consideration of comments and the record in this proceeding, we 

believe that it is appropriate to establish a 30-day study result deadline. Accordingly, 

transmission providers must perform and complete any necessary additional studies as 

soon as practicable, but no later than 30 days after the interconnection customer submits a 

formal technological advancement request to the transmission provider. Although 

Bonneville opposes a specific study completion timeframe, and suggests that a

transmission provider would meets its obligation if it uses reasonable efforts,950 we find 

that, given that the pro forma LGIP currently contains no requirement for such studies to 

be completed within a specified timeframe, a 30-day requirement to determine whether 

the proposed technological advancement is a material modification adds certainty to the 

interconnection process. 

536. Regarding the question of when in the process the transmission provider is no 

longer required to accommodate technological advancements, we adopt the NOPR 

proposal to permit interconnection customers to submit requests to incorporate 

technological advancements prior to the execution of the interconnection facilities study 

agreement. In response to commenters that suggest that interconnection customers

should be able to incorporate technological advancements at any point in the 

 949 See, e.g., id.

950 Bonneville 2017 Comments at 11.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 326 -

interconnection process without possible loss of queue position,951 we disagree. We 

believe that we are establishing a reasonable cut-off point for allowing technological 

advancements that will not be considered material modifications given that changes 

requested during the facilities study could delay the transmission provider’s ability to 

tender an interconnection service agreement and, consequently, delay other projects.952 

In addition, in response to EEI’s concerns regarding whether the Commission envisions

allowing different technological advancements to trigger the procedure at different points 

in the interconnection process, or if the Commission is proposing to allow one single set 

of technological advancements prior to the execution of the interconnection facilities 

study agreement, we clarify that interconnection customers must submit a technological 

advancement request for any type of technological advancement in the interconnection 

process up until execution of the interconnection facilities study agreement. However, to 

the extent that a transmission provider believes that it is appropriate to establish rules that 

permit technological advancements only at a single point in its interconnection process 

(prior to the execution of the interconnection facilities study agreement), we permit 

transmission providers to propose such a practice in their compliance filings. 

 951 See, e.g., AWEA 2017 Comments at 62 (stating that “the technological change 

procedure should be allowed at any point in the interconnection process”).

952 PJM 2017 Comments at 30.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 327 -

5. Modeling of Electric Storage Resources for Interconnection 

Studies 

a. NOPR Proposal

537. The NOPR proposed to require that transmission providers evaluate their methods 

for modeling electric storage resources for interconnection studies, identify whether their 

current modeling and study practices adequately and efficiently account for the 

operational characteristics of electric storage resources, and explain why and how their 

existing practices are or are not sufficient. The Commission also sought comment on 

whether establishing a unified model for studying electric storage resources would 

expedite the study process and therefore reduce time and costs expended by transmission 

providers. The Commission also asked what information electric storage resources 

should provide when submitting interconnection requests that transmission providers do 

not already require.

b. Comments

538. Several commenters support the proposal to require transmission providers to 

evaluate their methods for modeling electric storage resources for interconnection 

studies.953 MISO TOs state that MISO lacks clear standards for modeling electric 

storage, and ask that the Commission convene a workshop or technical conference to 

 953 AFPA 2017 Comments at 17; California Energy Storage Alliance 2017 

Comments at 9-11; Joint Renewable Parties 2017 Comments at 12-13; MISO TOs 2017 

Comments at 43; NEPOOL 2017 Comments at 18; NextEra 2017 Comments at 53; 

Public Interest Organizations 2017 Comments at 8-9; Indicated NYTOs 2017 Comments 

at 15. 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 328 -

allow the industry to determine best practices.954 NEPOOL argues that the NOPR 

proposal would improve modeling of storage and facilitate entry of storage resources into 

the markets.955 Non-Profit Utility Trade Associations and PJM state that they do not 

object to the proposal.956 

539. Other commenters support the proposal but ask the Commission to give 

transmission providers flexibility to address any necessary changes.957 For example, 

Indicated NYTOs state that the evaluation of storage-related interconnection must be 

conducted in the context of each regional stakeholder process.958 Duke and NYISO take

a similar view. They oppose a unified model for studying electric storage resources 

because it could remove a transmission provider’s flexibility to study the various use 

cases for storage.959 

540. Public Interest Organizations ask the Commission not to require all electric storage 

resources, including electric storage resources that will serve as a transmission asset, to 

 954 MISO TOs 2017 Comments at 43.

955 NEPOOL 2017 Comments at 18.

956 Non-Profit Utility Trade Associations 2017 Comments at 26; PJM 2017 

Comments at 30.

957 Indicated NYTOs 2017 Comments at 15; ITC 2017 Comments at 20-21; 

Bonneville 2017 Comments at 11-12.

958 Indicated NYTOs 2017 Comments at 15.

959 Duke 2017 Comments at 25; NYISO 2017 Comments at 45.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 329 -

go through the formal large generator interconnection process.960 Similarly, Schulte 

Associates suggests that an energy storage resource should be able to interconnect as a 

generator under the LGIP and LGIA and the electric storage resource should be able to 

also act as a transmission asset, if applicable.961 

541. Other commenters, primarily the RTOs/ISOs, believe current modeling practices 

are adequate for the interconnection of electric storage resources.962 ISO-NE and PJM 

state that their modeling practices are able to study storage resources when they are either 

charging or discharging energy.963 NYISO adds that modeling electric storage resources 

can be challenging because it depends on the services the resource wants to provide, but 

that current modeling approaches are sufficient as long as the interconnection customer 

provides accurate modeling data and validation of such data.964 CAISO states that its 

stakeholders support CAISO’s modeling of electric storage resources’ charging function 

as “negative generation” in lieu of conducting traditional firm load studies, which some 

participants and commenters identified as a best practice during the Commission’s 2016 

 960 Public Interest Organizations 2017 Comments at 8-9.

961 Schulte Associates 2017 Comments at 4.

962 CAISO 2017 Comments at 36-37; ISO-NE 2017 Comments at 55; MISO 2017 

Comments at 39; NYISO 2017 Comments at 45; PJM 2017 Comments at 31; 

AVANGRID 2017 Comments at 25. 

963 ISO-NE 2017 Comments at 55; PJM 2017 Comments at 31.

964 NYISO 2017 Comments at 45.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 330 -

Technical Conference and in post-technical conference comments.965 Idaho Power asks 

the Commission to elaborate on the size and capacity of electric storage resources to be 

evaluated.966

542. Schulte Associates suggests that electric storage resources should be able to 

propose consideration as a transmission asset under the pro forma LGIP and the pro 

forma LGIA and that this would require the RTOs/ISOs to consider the potential benefits 

and costs to the transmission system as part of its modeling methods going forward.967 

ESA, NextEra, TVA, and Xcel support modeling an electric storage resource based on its 

intended use,968 and MISO and Duke provide examples of specific information 

interconnection customers should provide.969

543. Some commenters argue that there is a need for clear modeling guidelines for 

electric storage resources. MISO and ESA recommend that the Commission require a 

consistent means by which transmission providers and system operators model electric 

 965 CAISO 2017 Comments at 37.

966 Idaho Power 2017 Comments at 7.

967 Schulte Associates 2017 Comments at 4.

968 ESA 2017 Comments at 17-18; NextEra 2017 Comments at 54; TVA 2017 

Comments at 18-19; Xcel 2017 Comment at 23.

969 Duke 2017 Comments at 26-27; MISO 2017 Comments at 39.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 331 -

storage charging.970 Several commenters support the “negative generation” approach 

employed in CAISO.971 

c. Commission Determination

544. In consideration of the comments, we decline to move forward with any 

requirements for modeling electric storage resources in this Final Rule. We agree with 

commenters that modeling electric storage resources as a single asset, as opposed to 

separate generation and load assets, and based on their intended use has merits. These 

approaches could streamline the interconnection of electric storage resources, save costs, 

and avoid modeling the charging of electric storage resources the same as other 

unpredictable, non-controllable load resources. However, given the limited experience 

interconnecting electric storage resources and the abundant desire for regional flexibility, 

we are not imposing any standard requirements at this time and instead continue to allow 

transmission providers to model electric storage resources in ways that are most 

appropriate in their respective regions. Additionally, in response to Schulte Associates, 

we are not requiring Transmission Providers to model electric storage resources serving 

as transmission assets under the pro forma LGIP and the pro forma LGIA at this time. 

Given the flexibility that we are providing, we find that gathering additional information 

on potential approaches for modeling electric storage resources is not necessary at this 

 970 MISO 2017 Comments at 39; ESA 2017 Comments at 16-17.

971 Id. at 17; NextEra 2017 Comments at 53; PG&E 2017 Comments at 9.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 332 -

time, but we encourage transmission providers to continue to consider approaches to 

modeling electric storage resources that will save costs and improve the efficiency of the 

interconnection process.

D. Other Issues

1. Whether Proposed Reforms Should Be Applied to Small 

Generation

a. Comments

545. In response to the Commission’s question in the NOPR,972 several commenters 

suggest that new proposals accepted for the LGIP and LGIA should also apply to the 

SGIP and SGIA.973 Joint Renewable Parties also contend that improved transparency 

would assist small generators in locating their facilities and moving through the 

interconnection process efficiently and cost-effectively.974 ESA supports extending the 

proposals regarding interconnection service below facility capacity, surplus 

interconnection service, provisional interconnection service, and electric storage 

modeling to apply to the pro forma SGIA and SGIP.975 California Energy Storage 

Alliance also suggests that the Commission consider simplified procedures for 

 972 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 11.

973 California Energy Storage Alliance 2017 Comments at 11; Joint Renewable 

Parties 2017 Comments at 3; ISO-NE 2017 Comments at 56.

974 Joint Renewable Parties 2017 Comments at 11.

975 ESA 2017 Comments at 18.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 333 -

interconnecting distributed electric storage resources that desire to participate in 

wholesale markets, either as a standalone resources or as part of an aggregation.976 TVA 

states that the small generator interconnection process could benefit from the proposed 

reforms and discussions involving affected system studies and any guidelines for 

modeling and evaluating electric storage resources.977

546. Others argue that the proposed reforms should not apply to small generating 

facilities.978 Duke, for instance, argues that the SGIP and SGIA processes are designed to 

be streamlined and that states use the processes as the bases for state small generator 

interconnection processes.979 Modesto asserts that, if the Commission believes it should 

make comparable revisions to the SGIP and SGIA, such revisions should be subject to 

appropriate notice and comment rulemaking procedures.980 Xcel states that if the 

Commission wishes to pursue this possibility, it should initiate a notice of inquiry.981 

 976 California Energy Storage Alliance 2017 Comments at 11-13.

977 TVA 2017 Comments at 19.

978 Duke 2017 Comments at 3-4; Modesto 2017 Comments at 22; SoCal Edison 

2017 Comments at 2; Xcel 2017 Comments at 5; see also Imperial 2017 Comments 20-

21.

979 Duke 2017 Comments at 3-4.

980 Modesto April 2017 Comments at 22; Xcel 2017 Comments at 5.

981 Id.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 334 -

547. PG&E and SoCal Edison ask the Commission to confirm that the NOPR does not 

require changes to PG&E’s wholesale distribution access tariff and GIPs, which primarily 

concern SGIAs.982 PG&E states that the administrative burden and costs of doing so 

outweighs the benefits.983 PG&E states that, as explained in section 2.13 of the 

wholesale distribution access tariff, such interconnection facilities are considered 

distribution facilities for purposes of the wholesale distribution access tariff.984 

b. Commission Determination

548. We decline to make the new requirements from this Final Rule applicable to the 

pro forma SGIP and the pro forma SGIA. Although the Commission sought comment on 

whether any of the proposed reforms should be applied to small generating facilities and 

implemented in the pro forma SGIP and pro forma SGIA, the Commission did not make 

any specific proposals as to the pro forma SGIP or pro forma SGIA. We also note that 

the majority of responsive commenters oppose such a change.985 

549. In response to the parties that support adopting the Final Rule reforms for small 

generators, we find that, while some of these reforms have the potential to aid small 

 982 PG&E 2017 Comments at 2; SoCal Edison 2017 Comments at 1-2.

983 PG&E 2017 Comments at 2.

984 Id. (citing Pac. Gas & Elec. Co., 77 FERC ¶ 61,077 (1996); see also SoCal 

Edison 2017 Comments at 1-2.

985 Duke 2017 Comments at 3-4; Modesto 2017 Comments at 22; SoCal Edison 

2017 Comments at 2; Xcel 2017 Comments at 5; see also Imperial 2017 Comments 20-

21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 335 -

generator interconnection, the differences between the large and small interconnection 

processes are significant enough to prevent us from acting in this proceeding. 

2. Issues Not Raised in the NOPR

a. Comments

550. Multiple commenters have commented on issues not raised in the NOPR. For 

instance, Joint Renewable Partners argue that the Commission has allowed the states to 

continue to administer Qualifying Facility (QF) interconnections where the QF sells the 

entire net output to the interconnecting utility, which has resulted in less favorable 

interconnection practices for QFs.986 Additionally, IECA urges the Commission to alter 

the QF minimum export threshold to be based on “total energy” exported to the grid and 

not on net system capacity because the current system discriminates against combined 

heat and power and waste heat recovery facilities in favor of other types of facilities.987 

Forecasting Coalition states that rates for interconnection service will decrease, and 

reliability will increase, if LGIPs require transmission providers to consider nontransmission alternatives, including dynamic line ratings.988 First Solar states that there is 

also significant misalignment in CAISO’s deliverability allocation procedures where 

upgrade cost caps deprive generators of the ability to deliver a plant’s full output, which 

 986 Joint Renewable Parties 2017 Comments at 13-15.

987 IECA 2017 Comments at 3.

988 Forecasting Coalition 2017 Comments at 1.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 336 -

can prevent interconnection customers from competing in solicitations or force them to 

withdraw from the queue.989 Invenergy argues that the Commission should update pro 

forma LGIA article 5.17 to incorporate recent changes in the Internal Revenue Service 

safe harbor rules.990 CAISO, Xcel, and Southern express views that the Commission 

move away from a first-come, first-served standard to a first-ready, first-served

standard.991 

b. Commission Determination 

551. We consider the comments summarized in the above section to be outside the 

scope of this proceeding. The NOPR proposed a number of specific reforms, to which 

commenters have reacted. The comments discussed in the above section have raised 

issues unrelated to the NOPR’s proposed reforms. Even if we were inclined to agree with 

the proposals made in these comments, we would not adopt them here given the 

inadequacy of the record on such proposals. 

3. Process Considerations 

a. Comments

552. Duke recommends that any new information required to be posted on OASIS be 

permitted to be posted without requiring new templates to be created through the NAESB 

 989 First Solar 2017 Comments at 1.

990 Invenergy 2017 comments at 16.

991 CAISO 2017 Comments at 38-39; Xcel 2017 Comments at 6-7; Southern 2017 

Comments at 6.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 337 -

process.992 OATI states that if the Final Rule requires new informational postings by 

transmission providers, the Commission should direct the nature and standards for those 

postings to NAESB.993 OATI states that access to any additional postings made on a 

transmission provider’s OASIS site requires secure and controlled access. OATI asks the 

Commission to assess the impact of new information on OASIS to decide if OASIS is the 

appropriate location for additional information and, if so, determine how currently 

available information on OASIS is accessed, and what would be necessary to post 

additional information.994

b. Commission Determination

553. We decline to specifically require that transmission providers work through 

NAESB for the development of templates or standards for any OASIS postings they 

make in compliance with this Final Rule. Transmission providers may coordinate as they 

determine appropriate to implement the Commission’s requirements and to develop 

relevant posting protocols. Additionally, we note that, in this Final Rule, we adopt 

OASIS requirements for the “Transparency Regarding Study Models and Assumptions” 

and “Interconnection Study Deadlines” sections. Additionally, in the “Transparency 

Regarding Study Models and Assumptions” and “Interconnection Study Deadlines” 

 992 Duke 2017 Comments at 28.

993 OATI 2017 Comments at 1-2.

994 Id. at 7.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 338 -

adopted requirements, we allow transmission providers to only include a link on OASIS

to the information required if it is posted on the transmission provider’s website. 

4. Compliance and Implementation 

a. Comments

554. EEI, Duke, ITC, MISO TOs, and Xcel request that the Commission allow 180 

days for compliance with any Final Rule.995 Duke and ITC also request a date of one 

year after the Final Rule for implementation of the revised OATTs included in the 

compliance filings.996 

b. Commission Determination

555. Section 35.28(f)(1) of the Commission’s regulations requires every public utility 

with a non-discriminatory OATT on file to also have on file the pro forma LGIP and pro 

forma LGIA “required by Commission rulemaking proceedings promulgating and 

amending” such agreements. Despite the comments described above, we see no reason to 

delay the effective date or extend the compliance deadline of this Final Rule. Therefore, 

the Commission is requiring all public utility transmission providers to submit 

compliance filings to adopt the requirements of this Final Rule as revisions to the LGIP 

 995 EEI 2017 Comments at 77; Duke 2017 Comments at 28; ITC 2017 Comments 

at 21; MISO TOs 2017 Comments at 44; Xcel 2017 Comments at 23.

996 Duke 2017 Comments at 28; ITC 2017 Comments at 21.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 339 -

and LGIA in their OATTs no later than 90 days after the issuance of this Final Rule in the 

Federal Register.997

556. Some public utility transmission providers may have provisions in their existing 

LGIPs or LGIAs subject to the Commission’s jurisdiction that the Commission has 

deemed to be consistent with or superior to the pro forma LGIP or pro forma LGIA or

permissible under the independent entity variation standard or regional reliability 

standard.998 Where these provisions are modified by this Final Rule, public utility 

transmission providers must either comply with this Final Rule or demonstrate that these 

previously-approved variations continue to be consistent with or superior to the pro 

forma LGIP and pro forma LGIA as modified by this Final Rule or continue to be 

permissible under the independent entity variation standard or regional reliability 

standard.999 We also find that transmission providers that are not public utilities must

adopt the requirements of this Final Rule as a condition of maintaining the status of their 

safe harbor tariff or otherwise satisfying the reciprocity requirement of Order No. 888.1000

 997 NOPR, FERC Stats. & Regs. ¶ 32,719 at P 231.

998 See Order No. 792, 145 FERC ¶ 61,159 at P 270.

999 See 18 CFR 35.28(f)(1)(i) (2017).

1000 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,760-63.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 340 -

V. Information Collection Statement

557. The collection of information contained in this Final Rule is being submitted to the 

Office of Management and Budget (OMB) for review under section 3507(d) of the 

Paperwork Reduction Act of 1995.1001 OMB’s regulations,1002 in turn, require approval 

of certain information collection requirements imposed by agency rules. Upon approval 

of a collection(s) of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of a rule will not be 

penalized for failing to respond to the collection of information unless the collection of 

information displays a valid OMB control number.

558. The reforms adopted in this Final Rule revise the Commission’s 

pro forma LGIP and pro forma LGIA. This Final Rule requires each public utility 

transmission provider to amend its LGIP and LGIA to: (1) remove the limitation that 

interconnection customers may only exercise the option to build transmission provider’s 

interconnection facilities and stand alone network upgrades in instances when the 

transmission owner cannot meet the dates proposed by the interconnection customer; 

(2) require that transmission providers establish interconnection dispute resolution 

procedures that would allow a disputing party to unilaterally seek non-binding dispute 

resolution; (3) require transmission providers to outline and make public a method for 

 1001 See 44 U.S.C. 3507(d) (2012).

1002 5 CFR 1320 (2017).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 341 -

determining contingent facilities; (4) require transmission providers to list the specific 

study processes and assumptions for forming the network models used for 

interconnection studies; (5) revise the definition of “Generating Facility” to explicitly 

include electric storage resources; (6) establish reporting requirements for aggregate 

interconnection study performance; (7) allow interconnection customers to request a level 

of interconnection service that is lower than their generating facility capacity; (8) require 

transmission providers to allow for provisional interconnection agreements that provide 

for limited operation prior to completion of the full interconnection process; (9) require 

transmission providers to create a process for interconnection customers to use surplus 

interconnection service at existing points of interconnection; and (10) require 

transmission providers to set forth a procedure to allow transmission providers to assess 

and, if necessary, study an interconnection customer’s technology changes without 

affecting the interconnection customer’s queued position. The reforms adopted in this 

Final Rule require revised filings of LGIPs and LGIAs with the Commission. The 

Commission anticipates the revisions required by this Final Rule, once implemented, will 

not significantly change currently existing burdens on an ongoing basis. With regard to 

those public utility transmission providers that believe they already comply with the 

revisions adopted in this Final Rule, they can demonstrate their compliance in the filing 

required 90 days after the issuance of this Final Rule in the Federal Register. The 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 342 -

Commission will submit the proposed reporting requirements to OMB for its review and 

approval under section 3507(d) of the Paperwork Reduction Act.1003

559. While the Commission expects the revisions adopted in this Final Rule will 

provide significant benefits, the Commission understands that implementation can be a 

complex and costly endeavor. The Commission solicited comments on the accuracy of 

the provided burden and cost estimates and any suggest methods for minimizing the 

respondents’ burdens. The Commission did not receive any comments concerning its 

burden or cost estimates. However, the Commission has made changes to its NOPR

proposals that are adopted in this Final Rule. First, the Commission has withdrawn the 

proposals regarding scheduled periodic restudies, self-funding by the transmission owner, 

and modeling of electric storage resources. Second, the Commission has modified the 

dispute resolution requirements so that they will apply both inside and outside 

RTOs/ISOs. Therefore, we have adjusted the burden estimate accordingly.

Burden Estimate and Information Collection Costs: The Commission believes that the 

burden estimates below are representative of the average burden on respondents. The 

estimated burden and cost1004 for the requirements contained in this Final Rule follow. 

 1003 44 U.S.C. 3507(d) (2012).

1004 The estimated hourly cost (salary plus benefits) provided in this section is 

based on the salary figures for May 2016 posted by the Bureau of Labor Statistics for the 

Utilities sector (available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000) and 

scaled to reflect benefits using the relative importance of employer costs in employee 

compensation from June 2016 (available at 

(continued ...)

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 343 -

FERC 516F

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses per 

Respondent

(2) )

Total Number 

of Responses

(1)*(2)=(3)

Average Burden 

(Hours) & Costs 

per Response

(4)

Total Annual 

Burden Hours & 

Total Annual Cost

(3)*(4)=(5)

Issue A1 –

Scheduled periodic 

restudies1005

126 N/A N/A N/A N/A

6 N/A N/A N/A N/A

Issue A2 –

Interconnection 

customer’s option 

to build (NonRTO/ISO)

126 1 (Year 1);

0 (Ongoing)1006

126 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308 

0 hrs. (Ongoing)

$0

504 hrs. (Year 1);

$38,808 

0 hrs. (Ongoing);

$0 

Issue A2 –

Interconnection 

customer’s option 

to build (RTO/ISO)

6 1 (Year 1);

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308

0 hrs. (Ongoing)

$0

24 hrs. (Year 1);

$1,848

0 (Ongoing)

$0 

 

https://www.bls.gov/oes/current/naics2_22.htm). The hourly estimates for salary plus 

benefits are: 

Auditing and accounting (code 13-2011), $53.00 

Computer and Information Systems Manager (code 11-3021), $100.68 

Computer and mathematical (code 15-0000), $60.70 

Economist (code 19-3011), $77.96 

Electrical Engineer (code 17-2071), $68.12 

Information and record clerk (code 43-4199), $39.14 

Information Security Analyst (code 15-1122), $66.34

Legal (code 23-0000), $143.68

Management (code 11-0000), $81.52 

The average hourly cost (salary plus benefits), weighting all of these skill sets evenly, is 

$76.79. The Commission rounds it to $77 per hour.

1005 There are no estimates for this section, because the Commission has 

withdrawn the NOPR proposal.

1006 Ongoing refers to Year 2 and ongoing.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 344 -

FERC 516F

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses per 

Respondent

(2) )

Total Number 

of Responses

(1)*(2)=(3)

Average Burden 

(Hours) & Costs 

per Response

(4)

Total Annual 

Burden Hours & 

Total Annual Cost

(3)*(4)=(5)

Issue A3 – Selffunding by the 

transmission 

owner1007 (NonRTO/ISO)

126 N/A N/A N/A N/A

Issue A3 – Selffunding by the 

transmission owner

(RTO/ISO)

6 N/A N/A N/A N/A

Issue A4 –

RTO/ISO dispute 

resolution (NonRTO/ISO)

126 1 (Year 1);

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308 

0 hrs. (Ongoing)

504 hrs. (Year 1);

$38,808

0 hrs. (Ongoing);

$0

Issue A4 -

RTO/ISO dispute 

resolution

(RTO/ISO)

6 1 (Year 1);

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308

0 hrs. (Ongoing)

24 hrs. (Year 1);

$1,848

0 (Ongoing)

$0 

Issue A5 – Capping 

costs for network 

upgrades1008 (NonRTO/ISO)

126 N/A N/A N/A N/A

Issue A5 – Capping 

costs for network 

upgrades

(RTO/ISO)

6 N/A N/A N/A N/A

Issue B1 –

Identification and 

definition of 

contingent facilities

(Non-RTO/ISO)

126 1 (Year 1);

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160 

0 hrs.; (Ongoing);

$0 

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

$0

Issue B1 –

Identification and 

definition of 

contingent facilities

(RTO/ISO)

6 1 (Year 1);

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

480 hrs. (Year 1);

$36,960;

0 hrs. (Ongoing);

$0

 1007 There are no estimates for this section, because the Commission has 

withdrawn the NOPR proposal.

1008 There are no estimates for this issue, because the NOPR did not propose, and 

the Final Rule did adopt, any requirements for this issue.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 345 -

FERC 516F

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses per 

Respondent

(2) )

Total Number 

of Responses

(1)*(2)=(3)

Average Burden 

(Hours) & Costs 

per Response

(4)

Total Annual 

Burden Hours & 

Total Annual Cost

(3)*(4)=(5)

Issue B2 –

Transparency in the 

interconnection 

process (NonRTO/ISO)

126 1 (Year 1);

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160 

0 hrs.; (Ongoing);

$0

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

$0

Issue B2 –

Transparency in the 

interconnection 

process (RTO/ISO)

6 1 (Year 1)

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

480 hrs. (Year 1);

$36,960 

0 hrs. (Ongoing);

$0

Issue B3 –

Curtailment 

concerns (NonRTO/ISO)

126 N/A N/A N/A N/A

Issue B3 –

Curtailment 

concerns

(RTO/ISO)

6 N/A N/A N/A N/A

Issue B4 –

Definition of 

generating facility

(non-RTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160 

0 hrs.; (Ongoing);

$0

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

$0 

Issue B4 –

Definition of 

generating facility

(RTO/ISO)

6 1 (Year 1)

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160 

0 hrs.; (Ongoing);

$0

480 hrs. (Year 1);

$36,960;

0 hrs. (Ongoing);

$0

Issue B5 –

Interconnection 

study deadlines

(non-RTO/ISO)

126 1 (Year 1)

4 (Ongoing)

126 (Year 1);

504 (Ongoing)

4 hrs. (Year 1);

$308

4 hrs. (Ongoing)

$308

504 hrs. (Year 1);

$38,808

2,016 hrs. (Ongoing);

$155,232

Issue B5 –

Interconnection 

study deadlines

(RTO/ISO)

6 1 (Year 1)

4 (Ongoing)

6 (Year 1);

24 (Ongoing)

4 hrs. (Year 1);

$308

4 hrs. (Ongoing)

$308

24 hrs. (Year 1);

$1,848

96 hrs. (Ongoing);

7,392

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 346 -

FERC 516F

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses per 

Respondent

(2) )

Total Number 

of Responses

(1)*(2)=(3)

Average Burden 

(Hours) & Costs 

per Response

(4)

Total Annual 

Burden Hours & 

Total Annual Cost

(3)*(4)=(5)

Issue B6 –

Improving 

Coordination of 

Affected 

Systems1009 (nonRTO/ISO)

126 N/A N/A N/A N/A

Issue B6 –

Improving 

Coordination of 

Affected Systems

(RTO/ISO)

6 N/A N/A N/A N/A

Issue C1 –

Requesting 

interconnection 

service below 

generating facility 

capacity (NonRTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

$0

Issue C1 –

Requesting 

interconnection 

service below 

generating facility 

capacity (RTO/ISO)

6 1 (Year 1)

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

480 hrs. (Year 1);

$36,960 

0 hrs. (Ongoing);

$0

Issue C2 –

Provisional 

agreements (nonRTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

$0

Issue C2 –

Provisional 

agreements

(RTO/ISO)

6 1 (Year 1)

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

480 hrs. (Year 1);

$36,960 

0 hrs. (Ongoing);

$0

 1009 There are no estimates for this issue, because the NOPR did not propose, and 

the Final Rule did adopt, any requirements for this issue.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 347 -

FERC 516F

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses per 

Respondent

(2) )

Total Number 

of Responses

(1)*(2)=(3)

Average Burden 

(Hours) & Costs 

per Response

(4)

Total Annual 

Burden Hours & 

Total Annual Cost

(3)*(4)=(5)

Issue C3 –

Utilization of 

surplus 

interconnection 

service (nonRTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308

0 hrs. (Ongoing)

$0

504 hrs. (Year 1);

$38,808

0 hrs. (Ongoing);

$0

Issue C3 –

Utilization of 

surplus 

interconnection 

service (RTO/ISO)

6 1 (Year 1)

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308

0 hrs. (Ongoing)

$0

24 hrs. (Year 1);

$1,848

0 (Ongoing)

$0 

Issue C4 – Material 

modification and 

incorporation of 

advanced 

technologies (nonRTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

$0

Issue C4 – Material 

modification and 

incorporation of 

advanced 

technologies

(RTO/ISO)

6 1 (Year 1)

0 (Ongoing)

6 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

$0 

480 hrs. (Year 1);

$36,960 

0 hrs. (Ongoing);

$0

Issue C5 –

Modeling of 

electric storage 

resources1010 (nonRTO/ISO)

126 N/A N/A N/A N/A

Issue C5 –

Modeling of 

electric storage 

resources

(RTO/ISO)

6 N/A N/A N/A N/A

Total Non-RTO/ISO, Year 1 1,260 62,244 hrs.; $4,792,788

Non-RTO/ISO, Ongoing 504 2,016 hrs.; $155,232

RTO/ISO, Year 1 60 2,976 hrs.; $229,152

RTO/ISO, Ongoing 24 96 hrs.; $7,392

Cost to Comply: The Commission has projected the cost of compliance as follows:

 1010 There are no estimates for this section, because the Commission has 

withdrawn the NOPR proposal.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 348 -

 Year 1: $5,021,940

 Ongoing: $162,624

Year 1 costs reflect costs to comply with the Final Rule. Year 2 represents ongoing costs 

that the transmission provider will face on an ongoing basis to fulfill the directives of this 

Final Rule. The reforms adopted in this Final Rule, once implemented, would not 

significantly change existing burdens on an ongoing basis.

The one-time burden of 65,220 hours will be averaged over three years (65,220 ÷ 3 = 

21,740 hours/year over three years).

The ongoing burden of 2,112 hours applies to only Year 2 and beyond.

The number of responses is also averaged over three years (1,320 responses (one-time) + 

528 responses (Year 2) + 528 responses (Year 3)) ÷ 3 = 792 responses/year.

The responses and burden for Years 1-3 will total respectively as follows:

Year 1: 792 responses; 21,740 hours.

Year 2: 792 responses; 21,740 hours + 2,112 hours + 2,112 hours = 25,964 hours.

Year 3: 792 responses; 21,740 hours + 2,112 hours + 2,112 hours = 25,964 hours.

Title: FERC-516F, Electric Rate Schedules and Tariff Filings.

Action: Proposed information collection.

OMB Control No.: TBD

Respondents for Proposal: Businesses or other for profit and/or not-for-profit 

institutions.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 349 -

Frequency of Information: One-time during Year 1. Multiple times during subsequent 

years.

Necessity of Information: The Commission issues this Final Rule to address 

interconnection practices that may be resulting in unjust and unreasonable or unduly 

discriminatory or preferential rates, terms, and conditions. The reforms are designed to 

improve certainty in the interconnection process, to promote more informed 

interconnection decisions by interconnection customers, and to enhance interconnection 

processes.

Internal Review: The Commission has reviewed the proposed changes and has 

determined that such changes are necessary. These requirements conform to the 

Commission’s need for efficient information collection, communication, and 

management within the energy industry. The Commission has specific, objective support 

for the burden estimates associated with the information collection requirements.

560. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873.

561. Comments concerning the collection of information and the associated burden 

estimate(s) in the Final Rule should be sent to the Commission in this docket and may 

also be sent to the Office of Information and Regulatory Affairs, Office of Management 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 350 -

and Budget, 725 17th Street, NW, Washington, DC 20503 [Attention: Desk Officer for 

the Federal Energy Regulatory Commission,]. 

562. Due to security concerns, comments should be sent electronically to the following 

email address: oira_submission@omb.eop.gov. Comments submitted to OMB should 

refer to FERC-516F and OMB Control No. to be determined.

VI. Environmental Analysis

563. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.1011 The Commission concludes that neither an 

Environmental Assessment nor an Environmental Impact Statement is required for this 

Final Rule under section 380.4(a)(15) of the Commission’s regulations, which provides a 

categorical exemption for approval of actions under sections 205 and 206 of the FPA 

relating to the filing of schedules containing all rates and charges for the transmission or 

sale of electric energy subject to the Commission’s jurisdiction, plus the classification, 

practices, contracts, and regulations that affect rates, charges, classification, and 

services.1012 

 1011 Regulation Implementing National Environmental Policy Act of 1969, Order 

No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).

1012 18 CFR 380.4(a)(15) (2017).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 351 -

VII. Regulatory Flexibility Act

564. The Regulatory Flexibility Act of 1980 (RFA)1013 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a rule and that minimize any significant economic 

impact on a substantial number of small entities. The Small Business Administration’s 

(SBA) Office of Size Standards develops the numerical definition of a small business.1014

The small business size standards are provided in 13 CFR 121.201.

565. The Commission estimates that the total number of public utility transmission 

providers that would have to modify the LGIPs and LGIAs within their currently 

effective OATTs is 132. Of these, the Commission estimates that approximately 43 

percent are small entities (approximately 57 entities). The Commission estimates the 

average total cost to each of these entities will require on average 494 hours or $38,045 in 

Year 1, 1015 and 16 hours or $1,232 in subsequent years. 1016 According to SBA 

guidance, the determination of significance of impact “should be seen as relative to the 

 1013 5 U.S.C. 601-12 (2012).

1014 13 CFR 121.101 (2017) Sector 22 (Utilities), NAICS code 22121 (Electric 

Power Transmission and Control).

1015 65,220 hours ÷ 132 = 494 hours/respondent; $5,021,940 ÷ 132 = 

$38,045/respondent.

1016 2,112 hours ÷ 132 = 16 hours/respondent; $162,624 ÷ 132 = 

$1,232/respondent.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 352 -

size of the business, the size of the competitor’s business, and the impact the regulation 

has on larger competitors.”1017 The Commission does not consider the estimated burden

to be a significant economic impact. As a result, the Commission certifies that the 

revisions adopted in this Final Rule will not have a significant economic impact on a 

substantial number of small entities.

VIII. Document Availability

566. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington, DC 20426.

567. From the Commission’s Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number of this document, excluding the last three 

digits, in the docket number field.

 1017 U.S. Small Business Administration, A Guide for Government Agencies: How 

to Comply with the Regulatory Flexibility Act, at 18 (August 2017), 

https://www.sba.gov/sites/default/files/advocacy/How-to-Comply-with-the-RFAWEB.pdf.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 353 -

568. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from the Commission’s Online Support at (202) 502-6652 (toll 

free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

IX. Effective Date and Congressional Notification

569. The Final Rule is effective 75 days from the date the rule is published in the 

Federal Register. The Commission has determined with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB that this rule 

is not a “major rule” as defined in section 351 of the Small Business Regulatory 

Enforcement Fairness Act of 1996. This Final Rule is being submitted to the U.S. 

Senate, the U.S. House of Representatives, and the U.S. Government Accountability 

Office.

List of Subjects in 18 CFR Part 37 

Conflicts of interest, Electric power plants, Electric utilities, Reporting and 

recordkeeping requirements

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 354 -

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 355 -

Note: Appendix A will not be published in the Federal Register.

Appendix A: List of Short Names of Commenters on the NOPR

Short Name or Acronym Commenter

AEP American Electric Power Service Corporation, 

on behalf of the operating companies of the 

American Electric Power system

AES Indianapolis Power & Light Company, 

The Dayton Power and Light Company, AES 

Storage LLC, AES ES Tait LLC, AES 

Distributed Energy and all other AES U.S. 

operating companies that own generation and 

storage

AFPA American Forest & Paper Association

Alevo Alevo USA Inc.

Alliance for Clean Energy Alliance for Clean Energy New York, Inc.

Alliant Alliant Energy Corporate Services, Inc.

APPA/LPPC American Public Power Association and Large 

Public Power Council

APS Arizona Public Service Company

AVANGRID AVANGRID, Inc.

AWEA American Wind Energy Association

Bonneville Bonneville Power Administration

CAISO California Independent System Operator, Corp.

California Energy Storage Alliance California Energy Storage Alliance

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 356 -

Cogeneration Association Cogeneration Association of California

Competitive Suppliers Electric Power Suppliers Association and 

the PJM Providers Group

Duke Duke Energy Corporation

EDP EDP Renewables North America LLC

EEI Edison Electric Institute

ELCON Electricity Consumers Resource Council

ESA Energy Storage Association

Eversource Eversource Energy Service Company

Exelon Exelon Corporation

First Solar First Solar, Inc.

Forecasting Coalition Dynamic Line Rating/Transmission 

Capacity Forecasting Coalition

FTC Federal Trade Commission Staff

Generation Developers EDF Renewable Energy, Inc., E.ON

Climate & Renewables North America, 

LLC and Enel Green Power North 

America, Inc.

Idaho Power Idaho Power Company

IECA Industrial Energy Consumers of America

Imperial Imperial Irrigation District

Indicated NYTOs Central Hudson Gas & Electric 

Corporation, Consolidated Edison 

Company of New York, Inc., Power 

Supply Long Island, New York Power 

Authority, Niagara Mohawk Power 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 357 -

Corporation, and Orange and Rockland 

Utilities, Inc.

Invenergy Invenergy Wind Development LLC, 

Invenergy Thermal Development LLC, 

Invenergy Storage Development LLC, 

and Invenergy Solar Development LLC

ISO-NE ISO New England Inc.

ITC International Transmission Company, 

Michigan Electric Transmission 

Company, LLC, ITC Midwest LLC, and 

ITC Great Plains, LLC

Joint Renewable Parties Community Renewable Energy 

Association and Renewable Energy

Coalition

MidAmerican MidAmerican Energy Company

MISO Midcontinent Independent System 

Operator, Inc.

MISO TOs Ameren Services Company, as agent for 

Union Electric Company, Ameren 

Illinois Company and Ameren 

Transmission Company of Illinois; 

American Transmission Company LLC; 

Big Rivers Electric Corporation; Central 

Minnesota Municipal Power Agency; 

City Water, Light & Power (Springfield, 

IL); Cleco Power LLC; Cooperative 

Energy; Dairyland Power Cooperative; 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 358 -

Duke Energy Business Services, LLC for 

Duke Energy Indiana, LLC; East Texas 

Electric Cooperative; Entergy Arkansas, 

Inc.; Entergy Louisiana, LLC; Entergy 

Mississippi, Inc.; Entergy New Orleans, 

Inc.; Entergy Texas, Inc.; Great River 

Energy; Hoosier Energy Rural Electric 

Cooperative, Inc.; Indiana Municipal 

Power Agency; Indianapolis Power & 

Light Company; International 

Transmission Company; ITC Midwest 

LLC; Michigan Electric Transmission 

Company, LLC; MidAmerican Energy 

Company; Minnesota Power (and its 

subsidiary Superior Water, L&P); 

Missouri River Energy Services; 

Montana-Dakota Utilities Co.; Northern 

Indiana Public Service Company; 

Northern States Power Company, a 

Minnesota corporation, and Northern 

States Power Company, a Wisconsin 

corporation, subsidiaries of Xcel Energy 

Inc.; Northwestern Wisconsin Electric 

Company; Otter Tail Power Company; 

Prairie Power Inc.; Southern Illinois 

Power Cooperative; Southern Indiana 

Gas & Electric Company; Southern 

Minnesota Municipal Power Agency; 

Wabash Valley Power Association, Inc.; 

and Wolverine Power Supply 

Cooperative, Inc.

Modesto Modesto Irrigation District

National Grid Niagara Mohawk Power Corporation, 

New England Power Company, New 

England Electric Transmission 

Corporation, New England HydroTransmission Corporation, New England 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 359 -

Hydro-Transmission Electric Company, 

Inc., The Narragansett Electric 

Company, and Massachusetts Electric 

Company

NEPOOL New England Power Pool Participants 

Committee

NextEra NextEra Energy Resources, LLC

Non-Profit Utility Trade Associations American Public Power Association, the 

Large Public Power Council, and the 

National Rural Electric Cooperative 

Association

NorthWestern NorthWestern Corporation

NYISO New York Independent System 

Operator, Inc.

OATI Open Access Technology International, 

Inc.

PG&E Pacific Gas & Electric Company

PJM PJM Interconnection, L.L.C.

Portland Portland General Electric Company

PSEG/PPL Public Service Electric and Gas 

Company and PPL Electric Utilities 

Corporation

Public Interest Organizations Americans for a Clean Energy Grid, 

Environmental Law & Policy Center, 

Natural Resources Defense Council, 

Sierra Club Environmental Law 

Program, Southern Environmental Law 

Center, Union of Concern Scientists

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 360 -

Renewable and Storage Associations Advanced Energy Economy, Americans 

for a Clean Energy Grid, American 

Council on Renewable Energy, 

American Wind Energy Association, 

Energy Storage Association, and Solar 

Energy Industries Association

Salt River Salt River Project Agricultural 

Improvement and Power District

Schulte Associates Schulte Associates LLC

SEIA Solar Energy Industries Association

Six Cities Cities of Anaheim, Azusa, Banning, 

Colton, Pasadena, and Riverside, 

California 

SoCal Edison Southern California Edison Company

Southern Southern Company Services, Inc. as 

agent for Alabama Power Company,

Georgia Power Company, Gulf Power 

Company, and Mississippi Power 

Company

Sunflower Sunflower Electric Power Corporation 

and Mid-Kansas Electric Company, LLC

TAPS Transmission Access Policy Study 

Group

TDU Systems Transmission Dependent Utility Systems

Tri-State Tri-State Generation and Transmission 

Association, Inc.

TVA Tennessee Valley Authority

Xcel Xcel Energy Services, Inc.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 361 -

Note: Appendix B will not be published in the Federal Register. Square brackets 

indicate that the text should be filled in as appropriate by the transmission provider.

Appendix B: Compilation of Final Rule changes to the pro forma LGIP

The Commission modifies the following sections of the pro forma LGIP as indicated 

below:

Section 1. Definitions

Contingent Facilities shall mean those unbuilt interconnection facilities 

and network upgrades upon which the interconnection request’s costs, timing, and 

study findings are dependent, and if delayed or not built, could cause a need for 

restudies of the interconnection request or a reassessment of the interconnection 

facilities and/or network upgrades and/or costs and timing.

Generating Facility shall mean Interconnection Customer’s device for the 

production and/or storage for later injection of electricity identified in the 

Interconnection Request, but shall not include the interconnection customer’s 

Interconnection Facilities.

Permissible Technological Advancement [Insert definition 

here].Provisional Interconnection Service shall mean interconnection service 

provided by Transmission Provider associated with interconnecting the 

Interconnection Customer’s Generating Facility to Transmission Provider’s 

Transmission System and enabling that Transmission System to receive electric 

energy and capacity from the Generating Facility at the Point of Interconnection, 

pursuant to the terms of the Provisional Large Generator Interconnection 

Agreement and, if applicable, the Tariff.

Provisional Large Generator Interconnection Agreement shall mean the 

interconnection agreement for Provisional Interconnection Service established 

between Transmission Provider and/or the Transmission Owner and the 

Interconnection Customer. This agreement shall take the form of the Large 

Generator Interconnection Agreement, modified for provisional purposes.

Surplus Interconnection Service shall mean any unneeded portion of 

Interconnection Service established in a Large Generator Interconnection 

Agreement, such that if Surplus Interconnection Service is utilized the total 

amount of Interconnection Service at the Point of Interconnection would remain 

the same.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 362 -

2.3 Base Case Data.

Base Case Data. Transmission Provider shall maintain provide base power 

flow, short circuit and stability databases, including all underlying 

assumptions, and contingency list on either its OASIS site or a passwordprotected website, upon request subject to confidentiality provisions in 

LGIP Section 13.1. In addition, Transmission Provider shall maintain 

network models and underlying assumptions on either its OASIS site or a 

password-protected website. Such network models and underlying 

assumptions should reasonably represent those used during the most recent 

interconnection study and be representative of current system conditions. If 

Transmission Provider posts this information on a password-protected 

website, a link to the information must be provided on Transmission 

Provider’s OASIS site. Transmission Provider is permitted to require that 

Interconnection Customers, OASIS site users and password-protected 

website users sign a confidentiality agreement before the release of 

commercially sensitive information or Critical Energy Infrastructure 

Information in the Base Case data. Such databases and lists, hereinafter 

referred to as Base Cases, shall include all (1) generation projects and (2ii) 

transmission projects, including merchant transmission projects that are 

proposed for the Transmission System for which a transmission expansion 

plan has been submitted and approved by the applicable authority.

3.1 General 

An Interconnection Customer shall submit to Transmission Provider an 

Interconnection Request in the form of Appendix 1 to this LGIP and a 

refundable deposit of $10,000. Transmission Provider shall apply the 

deposit toward the cost of an Interconnection Feasibility Study. 

Interconnection Customer shall submit a separate Interconnection Request 

for each site and may submit multiple Interconnection Requests for a single 

site. Interconnection Customer must submit a deposit with each 

Interconnection Request even when more than one request is submitted for 

a single site. An Interconnection Request to evaluate one site at two 

different voltage levels shall be treated as two Interconnection Requests. 

At Interconnection Customer's option, Transmission Provider and 

Interconnection Customer will identify alternative Point(s) of 

Interconnection and configurations at the Scoping Meeting to evaluate in 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 363 -

this process and attempt to eliminate alternatives in a reasonable fashion 

given resources and information available. Interconnection Customer will 

select the definitive Point(s) of Interconnection to be studied no later than 

the execution of the Interconnection Feasibility Study Agreement. 

Transmission Provider shall have a process in place to consider requests for 

Interconnection Service below the Generating Facility Capacity. These 

requests for Interconnection Service shall be studied at the level of 

Interconnection Service requested for purposes of Interconnection 

Facilities, Network Upgrades, and associated costs, but may be subject to 

other studies at the full Generating Facility Capacity to ensure safety and 

reliability of the system, with the study costs borne by the Interconnection 

Customer. Any Interconnection Facility and/or Network Upgrade costs 

required for safety and reliability also would be borne by the 

Interconnection Customer. Interconnection Customers may be subject to 

additional control technologies as well as testing and validation of those 

technologies consistent with Article 6 of the LGIA. The necessary control 

technologies and protection systems as well as any potential penalties for 

exceeding the level of Interconnection Service established in the executed, 

or requested to be filed unexecuted, LGIA shall be established in Appendix 

C of that executed, or requested to be filed unexecuted, LGIA.

3.3 Utilization of Surplus Interconnection Service. 

Transmission Provider must provide a process that allows an 

Interconnection Customer to utilize or transfer Surplus Interconnection 

Service at an existing Point of Interconnection. The original 

Interconnection Customer or one of its affiliates shall have priority to 

utilize Surplus Interconnection Service. If the existing Interconnection 

Customer or one of its affiliates does not exercise its priority, then that 

service may be made available to other potential interconnection customers.

3.3.1 Surplus Interconnection Service Requests.

Surplus Interconnection Service requests may be made by the existing

Interconnection Customer whose Generating Facility is already 

interconnected or one of its affiliates. Surplus Interconnection Service 

requests also may be made by another Interconnection Customer. 

Transmission Provider shall provide a process for evaluating 

interconnection requests for Surplus Interconnection Service. Studies for 

Surplus Interconnection Service shall consist of reactive power, short 

circuit/fault duty, stability analyses, and any other appropriate studies. 

Steady-state (thermal/voltage) analyses may be performed as necessary to 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 364 -

ensure that all required reliability conditions are studied. If the Surplus 

Interconnection Service was not studied under off-peak conditions, offpeak steady state analyses shall be performed to the required level 

necessary to demonstrate reliable operation of the Surplus Interconnection 

Service. If the original System Impact Study is not available for the 

Surplus Interconnection Service, both off-peak and peak analysis may need 

to be performed for the existing Generating Facility associated with the 

request for Surplus Interconnection Service. The reactive power, short 

circuit/fault duty, stability, and steady-state analyses for Surplus 

Interconnection Service will identify any additional Interconnection 

Facilities and/or Network Upgrades necessary.

3.34 Valid Interconnection Request.

3.34.1 Initiating and Interconnection Request.

3.34.2 Acknowledgement of Interconnection Request.

3.43.5.1 OASIS Posting. 

3.5.2 Transmission Provider will maintain on its OASIS or its website summary 

statistics related to processing Interconnection Studies pursuant to 

Interconnection Requests, updated quarterly. If Transmission Provider 

posts this information on its website, a link to the information must be 

provided on Transmission Provider’s OASIS site. For each calendar 

quarter, Transmission Providers must calculate and post the information 

detailed in sections 3.5.2.1 through 3.5.2.4. 

3.5.2.1 Interconnection Feasibility Studies processing time.

(A) Number of Interconnection Requests that had Interconnection 

Feasibility Studies completed within Transmission Provider’s coordinated 

region during the reporting quarter, 

(B) Number of Interconnection Requests that had Interconnection 

Feasibility Studies completed within Transmission Provider’s coordinated 

region during the reporting quarter that were completed more than [timeline 

as listed in Transmission Provider’s LGIP] after receipt by Transmission 

Provider of the Interconnection Customer’s executed Interconnection 

Feasibility Study Agreement, 

(C) At the end of the reporting quarter, the number of active valid 

Interconnection Requests with ongoing incomplete Interconnection 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 365 -

Feasibility Studies where such Interconnection Requests had executed 

Interconnection Feasibility Study Agreements received by Transmission 

Provider more than [timeline as listed in Transmission Provider’s LGIP] 

before the reporting quarter end, 

(D) Mean time (in days), Interconnection Feasibility Studies completed 

within Transmission Provider’s coordinated region during the reporting 

quarter, from the date when Transmission Provider received the executed 

the Interconnection Feasibility Study Agreement to the date when 

Transmission Provider provided the completed Interconnection Feasibility 

Study to the Interconnection Customer, 

(E) Percentage of Interconnection Feasibility Studies exceeding [timeline as 

listed in Transmission Provider’s LGIP] to complete this reporting quarter, 

calculated as the sum of 3.5.2.1(B) plus 3.5.2.1(C) divided by the sum of 

3.5.2.1(A) plus 3.5.2.1(C)). 

3.5.2.2 Interconnection System Impact Studies processing time. 

(A) Number of Interconnection Requests that had Interconnection System 

Impact Studies completed within Transmission Provider’s coordinated 

region during the reporting quarter, 

(B) Number of Interconnection Requests that had Interconnection System 

Impact Studies completed within Transmission Provider’s coordinated 

region during the reporting quarter that were completed more than [timeline 

as listed in Transmission Provider’s LGIP] after receipt by Transmission 

Provider of the Interconnection Customer’s executed Interconnection 

System Impact Study Agreement, 

(C) At the end of the reporting quarter, the number of active valid 

Interconnection Requests with ongoing incomplete System Impact Studies 

where such Interconnection Requests had executed Interconnection System 

Impact Study Agreements received by Transmission Provider more than 

[timeline as listed in Transmission Provider’s LGIP] before the reporting 

quarter end, 

(D) Mean time (in days), Interconnection System Impact Studies completed 

within Transmission Provider’s coordinated region during the reporting 

quarter, from the date when Transmission Provider received the executed 

Interconnection System Impact Study Agreement to the date when 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 366 -

Transmission Provider provided the completed Interconnection System 

Impact Study to the Interconnection Customer, 

(E) Percentage of Interconnection System Impact Studies exceeding 

[timeline as listed in Transmission Provider’s LGIP] to complete this 

reporting quarter, calculated as the sum of 3.5.2.2(B) plus 3.5.2.2(C)

divided by the sum of 3.5.2.2(A) plus 3.5.2.2(C)).

3.5.2.3 Interconnection Facilities Studies processing time. 

(A) Number of Interconnection Requests that had Interconnection Facilities 

Studies that are completed within Transmission Provider’s coordinated 

region during the reporting quarter, 

(B) Number of Interconnection Requests that had Interconnection Facilities 

Studies that are completed within Transmission Provider’s coordinated 

region during the reporting quarter that were completed more than [timeline 

as listed in Transmission Provider’s LGIP] after receipt by Transmission 

Provider of the Interconnection Customer’s executed Interconnection 

Facilities Study Agreement, 

(C) At the end of the reporting quarter, the number of active valid 

Interconnection Service requests with ongoing incomplete Interconnection 

Facilities Studies where such Interconnection Requests had executed 

Interconnection Facilities Studies Agreement received by Transmission 

Provider more than [timeline as listed in Transmission Provider’s LGIP] 

before the reporting quarter end,

(D) Mean time (in days), for Interconnection Facilities Studies completed 

within Transmission Provider’s coordinated region during the reporting 

quarter, calculated from the date when Transmission Provider received the 

executed Interconnection Facilities Study Agreement to the date when 

Transmission Provider provided the completed Interconnection Facilities 

Study to the Interconnection Customer, 

(E) Percentage of delayed Interconnection Facilities Studies this reporting 

quarter, calculated as the sum of 3.5.2.3(B) plus 3.5.2.3(C) divided by the 

sum of 3.5.2.3(A) plus 3.5.2.3(C)). 

3.5.2.4 Interconnection Service requests withdrawn from interconnection 

queue.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 367 -

(A) Number of Interconnection Service requests withdrawn from 

Transmission Provider’s interconnection queue during the reporting 

quarter, 

(B) Number of Interconnection Service requests withdrawn from 

Transmission Provider’s interconnection queue during the reporting quarter 

before completion of any interconnection studies or execution of any 

interconnection study agreements, 

(C) Number of Interconnection Service requests withdrawn from 

Transmission Provider’s interconnection queue during the reporting quarter 

before completion of an Interconnection System Impact Study, 

(D) Number of Interconnection Service requests withdrawn from 

Transmission Provider’s interconnection queue during the reporting quarter 

before completion of an Interconnection Facility Study, 

(E) Number of Interconnection Service requests withdrawn from 

Transmission Provider’s interconnection queue after execution of a 

generator interconnection agreement or Interconnection Customer requests 

the filing of an unexecuted, new interconnection agreement, 

(F) Mean time (in days), for all withdrawn Interconnection Service 

requests, from the date when the request was determined to be valid to 

when Transmission Provider received the request to withdraw from the 

queue.

3.5.3 Transmission Provider is required to post on OASIS or its website the 

measures in paragraph 3.5.2.1(A) through paragraph 3.5.2.4(F) for each 

calendar quarter within 30 days of the end of the calendar quarter. 

Transmission Provider will keep the quarterly measures posted on OASIS 

or its website for three calendar years with the first required reporting year 

to be 2017. If Transmission Provider retains this information on its 

website, a link to the information must be provided on Transmission 

Provider’s OASIS site. 

3.5.4 In the event that any of the values calculated in paragraphs 3.5.2.1(E), 

3.5.2.2(E) or 3.5.2.3(E) exceeds 25 percent for two consecutive calendar 

quarters, Transmission Provider will have to comply with the measures 

below for the next four consecutive calendar quarters and must continue 

reporting this information until Transmission Provider reports four 

consecutive calendar quarters without the values calculated in 3.5.2.1(E), 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 368 -

3.5.2.2(E) or 3.5.2.3(E) exceeding 25 percent for two consecutive calendar 

quarters: 

(i) Transmission Provider must submit a report to the Commission 

describing the reason for each study or group of clustered studies pursuant 

to an Interconnection Request that exceeded its deadline (i.e., 45, 90 or 180 

days) for completion (excluding any allowance for Reasonable Efforts). 

Transmission Provider must describe the reasons for each study delay and 

any steps taken to remedy these specific issues and, if applicable, prevent 

such delays in the future. The report must be filed at the Commission 

within 45 days of the end of the calendar quarter. 

(ii) Transmission Provider shall aggregate the total number of employeehours and third party consultant hours expended towards interconnection 

studies within its coordinated region that quarter and post on OASIS or its 

website. If Transmission Provider posts this information on its website, a 

link to the information must be provided on Transmission Provider’s 

OASIS site. This information is to be posted within 30 days of the end of 

the calendar quarter.

3.56 Coordination with Affected Systems.

3.67 Withdrawal.

3.8 Identification of Contingent Facilities. Transmission Provider shall post 

in this section a method for identifying the Contingent Facilities to be 

provided to Interconnection Customer at the conclusion of the System 

Impact Study and included in Interconnection Customer’s GIA. The 

method shall be sufficiently transparent to determine why a specific 

Contingent Facility was identified and how it relates to the interconnection 

request. Transmission Provider shall also provide, upon request of the 

Interconnection Customer, the estimated interconnection facility and/or 

network upgrade costs and estimated in-service completion time of each 

identified Contingent Facility when this information is readily available and 

not commercially sensitive.

4.4.1 Prior to the return of the executed Interconnection System Impact Study 

Agreement to Transmission Provider, modifications permitted under this 

Section shall include specifically: (a) a decrease of up to 60 percent of 

electrical output (MW) of the proposed project, through either (1) a 

decrease in plant size or (2) a decrease in interconnection service level 

(consistent with the process described in Section 3.1) accomplished by 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 369 -

applying transmission provider-approved injection-limiting equipment; (b) 

modifying the technical parameters associated with the Large Generating 

Facility technology or the Large Generating Facility step-up transformer 

impedance characteristics; and (c) modifying the interconnection 

configuration. For plant increases, the incremental increase in plant output 

will go to the end of the queue for the purposes of cost allocation and study 

analysis.

4.4.2 Prior to the return of the executed Interconnection Facility Study 

Agreement to the Transmission Provider, the modifications permitted under 

this Section shall include specifically: (a) additional 15 percent decrease of 

electrical output of the proposed project through either (1) a decrease in in 

plant size (MW) or (2) a decrease in interconnection service level 

(consistent with the process described in Section 3.1) accomplished by 

applying transmission provider-approved injection-limiting equipment;, and 

(b) Large Generating Facility technical parameters associated with 

modifications to Large Generating Facility technology and transformer

impedances; provided, however, the incremental costs associated with those 

modifications are the responsibility of the requesting Interconnection 

Customer; and (c) a Permissible Technological Advancement for the Large 

Generating Facility after the submission of the interconnection request. 

Section 4.4.4 specifies a separate technological change procedure including 

the requisite information and process that will be followed to assess 

whether the Interconnection Customer’s proposed technological 

advancement under Section 4.4.2(c) is a Material Modification. Section 1 

contains a definition of Permissible Technological Advancement.

4.4.4 Technological Change Procedure.

[Insert technological change procedure here].

6.3 Interconnection Feasibility Study Procedures. 

Transmission Provider shall utilize existing studies to the extent practicable 

when it performs the study. Transmission Provider shall use Reasonable 

Efforts to complete the Interconnection Feasibility Study no later than 

forty-five (45) Calendar Days after Transmission Provider receives the 

fully executed Interconnection Feasibility Study Agreement. At the request 

of Interconnection Customer or at any time Transmission Provider 

determines that it will not meet the required time frame for completing the 

Interconnection Feasibility Study, Transmission Provider shall notify 

Interconnection Customer as to the schedule status of the Interconnection 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 370 -

Feasibility Study. If Transmission Provider is unable to complete the 

Interconnection Feasibility Study within that time period, it shall notify 

Interconnection Customer and provide an estimated completion date with 

an explanation of the reasons why additional time is required. Upon 

request, Transmission Provider shall provide Interconnection Customer 

supporting documentation, workpapers and relevant power flow, short 

circuit and stability databases for the Interconnection Feasibility Study, 

subject to confidentiality arrangements consistent with Section 13.1. 

Transmission Provider shall study the interconnection request at the level of 

service requested by the interconnection customer, unless otherwise 

required to study the full Generating Facility Capacity due to safety or 

reliability concerns.

7.3 Scope of Interconnection System Impact Study. 

The Interconnection System Impact Study shall evaluate the impact of the 

proposed interconnection on the reliability of the Transmission System. The 

Interconnection System Impact Study will consider the Base Case as well 

as all generating facilities (and with respect to (iii) below, any identified 

Network Upgrades associated with such higher queued interconnection) 

that, on the date the Interconnection System Impact Study is commenced: 

(i) are directly interconnected to the Transmission System; (ii) are 

interconnected to Affected Systems and may have an impact on the 

Interconnection Request; (iii) have a pending higher queued 

Interconnection Request to interconnect to the Transmission System; and 

(iv) have no Queue Position but have executed an LGIA or requested that 

an unexecuted LGIA be filed with FERC. 

The Interconnection System Impact Study will consist of a short circuit 

analysis, a stability analysis, and a power flow analysis. The 

Interconnection System Impact Study will state the assumptions upon 

which it is based; state the results of the analyses; and provide the 

requirements or potential impediments to providing the requested 

interconnection service, including a preliminary indication of the cost and 

length of time that would be necessary to correct any problems identified in 

those analyses and implement the interconnection. For purposes of 

determining necessary interconnection facilities and network upgrades, the 

System Impact Study shall consider the level of interconnection service 

requested by the Interconnection Customer, unless otherwise required to 

study the full Generating Facility Capacity due to safety or reliability 

concerns. The Interconnection System Impact Study will provide a list of 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 371 -

facilities that are required as a result of the Interconnection Request and a 

non-binding good faith estimate of cost responsibility and a non-binding 

good faith estimated time to construct.

8.2 Scope of Interconnection Facilities Study. 

The Interconnection Facilities Study shall specify and estimate the cost of 

the equipment, engineering, procurement and construction work needed to 

implement the conclusions of the Interconnection System Impact Study in 

accordance with Good Utility Practice to physically and electrically connect 

the Interconnection Facility to the Transmission System. The 

Interconnection Facilities Study shall also identify the electrical switching 

configuration of the connection equipment, including, without limitation: 

the transformer, switchgear, meters, and other station equipment; the nature 

and estimated cost of any Transmission Provider's Interconnection 

Facilities and Network Upgrades necessary to accomplish the 

interconnection; and an estimate of the time required to complete the 

construction and installation of such facilities. The Facilities Study will also 

identify any potential control equipment for requests for Interconnection 

Service that are lower than the Generating Facility Capacity.

13.5.5 Non-binding dispute resolution procedures. If a Party has submitted a 

Notice of Dispute pursuant to section 13.5.1, and the Parties are unable to 

resolve the claim or dispute through unassisted or assisted negotiations 

within the thirty (30) Calendar Days provided in that section, and the 

Parties cannot reach mutual agreement to pursue the section 13.5 arbitration 

process, a Party may request that Transmission Provider engage in Nonbinding Dispute Resolution pursuant to this section by providing written 

notice to Transmission Provider (“Request for Non-binding Dispute 

Resolution”). Conversely, either Party may file a Request for Non-binding 

Dispute Resolution pursuant to this section without first seeking mutual 

agreement to pursue the section 13.5 arbitration process. The process in 

section 13.5.5 shall serve as an alternative to, and not a replacement of, the 

section 13.5 arbitration process. Pursuant to this process, a transmission 

provider must within 30 days of receipt of the Request for Non-binding 

Dispute Resolution appoint a neutral decision-maker that is an independent 

subcontractor that shall not have any current or past substantial business or 

financial relationships with either Party. Unless otherwise agreed by the 

Parties, the decision-maker shall render a decision within sixty (60) 

Calendar Days of appointment and shall notify the Parties in writing of 

such decision and reasons therefore. This decision-maker shall be 

authorized only to interpret and apply the provisions of the LGIP and LGIA 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 372 -

and shall have no power to modify or change any provision of the LGIP 

and LGIA in any manner. The result reached in this process is not binding, 

but, unless otherwise agreed, the Parties may cite the record and decision in 

the non-binding dispute resolution process in future dispute resolution 

processes, including in a section 13.5 arbitration, or in a Federal Power Act 

section 206 complaint. Each Party shall be responsible for its own costs 

incurred during the process and the cost of the decision-maker shall be 

divided equally among each Party to the dispute.

Appendix 1 to LGIP 

5. 

h. Requested capacity (in MW) of Interconnection Service (if 

lower than the Generating Facility Capacity).

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 373 -

NOTE: Appendix C will not be published in the Federal Register. Square brackets 

indicate that the text should be filled in as appropriate by the transmission provider.

Appendix C: Compilation of Final Rule changes to the pro forma LGIA

The Commission modifies the following sections of the pro forma LGIA as indicated 

below:

Article 1. Definitions

Generating Facility shall mean Interconnection Customer’s device for the 

production and/or storage for later injection of electricity identified in the Interconnection 

Request, but shall not include the interconnection customer’s Interconnection Facilities.

Provisional Interconnection Service shall mean interconnection service 

provided by Transmission Provider associated with interconnecting the 

Interconnection Customer’s Generating Facility to Transmission Provider’s 

Transmission System and enabling that Transmission System to receive electric 

energy and capacity from the Generating Facility at the Point of Interconnection, 

pursuant to the terms of the Provisional Large Generator Interconnection 

Agreement and, if applicable, the Tariff.

Provisional Large Generator Interconnection Agreement shall mean the 

interconnection agreement for Provisional Interconnection Service established 

between Transmission Provider and/or the Transmission Owner and the 

Interconnection Customer. This agreement shall take the form of the Large 

Generator Interconnection Agreement, modified for provisional purposes.

Surplus Interconnection Service shall mean any unneeded portion of 

Interconnection Service established in a Large Generator Interconnection 

Agreement, such that if Surplus Interconnection Service is utilized the total 

amount of Interconnection Service at the Point of Interconnection would remain 

the same.

5.1 Options. Unless otherwise mutually agreed to between the Parties, 

Interconnection Customer shall select the In-Service Date, Initial Synchronization 

Date, and Commercial Operation Date; and either the Standard Option or 

Alternate Option set forth below for completion of Transmission Provider's 

Interconnection Facilities and Network Upgrades, as set forth in Appendix A, 

Interconnection Facilities and Network Upgrades, and such dates and selected 

option shall be set forth in Appendix B, Milestones. At the same time, 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 374 -

Interconnection Customer shall indicate whether it elects to exercise the Option to 

Build set forth in article 5.1.3 below. If the dates designated by Interconnection 

Customer are not acceptable to Transmission Provider, Transmission Provider 

shall so notify Interconnection Customer within thirty (30) Calendar Days. Upon 

receipt of the notification that Interconnection Customer’s designated dates are not 

acceptable to Transmission Provider, the Interconnection Customer shall notify 

Transmission Provider within thirty (30) Calendar Days whether it elects to 

exercise the Option to Build if it has not already elected to exercise the Option to 

Build.

5.1.3 Option to Build. If the dates designated by Interconnection Customer are not 

acceptable to Transmission Provider, Transmission Provider shall so notify 

Interconnection Customer within thirty (30) Calendar Days and unless the Parties 

agree otherwise, Interconnection Customer shall have the option to assume 

responsibility for the design, procurement and construction of Transmission 

Provider's Interconnection Facilities and Stand Alone Network Upgrades on the 

dates specified in article 5.1.2. Transmission Provider and Interconnection 

Customer must agree as to what constitutes Stand Alone Network Upgrades and 

identify such Stand Alone Network Upgrades in Appendix A. Except for Stand 

Alone Network Upgrades, Interconnection Customer shall have no right to 

construct Network Upgrades under this option.

5.1.4 Negotiated Option. If Interconnection Customer elects not to exercise its option 

under Article 5.1.3, Option to Build, Interconnection Customer shall so notify 

Transmission Provider within thirty (30) Calendar Days, and If the dates 

designated by Interconnection Customer are not acceptable to Transmission 

Provider, the Parties shall in good faith attempt to negotiate terms and conditions 

(including revision of the specified dates and liquidated damages, the provision of 

incentives, or the procurement and construction of a portion of Transmission 

Provider's Interconnection Facilities and Stand Alone Network Upgrades by 

Interconnection Customer all facilities other than Transmission Provider’s 

Interconnection Facilities and Stand Alone Network Upgrades if the 

Interconnection Customer elects to exercise the Option to Build under article 

5.1.3) pursuant to which Transmission Provider is responsible for the design, 

procurement and construction of Transmission Provider’s Interconnection 

Facilities and Network Upgrades. If the Parties are unable to reach agreement on

such terms and conditions, then, pursuant to article 5.1.1 (Standard Option),

Transmission Provider shall assume responsibility for the design, procurement and 

construction of Transmission Provider's Interconnection Facilities and Network 

Upgrades all facilities other than Transmission Provider’s Interconnection 

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Docket No. RM17-8-000 - 375 -

Facilities and Stand Alone Network Upgrades if the Interconnection Customer 

elects to exercise the Option to Build pursuant to article 5.1.1, Standard Option. 

5.9 Limited Operation Other Interconnection Options

5.9.1 Limited Operation.

5.9.2 Provisional Interconnection Service. Upon the request of Interconnection 

Customer, and prior to completion of requisite Interconnection Facilities, 

Network Upgrades, Distribution Upgrades, or System Protection Facilities 

Transmission Provider may execute a Provisional Large Generator 

Interconnection Agreement or Interconnection Customer may request the 

filing of an unexecuted Provisional Large Generator Interconnection 

Agreement with the Interconnection Customer for limited interconnection 

service at the discretion of Transmission Provider based upon an evaluation 

that will consider the results of available studies. Transmission Provider 

shall determine, through available studies or additional studies as 

necessary, whether stability, short circuit, thermal, and/or voltage issues 

would arise if Interconnection Customer interconnects without 

modifications to the Generating Facility or Transmission Provider’s system. 

Transmission Provider shall determine whether any Interconnection 

Facilities, Network Upgrades, Distribution Upgrades, or System Protection 

Facilities that are necessary to meet the requirements of NERC, or any 

applicable Regional Entity for the interconnection of a new, modified 

and/or expanded Generating Facility are in place prior to the 

commencement of interconnection service from the Generating Facility. 

Where available studies indicate that such, Interconnection Facilities, 

Network Upgrades, Distribution Upgrades, and/or System Protection 

Facilities that are required for the interconnection of a new, modified and/or 

expanded Generating Facility are not currently in place, Transmission 

Provider will perform a study, at the Interconnection Customer’s expense, 

to confirm the facilities that are required for Provisional Interconnection 

Service. The maximum permissible output of the Generating Facility in the 

Provisional Large Generator Interconnection Agreement shall be studied 

and updated [on a frequency determined by Transmission Provider and at 

the Interconnection Customer’s expense.]. Interconnection Customer 

assumes all risk and liabilities with respect to changes between the 

Provisional Large Generator Interconnection Agreement and the Large 

Generator Interconnection Agreement, including changes in output limits 

and Interconnection Facilities, Network Upgrades, Distribution Upgrades, 

and/or System Protection Facilities cost responsibilities.

20180419-3062 FERC PDF (Unofficial) 04/19/2018
Document Content(s)

RM17-8-000.DOCX.......................................................1-377

20180419-3062 FERC PDF (Unofficial) 04/19/2018