Order-845.pdf

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

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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

[email protected]

SUPPLEMENTARY INFORMATION:

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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.

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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.

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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.......................__

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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.

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

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).

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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

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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 commerce

must provide interconnection service to large generating

facilities.

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

of the Federal Power Act (FPA)

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.

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).

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

Capacity of more than 20 [megawatts].”

Pro forma LGIA Art. 1.

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

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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.

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,

with

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

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

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

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

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

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study deadline metrics, provisional interconnection service, utilization of surplus

interconnection service, and material modification.

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.

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.

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.

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).

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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.”

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. 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.”

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.”

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

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

See Id. P 10.

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

Id. P 11.

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

queue issues based on the December 2007 technical conference and subsequent

comments.

The Commission acknowledged that delays in processing interconnection

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

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

Technical Conference (Nov. 2, 2007).

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

(2008 Order).

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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.

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.”

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

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

Id. P 8.

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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

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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

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

impacts affected systems.

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.

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).

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

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.

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.

For example, the Commission noted that many interconnection

customers experience delays, and some interconnection queues have significant backlogs

and long timelines.

The Commission also recognized the recurring problem of late-

stage interconnection request withdrawals that lead to interconnection restudies and

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

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

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

Id. P 26.

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

up to a year)).

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consequent delays for lower-queued interconnection customers.

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.

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)).

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A. Comments on Overall Approach

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

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.”

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.”

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

rulemaking.

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.

ESA

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

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 .

TAPS 2017 Comments at 1.

Generation Developers 2017 Comments at 2.

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

Id. at 5-6.

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resources and prevents them from providing low cost reliability services.

ESA asserts,

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

transmission provider flexibility and interconnection customer certainty.

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

Invenergy

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

fundamental causes of these [interconnection] delays unaddressed.”

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.

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

Id. at 6.

Id. at 19.

IECA 2017 Comments at 2.

Invenergy 2017 Comments at 1.

NEPOOL 2017 Comments at 5.

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provider is a vertically integrated utility.

CAISO recognizes the need to nationalize

many of the practices proposed in the NOPR.

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.”

They object,

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

the NOPR’s proposed reforms.

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.

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.

Joint Renewable Parties 2017 Comments at 1-2.

CAISO 2017 Comments at 37.

Non-Profit Utility Trade Associations 2017 Comments at 4.

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.

California Energy Storage Alliance 2017 Comments at 1-2.

Id. at 13.

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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.

It states that the volume of interconnection requests and the inherently

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

withdrawals.

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

raises concerns regarding the feasibility of processing interconnection requests.

ISO-

NE states that several of the proposed reforms may be overly prescriptive and may have

unintended negative consequences.

Southern argues that the NOPR fails to address

problems or delays caused or exacerbated by interconnection customers.

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.

EEI requests that the Commission not deviate from its

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

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.

EEI 2017 Comments at 9.

Imperial 2017 Comments at 1.

ISO-NE 2017 Comments at 2.

Southern 2017 Comments at 4-5.

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.

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borne by the interconnection customer.”

Similarly, Salt River states that the NOPR

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

causation principle.

Southern asks the Commission to reconsider those proposals that

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

providers.

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.

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.

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

procedures to vary according to differing regional needs.

Similarly, MISO TOs state

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

pro forma

EEI 2017 Comments at 9.

Salt River 2017 Comments at 1-2.

Southern 2017 Comments at 4.

APS 2017 Comments at 5-6.

Id. at 7.

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

Comments at 3.

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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.

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.

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.

MISO TOs 2017 Comments at 4.

NEPOOL 2017 Comments at 6.

NYISO 2017 Comments at 1.

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

rulemaking to allow for another round of notice and comment.

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.

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.”

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.

Southern 2017 Comments a 6.

EEI 2017 Comments at 76.

Duke 2017 Comments at 3.

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 ...)

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

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,

stifle competition,

result in uncertainty

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).

See supra P 26.

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).

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);

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

“should increase cost certainty”).

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inaccurate information,

or potentially unduly discriminate against new technologies.

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.

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”).

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’”).

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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

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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

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

variation using the regional difference rationale.”

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.

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.”

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

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

Id.

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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.

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.

Duke 2017 Comments at 3.

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1. Scheduled Periodic Restudies

a. NOPR Proposal

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

providers that conduct cluster studies

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).

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.

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.

The

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.

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

Id. PP 48-49.

Id. P 50.

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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).

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.

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.

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

Id. P 51.

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.

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.

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project financing.

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.

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.

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.

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.

NextEra suggests that

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

NextEra 2017 Comments at 6.

Id.

Id. at 6 -7.

AWEA 2017 Comments at 9-10.

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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.

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.

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.

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.

NextEra 2017 Comments at 7.

Xcel 2017 Comments at 7.

AVANGRID 2017 comments at 5-6.

AFPA 2017 Comments at 3.

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

predictability that could be valuable to project developers.

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.

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.

Southern agrees with the Commission that transmission providers that do not

conduct interconnection studies in clusters should not have to perform periodic

restudies.

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.

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

APPA/LPPC 2017 Comments at 5.

Id.

Duke 2017 Comments at 4.

Southern 2017 Comments at 9.

CAISO 2017 Comments at 7.

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course of the prior year.

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.

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.

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

do not share CAISO’s market features may be problematic.

CAISO states that, as ISO-

NE 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.

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

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

Id.

Id. at 7-8.

Id. at 8.

Id.

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

on the efficacy of periodic restudies.

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.

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.

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.

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.

According to Invenergy, an important missing element in the restudy

Id.

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

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

Generation Developers 2017 Comments at 6-7.

EDP 2017 Comments at 3.

Invenergy 2017 Comments at 5

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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.

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

Id.

100

PJM 2017 Comments at 5.

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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.

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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.

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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.

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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 Phase

119

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.

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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.

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on this issue, existing variations in interconnection processes suggest that a one-size-fits-

all 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

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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 facilities

127

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 ...)

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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.

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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.

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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.

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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.

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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]

135

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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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).

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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.

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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.

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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.

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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.

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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.

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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.

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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

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

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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

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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)

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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).

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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.

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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.

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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).

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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.

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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

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.

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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.

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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.

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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.

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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.

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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.

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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.

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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 Non-

binding 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

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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

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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.

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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 non-

binding dispute resolution provisions adopted in this Final Rule. We note, however, that

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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/ISO-

like 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.

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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 non-

RTOs/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.

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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.

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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.

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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 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.

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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.

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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/Curtailed-

OperationalGeneratorReport Glossary.aspx).

447

CAISO 2017 Comments at 19.

448

Id.

449

MISO 2017 Comments at 28.

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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.

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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 unit-

specific 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.

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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.

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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)).

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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).

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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

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)).

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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.

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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.

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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).

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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.

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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.

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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 LGIP

521

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.

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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 ...)

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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 proposed

526

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.

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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.

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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.

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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; Non-

Profit Utility Trade Associations 2017 Comments at 17.

543

MidAmerican 2017 Comments at 14.

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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.

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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.

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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.

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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.

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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 Posting

566

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).

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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

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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

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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.

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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

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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.

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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.

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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.

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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 later-

identified 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.

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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.

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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.

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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 request

591

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.

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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 custome

r‐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 ...)

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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.

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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

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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

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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.

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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).

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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

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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.

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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.

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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.

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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.

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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

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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

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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.

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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.

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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.

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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.

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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.

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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

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.

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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

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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.

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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.

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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.

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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

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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

increase in plant output will go to the end of the queue for the purposes of cost allocation

and study analysis.

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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.

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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

electrical output of the proposed project through either (1) a decrease

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

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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

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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.

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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.

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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.

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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.

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417. As mentioned above, article 17 of the

pro forma LGIA provides a process for

termination of an LGIA if a party defaults

727

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.

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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.

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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.

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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.

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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.

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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.

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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.”

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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,

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Interconnection Facilities, Distribution Upgrades, and/or System

Protection Facilities cost responsibilities.

744

b. General

i. Comments

430. Most responsive commenters either support the proposal

745

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.

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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.

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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.

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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.

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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 higher-

queued 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.

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5.9.2

769

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.

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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

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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.

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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.

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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.

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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):

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

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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.

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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.

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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.

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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.

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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.

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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.

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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.”

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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 ...)

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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.”

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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 co-

location 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.

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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 non-

affiliates 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.

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(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.

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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.

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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.

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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

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.

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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

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 ...)

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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).

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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

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).

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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

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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).

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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:

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(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 Non-

Discriminatory 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).

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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.

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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

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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

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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.

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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.

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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.

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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.

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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 non-

surplus 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.

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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.

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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. MidAmerican

857

and CAISO

858

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.

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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

Systems

862

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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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 ...)

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b. Technological Change Procedure

i. Comments

515. The majority of commenters support

891

or do not object

892

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.

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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.

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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.

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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.

906

EEI 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.

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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.

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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

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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.”

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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.

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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

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.

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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.

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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.

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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.

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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 type

937

(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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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 non-

transmission 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.

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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.

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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.

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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.

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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.

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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).

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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

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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 cost

1004

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 ...)

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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

restudies

1005

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 (Non-

RTO/ISO)

126 1 (Year 1);

0 (Ongoing)

1006

126 (Year 1);

0 (Ongoing)

4 hrs. (Year 1);

$308

0 hrs. (Ongoing)

504 hrs. (Year 1);

$38,808

0 hrs. (Ongoing);

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)

24 hrs. (Year 1);

$1,848

0 (Ongoing)

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.

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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 – Self-

funding by the

transmission

owner

1007

(Non-

RTO/ISO)

126 N/A N/A N/A N/A

Issue A3 – Self-

funding by the

transmission owner

(RTO/ISO)

6 N/A N/A N/A N/A

Issue A4 –

RTO/ISO dispute

resolution (Non-

RTO/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);

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)

Issue A5 – Capping

costs for network

upgrades

1008

(Non-

RTO/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);

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

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);

480 hrs. (Year 1);

$36,960;

0 hrs. (Ongoing);

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.

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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 (Non-

RTO/ISO)

126 1 (Year 1);

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

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);

480 hrs. (Year 1);

$36,960

0 hrs. (Ongoing);

Issue B3 –

Curtailment

concerns (Non-

RTO/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);

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

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);

480 hrs. (Year 1);

$36,960;

0 hrs. (Ongoing);

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

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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

Systems

1009

(non-

RTO/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 (Non-

RTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

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);

480 hrs. (Year 1);

$36,960

0 hrs. (Ongoing);

Issue C2 –

Provisional

agreements (non-

RTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

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);

480 hrs. (Year 1);

$36,960

0 hrs. (Ongoing);

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.

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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 (non-

RTO/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);

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)

24 hrs. (Year 1);

$1,848

0 (Ongoing)

Issue C4 – Material

modification and

incorporation of

advanced

technologies (non-

RTO/ISO)

126 1 (Year 1)

0 (Ongoing)

126 (Year 1);

0 (Ongoing)

80 hrs. (Year 1);

$6,160

0 hrs.; (Ongoing);

10,080 hrs. (Year 1);

$776,160

0 hrs. (Ongoing);

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);

480 hrs. (Year 1);

$36,960

0 hrs. (Ongoing);

Issue C5 –

Modeling of

electric storage

resources

1010

(non-

RTO/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.

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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.

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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

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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).

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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.

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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-RFA-

WEB.pdf.

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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.referenceroo[email protected].

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.

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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

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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

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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;

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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 Hydro-

Transmission Corporation, New England

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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

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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.

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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.

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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 password-

protected 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

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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

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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.

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,

Interconnection Requests with ongoing incomplete Interconnection

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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,

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

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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,

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.

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(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,

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),

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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 employee-

hours 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

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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

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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

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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