Small Generator Interconnection Agreements and Procedures

Federal RegisterDec 5, 2013

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[RM13-2-000; Order No. 792]

Small Generator Interconnection Agreements and Procedures

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

In this Final Rule, the Federal Energy Regulatory Commission (Commission) is amending the

pro forma

Small Generator Interconnection Procedures (SGIP) and

pro forma

Small Generator Interconnection Agreement (SGIA) to: Incorporate provisions that provide an Interconnection Customer with the option of requesting from the Transmission Provider a pre-application report providing existing information about system conditions at a possible Point of Interconnection; revise the 2 megawatt (MW) threshold for participation in the Fast Track Process included in section 2 of the

pro forma

SGIP; revise the customer options meeting and the supplemental review following failure of the Fast Track screens so that the supplemental review is performed at the discretion of the Interconnection Customer and includes minimum load and other screens to determine if a Small Generating Facility may be interconnected safely and reliably; revise the

pro forma

SGIP Facilities Study Agreement to allow the Interconnection Customer the opportunity to provide written comments to the Transmission Provider on the upgrades required for interconnection; revise the

pro forma

SGIP and the

pro forma

SGIA to specifically include energy storage devices; and clarify certain sections of the

pro forma

SGIP and the

pro forma

SGIA. The reforms should ensure interconnection time and costs for Interconnection Customers and Transmission Providers are just and reasonable and help remedy undue discrimination, while continuing to ensure safety and reliability.

DATES:

This rule is effective February 3, 2014.

FOR FURTHER INFORMATION CONTACT:

Leslie Kerr (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8540,

Leslie.Kerr@ferc.gov

Monica Taba (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6789,

Monica.Taba@ferc.gov

Christopher Kempley (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8442,

Christopher.Kempley@ferc.gov

SUPPLEMENTARY INFORMATION:

145 FERC ¶ 61,159

Before Commissioners: Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony Clark.

Final Rule

(Issued November 22, 2013)

Paragraph Nos.

I. Introduction

II. Background

A. Order No. 2006

B. Solar Energy Industries Association Petition and the Notice of Proposed Rulemaking

III. Need for Reform

A. Commission Proposal

B. Comments

C. Commission Determination

IV. Proposed Reforms

A. Pre-Application Report

1. Commission Proposal

2. Need for a Pre-Application Report

a. Comments

b. Commission Determination

3. Pre-Application Report Fee

a. Comments

b. Commission Determination

4. Pre-Application Report Timeline

a. Comments

b. Commission Determination

5. Pre-application Report Request Form

a. Comments

b. Commission Determination

6. Readily Available Information

a. Comments

b. Commission Determination

7. Other Issues

a. Comments

b. Commission Determination

B. Threshold for Participation in the Fast Track Process

1. Commission Proposal

2. Comments

3. Commission Determination

102

C. Fast Track Customer Options Meeting and Supplemental Review

112

1. Commission Proposal

112

2. General Comments on the Customer Options Meeting and the Supplemental Review

114

a. Comments

114

b. Commission Determination

118

3. Minimum Load Screen (SGIP Section 2.4.4.1)

119

a. Comments

119

b. Commission Determination

142

4. Voltage and Power Quality Screen and Safety and Reliability Screen (SGIP Sections 2.4.4.2 and 2.4.4.3)

150

a. Comments

150

b. Commission Determination

157

5. Supplemental Review Screen Order (SGIP Section 2.4.2)

163

a. Comments

163

b. Commission Determination

165

6. Supplemental Review Fee (SGIP Sections 2.4.1 and 2.4.3)

166

a. Comments

166

b. Commission Determination

171

7. Process Following Completion of the Customer Options Meeting and the Supplemental Review (SGIP Sections 2.3.1, 2.4.4 and 2.4.5)

175

a. Comments

175

b. Commission Determination

182

D. Review of Required Upgrades

190

1. Commission Proposal

190

2. Comments

191

3. Commission Determination

204

E. Revision to SGIA Section 1.5.4 Regarding Over and Under-Frequency Events

211

1. Commission Proposal

211

2. Comments

212

3. Commission Determination

221

F. Interconnection of Storage Devices

223

1. Commission Proposal

223

2. Comments

224

3. Commission Determination

228

G. Other Issues

233

1. Network Resource Interconnection Service

233

a. Commission Proposal

233

b. Comments

234

c. Commission Determination

236

2. Hosting Capacity

238

a. Comments

238

b. Commission Determination

244

3. Jurisdiction

245

a. Comments

245

b. Commission Determination

247

4. Miscellaneous

250

a. Commission Proposal

250

b. Comments

251

c. Commission Determination

258

V. Compliance

263

A. Commission Proposal

263

B. Comments

266

C. Commission Determination

270

VI. Information Collection Statement

278

VII. Environmental Analysis

283

VIII. Regulatory Flexibility Act Analysis

284

IX. Document Availability

286

X. Effective Date and Congressional Notification

289

Appendix A: List of Short Names of Commenters on the Notice of Proposed Rulemaking

Appendix B: Flow Chart for Interconnecting a Certified Small Generating Facility Using the “Fast Track Process”

Appendix C: Revisions to the

Pro Forma

SGIP

Appendix D: Revisions to the

Pro Forma

SGIA

I. Introduction

1. In this Final Rule, the Federal Energy Regulatory Commission (Commission) is amending the

pro forma

Small Generator Interconnection Procedures (SGIP) and

pro forma

Small Generator Interconnection Agreement (SGIA) to: (1) Incorporate provisions that provide an Interconnection Customer with the option of requesting from the Transmission Provider a pre-application report providing existing information about system conditions at a possible Point of Interconnection; (2) revise the 2 megawatt (MW) threshold for participation in the Fast Track Process included in section 2 of the

pro forma

SGIP; (3) revise the customer options meeting and the supplemental review following failure of the Fast Track screens so that the supplemental review is performed at the discretion of the Interconnection Customer and includes minimum load and other screens to determine if a Small Generating Facility may be interconnected safely and reliably; (4) revise the

pro forma

SGIP Facilities Study Agreement to allow the Interconnection Customer the opportunity to provide written comments to the Transmission Provider on the upgrades required for interconnection; (5) revise the

pro forma

SGIP and the

pro forma

SGIA to specifically include energy storage devices; and (6) clarify certain sections of the

pro forma

SGIP and the

pro forma

2. Originally adopted in Order No. 2006,

the

pro forma

SGIP and the

pro forma

SGIA establish the terms and conditions under which public utilities

must provide interconnection service to Small Generating Facilities

of no more than 20 MW. Based on the record in this proceeding, the Commission finds it necessary under section 206 of the Federal Power Act

(FPA) to revise the

pro forma

SGIP and the

pro forma

SGIA to ensure that the rates, terms and conditions under which public utilities provide interconnection service to Small Generating Facilities remain just and reasonable and not unduly discriminatory. The Commission believes that taking these actions at this time is in the public interest. The Commission routinely evaluates the effectiveness of its regulations and policies in light of changing industry conditions to determine if reforms are necessary to satisfy its statutory obligation of ensuring just and reasonable and not unduly discriminatory rates, terms and conditions of service.

As concerns generator interconnection, regions of the country are experiencing significant penetrations of small generation and increasing requests for small generator interconnection. In Order No. 2006, the Commission anticipated the need to revisit its small generator interconnection regulations as the industry evolves, requesting stakeholders to convene informal meetings “to consider and recommend consensus proposals for changes in the Commission's rules for small generator interconnection.”

The time is ripe to promulgate such changes in light of the increased penetration of small generator resources, the continued focus by states and others on the development of distributed resources,

and the need for this Commission to have its regulations and policies ensure just and reasonable rates, terms and conditions of service.

Standardization of Small Generator Interconnection Agreements and Procedures,

Order No. 2006, FERC Stats. & Regs. ¶ 31,180,

order on reh 'g,

Order No. 2006-A, FERC Stats. & Regs. ¶ 31,196 (2005),

order on clarification,

Order No. 2006-B, FERC Stats. & Regs. ¶ 31,221 (2006).

For purposes of this Final Rule, a public utility is a utility that owns, controls, or operates facilities used for transmitting electric energy in interstate commerce, as defined by the 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

SGIP and the

pro forma

SGIA.

Capitalized terms used in this Final Rule have the meanings specified in the Glossaries of Terms or the text of the

pro forma

SGIP or SGIA. A Small Generating Facility is the device for which the Interconnection Customer has requested interconnection. The owner of the Small Generating Facility is the Interconnection Customer. The utility entity with which the Small Generating Facility is interconnecting is the Transmission Provider.

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

See

Plan for Retrospective Analysis of Existing Rules, Docket No. AD12-6-000,

available at http://www.ferc.gov/legal/maj-ord-reg/retro-analysis/ferc-eo-13579.pdf

See also Integration of Variable Energy Resources,

Order No. 764, FERC Stats. & Regs. ¶ 31,331 (2012).

Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 118.

Distributed resources are sources of electric power that are not directly connected to a bulk power transmission system. Distributed resources include both generators and energy storage technologies. (Institute of Electrical and Electronics Engineers (IEEE) Standard 1547 for Interconnecting Distributed Resources with Electric Power Systems, p. 3).

3. The reforms we adopt largely track the proposals set forth in the Notice of Proposed Rulemaking issued in this proceeding on January 17, 2013,

with modifications to address suggestions and concerns raised in comments. Among other things, the Commission has revised aspects of the pre-application report requirement, the Fast Track eligibility threshold, and the supplemental review requirement to balance the interests of the Interconnection Customer with those of the Transmission Provider. With these modifications, the Commission concludes that the package of reforms adopted in this Final Rule will reduce the time and cost to process small generator interconnection requests for Interconnection Customers and Transmission Providers, maintain reliability, increase energy supply, and remove barriers to the development of new energy resources. This fulfills our statutory obligation to ensure that rates, terms and conditions for Commission-jurisdictional services are just and reasonable and not unduly discriminatory, as sections 205 and 206 of the FPA require.

Small Generator Interconnection Agreements and Procedures,

78 FR 7524 (Feb. 1, 2013) (NOPR), FERC Stats. & Regs. ¶ 32,697 (2013).

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

II. Background

A. Order No. 2006

4. In Order No. 2006, the Commission established a

pro forma

SGIP and SGIA for the interconnection of generation resources no larger than 20 MW, continuing the process begun in Order No. 2003

of standardizing the terms and conditions of Commission-jurisdictional interconnection service. The Commission adopted the

pro forma

SGIA and the

pro forma

SGIP to respond to business and technology changes in the electric industry. Where the electric industry was once primarily the domain of vertically integrated utilities generating power at large centralized plants, the Commission noted in Order No. 2006 that advances in technology had created a burgeoning market for small power plants that may offer economic, reliability or environmental benefits.

Standardization of Generator Interconnection Agreements and Procedures,

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

order on reh'g,

Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160,

order on reh'g,

Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171 (2004),

order on reh'g,

Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005),

aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs

FERC,

475 F.3d 1277 (D.C. Cir. 2007),

cert. denied,

552 U.S. 1230 (2008).

Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 9.

5. The

pro forma

SGIP describes how an Interconnection Customer's interconnection request (application) should be evaluated, and includes three alternative procedures for evaluating an interconnection request. These procedures include the Study Process, which can be used by any generating facility with a capacity no larger than 20 MW, and two procedures that use certain technical screens to quickly identify any safety or reliability issues associated with proposed interconnections: (1) The Fast Track Process for certified

Small Generating Facilities no larger than 2 MW; and (2) the 10 kilowatt (kW) Inverter Process for certified inverter-based

Small Generating Facilities no larger than 10 kW.

See

Attachments 3 and 4 of the

pro forma

SGIP, which specify the codes, standards, and certification requirements that Small Generating Facilities must meet. Order No. 2006, FERC Stats. & Regs. ¶ 31,180.

An inverter is a device that converts the direct current (DC) voltage and current of a DC generator to alternating voltage and current. For example, the output of a solar panel is DC. The solar panel's output must be converted by an inverter to alternating current (AC) before it can be interconnected with a utility's AC electric system. Such inverters, particularly newer inverters, often incorporate additional power electronics that can provide other safety or power quality functions.

6. The Study Process in section 3 of the

pro forma

SGIP, which can be used by any generating facility with a capacity no larger than 20 MW, is used to evaluate small generator interconnection requests that do not qualify for either the Fast Track Process or the 10 kW Inverter Process. The Study Process is similar to the process under the Large Generator Interconnection Procedures (LGIP) set forth in Order No. 2003. The Study Process normally consists of a scoping meeting, a feasibility study, a system impact study, and a facilities study. These studies identify any adverse system impacts

that must be

addressed before the Small Generating Facility may be interconnected as well as any equipment modifications that may be required to accommodate the interconnection. Once the Interconnection Customer agrees to fund any needed upgrades, an SGIA is executed that, among other things, formalizes responsibility for construction and payment for interconnection facilities and upgrades.

An adverse system impact means that technical or operational limits on conductors or equipment

are exceeded under the interconnection, which may compromise the safety or reliability of the electric system.

Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 44.

7. The Fast Track Process eliminates the scoping meeting and three interconnection studies and instead uses technical screens to quickly identify reliability or safety issues. If the proposed interconnection passes the screens, the Transmission Provider offers the Interconnection Customer an SGIA without further study. If the proposed interconnection fails the screens, but the Transmission Provider nevertheless determines that the Small Generating Facility may be interconnected without affecting safety and reliability, the Transmission Provider provides the Interconnection Customer with an SGIA. If the Transmission Provider does not or cannot determine that the Small Generating Facility may be interconnected without affecting safety and reliability, the Transmission Provider offers the Interconnection Customer the opportunity to attend a customer options meeting to discuss how to proceed. In that meeting, the Transmission Provider must: (1) Offer to perform facility modifications or minor modifications to the Transmission Provider's system (e.g., changing meters, fuses, relay settings) that would allow interconnection and provide a non-binding good faith estimate of the cost to make such modifications; (2) offer to perform a supplemental review if the Transmission Provider concludes that the supplemental review might determine that the Small Generating Facility could continue to qualify for interconnection pursuant to the Fast Track Process, where such supplemental review is paid for by the Interconnection Customer, and provide a non-binding good faith estimate of the cost of that review;

or (3) obtain the Interconnection Customer's agreement to continue evaluating the interconnection request under the Study Process. If the Transmission Provider determines in the supplemental review that the Small Generating Facility can be interconnected safely and reliably and the Interconnection Customer agrees to pay for any upgrades identified in the supplemental review, the Transmission Provider and the Interconnection Customer execute an SGIA. If, after the supplemental review, the Transmission Provider still is unable to determine that the proposed interconnection would not degrade the safety and reliability of its electric system, the interconnection request is evaluated using the Study Process.

The purpose of the supplemental review is to determine if the Small Generating Facility can be interconnected safely and reliably, however, the

pro forma

SGIP does not include details regarding how the Transmission Provider is to perform the supplemental review.

8. The 10 kW Inverter Process is available for the interconnection of certified inverter-based generators no larger than 10 kW. The 10 kW Inverter Process includes a simplified application form, interconnection procedures, and a brief set of terms and conditions (rather than a separate interconnection agreement). The 10 kW Inverter Process uses the same technical screens as the Fast Track Process. If the results of the analysis using the technical screens indicate that the generator can be interconnected safely and reliably, the interconnection application is approved. To simplify the 10 kW Inverter Process, the Interconnection Customer agrees to the terms and conditions of the interconnection at the time the interconnection request is made.

Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 46.

9. The ten technical screens used in the Fast Track and 10 kW Inverter Processes are included in section 2.2.1 of the

pro forma

SGIP. The screen in section 2.2.1.2 of the

pro forma

SGIP, which is referred to in this Final Rule as the 15 Percent Screen, will be discussed at some length below:

For interconnection of a proposed Small Generating Facility to a radial distribution circuit, the aggregated generation, including the proposed Small Generating Facility, on the circuit shall not exceed 15 [percent] of the line section annual peak load as most recently measured at the substation. A line section is that portion of a Transmission Provider's electric system connected to a customer bounded by automatic sectionalizing devices or the end of the distribution line.

B. Solar Energy Industries Association Petition and the Notice of Proposed Rulemaking

10. On February 16, 2012, pursuant to sections 205 and 206 of the FPA and Rule 207 of the Commission's Rules of Practice and Procedure,

and noting that the Commission encouraged stakeholders to submit proposed revisions to the regulations set forth in Order No. 2006, the Solar Energy Industries Association (SEIA) filed a Petition to Initiate Rulemaking (Petition) requesting that the Commission revise the

pro forma

SGIA and SGIP set forth in Order No. 2006.

In its Petition, SEIA asserted that the

pro forma

SGIP and SGIA as applied to small solar generation are no longer just and reasonable, have become unduly discriminatory, and present unreasonable barriers to market entry.

SEIA noted that its Petition applies exclusively to solar electric generation due to its unique characteristics.

18 CFR 385.207 (2013).

SEIA Petition at 4 (citing Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 118).

Id.

at 12.

Id.

at 4 (explaining that solar generation occurs only during daylight hours when peak load typically occurs, and solar photovoltaic technology utilizes inverters with built-in functions that protect the safety and reliability of the electric system).

11. On February 28, 2012, the Commission issued a Notice of Petition for Rulemaking in Docket No. RM12-10-000, seeking public comment on SEIA's Petition. The Commission received a number of comments, protests, and answers in response.

12. On July 17, 2012, the Commission convened a technical conference in Docket Nos. RM12-10-000 and AD12-17-000 in order to discuss issues related to SEIA's Petition. The Commission received nine post-technical conference comments, including clarifying comments from SEIA.

13. On January 17, 2013, the Commission issued the NOPR in this proceeding, proposing a package of reforms to the

pro forma

SGIA and the

pro forma

SGIP.

Commission staff held a workshop on March 27, 2013, at which stakeholders discussed the NOPR proposals. In addition to the Commission staff workshop, some stakeholders formed a stakeholder working group (SWG) to develop revisions to the NOPR proposals.

Comments on the NOPR as well as comments generated by the Commission staff workshop were due June 3, 2013. The Commission received thirty-three timely comments, four comments out of time and two reply comments out of time.

NOPR, FERC Stats. & Regs. ¶ 32,697. While SEIA's Petition was specific to small solar generation, the NOPR included all Small Generating Facilities.

The SWG included EEI, NRECA, APPA, IREC, SEIA, NREL, and other stakeholders.

See

Appendix A, List of Short Names of Commenters on the Notice of Proposed Rulemaking.

14. The stakeholders that participated in the SWG indicated in their comments

that the SWG came to agreement on certain revisions to the proposals for the pre-application report and the threshold for participation in the Fast Track Process. The National Rural Electric Cooperative Association, Edison Electric Institute and the American Public Power Association (NRECA, EEI & APPA), the Interstate Renewable Energy Council (IREC), SEIA, and National Renewable Energy Laboratory (NREL) submitted SWG proposed revisions with their comments.

III. Need for Reform

A. Commission Proposal

15. In light of changes in the energy industry since the issuance of Order No. 2006, and based on the comments submitted in response to the SEIA Petition and the July 17, 2012 Technical Conference, the Commission preliminarily found that proposed reforms were needed to ensure that the rates, terms, and conditions of interconnection service for Small Generating Facilities are just and reasonable and not unduly discriminatory or preferential.

In particular, the Commission cited the growth in grid-connected solar photovoltaic (PV) generation since the issuance of Order No. 2006 and the growth in small generator interconnection requests driven by state renewable portfolio standards as the impetus for re-examining the

pro forma

SGIP.

The Commission reasoned that if generation penetration levels are causing projects to fail the 15 Percent Screen, the screen should be re-examined to determine if revisions could be made to allow projects to continue to participate in the less costly and time-consuming Fast Track Process while maintaining the safety and reliability of the Transmission Provider's system.

Further, the Commission noted that in addition to the proposed reforms applying to Commission-jurisdictional interconnections, the Commission intended that the proposed reforms serve as a model for state interconnection rules.

NOPR, FERC Stats. & Regs. ¶ 32,697 at P 18.

Id.

P 20.

Id.

P 22.

Id.

P 23.

B. Comments

16. Many commenters support the Commission's proposed reforms.

Commenters state that the recent rapid growth in small generators and expected significant growth in coming years, driven by public policies such as state renewable portfolio standards, requires revising the SGIP and SGIA.

For example, Public Interest Organizations

note that state solar initiatives are resulting in penetrations of distributed generation in excess of 15 percent on some line sections

and that the public policies driving the increase in Small Generating Facilities, together with lower prices for solar panels, smart grid enhancements and other factors, have “given rise to barriers like lengthy interconnection queues and a lack of transparency about system conditions.”

Public Interest Organizations believe that these facts clearly demonstrate the need to reconsider the SGIP and to enact the proposed reforms to reduce the time and cost of processing the increasing volume of distributed generation projects.

IREC and SEIA similarly assert that reforming the SGIP and SGIA is essential to support the continued growth of the wholesale market for solar and other distributed resources.

Public Interest Organizations go on to state that:

See, e.g.,

American Wind Energy Association (AWEA) at 2-3; Clean Coalition at 2; ClearEdge Power (CEP) at 1-2; ComRent International (ComRent) at 1; Community Renewable Energy Association (CREA) at 1-2; Office of the People's Counsel for the District of Columbia (DCOPC) at 1; Duke Energy Corporation (Duke Energy) at 1; ELCON at 3; Electricity Storage Association (ESA) at 3; Fuel Cell & Hydrogen Energy Association (FCHEA) at 1-2; Max Hensley at 1-2; Industrial Energy Consumers of America (IECA) at 4; IREC at 2; NRG at 2; Public Interest Organizations at 6-9; SEIA at 1; Union of Concerned Scientists (UCS) at 3, 8-9; and Lucia Villaran at 1-2.

IREC at 3 (citing Solar Electric Power Association, 2012 SEPA Utility Solar Rankings Executive Summary 2 (2013)),

available at http://www.solarelectricpower.org/media/279520/sepa-top-10-executive-summary_final-v2.pdf

); AWEA at 3; DCOPC at 3-4; ELCON at 5; NRG at 2; Public Interest Organizations at 3-4, 6-9; and UCS at 9.

The Center for Rural Affairs, Climate + Energy Project, Conservation Law Foundation, Energy Future Coalition, Environmental Defense Fund, Environmental Law & Policy Center, Environment Northeast, Fresh Energy, Great Plains Institute, National Audubon Society, Natural Resources Defense Council, Northwest Energy Coalition, Pace Energy and Climate Center, Piedmont Environmental Council, Sierra Club, Southern Alliance for Clean Energy, Southern Environmental Law Center, Sustainable FERC Project, Union of Concerned Scientists, Utah Clean Energy, Western Grid Group, Western Resource Advocates, The Wilderness Society and Wind on the Wires are referred to collectively as Public Interest Organizations in this Final Rule.

Public Interest Organizations at 4-5.

Id.

at 1.

Id.

at 5-9.

IREC at 4 and SEIA at 1.

The increased volume of applications along with the higher penetration levels that will result from these policy changes necessitate updating SGIP to enable providers to continue processing applications efficiently and without imposing unnecessary financial or regulatory hurdles to [distributed generation] development. Since in some instances existing SGIP act as regulatory barriers to further reliable deployment of [distributed generation] resources, the SGIP have become unduly discriminatory and can no longer be assumed to be just and reasonable.

Public Interest Organizations at 5.

17. CREA and ESA support the effort to reform the SGIP and assert that the current system results in delays and unnecessarily increases project costs. AWEA and ELCON

similarly state that the proposed reforms ensure that small generator interconnection requests are processed in a just and reasonable and not unduly discriminatory manner.

The Electricity Consumers Resource Council, American Chemistry Council, American Forest & Paper Association, American Iron and Steel Institute, CHP Association and Council of Industrial Boiler Owners are collectively referred to as ELCON in this Final Rule.

AWEA at 2 and ELCON at 3.

18. International Transmission Company (ITC) supports streamlining the SGIP in ways that maintain safety and reliability.

ITC at 6.

19. Independent System Operators (ISO) and Regional Transmission Organizations (RTO) generally support the NOPR objectives,

but request, in recognition of regional differences and existing ISO/RTO interconnection processes, that they be allowed to meet those objectives under either the independent entity variation standard

or the regional differences standard.

Similarly, the National Association of Regulatory Utility Commissioners (NARUC) supports the Commission's efforts to update the

pro forma

SGIP and SGIA, but requests flexibility in the revisions to account for regional differences.

NARUC also states that

the reforms should not impinge on successful state interconnection procedures.

CAISO at 1, 9; IRC at 1; ISO-NE at 8, 15; MISO at 4-5; NYISO & NYTO at 2; and PJM at 1, 3-4.

CAISO at 2 and 7 and NYISO & NYTO at 4, 24-25. The independent entity variation is a balanced approach that provides RTOs and ISOs greater flexibility to customize their interconnection procedures and agreements to accommodate regional needs. It recognizes that an RTO or ISO has differing operating characteristics depending on its size and location and is less likely to act in an unduly discriminatory manner than a Transmission Provider that is also a market participant.

See

Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at PP 822-827.

ISO-NE at 2, 5-7; PJM at 4; and IRC at 1, 3-6. A regional differences standard would allow variations based on regional differences resulting from regional interconnection standards or reliability requirements. For non-independent Transmission Providers, Order No. 2006 recognizes regional reliability variations based on established regional reliability requirements when supported by reference to established regional reliability requirements and including the text of the reliability requirement.

See

Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 546.

NARUC at 10.

Id.

20. NRECA, EEI & APPA believe that the

pro forma

SGIP and SGIA adopted in Order No. 2006 continue to be just and reasonable and strike a fair balance between the competing goals of uniformity and flexibility while ensuring safety and reliability.

NRECA, EEI & APPA further assert that the current record cannot support a finding that existing Order No. 2006 procedures are unjust, unreasonable or unduly preferential, nor can the record support a finding that the Commission's proposals are just and reasonable, not unduly preferential, or would not impair reliability or safety.

Specifically, NRECA, EEI & APPA contend that before modifications to the Fast Track Process are considered, there must be evidence to suggest that the 15 Percent Screen no longer serves to adequately reduce interconnection costs and time compared to the full Study Process. They further argue that there also must be evidence showing that higher penetrations of generation can be safely and reliably accommodated without the need for the Study Process.

They also believe, however, that the

pro forma

SGIP and SGIA can be revised to enable the growth of renewable energy while continuing to facilitate jurisdictional interconnections in a just and reasonable manner and to benefit consumers and other stakeholders.

NRECA, EEI & APPA at 9.

Id. at 10.

Id.

at 11.

Id.

at 1, 10. Duquesne Light supports the comments submitted by NRECA, EEI & APPA. (Duquesne Light at 3.)

C. Commission Determination

21. The Commission is persuaded to adopt its proposed revisions to the

pro forma

SGIP and the

pro forma

SGIA, as modified herein.

Without these reforms, the continued growth in Small Generating Facilities could cause inefficient interconnection queue backlogs and require some Small Generating Facilities to undergo the more costly Study Process when they could be interconnected under the Fast Track Process safely and reliably. Costs resulting from such inefficiencies in the interconnection process would ultimately be borne by consumers. The record in this proceeding does not refute the nature of the changes now occurring and expected to continue.

The Commission concludes that the revisions to the

pro forma

SGIP and

pro forma

SGIA adopted herein were reasonably foreseeable based on the NOPR, the March 2013 workshop and the comments received on the NOPR.

22. For example, approximately 3,300 MW of grid-connected PV capacity were installed in the U.S. in 2012,

compared to 79 MW in 2005, the year Order No. 2006 was issued.

The cumulative capacity of U.S. distributed PV is projected to double from mid-2013 to the end of 2015.

Similarly, installed wind generation with a capacity of 20 MW or less has increased in the contiguous United States from 1,185 MW in 2005 to 2,961 MW in 2012.

The growth in Small Generating Facilities is leading to an increase in small generator interconnection requests. In the NOPR, the Commission cited Commission filings that referenced higher volumes of small generator interconnection requests.

In its comments, IREC cited an unprecedented level of small solar interconnections.

Sherwood, Larry, U.S. Solar Market Trends 2012 at 4,

available at http://www.irecusa.org/wp-content/uploads/2013/07/Solar-Report-Final-July-2013-1.pdf

U.S. Solar Market Insight Report, 2012 Year in Review, Executive Summary Table 2.1,

available at http://www.seia.org/research-resources/us-solar-market-insight-2012-year-in-review

See

Lacey, Stephen, Chart: 2/3rds of Global Solar PV Has Been Installed in the Last 2.5 Years,

available at http://www.greentechmedia.com/articles/read/chart-2-3rds-of-global-solar-pv-has-been-connected-in-the-last-2.5-years

SNL Financial,

Power Plant Summary

(2013).

See, e.g., Cal. Indep. Sys. Operator Corp.,

133 FERC ¶ 61,223, at P 3 (2010) (stating that an increasing volume of small generator interconnection requests had created inefficiencies);

Pacific Gas & Elec. Co.,

135 FERC ¶ 61,094, at P 4 (2011) (stating that increased small generator interconnection requests resulted in a backlog of 170 requests over three years);

PJM Interconnection, LLC,

139 FERC ¶ 61,079, at P 12 (2012) (stating that smaller projects comprised 66 percent of recent queue volume).

IREC at 3 (citing Becky Campbell & Mike Taylor, 2011 Solar Electric Power Association Utility Solar Rankings at 7 (May 2012)).

23. As noted by some commenters

and as the Commission noted in the NOPR, state renewable portfolio standards are driving small generator interconnection requests.

As of March 2013, 29 states and the District of Columbia had renewable portfolio standards, and an additional eight states had renewable portfolio goals.

Some state renewable portfolio standards include increasing percentages of renewable energy resources over time, which will lead to increasing penetrations of these resources. Some states have also adopted goals and policies to promote distributed generation.

Commenters also attribute the increase in PV to a decline in capital costs.

Installed costs for distributed PV installations fell by approximately 12 percent from 2011 to 2012, and have fallen 33 percent since 2009.

Public Interest Organizations at 3-5; IREC at 2; UCS at 3; and DCOPC at 3.

NOPR, FERC Stats. & Regs. ¶ 32,697 at P 20.

See

Dep't of Energy, IREC & North Carolina Solar Center, Renewable Portfolio Standard Policies (2013),

available at http://www.dsireusa.org/documents/summarymaps/RPS_map.pdf

See

Dep't of Energy, IREC & North Carolina Solar Center, Renewable Portfolio Standard Policies with Solar/Distributed Generation Provisions (2013),

available at http://www.dsireusa.org/documents/summarymaps/Solar_DG_RPS_map.pdf

VSI at 1-2 and Public Interest Organizations at 1.

Sherwood, Larry, U.S. Solar Market Trends 2012 at 2,

available at http://www.irecusa.org/wp-content/uploads/2013/07/Solar-Report-Final-July-2013-1.pdf

24. The needs of Small Generating Facility developers, however, must be balanced against the concerns of the Transmission Providers, and the Commission has taken these concerns into consideration in developing this Final Rule. For example, the Commission notes that this Final Rule does not modify the 15 Percent Screen or any of the existing Fast Track screens. Rather, the Commission modifies the optional supplemental review process following failure of any of the Fast Track screens to include three supplemental review screens. In regions of the country where penetration levels are not high enough to cause Interconnection Customers to fail the 15 Percent Screen, Transmission Providers will generally continue to evaluate the penetration level of generation based on the 15 Percent Screen. However, in regions of the country where the 15 Percent Screen is causing Interconnection Customers to fail the Fast Track screens, the revised supplemental review will offer an opportunity to continue to be evaluated under the Fast Track Process.

25. The Commission therefore finds that our actions in this Final Rule are consistent with the standards that the court set forth in

National Fuel

FERC

and therefore disagrees with EEI, NRECA, and APPA that the existing record does not support the finding that the current SGIP and SGIA are unjust, unreasonable and unduly discriminatory. In the terminology of

National Fuel,

we find that a theoretical threat exists and we show herein how this threat justifies the costs that this Final Rule would create.

We conclude that, in light of the increasing small generator interconnection requests referenced in Commission filings

and

in this proceeding,

the state renewable portfolio standards driving these requests,

and the growth in solar PV installations,

the reforms adopted herein are necessary to correct operational practices that can unnecessarily limit, and increase the cost of,

Commission-jurisdictional interconnections under the SGIP and SGIA. The Commission believes that adopting the reforms in this Final Rule will reduce the time and cost to process small generator interconnection requests for Interconnection Customers and Transmission Providers alike.

468 F.3d 831, 839-44 (D.C. Cir. 2006) (

National Fuel

Id.

at 844.

See, e.g., Cal. Indep. Sys. Operator Corp.,

133 FERC ¶ 61,223, at P 3 (2010) (stating that an increasing volume of small generator

interconnection requests had created inefficiencies);

Pacific Gas & Elec. Co.,

135 FERC ¶ 61,094, at P 4 (2011) (stating that increased small generator interconnection requests resulted in a backlog of 170 requests over three years);

PJM Interconnection, LLC,

139 FERC ¶ 61,079, at P 12 (2012) (stating that smaller projects comprised 66 percent of recent queue volume).

IREC at 3, citing Becky Campbell & Mike Taylor, 2011 Solar Electric Power Association Utility Solar Rankings at 7 (May 2012).

As noted above, as of March 2013, 29 states and the District of Columbia had renewable portfolio standards, and an additional eight states had renewable portfolio goals.

See supra

P 0.

As noted above, approximately 3,300 MW of grid-connected PV capacity were installed in the U.S. in 2012 compared to 79 MW in 2005. Further, the cumulative capacity of U.S. distributed PV is projected to double from mid-2013 to the end of 2015.

See supra

P 0.

E.g.,

some of the reforms adopted herein are intended to increase the number of Small Generating Facilities that may be interconnected under the Fast Track Process rather than the Study Process. The cost to be evaluated under the

pro forma

SGIP Fast Track Process (without supplemental review) is $500. Under the

pro forma

SGIP Study Process, the Interconnection Customer must pay a deposit not to exceed $1,000 toward the cost of the feasibility study with its interconnection request and pay the actual cost of any required studies (normally a feasibility study, a system impact study, and a facilities study).

26. Specifically, as discussed above, the Commission believes that the current SGIP and SGIA inhibit the continued growth in Small Generating Facilities and cause unnecessary costs to be passed on to consumers. We agree with commenters that assert that the proposed reforms are necessary to avoid delays and unnecessary project costs (

e.g.,

under the SGIP originally adopted in Order No. 2006, generators that could be interconnected safely and reliably under the Fast Track Process are required to undergo the more costly and time-consuming Study Process).

Hence, we conclude that such delays and increased project costs are likely without the reforms proposed herein and that this threat is significant enough to justify the reforms imposed by this Final Rule. The threat is not one that can be addressed adequately or efficiently through the adjudication of individual complaints.

The remedy we adopt is justified sufficiently by the theoretical threat identified herein and based on the comments received, the identified theoretical threat represents a reasonable prediction of future market conditions.

See supra

P 0.

Individual adjudications by their nature focus on discrete questions of a specific case. Rules setting forth general principles are necessary to ensure that adequate processes are in place.

See, e.g., Black Oak Energy, LLC

FERC,

Nos. 08-1386, 11-1275, 12-1286, 2013 WL 3988709, at *8 (D.C. Cir. Aug. 6, 2013) (stating “[W]e defer to reasonable and cogent explanations of predictable economic outcomes, even in the absence of retrospective data”);

Sacramento Mun. Util. Dist.

FERC,

616 F.3d 520, 542 (D.C. Cir. 2010); Louisiana

Pub. Serv. Comm'n

FERC,

551 F.3d 1042, 1045 (D.C. Cir. 2008);

Envtl. Action, Inc.

FERC,

939 F.2d 1057, 1064 (D.C. Cir. 1991) (stating, “[I]t is within the scope of the agency's expertise to make . . . a prediction about the market it regulates, and a reasonable prediction deserves . . . deference notwithstanding that there might also be another reasonable view”).

27. As acknowledged in the NOPR, the need for implementation of the reforms may not be uniform across the country.

The reforms adopted in this Final Rule will likely have a greater impact on Transmission Providers in areas with a significant penetration of distributed resources and a larger number of small generator interconnection requests.

The Commission believes that this Final Rule balances the needs of Small Generating Facilities and public utility Transmission Providers, while providing flexibility to different regions of the country. Moreover, to further accommodate regional differences and in response to the comments submitted by RTOs and ISOs, the Commission is allowing independent Transmission Providers to comply with this Final Rule under the independent entity variation standard or the regional differences standard, consistent with the approach adopted in Order No. 2006.

Finally, we affirm that it is not our intent in this Final Rule to interfere with state interconnection procedures and agreements in any way. Similar to our approach in Order No. 2006,

our hope is that states may find this rule helpful in formulating or updating their own interconnection rules, but states are under no obligation to adopt the provisions of this Final Rule.

NOPR, FERC Stats. & Regs. ¶ 32,697 at P 24.

Id.

at P 4.

See infra

section V.

Order No. 2006, FERC Stats. & Regs. ¶ 31,380 at P 8.

IV. Proposed Reforms

A. Pre-Application Report

1. Commission Proposal

28. According to the reforms included in the NOPR, Transmission Providers would be required to provide Interconnection Customers the option to request a pre-application report that would contain readily available information about system conditions at a Point of Interconnection in order to help that customer select the best site for its Small Generating Facility. The Commission proposed the pre-application report to promote transparency and efficiency in the interconnection process and to provide information to Interconnection Customers about system conditions at a particular Point of Interconnection.

NOPR, FERC Stats. & Regs. ¶ 32,697 at P 26.

29. To the extent available, the proposed pre-application report would include the following items:

a. Total capacity and available capacity of the facilities that serve the Point of Interconnection;

b. Existing and queued generation at the facilities likely serving the Point of Interconnection;

c. Voltage of the facilities that serve the Point of Interconnection;

d. Circuit distance between the proposed Point of Interconnection and the substation likely to serve the Point of Interconnection (Substation);

e. Number and rating of protective devices and number and type of voltage regulating devices between the proposed Point of Interconnection and the Substation;

f. Number of phases available at the proposed Point of Interconnection;

g. Limiting conductor ratings from the proposed Point of Interconnection to the Substation;

h. Peak and minimum load data; and

i. Existing or known constraints associated with the Point of Interconnection.

30. The Commission proposed a non-refundable $300 fee for the pre-application report and required that the report be provided within 10 business days of the initial request.

The Commission proposed that the pre-application report would only include information already available to the Transmission Provider.

Additionally, the proposed revisions to the

pro forma

SGIP, which were attached to the NOPR, state that “The pre-application report request does not obligate the Transmission Provider to conduct a

study or other analysis of the proposed generator in the event that data is not readily available.”

Id.

at P 28 and proposed

pro forma

SGIP at section 1.2.2.

NOPR, FERC Stats. & Regs. ¶ 32,697 at P 27.

Id.,

Appendix C, SGIP section 1.2.4.

2. Need for a Pre-Application Report

a. Comments

31. Many commenters support the concept of a pre-application report.

The California Public Utilities Commission (CPUC) supports the pre-application report and states that it will increase transparency and efficiency, reduce costs, and provide necessary information to Interconnection Customers.

Other commenters assert that the pre-application report is critical for developers to determine the best Points of Interconnection because it will eliminate some of the uncertainties involved in the interconnection process and thus reduce developer costs and schedule delays.

FCHEA states that the pre-application report will alert a project developer to potential issues at a Point of Interconnection prior to making a significant financial commitment.

NREL at 2; Clean Coalition at 3; CPUC at 4; CREA at 2; DCOPC at 4; Duke Energy at 3; ELCON at 4; FCHEA at 1; IECA at 4; LES at 1; NRECA, EEI & APPA at 6; and NRG at 5.

CPUC at 5.

CEP at 1; CREA at 2; DCOPC at 4; Duke Energy at 3; IREC at 9; NRG at 4; and Public Interest Organizations at 9.

FCHEA at 1.

32. A number of commenters state that the pre-application report will likely reduce the number of interconnection requests submitted to Transmission Providers because developers frequently submit multiple interconnection requests for a single project in an effort to determine the most advantageous Point of Interconnection.

Similarly, IREC and SEIA contend that a pre-application report would benefit Transmission Providers by reducing the volume of interconnection requests that are either non-viable or difficult to accommodate.

Finally, Sandia National Laboratories (Sandia) and SEIA state that the pre-application report will foster communication between developers and Transmission Providers and will improve the interconnection process.

AWEA at 3-4; CREA at 2; IREC at 9; ITC at 8; and NRG at 5.

IREC at 9 and SEIA at 10.

Sandia at 2 and SEIA at 12.

33. Several RTOs and ISOs,

however, contend that they already offer various opportunities for Interconnection Customers to ask questions and request information that is similar to the information in the pre-application report. These commenters state that information related to the type, amount and location of interconnected and pending projects and studies is readily available by phone, on their Web sites, or through their Critical Energy Infrastructure Information (CEII) process.

ISO New England (ISO-NE) asserts that there is no indication that the information it currently makes available to Interconnection Customers is insufficient.

ISO-NE., MISO, PJM, and NYISO.

ISO-NE at 8; MISO at 5-6; NYISO & NYTO at 13-14; and PJM at 5.

ISO-NE at 8.

34. Midcontinent Independent System Operator (MISO) states that its existing procedures, including a pre-application meeting, may be more effective than the proposed pre-application report procedures.

MISO asserts that a pre-application meeting achieves the same goals of transparency and data sharing without the cost and inefficient expenditure of resources that a pre-application report would require.

MISO further asserts that requiring the Transmission Provider to contact the Transmission Owner to collect information may be inefficient and that permitting the Interconnection Customer to directly contact the Transmission Owner may be more efficient.

MISO at 4 (referencing section 6.1 of MISO's Generator Interconnection Procedure).

Id.

at 5.

Id.

at 5-6.

35. The California Independent System Operator Corporation (CAISO) states that it supports the provision of a pre-application report, but in some cases the pre-application report information is only available from the participating Transmission Owner and in other cases it does not exist for networked transmission systems. CAISO requests that the Commission allow ISOs and RTOs to provide a pre-application report that is appropriate to interconnecting to a networked transmission system, such as existing and queued generation not at the same Point of Interconnection but affected by the same transmission constraints.

CAISO at 4.

36. San Diego Gas & Electric Company, Southern California Edison Company and Pacific Gas and Electric Company (California Utilities) state that larger interconnection projects should be required to obtain a pre-application report because it will increase the likelihood that these projects will select Points of Interconnection that qualify for Fast Track evaluation.

California Utilities at 4.

b. Commission Determination

37. The Commission concludes that providing the Interconnection Customer with the opportunity to request the pre-application report will benefit the interconnection process by helping Interconnection Customers make more informed siting decisions and may diminish the practice of requesting multiple interconnection requests for a single project, which benefits both Transmission Providers and Interconnection Customers. As such, the Commission adopts its proposal to require the Transmission Provider to provide Interconnection Customers with the opportunity to request a pre-application report, as modified herein.

38. While the Commission appreciates that some Transmission Providers may already make available some of the information in the pre-application report, commenters suggest that this information may not be available from all Transmission Providers. Therefore, the Commission finds it just and reasonable to include the pre-application report in the

pro forma

SGIP.

39. With regard to MISO's assertion that requiring the Transmission Provider to contact the Transmission Owner to collect information may be less efficient than permitting the Interconnection Customer to directly contact the Transmission Owner, we note that the Transmission Provider is generally the point of contact for the Interconnection Customer that coordinates the various SGIP processes (e.g., interconnection requests and the studies in the section 3 Study Process). As such, the Transmission Provider is expected to coordinate with the Transmission Owner and the Interconnection Customer, so we are not persuaded that we should adopt SGIP language requiring the Interconnection Customer to contact the Transmission Owner directly in the case of the pre-application report.

40. Finally, with regard to MISO's comment that its existing pre-application procedures may be more effective than the pre-application report proposed in the NOPR, as discussed below, in cases where provisions in public utility Transmission Providers' existing interconnection procedures would be modified by the Final Rule, public utility Transmission Providers must either comply with the Final Rule or demonstrate that previously approved variations meet one of the standards for variance provided for in this Final Rule.

See infra

section V.

3. Pre-Application Report Fee

a. Comments

41. Several commenters support the proposed $300 fee for the pre-application report.

IREC asserts that the $300 fee is appropriate for the effort required to provide the report, noting that there is currently no fee for the provision of similar system information under section 1.2.1 of the SGIP.

NREL states that the proposed $300 fee only allows the Transmission Provider to provide information that is quickly accessible.

CPUC at 4; CREA at 2; IREC at 12; MISO at 3-4; NRG at 5; and Public Interest Organizations at 9.

IREC at 12. Under section 1.2 of the

pro forma

SGIP, the Interconnection Customer may request from the Transmission Provider “relevant system studies, interconnection studies, and other materials useful to an understanding of an interconnection” at a specific proposed Point of Interconnection.

NREL at 3.

42. Several commenters, including many Transmission Providers, recommend that the Commission set the cost of the pre-application report equal to the Transmission Provider's actual incurred cost rather than a fixed $300 fee.

ISO-NE at 13-14; ITC at 7-8; NARUC at 5; NRECA, EEI & APPA at 16; and NREL at 3.

43. PJM Interconnection (PJM) estimates that the processing and preparation of a single report will take ten to twelve hours in administration, preparation, and final review and cost at least $1,500.

100

NRECA, EEI & APPA similarly state that, on average, the processing and preparation of a single report will likely require at least eight hours of an engineer's time, at a cost of $150 per hour, resulting in a minimum initial pre-application report fee of $1,200, not including time spent coordinating with the distribution utility to gather system information.

101

IREC, on the other hand, contends that the coordination between the Transmission Provider and the utility should not be overly burdensome for either party, and it is not significantly different from the coordination required during the SGIP Study Process.

102

100

PJM at 8.

101

NRECA, EEI & APPA at 16.

102

IREC at 12.

44. NRECA, EEI & APPA also request that the $300 fee be adjusted annually based on an inflation index, such as the Consumer Price or Handy-Whitman index, so that fees charged reflect the actual cost to prepare the pre-application report.

103

ITC proposes a “deposit/not-to-exceed” fee structure for the pre-application report whereby the Interconnection Customer submits a $300 deposit and designates a dollar amount that the Transmission Provider is not to exceed when preparing the report.

104

ITC proposes that the cost of the pre-application report be trued-up upon completion based on the Transmission Provider's actual incurred costs.

105

103

NRECA, EEI & APPA at 16.

104

ITC at 8.

105

Id.

at 8-9.

b. Commission Determination

45. The Commission finds that a fixed pre-application report fee will both provide cost certainty to Interconnection Customers and result in lower administrative costs than other fee structures. The Commission notes that this approach is similar to Commission treatment of other fixed processing fees in Order No. 2006.

106

Thus, the Commission will not adopt NRECA, EEI & APPA's proposal to index the pre-application report fee because Transmission Providers will have the opportunity to propose revisions to the fixed pre-application report fee in the compliance filing and in any subsequent FPA section 205 filings.

106

Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 126.

46. While the Commission believes that the $300 fee often will be adequate to recover Transmission Providers' costs of preparing the pre-application report given that Transmission Providers are only asked to provide “readily available” information, the Commission finds it would be unjust and unreasonable for Transmission Providers not to recover their actual pre-application report preparation costs. Accordingly, the Commission will adopt the $300 fee as the default fee in the

pro forma

SGIP and give Transmission Providers the opportunity to propose a different fixed cost-based fee for preparing pre-application reports supported by a cost justification as part of the compliance filing required by this Final Rule. The Commission notes that the Transmission Provider already provides information to the Interconnection Customer under section 1.2 of the

pro forma

SGIP. Therefore the pre-application report fee should only include the cost of providing the incremental information required under this Final Rule.

4. Pre-Application Report Timeline

a. Comments

47. The Commission received multiple comments about the ten-business-day timeline for providing the proposed pre-application report. MISO and Public Interest Organizations support the proposed ten-business-day timeframe for the pre-application report.

107

SEIA contends that a predictable date certain for the pre-application report is crucial for developers.

108

SEIA finds the proposed timeline reasonable, but requests that if the Commission extends the timeline, it allow Transmission Providers to request a one-time ten-day extension if necessary.

109

107

MISO Comments at 3-4; Public Interest Organizations at 9.

108

SEIA Reply Comments at 6.

109

Id.

at 7.

48. NRECA, EEI & APPA assert that SEIA's ten-day extension proposal would lead to inefficient use of Commission and utility resources, and that ten additional days would likely be insufficient in many circumstances.

110

Instead, NRECA, EEI & APPA request that the Commission clarify that section 4.1 of the current

pro forma

SGIP (“Reasonable Efforts”) provides the Transmission Provider with the option of promptly communicating to the Interconnection Customer the nature of any delays, including force majeure events,

111

in preparing a pre-application report and allows for both parties to agree on the Transmission Provider delivering the pre-application report on a different date.

112

NRECA, EEI & APPA state that this arrangement will give the developer some degree of certainty as to when it can expect to see a pre-application report, while allowing the utility reasonable flexibility given the realities of staffing and work load.

113

ISO-NE., PJM and the ISO/RTO Council (IRC) also ask the Commission to affirmatively state that section 4.1 of the SGIP applies to the pre-application report timeline.

114

110

NRECA, EEI & APPA Reply Comments at 13-14.

111

NRECA, EEI & APPA at 18, Appendix C (requesting that the Commission include language in the SGIP to cover delays related to force majeure events).

112

Id.

at 18-19.

113

Id.

at 19.

114

IRC at 9-10; ISO-NE at 12; and PJM at 10.

49. Duke Energy proposes that when a Transmission Provider has reached its maximum ability to process pre-application requests within the prescribed ten-business-day deadline, any subsequent requests received during that heavy volume period would be placed in a queue. Under Duke Energy's proposal, Interconnection Customers would be notified of the likely timing of the Transmission Provider's processing of their requests. Once the backlog of requests has been processed, the Transmission Provider would resume

processing pre-application requests within the ten-business-day period.

115

Duke Energy at 4-5.

50. ISO-NE also requests that the Commission allow for additional time for providing the pre-application report.

116

New York Independent System Operator and New York Transmission Owners (NYISO & NYTO) and PJM recommend that the Commission extend the proposed time period for processing the pre-application report to 20 business days.

117

IRC also states that ten business days is not enough time to produce the pre-application report and therefore asks the Commission to provide each region with the flexibility to propose its own time frame.

118

116

ISO-NE at 12-13.

117

NYISO & NYTO at 16; and PJM at 10.

118

IRC at 9.

b. Commission Determination

51. The Commission is persuaded by Transmission Provider comments that certain circumstances could make the ten-business-day timeline difficult to meet. The Commission will therefore modify its proposal and extend the pre-application report due date from 10 to 20 business days, as proposed by NYISO & NYTO and PJM.

119

We find that this deadline balances Transmission Provider concerns about having adequate time to prepare the report with Interconnection Customer concerns regarding the importance of knowing when they will receive the report. As such, Transmission Providers will be required to provide the pre-application report within 20 business days of the initial request.

119

NYISO & NYTO at 16; and PJM at 10.

52. With regard to the request of ISO-NE., IRC, PJM, and NRECA, EEI & APPA for clarification about whether section 4.1 (“Reasonable Efforts”) of the existing

pro forma

SGIP will apply to the pre-application report timeline,

120

we affirm that section 4.1 of the

pro forma

SGIP applies to the pre-application report. To not do so would mean that the Reasonable Efforts section would apply to some items in the SGIP and not others. As such, the Commission declines to adopt Duke Energy's proposal to establish a pre-application queue when a Transmission Provider experiences heavy volumes of pre-application report requests and is unable to meet the pre-application report timeline because such situations may be addressed under section 4.1 of the

pro forma

SGIP in a comparable, not unduly discriminatory manner. Nonetheless, the Commission notes that the pre-application report contains only readily available information, so we expect that the Transmission Provider should be able to produce a pre-application report within 20 business days in most circumstances.

120

IRC at 10; ISO-NE at 12; NRECA, EEI & APPA Reply Comments at 14; and PJM at 10.

5. Pre-Application Report Request Form

a. Comments

53. Several commenters recommend that Interconnection Customers complete a pre-application report request form to facilitate report preparation.

121

ITC offers as a basis for such a form that Interconnection Customers could designate broad geographic areas as proposed Points of Interconnection when requesting a pre-application report, thus requiring the Transmission Provider to select the exact Point of Interconnection for the Interconnection Customer.

122

121

IREC at 10; ISO-NE at 11; ITC at 10; NRECA, EEI and APPA at 13; NYISO & NYTO at 16; SEIA at 2; NREL at 2; and PJM at 9.

122

ITC at 10.

54. Such a form is also supported by the SWG

123

and PJM.

124

They suggest that the proposed pre-application request form seeks the following information from Interconnection Customers: (1) Project contact information; (2) project location, including street address with nearby cross streets and town; (3) meter number, pole number, or other equivalent information identifying the proposed Point of Interconnection; (4) type of generator; (5) size of generator; (6) single or three-phase generator configuration; (7) whether the generator is stand-alone or serves on-site load; and (8) whether the project requires new service or is an expansion of existing service.

125

123

See supra

note 23. The group drafted proposed revisions to the pre-application report proposal that were submitted by several commenters.

124

IREC at 10 and PJM at 9.

125

PJM at 9; IREC, Attachment A, §§ 1.2.2.1-1.2.2.8; NRECA, EEI & APPA, Attachment A, §§ 1.2.2.1-1.2.2.8; NREL, attachment to comments, §§ 1.2.2.1-1.2.2.8; and SEIA, Attachment B, §§ 1.2.2.1-1.2.2.8.

55. ITC, IRC and NYISO & NYTO also support a standardized pre-application report request form.

126

IRC states that, although it supports including a standard request form in each Transmission Provider's tariff, the Final Rule should allow the request form to vary by region if needed.

127

126

ITC at 10; IRC at 9; NRECA, EEI & APPA at 13; and NYISO & NYTO at 16.

127

IRC at 9.

b. Commission Determination

56. In response to commenter requests, the Commission adopts the standardized pre-application report request form as proposed by the SWG in section 1.2.2 of the

pro forma

SGIP, as modified herein

128

and with certain minor clarifying modifications, to use when requesting a pre-application report. The Commission believes the request form will resolve uncertainty about the precise location of the Point of Interconnection and expedite the pre-application report process.

128

See, e.g., supra

P 0.

6. Readily Available Information

a. Comments

57. SEIA and DCOPC state that the proposed pre-application report will not burden Transmission Providers because it will be compiled from existing material.

129

IREC claims that utilities have made significant investments in smart grid infrastructure, SCADA and other methods of gathering system information so that minimum and peak load data will be available in the future, and the SGIP should encourage the collection of such information.

130

Sandia and UCS raise similar arguments about the availability of this data.

131

129

DCOPC at 4 and SEIA at 11.

130

IREC at 10.

131

Sandia at 2 and UCS at 14-15.

58. Several commenters request that the Commission affirm that Transmission Providers are only required to provide existing information that is readily available in the pre-application report.

132

Additionally, multiple commenters request that the Commission define the terms “already available” and/or “readily available” as they relate to information provided in the pre-application report.

133

MISO suggests it means providing existing data in its existing form.

134

IRC further requests that the Commission clearly state in section 1.2.4 or add a new section 1.2.5 stating that “[a]ny further analysis related to the proposed generator or in follow-up to the information contained in the report shall be conducted pursuant to an interconnection request.”

135

132

Bonneville at 2-3; Duke Energy at 4; ISO-NE at 14; and MISO at 6.

133

Clean Coalition at 3; Duke Energy at 4; IRC at 10; and MISO at 6.

134

MISO at 6.

135

IRC at 10-11.

59. ISO-NE and NYISO & NYTO state that notwithstanding the caveat in section 1.2.4, the pre-application report only need include existing data and note that the inclusion of all of the categories of data listed in section 1.2.3 of the

pro forma

SGIP could create an unreasonable expectation regarding the information to be included in the pre-

application report.

136

ISO-NE and NYISO & NYTO therefore ask the Commission to clarify that the items proposed to be included in the pre-application report are examples that may be amended by the Transmission Provider based on readily available information.

137

IRC asks that the Commission allow each region to specify what information is actually available in a pre-application process to assist prospective Interconnection Customers.

138

136

ISO-NE at 9 and NYISO & NYTO at 15.

137

NYISO & NYTO at 14.

138

IRC at 10.

60. NREL comments that the proposed SGIP states that minimum daytime load information will be provided in the pre-application report “when available” and that this should be modified to state that load information “will be measured or calculated.”

139

FCHEA and CEP assert that one of the key pieces of information that should be included in the pre-application report is whether the 15 Percent Screen has been exceeded or is close to being exceeded on a particular line segment.

140

NRECA, EEI & APPA submitted proposed revisions to the information included in the pre-application report, including removing some items from the report.

141

IREC states that striking relevant pieces of information, such as minimum or peak load data, from the report because it may not be currently available would be inconsistent with policy goals and fails to recognize that grid investments may make the information possible to collect in the future.

142

139

NREL at 3.

140

CEP at 2 and FCHEA at 2.

141

NRECA, EEI & APPA, Appendix B at 1-2.

142

IREC at 9-10.

61. NRECA, EEI & APPA state that they are particularly concerned with the Commission's proposal to require that utilities provide minimum load and available capacity in the pre-application report when such data are not currently available.

143

They assert that collection of minimum load data is burdensome to most utilities because it is not a critical system operating criteria and is difficult to determine accurately.

144

143

NRECA, EEI & APPA at 14.

144

Id.

at 14.

62. Duke Energy states that although daytime minimum load data may be available where there are electronic meters and communication equipment, in many instances the data are available only at the substation circuit breaker and not by line section. Duke Energy therefore asserts that in some cases it would have to estimate the minimum load.

145

ITC suggests that the Commission explain how Transmission Providers should calculate minimum load for the purposes of the pre-application report.

146

145

Duke Energy at 5.

146

ITC at 9-10.

b. Commission Determination

63. The Commission appreciates Transmission Provider concerns about the burden associated with creating new information (either form or substance) for the purposes of the pre-application report. We reaffirm that Transmission Providers are only required to provide the items in the

pro forma

SGIP section 1.2.3 if they are readily available, in accordance with section 1.2.4 of the SGIP. Accordingly, in response to NRECA, EEI & APPA and Duke Energy, the provision of actual or estimated minimum load data is not required unless it is readily available. To address concerns with the definition of “readily available,” we clarify that “readily available” means information that the Transmission Provider currently has on hand. That is, the Transmission Provider is not required to create new data.

147

However, the Transmission Provider is required to compile, gather, and summarize the information that it has readily available to it in a format that presents useful information.

148

The costs associated with that effort should be commensurate with the fee the Transmission Provider charges for the pre-application report. If providing some of the items in the pre-application report would require the Transmission Provider to undertake studies or analysis beyond gathering and presenting existing information, then the information is not readily available and the Transmission Provider is not obligated to include this information in the report. We note, however, that performing simple calculations with existing information, such as calculating available capacity as described below, falls within the meaning of readily available information.

149

The Commission finds that requiring Transmission Providers to provide information in pre-application reports beyond what is readily available would increase Transmission Provider costs and likely result in the under-recovery of report preparation costs. The Commission believes the default $300 fixed fee is consistent with the readily available standard, which limits the effort required by Transmission Providers.

147

The Commission declines to prescribe a methodology for calculating minimum load for the purpose of the pre-application report, as requested by ITC, because such a calculation is not required for the sole purpose of the pre-application report. The provision of minimum load data in the pre-application report, whether actual or estimated, is only required if this information is readily available. Further, to the extent such a calculation is made under section 2.4.4.1 of the SGIP adopted herein, the Commission leaves the methodology to the discretion of the Transmission Provider.

148

See supra

P 0. The Commission clarifies that the Transmission Provider shall be the point of contact for the Interconnection Customer and may be required to coordinate with the Transmission Owner to execute the requirements of the SGIP adopted herein, including the pre-application report. Accordingly, we find that information that is readily available to the Transmission Owner shall be deemed readily available to the Transmission Provider as well.

149

See infra

P 0.

64. The Commission is also persuaded by IREC's comments that pre-application report items should not be struck from the report due to current unavailability because the items may become available in the future. Thus, the Commission finds that the default pre-application report should include the items listed from section 1.2.3 of the proposed SGIP while at the same time reaffirming that Transmission Providers are not obligated to provide information that is not readily available.

7. Other Issues

a. Comments

65. IREC, Pepco

150

and SEIA propose adding a new section 1.2.3.1 to the

pro forma

SGIP stating that the Transmission Provider will identify the substation/area bus, bank or circuit likely to serve the proposed Point of Interconnection and clarifying how the Transmission Provider will select which circuit to include as the Point of Interconnection in the pre-application report if there is more than one circuit to which the Interconnection Customer could connect.

151

The commenters also propose to clarify in section 1.2.3.1 that the Transmission Provider will not be liable if the selected circuit is not the most cost-effective option and explains that customers who want information on all options must request multiple pre-application reports.

152

150

Pepco Holdings Inc., Atlantic City Electric Company, Delmarva Power & Light Company, and Potomac Electric Power Company are referred to collectively as Pepco in this Final Rule.

151

IREC at 10; Pepco, Appendix to comment at section 1.2.3.1; SEIA at Attachment A section 1.2.3.1.

152

IREC at 10-11; Pepco at 6.

66. Several commenters,

153

including the SWG, note that the electric system is constantly changing and the information provided in the pre-application report might quickly become out of date. As a result, they request that the SGIP and each pre-application report that a utility

produces include a disclaimer indicating that the pre-application report is for informational purposes, is non-binding, and does not convey any rights in the interconnection process.

154

153

Duke Energy at 6; IREC Attachment A, section 1.2.2 presenting the SWG recommendations; and NRECA, EEI & APPA at 12.

154

NRECA, EEI & APPA at 12-13, and NYISO & NYTO at 16.

67. ITC argues that given its dynamic nature, Transmission Providers may not be able to accurately predict the available capacity of the substation/area bus or bank circuit most likely to serve the proposed Point of Interconnection at every point in time.

155

ITC proposes that the Commission specify that the Transmission Provider's base-case estimate of available capacity is sufficient for the pre-application report.

156

Duke Energy states that Interconnection Customers can calculate this available capacity from the information provided in sections 1.2.3.1 through 1.2.3.3 of the SGIP; therefore, the Transmission Provider should not be required to provide available capacity in the pre-application report.

157

155

ITC at 9.

156

Id.

at 9.

157

Duke Energy at 6.

68. Various commenters request that the pre-application report contain information that the Commission did not include in the NOPR. For example, several commenters propose to add the following items to the pre-application report: (1) Distance from a three-phase circuit if the Point of Interconnection is on a single-phase circuit; and (2) whether the Point of Interconnection is located on an area network, spot network, grid network, or radial supply.

158

IREC asserts that this approach will provide relevant system information to developers.

159

SEIA also proposes to include the substation/area bus, bank or circuit most likely to serve the Point of Interconnection.

160

NARUC states that the pre-application report should include a simple “yes” or “no” question as to whether minimum load data would be readily available should it be needed to help a developer remain in the Fast Track Process.

161

158

IREC at 11-12; NRECA, EEI & APPA Appendix B at 1; Pepco at 11; and SEIA at 11.

159

IREC at 11.

160

SEIA at 11.

161

NARUC at 5.

69. Landfill Energy Systems (LES) state that the pre-application report should identify the type of existing relays that are currently being utilized and any known, or likely, need to replace those relays.

162

LES states that if, for example, the Transmission Owner is likely to require the Interconnection Customer to replace and/or upgrade existing equipment, such as a relay system, a reclosing system, or a breaker failure protection system, or to install fiber optic cable, it should be noted in the pre-application report.

163

LES also requests that the pre-application report include a map that shows the Transmission Provider's lines in the area for the Interconnection Customer to consider as alternative Points of Interconnection.

164

162

LES at 2.

163

Id.

at 2-3.

164

Id.

at 3.

70. Clean Coalition recommends that the Commission require that Transmission Providers maintain information about all distribution interconnection applications in a public spreadsheet/database for easy review and tracking by developers, advocates, and policymakers.

165

Clean Coalition further asserts that, where warranted by demand, existing grid information should be made available in map and spreadsheet formats on the utility's Web site.

166

NRECA, EEI & APPA claim that the Clean Coalition's proposal is unduly burdensome, overbroad, ambiguous, may result in the release of CEII, and would constitute jurisdictional overreach by the Commission.

167

165

Clean Coalition at 5-6.

166

Id.

at 6.

167

NRECA, EEI & APPA Reply Comments at 15-16.

71. NRECA, EEI & APPA state that any information that is required to be included in the pre-application report must be consistent with existing safeguards against the public disclosure of non-public transmission system information, confidential information, or CEII.

168

CAISO similarly notes that some of the information may be proprietary to participating Transmission Owners or might be CEII, which could require a non-disclosure and limited use agreement.

169

168

NRECA, EEI & APPA at 14.

169

CAISO at 4.

72. PJM asks the Commission to clarify that although there may be some limited follow-up on the pre-application report (e.g., questions about the report from the Interconnection Customer), more detailed inquiries would need to be addressed through the submission of an interconnection request by the Interconnection Customer.

170

Duke Energy requests that the Commission clarify that any transmission information provided in the report would not be required to be posted on the OASIS.

171

NRECA, EEI & APPA state that each request related to a particular Point of Interconnection should be treated as a request for a separate pre-application report and the Transmission Provider must be able to collect a fee for each report it prepares.

172

NRECA, EEI & APPA assert that this is appropriate because requests for multiple interconnection points may require companies to gather information from various sources for each Point of Interconnection.

173

IREC and Pepco also propose SGIP language which states that customers who want information on multiple circuits at a single Point of Interconnection must request a separate pre-application report for each circuit.

174

170

PJM at 10.

171

Duke Energy at 6.

172

NRECA, EEI & APPA at 17.

173

Id.

174

IREC at 10-11; Pepco at 6.

73. CAISO suggests that the Commission may want to provide greater flexibility for Transmission Providers to fashion a pre-application process to exchange information with developers following issuance of a pre-application report if developers have any follow-up questions.

175

NYISO & NYTO suggest that Transmission Providers might provide the Interconnection Customer the option of a follow-up meeting to discuss the pre-application report.

176

Finally, ISO-NE proposes to refer to entities that request pre-application reports as “potential Interconnection Customers” rather than “Interconnection Customers” in section 1.2 of the SGIP, which outlines the pre-application report.

177

175

CAISO at 4.

176

NYISO & NYTO at 16.

177

ISO-NE at 10.

b. Commission Determination

74. The Commission agrees with commenters that the information provided in pre-application reports should be for informational purposes only given the dynamic nature of system conditions. Accordingly, the Commission will include a disclaimer in the

pro forma

SGIP and pre-application report stating that the information provided in the pre-application report is non-binding and that the Transmission Provider will not be held liable if information in the report is no longer accurate. The Commission notes that similar pre-application report disclaimers are proposed in SGIP proceedings in Ohio and Massachusetts.

178

Pub. Utilis. Comm'n of Ohio,

In the Matter of the Comm'n's Review of Chapter 4901:1-22, Ohio Admin. Code, Regarding Interconnection Servs.,

Case No. 12-2051-EL-ORD, at 7 (2013),

available at http://www.seia.org/sites/default/files/Ohio-Supplemental-Entry.pdf;

Mass. Dep't of Pub. Utils.,

Order on the Distributed Generation Working Group's Redlined Tariff and Non-Tariff Recommendations,

Docket No. D.P.U. 11-75-E, at 14 (2013).

75. NRECA, EEI & APPA, Pepco, SEIA, and IREC propose adding the following two items to the pre-application report: (1) For single-phase circuits, the distance of the Point of Interconnection from the three-phase circuit; and (2) whether the Point of Interconnection is located on an area network, spot network, grid network, or radial supply.

179

The Commission is persuaded that this additional information will be useful to assess whether a project will qualify for the Fast Track Process at a given Point of Interconnection. Furthermore, the information should be readily available to Transmission Providers because it relates to basic system configuration. Accordingly, sections 1.2.3.10 and 1.2.3.12 of the SGIP are revised to include these items.

179

See supra

note 158.

76. In order to clarify Interconnection Customer expectations with respect to the pre-application report, the Commission adopts IREC, SEIA and Pepco's proposed disclaimer that the bank or circuit selected by the Transmission Provider in the pre-application report does not necessarily indicate the circuit to which the Interconnection Customer may ultimately connect. The disclaimer is added to section 1.2.3 of the SGIP. However, the Commission declines to adopt IREC, SEIA and Pepco's request to clarify how the Transmission Provider will select which circuit to include in the pre-application report if there is more than one circuit to which the Interconnection Customer could interconnect because methodologies for selecting a circuit may be differ depending on the circumstances of the proposed interconnection and may differ among Transmission Providers. If Transmission Providers wish to provide this information to Interconnection Customers, they may do so in business practices.

77. In response to Duke Energy's inquiry, the Commission affirms that information Transmission Providers provide in the pre-application will have no bearing on OASIS reporting requirements. The Commission also affirms that the pre-application report only applies to a single Point of Interconnection and that Interconnection Customers must submit payment and separate pre-application request forms if they are requesting information about multiple Points of Interconnection, including multiple circuits at a single Point of Interconnection. The Commission also finds that it would be unjust and unreasonable to expect the Transmission Provider to bear the cost of any follow-up studies resulting from the pre-application report. Therefore, apart from reasonable clarification of items in the pre-application report, the Transmission Provider is not required as part of this Final Rule to conduct any studies or analysis after furnishing the pre-application report unless the Interconnection Customer proceeds with a formal interconnection request.

78. The Commission expects Transmission Providers to continue to abide by the recommendations outlined in section 1.1.5 of the

pro forma

SGIP and with section 1.2.1 of the

pro forma

SGIP, which states that information may be provided “to the extent such provision does not violate confidentiality provisions of prior agreements or critical infrastructure requirements” and that “[t]he Transmission Provider shall comply with reasonable requests for such information.”

79. The Commission rejects ISO-NE's request to refer to entities requesting pre-application reports as “potential Interconnection Customers” within the

pro forma

SGIP because we are not aware that use of the term “Interconnection Customer” in the pre-application section 1.2 of the

pro forma

SGIP adopted under Order No. 2006 caused confusion or set incorrect expectations for Interconnection Customers or Transmission Providers.

80. The Commission rejects LES's request that Transmission Providers indicate what upgrades, if any, will be required at a Point of Interconnection when preparing a pre-application report for that Point of Interconnection. This information may not be readily available to a Transmission Provider.

81. The Commission is not persuaded by Duke Energy's assertion that it is unreasonable to ask Transmission Providers to provide available capacity, or an estimate of available capacity. Providing available capacity will not burden the Transmission Provider because doing so only requires Transmission Providers to subtract aggregate existing and queued capacity from total capacity, and will provide additional clarity to the interconnection customer.

82. The Commission finds Clean Coalition and LES's proposal to make certain small generator interconnection data publicly available as beyond the scope of the NOPR. However, we encourage Transmission Providers to look for ways to streamline the provision of and make transparent relevant public information in order to facilitate small generator interconnections.

B. Threshold for Participation in the Fast Track Process

1. Commission Proposal

83. In the NOPR, the Commission proposed to revise the 2 MW threshold for participation in the Fast Track Process to be based instead on individual system and generator characteristics up to a limit of 5 MW, as shown in Table 1 below.

ER05DE13.000

2. Comments

84. Many commenters support increasing the Fast Track threshold from 2 MW to 5 MW.

181

IREC states that the purpose of eligibility limits to the Fast Track Process should be to filter out projects that are highly unlikely to pass the Fast Track screens in order to save time and set clear customer expectations. However, IREC states that the eligibility limits do not need to duplicate or go beyond the Fast Track screens themselves.

182

180

NOPR, FERC Stats. & Regs. ¶ 32,697 at P 30.

181

AWEA at 4; CREA at 2; IECA at 4-5; NRG at 5; SEIA at 13-14; Clean Coalition at 7; CEP at 1; ELCON at 4-5; ESA at 3-4; FCHEA at 1; IECA at 4-5; IREC at 13; LES at 2; Sandia at 2; and Public Interest Organizations at 10.

182

IREC at 13.

85. DCOPC states that it has no objections to the new Fast Track eligibility table proposed for section 2.1 of the SGIP or to raising the maximum eligibility size from 2 MW to 5 MW, as long as this change does not compromise system safety and grid reliability.

183

DCOPC at 5.

86. Sandia supports the new Fast Track eligibility proposal in the NOPR, as it more accurately differentiates interconnection requests that do not cause impacts from those that could need further study and states that the characteristics in the proposal for Fast Track eligibility are technically reasonable.

184

Sandia at 2.

87. Clean Coalition states that it prefers no Fast Track eligibility threshold because the Fast Track screens themselves eliminate projects that are not appropriate for the Fast Track Process.

185

However, Clean Coalition states that because of utility concerns about eliminating the threshold, it supports the Commission's proposal for increasing the threshold.

186

185

Clean Coalition at 7.

186

Id.

88. Max Hensley states that the Commission should allow facilities of up to 10 MW to qualify for the Fast Track Process. Mr. Hensley believes this would increase the market for distributed solar power generation and lower prices for residential customers.

187

Max Hensley at 1.

89. ITC generally supports increasing the upper bound of the Fast Track proposal based on line voltage, line amperage and proximity to the substation but is concerned that Interconnection Customers will abuse the 5 MW limit by submitting multiple interconnection requests for the same project in an effort to circumvent the Study Process, to the detriment of system reliability (e.g., a 20 MW wind farm comprised of five 4-MW wind turbines might submit five separate interconnection requests rather than a single 20 MW interconnection request). ITC recommends that the Commission allow individual ISOs or RTOs to coordinate Fast Track interconnections through their existing interconnection queue process to ensure Interconnection Customers are not able to circumvent the required studies necessary to protect safety and reliability.

188

ITC at 11.

90. ISO-NE requests that the Final Rule allow flexibility to account for eligibility limits that may be unique to the region. For example, ISO-NE states that eligibility for the Fast Track Process in New England is limited to interconnections to distribution facilities and does not apply to facilities rated 69 kV or higher that are used for regional transmission service.

189

ISO-NE at 15.

91. NYISO & NYTO do not believe the Commission's proposed expansion of the Fast Track eligibility to 5 MW and the introduction of minimum load and other screens for the supplemental review process are likely to improve the time and cost to process the interconnection requests of small facilities in New York at this time.

190

NYISO & NYTO state that most of the very small generating facilities in New York seek to interconnect to distribution facilities that are not subject to the Commission's jurisdiction and are generally able to skip most, if not all, of the time and expense of the full study process due to their limited system impacts.

191

190

NYISO & NYTO at 16.

191

Id.

at 16-17.

92. Duke Energy states that the proposed values in the Fast Track threshold table are not realistic for distribution systems. Duke Energy asserts that, based on its experience, a 1 MW generator proposing to interconnect to its distribution facilities

under 5 kV, which are lightly loaded and have small conductor sizes, would not pass the Fast Track screens because it would likely exceed the minimum load of the line section and might exceed the rating of the conductor.

192

Duke Energy therefore urges the Commission to consider lowering the proposed threshold levels to values that are more realistic for a distribution system.

193

192

Duke Energy at 7.

193

Id.

at 9-10.

See

Duke Energy at 9 for its proposed Fast Track eligibility table.

93. NRECA, EEI & APPA support basing Fast Track eligibility on individual system and generator characteristics.

194

They state that it is difficult to use the size of the generator as a threshold to determine whether the Small Generating Facility should go through the Fast Track Process and that the location of the point of common coupling and the interconnecting feeder and loading characteristics should be major factors for determining Fast Track eligibility.

195

194

NRECA, EEI & APPA at 19.

195

Id.

at 19-20.

94. NRECA, EEI & APPA assert that there is no standard definition of distribution system voltages in the United States and that there needs to be an upper bound voltage class limit that captures voltages of up to 69 kV. They state that the Commission should continue to follow its own precedent of taking into account the differences in utilities' distribution systems by building a degree of flexibility into the Final Rule with respect to the criteria for determining Fast Track eligibility.

196

Id.

at 20.

95. NRECA, EEI & APPA note that in Massachusetts and Rhode Island, the Fast Track Process does not include a 2 MW limit, but instead inverter-based equipment that has been “listed” using the UL1741 testing procedure is eligible for an expedited process.

197

They state that multiple inverter projects may or may not be considered “listed” in the proposed configuration, which means that some projects may not be eligible for the Fast Track Process.

198

According to NRECA, EEI & APPA, on a regional level, the capacity of solar projects that tend to pass the screen tests is typically in the 2 MW range. They therefore urge the Commission to keep this factor in mind when considering raising the limit to 5 MW.

199

197

Id.

198

Id.

at 20-21.

199

Id.

at 21.

96. NRECA, EEI & APPA state that they are concerned that the third column of the Fast Track eligibility table in the NOPR, which refers to the location of a distributed generation facility on the feeder system relative to the distance from the source substation, would raise expectations from developers that they may be eligible for the Fast Track Process when they may not be.

200

The SWG agreed on proposed revised language to be inserted in section 2.1 of the SGIP to clarify the intent of the Fast Track eligibility limits and to address concerns regarding the role of the eligibility limits in setting customer expectations.

201

200

Id.

201

IREC at 14.

97. Several commenters

202

submitted the table for Fast Track eligibility proposed by the SWG as shown in Table 2 below. The SWG proposes revising the Fast Track eligibility threshold applicable to inverter-based generators. The SWG also proposes the following changes to Fast Track Process eligibility: (1) Making all projects interconnecting to lines greater than 69-kV ineligible for the Fast Track Process (inverter-based projects interconnecting to lines up to and including 69 kV would be eligible for the Fast Track Process based on Table 2 below); (2) maintaining the current 2 MW limit for Fast Track eligibility for synchronous and induction machines (as opposed to inverter-based generators); (3) for lines below 5 kV, changing the Fast Track eligibility regardless of location to 500 kW for inverter-based projects; and (4) in the third column of the table, replacing “≥ 600 Ampere Line” with “a Mainline” and a footnote defining “Mainline.”

203 204 205

202

NRECA, EEI & APPA Appendix A; IREC Attachment A; NREL Attachment; and SEIA Attachment B. The Commission notes that there were minor differences among the tables submitted by NRECA, EEI & APPA, IREC, SEIA and NREL.

203

IREC at 14-15.

204

NRECA, EEI & APPA, Appendix A.

205

AWG is American wire gauge, a standardized system used for the diameters of round conducting wires to help determine its current-carrying capacity and electrical resistance.

Table 2—Fast Track Eligibility for Listed Inverter-Based Systems as Proposed by NRECA, EEI & APPA

Line voltage

Fast Track eligibility regardless of

location

Fast Track eligibility on a mainline * and ≤2.5 miles ** from substation

<5 kilovolt (kV)

≤500 kW

≥5 kV and <15 kV

≤2 MW

≤3 MW

≥15 kV and <30 kV

≤3 MW

≤4 MW

≥30 kV and <70 kV

≤4 MW

≤5 MW

* For purposes of this table, a mainline will typically constitute lines with wire sizes of 4/0 AWG, 336.4 kcmil, 397.5 kcmil, 477 kcmil and 795 kcmil.

** Electrical Circuit Miles.

*** An Interconnection Customer can determine this information in advanced [sic] by requesting a Pre-Application Report pursuant to section 1.2 [of the SGIP].

98. IREC believes the proposed revisions to the Fast Track eligibility table agreed to by the SWG are reasonable and reflect a technically justified approach to Fast Track eligibility. It recommends that the Commission adopt the proposed revisions.

206

Further, IREC states that some projects connecting to lines greater than 69 kV should go through the Study Process because the cost of interconnecting to larger lines is likely to be significant enough that generators may benefit from a more thorough cost estimate.

207

Regarding the 2 MW Fast Track eligibility limit for synchronous, induction machines, IREC notes that there are important technical differences between these generators and inverter-based systems that may require further consideration, so the SWG agreed that the Commission should maintain the current limit for these generators.

208

Finally, IREC states that although it believes that the MW limits proposed by the Commission in the NOPR are sufficiently conservative, it supports the

SWG proposal because it provides comfort to utilities interconnecting generators on lines below 5 kV.

209

206

IREC at 14.

207

Id.

at 15.

208

Id.

209

Id.

99. While SEIA would prefer to eliminate the threshold for participation in the Fast Track Process, it views the Commission's proposal as a reasonable and appropriate balance between a developer's need for an efficient interconnection process and the safety and reliability concerns raised with respect to broadening the Fast Track screens.

210

SEIA supports the agreement reached by the SWG on revisions to the Commission's proposal, which primarily narrows the scope of projects that would be eligible for the Fast Track Process at either end of the voltage spectrum, while maintaining Fast Track eligibility for the vast majority of distributed solar projects.

211

SEIA believes the Commission's proposal as modified by the SWG represents a reasonable compromise between developers and Transmission Providers and therefore recommends that the Commission adopt the SWG's proposal on Fast Track Process eligibility.

212

Public Interest Organizations and NREL also support the SWG's proposed changes to Fast Track eligibility.

213

210

SEIA at 13-14.

211

Id.

at 14.

212

Id.

213

NREL at 3 and Public Interest Organizations at 10-11.

100. NYISO & NYTO support the SWG's revised Fast Track eligibility table, but state that the upper voltage limit for a very small generating facility's eligibility in the Fast Track Process should be limited to 50 kV.

214

They note that the system modifications and costs associated with a Small Generating Facility interconnecting to 69 kV facilities in New York will require careful evaluation to ensure safety and reliability and should therefore remain within the Study Process.

215

214

NYISO & NYTO at 17.

215

Id.

101. AWEA opposes limiting Fast Track eligibility to 2 MW for synchronous and induction machines. AWEA states that it understands the reason for this limit is due to concerns about the fault current contribution of different types of wind turbine generators. It states that these concerns are unfounded and that wind turbines up to 5 MW should be allowed to participate in the Fast Track Process. Alternatively, AWEA states that screens that identify the type of wind turbine and the fault current contribution of that type could be used to allow wind turbines to participate in the Fast Track Process up to 5 MW.

216

AWEA Supplemental Comments at 3-5.

3. Commission Determination

102. The Commission concludes that it is just and reasonable to adopt the Fast Track eligibility thresholds proposed by the SWG, with modifications as discussed below.

103. The Commission agrees with the following reforms proposed by the SWG: (1) Modifying Fast Track eligibility for inverter-based machines to be based on individual system and generator characteristics; (2) for lines below 5 kV, limiting Fast Track eligibility to generators less than 500 kW for a conductor less than 5 kV regardless of location; and (3) making all projects interconnecting to lines greater than 69-kV ineligible for the Fast Track Process. The Commission finds that the modifications to Fast Track eligibility proposed by the SWG, reflected in Table 3 below, are just and reasonable and strike a balance between allowing larger projects to use the Fast Track Process while ensuring safety and reliability.

Table 3—Fast Track Eligibility for Inverter-Based Systems, as Adopted in This Final Rule

Line voltage

Fast Track eligibility regardless of

location

Fast Track eligibility on a mainline

and ≤2.5 electrical

circuit miles from

substation

<5 kilovolt (kV)

≤500 kW

≥5 kV and <15 kV

≤2 MW

≤3 MW

≥15 kV and <30 kV

≤3 MW

≤4 MW

≥30 kV and ≤69 kV

≤4 MW

≤5 MW

For purposes of this table, a mainline is the three-phase backbone of a circuit. It will typically constitute lines with wire sizes of 4/0 American wire gauge, 336.4 kcmil, 397.5 kcmil, 477 kcmil and 795 kcmil.

An Interconnection Customer can determine this information about its proposed interconnection location in advance by requesting a pre-application report pursuant to section 1.2 of the SGIP.

104. The SWG's proposed Fast Track eligibility table indicates that it is applicable to “listed” (see Table 2 above) inverter-based systems. However, section 2.1 of the SGIP states that a Small Generating Facility must meet the “codes, standards, and certification requirements of Attachments 3 and 4” of the SGIP, “or the Transmission Provider has to have reviewed the design or tested the proposed Small Generating Facility and is satisfied that it is safe to operate.” In order to eliminate potential confusion regarding the applicability of the Fast Track Process and to eliminate potential conflicts between the language of section 2.1 of the SGIP and the Fast Track eligibility table (Table 3 above), the Commission does not adopt the references to listing or certification in the title of the table submitted by the SWG. In doing so, the text of the Fast Track eligibility table will be consistent with section 2.1, which allows that Small Generating Facilities either be certified

have been reviewed or tested by the Transmission Provider and determined to be safe to operate. We also note that in section 2.1 of the SGIP, we only refer to “certified inverter-based systems” rather than “listed or certified inverter-based systems” as proposed by the SWG because listing is a type of certification under Attachments 3 and 4 of the SGIP.

105. The Commission acknowledges comments stating that voltages below 5 kV are being phased out. Nonetheless, such facilities can still be found in parts of the country and, therefore, our reforms must address reliability concerns with this voltage class. We conclude that imposing lower limits on lower voltage lines is reasonable. As Duke Energy notes in its comments, a request to interconnect to distribution facilities under 5 kV, which are typically lightly loaded and have small conductor sizes, would likely exceed the minimum load of the line section and the conductor rating.

106. The Commission will maintain the 2 MW Fast Track threshold for

synchronous and induction machines as suggested by the SWG because there are important technical differences between these generators and inverter-based generators. The Commission notes that, in general, the technical characteristics of synchronous and induction machines, such as higher fault current capabilities, may require further study to ensure the safety and reliability of the interconnection.

217

Therefore, we agree that synchronous and induction machines should continue to be subject to the 2 MW Fast Track threshold.

218

We are not persuaded by AWEA that the safety and reliability concerns of the SWG associated with synchronous and induction machines are unfounded and therefore decline at this time to include these machines in Fast Track eligibility beyond the existing 2 MW threshold. Further, in response to AWEA's proposal to modify the Fast Track Process to include screens based on the type of wind turbine and the fault current contribution of that type to allow wind turbines to participate in the Fast Track Process up to 5 MW, we find that AWEA's proposal has not been developed and vetted in this rulemaking process, therefore we decline to adopt the proposal.

219

We note, however, that in accordance with section 2.1 of the SGIP, synchronous and induction machines up to 5 MW that are interconnected to the Transmission Provider's system through a certified inverter or that have been reviewed or tested by the Transmission Provider and determined to be safe to operate may be interconnected under the Fast Track Process in accordance with Table 3 above.

217

Thomas Cleveland & Michael Sheehan, Updated Recommendations for FERC Small Generator Interconnection Procedures Screens (July 2010),

available at http://www.solarabcs.org/about/publications/reports/ferc-screens/pdfs/ABCS-FERC_studyreport.pdf,

p. 2 and Appendix I.

218

We note that inverter-based wind turbines would not be excluded from the 2 MW to 5 MW thresholds shown in the Fast Track eligibility table adopted in this Final Rule.

219

If a Transmission Provider prefers to adopt Fast Track eligibility criteria that differ from the table adopted in this Final Rule and that would accomplish AWEA's proposal, it may propose to do so as part of its compliance filing. Transmission Providers that propose to adopt different Fast Track eligibility criteria must submit compliance filings demonstrating that their proposed approach is consistent with or superior to the table adopted in this Final Rule, or meets another standard allowed in section V of this Final Rule.

107. The Commission adopts the SWG proposal to limit Fast Track eligibility to those projects connecting to lines at 69 kV and below. The Commission is persuaded by commenters

220

that even though not all Small Generating Facilities interconnecting to lines above 69 kV would require study, some of them will, and the Commission agrees that the costs and system modifications of interconnecting to lines larger than 69 kV are likely significant enough that generators may benefit from the more thorough estimate developed through the Study Process.

220

IREC at 14-15, Public Interest Organizations at 11.

108. Regarding ITC's concerns, the Commission believes that the potential for Interconnection Customers to submit multiple interconnection requests for the same project in an effort to circumvent the Study Process is limited because the Fast Track screens consider the aggregate generation on a line section.

109. The Commission acknowledges NYISO & NYTO's comment that certain facilities in New York may require a detailed study to ensure safety and reliability. However, the Fast Track Process itself will identify such facilities so they need not be eliminated from Fast Track eligibility.

110. Finally, to address NRECA, EEI & APPA's concern that the third column of the Fast Track eligibility table in the NOPR could raise Interconnection Customer expectations regarding eligibility for the Fast Track Process, the Commission adopts language in section 2.1 of the

pro forma

SGIP reminding small generators that Fast Track eligibility is distinct from the Fast Track Process itself, and that being found eligible for the Fast Track Process does not imply or indicate that a project will pass the Fast Track or supplemental review screens.

221

The Commission adds the following language to the first paragraph of section 2.1 of the SGIP:

However, Fast Track eligibility is distinct from the Fast Track Process itself, and eligibility does not imply or indicate that a Small Generating Facility will pass the Fast Track screens in section 2.2.1 below of the Supplemental Review screens in section 2.4.1 below.

C. Fast Track Customer Options Meeting and Supplemental Review

1. Commission Proposal

111. In the NOPR, the Commission proposed modifications to the customer options meeting following the failure of any of the Fast Track screens. The Commission proposed to require the Transmission Provider to offer to perform a supplemental review of the proposed interconnection without condition.

222

Additionally, the Commission proposed to modify the supplemental review by including three screens: (1) The Minimum Load Screen; (2) the power quality and voltage screen; and (3) the safety and reliability screen.

223

222

Section 2.3.2 of the SGIP adopted in Order No. 2006 gave the Transmission Provider the discretion to offer to perform a supplemental review if the “Transmission Provider concludes that the supplemental review might determine that the Small Generating Facility could continue to qualify for interconnection pursuant to the Fast Track Process.”

223

For the full text of the proposed screens, see section 2.4 of Appendix C to the NOPR. “Minimum Load Screen” refers to SGIP section 2.4.1.1 of Appendix C to the NOPR or SGIP section 2.4.4.1 of Appendix C to the Final Rule. The Minimum Load Screen tests whether the aggregate Generating Facility capacity on a line section is less than 100 percent of minimum load for all line sections bounded by automatic sectionalizing devices upstream of the proposed Small Generating Facility (using 100 percent of daytime minimum load for solar PV generators with no battery storage and 100 percent of absolute minimum load for all other Small Generating Facilities).

112. The Commission also proposed language in section 2.4.2 of the SGIP to clarify the requirements following the conclusion of the supplemental review. The Commission proposed that the Transmission Provider perform the supplemental review for a nonrefundable fee of $2,500.

2. General Comments on the Customer Options Meeting and the Supplemental Review

a. Comments

113. Several commenters support the Commission's proposed supplemental review reforms.

224

ITC expresses general support for the proposed changes in the customer options meeting and supplemental review process but offers several recommendations.

225

IREC supports the proposed supplemental review process with the optional use of “hosting capacity.”

226

IREC states that utilities operating with high distributed generation penetrations have found that with additional time and screening, they are able to safely interconnect generators without full study (

e.g.,

California and Hawaii have adopted screens similar to those in the NOPR).

227

SEIA believes the proposed supplemental review reforms will support the interconnection of renewable generation needed to meet the demand created by state policies.

228

AWEA and IREC both assert that the

proposed revisions to the supplemental review process are a well-designed solution for efficiently handling increased volume and penetrations of distributed generation without compromising safety and reliability.

229

NRG Companies states the revised supplemental review process will provide transparency and allow small generators to avoid lengthy and costly interconnection procedures.

230

224

AWEA, CEP, Clean Coalition, DCOPC, ELCON, FCHEA, IREC, NRG, Public Interest Organizations, SEIA, and UCS.

225

ITC at 11.

226

IREC at 17. “Hosting capacity” is an alternative approach to the interconnection procedures in the NOPR under which the Transmission Provider calculates the maximum aggregate generating capacity that a distribution circuit can accommodate at a proposed Point of Interconnection without requiring the construction of facilities by the Transmission Provider on its own system and while maintaining the safety, reliability and power quality of the distribution circuit.

See infra

P 0.

227

IREC at 19.

228

SEIA at 6.

229

AWEA at 4 and IREC at 17.

230

NRG at 4.

114. CPUC notes that the proposed supplemental review screens are modeled after California's Electric Rule 21 and recommends that the Commission adopt the supplemental review screens.

231

CPUC states that the proposed supplemental review screens will harmonize state and federal interconnection standards, allow for increased penetration of Small Generating Facilities, and are consistent with safe and reliable electric service.

232

231

CPUC at 6-7. California Electric Rule 21 is the California distribution level interconnection rules and regulations (Rule 21). It includes supplemental review screens similar to those proposed by the Commission in the NOPR.

232

CPUC at 7.

115. MISO warns that although the additional screens are designed to create more cohesiveness between the parties and to increase the movement of projects through the interconnection queue, they can instead lead to conflict over the underlying data used in the screens.

233

MISO at 8-9.

116. NYISO & NYTO state that the time required to perform the supplemental review screens would be better spent conducting an Interconnection Feasibility Study.

234

According to NYISO & NYTO, requiring that the performance of the additional screens could exacerbate, rather than mitigate, the time and costs associated with the interconnection process and would not preclude the possibility that the proposed Small Generating Facility may still be required to participate in the Study Process.

235

234

NYISO & NYTO at 20-21.

235

Id.

at 21.

b. Commission Determination

117. The Commission adopts the proposed revisions to the customer options meeting and the supplemental review, with some modifications as discussed below, including three supplemental review screens (the Minimum Load Screen,

236

the voltage and power quality screen

237

and the safety and reliability screen

238

). The Commission is persuaded by the comments and by the apparent successful implementation thus far of a similar process in California that the revised customer options meeting and supplemental review will enhance transparency and consistency of the supplemental review process and thus ensure that interconnection remains just and reasonable and not unduly discriminatory, particularly in regions with increasing penetrations of Small Generating Facilities. The Commission further finds that the SGIP retains sufficient flexibility (e.g., through the initial Fast Track screens in section 2.2.1) to meet the needs of regions that do not have significant penetrations of Small Generating Facilities. The Commission believes adopting the revisions to the customer options meeting and the supplemental review best balances the benefits of interconnecting Small Generating Facilities under the quicker, less costly Fast Track Process with the needs of Transmission Providers to protect the safety and reliability of their systems.

236

See

SGIP section 2.4.4.1 of Appendix C attached hereto.

237

See

SGIP section 2.4.4.2 of Appendix C attached hereto.

238

See

SGIP section 2.4.4.3 of Appendix C attached hereto.

3. Minimum Load Screen (SGIP Section 2.4.4.1)

a. Comments

118. IREC, SEIA, the Vote Solar Initiative (VSI) and UCS support including the Minimum Load Screen in the supplemental review.

239

IREC contends that minimum load is an appropriate evaluation standard in the SGIP supplemental review because minimum load is a more accurate metric for evaluating system risk, and many utilities have or soon will have a year or more of minimum load data on some circuits.

240

According to IREC, utilities that are not experiencing high penetrations of distributed generation will not have a need to determine minimum load in the near term and will have time to refine their process for evaluating minimum load as distributed generation penetration grows in their service territory.

241

239

IREC at 17; SEIA at 4-5; VSI at 2; and UCS at 18-19.

240

IREC at 17-18.

241

Id.

at 18-19.

119. SEIA states that without the Minimum Load Screen, ratepayers will bear the cost of unnecessarily costly and complex interconnection processes, and that achievement of the states' clean energy policies may be jeopardized.

242

Public Interest Organizations state that the Minimum Load Screen will accommodate higher penetrations of distributed generation without creating significant backlogs in study queues.

243

242

SEIA at 6.

243

Public Interest Organizations at 13-14.

120. SEIA and AWEA state that the Minimum Load Screen, which is similar to CPUC Rule 21, is a national best practice for distributed generation penetration levels and demonstrates that aggregate interconnected generating capacity can be 100 percent of minimum load on a distribution line section without impairing safety or reliability.

244

SEIA notes that the California Utilities called Rule 21 “a model for use in reforming the Fast Track [P]rocess”

245

and that EEI indicated support for a minimum load screen similar to the one in Rule 21 in the context of a supplemental review process.

246

SEIA states that California's experience with Rule 21 demonstrates the viability of the Minimum Load Screen on a national level so there is no need for a lower standard.

247

Given the widespread support for the Minimum Load Screen, NREL analysis, the CPUC's adoption of the Rule 21 minimum load screen, and the technical feasibility and protections afforded by the other proposed supplemental review screens, SEIA urges the Commission to adopt the proposed supplemental review process, including the Minimum Load Screen.

248

Clean Coalition credits the Rule 21 supplemental review with leading to significant improvements in the Fast Track Process, including allowing larger projects to succeed under the Fast Track Process than would be allowed under the 15 Percent Screen.

249

FCHEA recommends that all types of distributed generation, especially stationary fuel cells, be included in the new screen.

250

244

SEIA at 6; AWEA at 4.

245

SEIA at 6 (citing comments of the California Utilities in Docket No. AD12-17-000 at 4).

246

Id.

at 6-7 (citing EEI comments in Docket No. AD12-17-000 at 11, n. 10).

247

Id.

at 10.

248

Id.

249

Clean Coalition at 7.

250

FCHEA at 2.

121. NREL considers minimum daytime load, as included in the proposed Minimum Load Screen, to be the appropriate approach for solar PV systems because it more precisely estimates the ratio between generation and load on a line section.

251

NREL at 4.

122. NRECA, EEI & APPA and NYISO & NYTO do not support the Minimum Load Screen, stating that minimum load is not a critical system operating criterion and cannot be determined accurately because line section

monitoring is typically unavailable.

252

NRECA, EEI & APPA contend that the investment needed to obtain the data would be unacceptably high unless a utility has other operational reasons for investing in the measuring devices needed to acquire the data.

253

252

NRECA, EEI & APPA at 23 and NYISO & NYTO at 21.

253

NRECA, EEI & APPA at 23.

123. Duke Energy expresses concern about the proposal to calculate daytime minimum load, stating that calculating minimum load when actual load data are not available may not adequately reflect system conditions.

254

Duke Energy at 11-12.

124. SEIA claims that NRECA, EEI & APPA's NOPR comments that describe how utilities use other sources of information to estimate minimum load data demonstrate that the proposed

pro forma

SGIP gives Transmission Providers sufficient flexibility to perform the Minimum Load Screen when minimum load data are not available.

255

SEIA Reply Comments at 4.

125. UCS asserts that the Commission should order utilities to start collecting daytime minimum load data in areas where distributed generation penetration levels of five percent of peak load or higher are proposed.

256

UCS at 20.

126. NRECA, EEI & APPA contend that utilities must take an “appropriately cautious” approach to integrating distributed generation because the industry is still in the early stages of evaluating the impact that increased distributed generation will have on transmission and distribution systems.

257

They claim that rapid integration of distributed generation can cause the flow direction to change and introduce significant reliability concerns. They argue that while interconnection studies may identify reverse power flow issues and possible solutions, more detailed studies of individual line protection and control devices are necessary to prevent damage to Transmission Provider equipment.

258

257

NRECA, EEI & APPA Reply Comments at 7.

258

Id.

at 6.

127. NRECA, EEI & APPA dispute SEIA's claims that the Minimum Load Screen is widely supported, offering their own opposition as evidence to the contrary. They also urge the Commission to give substantial weight to Transmission Provider comments about the Minimum Load Screen because they are responsible for ensuring the safety and reliability of their systems.

259

Id.

at 10.

128. NRECA, EEI & APPA assert that the Minimum Load Screen: (1) Is not consistent with Good Utility Practice because utilities typically do not operate their systems at or beyond the threshold of when problems are known to occur; (2) limits the utility's future flexibility to move loads when new facilities are built in an area and limits the ability to deploy additional line sectionalizing devices for reliability enhancement; (3) requires the utility to maintain some amount of minimum load on a feeder where a distributed generation project has been operating and a large load is lost; and (4) results in additional costs being recovered from all other customers to rectify the problems, requiring additional infrastructure investment to move loads by constructing new feeder ties or other needed solutions.

260

Therefore, they urge the Commission to retain the existing 15 Percent Screen.

261

260

NRECA, EEI & APPA at 26.

261

Id.

at 7.

129. Duke Energy believes that the Minimum Load Screen may not provide a sufficient margin of safety to account for the variability of load on a distribution circuit and for the variability of output of certain types of Small Generating Facilities.

262

Duke Energy asserts that the intermittent nature of PV generation connected on distribution lines may interfere with smart grid applications and load monitoring equipment, and may cause restoration schemes and voltage and reactive power schemes to operate improperly. Duke Energy states that the existing 15 Percent Screen has a safety margin for minimum load built into the screen, which minimizes the negative effects of variable generation.

263

Duke Energy also comments that the Minimum Load Screen will require utilities to estimate minimum load and that these estimates may involve high rates of error.

264

262

Duke Energy at 10.

263

Id.

at 11.

264

Id.

at 11-12.

130. IREC argues, however, that Transmission Providers infrequently have to transfer load between circuits and can retain flexibility on a particular circuit by identifying this need through the application of the additional supplemental review screens.

265

IREC further states that the safety, reliability, and power quality screens in the supplemental review process, along with providing 20 business days for the Transmission Provider to perform the supplemental review, provide utilities with sufficient time and flexibility to evaluate a proposed generator and enable more generators to be interconnected safely without a full study.

266

265

IREC at 24.

266

Id.

at 17.

131. IREC asserts that it is inappropriate to view the Minimum Load Screen in isolation from the other supplemental review screens.

267

IREC argues that when viewed together, the supplemental review screens provide the flexibility to identify circumstances where high penetrations of distributed generation may require additional study.

268

SEIA and Public Interest Organizations similarly assert that even if a proposed Small Generating Facility passes the Minimum Load Screen, it would be subject to additional study if it failed either of the other two screens, which address reliability and operational flexibility.

269

IREC states that inverter-based systems minimize risks that may arise at higher penetrations.

270

IREC further states that the Minimum Load Screen does not increase the risk of problems related to load changes and notes that problems related to load changes could also be raised in relation to projects that undergo the Study Process (

i.e.,

increasing the number of generators that are able to interconnect without full study does not exacerbate the problem associated with changes in load, nor would requiring full study for more generators reduce this risk).

271

SEIA states that the Minimum Load Screen is conservative because the likelihood of every generator on a circuit generating power at its nameplate capacity while the circuit's load is simultaneously at its minimum is extremely rare.

272

267

Id.

at 22.

268

Id.

269

Public Interest Organizations at 14 and SEIA at 8.

270

IREC at 23.

271

Id.

272

SEIA at 8-9.

132. NRECA, EEI & APPA state that if the Commission adopts a minimum load screen, 67 percent for such a screen is a reasonable starting point because it provides an appropriate initial buffer to protect safety, reliability and power quality, and is consistent with the configuration of many distribution systems.

273

Further, they claim that any threshold higher than 67 percent of minimum load for those distribution circuits involving both inverter-based PV and rotating generator machines would impose an unacceptable threat to safety, reliability, and power quality.

274

They argue that no more than a 33 percent minimum load screen is

appropriate for areas or applications involving only rotating machines.

275

They state that the Commission could follow the Massachusetts Department of Public Utilities' procedure by adopting a 67 percent minimum load screen and holding an annual technical workshop with interested parties to determine whether the percentage chosen for the screen is working as planned or determine whether the chosen percentage should be revised.

276

273

NRECA, EEI & APPA Reply Comments 9.

274

NRECA, EEI & APPA at 7, 25.

275

Id.

at 25.

276

Id.

133. SEIA contends that the 67 percent Minimum Load Screen is inappropriate because the only rationale presented was the adoption of this screen on an interim basis in Massachusetts.

277

Sandia and SEIA state that the 67 percent minimum load screen adopted in Massachusetts serves only as an interim standard while a working group investigates the appropriate level for a minimum load screen.

278

SEIA asserts that holding annual technical conferences to reassess the Minimum Load Screen will impose uncertainty on utilities and developers and will burden the Commission.

279

277

SEIA Reply Comments at 3.

278

Sandia at 4 and SEIA at 9 (citing

Order on the Distributed Generation Working Group's Redlined Tariff and Non-Tariff Recommendations,

Massachusetts Department of Public Utilities 11-75-E at 34).

279

SEIA Reply Comments at 3.

134. Sandia, IREC and SEIA argue that a 67 percent minimum load screen lacks technical justification.

280

Sandia and IREC note that the 67 percent minimum load screen adopted in Massachusetts on an interim basis was derived from a Sandia report on anti-islanding, and that it is not appropriate to use the screen to determine if further study of a Small Generating Facility is required.

281

IREC asserts that a 67 percent minimum load screen would do little to improve the interconnection process.

282

280

IREC at 20-21; Sandia at 4; and SEIA at 9.

281

IREC at 20-21 and Sandia at 4, citing M. Ropp and A. Ellis,

Suggested Guidelines for Assessment of DG Unintentional Islanding Risk,

Sandia National Laboratories (March 2013), p. 5, available at:

http://energy.sandia.gov/wp/wp-content/gallery/uploads/SAND2012-1365-v2.pdf

282

IREC at 21.

135. SEIA further states that NREL determined that if aggregate generation on a line section is below 100 percent of minimum load, the risk of power backfeeding beyond the substation is minimal; therefore power quality, voltage control and other safety and reliability concerns may be addressed without a full study of the proposed Small Generating Facility.

283

SEIA also notes that at the July 17, 2012 technical conference,

284

NREL stated that there are systems designed to work well with aggregate generation in excess of 100 percent of minimum load and there is no “hard and fast ceiling” that exceeding 100 percent of daytime minimum load would cause a system to fail.

285

283

SEIA at 7 (citing NREL, Technical Report: Updating Small Generator Interconnection Procedures for New Market Conditions 30 (Dec. 2012)).

284

See supra

P 0.

285

SEIA at 7 (citing Technical Conference Transcript at 92:15-21).

136. Sandia states that there are many circuits with aggregated PV that are operating above 100 percent of minimum load, but the risk of unintentional islanding of inverter-based distributed generation is extremely low.

286

Therefore, Sandia asserts that, for distributed generation with anti-islanding capability,

287

a screening threshold of 100 percent of minimum load is sufficiently conservative to mitigate the risk of unintentional islanding.

288

286

Sandia at 5.

287

Id.

at 4-5 (noting that all new UL 1741-listed inverter-based distributed generation must have anti-islanding capability).

288

Id.

at 5.

137. NREL states that it has documented examples of PV systems operating at levels over 300 percent of minimum daytime load.

289

NREL believes that utilities should be encouraged to increase this penetration screen percentage on line sections with feeders that have shorter average distances to a substation, lower average impedance, and a lower average stiffness factor.

290

289

NREL at 4.

290

Id.

at 5, stiffness factor is defined as the available utility fault current divided by the distributed generation rated output current at the point of common coupling.

138. MISO suggests that for facilities less than 100 kV, it may be more efficient to assess the impact of a possible back-feed event rather than conduct a Minimum Load Screen analysis.

291

MISO Comments at 9.

139. VSI asserts that the Minimum Load Screen can be implemented without the other supplemental review screens for two reasons: (1) Minimum daytime loads tend to occur in the early morning hours and are not coincident with maximum solar output; and (2) the diversity of solar installations adds to the safety margin because the varying size, angles, orientations, and regional cloud cover make it unlikely that the generation of all the solar installations will peak at the same time.

292

VSI at 3.

140. NRECA, EEI & APPA suggest deleting the proposed requirement to consider only net export energy from small generators that serve onsite load (proposed SGIP section 2.4.1.1.2) because it requires consideration of the net export of power by the Small Generating Facility that may flow on the Transmission Provider's system rather than total output of the Small Generating Facility in the application of the Minimum Load Screen. They argue that on-site load can vary and cannot be counted on to consume some of the Small Generating Facility's output. The commenters also state that relying on reverse power relays alone does not mitigate all concerns related to the potential impact of reverse power flow on the Transmission Provider's system.

293

NRECA, EEI & APPA, Appendix B at 2.

b. Commission Determination

141. The Commission adopts the Minimum Load Screen

294

as proposed in the NOPR, with modifications as discussed below. We appreciate the concerns of Transmission Providers with regard to the Minimum Load Screen, but believe that the Minimum Load Screen is sufficiently conservative, particularly when viewed together with the other two supplemental review screens. Taken as a whole, the supplemental review screens provide the flexibility to identify circumstances when additional studies may be required while avoiding an unjust and unreasonable increase in expense and delay in interconnection. That is, the three screens in the supplemental review are designed to strike a balance between handling the increased volume of interconnection requests and penetrations of small generators and maintaining the safety and reliability of the electric systems.

294

See

SGIP section 2.4.4.1 of Appendix C attached hereto.

142. The Minimum Load Screen is used in assessing whether an Interconnection Customer that initially failed the Fast Track screens may still interconnect under the Fast Track Process. If the aggregate generating capacity on a line section, including the proposed Small Generating Facility, is less than 100 percent of minimum load, there are two additional screens, the voltage and power quality screen and the safety and reliability screen, that the Small Generating Facility must pass to be interconnected. Regarding NRECA, EEI & APPA's assertion that the use of 100 percent of minimum load limits the flexibility to move loads and the ability to deploy additional sectionalizing

devices for reliability enhancement, we note that one of the factors to be considered in the safety and reliability screen of the supplemental review asks whether operational flexibility is reduced by the proposed Small Generating Facility (see SGIP section 2.4.1.3.5). Therefore, the Commission agrees with IREC that this concern can be evaluated under the safety and reliability screen.

143. The Commission finds that a 100 percent minimum load screen more appropriately balances these considerations than the 33 and 67 percent minimum load screens proposed by NRECA, EEI & APPA. We note that a 33 percent minimum load screen would be even more conservative than the existing 15 Percent Screen (which approximates a 50 percent minimum load screen).

295

The 15 Percent Screen can be viewed as a “rule of thumb” that minimum load is approximately 30 percent of peak load on a given line section with a 50 percent safety margin.

See

Nat'l Renewable Energy Lab,

Updating Interconnection Screens for PV System Integration

2 (Feb. 2012),

available at http://www.nrel.gov/docs/fy12osti/54063.pdf.

144. The Commission acknowledges the concerns of NRECA, EEI & APPA and NYISO & NYTO that minimum load does not represent a critical system operating criterion so currently minimum load data are typically not measured and/or recorded, but the Commission agrees with IREC that minimum load is a more accurate metric for evaluating system risk posed by a potential interconnection than peak load. The Commission also acknowledges IREC's comment that Transmission Providers experiencing high penetrations of Small Generating Facilities have or soon may have a year or more of minimum load data on some circuits. Contrary to UCS' request and in response to NRECA, EEI & APPA's comments, the Commission is not at this time requiring Transmission Providers to purchase equipment or otherwise make investments to obtain minimum load data. The adopted reform gives the Transmission Provider the flexibility to calculate, estimate or determine minimum load if data are not available. Further, the language allows the Transmission Provider not to perform the Minimum Load Screen if data are unavailable or if it is unable to calculate, estimate or determine minimum load.

296

Under section 2.4.4 of the SGIP adopted herein, if a Transmission Provider is unable to perform the Minimum Load Screen, it must notify the Interconnection Customer to obtain the Interconnection Customer's permission to continue the supplemental review (

see infra

P 0), to terminate the supplemental review or to withdraw the interconnection request. Further, in section 2.4.4.1 of the SGIP, when the Transmission Provider notifies the Interconnection Customer of the results of the supplemental review, it must include the reason that it is unable to perform the Minimum Load Screen.

145. Regarding Duke Energy's concern that calculations of daytime minimum load may not adequately reflect system conditions, the Commission clarifies that if the Transmission Provider is concerned that its minimum load calculations may not adequately reflect system conditions in a particular instance and the Transmission Provider is unable to correct for any inaccuracies in the calculations or estimate or determine minimum load in some other way, the Transmission Provider may elect not to perform the Minimum Load Screen. However, the Transmission Provider must provide the reason it is unable to perform the screen to the Interconnection Customer, in accordance with SGIP section 2.4.4.1.

146. Regarding Duke Energy's assertion that the 15 Percent Screen should be maintained because it includes a safety margin that minimizes the negative effects of intermittent generation (such as problems with smart grid applications, load monitoring equipment, restoration schemes, and voltage and reactive power control schemes), the Commission finds that such issues are appropriately addressed under the voltage and power quality and the safety and reliability screens of the supplemental review.

147. The Commission acknowledges comments that utilities study the aggregate nameplate generation on the system relative to the Small Generating Facility output, that on-site load can vary, and that Transmission Providers should not net out on-site load when applying the Minimum Load Screen. Rather than deleting proposed section 2.4.1.1.2

297

entirely, however, the Commission changes “onsite electrical load” to “station service load,” since station service load is typically netted out when considering the aggregate generation. Further, the Commission modifies section 2.4.4.1 to clarify that on-site load served by a proposed Small Generating Facility should be accounted for in minimum load for the purpose of applying the Minimum Load Screen.

297

Section 2.4.4.1.2 in the SGIP adopted herein.

148. Finally, the Commission disagrees with VSI that the Minimum Load Screen alone is generally sufficient to determine if a Small Generating Facility may be interconnected safely and reliably without undergoing full study. The additional screens are necessary to ensure the safety and reliability of the proposed interconnection and to allow Transmission Providers the flexibility to identify issues that may be unique to a particular Small Generating Facility.

4. Voltage and Power Quality Screen and Safety and Reliability Screen (SGIP Sections 2.4.4.2 and 2.4.4.3)

a. Comments

149. The Commission received a number of comments regarding the details of the proposed voltage and power quality screen

298

and the safety and reliability screen.

299

NYISO & NYTO are concerned that these screens could be passed by a single generator, but aggregate distributed generation in an area could result in voltage and/or power quality issues to neighboring customers.

300

298

See

SGIP section 2.4.1.2 of Appendix C to the NOPR.

299

See

SGIP section 2.4.1.3 of Appendix C to the NOPR.

300

NYISO & NYTO at 21.

150. ITC notes that it has performed power quality screens and asserts that performing the voltage and power quality screen requires monitoring equipment that is typically found on distribution-level systems and adding it to ITC's transmission-level system would present “substantial logistical problems.”

301

ITC states that performing the power quality and voltage screen would impose costs in excess of the $2,500 supplemental review fee without providing commensurate benefits.

302

Similarly, NRECA, EEI & APPA state that the power quality and voltage screen is difficult to perform without detailed engineering analysis and the $2,500 supplemental review fee would not cover the cost of performing the screen.

303

ITC does not recommend increasing the supplemental review fee to cover the cost of performing this screen. Rather, ITC recommends that the voltage and power quality screen should be an optional analysis performed at the request of individual Interconnection Customers on a fee-for-service basis. Alternatively, ITC suggests that the inclusion and precise methodology of this screen should be left to the discretion of individual ISOs/RTOs.

304

301

ITC at 13-14.

302

Id.

at 13-15.

303

NRECA, EEI & APPA, Appendix B at 3.

304

ITC at 13-15.

151. NRECA, EEI & APPA note that the voltage and power quality screen does not specify if the screen applies at the point of common coupling or at the Point of Interconnection.

305

NRECA, EEI & APPA, Appendix B at 3.

152. NRECA, EEI & APPA suggest revising the screen as follows:

2.4.1.2 In aggregate with existing generation on the line section:

ER05DE13.001

153. NRECA,

EEI & APPA recommend adding the following final sentence to proposed SGIP section 2.4.1.3: “If any one or more of the following safety and reliability protection test screens fail, then proceed to a feasibility and/or system impact study in [s]ections 3.3 and 3.4.”

307

306

Id.

307

Id.

154. In addition, NRECA, EEI & APPA recommend adding the following to proposed section 2.4.1.3: “For safety and reliability protection of the line section, the aggregate generation existing, in queue for installation, and being proposed shall be considered for evaluating the generation types within the regional limits established for interactive system operability as specified by the Transmission Provider.”

308

Id.

155. Finally, NRECA, EEI & APPA suggest deleting proposed SGIP section 2.4.1.3.3, which examines the proposed interconnection's proximity to the substation and the class of conductor cable between the substation and the proposed Point of Interconnection, because different distribution line constructions can affect system impedance differently.

309

Id.

b. Commission Determination

156. The Commission adopts the NOPR proposal for the voltage and power quality screen and the safety and reliability screen, as modified below.

157. Regarding NYISO & NYTO's concern that the voltage and power quality and safety and reliability screens could be passed by a single generator, but aggregate distributed generation in an area could result in voltage and/or power quality issues to neighboring customers, we note that sections 2.4.4.2 and 2.4.4.3 of the SGIP adopted herein specify that the proposed Small Generating Facility should be evaluated with existing aggregate generation on a line section, so any issues associated with aggregate generation should emerge as a result of the performance of these screens.

158. In response to ITC's comment that the cost of the voltage and power quality screen may be greater than the benefit associated with the screen and NRECA, EEI & APPA's comment that this screen is difficult to perform without detailed engineering analysis, we will permit Transmission Providers to propose an alternative methodology for performing this screen when submitting filings in compliance with this Final Rule.

310

See infra

section V.

159. In response to NRECA, EEI and APPA, the Commission clarifies that a proposed interconnection being evaluated under the voltage and power quality supplemental review screen must meet the requirements as specified in the applicable IEEE standards. Therefore, we delete “at the Point of Interconnection” from section 2.4.4.2 of the

pro forma

SGIP adopted herein so there is not a conflict between the SGIP and the IEEE standards.

160. The Commission declines to add “such that load on the Transmission Provider's transformer with automatic voltage control or line voltage regulator is 20 [percent] greater than the aggregate generation on the line section” to section 2.4.4.2 of the SGIP adopted herein as suggested by NRECA, EEI & APPA because the commenters do not provide an explanation or support for making this revision. For the same reasons the Commission declines to add the language under section 2.4.4.3 as proposed by NRECA, EEI & APPA.

161. Finally, the Commission acknowledges NRECA, EEI & APPA's concerns regarding different distribution line constructions affecting system impedance differently. Therefore, in order to account for differences in distribution systems and to make this section consistent with the Fast Track eligibility table in section 2.1 of the SGIP, the Commission adopts the following language in section 2.4.4.3.3 of the SGIP:

Whether the proposed Small Generating Facility is located in close proximity to the substation (i.e., less than 2.5 electrical circuit miles), and whether the line section from the substation to the Point of Interconnection is a Mainline rated for normal and emergency ampacity.

5. Supplemental Review Screen Order (SGIP Section 2.4.2)

a. Comments

162. NRECA, EEI & APPA argue that the safety and reliability screen should be performed first in the supplemental review, and that a Small Generating Facility that fails the safety and reliability screen should be required to proceed directly to the Study Process.

311

They assert that Transmission Providers could be spared the time and cost of performing the remaining supplemental review screens if it is known at the beginning of the supplemental review that interconnection of a Small Generating Facility poses a threat to the safety and reliability of the system.

312

311

NRECA, EEI & APPA at 26.

312

Id.

at 27.

163. SEIA opposes any change to the order in which the supplemental review screens are applied.

313

SEIA contends

that the Commission's supplemental review screens are proposed to be completed in the same manner as the Rule 21 screens.

314

Thus, SEIA contends that the Commission proposed that the three supplemental review screens be conducted in the following order: (1) Minimum Load Screen; (2) power quality and voltage screen; and (3) safety and reliability screen. SEIA states that the Commission should maintain this order to avoid inconsistencies between the SGIP and Rule 21.

315

SEIA also argues that changing the order of the screens will not save utilities the time and expense of performing additional screens because the Interconnection Customer bears the cost of the supplemental review, not the utility.

316

313

SEIA Reply Comments at 2.

314

Id.

at 5.

315

Id.

316

Id.

b. Commission Determination

164. In order to allow for flexibility in the supplemental review process and to potentially save the Interconnection Customer the cost of unnecessary supplemental review screens, the Commission adopts language in SGIP section 2.4 that allows the Interconnection Customer to specify an order in which the supplemental review screens are to be performed, as well as a requirement that the Transmission Provider notify the Interconnection Customer if the Small Generating Facility fails any of the screens and obtain the Interconnection Customer's permission to continue with the supplemental review for informational purposes or in order to determine if the interconnection may proceed with minor modifications to the Transmission Provider's system.

317

The Commission finds, contrary to arguments by NRECA, EEI & APPA and SEIA, that because the Interconnection Customer is paying for the screens, the Interconnection Customer should be able to specify the order in which the Transmission Provider performs the screens. However, we note that any delay in obtaining permission from an Interconnection Customer under these requirements may impact the Transmission Provider's ability to complete the supplemental review within the specified timeframe. To avoid the possibility of any such delays, an Interconnection Customer may provide instructions for how to proceed after a supplemental review screen failure at the time the Interconnection Customer accepts the Transmission Provider's offer to perform the supplemental review under section 2.4.1 of the

pro forma

SGIP adopted herein.

317

See infra

P 0.

6. Supplemental Review Fee (SGIP Sections 2.4.1 and 2.4.3)

a. Comments

165. NREL believes that the $2,500 supplemental review fee strikes a balance in cost and time and supports the fee.

318

IECA states that the $2,500 fee is appropriate.

319

318

NREL at 4.

319

IECA at 5.

166. NRECA, EEI & APPA and ISO-NE do not believe the $2,500 fee covers the cost of performing the supplemental review.

320

NRECA, EEI & APPA recommend, at the very least, that the $2,500 fee represents a base payment, and that the fee be adjusted for inflation with either the Consumer Price Index or the Handy-Whitman Index.

321

ISO-NE requests regional flexibility to determine a fee that adequately covers the supplemental review costs.

322

320

NRECA, EEI & APPA at 22-23; ISO-NE at 17.

321

NRECA, EEI & APPA at 22-23.

322

ISO-NE at 17.

167. NYISO & NYTO estimate the actual cost of a supplemental review will be approximately equivalent to the cost of an average interconnection feasibility study for a Small Generating Facility ($30,000), and therefore claim that the proposed $2,500 supplemental review fee is insufficient to cover the cost of the review.

323

NYISO & NYTO propose either adopting a higher supplemental review fee or retaining the existing requirement that the Interconnection Customer provide a deposit for the estimated cost of the work, which would be refunded, based on actual costs.

324

323

NYISO & NYTO at 19.

324

Id.

at 19-20.

168. ITC and PJM assert that Interconnection Customers should be required to pay the Transmission Provider for its actual cost incurred in performing the supplemental review rather than a flat $2,500 fee, which may result in over- or under-recovery of the Transmission Provider's actual incurred expenses.

325

ITC believes the $2,500 fee will be “consistently and substantially less than the true cost” of performing the proposed supplemental review.

326

DCOPC requests that the Commission ensure that the Interconnection Customer is solely responsible for all supplemental review costs rather than allocating these costs to load.

327

If the Commission does not require the Interconnection Customer to pay the actual cost of the supplemental review, PJM requests clarification by the Commission that allocating costs in excess of the $2,500 review fee to load is just and reasonable.

328

325

ITC at 12; and PJM at 12.

326

ITC at 12.

327

DCOPC at 7.

328

PJM at 12.

169. ITC recommends that the Commission adopt a “deposit/not-to-exceed” fee structure whereby the Interconnection Customer provides an initial deposit and identifies an amount that the Transmission Provider is not to exceed while it prepares the supplement

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