
[Federal Register Volume 78, Number 234 (Thursday, December 5, 2013)]
[Rules and Regulations]
[Pages 73239-73354]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-28515]



[[Page 73239]]

Vol. 78

Thursday,

No. 234

December 5, 2013

Part II





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





Small Generator Interconnection Agreements and Procedures; Final Rule

  Federal Register / Vol. 78 , No. 234 / Thursday, December 5, 2013 / 
Rules and Regulations  

[[Page 73240]]


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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.

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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......................................                  1
II. Background.......................................                  4
    A. Order No. 2006................................                  4
    B. Solar Energy Industries Association Petition                   10
     and the Notice of Proposed Rulemaking...........
III. Need for Reform.................................                 15
    A. Commission Proposal...........................                 15
    B. Comments......................................                 16
    C. Commission Determination......................                 21
IV. Proposed Reforms.................................                 28
    A. Pre-Application Report........................                 28
        1. Commission Proposal.......................                 28
        2. Need for a Pre-Application Report.........                 31
            a. Comments..............................                 31
            b. Commission Determination..............                 37
        3. Pre-Application Report Fee................                 41
            a. Comments..............................                 41
            b. Commission Determination..............                 45
        4. Pre-Application Report Timeline...........                 47
            a. Comments..............................                 47
            b. Commission Determination..............                 51
        5. Pre-application Report Request Form.......                 53
            a. Comments..............................                 53
            b. Commission Determination..............                 56
        6. Readily Available Information.............                 57
            a. Comments..............................                 57
            b. Commission Determination..............                 63
        7. Other Issues..............................                 65
            a. Comments..............................                 65
            b. Commission Determination..............                 74
    B. Threshold for Participation in the Fast Track                  83
     Process.........................................
        1. Commission Proposal.......................                 83
        2. Comments..................................                 84
        3. Commission Determination..................                102
    C. Fast Track Customer Options Meeting and                       112
     Supplemental Review.............................
        1. Commission Proposal.......................                112
        2. General Comments on the Customer Options                  114
         Meeting and the Supplemental Review.........
            a. Comments..............................                114
            b. Commission Determination..............                118
        3. Minimum Load Screen (SGIP Section 2.4.4.1)                119
            a. Comments..............................                119

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            b. Commission Determination..............                142
        4. Voltage and Power Quality Screen and                      150
         Safety and Reliability Screen (SGIP Sections
         2.4.4.2 and 2.4.4.3)........................
            a. Comments..............................                150
            b. Commission Determination..............                157
        5. Supplemental Review Screen Order (SGIP                    163
         Section 2.4.2)..............................
            a. Comments..............................                163
            b. Commission Determination..............                165
        6. Supplemental Review Fee (SGIP Sections                    166
         2.4.1 and 2.4.3)............................
            a. Comments..............................                166
            b. Commission Determination..............                171
        7. Process Following Completion of the                       175
         Customer Options Meeting and the
         Supplemental Review (SGIP Sections 2.3.1,
         2.4.4 and 2.4.5)............................
            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                 211
     and Under-Frequency Events......................
        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 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.

[[Page 73242]]

    2. Originally adopted in Order No. 2006,\1\ the pro forma SGIP and 
the pro forma SGIA establish the terms and conditions under which 
public utilities \2\ must provide interconnection service to Small 
Generating Facilities \3\ 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 \4\ (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.\5\ 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.'' \6\ 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,\7\ and the need for this Commission to have its regulations 
and policies ensure just and reasonable rates, terms and conditions of 
service.
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    \1\ 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).
    \2\ 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.
    \3\ 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.
    \4\ 16 U.S.C. 824e (2012).
    \5\ 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).
    \6\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 118.
    \7\ 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).
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    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,\8\ 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.\9\
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    \8\ Small Generator Interconnection Agreements and Procedures, 
78 FR 7524 (Feb. 1, 2013) (NOPR), FERC Stats. & Regs. ] 32,697 
(2013).
    \9\ 16 U.S.C. 824d and 824e (2012).
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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 \10\ 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.\11\
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    \10\ 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 v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 
U.S. 1230 (2008).
    \11\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 9.
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    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 \12\ Small Generating 
Facilities no larger than 2 MW; and (2) the 10 kilowatt (kW) Inverter 
Process for certified inverter-based \13\ Small Generating Facilities 
no larger than 10 kW.
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    \12\ 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.
    \13\ 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.
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    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 \14\ that must be

[[Page 73243]]

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.\15\
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    \14\ 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.
    \15\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 44.
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    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; 
\16\ 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.
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    \16\ 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.
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    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.\17\
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    \17\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 46.
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    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,\18\ 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.\19\ 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.\20\ SEIA noted that its Petition applies exclusively to solar 
electric generation due to its unique characteristics.\21\
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    \18\ 18 CFR 385.207 (2013).
    \19\ SEIA Petition at 4 (citing Order No. 2006, FERC Stats. & 
Regs. ] 31,180 at P 118).
    \20\ Id. at 12.
    \21\ 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).
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    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.\22\ 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.\23\ 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.\24\
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    \22\ NOPR, FERC Stats. & Regs. ] 32,697. While SEIA's Petition 
was specific to small solar generation, the NOPR included all Small 
Generating Facilities.
    \23\ The SWG included EEI, NRECA, APPA, IREC, SEIA, NREL, and 
other stakeholders.
    \24\ See Appendix A, List of Short Names of Commenters on the 
Notice of Proposed Rulemaking.
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    14. The stakeholders that participated in the SWG indicated in 
their comments

[[Page 73244]]

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.\25\ 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.\26\ 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.\27\ 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.\28\
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    \25\ NOPR, FERC Stats. & Regs. ] 32,697 at P 18.
    \26\ Id. P 20.
    \27\ Id. P 22.
    \28\ Id. P 23.
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B. Comments

    16. Many commenters support the Commission's proposed reforms.\29\ 
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.\30\ For example, Public Interest Organizations \31\ note that 
state solar initiatives are resulting in penetrations of distributed 
generation in excess of 15 percent on some line sections \32\ 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.'' \33\ 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.\34\ 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.\35\ Public Interest Organizations go on to 
state that:
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    \29\ 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.
    \30\ 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.
    \31\ 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.
    \32\ Public Interest Organizations at 4-5.
    \33\ Id. at 1.
    \34\ Id. at 5-9.
    \35\ 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.\36\
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    \36\ 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 \37\ similarly state that the proposed 
reforms ensure that small generator interconnection requests are 
processed in a just and reasonable and not unduly discriminatory 
manner.\38\
---------------------------------------------------------------------------

    \37\ 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.
    \38\ AWEA at 2 and ELCON at 3.
---------------------------------------------------------------------------

    18. International Transmission Company (ITC) supports streamlining 
the SGIP in ways that maintain safety and reliability.\39\
---------------------------------------------------------------------------

    \39\ ITC at 6.
---------------------------------------------------------------------------

    19. Independent System Operators (ISO) and Regional Transmission 
Organizations (RTO) generally support the NOPR objectives,\40\ 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 \41\ 
or the regional differences standard.\42\ 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.\43\ NARUC also states that

[[Page 73245]]

the reforms should not impinge on successful state interconnection 
procedures.\44\
---------------------------------------------------------------------------

    \40\ 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.
    \41\ 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.
    \42\ 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.
    \43\ NARUC at 10.
    \44\ 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.\45\ 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.\46\ 
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.\47\ 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.\48\
---------------------------------------------------------------------------

    \45\ NRECA, EEI & APPA at 9.
    \46\ Id. at 10.
    \47\ Id. at 11.
    \48\ 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.\49\ 
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.
---------------------------------------------------------------------------

    \49\ 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,\50\ compared to 79 MW in 
2005, the year Order No. 2006 was issued.\51\ The cumulative capacity 
of U.S. distributed PV is projected to double from mid-2013 to the end 
of 2015.\52\ 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.\53\ 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.\54\ In its comments, IREC cited an unprecedented level of 
small solar interconnections.\55\
---------------------------------------------------------------------------

    \50\ 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.
    \51\ 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.
    \52\ 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.
    \53\ SNL Financial, Power Plant Summary (2013).
    \54\ 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).
    \55\ 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 \56\ and as the Commission noted in 
the NOPR, state renewable portfolio standards are driving small 
generator interconnection requests.\57\ As of March 2013, 29 states and 
the District of Columbia had renewable portfolio standards, and an 
additional eight states had renewable portfolio goals.\58\ 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.\59\ Commenters also 
attribute the increase in PV to a decline in capital costs.\60\ 
Installed costs for distributed PV installations fell by approximately 
12 percent from 2011 to 2012, and have fallen 33 percent since 
2009.\61\
---------------------------------------------------------------------------

    \56\ Public Interest Organizations at 3-5; IREC at 2; UCS at 3; 
and DCOPC at 3.
    \57\ NOPR, FERC Stats. & Regs. ] 32,697 at P 20.
    \58\ 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.
    \59\ 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.
    \60\ VSI at 1-2 and Public Interest Organizations at 1.
    \61\ 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 v. FERC \62\ 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.\63\ We conclude that, in 
light of the increasing small generator interconnection requests 
referenced in Commission filings \64\ and

[[Page 73246]]

in this proceeding,\65\ the state renewable portfolio standards driving 
these requests,\66\ and the growth in solar PV installations,\67\ the 
reforms adopted herein are necessary to correct operational practices 
that can unnecessarily limit, and increase the cost of,\68\ 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.
---------------------------------------------------------------------------

    \62\ 468 F.3d 831, 839-44 (D.C. Cir. 2006) (National Fuel).
    \63\ Id. at 844.
    \64\ 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).
    \65\ IREC at 3, citing Becky Campbell & Mike Taylor, 2011 Solar 
Electric Power Association Utility Solar Rankings at 7 (May 2012).
    \66\ 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.
    \67\ 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.
    \68\ 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).\69\ 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.\70\ 
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.\71\
---------------------------------------------------------------------------

    \69\ See supra P 0.
    \70\ 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.
    \71\ See, e.g., Black Oak Energy, LLC v. 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. v. FERC, 616 F.3d 520, 542 
(D.C. Cir. 2010); Louisiana Pub. Serv. Comm'n v. FERC, 551 F.3d 
1042, 1045 (D.C. Cir. 2008); Envtl. Action, Inc. v. 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.\72\ 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.\73\
    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.\74\ 
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,\75\ 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.
---------------------------------------------------------------------------

    \72\ NOPR, FERC Stats. & Regs. ] 32,697 at P 24.
    \73\ Id. at P 4.
    \74\ See infra section V.
    \75\ 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.\76\
---------------------------------------------------------------------------

    \76\ 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.\77\ The Commission proposed that 
the pre-application report would only include information already 
available to the Transmission Provider.\78\ 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

[[Page 73247]]

study or other analysis of the proposed generator in the event that 
data is not readily available.'' \79\
---------------------------------------------------------------------------

    \77\ Id. at P 28 and proposed pro forma SGIP at section 1.2.2.
    \78\ NOPR, FERC Stats. & Regs. ] 32,697 at P 27.
    \79\ 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.\80\ 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.\81\ 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.\82\ 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.\83\
---------------------------------------------------------------------------

    \80\ 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.
    \81\ CPUC at 5.
    \82\ 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.
    \83\ 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.\84\ 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.\85\ 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.\86\
---------------------------------------------------------------------------

    \84\ AWEA at 3-4; CREA at 2; IREC at 9; ITC at 8; and NRG at 5.
    \85\ IREC at 9 and SEIA at 10.
    \86\ Sandia at 2 and SEIA at 12.
---------------------------------------------------------------------------

    33. Several RTOs and ISOs,\87\ 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.\88\ ISO New England (ISO-NE) asserts that there is no 
indication that the information it currently makes available to 
Interconnection Customers is insufficient.\89\
---------------------------------------------------------------------------

    \87\ ISO-NE., MISO, PJM, and NYISO.
    \88\ ISO-NE at 8; MISO at 5-6; NYISO & NYTO at 13-14; and PJM at 
5.
    \89\ 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.\90\ 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.\91\ 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.\92\
---------------------------------------------------------------------------

    \90\ MISO at 4 (referencing section 6.1 of MISO's Generator 
Interconnection Procedure).
    \91\ Id. at 5.
    \92\ 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.\93\
---------------------------------------------------------------------------

    \93\ 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.\94\
---------------------------------------------------------------------------

    \94\ 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.\95\
---------------------------------------------------------------------------

    \95\ See infra section V.

---------------------------------------------------------------------------

[[Page 73248]]

3. Pre-Application Report Fee
a. Comments
    41. Several commenters support the proposed $300 fee for the pre-
application report.\96\ 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.\97\ NREL states that the proposed $300 fee 
only allows the Transmission Provider to provide information that is 
quickly accessible.\98\
---------------------------------------------------------------------------

    \96\ CPUC at 4; CREA at 2; IREC at 12; MISO at 3-4; NRG at 5; 
and Public Interest Organizations at 9.
    \97\ 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.
    \98\ 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.\99\
---------------------------------------------------------------------------

    \99\ 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

[[Page 73249]]

processing pre-application requests within the ten-business-day 
period.\115\
---------------------------------------------------------------------------

    \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, Sec. Sec.  1.2.2.1-1.2.2.8; 
NRECA, EEI & APPA, Attachment A, Sec. Sec.  1.2.2.1-1.2.2.8; NREL, 
attachment to comments, Sec. Sec.  1.2.2.1-1.2.2.8; and SEIA, 
Attachment B, Sec. Sec.  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-

[[Page 73250]]

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

[[Page 73251]]

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\
---------------------------------------------------------------------------

    \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).

---------------------------------------------------------------------------

[[Page 73252]]

    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.

[[Page 73253]]

[GRAPHIC] [TIFF OMITTED] TR05DE13.000

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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

[[Page 73254]]

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\
---------------------------------------------------------------------------

    \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
------------------------------------------------------------------------
                                                          Fast Track
                                      Fast Track       eligibility on a
          Line voltage                eligibility       mainline * and
                                     regardless of      <=2.5 miles **
                                       location         from substation
------------------------------------------------------------------------
<5 kilovolt (kV)................            <=500 kW            <=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

[[Page 73255]]

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\
---------------------------------------------------------------------------

    \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
------------------------------------------------------------------------
                                                          Fast Track
                                      Fast Track       eligibility on a
                                      eligibility      mainline \1\ and
          Line voltage               regardless of     <=2.5 electrical
                                       location       circuit miles from
                                                        substation \2\
------------------------------------------------------------------------
<5 kilovolt (kV)................            <=500 kW            <=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
------------------------------------------------------------------------
\1\ 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.
\2\ 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 or 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

[[Page 73256]]

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\
---------------------------------------------------------------------------

    \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

[[Page 73257]]

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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

[[Page 73258]]

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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

[[Page 73259]]

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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

[[Page 73260]]

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \305\ NRECA, EEI & APPA, Appendix B at 3.
---------------------------------------------------------------------------

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

[[Page 73261]]

    2.4.1.2 In aggregate with existing generation on the line section:
    [GRAPHIC] [TIFF OMITTED] TR05DE13.001
    
    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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

[[Page 73262]]

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 supplemental review.\329\ ITC 
proposes that the supplemental review costs could be trued-up based on 
actual incurred costs after the study is complete.\330\
---------------------------------------------------------------------------

    \329\ ITC at 12-13.
    \330\ Id. at 8, 12-13.
---------------------------------------------------------------------------

b. Commission Determination
    170. The Commission agrees with commenters that the Interconnection 
Customer should be responsible for the actual cost of conducting the 
supplemental review, therefore, the Commission adopts a supplemental 
review fee based on actual costs. We are concerned that because the 
supplemental review is not based solely on information already 
available to the Transmission Provider (unlike the pre-application 
report), there may be significant cost differences between supplemental 
reviews for different projects. Therefore, a fixed fee would result in 
Interconnection Customers with smaller supplemental review costs 
subsidizing Interconnection Customers with larger supplemental review 
costs.
    171. Similar to the supplemental review and other processes (e.g., 
the feasibility study and the system impact study) in the pro forma 
SGIP,\331\ prior to performing the supplemental review, the 
Transmission Provider will be required to provide the Interconnection 
Customer with a good faith estimate of the cost to perform the 
supplemental review, and the Interconnection Customer will be required 
to pay this amount as a deposit in advance of the supplemental review. 
After the supplemental review is complete, the Transmission Provider 
and the Interconnection Customer will reconcile any difference between 
the deposit paid by the Interconnection Customer and the actual cost to 
perform the supplemental review.
---------------------------------------------------------------------------

    \331\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 187.
---------------------------------------------------------------------------

    172. Consistent with the Commission's determination on SGIP study 
cost responsibility in Order No. 2006, the Interconnection Customer 
will

[[Page 73263]]

be required to pay for the supplemental review, regardless of the 
conclusions reached, rather than unreasonably shift this cost to other 
transmission customers that do not benefit from the review. However, 
whenever possible, the Transmission Provider should use existing 
information and studies instead of performing additional analyses for 
the supplemental review in order to reduce costs for the 
Interconnection Customer. Although the Interconnection Customer is not 
to be charged for such existing information and studies, it is 
responsible for costs associated with any new analysis and any 
modification to an existing analysis that are reasonably necessary to 
evaluate the proposed interconnection under the supplemental review.
    173. We are not adopting ITC's proposal to allow Interconnection 
Customers to specify the maximum amount that the Transmission Provider 
may spend to prepare the supplemental review. Rather, the Commission 
believes that the Transmission Provider's good faith estimate of the 
cost to perform the review, along with the requirement described above 
that the Transmission Provider notify the Interconnection Customer upon 
failure of a supplemental review screen, provides the Interconnection 
Customer with a reasonable degree of transparency and cost certainty in 
the supplemental review process.
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)
a. Comments
    174. NRECA, EEI & APPA, MISO and ITC request additional 
clarification regarding what changes qualify as ``minor modifications'' 
to the Transmission Provider's system.\332\ ITC requests that the 
Commission provide a cost threshold or a more extensive list of 
examples of what constitutes a minor modification.\333\ NRECA, EEI & 
APPA believe that ``minor'' would mean that ``the proposed 
interconnection requires no construction of facilities by the 
Transmission Provider on its own system'' and refers to modifications 
such as ``changing meters, fuses, [and] relay settings'' on the 
Transmission Provider's system.\334\
---------------------------------------------------------------------------

    \332\ ITC at 13; MISO at 8; and NRECA, EEI & APPA at 22 (citing 
the NOPR, 142 FERC ] 61,049 at P 33 (stating that the Transmission 
Provider must offer to perform minor modifications to its system and 
provide a non-binding estimate of the cost at the customer options 
meeting)).
    \333\ ITC at 13.
    \334\ NRECA, EEI & APPA at 22 (citing the proposed pro forma 
SGIP at sections 2.3.1 and 2.4.2).
---------------------------------------------------------------------------

    175. NYISO & NYTO request that ``minor modifications'' only include 
upgrades that fall within the definition of Local System Upgrade 
Facilities in the NYISO tariff.\335\ NYISO & NYTO also request that the 
Commission clarify the extent to which security is required for such 
modifications and clarify that the Transmission Provider will forward 
the Interconnection Customer an interconnection agreement that requires 
the Interconnection Customer to pay the costs of the required system 
modifications prior to interconnection and requests that the Commission 
make similar modifications to the proposed requirement in section 2.4.2 
regarding the provision of an interconnection agreement when the 
interconnection only requires minor modifications.\336\ NYISO & NYTO 
propose that the Commission also modify section 2.4.2 of the SGIP to 
require that an Interconnection Customer's interconnection request 
``shall'' be evaluated under the Study Process if it requires more than 
minor modifications to the Transmission Provider's system or be 
withdrawn.\337\
---------------------------------------------------------------------------

    \335\ NYISO & NYTO at 19.
    \336\ Id.
    \337\ Id. at 20.
---------------------------------------------------------------------------

    176. NYISO & NYTO state that since the supplemental review is 
optional, an Interconnection Customer's failure to agree and pay for 
the supplemental review should not lead to the withdrawal of its 
interconnection request. They request that the Commission require that 
if an Interconnection Customer does not agree in writing and pay the 
supplemental review fee within 15 business days, its interconnection 
request shall be directed to the Study Process for evaluation.\338\
---------------------------------------------------------------------------

    \338\ Id.
---------------------------------------------------------------------------

    177. ISO-NE argues that requiring the Transmission Provider to 
provide the Interconnection Customer with an interconnection agreement 
within five business days of the customer options meeting when the 
Interconnection Customer agrees to pay for modifications to the 
Transmission Provider's system is problematic.\339\ Further, ISO-NE 
asserts that the existing ten business day deadline for providing an 
interconnection agreement following supplemental review when 
modifications to the Transmission Provider's system are required is 
extremely tight and states that the Commission should not reduce this 
timeframe.\340\
---------------------------------------------------------------------------

    \339\ ISO-NE at 16.
    \340\ Id. at 16-17.
---------------------------------------------------------------------------

    178. PJM is concerned that Transmission Providers will not be able 
to provide an executable interconnection agreement within five business 
days if the Interconnection Customer chooses to move forward based on 
the non-binding good faith estimate to perform modifications to the 
Transmission Provider's system offered during the customer options 
meeting. PJM therefore requests that the Commission allow ten business 
days, which it believes will enable more projects to obtain a quick 
interconnection agreement.\341\ PJM also asks that the Commission 
increase each of the timeframes concerning the provision of 
interconnection agreements in the current supplemental review process 
by adding five business days to each stated deadline to accommodate the 
greater number of interconnection agreements that may result from the 
proposed reforms to the Fast Track Process.\342\
---------------------------------------------------------------------------

    \341\ PJM at 11.
    \342\ Id. at 12.
---------------------------------------------------------------------------

    179. Bonneville Power Administration (Bonneville) states that the 
supplemental review should include an examination of Affected 
Systems.\343\
---------------------------------------------------------------------------

    \343\ Bonneville at 3-4. An Affected System is ``[a]n electric 
system other than the Transmission Provider's Transmission System 
that may be affected by the proposed interconnection.'' SGIP, 
Attachment 1.
---------------------------------------------------------------------------

    180. Finally, NYISO & NYTO request that the Commission retain 
``does not'' in section 2.2.4 of the SGIP in order to enable the 
Interconnection Customer to have a customer options meeting when the 
Transmission Provider has the capability to but does not determine from 
the initial screens that the proposed facility can be interconnected 
safely and reliability under current system conditions.\344\ Section 
2.2.4 of the SGIP currently states that the Transmission Provider will 
offer Interconnection Customers a customer options meeting if the 
proposed interconnection fails the Fast Track screens but the 
Transmission Provider ``does not or cannot'' determine that the 
facility could interconnect consistently with safety, reliability, and 
power quality standards. In the NOPR, the Commission proposes to 
replace ``does not or cannot determine'' with ``cannot determine.''
---------------------------------------------------------------------------

    \344\ NYISO & NYTO at 18.
---------------------------------------------------------------------------

b. Commission Determination
    181. The Commission adopts the NOPR proposal to govern the process 
after the supplemental screen(s) have

[[Page 73264]]

been completed as modified below. We agree with NYISO & NYTO that 
section 2.4.5 of the SGIP should be modified to require that an 
Interconnection Customer's interconnection request ``shall'' be 
evaluated under the Study Process if it requires more than minor 
modifications to the Transmission Provider's system, and the 
Interconnection Customer does not withdraw its Small Generating 
Facility. To further clarify the outcome of the supplemental review 
process, the Commission adopts language in section 2.4.5 for the 
following circumstances: (1) The proposed interconnection passes the 
supplemental review screens and does not require construction of 
facilities by the Transmission Provider on its own system; (2) 
interconnection facilities or minor modifications to the Transmission 
Provider's system are required for the proposed interconnection to pass 
the supplemental review screens; and (3) the proposed interconnection 
would require more than interconnection facilities or minor 
modifications to the Transmission Provider's system to pass the 
supplemental review screens. In the first circumstance, the proposed 
interconnection passes the supplemental review screens, and the 
Interconnection Customer is provided with an interconnection agreement 
within ten business days of notification of the supplemental review 
results. In the second circumstance, the proposed interconnection 
passes the supplemental review screens, and, if the Interconnection 
Customer agrees to pay for the modifications to the Transmission 
Provider's system, the Interconnection Customer is provided with an 
interconnection agreement within 15 business days of receiving written 
notification of the supplemental review results. In the third 
circumstance, the proposed interconnection does not pass the 
supplemental review screens and must continue to be evaluated under the 
Study Process unless the Interconnection Customer withdraws its Small 
Generating Facility.
    182. The Commission affirms that, consistent with Order No. 2006, 
examples of ``minor modifications'' to the Transmission Provider's 
system in the context of the supplemental review include changing 
meters, fuses, and relay settings.\345\ However, we also note that 
these are examples only and therefore minor modifications could include 
other items that the Transmission Provider determines could be made to 
its system safely and reliably without further study of the 
interconnection. Because ``minor modifications'' could include items 
other than the listed examples,\346\ the Commission does not herein 
establish a cost threshold or a more extensive list of items that would 
qualify as ``minor modifications.'' We do, however, modify section 
2.4.5 to include language that the Transmission Provider will provide 
an interconnection agreement to the Interconnection Customer if the 
Interconnection Customer agrees to pay for the modifications to the 
Transmission Provider's system, similar to the language in section 
2.3.1 of the SGIP.
---------------------------------------------------------------------------

    \345\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 159 and 
section 2.3.1 of the SGIP.
    \346\ ``Minor modifications'' could, in some circumstances, 
include construction of facilities by the Transmission Provider on 
its own system, provided that the Transmission Provider were able to 
determine without further study that such modifications are safe and 
reliable. Such circumstances may be rare, but we see no reason to 
foreclose their possibility completely.
---------------------------------------------------------------------------

    183. The Commission disagrees with NYISO & NYTO that the time spent 
on a supplemental review would be better spent on a feasibility study. 
The Commission acknowledges that a supplemental review could add to the 
overall time of the interconnection process if a project fails the 
supplemental review and must be evaluated under the Study Process. 
However, if the Small Generating Facility is able to be interconnected 
under the Fast Track Process as a result of undergoing supplemental 
review, the interconnection process will be much shorter when compared 
with the Study Process. Further, the Commission notes that the purpose 
of the supplemental review is to determine if the Small Generating 
Facility may be interconnected safely and reliably without undergoing 
full study, including a feasibility study.
    184. We agree with NYISO & NYTO that since the supplemental review 
is optional, an Interconnection Customer's failure to agree and pay for 
the supplemental review should not lead to the withdrawal of its 
interconnection request. Therefore, we adopt language in section 2.4.1 
of the SGIP stating that, if an Interconnection Customer does not agree 
in writing and pay the supplemental review fee within 15 business days, 
the Transmission Provider shall direct the interconnection request to 
the section 3 Study Process for evaluation unless it is withdrawn by 
the Interconnection Customer.
    185. In response to comments that the five business day deadline 
for providing the Interconnection Customer with an interconnection 
agreement when the Interconnection Customer accepts the Transmission 
Provider's offer at the customer options meeting to perform 
modifications to the Transmission Provider's system and agrees to pay 
for these modifications is too short, the Commission revises the 
deadline in section 2.3.1 to ten business days as proposed by PJM. 
Further, the Commission also adopts a ten business day deadline in 
section 2.4.5.1 for provision of an interconnection agreement that 
requires no construction of facilities or minor modifications to the 
Transmission Provider's system to accommodate any increased volume of 
interconnection agreements associated with the Fast Track Process 
reforms adopted herein. Finally, the Commission adopts the 15 business 
day deadline in section 2.4.5.2 for provision of an interconnection 
agreement when interconnection facilities or minor modifications to the 
Transmission Provider's system are required, as proposed in the 
NOPR.\347\ This provides an additional five business days beyond the 
deadline in section 2.4.1.3 of the pro forma SGIP adopted in Order No. 
2006 and should accommodate any increased volume of interconnection 
agreements associated with the Fast Track Process reforms adopted 
herein.
---------------------------------------------------------------------------

    \347\ See section 2.4.2 of the SGIP in Appendix C to the NOPR.
---------------------------------------------------------------------------

    186. The Commission notes that in order to interconnect under the 
Fast Track Process supplemental review, a Small Generating Facility 
must pass all three supplemental review screens. In order to minimize 
supplemental review costs, the Commission will require the Transmission 
Provider to notify the Interconnection Customer within two business 
days following the failure of a supplemental review screen and obtain 
the Interconnection Customer's permission to: (1) Continue with the 
supplemental review at the Interconnection Customer's expense for 
informational purposes or to determine if the proposed interconnection 
would require only interconnection facilities or minor modifications to 
the Transmission Provider's system and thus qualify for interconnection 
under the Fast Track Process in accordance with section 2.4.5.2 of the 
pro forma SGIP adopted under this Final Rule; (2) terminate the 
supplemental review and continue evaluating the interconnection request 
under the SGIP section 3 Study Process; or (3) terminate the 
supplemental review upon withdrawal of the interconnection request by 
the Interconnection Customer. The Commission extends the supplemental 
review timeline in section 2.4.4 of the

[[Page 73265]]

SGIP to 30 business days to accommodate this process.
    187. With regard to Bonneville's concern that the supplemental 
review should include an examination of Affected Systems, section 4.9 
of the SGIP already directs Transmission Providers to consider Affected 
Systems during the Fast Track screens when possible. Accordingly, the 
Commission finds that Bonneville's proposal to amend section 2.2.1.1 of 
the SGIP is unnecessary.
    188. Finally, the Commission agrees with NYISO & NYTO's request to 
keep ``does not or cannot'' in section 2.2.4 of the SGIP because it 
will enable the Interconnection Customer to have a customer options 
meeting when the Transmission Provider has the capability to but does 
not determine from the Fast Track screens that the proposed facility 
can be interconnected safely and reliably.

D. Review of Required Upgrades

1. Commission Proposal
    189. The Commission proposed to give Interconnection Customers the 
opportunity to review and comment upon the upgrades the Transmission 
Provider finds necessary for interconnection.\348\ The Commission also 
proposed that the Transmission Provider must provide ``supporting 
documentation, workpapers, and databases or data'' developed in 
preparation of the facilities study upon request.\349\ These proposals 
would make the SGIP consistent with the LGIP with respect to providing 
comments on upgrades required for interconnection.
---------------------------------------------------------------------------

    \348\ NOPR, FERC Stats. & Regs. ] 32,697 at P 41.
    \349\ Id. P 43.
---------------------------------------------------------------------------

2. Comments
    190. Many commenters support the Commission's proposal to allow 
Interconnection Customers to review and comment on the upgrades the 
Transmission Provider deems necessary for interconnection because it 
would facilitate communication and transparency in the interconnection 
process.\350\ SEIA states that many parties are already familiar with 
the proposed process because it is based on the LGIP.\351\ CREA states 
that the opportunity to provide written comments enables 
Interconnection Customers to understand the proposed upgrades, seek a 
professional review, and make comments to the Transmission Provider 
that must be considered.\352\ FCHEA states that allowing the 
Interconnection Customer the opportunity to provide written comments on 
the network upgrades required for interconnection could significantly 
increase the amount of distributed generation.\353\
---------------------------------------------------------------------------

    \350\ AWEA, CEIP, Clean Coalition, CREA, DCOPC, Duke Energy, 
ELCON, FCHEA, IECA, ITC, NRG, Public Interest Organizations, and 
SEIA.
    \351\ SEIA at 15.
    \352\ CREA at 3.
    \353\ FCHEA at 1.
---------------------------------------------------------------------------

    191. MISO states that its current generator interconnection 
procedures already provide for Interconnection Customer review and 
comment with respect to potential upgrades required for 
interconnection. Therefore, MISO does not oppose the Commission's 
proposed revisions to the pro forma SGIP so long as it would consider 
MISO's existing generator interconnection procedures to meet this 
requirement as it applies to small generator interconnections.\354\
---------------------------------------------------------------------------

    \354\ MISO at 9-10.
---------------------------------------------------------------------------

    192. ISO-NE., MISO and CAISO similarly request that the Commission 
accommodate previously approved regional variations.\355\ CAISO states 
that, although its procedures are not entirely aligned with the 
Commission's proposal, its tariff provides all Interconnection 
Customers with the opportunity to submit written comments on both the 
phase I and phase II interconnection reports, which comply with the 
proposed reforms.\356\ CAISO states that the Commission should 
recognize that variations from the proposed pro forma reforms may still 
be just and reasonable.\357\
---------------------------------------------------------------------------

    \355\ CAISO at 6; ISO-NE at 17; and MISO at 9-10.
    \356\ CAISO at 8.
    \357\ CAISO at 6.
---------------------------------------------------------------------------

    193. NYISO explains that it does not permit written comments in its 
LGIP, but instead offers Interconnection Customers the opportunity to 
meet with NYISO and NYTO to discuss the results of the facilities 
study, which gives Interconnection customers ample opportunity to 
comment.\358\ NYISO & NYTO thus propose that the Commission require a 
facilities study meeting instead of written comments.\359\ NYISO & NYTO 
assert that a meeting would provide an opportunity for the 
Interconnection Customer to provide feedback without extending the 
process by a number of days or creating the expectation that the 
Transmission Provider will make changes to the facilities study based 
on the Interconnection Customer's comments.\360\
---------------------------------------------------------------------------

    \358\ NYISO & NYTO at 22.
    \359\ Id.
    \360\ Id.
---------------------------------------------------------------------------

    194. If the Commission requires written comments, NYISO & NYTO 
request that the Commission clarify that the Transmission Provider is 
not required to perform additional analysis or make other modifications 
based on the Interconnection Customer's comments, unless the 
Interconnection Customer agrees to pay for the additional studies 
required.\361\
---------------------------------------------------------------------------

    \361\ Id.
---------------------------------------------------------------------------

    195. VSI supports the inclusion of written Interconnection Customer 
comments in the Facilities Study Agreement but expresses concern that 
the comments may not be seriously considered by the Transmission 
Provider.\362\ VSI and LES assert that Interconnection Customers should 
only be responsible for the cost of the minimum upgrades and 
interconnection facilities required to interconnect the small 
generator's project to prevent a Transmission Provider from knowingly 
or unknowingly making the interconnection upgrades prohibitively 
expensive.\363\
---------------------------------------------------------------------------

    \362\ VSI at 4-5.
    \363\ LES at 4 and VSI at 4-5.
---------------------------------------------------------------------------

    196. LES states that if a Transmission Provider wishes to install 
interconnection facilities in addition to those needed to interconnect 
the Interconnection Customer's project, the cost of those facilities 
should be included in the Transmission Provider's rate base and 
allocated to all system users. LES asserts that the cost of those 
upgrades should not be imposed on the Small Generating Facility 
alone.\364\ LES asserts that the Interconnection Customer should not be 
required to interconnect at a substation when transmission or 
distribution lines are closer. Some parties request that the Commission 
offer the Interconnection Customer a mechanism to resolve disputes over 
required upgrades.\365\ VSI proposes new language for the Facilities 
Study Agreement section 10.0 that would allow for an expedited review 
by the public utility regulatory authority having jurisdiction over the 
upgrade costs at issue.\366\ LES argues that the Commission needs to 
provide a remedy for promptly and efficiently resolving disputes over 
the minimum upgrades and interconnection facilities needed to 
interconnect a Small Generating Facility. For example, LES states that 
if a Transmission Provider mischaracterizes a network upgrade or 
interconnection facility in order to avoid paying that cost itself, the 
small generator must have recourse available.\367\ Otherwise, 
Transmission

[[Page 73266]]

Providers may claim to have final discretion over what interconnection 
facilities are required to be built.\368\
---------------------------------------------------------------------------

    \364\ LES at 4.
    \365\ Max Hensley at 1; LES at 4; Lucia Villaran at 2; and VSI 
at 4-5.
    \366\ VSI at 6.
    \367\ LES at 4.
    \368\ Id. at 4.
---------------------------------------------------------------------------

    197. IECA recommends that the Commission monitor and measure the 
effectiveness and efficiency of its SGIP. IECA states that the 
Commission should assure that the SGIP and LGIP do not have the 
unintended consequence of providing opportunities for Transmission 
Providers to easily stop SGIP or LGIP applications with endless 
evaluation processes of ``meaningful dialogue,'' which the review of 
required upgrades is intended to promote.\369\ IECA asserts that the 
Commission should initiate a process that routinely gathers key 
information to monitor the utilization and outcomes of the SGIP and 
should track, characterize, tabulate, and annually report all resolved 
and unresolved interconnection applications under its SGIP for the 
purpose of identifying and potentially removing interconnection 
barriers.\370\
---------------------------------------------------------------------------

    \369\ IECA at 7.
    \370\ Id.
---------------------------------------------------------------------------

    198. Clean Coalition recommends that the Commission allow the 
Interconnection Customer to use third party contractors to perform the 
required upgrades, as is allowed under Rule 21, at the Interconnection 
Customer's option.\371\ Clean Coalition asserts that this will allow 
competition to reduce upgrade costs and ensure that Transmission 
Providers keep upgrade costs low.\372\
---------------------------------------------------------------------------

    \371\ Clean Coalition at 8.
    \372\ Id.
---------------------------------------------------------------------------

    199. NRECA, EEI & APPA, however, state that a developer's use of a 
third party to provide input on the process relating to upgrade 
requirements, alternatives and related issues can further complicate 
the process.\373\ They state that formalizing these practices will do 
more harm than good because adding steps to the process can potentially 
delay and adversely impact other projects.\374\ NRECA, EEI & APPA also 
assert that third-party contractors performing upgrades at the 
Interconnection Customer's option raises safety, liability, access, and 
reliability concerns.\375\ The commenters suggest that the Commission 
only permit Interconnection Customers to use third-party contractors to 
perform upgrades in cases where the Transmission Provider agrees.\376\
---------------------------------------------------------------------------

    \373\ NRECA, EEI & APPA at 27-28.
    \374\ Id. at 28.
    \375\ NRECA, EEI & APPA Reply Comments at 11-12.
    \376\ Id. at 12.
---------------------------------------------------------------------------

    200. NRECA, EEI & APPA urge the Commission to ensure that utilities 
are properly compensated for the time and expenses associated with 
documenting the decision-making process to determine required 
upgrades.\377\ NRECA, EEI & APPA assert that in order to balance the 
Interconnection Customer's desire to have additional information on 
required upgrades with the added burden on Transmission Providers of 
preparing such information, the Commission must clearly state that the 
utility can collect its estimated costs before any additional study 
work is done.\378\
---------------------------------------------------------------------------

    \377\ NRECA, EEI & APPA at 8.
    \378\ Id.
---------------------------------------------------------------------------

    201. SEIA opposes charging Interconnection Customers additional 
fees associated with documenting the decision-making process of the 
facilities study.\379\ SEIA asserts that these additional costs are 
unwarranted because the LGIP currently requires Interconnection 
Customers to pay the Transmission Provider's actual costs of completing 
the facilities study and the SGIP should be consistent with the 
LGIP.\380\ Additionally, SEIA claims that compensating Transmission 
Providers for meetings and data gathering would constitute an 
``unlimited and undefined blank check'' to recover costs beyond those 
actually incurred and create unnecessary uncertainty for 
developers.\381\ NRECA, EEI & APPA state that they are not requesting a 
blank check and assert that Transmission Providers should be permitted 
to recover all prudently incurred costs resulting from such 
documentation requirements.\382\
---------------------------------------------------------------------------

    \379\ SEIA Reply Comments at 8.
    \380\ Id.
    \381\ Id.
    \382\ NRECA, EEI & APPA Reply Comments at 13.
---------------------------------------------------------------------------

    202. Finally, NYISO & NYTO assert that the Commission should 
include the proposed revisions to the Facilities Study Agreement 
allowing the Interconnection Customer the opportunity to review and 
comment upon the upgrades the Transmission Provider finds necessary for 
interconnection in section 3.5 of the pro forma SGIP to be consistent 
with the similar procedures for Large Generating Facilities in sections 
8.3 and 8.4 of the LGIP.\383\
---------------------------------------------------------------------------

    \383\ NYISO & NYTO at 22-23.
---------------------------------------------------------------------------

3. Commission Determination
    203. The Commission affirms its proposal to allow Interconnection 
Customers to provide written comments on the required upgrades in the 
facilities study. The Commission believes the adoption of this proposal 
will allow Interconnection Customers to have a meaningful opportunity 
to review any upgrades associated with an interconnection request and 
engage in a dialogue with the Transmission Provider. In addition, 
allowing Interconnection Customers the opportunity to provide written 
comments on required upgrades helps to ensure interconnection costs are 
just and reasonable.
    204. The Commission agrees with SEIA that the Interconnection 
Customer is entitled to view the facilities study supporting 
documentation because it is funding the study. The Commission is not 
persuaded by APPA, EEI & NRECA's claim that documenting the facilities 
study will be unduly burdensome because the LGIP has a similar 
requirement. However, the Commission affirms that Transmission 
Providers are entitled to collect all just and reasonable costs 
associated with producing the facilities study, including any 
reasonable documentation costs.
    205. We note that Transmission Providers that incorporate, or 
propose to incorporate, comments through a different process may submit 
compliance filings demonstrating that the process is consistent with or 
superior to the requirements contained herein or meets another standard 
allowed for in this Final Rule.\384\
---------------------------------------------------------------------------

    \384\ See infra section V.
---------------------------------------------------------------------------

    206. Various parties propose a regulatory review of required 
upgrades when there is a dispute. The Commission rejects this request 
because the parties have the option of utilizing the SGIA dispute 
resolution procedures outlined in section 4.2 of the SGIP to resolve 
such disputes. In addition, in the event the dispute cannot be 
resolved, the Interconnection Customer may request that the 
Transmission Provider file the unexecuted interconnection agreement 
with the Commission.\385\
---------------------------------------------------------------------------

    \385\ See SGIP section 4.8 of Appendix C attached hereto.
---------------------------------------------------------------------------

    207. The Commission declines to adopt NYISO & NYTO's proposal to 
affirm that Transmission Providers are not required to perform 
additional analysis or make modifications based on comments unless the 
Interconnection Customer agrees to pay for the additional studies. 
While the Commission does not require Transmission Providers to modify 
the facilities study after receiving Interconnection Customer comments, 
the Commission encourages Transmission Providers to consider these 
comments when finalizing the facilities study. Further, the Commission 
reaffirms that the

[[Page 73267]]

Transmission Provider should make the final decision on upgrades 
required for interconnection because the Transmission Provider is 
ultimately responsible for the safety and reliability of its 
system.\386\ For the same reason, the Commission finds that third-party 
contractors may not perform any interconnection-associated network 
upgrades without Transmission Provider consent.
---------------------------------------------------------------------------

    \386\ NOPR, FERC Stats. & Regs. ] 32,697 at P 27. We note that 
this decision by the Transmission Provider is ``final'' in the 
context of the dialogue between the Interconnection Customer and the 
Transmission Provider, but may be reviewed in some circumstances by 
the Commission (e.g., in response to a compliant that a Transmission 
Provider is requiring certain upgrades in an arbitrary or unduly 
discriminatory manner).
---------------------------------------------------------------------------

    208. The Commission's experience with the LGIP comment process does 
not suggest that allowing comments prevents new interconnections, which 
was a concern raised by IECA. Therefore, the Commission finds it 
unnecessary to formally monitor the number of Small Generating Facility 
interconnections at this time.\387\ If an Interconnection Customer 
believes it is being treated in an unduly discriminatory manner, it may 
file a complaint with the Commission.
---------------------------------------------------------------------------

    \387\ We note that section 4.7 of the SGIP requires the 
retention of certain records for three years and provides that such 
records are subject to audit.
---------------------------------------------------------------------------

    209. Finally, the Commission disagrees with NYISO & NYTO that the 
provisions related to Interconnection Customers providing written 
comments on required upgrades should be included in section 3.5 of the 
SGIP to be consistent with the LGIP. In the SGIP, the details regarding 
the facilities study report are found in the SGIA, so the Commission 
finds it appropriate to add the provisions related to providing written 
comments on required upgrades to the SGIA as proposed.

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

1. Commission Proposal
    210. In the NOPR, the Commission proposed revisions to section 
1.5.4 of the SGIA to address a reliability concern related to automatic 
disconnection of the Small Generating Facility during over- and under-
frequency events that could become a matter of concern at high 
penetrations of PV resources. The proposed revisions to section 1.5.4 
would require the Interconnection Customer to design, install, 
maintain, and operate its Small Generating Facility, in accordance with 
the latest version of the applicable standards (e.g., IEEE Standard 
1547 for Interconnecting Distributed Resources with Electric Power 
Systems), to prevent automatic disconnection during over- and under-
frequency events and to ensure that rates remain just and 
reasonable.\388\
---------------------------------------------------------------------------

    \388\ NOPR, FERC Stats. & Regs. ] 32,697 at P 46.
---------------------------------------------------------------------------

2. Comments
    211. ISO-NE supports the Commission's proposal to mitigate the 
potential frequency problems and requests that the Commission revise 
the proposed modifications to include a voltage ride-through provision 
as well.\389\ CAISO supports the proposed reform but urges the 
Commission to coordinate its proposed reform with the outcome of the 
CPUC's Rule 21 proceedings.\390\
---------------------------------------------------------------------------

    \389\ ISO-NE at 20.
    \390\ CAISO at 8.
---------------------------------------------------------------------------

    212. CPUC states that it is currently developing technical 
standards to address voltage, frequency and other issues arising from 
Small Generating Facilities and is unable to provide comments until 
those standards are finalized.\391\ CPUC notes that it is focusing on 
``smart inverters'' to mitigate the voltage, frequency and other 
impacts of Small Generating Facilities.\392\
---------------------------------------------------------------------------

    \391\ CPUC at 7-8.
    \392\ Id. at 7.
---------------------------------------------------------------------------

    213. ComRent suggests that the Final Rule recognize the upcoming 
changes to IEEE 1547, including more interactive control of distributed 
resources by the electric power system operator and test requirements 
for interconnection.\393\ ComRent encourages the Commission to 
reference the current version of the standards and acknowledge that the 
requirements may evolve through the consensus standards making process. 
ComRent also notes that the capability to provide documented tests for 
interconnection and impact to a wide range of variables are available 
today in the size range being discussed in this rulemaking.\394\
---------------------------------------------------------------------------

    \393\ ComRent at 1.
    \394\ ComRent at 1.
---------------------------------------------------------------------------

    214. AWEA expresses concern that a requirement to comply with IEEE 
1547 could actually be counterproductive for making the power system 
more resilient to over- or under-frequency events.\395\ AWEA argues 
that IEEE 1547 as currently drafted requires distributed generation up 
to 10 MW to remain online only during extremely small frequency 
deviations, and requires them to disconnect during moderate frequency 
deviations.\396\ AWEA asserts that this requirement counters the 
Commission's stated goal of preventing automatic disconnection during 
an over- or under-frequency event.\397\ In supplemental comments, AWEA 
notes that pending revisions to IEEE 1547 no longer prohibit voltage 
and frequency ride-through for distributed generators.\398\
---------------------------------------------------------------------------

    \395\ AWEA at 2.
    \396\ Id. at 5.
    \397\ Id.
    \398\ AWEA Supplemental Comments at 5.
---------------------------------------------------------------------------

    215. AWEA states that the Commission should convene a technical 
conference and pursue other efforts to ensure that IEEE and other 
entities are working towards a standard that will prevent automatic 
disconnection of new distributed generation during moderate over- and 
under-frequency events.\399\ In addition, AWEA states that the 
Commission should clarify that, while the ride-through requirement for 
new generators may evolve as standards like IEEE 1547 evolve, the 
requirement for existing generators will be fixed at whatever standard 
was in place at the time the SGIA for that generator was 
implemented.\400\
---------------------------------------------------------------------------

    \399\ AWEA at 6.
    \400\ Id. at 7.
---------------------------------------------------------------------------

    216. The California Utilities assert that further exploration of 
this issue is needed before any rules are proposed.\401\ The California 
Utilities assert that the Commission should consider the role of the 
smart inverter because it may provide the ability to address frequency 
and voltage ride-through and other benefits related to voltage control 
and reactive power support.\402\
---------------------------------------------------------------------------

    \401\ California Utilities at 5.
    \402\ Id.
---------------------------------------------------------------------------

    217. NRECA, EEI & APPA assert that the proposed revisions to SGIA 
section 1.5.4 will require the Interconnection Customer to design, 
install, maintain and operate its Small Generating Facility in 
accordance with the latest version of the applicable North American 
Electric Reliability Corporation (NERC) reliability standards, unless 
the Transmission Provider has established different requirements that 
apply to all similarly situated generators in the control area on a 
comparable basis, to prevent automatic disconnection during an over- or 
under-frequency event.\403\ NRECA, EEI &APPA suggest revising the 
proposed language in SGIA section 1.5.4 as follows:
---------------------------------------------------------------------------

    \403\ NRECA, EEI & APPA at 28-29.

    1.4.1.2 ``. . . The Interconnection Customer agrees to design, 
install, maintain, and operate its Small Generating Facility so as 
to reasonably minimize the likelihood of (1) a disturbance of its 
Small Generating Facility adversely affecting or impairing the 
system or equipment of the Transmission Provider and any Affected 
Systems, and (2)

[[Page 73268]]

a disturbance of the system or equipment of the Transmission 
Provider or any Affected System causing off-normal frequency 
deviations unless the Transmission Provider has established 
different requirements that apply to all similarly situated 
generators in the control area on a comparable basis and resulting 
in a common mode disconnection of its Small Generating Facility.'' 
\404\
---------------------------------------------------------------------------

    \404\ Id., Appendix B at 4.

    218. NRECA, EEI & APPA also request that the following sentence be 
added to SGIA section 1.5.2 requiring the Small Generating Facility to 
permit equal current in each phase conductor: ``Voltage unbalance 
resulting from unbalanced currents shall not exceed 2% between phases 
and shall not cause objectionable effects upon or interfere with the 
operation of the interconnection to the [Transmission Provider's 
System]. This criterion shall be met with and without generation.'' 
\405\
---------------------------------------------------------------------------

    \405\ Id.
---------------------------------------------------------------------------

    219. NRECA, EEI & APPA state that the Commission should not 
reference or incorporate IEEE Standards 1547 or 1547.1 into the Final 
Rule because mandatory standards do not permit the flexibility needed 
to allow IEEE standards to evolve and will likely impede the current 
1547 standard development process.\406\ They also assert that 
references to standards can lead to conflicting requirements if those 
standards are subsequently updated.\407\ Citing Commission precedent, 
NRECA, EEI & APPA state that in the past, the Commission has declined 
to use rulemaking proceedings to make voluntary IEEE standards 
mandatory.\408\
---------------------------------------------------------------------------

    \406\ NRECA, EEI & APPA Reply Comments at 17.
    \407\ Id.
    \408\ Id. (citing Trans. Relay Loadability Reliability Std., 
Order No. 733, 130 FERC ] 61,221, at P 207 (2010)).
---------------------------------------------------------------------------

3. Commission Determination
    220. The Commission declines to adopt the NOPR proposal to revise 
to section 1.5.4 of the SGIA, or any of the revisions proposed by 
commenters, at this time. Section 1.5.4 of the pro forma SGIA adopted 
in Order No. 2006 already requires an Interconnection Customer to 
``construct its facilities or systems in accordance with applicable 
specifications that meet or exceed those provided by the National 
Electrical Safety Code, the American National Standards Institute, 
IEEE, Underwriter's Laboratory, and Operating Requirements in effect at 
the time of construction and other applicable national and state codes 
and standards.'' Based on the comments received, the Commission does 
not see a need to change section 1.5.4 of the SGIA at this time. As 
NRECA, EEI & APPA note, these standards may be revised as systems 
evolve. The Commission recognizes that IEEE is currently in the process 
of revising the requirements under IEEE Standard 1547a \409\ for 
frequency ride-through, voltage ride-through, and voltage regulation. 
IEEE standards are reconsidered every 10 years, and at the end of the 
10-year period, the standard may be either revised or withdrawn.\410\ 
The revision of the IEEE Standard 1547 will begin in early 2014, which 
will allow another opportunity to either correct or address outdated 
requirements in the standard. We encourage Transmission Providers and 
NERC to participate in the IEEE standards development process to 
provide input on the effects of the growing penetration of distributed 
generation on the bulk-power system. The Commission will continue to 
follow this process and may revise the pro forma SGIA as it relates to 
IEEE Standard 1547 in the future, if necessary.
---------------------------------------------------------------------------

    \409\ IEEE Standard 1547a is an amendment to IEEE Standard 1547 
to establish updates to voltage regulation, as well as response to 
abnormal voltage and frequency conditions.
    \410\ See ``Revising Standards,'' available at http://standards.ieee.org/develop/revisestds.html.
---------------------------------------------------------------------------

    221. Finally, the Commission disagrees with NRECA, EEI & APPA's 
comment that section 1.5.2 requires the Interconnection Customer to 
design, install, maintain, and operate its Small Generating Facility in 
accordance with the latest version of the applicable NERC reliability 
standards. The pro forma SGIA is applicable to generators no larger 
than 20 MW (approximately 20 megavolt amperes (MVA)). The NERC 
reliability standards are generally applicable to generators greater 
than 20 MVA.\411\ Therefore, NERC reliability standards would generally 
not apply to Small Generating Facilities executing the SGIA. However, 
the Commission notes that IEEE Standard 1547 applies to generators with 
a capacity of 10 MVA or less. The Commission encourages IEEE to 
formulate interconnection standards for generators between 10 and 20 
MVA.
---------------------------------------------------------------------------

    \411\ NERC Statement of Compliance Registry Criteria at p. 9, 
available at http://www.nerc.com/files/Appendix_5B_RegistrationCriteria_20120131.pdf.
---------------------------------------------------------------------------

F. Interconnection of Storage Devices

1. Commission Proposal
    222. In the NOPR, the Commission announced that it would hold a 
workshop before the end of the comment period that would include the 
following topic: ``Whether storage devices could fall within the 
definition of Small Generating Facility included in Attachment 1 to the 
SGIP and Attachment 1 to the SGIA as devices that produce 
electricity.'' The March 27, 2013 workshop included a roundtable 
discussion on the interconnection of storage devices. The Commission 
requested comments on issues raised at the workshop in addition to 
comments on the NOPR.\412\
---------------------------------------------------------------------------

    \412\ NOPR, FERC Stats. & Regs. ] 32,697 at P 49.
---------------------------------------------------------------------------

2. Comments
    223. CREA supports including storage devices within the definition 
of Small Generating Facility.\413\ CREA opines that expanding the 
definition to include storage will incentivize small generators to keep 
abreast of future innovations in storage technology.\414\ CAISO 
believes the existing definition is sufficiently broad to encompass a 
storage device and therefore apply the SGIP to such a facility if it is 
less than 20 MW.\415\
---------------------------------------------------------------------------

    \413\ CREA at 3.
    \414\ Id.
    \415\ CAISO at 9.
---------------------------------------------------------------------------

    224. The California Utilities believe that further exploration of 
this issue is needed before any rules are proposed and note that 
interconnection of storage devices will be discussed during Phase II of 
California's Rule 21 proceeding.\416\
---------------------------------------------------------------------------

    \416\ California Utilities at 5. Also, see supra note 231.
---------------------------------------------------------------------------

    225. ESA states that the Commission should define a Small 
Generating Facility as ``a device used for the production and/or 
storage for later injection of electricity having a maximum output of 
no more than 20 MW.'' \417\ ESA states that the Commission should 
measure the capacity of a storage resource based on the maximum 
quantity that the resource can inject to the grid to be comparable to 
other small generators for the purposes of determining if the storage 
device is a Small Generator or qualifying it for the Fast Track 
Process.\418\
---------------------------------------------------------------------------

    \417\ ESA at 6.
    \418\ Id. at 5.
---------------------------------------------------------------------------

    226. ESA also recommends that the Commission clarify how to measure 
the size of interconnections that are combining renewable resources 
with storage devices.\419\ ESA recommends that interconnection size be 
measured by the maximum intended injection of the combined 
resource.\420\ ESA states that its recommendations are entirely 
consistent with the interpretation to date of the SGIP for storage 
projects, and that it merely wants the Commission to confirm existing 
practice.\421\
---------------------------------------------------------------------------

    \419\ Id.
    \420\ Id. 6.
    \421\ Id. at 5.

---------------------------------------------------------------------------

[[Page 73269]]

3. Commission Determination
    227. The Commission finds, based on the comments received, that it 
is appropriate to adopt certain revisions to the pro forma SGIP to 
explicitly account for the interconnection of storage devices in order 
to ensure that storage devices are interconnected in a just and 
reasonable and not unduly discriminatory manner. The Commission 
acknowledges that the interconnection of storage devices will be 
discussed in the ongoing Rule 21 proceeding as the California Utilities 
point out in their comments.\422\ As more experience is gained with the 
interconnection of storage devices and as the issue is explored further 
in other proceedings, such as the Rule 21 proceeding, the Commission 
may adopt further revisions to the pro forma SGIP and SGIA associated 
with the interconnection of storage devices.
---------------------------------------------------------------------------

    \422\ California Utilities at 5.
---------------------------------------------------------------------------

    228. The Commission agrees with CAISO that the definition of Small 
Generating Facility is broad enough to include storage devices. 
However, the Commission also agrees with ESA and CREA that, in order to 
improve the transparency of the SGIP, the definition of Small 
Generating Facility in the pro forma SGIP and SGIA should be clarified 
to explicitly include storage devices. Accordingly, the Commission 
revises the definition of Small Generating Facility in Attachment 1 to 
the SGIP and Attachment 1 to the SGIA as follows: ``The Interconnection 
Customer's device for the production and/or storage for later injection 
of electricity identified in the Interconnection Request, but shall not 
include the Interconnection Customer's Interconnection Facilities.''
    229. The Commission agrees with ESA that when determining whether a 
storage device may interconnect under the SGIP and/or whether it 
qualifies for the Fast Track Process, the Transmission Provider should 
generally assume that the capacity of the storage device is equal to 
the maximum capacity that the particular device is capable of injecting 
into the Transmission Provider's system (e.g., a storage device capable 
of injecting 500 kW into the grid and absorbing 500 kW from the grid 
would be evaluated at 500 kW for the purpose of determining if it is a 
Small Generating Facility or whether it qualifies for the Fast Track 
Process). Thus, the Commission revises SGIP section 4.10.3 to clarify 
that the term ``capacity'' of the Small Generating Facility in the SGIP 
refers to the maximum capacity that a device is capable of injecting 
into the Transmission Provider's system. When interconnecting such a 
storage device, the revisions to SGIP section 4.10.3 adopted herein do 
not preclude a Transmission Provider from studying the effect on its 
system of the absorption of energy by the storage device and making 
determinations based on the outcome of these studies.
    230. To address ESA's comment related to combining generation 
resources with storage resources (e.g., a storage facility operating to 
firm a variable energy resource), the Commission further revises SGIP 
section 4.10.3. Under section 4.10.3 adopted herein, the Transmission 
Provider is to measure the capacity of a Small Generating Facility 
based on the capacity specified in the interconnection request, which 
may be less than the maximum capacity that a device is capable of 
injecting into the Transmission Provider's system, provided that the 
Transmission Provider agrees, with such agreement not to be 
unreasonably withheld, that the manner in which the Interconnection 
Customer proposes to limit the maximum capacity that its facility is 
capable of injecting into the Transmission Provider's system will not 
adversely affect the safety and reliability of the Transmission 
Provider's system. For example, an Interconnection Customer with a 
combined resource may propose a control system, power relays, or both 
for the purpose of limiting its maximum injection amount into the 
Transmission Provider's system.
    231. The Commission notes that in Order No. 2006 it considered 
evaluating Small Generating Facilities based on less than their maximum 
rated capacity, but determined that this would not ensure that proper 
protective equipment is designed and installed and that the safety and 
reliability of the Transmission Provider's system could be 
maintained.\423\ However, as discussed above, the energy industry has 
changed since Order No. 2006 was issued.\424\ The use of storage in 
combination with other resources was not contemplated in Order No. 
2006. In order to balance the needs of Small Generating Facilities and 
Transmission Providers, the Commission clarifies that section 4.10.3 
adopted herein applies only to the determination of whether a resource 
is a Small Generating Facility to be evaluated under the SGIP rather 
than the LGIP, or if it qualifies for the Fast Track Process. In the 
Study Process, the Transmission Provider has the discretion to study 
the combined resource using the maximum capacity the Small Generating 
Facility is capable of injecting into the Transmission Provider's 
system and require proper protective equipment to be designed and 
installed so that the safety and reliability of the Transmission 
Provider's system is maintained. Similarly, in the Fast Track Process, 
the Transmission Provider may apply the Fast Track screens or the 
supplemental review screens using the maximum capacity the Small 
Generating Facility is capable of injecting into the Transmission 
Provider's system in a manner that ensures that the safety and 
reliability of its system is maintained.
---------------------------------------------------------------------------

    \423\ See Order No. 2006, FERC Stats. & Regs. ] 31,180 at PP 79-
86.
    \424\ See supra PP 0-0.
---------------------------------------------------------------------------

G. Other Issues

1. Network Resource Interconnection Service
a. Commission Proposal
    232. The Commission proposed to revise section 1.1.1 of the pro 
forma SGIP to require Interconnection Customers wishing to interconnect 
its Small Generating Facility using Network Resource Interconnection 
Service to do so under the LGIP and execute the LGIA. The Commission 
explained that this requirement was included in Order No. 2006 \425\ 
but was not made clear in the pro forma SGIP. To facilitate this 
clarification, the Commission also proposed to add the definitions of 
Network Resource and Network Resource Interconnection Service to 
Attachment 1, Glossary of Terms, of the pro forma SGIP.\426\
---------------------------------------------------------------------------

    \425\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 140.
    \426\ NOPR, FERC Stats. & Regs. ] 32,697 at P 45.
---------------------------------------------------------------------------

b. Comments
    233. MISO states that its generator interconnection procedures and 
agreement are the result of a merger of its LGIP/LGIA and SGIP/SGIA in 
2008. Because it does not differentiate between small and large 
interconnection requests, MISO states that the proposed revisions to 
section 1.1.1 of the pro forma SGIP would likely not apply to 
MISO.\427\ MISO further asserts that its generator interconnection 
procedures already provide comparable definitions for ``Network 
Resource'' and ``Network Resource Interconnection Service.'' \428\
---------------------------------------------------------------------------

    \427\ MISO at 10.
    \428\ Id. at 10-11.
---------------------------------------------------------------------------

    234. NYISO & NYTO state this proposed revision could undermine the 
requirements in Attachment Z of the NYISO OATT that permit a Small 
Generating Facility to elect Capacity Resource Interconnection Service 
under

[[Page 73270]]

NYISO's SGIP and to execute an SGIA.\429\ NYISO & NYTO assert that 
making Small Generating Facilities subject to the LGIP and requiring an 
LGIA would greatly increase the time and expense of interconnecting 
such projects. Therefore, NYISO & NYTO ask the Commission to clarify 
that the proposed revisions will not disturb these existing 
procedures.\430\
---------------------------------------------------------------------------

    \429\ NYISO & NYTO at 23.
    \430\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    235. The Commission adopts the revisions as proposed in the NOPR. 
As the Commission noted in the NOPR, the revision is meant to clarify 
in the pro forma SGIP an Order No. 2006 requirement rather than 
implement a new requirement.
    236. Our intent is not to require revisions to interconnection 
procedures that have previously been found to be consistent with or 
superior to the pro forma SGIP and SGIA with regard to this Order No. 
2006 requirement or permissible under the independent entity variation 
standard. In cases where provisions in Transmission Providers' existing 
interconnection procedures have been found by the Commission to be 
consistent with or superior to the pro forma SGIP and SGIA originally 
adopted under Order No. 2006 or permissible under the independent 
entity variation standard would be modified by the Final Rule, public 
utility Transmission Providers must either comply with the Final Rule 
or demonstrate that these previously approved variations meet the 
standard under which they are filed.\431\
---------------------------------------------------------------------------

    \431\ See infra P 0.
---------------------------------------------------------------------------

2. Hosting Capacity
a. Comments
    237. Pepco offers its ``hosting capacity'' process as an 
alternative approach to the interconnection procedures in the NOPR and 
claims that it is superior to the proposed pre-application report and 
Fast Track screens.\432\ According to Pepco, its hosting capacity 
approach 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.\433\ 
Pepco states that hosting capacity is determined by applying the 
screens set forth in section 2.4.1.1 to 2.4.1.3 of the SGIP and will 
describe the amount of additional generating capacity a distribution 
circuit can accommodate above what has already been approved or queued 
for interconnection without requiring the construction of facilities by 
the Transmission Provider.\434\
---------------------------------------------------------------------------

    \432\ Pepco at 4.
    \433\ Pepco, Attachment 1.
    \434\ Id. (stating that its hosting capacity considers queued 
capacity for which an interconnection agreement has not been 
issued).
---------------------------------------------------------------------------

    238. Pepco states that it has successfully interconnected over 
7,700 PV systems by using load flow tools to determine a maximum 
allowable hosting capacity at a given Point of Interconnection on its 
transmission and distribution systems.\435\ Pepco asserts that load 
flow tools have allowed PV interconnections on many circuits that would 
otherwise not be available to new generation because they would violate 
a number of existing technical screens under the current SGIP, 
including the 15 Percent Screen.\436\
---------------------------------------------------------------------------

    \435\ Id. at 4.
    \436\ Id.
---------------------------------------------------------------------------

    239. IREC, Sandia and SEIA support allowing Transmission Providers 
to use load-flow tools to determine the hosting capacity at a 
particular Point of Interconnection in both the pre-application report 
and the Fast Track process, and encourage the Commission to include 
language related to hosting capacity in the Final Rule and in the pro 
forma SGIP.\437\ IREC states that hosting capacity would replace the 
total, allocated and available capacity in the pre-application report 
because these items are no longer valuable once the hosting capacity is 
known.\438\ IREC notes that the SGIP hosting capacity provisions it 
proposes with Pepco, NREL, and Sandia would not be mandatory for 
Transmission Providers, but would allow for the use of hosting capacity 
where the capability exists.\439\
---------------------------------------------------------------------------

    \437\ IREC at 8; Sandia at 3; and SEIA at 11.
    \438\ IREC at 11.
    \439\ Id. at 8, 11.
---------------------------------------------------------------------------

    240. IREC supports allowing Transmission Providers to elect not to 
use the Fast Track screens when they can provide hosting capacity, but 
would require them to comply with the 15 Percent Screen at a 
minimum.\440\ IREC states that if the Transmission Provider determines 
that using hosting capacity limits its ability to connect a proposed 
generator without further study, the Transmission Provider would be 
required to provide the Interconnection Customer with an explanation of 
the power flow, criteria violations, and/or queued projects that limit 
the hosting capacity.\441\ IREC believes the revisions related to 
hosting capacity will significantly improve the Fast Track Process for 
both generators and Transmission Providers, and may allow for larger 
generators or greater penetrations of distributed generation to 
interconnect using the Fast Track Process.\442\ Further, IREC supports 
incorporating the hosting capacity provisions into the SGIP rather than 
requiring Transmission Providers to seek modifications to the pro forma 
SGIP.\443\
---------------------------------------------------------------------------

    \440\ Id. at 16.
    \441\ Id.
    \442\ Id. at 8, 16.
    \443\ Id. at 16.
---------------------------------------------------------------------------

    241. NREL supports the use of hosting capacity as long as 
Transmission Providers are transparent regarding how hosting capacity 
is determined.\444\ VSI also supports IREC and Pepco's hosting capacity 
proposal.\445\ VSI states that the duration of the Study Process would 
decrease and existing equipment would be better optimized if all 
Transmission Providers had the capability to determine their hosting 
capacity in advance of the pre-application report.\446\
---------------------------------------------------------------------------

    \444\ NREL at 3.
    \445\ VSI at 2.
    \446\ Id.
---------------------------------------------------------------------------

    242. Sandia supports the use of dynamic load flow analysis to 
determine the hosting capacity of a circuit, as it is the most 
comprehensive and accurate way to determine the deployment level of 
distributed generation that can be accommodated on a distribution 
circuit without system upgrades.\447\
---------------------------------------------------------------------------

    \447\ Sandia at 3.
---------------------------------------------------------------------------

b. Commission Determination
    243. The Commission encourages Transmission Providers to develop 
innovative and transparent interconnection processes that provide 
valuable information to Interconnection Customers. However, the 
Commission declines to include hosting capacity in the SGIP at this 
time because the record does not contain a sufficient discussion of the 
proposal. Transmission Providers wishing to utilize hosting capacity as 
part of their interconnection process may propose such procedures in 
their compliance filings for this Final Rule. Similar to other filings 
that do not conform with the pro forma SGIP and SGIA adopted under this 
Final Rule, the Commission will consider whether such procedures meet 
the compliance standard under which the filing was made.\448\
---------------------------------------------------------------------------

    \448\ See infra section V for a discussion of compliance with 
this Final Rule.

---------------------------------------------------------------------------

[[Page 73271]]

3. Jurisdiction
a. Comments
    244. NRECA, EEI & APPA assert that the NOPR incorrectly states that 
``[t]he pro forma SGIP and SGIA are used by a public utility to 
interconnect a Small Generating Facility with the utility's 
transmission or with its jurisdictional distribution facilities for the 
purpose of selling electric energy at wholesale in interstate 
commerce.'' \449\ They state that, as explained in Order No. 2003-C, 
the Commission's authority ``is limited to the wholesale transaction'' 
and ``it may not regulate the `local distribution' facility itself, 
which remains state-jurisdictional.'' \450\ NRECA, EEI & APPA therefore 
state that the Commission was incorrect in characterizing distribution 
facilities as ``[FERC] jurisdictional.'' They ask that the Commission 
correct this improper characterization.
---------------------------------------------------------------------------

    \449\ NRECA, EEI & APPA at 29 (quoting the NOPR, FERC Stats. & 
Regs. ] 32, 6a7 at P1, n. 4) (emphasis added).
    \450\ Id. at 29-30 (referencing Order No. 2003-C, FERC Stats. & 
Regs. ] 31,190 at P 53).
---------------------------------------------------------------------------

    245. NYISO & NYTO similarly ask the Commission to clarify that the 
term ``Distribution System'' as proposed in sections 1.1.1, 3.1 and 2.1 
of the SGIP is limited to distribution facilities that are subject to 
the Commission's jurisdiction.\451\
---------------------------------------------------------------------------

    \451\ NYISO & NYTO at 24.
---------------------------------------------------------------------------

b. Commission Determination
    246. The Commission clarifies that the scope of its jurisdiction in 
this proceeding with respect to distribution facilities is identical to 
the jurisdiction previously asserted and as described in Order Nos. 888 
\452\ and 2003. Just as the Commission stated in Order No. 2003-A:
---------------------------------------------------------------------------

    \452\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g, 
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order 
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom. 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. 
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

    There is no intent to expand the jurisdiction of the Commission 
in any way; if a facility is not already subject to Commission 
jurisdiction at the time interconnection is requested, the Final 
Rule will not apply. Thus, only facilities that already are subject 
to the Transmission Provider's OATT are covered by this rule. The 
Commission is not encroaching on the States' jurisdiction and is not 
improperly asserting jurisdiction over ``local distribution'' 
facilities.\453\
---------------------------------------------------------------------------

    \453\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 700.

    247. In response to NYISO & NYTO's comment, the Commission 
clarifies that the term ``Distribution System'' as used in this Final 
Rule is limited to distribution facilities that are subject to the 
Commission's jurisdiction.
    248. In Order No. 2006, the Commission stated that the regulations 
promulgated under Order No. 2006 applied to interconnections to 
facilities that are already subject to a Commission-jurisdictional OATT 
at the time the interconnection request is made and that will be used 
for purposes of jurisdictional wholesale sales.\454\ In Order No. 2003-
C, however, the Commission clarified that, ``while the Commission may 
regulate the entire transmission component * * * of the wholesale 
transaction--whether the facilities used to transmit are labeled 
`transmission' or `local distribution'--it may not regulate the `local 
distribution' facility itself, which remains state-jurisdictional.'' 
\455\ The Commission clarifies that its jurisdiction under this Final 
Rule does not extend to local distribution facilities.
---------------------------------------------------------------------------

    \454\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at PP 7-8.
    \455\ Order No. 2003, FERC Stats. & Regs. ] 31,146.
---------------------------------------------------------------------------

4. Miscellaneous
a. Commission Proposal
    249. In addition to the proposed reforms and clarifications 
described above, the Commission proposed to correct section 3.3.5 of 
the pro forma SGIA. Specifically, we proposed to replace the first word 
of this section (``This'') with ``The.''
b. Comments
    250. Several comments did not fit neatly within the topics 
discussed in the NOPR. FCHEA and CEP support increasing the project 
size threshold for requiring telemetry equipment to 5 MW because this 
equipment can add significant financial burden to distributed 
generation projects.\456\ FCHEA and CEP state that the Commission 
should strongly encourage the states to match the Commission threshold 
in state interconnection procedures to avoid discouraging development 
of distributed generation projects.\457\ CEP also recommends several 
changes to net metering and demand charges associated with distributed 
generation.\458\
---------------------------------------------------------------------------

    \456\ FCHEA at 1.
    \457\ Id. at 2.
    \458\ CEP at 2-3.
---------------------------------------------------------------------------

    251. ELCON and IECA submitted comments in support of advancing 
combined heat and power (CHP) interconnections.\459\ ELCON claims that 
various barriers to the development of large CHP generation currently 
exist and urges the Commission to initiate a Notice of Inquiry to 
investigate the issues.\460\ IECA states that the Commission should 
establish longer-term capacity payment mechanisms to encourage capital 
formation for manufacturer CHP and waste heat recovery investments, 
such as a 15- to 20-year term capacity payment.\461\
---------------------------------------------------------------------------

    \459\ ELCON at 4.
    \460\ Id. at 6-7 and IECA at 10.
    \461\ IECA at 10.
---------------------------------------------------------------------------

    252. Bonneville recommends that, to prevent an Affected System 
\462\ from having to construct upgrades or new facilities in response 
to an interconnection, the Commission should revise section 2.2.1.10 of 
the SGIP to read ``No construction of facilities by the Transmission 
Provider on its own system, nor construction of any facilities on any 
Affected System, shall be required to accommodate the Small Generating 
Facility.'' \463\
---------------------------------------------------------------------------

    \462\ See supra note 343.
    \463\ Bonneville at 3.
---------------------------------------------------------------------------

    253. NREL states that it has analyzed PV systems integrated onto 
secondary network distribution systems and has found that there are 
methods of increasing the amount of interconnected PV generation on a 
spot network without affecting reliability and power quality.\464\ NREL 
proposes adding language to the Secondary Network Distribution System 
screen.\465\
---------------------------------------------------------------------------

    \464\ NREL at 5.
    \465\ Id. NREL proposes adding the following to the Secondary 
Network Distribution System screen: ``or 25kVA less than the minimum 
daytime load of the network when the proposed Small Generating 
Facility is a PV system and will have minimum import relay and 
dynamically controlled inverter controls installed to prevent 
backfeed onto the secondary network.''
---------------------------------------------------------------------------

    254. NRECA, EEI & APPA suggest adjusting the feasibility study 
deposit of $1,000 and the Fast Track processing fee of $500 annually 
based on the Consumer Price Index.\466\ The commenters also suggest 
changing the record retention requirement in SGIP section 4.7 from 
three years to five years.\467\ NRECA, EEI & APPA also suggest two 
changes to the Fast Track screens in section 2.2.1: (1) Adding language 
to section 2.2.1.2 for areas bounded by a voltage regulation zone of a 
distribution line or a power transformer; and (2) revising the 10 MW 
aggregate interconnected generation threshold in section 2.2.1.9 for 
areas with known or posted transient stability limitations to 
accommodate ISOs and

[[Page 73272]]

RTOs that may have lower thresholds.\468\
---------------------------------------------------------------------------

    \466\ NRECA, EEI & APPA, Appendix B at 3-4.
    \467\ Id. at 3.
    \468\ Id. at 2.
---------------------------------------------------------------------------

    255. Clean Coalition strongly urges the Commission to ensure that 
any SGIP reforms adopted in this Final Rule apply equally to grid 
operators using the SGIP and to those that have combined the SGIP and 
LGIP into a single generator interconnection procedure.\469\
---------------------------------------------------------------------------

    \469\ Clean Coalition at 9.
---------------------------------------------------------------------------

    256. UCS asks the Commission to ``assert an affirmative 
obligation'' that Transmission Providers integrate and use the voltage 
support capability provided by Small Generating Facilities.\470\ UCS 
asserts that the Transmission Provider's failure to utilize the voltage 
control capability of Small Generating Facilities increases the 
interconnection costs because the Transmission Provider may require 
upgrades to provide voltage support rather than using the capability 
inherent in the proposed facility.\471\
---------------------------------------------------------------------------

    \470\ UCS at 22.
    \471\ Id. at 25.
---------------------------------------------------------------------------

c. Commission Determination
    257. The Commission finds the following to be beyond the scope of 
this proceeding: (1) FCHEA and CEP's requests to increase the threshold 
for requiring telemetry equipment; (2) ELCON and IECA's recommendations 
regarding CHP; (3) CEP's recommendations with regard to net metering 
and demand charges associated with distributed generation; (4) NRECA, 
EEI & APPA's proposed changes to the Fast Track screens in SGIP section 
2.2.1; (5) NRECA, EEI & APPA's proposal to change the record retention 
requirement in SGIP section 4.7 from three years to five years; (6) 
NREL's proposal to add language to the Secondary Network Distribution 
System screen in section 2.2.1.3 of the SGIP; and (7) UCS's request 
that the Commission require Transmission Providers to integrate and use 
the voltage support capability provided by Small Generating Facilities.
    258. With regard to the impact of Fast Track screens on Affected 
Systems, section 4.9 of the SGIP already directs Transmission Providers 
to consider Affected Systems during the Fast Track screens when 
possible. Accordingly, the Commission finds that Bonneville's proposal 
to amend section 2.2.1.1 of the SGIP is unnecessary.
    259. We decline to adjust the Fast Track processing fee for 
inflation because, as provided for in Order No. 2006, Transmission 
Providers may submit a filing under FPA section 205 if the fixed fees 
in the pro forma SGIP do not sufficiently recover their costs.\472\ We 
also decline to adjust the feasibility study deposit for inflation 
because Transmission Providers collect actual costs for the feasibility 
study. If a Transmission Provider would like to increase this deposit, 
it may propose to do so in its compliance filing.\473\
---------------------------------------------------------------------------

    \472\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 126.
    \473\ See infra section V.
---------------------------------------------------------------------------

    260. Regarding Clean Coalition's request that the Commission 
require that the SGIP reforms adopted herein apply to public utility 
Transmission Providers that have combined their SGIP and LGIP into a 
single set of generator interconnection procedures, the Commission 
affirms that the reforms adopted herein apply to all Commission-
jurisdictional SGIPs, including those that have been combined with 
LGIPs.
    261. Finally, the Commission replaces the first word of section 
3.3.5 of the pro forma SGIA (``This'') with ``The'' as proposed in the 
NOPR. The Commission also makes certain minor clarifying revisions to 
the flow chart in Appendix B to this Final Rule.

V. Compliance

A. Commission Proposal

    262. In the NOPR, the Commission stated that each public utility 
Transmission Provider would be required to submit a compliance filing 
within six months of the effective date of the Final Rule revising its 
SGIP and SGIA or other document(s) subject to the Commission's 
jurisdiction as necessary to demonstrate that it meets the requirements 
as set forth in the Final Rule.\474\
---------------------------------------------------------------------------

    \474\ NOPR, FERC Stats. & Regs. ] 32,697 at P 50.
---------------------------------------------------------------------------

    263. The Commission acknowledged that in some cases, public utility 
Transmission Providers may have provisions in their existing SGIPs and 
SGIAs that the Commission has deemed to be consistent with or superior 
to the pro forma SGIP and SGIA. The Commission indicated that where 
these provisions are modified by the Final Rule, public utility 
Transmission Providers must either comply with the Final Rule or 
demonstrate that these previously-approved variations continue to be 
consistent with or superior to the pro forma SGIP and SGIA as modified 
by the Final Rule.
    264. The Commission also proposed that Transmission Providers that 
are not public utilities would have to adopt the requirements of the 
Final Rule as a condition of maintaining the status of their safe 
harbor tariff or otherwise satisfying the reciprocity requirement of 
Order No. 888.\475\
---------------------------------------------------------------------------

    \475\ See Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-
63.
---------------------------------------------------------------------------

B. Comments

    265. Several commenters urge the Commission to permit regional 
discretion and flexibility in the implementation of the SGIP.\476\ 
Commenters urge the Commission to adopt a process that permits each 
region to develop and implement its own specific proposals to the 
problems identified by the Commission.\477\ CAISO comments that the pro 
forma proposals may not in all instances allow ISOs and RTOs operating 
high-voltage transmission systems to streamline interconnections for 
Small Generating Facilities.\478\
---------------------------------------------------------------------------

    \476\ CAISO at 2; California Utilities at 4; ISO-NE at 2; IRC at 
1; NYISO & NYTO at 2; and PJM at 4.
    \477\ CAISO at 2; IRC at 1; and NYISO & NYTO at 3.
    \478\ CAISO at 2.
---------------------------------------------------------------------------

    266. NYISO & NYTO state that the Commission should direct each ISO/
RTO to report on the status of its processing of small generator 
interconnection requests and to develop with its stakeholders and 
implement, where needed, regionally-tailored reforms to its SGIP.\479\ 
Additionally, they state a regional approach would be consistent with 
the Commission's order concerning interconnection queuing practices 
where the Commission permitted each region the opportunity to propose 
its own solution to problems identified by the Commission with respect 
to queue management.\480\ NYISO & NYTO request that the Commission 
clarify that, consistent with Order No. 2006, it will permit RTOs and 
ISOs to seek ``independent entity variations'' from any revisions to 
the pro forma SGIP to accommodate regional differences.\481\
---------------------------------------------------------------------------

    \479\ NYISO & NYTO at 3.
    \480\ NYISO & NYTO at 4 (referencing Interconnection Queuing 
Practices, Order on Technical Conference, 122 FERC ] 61,252 (March 
20, 2008) (Queue Management Order)).
    \481\ Id. (referencing Order No. 2006, FERC Stats. & Regs. ] 
31,180 at P 549).
---------------------------------------------------------------------------

    267. CAISO states that it has commenced a stakeholder initiative to 
examine the need for interconnection procedure enhancements, including 
developing new Fast Track screens that are specific to the networked 
transmission system, and request that any action in this proceeding not 
preclude it from proposing enhancements to Fast Track screens 
consistent with the independent entity variation standard.\482\
---------------------------------------------------------------------------

    \482\ CAISO at 7.

---------------------------------------------------------------------------

[[Page 73273]]

    268. ISO-NE states that its pro forma SGIP has varied greatly from 
the Commission's pro forma SGIP since its implementation in 2006. 
Therefore ISO-NE requests regional flexibility to maintain the 
previously approved variations.\483\ NARUC similarly emphasizes that 
``proposals appropriate for one State or region of the country may not 
be appropriate, or permitted by State law or regulation, in other 
regions.'' \484\ The California Utilities and NARUC also believe that 
the rules and procedures must be flexible enough to accommodate 
differences between the standards set by states and those set by the 
Commission in order for utilities to provide comparable service to 
generators interconnecting to their electric systems.\485\
---------------------------------------------------------------------------

    \483\ ISO-NE at 19.
    \484\ NARUC at 4.
    \485\ California Utilities at 4.
---------------------------------------------------------------------------

C. Commission Determination

    269. The Commission requires each public utility Transmission 
Provider to submit a compliance filing within six months of the 
effective date of this Final Rule revising its SGIP and SGIA or other 
document(s) subject to the Commission's jurisdiction as necessary to 
demonstrate that it meets the requirements set forth herein.
    270. The Commission will consider requests for variations from this 
rule submitted on compliance on the same bases as the variations 
permitted for compliance with Order No. 2006.\486\ Specifically, in 
cases where provisions in public utility Transmission Providers' 
existing SGIPs and SGIAs have been found by the Commission to be 
consistent with or superior to the pro forma SGIP and SGIA originally 
adopted under Order No. 2006 or permissible under the independent 
entity variation standard or regional reliability variation would be 
modified by the Final Rule, public utility Transmission Providers must 
either comply with the Final Rule or demonstrate that these previously-
approved variations are consistent with or superior to the pro forma 
SGIP and SGIA as modified by the Final Rule or otherwise meet the 
requirements of this section.
---------------------------------------------------------------------------

    \486\ See Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 546-
550.
---------------------------------------------------------------------------

    271. Any non-public utility that has a safe harbor tariff may amend 
its small generator interconnection agreements and procedures so that 
they substantially conform or are superior to the pro forma SGIP and 
SGIA as revised by this Final Rule if it wishes to continue to qualify 
for safe harbor treatment.
    272. As in Order Nos. 2003 and 2006, we will apply a regional 
differences rationale to accommodate variations from the Final Rule 
during compliance, but with certain restrictions. We conclude that a 
non-independent transmission provider (such as a Transmission Provider 
that owns generators or has Affiliates that own generators) and an RTO 
and ISO should be treated differently because an RTO or ISO does not 
raise the same level of concern regarding undue discrimination.\487\ 
Accordingly, we will allow an RTO or ISO greater flexibility to propose 
variations from the Final Rule provisions, as further discussed below.
---------------------------------------------------------------------------

    \487\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 822.
---------------------------------------------------------------------------

    273. We will require, however, that non-independent transmission 
providers justify variations in non-price terms and conditions of the 
Final Rule using the approach taken in Order No. 888, which allows them 
to propose variations on compliance that are ``consistent with or 
superior to'' the OATT.\488\ The Commission will consider two 
categories of variations from the Final Rule submitted by a non-
independent Transmission Provider.\489\ First, the Commission will 
consider ``regional reliability variations'' that track established 
reliability requirements (i.e., requirements approved by the applicable 
NERC Regional Entity and the Commission).\490\ Any request for a 
``regional reliability variation'' must be supported by references to 
established reliability requirements, and the text of the reliability 
requirements must be provided in support of the variation. If the 
variation is for any other reason, the non-independent Transmission 
Provider must demonstrate that the variation is ``consistent with or 
superior to'' the Final Rule provision. Any request for application of 
this standard will be considered under Federal Power Act section 205 
and must be supported by arguments explaining how each variation meets 
the standard.\491\
---------------------------------------------------------------------------

    \488\ Id. at PP 822-827.
    \489\ See Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 546 
(citing Order No. 2003 FERC Stats. & Regs. ] 31,146 at PP 824-825).
    \490\ Id.
    \491\ Id.
---------------------------------------------------------------------------

    274. We will permit ISOs and RTOs to seek ``independent entity 
variations'' from any revisions to the pro forma SGIP and SGIA. This is 
a balanced approach that recognizes that an RTO or ISO has different 
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. The RTO or ISO 
shall therefore have greater flexibility to customize its 
interconnection procedures and agreements to accommodate regional 
needs.\492\
---------------------------------------------------------------------------

    \492\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 
822-827.
---------------------------------------------------------------------------

    275. Finally, for a non-independent Transmission Provider that 
belongs to an RTO or ISO, the RTO's or ISO's Commission-approved 
agreements and procedures are to govern interconnection with its 
members' facilities that are under the operational control of the RTO 
or ISO. An interconnection with a Commission jurisdictional facility 
that is owned by a non-independent Transmission Provider but is not 
under the operational control of the RTO or ISO is to be conducted 
according to the non-independent Transmission Provider's procedures and 
agreements. A non-independent Transmission Provider, even if it belongs 
to an RTO or ISO, is not eligible for ``independent entity variations'' 
for procedures and agreements applicable to interconnection with 
facilities that remain within its operational control (and, therefore, 
are subject to a tariff different than the RTO or ISO's OATT).\493\
---------------------------------------------------------------------------

    \493\ See Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 550.
---------------------------------------------------------------------------

    276. Requests for regional reliability variations or independent 
entity variations are due on the effective date of this Final Rule. 
Requests for variations that are ``consistent with or superior to'' the 
pro forma OATT may be submitted on or after the effective date of the 
Final Rule.

VI. Information Collection Statement

    277. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection and data retention 
requirements imposed by agency rules.\494\ Upon approval of a 
collection(s) of information, OMB will assign an OMB control number and 
an expiration date. Respondents subject to the filing requirements of a 
rule will not be penalized for failing to respond to these collections 
of information unless the collections of information display a valid 
OMB control number.
---------------------------------------------------------------------------

    \494\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------

    278. The Commission is submitting the proposed modifications to its 
information collections to OMB for review and approval in accordance 
with section 3507(d) of the Paperwork

[[Page 73274]]

Reduction Act of 1995.\495\ In the NOPR, the Commission solicited 
comments on the need for this information, whether the information will 
have practical utility, the accuracy of provided burden estimates, ways 
to enhance the quality, utility, and clarity of the information to be 
collected or retained, and any suggested methods for minimizing the 
respondents' burden, including the use of automated information 
techniques. The Commission included a table that listed the estimated 
public reporting burdens for the proposed reporting requirements, as 
well as a projection of the costs of compliance for the reporting 
requirements. The Commission also requested comments on three proposed 
revisions that were not included in the table: (1) The proposed 
revision of the 2 MW threshold for participation in the Fast Track 
Process (the Commission estimated that 100 Interconnection Customers 
annually may participate in the Fast Track Process rather than the 
Study Process under the NOPR); (2), the proposed revision to section 
2.3.2 of the SGIP wherein the Transmission Provider would no longer be 
required to provide a good faith estimate of the cost of performing the 
supplemental review to the Interconnection Customer; and (3) the 
proposal to revise section 1.1.1 of the pro forma SGIP to require that 
if an Interconnection Customer wishes to interconnect its Small 
Generating Facility using Network Resource Interconnection Service, it 
must do so under the LGIP and execute the LGIA.
---------------------------------------------------------------------------

    \495\ 44 U.S.C. 3507(d) (2012).
---------------------------------------------------------------------------

    279. The Commission did not receive any comments specifically 
addressing the burden estimates provided in the NOPR. However, the 
Commission has made changes to its proposal that are adopted in this 
Final Rule. First, the number of conforming changes to the SGIP and 
SGIA have increased (e.g., changes related to the interconnection of 
storage facilities and the pre-application report request form), so we 
have increased the burden estimate in the table below. Second, the 
addition of the pre-application report request form may increase the 
burden on Interconnection Customers requesting a pre-application 
report, so we have increased the burden estimate in the table. Third, 
we added two items to the pre-application report, so we have increased 
the burden estimate for Transmission Providers to prepare the pre-
application report in the table below. Because we did not adopt the 
proposed revision to section 2.3.2 of the SGIP wherein the Transmission 
Provider would no longer be required to provide a good faith estimate 
of the cost of performing the supplemental review to the 
Interconnection Customer, we are not modifying the burden estimate for 
the supplemental review. Further, because we did not receive comments 
on the other proposed revisions discussed above that were not included 
in the table, we are not modifying the burden estimate to account for 
these revisions. The Commission believes that the revised burden 
estimates below are representative of the average burden on 
respondents.
    Burden Estimate: The estimated public reporting burden and cost for 
the requirements contained in this Final Rule follow:
BILLING CODE 6717-01-P

[[Page 73275]]

[GRAPHIC] [TIFF OMITTED] TR05DE13.002


[[Page 73276]]


BILLING CODE 0617-01-C
    Cost to Comply: Total Annual Hours for Collection in initial year 
(14,790 hours) @ $75/hour \499\ = $1,109,250.
---------------------------------------------------------------------------

    \499\ This figure is the average of the salary plus benefits for 
an attorney, consultant (engineer), engineer, and administrative 
staff. The wages are derived from the Bureau of Labor and Statistics 
at http://bls.gov/oes/current/naics3_221000.htm and the benefits 
figure from http://www.bls.gov/news.release/ecec.nr0.htm.
---------------------------------------------------------------------------

    Total Annual Hours for Collection in subsequent years (13,796 
hours) @ $75/hour = $1,034,700.
    Title: FERC-516A, Standardization of Small Generator 
Interconnection Agreements and Procedures.
    Action: Revision of Currently Approved Collection of Information.
    OMB Control No. 1902-0203.
    Respondents for this Rulemaking: Businesses or other for profit 
and/or not-for-profit institutions.
    Frequency of Information: As indicated in the table.
    Necessity of Information: The Commission is adopting these 
amendments to the pro forma SGIP and SGIA in order to more efficiently 
and cost-effectively interconnect generators no larger than 20 MW 
(small generators) to Commission-jurisdictional transmission systems. 
The purpose of this Final Rule is to revise the pro forma SGIP and SGIA 
so small generators can be reliably and efficiently integrated into the 
electric grid and to ensure that Commission-jurisdictional services are 
provided at rates, terms and conditions that are just and reasonable 
and not unduly discriminatory. This Final Rule seeks to achieve this 
goal by amending the pro forma SGIP and SGIA as described previously.
    Internal Review: The Commission has reviewed the proposed changes 
and has determined that the changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has assured itself, by means of internal review, that there 
is specific, objective support for the burden estimates associated with 
the information collection requirements.
    280. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
    281. Comments on the requirements of this rule can be sent to the 
Office of Information and Regulatory Affairs, Office of Management and 
Budget, 725 17th Street NW., Washington, DC 20503 [Attention: Desk 
Officer for the Federal Energy Regulatory Commission]. For security 
reasons, comments to OMB should be submitted by email to: oira_submission@omb.eop.gov. Comments submitted to OMB should include Docket 
No. RM13-2-000 and OMB Control No. 1902-0203.

VII. Environmental Analysis

    282. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\500\ The 
Commission has categorically excluded certain actions from these 
requirements as not having a significant effect on the human 
environment.\501\ The actions proposed here fall within categorical 
exclusions in the Commission's regulations for rules that are 
clarifying, corrective, or procedural, for information gathering, 
analysis, and dissemination, and for sales, exchange, and 
transportation of natural gas that requires no construction of 
facilities.\502\ Therefore, an environmental assessment is unnecessary 
and has not been prepared as part of this Final Rule.
---------------------------------------------------------------------------

    \500\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \501\ 18 CFR 380.4 (2013).
    \502\ See 18 CFR 380.4(a)(2)(ii) (2013).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act Analysis

    283. The Regulatory Flexibility Act of 1980 (RFA) \503\ generally 
requires a description and analysis of Final Rules that will have 
significant economic impact on a substantial number of small entities. 
The Commission estimates that the total number of Transmission 
Providers impacted by this Final Rule that are small entities is 11. 
The Commission estimates that the average total cost for each of these 
entities will be minimal, since most of the cost will be recovered from 
fees paid by Interconnection Customers. The estimated total number of 
Interconnection Customers that may be impacted by the requirements of 
this Final Rule is 800.\504\ Of these, all are considered small. The 
Commission estimates that the total annual cost for each entity is 
$2,055.\505\ The Commission does not consider this to be a significant 
economic impact. Further, the Commission expects that Interconnection 
Customers that are able to participate in the Fast Track Process rather 
than the Study Process will benefit from the proposed revisions to the 
pro forma SGIP.
---------------------------------------------------------------------------

    \503\ 5 U.S.C. 601-612 (2012).
    \504\ We assume that 800 Commission-jurisdictional 
interconnection requests will be made annually. For the purposes of 
this Final Rule, each of these requests is assumed to be made by a 
separate Interconnection Customer.
    \505\ This number is derived by multiplying the hourly figure 
for Interconnection Customers in the Burden Estimate table (1,300) 
plus an additional 750 hours associated with reviewing the draft 
facilities study report by the cost per hour ($75); plus the $300 
fee per pre-application report multiplied by 800 Interconnection 
Customers; plus the cost of the supplemental review (assumed to be 
$2,500) multiplied by 500 Interconnection Customers; all divided by 
the total number of Interconnection Customers (800). ((2,050 hrs * 
$75/hr) + ($300 * 800) + ($2,500 * 500))/800 = $2,055.
---------------------------------------------------------------------------

    284. Based on the above, the Commission certifies that this Final 
Rule will not have a significant economic impact on a substantial 
number of small entities. Accordingly, no regulatory flexibility 
analysis is required.

IX. Document Availability

    285. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    286. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    287. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

X. Effective Date and Congressional Notification

    288. These regulations are effective February 3, 2014. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Act of 1996. The Commission will submit this

[[Page 73277]]

Final Rule to both houses of Congress and the Government Accountability 
Office.
    The Commission orders:

    By the Commission. Chairman Wellinghoff is not participating.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    Note: Appendix A will not be published in the Code of Federal 
Regulations.

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

------------------------------------------------------------------------
    Short name or acronym                      Commenter
------------------------------------------------------------------------
AWEA.........................  American Wind Energy Association.
Bonneville...................  Bonneville Power Administration.
CAISO........................  California Independent System Operator
                                Corporation.
California Utilities.........  San Diego Gas & Electric Company,
                                Southern California Edison Company and
                                Pacific Gas and Electric Company.
CEP..........................  ClearEdge Power.
Clean Coalition..............  Clean Coalition.
ComRent......................  ComRent International.
CPUC.........................  California Public Utilities Commission.
CREA.........................  Community Renewable Energy Association.
DCOPC........................  Office of the People's Counsel for the
                                District of Columbia.
Duke Energy..................  Duke Energy Corporation.
Duquesne Light...............  Duquesne Light.
ELCON........................  Electricity Consumers Resource Council,
                                American Chemistry Council, American
                                Forest & Paper Association, American
                                Iron and Steel Institute, CHP
                                Association and Council of Industrial
                                Boiler Owners.
ESA..........................  Electricity Storage Association.
FCHEA........................  Fuel Cell & Hydrogen Energy Association.
IECA.........................  Industrial Energy Consumers of America.
IREC.........................  Interstate Renewable Energy Council.
IRC..........................  ISO/RTO Council.
ISO-NE.......................  ISO New England.
ITC..........................  International Transmission Company.
LES..........................  Landfill Energy Systems.
Lucia Villaran...............  Lucia Villaran.
Max Hensley..................  Max Hensley.
MISO.........................  Midcontinent Independent System Operator.
NARUC........................  National Association of Regulatory
                                Utility Commissioners.
NRECA, EEI & APPA............  National Rural Electric Cooperative
                                Association, Edison Electric Institute
                                and American Public Power Association.
NREL.........................  National Renewable Energy Laboratory.
NRG Companies................  NRG Companies.
NYISO & NYTO.................  New York Independent System Operator and
                                New York Transmission Owners.
Pepco........................  Pepco Holdings Inc., Atlantic City
                                Electric Company, Delmarva Power & Light
                                Company and Potomac Electric Power
                                Company.
PJM..........................  PJM Interconnection, LLC.
Public Interest Organizations  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.
Sandia.......................  Sandia National Laboratories.
SEIA.........................  Solar Energy Industries Association.
UCS..........................  Union of Concerned Scientists.
VSI..........................  Vote Solar Initiative.
------------------------------------------------------------------------


    Note: Appendix B will not be published in the Code of Federal 
Regulations.


[[Page 73278]]



Appendix B

BILLING CODE 6717-01-P
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Appendix C: Revisions to the Pro Forma SGIP
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    Note:  Appendix D will not appear in the Code of Federal 
Regulations.

Appendix D: Revisions to the Pro Forma SGIA

------------------------------------------------------------------------
          Section number                          Revision
------------------------------------------------------------------------
3.3.5 (Termination)...............  Replace the first word of the
                                     section (``This'') with ``The''.
Attachment 1 (Glossary of Terms)..  Revise the definition of Small
                                     Generating Facility as follows:
                                     Small Generating Facility--The
                                     Interconnection Customer's device
                                     for the production and/or storage
                                     for later injection of electricity
                                     identified in the Interconnection
                                     Request, but shall not include the
                                     Interconnection Customer's
                                     Interconnection Facilities.
------------------------------------------------------------------------

[FR Doc. 2013-28515 Filed 12-4-13; 8:45 am]
BILLING CODE 6717-01-C


