UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

\[Docket No. RM02-12-000; Order No. 2006\]

Standardization of Small Generator Interconnection Agreements and
Procedures

(Issued May 12, 2005)

[AGENCY]{.underline}: Federal Energy Regulatory Commission.

[ACTION]{.underline}: Final Rule

[SUMMARY]{.underline}: The Federal Energy Regulatory Commission
(Commission) is amending its regulations under the Federal Power Act to
require public utilities that own, control, or operate facilities for
transmitting electric energy in interstate commerce to amend their open
access transmission tariffs to include standard generator
interconnection procedures and an agreement that the Commission is
adopting in this order and to provide interconnection service to devices
used for the production of electricity having a capacity of no more than
20 megawatts. A non-public utility that seeks voluntary compliance with
the reciprocity condition of an open access transmission tariff may
satisfy this condition by adopting these procedures and agreement.

[EFFECTIVE DATE]{.underline}: This Final Rule will become effective
\[insert date that is 60 days after publication in the [FEDERAL
REGISTER]{.underline}.\]

[FOR FURTHER INFORMATION CONTACT]{.underline}:

Kumar Agarwal (Technical Information)

Office of Market, Tariffs and Rates

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

\(202\) 502-8923

Bruce Poole (Technical Information)

Office of Market, Tariffs and Rates

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

\(202\) 502-8468

Kirk Randall (Technical Information)

Office of Market, Tariffs and Rates

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

\(202\) 502-8092

Patrick Rooney (Technical Information)

Office of Market, Tariffs and Rates

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

\(202\) 502-6205

Abraham Silverman (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

\(202\) 502-6444

[SUPPLEMENTARY INFORMATION]{.underline}:

**TABLE OF CONTENTS**

Page No.

[**I.** **INTRODUCTION** - 1 -](#__RefHeading___Toc103479253)

[**A.** **Background** - 6 -](#__RefHeading___Toc103479254)

[**B.** **Need for a Standard Generator Interconnection Procedures and
Agreement** - 7 -](#__RefHeading___Toc103479255)

[**C.** **The Large and Small Generator Interconnection Rulemaking
Proceedings** - 8 -](#__RefHeading___Toc103479256)

[**II.** **DISCUSSION** - 13 -](#__RefHeading___Toc103479257)

[**A.** **Descriptions of the SGIP and SGIA** - 14
-](#__RefHeading___Toc103479258)

[**B.** **Overview of the Interconnection Process for Small Generating
Facilities** - 17 -](#__RefHeading___Toc103479259)

[**C.** **Issues Related to Both the SGIP and the SGIA** - 19
-](#__RefHeading___Toc103479260)

[Consistency between the Large Generator and Small Generator\
Documents - 20 -](#__RefHeading___Toc103479261)

[Definitions of Terms Used in the SGIP and SGIA - 23
-](#__RefHeading___Toc103479262)

[Emergency Condition - 23 -](#__RefHeading___Toc103479263)

[Network Upgrades - 24 -](#__RefHeading___Toc103479264)

[Use of Calendar Days v. Business Days - 24
-](#__RefHeading___Toc103479265)

[Maximum Size of a Small Generating Facility - 25
-](#__RefHeading___Toc103479266)

[Revising the Maximum Size of a Small Generating Facility - 25
-](#__RefHeading___Toc103479267)

[Increasing the Capacity of an Existing Small Generating\
Facility - 27 -](#__RefHeading___Toc103479268)

[Evaluating the Generating Facility Based on Less Than Its Maximum Rated
Capacity - 28 -](#__RefHeading___Toc103479269)

[Evaluating Small Generating Facilities with Multiple Points\
of Interconnection - 30 -](#__RefHeading___Toc103479270)

[Dispute Resolution - 31 -](#__RefHeading___Toc103479271)

[Confidentiality - 34 -](#__RefHeading___Toc103479272)

[Keeping the Small Generator Interconnection Rules Current - 36
-](#__RefHeading___Toc103479273)

[**D.** **Issues Related to the Interconnection Request** - 37
-](#__RefHeading___Toc103479274)

[Processing Fees and Study Deposits - 37
-](#__RefHeading___Toc103479275)

[Receipt Confirmation and Requests for Additional Data - 40
-](#__RefHeading___Toc103479276)

[Interconnection Products and Service Options - 40
-](#__RefHeading___Toc103479277)

[Ministerial Changes to the Interconnection Request - 44
-](#__RefHeading___Toc103479278)

[**E.** **Issues Related to the SGIP** - 44
-](#__RefHeading___Toc103479279)

[Using Voltage Level to Determine Which Procedures to Apply - 44
-](#__RefHeading___Toc103479280)

[Certification of the Small Generating Facility (Proposed SGIP\
Section 3.1) - 46 -](#__RefHeading___Toc103479281)

[Super-Expedited Procedures (Proposed SGIP Section 3) and\
Expedited Procedures (Proposed SGIP Section 4.3) - 48
-](#__RefHeading___Toc103479282)

[Queuing Priority (Proposed SGIP Section 4.4) - 52
-](#__RefHeading___Toc103479283)

[Scoping Meeting (Proposed SGIP Section 4.5) - 54
-](#__RefHeading___Toc103479284)

[Interconnection Studies (Proposed SGIP Sections 4.6, 4.7, and 4.8) - 55
-](#__RefHeading___Toc103479285)

[Study Cost Obligations - 55 -](#__RefHeading___Toc103479286)

[Study Requirements - 55 -](#__RefHeading___Toc103479287)

[Study Deadlines - 56 -](#__RefHeading___Toc103479288)

[Post Operational Evaluation of the Interconnection - 57
-](#__RefHeading___Toc103479289)

[Execution of the SGIA - 57 -](#__RefHeading___Toc103479290)

[**F.** **Issues Related to the SGIA** - 58
-](#__RefHeading___Toc103479291)

[Responsibilities of the Parties (Proposed SGIA Article 2.2) - 58
-](#__RefHeading___Toc103479292)

[Metering (Proposed SGIA Article 2.4) - 62
-](#__RefHeading___Toc103479293)

[Equipment Testing and Inspection (Proposed SGIA Article 3.1) - 62
-](#__RefHeading___Toc103479294)

[Right of Access (Proposed SGIA Article 3.3) - 63
-](#__RefHeading___Toc103479295)

[Term of Agreement (Proposed SGIA Article 4.2) - 64
-](#__RefHeading___Toc103479296)

[Termination (Proposed SGIA Article 4.3) and Default (Proposed\
SGIA Article 6.17) - 65 -](#__RefHeading___Toc103479297)

[Emergency Conditions (Proposed SGIA Article 4.4.1) - 67
-](#__RefHeading___Toc103479298)

[Temporary Disconnection -- Routine Maintenance, Construction, and
Repair (Proposed SGIA Article 4.4.2) and Forced Outages (Proposed\
SGIA Article 4.4.3) - 68 -](#__RefHeading___Toc103479299)

[Temporary Disconnection -- Adverse Operating Effects (Proposed\
SGIA Article 4.4.4) - 69 -](#__RefHeading___Toc103479300)

[Temporary Disconnection -- Modification of the Generating Facility
(Proposed SGIA Article 4.4.5) - 71 -](#__RefHeading___Toc103479301)

[Temporary Disconnection -- Reconnection (Proposed SGIA Article\
4.4.6) - 71 -](#__RefHeading___Toc103479302)

[Financial Security Arrangements (Proposed SGIA Article 5.2) - 72
-](#__RefHeading___Toc103479303)

[Milestones (Proposed SGIA Article 5.3) - 75
-](#__RefHeading___Toc103479304)

[Billing and Payment (Proposed SGIA Article 5.4) - 76
-](#__RefHeading___Toc103479305)

[Billing Procedure for Interconnection Facilities Construction\
(Proposed SGIA Article 5.4.1) and Final Accounting (Proposed\
SGIA Article 5.4.2) - 77 -](#__RefHeading___Toc103479306)

[Assignment (Proposed SGIA Article 6.5) - 78
-](#__RefHeading___Toc103479307)

[Insurance (Proposed SGIA Article 6.16) - 80
-](#__RefHeading___Toc103479308)

[Reservation of Rights (Proposed SGIA Article 6.20) - 88
-](#__RefHeading___Toc103479309)

[Signatures and Parties to the SGIA (Proposed SGIA Article 9) - 88
-](#__RefHeading___Toc103479310)

[Liability - 91 -](#__RefHeading___Toc103479311)

[General Approach - 92 -](#__RefHeading___Toc103479312)

[Consequential Damages (Proposed SGIA Article 6.19) - 94
-](#__RefHeading___Toc103479313)

[Indemnity (Proposed SGIA Article 6.13) - 95
-](#__RefHeading___Toc103479314)

[Force Majeure (Proposed SGIA Article 6.14) - 98
-](#__RefHeading___Toc103479315)

[Reactive Power - 99 -](#__RefHeading___Toc103479316)

[Generator Balancing Requirements - 100 -](#__RefHeading___Toc103479317)

[Appendices to the SGIA - 101 -](#__RefHeading___Toc103479318)

[**G.** **The 10 kW Inverter Process** - 101
-](#__RefHeading___Toc103479319)

[**H.** **Other Significant Issues** - 104
-](#__RefHeading___Toc103479320)

[Pricing/Cost Recovery for Interconnection Facilities and Upgrades
(Proposed SGIA Article 5.1) - 105 -](#__RefHeading___Toc103479321)

[Pricing Comments that the Commission Already Addressed\
in the Large Generator Interconnection Proceeding - 107
-](#__RefHeading___Toc103479322)

[Applicability of the Commission\'s Interconnection Pricing\
Policy to the Interconnection of Small Generating Facilities - 108
-](#__RefHeading___Toc103479323)

[Implementation of the Interconnection Pricing Policy for\
Small Generating Facilities - 112 -](#__RefHeading___Toc103479324)

[Responsibility for Operation and Maintenance Costs - 117
-](#__RefHeading___Toc103479325)

[Responsibility for the Construction of Upgrades - 119
-](#__RefHeading___Toc103479326)

[Miscellaneous Pricing Issues - 120 -](#__RefHeading___Toc103479327)

[Commission Jurisdiction under the Federal Power Act - 121
-](#__RefHeading___Toc103479328)

[Arguments that the Commission Should Delay or Abandon the\
Small Generator Interconnection Rulemaking - 129
-](#__RefHeading___Toc103479329)

[Arguments in Favor of Deferring to the States on Small\
Generator Interconnections - 129 -](#__RefHeading___Toc103479330)

[Arguments that the NOPR Is Too Complex - 132
-](#__RefHeading___Toc103479331)

[Arguments in Favor of a Non-Binding Model Rule - 134
-](#__RefHeading___Toc103479332)

[Issues Relating to Qualifying Facilities - 134
-](#__RefHeading___Toc103479333)

[Taxes - 136 -](#__RefHeading___Toc103479334)

[OATT Reciprocity Requirements - 140 -](#__RefHeading___Toc103479335)

[Coordination with Affected Systems - 141
-](#__RefHeading___Toc103479336)

[**I.** **Compliance Issues** - 142 -](#__RefHeading___Toc103479337)

[Amendments to the Transmission Provider\'s OATT - 143
-](#__RefHeading___Toc103479338)

[Variations from the Final Rule - 143 -](#__RefHeading___Toc103479339)

[Interconnection Requests Submitted Prior to the Effective Date of\
this Final Rule and Grandfathering of Existing Interconnection\
Agreements - 145 -](#__RefHeading___Toc103479340)

[Order No. 2001 and the Filing of Interconnection Agreements - 148
-](#__RefHeading___Toc103479341)

[**III.** **INFORMATION COLLECTION STATEMENT** - 149
-](#__RefHeading___Toc103479342)

[**IV.** **ENVIRONMENTAL IMPACT STATEMENT** - 153
-](#__RefHeading___Toc103479343)

[**V.** **REGULATORY FLEXIBILITY ACT** - 154
-](#__RefHeading___Toc103479344)

[**VI.** **DOCUMENT AVAILABILITY** - 156
-](#__RefHeading___Toc103479345)

[**VII.** **EFFECTIVE DATE AND CONGRESSIONAL NOTIFICATION** - 157
-](#__RefHeading___Toc103479346)

**REGULATORY TEXT**

[Appendix A](#AppendixA) -- Commenter Acronyms

[Appendix B](#appendixb) -- Flow Chart for Interconnecting a Small
Generating Facility Using the \"Study Process\"

[Appendix C](#appendixc) -- Flow Chart for Interconnecting a Certified
Small Generating Facility No Larger than 2 MW Using the \"Fast Track
Process\"

[Appendix D](#appendixd) -- Flow Chart for Interconnecting a Certified
Inverter-Based Small Generating Facility No Larger than 10 kW Using the
\"10 kW Inverter Process\"

[Appendix E]{.underline} -- Small Generator Interconnection Procedures
(SGIP)

[Appendix F]{.underline} -- Small Generator Interconnection Agreement
(SGIA)

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Pat Wood, III, Chairman;

Nora Mead Brownell, Joseph T. Kelliher,

and Suedeen G. Kelly.

Standardization of Small Generator

Interconnection Agreements and Procedures Docket No. RM02-12-000

ORDER NO. 2006

FINAL RULE

(Issued May 12, 2005)

**I. Introduction**[]{#__RefHeading___Toc103479253 .anchor}

1.  This Final Rule requires all public utilities[^1] to adopt standard
    rules for interconnecting new sources of electricity no larger than
    20 megawatts (MW). It continues the process begun in Order No. 2003
    of standardizing the terms and conditions of interconnection service
    for Interconnection Customers of all sizes.[^2] It will reduce
    interconnection time and costs for Interconnection Customers and
    Transmission Providers,[^3] preserve reliability, increase energy
    supply, lower wholesale prices for customers by increasing the
    number and types of new generation that will compete in the
    wholesale electricity market, facilitate development of
    non-polluting alternative energy sources, and help remedy undue
    discrimination, as sections 205 and 206 of the FPA require.[^4]
    Public utilities must amend[^5] their open access transmission
    tariffs (OATTs) to include a Small Generator Interconnection
    Procedures document (SGIP -- Appendix E to this Preamble) and a
    Small Generator Interconnection Agreement (SGIA -- Appendix F to
    this Preamble).

2.  The SGIP contains the technical procedures the Interconnection
    Customer and Transmission Provider (the Parties) must follow once
    the Interconnection Customer requests interconnection of its Small
    Generating Facility. It provides three ways to evaluate the
    Interconnection Request. They are the default Study Process that
    could be used by any Small Generating Facility, and two procedures
    that use technical screens to evaluate proposed
    interconnections: (1) the Fast Track Process for a certified Small
    Generating Facility no larger than 2 MW[^6] and (2) the 10 kW
    Inverter Process for a certified inverter-based Small Generating
    Facility no larger than 10 kW.[^7] All three are designed to ensure
    that the proposed interconnection will not endanger the safety and
    reliability of the Transmission Provider\'s Transmission System.

3.  The SGIA contains contractual provisions appropriate for the
    interconnection of a Small Generating Facility, including provisions
    for the payment for modifications made to the Transmission
    Provider\'s Transmission System to accommodate the interconnection.
    The SGIA is signed by the Parties after they have successfully
    completed the evaluation of a proposed interconnection under the
    SGIP Study Process or Fast Track Process. The SGIA does not apply to
    requests to interconnect submitted under the 10 kW Inverter Process,
    however, which uses a simplified all-in-one application
    form/procedures/terms and conditions document that is included in
    SGIP Attachment 5.

4.  We conclude that general consistency between the Commission\'s
    interconnection procedures document and interconnection agreement
    adopted in this Final Rule and those of the states will be helpful
    to removing roadblocks to the interconnection of Small Generating
    Facilities. To a large extent, this Final Rule harmonizes state and
    federal practices by adopting many of the best practices
    interconnection rules recommended by the National Association of
    Regulatory Utility Commissioners (NARUC). By doing so, we hope to
    minimize the federal-state division and promote consistent,
    nationwide interconnection rules. We hope that states that do not
    currently have interconnection rules for small generators will look
    to the documents presented in this Final Rule and NARUC as guides
    for their own. In particular, the \"Fast Track Process\" and the
    \"10 kW Inverter Process\" should go a long way towards harmonizing
    state-federal interconnection practices.

5.  Finally, the application of this Final Rule is the same as with
    Order No. 2003 for Large Generating Facilities. Specifically, this
    Final Rule applies only to interconnections with facilities that are
    already subject to the Transmission Provider\'s OATT at the time the
    Interconnection Request is made.

6.  The SGIP and SGIA include separate definitions for \"Transmission
    System\" and \"Distribution System\" to account for the distinct
    engineering and cost allocation implications of an interconnection
    with a Distribution System. The SGIP and SGIA, like Order No. 2003,
    define \"Transmission System\" as \"\[t\]he facilities owned,
    controlled or operated by the Transmission Provider or the
    Transmission Owner that are used to provide transmission service
    under the Tariff.\" Any interconnection with a Transmission System
    (under an OATT) by a Small Generating Facility is subject to this
    Final Rule.

7.  The SGIP and the SGIA, like Order No. 2003, also use the term
    \"Distribution System.\" \"Distribution System\" is defined as
    \"\[t\]he Transmission Provider\'s facilities and equipment used to
    transmit electricity to ultimate usage points such as homes and
    industries directly from nearby generators or from interchanges with
    higher voltage transmission networks which transport bulk power over
    longer distances. The voltage levels at which Distribution Systems
    operate differ among areas.\" If a Small Generating Facility
    proposes to interconnect with a portion of the Distribution System
    subject to an OATT for the purpose of making wholesale sales, then
    this Final Rule would apply.[^8] However, an interconnection to a
    portion of a Distribution System that is not already subject to an
    OATT would not be subject to this Final Rule.

8.  \"Distribution\" is a vague term, usually used to refer to
    non-networked, often lower-voltage facilities, that carry power in
    one direction. Commission-jurisdictional facilities with these
    characteristics are referred to as \"Distribution Systems subject to
    an OATT\" throughout this Final Rule. This Final Rule\'s use of the
    term \"Distribution System\" has nothing to do with whether the
    facility is under this Commission\'s jurisdiction; some
    \"distribution\" facilities are under our jurisdiction and others
    are \"local distribution facilities\" subject to state
    jurisdiction.[^9]  This Final Rule does not violate the FPA section
    201(b)(1) provision that the Commission does not have jurisdiction
    over local distribution facilities "except as specifically provided.
    . ."[^10] This is because the Final Rule applies only to
    interconnections to facilities that are already subject to a
    jurisdictional OATT at the time the interconnection request is made
    and that will be used for purposes of jurisdictional wholesale
    sales.  Because of the limited applicability of this Final Rule, and
    because the majority of small generators interconnect with
    facilities that are not subject to an OATT, this Final Rule will not
    apply to most small generator interconnections. Nonetheless, our
    hope is that states may find this rule helpful in formulating their
    own interconnection rules.

**A. Background**[]{#__RefHeading___Toc103479254 .anchor}

9.  This Final Rule responds 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,
    advances in technology have created a burgeoning market for small
    power plants that may offer economic, reliability, or environmental
    benefits.

10. With these developments in mind, the Commission continues in this
    rulemaking to work to encourage fully competitive bulk power
    markets. The effort took its first significant step with Order No.
    888,[^11] which required public utilities to provide other entities
    comparable access to their Transmission Systems. The effort
    continued with Order No. 2000,[^12] which began the process of
    developing Regional Transmission Organizations (RTOs). Most
    recently, the Commission established a standard Large Generator
    Interconnection Procedures document (LGIP) and a standard Large
    Generator Interconnection Agreement (LGIA) for generating facilities
    larger than 20 MW.[^13]

11. The Commission, pursuant to its responsibility under sections 205
    and 206 of the FPA to remedy undue discrimination, is requiring all
    public utilities that own, control, or operate facilities for
    transmitting electric energy in interstate commerce to append to
    their OATTs the SGIP and SGIA we are adopting in this Final Rule.
    These documents provide just and reasonable terms and conditions of
    interconnection service. They also strike a reasonable balance
    between the competing goals of uniformity and flexibility while
    ensuring safety and reliability are protected.

    **B. Need for a Standard Generator Interconnection Procedures and
    Agreement**[]{#__RefHeading___Toc103479255 .anchor}

12. In fulfilling its responsibilities under sections 205 and 206 of the
    FPA, the Commission is required to remedy undue discrimination. The
    Commission must also ensure that the rates, contracts, and practices
    affecting jurisdictional transmission service do not reflect an
    undue preference or advantage for Transmission Providers and their
    affiliates and are just and reasonable. The Commission\'s regulatory
    authority under the FPA \"clearly carries with it the responsibility
    to consider, in appropriate circumstances, the anticompetitive
    effects of regulated aspects of interstate utility operations. . .
    .\"[^14]

13. The record underlying Order No. 888 showed that public utilities
    owning or controlling jurisdictional transmission facilities had the
    incentive to engage in, and had engaged in, unduly discriminatory
    transmission practices.[^15] The Commission in Order No. 888
    thoroughly discussed the legislative history and case law involving
    sections 205 and 206, concluded that it has the authority and
    responsibility to remedy the undue discrimination it found by
    requiring open access, and decided to do so through a rulemaking on
    a generic, industry-wide basis.[^16] The Supreme Court affirmed the
    Commission\'s decision to exercise this authority by requiring
    non-discriminatory (comparable) open access as a remedy for undue
    discrimination.[^17] However, Order No. 888 did not specifically
    address interconnection service.[^18]

14. In [Tennessee Power]{.underline},[^19] the Commission clarified that
    interconnection is a critical component of open access transmission
    service and thus is subject to the requirement that utilities offer
    comparable service under the OATT. The Commission encouraged, but
    did not require, each Transmission Provider to revise its OATT to
    include interconnection procedures, including a standard
    interconnection agreement and specific criteria, procedures,
    milestones, and timelines for evaluating applications for
    interconnection.[^20]

15. As discussed in Order No. 2003, interconnection is a critical
    component of transmission service, and having a standard
    interconnection procedures and a standard agreement applicable to
    Small Generating Facilities will (1) limit opportunities for
    transmitting utilities to favor their own generation, (2) remove
    unfair impediments to market entry for small generators by reducing
    interconnection costs and time, and (3) encourage investment in
    generation and transmission infrastructure, where needed.[^21] We
    expect the SGIP and SGIA adopted here will resolve most disputes,
    minimize opportunities for undue discrimination, foster increased
    development of economic Small Generating Facilities, and protect
    system reliability.

    **C. The Large and Small Generator Interconnection Rulemaking
    Proceedings**[]{#__RefHeading___Toc103479256 .anchor}

16. In the Advance Notice of Proposed Rulemaking (ANOPR) issued in
    Docket No. RM02-1-000, the Commission initiated a collaborative
    process where members of the public, electric industry participants,
    and federal and state agencies (collectively, stakeholders) were
    invited to draft proposed generator interconnection procedures and a
    generator interconnection agreement.[^22] The stakeholders filed
    their consensus documents in January 2002. The Commission then
    issued a Notice of Proposed Rulemaking (Large Generator
    Interconnection NOPR)[^23] proposing standard interconnection
    procedures and a standard interconnection agreement that generally
    followed the consensus documents. The Large Generator
    Interconnection NOPR also proposed solutions to issues left
    unresolved in the consensus documents.

17. Although the Large Generator Interconnection NOPR provided special
    treatment for Small Generating Facilities, some commenters urged the
    Commission to initiate a separate proceeding to develop standard
    interconnection procedures and agreements that addressed the unique
    concerns of Small Generating Facilities.[^24] They proposed one set
    of simplified interconnection rules for Small Generating Facilities
    no larger than 2 MW, and another for facilities larger than 2 MW but
    no larger than 20 MW. Persuaded that different procedures and
    agreements were indeed needed, the Commission severed Small
    Generating Facilities from the Large Generator Interconnection
    proceeding and issued a Small Generator Interconnection Advance
    Notice of Proposed Rulemaking (ANOPR) in August 2002.[^25] The Small
    Generator Interconnection ANOPR proposed two SGIPs and two SGIAs
    (ANOPR SGIPs and SGIAs) using 2 MW as a breakpoint. It encouraged
    stakeholders to pursue consensus on the ANOPR SGIPs and SGIAs. To
    that end, the Commission convened a series of public meetings
    designed to enable them to discuss and reach as much consensus as
    possible.

18. The negotiating parties, who we refer to collectively as Joint
    Commenters, then filed SGIPs and SGIAs (Joint Commenters\' SGIPs and
    SGIAs) with the Commission.[^26] While Joint Commenters reached
    consensus on some issues, many remained unresolved. Joint
    Commenters\' SGIPs included two procedures for evaluating whether a
    proposed Small Generating Facility could be interconnected safely
    and without degrading reliability. The first was a standard Study
    Process that used a scoping meeting and three technical studies to
    evaluate a proposed interconnection. The second was a streamlined
    procedure that used technical screens to identify those proposed
    interconnections that clearly would not jeopardize the safety and
    reliability of the Transmission Provider\'s electric system. Public
    comments on the Small Generator Interconnection ANOPR were filed
    shortly thereafter.

19. In July 2003, the Commission issued Order No. 2003, which
    established standard procedures and an interconnection agreement for
    the interconnection of large generators and explained the
    Commission\'s jurisdiction over interconnections. The Commission
    simultaneously issued the Small Generator Interconnection NOPR.[^27]
    Certain provisions in the Large Generator Interconnection Final Rule
    as well as Joint Commenters\' SGIPs/SGIAs influenced the Small
    Generator Interconnection NOPR.[^28] The Commission asked commenters
    to address whether Small Generating Facilities should be treated
    differently from Large Generating Facilities under the LGIP and LGIA
    adopted in Order No. 2003.

20. Sixty-five entities submitted initial comments in response to the
    Small Generator Interconnection NOPR. The comments generally support
    the Commission\'s effort to remove barriers to the development of
    Small Generating Facilities. Following the issuance of the Small
    Generator Interconnection NOPR and the initial comment due date,
    NARUC in October 2003 updated its own interconnection procedures and
    agreement, referred to here as the NARUC Model. NARUC stated that
    the NARUC Model is based on the best practices of the state
    regulatory agencies that have interconnection procedures for small
    generators. NARUC encouraged state regulators to use the NARUC Model
    as a basis for developing their interconnection procedures and
    suggested that the Commission\'s documents reflect these \"best
    practices.\" On July 7, 2004, the Commission staff added to the
    record in this proceeding the latest version of the NARUC
    Model.[^29] A few commenters favor terminating this proceeding or,
    in the alternative, adopting the NARUC Model.

21. The Commission then issued a Notice of Request for Supplemental
    Comments, observing that the small generator industry had continued
    to evolve since the Commission first received comments in this
    proceeding.[^30] In the notice, the Commission observed that several
    states had recently adopted new guidelines for small generator
    interconnections, and that the stakeholders who participated in the
    Commission\'s ANOPR process were continuing to work toward resolving
    various SGIP and SGIA issues. The Commission invited joint
    supplemental comments describing new consensus positions but
    discouraged resubmissions of prior positions.

22. Joint Commenters, which as noted above represents a diverse group of
    small generator interests, Transmission Providers, and state
    regulators who participated in the ANOPR process, was the only group
    to file a consensus position. Some Joint Commenters -- Small
    Generator Coalition, NRECA, and NARUC -- filed their own
    supplemental comments as well. Ten other entities (mostly state
    regulatory commissions[^31]) submitted supplemental comments.[^32]

23. In its supplemental comments, Joint Commenters endorsed a single
    SGIP and single SGIA for Small Generating Facilities no larger than
    20 MW. Joint Commenters recommended several revised provisions in
    areas where they had not been able to reach consensus during the
    ANOPR process. These included dispute resolution, confidentiality,
    insurance, equipment certification, and technical screens, among
    others. Joint Commenters, which includes NARUC, also endorsed a
    greatly simplified all-in-one application form/procedures/terms and
    conditions document for the interconnection of certified
    inverter-based Small Generating Facilities no larger than 10 kW.

24. In Order No. 2003-A, the Commission determined that the LGIP and
    LGIA were designed around the needs of traditional synchronous
    technology generators and that generators relying on non-synchronous
    technologies, such as wind plants, may find that a specific
    requirement is inapplicable or that a different approach is
    needed.[^33] Accordingly, the Commission added a blank Appendix G
    (Requirements of Generators Relying on Non-Synchronous Technologies)
    to the LGIA as a placeholder for requirements specific to
    non-synchronous technologies.[^34] At a September 24, 2004 technical
    conference on the interconnection requirements of non-synchronous
    technologies, panelists were asked whether Appendix G type
    requirements should apply to Small Generating Facilities. They
    responded that special capabilities, such as low voltage
    ride-through, simply were not needed for any Small Generating
    Facility, whether wind powered or not. As a result, the Wind NOPR
    issued shortly thereafter applies only to the interconnection of
    wind powered generators 20 MW or larger.[^35] In its supplemental
    comments, National Grid asks the Commission to implement standards
    for Small Generating Facilities that are similar to those proposed
    for Large Generating Facilities in the Wind NOPR. This Final Rule
    does not include such standards. The wind generating facilities that
    will interconnect under this Final Rule will be small and will have
    minimal impact on the Transmission Provider's electric system. The
    reliability requirements proposed for wind powered Large Generating
    Facilities are not needed for small wind generating facilities.

25. In crafting this Final Rule, we considered all of the comments
    received throughout the course of this proceeding, including the
    initial documents submitted by Joint Commenters in response to the
    ANOPR, the Small Generator Interconnection NOPR and the comments
    filed in response, the NARUC Model, and the supplemental comments.
    We considered all comments filed in response to the Small Generator
    Interconnection NOPR before April 29, 2005, and they are part of the
    record in this proceeding.[^36]

    **II. DISCUSSION**[]{#__RefHeading___Toc103479257 .anchor}

26. Part A of this discussion (Descriptions of the SGIP and SGIA)
    describes in general terms the interconnection procedures document
    (SGIP) and interconnection agreement (SGIA) we are adopting in this
    Final Rule.

27. Part B (Overview of the Interconnection Process for Small Generating
    Facilities) describes the processes that the Interconnection
    Customer and the Transmission Provider must follow to interconnect
    the Small Generating Facility with the Transmission Provider\'s
    Transmission System.

28. Part C (Issues Related to Both the SGIP and the SGIA) addresses
    issues that are common to the interconnection procedures and
    agreement documents.

29. Part D (Issues Related to the Interconnection Request) addresses
    issues related to the Interconnection Request (application form)
    that the Interconnection Customer submits to the Transmission
    Provider to request interconnection of its Small Generating
    Facility.

30. Part E (Issues Related to the SGIP) addresses issues related only to
    the interconnection procedures document.

31. Part F (Issues Related to the SGIA) addresses issues related only to
    the interconnection agreement.

32. Part G (The 10kW Inverter Process) describes the simplified
    all-in-one application form/procedures/terms and conditions document
    for the interconnection of certified inverter-based Small Generating
    Facilities no larger than 10 kW.

33. Part H (Other Significant Issues) addresses the pricing of
    Interconnection Facilities and Upgrades, jurisdictional issues,
    variations from the Final Rule, the availability of waivers for
    small entities, the effect of this Final Rule on the OATT
    reciprocity provisions, and others.

34. Finally, Part I (Compliance Issues) addresses issues pertaining to
    the requirement that a Transmission Provider file conforming
    amendments to its existing OATT, the treatment to be accorded to
    existing interconnection agreements (grandfathering), and how a
    Transmission Provider is to file executed and unexecuted
    interconnection agreements.

    **A. Descriptions of the SGIP and
    SGIA**[]{#__RefHeading___Toc103479258 .anchor}

35. In Order No. 2003, the Commission adopted two documents that are to
    be used for the interconnection of Large Generating Facilities --
    the Large Generator Interconnection Procedures document and the
    Large Generator Interconnection Agreement. The LGIP describes how
    the Interconnection Customer\'s Interconnection Request (i.e.,
    application) is to be evaluated from an engineering perspective
    using a four-step process. These are the scoping meeting, the
    feasibility study, the system impact study, and the facilities
    study. The purpose of the evaluation is to determine the impact the
    proposed interconnection will have on the Transmission Provider\'s
    electric system and identify new equipment and modifications needed
    to accommodate the interconnection. The LGIA, which is signed after
    the proposed interconnection has been successfully evaluated using

    the provisions contained in the LGIP, describes the legal
    relationships of the Parties, including who pays for equipment
    modifications to the Transmission Provider\'s electric system.

36. The SGIP and SGIA we adopt in this Final Rule serve the same
    purposes as the LGIP and LGIA. The SGIP includes the same four-step
    process for evaluating an Interconnection Request as does the LGIP,
    except that it is simplified in several aspects and includes
    timelines to accelerate the interconnection of Small Generating
    Facilities. In the SGIP, this procedure is termed the \"Study
    Process.\" The SGIP also includes special procedures for evaluating
    two subgroups of Small Generating Facilities, (1) a \"Fast Track
    Process\" that uses technical screens to evaluate a certified Small
    Generating Facility no larger than 2 MW, and (2) a \"10 kW Inverter
    Process\" that uses the same technical screens to evaluate a
    certified inverter-based Small Generating Facility no larger than 10
    kW. The SGIA serves the same purpose for the interconnection of a
    Small Generating Facility as the LGIA does for a Large Generating
    Facility. It describes the legal relationships of the Parties,
    including who will pay for equipment modifications to the
    Transmission Provider\'s electric system.

37. The Commission received many comments proposing modifications to the
    Proposed SGIP and Proposed SGIA, which helped greatly to shape this
    Final Rule. NARUC argued that the Commission should adopt portions
    of its Model to harmonize federal interconnection rules with those
    found in states with interconnection rules. Small Generator
    Coalition recommended that the Commission in this proceeding adopt
    the NARUC Model instead of the Proposed SGIP and Proposed SGIA. Some
    of the provisions proposed by Joint Commenters (which includes NARUC
    representation) in its supplemental comments also followed the NARUC
    Model. We are adopting in this Final Rule many of these consensus
    provisions as well as those proposed by NARUC because they are just
    and reasonable and serve the twin goals of removing barriers to the
    development of small generation while preserving the safety and
    reliability of the nation\'s electric system.

38. The SGIP, while relying heavily on NARUC\'s and Joint Commenters\'
    proposals, is not a significant departure from the Proposed SGIP.
    Both use nearly identical interconnection study processes (\"Study
    Process\") to evaluate Interconnection Requests that do not qualify
    for special handling. Regarding special handling, both use technical
    screens to identify Small Generating Facilities no larger than 2 MW
    that can be interconnected with no adverse impact on safety or
    reliability. The SGIP we adopt in this Final Rule, however, includes
    two such special procedures, the Fast Track Process and the 10 kW
    Process. The choice of which one the Interconnection Customer may
    use depends on the size and technology of the Small Generating
    Facility. The SGIP also includes the Interconnection Request
    (application form) that is to be used by all Interconnection
    Customers except those eligible to use the 10 kW Process, and
    feasibility study, system impact study, and facilities study
    agreements that are to be used in the Study Process.[^37]

39. The SGIA is to be used for the interconnection of all Small
    Generating Facilities subject to this Final Rule, with the exception
    of certain very small inverter-based generators that use an
    all-in-one application form/procedures/terms and conditions document
    (the 10 kW Inverter Process document). The Proposed SGIA included
    several provisions that were similar to those contained in the LGIA
    that was issued concurrent with the Small Generator Interconnection
    NOPR. Some commenters complained that the Proposed SGIA was too long
    and complex for owners of Small Generating Facilities, who may be
    small businesses or operators of small farms, for example. We are
    streamlining and simplifying the SGIA in many ways to address these
    concerns. We are adopting Joint Commenters\' proposals submitted in
    its supplemental comments where appropriate and have given
    consideration to the recommendations contained in the NARUC Model
    and those suggested by other commenters. In particular, the SGIA
    does away with the requirement that Interconnection Customers
    maintain multiple kinds of insurance, instead requiring only that
    they maintain a reasonable amount based on the specific
    characteristics of the interconnection.  We also adopt a streamlined
    dispute resolution provision designed to resolve disputes as quickly
    and inexpensively as possible.  We have also shortened the contract
    termination provisions and the various liability related provisions.

40. We adopt in the SGIA the same pricing policy for Network Upgrades to
    the Transmission Provider\'s Transmission System as in Order
    No. 2003. For a Small Generating Facility interconnecting with a
    non-independent entity such as a vertically integrated utility, the
    Interconnection Customer initially funds the cost of any required
    Network Upgrades (i.e., Upgrades to the Transmission System at or
    beyond the Point of Interconnection) and it is then subsequently
    reimbursed for this upfront payment by the Transmission Provider.
    However, we expect that, for most interconnections of Small
    Generating Facilities, there will be no Network Upgrades. We also
    allow more pricing flexibility for a Transmission System that is
    operated by an independent entity such as an RTO or Independent
    System Operator (ISO). The costs of Distribution Upgrades are
    directly assigned to the Interconnection Customer.

41. In conclusion, we encourage the standardization of interconnection
    practices across the nation, using as a starting point the SGIP and
    SGIA found in this Final Rule. We hope to foster seamless
    interconnection procedures for Interconnection Customers and
    Transmission Providers. Equipment manufacturers will have compatible
    technical specifications to meet. New generation will be located on
    the basis of what works best for the Interconnection Customer and
    the Transmission Provider, not jurisdictional differences in
    interconnection rules.

> **B. Overview of the Interconnection Process for Small Generating
> Facilities** []{#__RefHeading___Toc103479259 .anchor}

42. Before submitting its Interconnection Request, the Interconnection
    Customer may informally discuss the proposed interconnection with
    the Transmission Provider.[^38] The Interconnection Customer then
    submits an Interconnection Request to the Transmission Provider and
    the Transmission Provider assigns the Interconnection Customer\'s
    project a Queue Position based on the date and time the
    Interconnection Request is received by the Transmission Provider.
    The Interconnection Request must be accompanied by a deposit that
    goes toward the cost of the feasibility study, unless it is
    submitted under the Fast Track Process or the 10 kW Inverter
    Process, which have small processing fees.

43. As noted above, an Interconnection Request can be evaluated in one
    of three ways. The Study Process is the default method; it relies on
    the scoping meeting and standard feasibility, system impact, and
    facilities studies to evaluate the safety and reliability of the
    proposed interconnection. It is identical in concept to the
    evaluation procedure that is used for the interconnection of Large
    Generating Facilities. Two optional methods are available to
    Interconnection Customers whose Small Generating Facilities are
    certified and no larger than 2 MW. The 10 kW Inverter Process is
    available for owners of inverter-based Small Generating Facilities
    no larger than 10 kW and the Fast Track Process is available for
    owners of any kind of Small Generating Facility no larger than 2 MW.

44. The Study Process normally consists of a scoping meeting, a
    feasibility study, a system impact study, and a facilities study. At
    the scoping meeting, the Parties discuss the proposed
    interconnection and review any existing studies that could aid in
    the evaluation of the proposed interconnection. The feasibility
    study is a preliminary technical assessment of the proposed
    interconnection. The system impact study is a more detailed
    assessment of the effect the interconnection would have on the
    Transmission Provider\'s electric system and Affected Systems. The
    facilities study determines what modifications to the Transmission
    Provider\'s electric system are needed, including the detailed costs
    and scheduled completion dates for these modifications. These
    studies identify adverse system impacts[^39] that need to be
    addressed before the Small Generating Facility may be interconnected
    and any equipment modifications required to accommodate the
    interconnection. The Interconnection Customer pays the Transmission
    Provider\'s actual cost of performing the studies. Once the
    Interconnection Customer agrees to fund any needed Upgrades, the
    Parties execute an SGIA that, among other things, formalizes
    responsibility for construction and payment for Interconnection
    Facilities and Upgrades.[^40]

45. A Fast Track Process is available for certified Small Generating
    Facilities no larger than 2 MW. Under this process, in place of the
    scoping meeting and three interconnection studies, technical screens
    are used to quickly identify reliability or safety issues. If the
    proposed interconnection passes the screens, the Transmission
    Provider offers the Interconnection Customer an SGIA. If the
    proposed interconnection fails the screens, but the Transmission
    Provider determines that the Small Generating Facility may
    nevertheless be interconnected without affecting safety and
    reliability, the Transmission Provider also offers the
    Interconnection Customer an SGIA. However, if the Transmission
    Provider is concerned that the interconnection could degrade the
    safety and reliability of its electric system, the Parties may
    conduct a customer options meeting to discuss how to proceed. In
    that meeting, the Transmission Provider must offer to perform a
    supplemental review of the proposed interconnection, paid for by the
    Interconnection Customer, to identify Upgrades needed to accommodate
    the interconnection. Once the Interconnection Customer agrees to pay
    for any Upgrades called for in the supplemental review, the Parties
    execute an SGIA. If, after the supplemental review, the Transmission
    Provider still is unsure whether the proposed interconnection will
    degrade the safety and reliability of the its electric system, the
    Interconnection Request is evaluated using the Study Process
    described above; i.e., scoping meeting, feasibility, system impact,
    and facilities studies, followed by the execution of an SGIA.

46. Finally, the 10 kW Inverter Process is available for the
    interconnection of certified inverter-based generators no larger
    than 10 kW. The all-in-one 10 kW Inverter Process document includes
    a simplified application form, interconnection procedures, and a
    brief set of terms and conditions (akin to an interconnection
    agreement). The 10 kW Inverter Process uses the same technical
    screens to evaluate the safety and reliability of the proposed
    interconnection as the Fast Track Process. Unless the Transmission
    Provider demonstrates that the Small Generating Facility cannot be
    interconnected safely and reliably based on the results of an
    analysis using the screens, the Transmission Provider approves the
    application. Once the Interconnection Customer certifies that
    equipment installation is complete and upon a satisfactory
    inspection by the Transmission Provider, the Transmission Provider
    authorizes the interconnection. To further simplify the
    interconnection process, what would normally be considered a
    separate interconnection agreement has been distilled into a terms
    and conditions document that the Interconnection Customer agrees to
    at time the Interconnection Request is submitted to the Transmission
    Provider. The all-in-one 10 kW Process document is included in
    Attachment 5 to the SGIP.

    **C. Issues Related to Both the SGIP and the
    SGIA**[]{#__RefHeading___Toc103479260 .anchor}

47. This discussion, and those that follow, addresses the evolution of
    the SGIP and SGIA from the Proposed SGIP and Proposed SGIA. As is
    the custom in most Commission rulemakings, we use the Small
    Generator Interconnection NOPR as our point of reference, discussing
    each issue in turn, describing the comments addressed to the topic,
    and closing with the Commission conclusion. There are differences
    between the Proposed SGIP and SGIA and the documents we adopt in
    this Final Rule that reflect the helpful comments filed in this
    rulemaking. For example, we have in some instances adopted
    terminology more compatible with that used in state interconnection
    documents. This should make for simpler, more easily understood
    documents for small generators that are compatible across
    jurisdictions for both Interconnection Customers and Transmission
    Providers. However, the SGIP and SGIA also need to be interpreted in
    the broader context of the entire collection of generator
    interconnection documents that will appear in a Transmission
    Provider\'s OATT, including the LGIP and LGIA. Thus, there are some
    instances where consistency among generator interconnection
    documents within a single tariff makes it necessary to adopt Large
    Generator Interconnection terminology or policy. The Commission
    asked for comments in the Small Generator Interconnection NOPR
    addressing this topic, and it is the first to be addressed in the
    discussion that follows.

48. Many of the issues in this rulemaking also arose in the Large
    Generator Interconnecting rulemaking and we will not address them
    again here at any great length.

    Where there is no compelling reason to depart from prior precedent,
    we affirm the Commission\'s prior decisions without detailed
    discussion. Therefore, this order focuses on those issues needing a
    small-generator-specific resolution.

49. Finally, we note that the 10 kW Inverter Process for certified
    inverter-based Small Generating Facilities is an all-in-one
    application form/procedures/terms and conditions document that does
    not lend itself easily to the separate discussions of the Proposed
    SGIP/SGIA and the SGIP and SGIA discussions that follow. We will
    address it in the separate Part G discussion, below. We emphasize,
    however, that the intent of this Final Rule is that the 10 kW
    Inverter Process fits within the framework of the SGIP and SGIA, and
    it is for that reason that we encourage Interconnection Customers
    and Transmission Providers to use this Preamble, the SGIP, and the
    SGIA for assistance in interpreting the 10 kW Inverter Process
    should a dispute arise.

> **Consistency between the Large Generator and Small Generator
> Documents**[]{#__RefHeading___Toc103479261 .anchor}

50. In the Small Generator Interconnection NOPR, the Commission asked
    commenters to address the need for consistency between the
    provisions of the LGIP/LGIA and the SGIP/SGIA.

    **Comments**

51. NARUC argued that the Small Generator Interconnection NOPR was too
    complicated for most small generator interconnections. Instead, the
    Commission should adopt portions of the NARUC Model or otherwise
    simplify the interconnection process. NARUC pointed out that many
    Small Generating Facilities (including most inverter-based
    generators) will interconnect with low voltage facilities, whether
    Commission-jurisdictional or state-jurisdictional. Thus, this Final
    Rule should be as consistent with state interconnection rules as
    possible to encourage national consistency and discourage
    forum-shopping. Joint Commenters also supports this outcome.

52. AEP supports consistency between the large and small generator
    documents. However, it notes that Joint Commenters developed
    consensus positions on many issues during the ANOPR process. Where
    such agreement was reached, AEP proposes that the Commission adopt
    that position.

53. Midwest ISO argues that the Commission should ensure consistency
    between the large and small generator documents, wherever possible,
    because all stakeholders will benefit from a consistent approach to
    the interconnection of generation facilities.

54. PJM, on the other hand, proposes that the Commission simply use the
    LGIA for all interconnections, arguing that having different rules
    for large and small generator interconnections would be overly
    burdensome. PJM also states that its own interconnection rules take
    this approach and are hailed as being very successful.

55. Baltimore G&E argues that the Commission should require the same
    terms for all generators, regardless of size, unless there is a
    specific reason not to do so. Therefore, it requests that the
    Commission provide a clear explanation wherever these Final Rule
    provisions differ from those in Order No. 2003. Southern Company
    agrees, arguing that Large and Small Generating Facilities should be
    treated similarly \"because both can have . . . significant impacts
    upon the Transmission Provider\'s electric system.\"[^41]

56. BPA argues that the procedures and technical requirements applicable
    to large generators \"should not apply to the interconnection of
    small generators that have minimal impacts on a transmission
    grid.\"[^42] However, where the Commission does use \"substantially
    similar or consistent procedures, contract terms, and other
    requirements\" for both Large and Small Generating Facilities, \"the
    Commission should strive to provide consistency between its large
    and small generator rules.\"[^43]

57. Nevada Power also supports the concept of having the provisions
    applicable to Small Generating Facilities similar to those in Order
    No. 2003. According to Nevada Power, \"\[t\]hese commonalities will
    avoid the confusion of differing terminologies, facilitate
    consistent and fair implementation, and minimize the need for
    separate, parallel administrative processes to administer the
    agreements.\"[^44] However, Nevada Power also argues that
    consistency should not compromise the goals of simplifying and
    expediting the interconnection of Small Generating Facilities.
    Instead, this Final Rule should be designed to \"enable a common
    language and common administrative procedures to be implemented and
    still maintain appropriate distinctions between the small generators
    and the large generators.\"[^45] Nevada Power argues that the
    benefits of consistency are illustrated by Proposed SGIA article
    5.1.2.1, which specifies the refund process for advances made by the
    Interconnection Customer for Network Upgrades. By having the same
    refund process for the amounts advanced for Network Upgrades in the
    SGIA and the LGIA, the Transmission Provider can set up one system,
    instead of two separate systems, to track and make any such refunds.

58. In their supplemental comments, NARUC and the other Joint Commenters
    proposed SGIP and SGIA provisions that balance the need for
    simplicity with the need of Transmission Providers to ensure the
    safety and reliability of the Transmission Provider\'s electric
    system. In addition, Joint Commenters also proposed a process for
    certified inverter-based Small Generating Facilities no larger than
    10 kW that can also be used as a model for the states.

    **Commission Conclusion**

59. Unless expressly changed in this Final Rule, the Commission\'s
    existing interconnection precedent and Order No. 2003 are relevant
    to this Final Rule and should be used as guidance for interpretation
    and implementation. We have tried to be consistent between the rules
    for Large and Small Generating Facilities, unless there is a
    specific reason to do otherwise, while considering NARUC\'s call for
    federal-state consistency and the recommendations of other
    commenters.

60. We note Joint Commenters\' proposal of much simpler interconnection
    procedures and agreement for inverter-based generators no larger
    than 10 kW.[^46] Taking these extremely small units out of the mix
    has allowed us to adopt standard rules for larger Small Generating
    Facilities. According to NARUC, the process of interconnecting with
    a state-jurisdictional facility should not be substantially
    different from the process for interconnecting with a
    Commission-jurisdictional facility. Standard interconnection
    procedures are especially important for Interconnection Customers
    and manufacturers of off-the-shelf generating equipment.

61. In general, we are including standard contractual provisions in the
    SGIA that are consistent with their counterparts in the LGIA.
    However, in many cases commenters stressed the need to simplify
    those provisions to avoid burdening Small Generating Facilities.
    Many commenters offered ways to shorten and simplify those
    provisions. Where possible, we accept those proposals. These
    streamlined provisions adequately protect the Parties while lowering
    the transaction costs of entering into an interconnection agreement.
    The SGIP closely tracks the revised NARUC Model but adopts the
    single screen that NARUC and the other Joint Commenters later
    proposed in supplemental comments. Last, we have ensured that
    provisions common to the SGIP and SGIA (such as dispute resolution
    and confidentiality) are consistent.

62. **Definitions of Terms Used in the SGIP and
    SGIA**[]{#__RefHeading___Toc103479262 .anchor} **--** NARUC and
    others propose that the Commission use the defined terms in the
    NARUC Model instead of those found in the Small Generator
    Interconnection NOPR. We conclude that several of the terms defined
    in the Proposed SGIP and SGIA are either unnecessary or add
    complexity to the interconnection process. We are simplifying the
    SGIP and SGIA by deleting those definitions. Comments on specific
    terms are discussed below.

63. **Emergency Condition**[]{#__RefHeading___Toc103479263 .anchor} --
    The Proposed SGIA defined Emergency Condition as a situation that,
    in the judgment of the Party making the claim, is imminently likely
    to (1) endanger life or property, (2) have an adverse impact on the
    safety or reliability of the Transmission Provider\'s or an affected
    third party\'s electric system (Affected System), or (3) have a
    material adverse effect on the safety or operation of the
    Interconnection Customer\'s facilities. If there is an Emergency
    Condition, the Transmission Provider may take necessary and
    appropriate actions to protect the safety and reliability of its
    electric system, including interrupting, suspending, or curtailing
    interconnection service. While system restoration and black start
    are considered Emergency Conditions, the Small Generating Facility
    is not obligated to have black start capability.

**Comment**

64. Bureau of Reclamation objects to the provision that the Small
    Generating Facility is not obligated by the SGIA to have black start
    capability. Black start capability is an issue best handled by the
    control area rather than the Transmission Provider and that
    mentioning black start here raises the question of by whom and when
    black start capability could be required of the Small Generating
    Facility. In addition, Bureau of Reclamation proposes that the
    definition of Emergency Condition also include a \"threat or danger
    to the environment.\"

> **Commission Conclusion**

65. We see no need to modify the definition of Emergency Condition. The
    SGIA does not interfere with the control area\'s ability to
    establish a voluntary restoration plan, including black start. The
    SGIA requires the Parties to adhere to all Applicable Laws and
    Regulations relating to pollution and protection of the environment
    or natural resources. Therefore, Bureau of Reclamations\' proposed
    revision is not necessary.

66. **Network Upgrades**[]{#__RefHeading___Toc103479264 .anchor} --
    Comments concerning the definition of Network Upgrades are addressed
    in Part II.H (Pricing/Cost Recovery for Interconnection Facilities
    and Upgrades).

67. **Use of Calendar Days v. Business
    Days**[]{#__RefHeading___Toc103479265 .anchor} -- The Proposed SGIP
    and Proposed SGIA used both calendar days and Business Days to
    establish deadlines for particular activities.

**Comments**

68. Ameren, EEI, and NYTO request that all references to calendar day be
    changed to \"Business Day.\" Ameren and EEI state that doing so
    would make the SGIP and SGIA consistent. They also state that this
    is particularly important for the three and five day time limits,
    especially where the Transmission Provider may not have sufficient
    staff to respond within the required time. Ameren and NYTO argue
    that using both calendar days and Business Days is confusing. NYTO
    further notes that using Business Days rather than calendar days
    gives the Parties more time to meet deadlines. In addition, NYTO
    states that using calendar days does not account for normal business
    delays, including those caused by storm emergencies.

> **Commission Conclusion**

69. We agree that references to the passage of time should be
    consistent. Accordingly, we are changing calendar days to Business
    Days throughout the SGIP and SGIA, with two exceptions. First, using
    calendar days is proper in the SGIA\'s billing and payment
    provisions because these activities are traditionally tied to
    calendar days. Second, SGIA article 7.6.1 Default provisions are
    stated in terms of calendar days to be consistent with the
    Commission\'s regulations that require at least 60 calendar days
    notice of a proposed cancellation or termination of a contract.
    Where we have replaced calendar days with Business Days, we have
    adjusted the number of days to reflect about the same passage of
    time. Arguments relating to the amount of time a Party has to
    complete an action are discussed below.

70. **Maximum Size of a Small Generating
    Facility**[]{#__RefHeading___Toc103479266 .anchor} **--** In the
    Small Generator Interconnection NOPR, the maximum size of a Small
    Generating Facility is 20 MW. Where there is more than one unit
    generating power at a particular site, the Commission proposed to
    aggregate the total capacity of all generation units using the same
    Point of Interconnection. The Commission sought comments on a
    circumstance when the Interconnection Customer desires to increase
    the capacity of an existing generating facility. The Commission
    proposed that the total size of the facility would be determined by
    the sum of the existing and the incremental capacity. Thus, a 10 MW
    addition to an existing 15 MW facility would be treated as a 25 MW
    facility. The Commission also sought comments on how to evaluate an
    Interconnection Request that specifies a level of capacity below the
    maximum rating of the Small Generating Facility. Finally, the
    Commission invited comments on whether Small Generating Facilities
    with multiple Points of Interconnection should be treated separately
    for queuing and interconnection study purposes.

    **Comments**

    **Revising the Maximum Size of a Small Generating
    Facility**[]{#__RefHeading___Toc103479267 .anchor}

71. Ameren, EEI, and NRECA ask the Commission to reduce the maximum size
    of a Small Generating Facility from 20 MW to 10 MW. They argue that
    the lower size limit would help ensure safety and reliability of the
    Transmission Provider\'s electric system. They also note that it
    would also be consistent with IEEE Standard 1547,[^47] and argue
    that the 20 MW size limit is particularly challenging for
    Transmission Providers because of the types of analyses required to
    evaluate their interconnection and the restrictive time limits
    placed on performing them.

72. EEI similarly argues that many states have adopted 10 MW as the
    maximum size of a Small Generating Facility and that the Commission
    should follow suit. It argues that a 10 MW size limit is better
    suited to the Small Generating Facility configurations most likely
    to be proposed under the Final Rule. While reducing the size limit
    to 10 MW

    creates a gap between the Large and Small Generating Facility
    interconnection provisions, that gap can be easily remedied by
    making the LGIP and LGIA applicable to generating facilities larger
    than 10 MW.

73. NRECA notes in its initial comments that 10 MW is the upper limit
    for small generators in Texas, California, New York, and Ohio, and
    that no state currently has rules that apply to the interconnection
    of generators larger than 10 MW. According to NRECA, the
    Commission\'s statement in the Small Generator Interconnection NOPR
    that the 20 MW maximum size would \"encourage the development of a
    greater number of small generators and promote the development of
    innovative small generation technologies\" is not supported by
    engineering reality and industry practice. NRECA participated with
    Joint Commenters in developing consensus provisions for the SGIP and
    SGIA that were submitted in Joint Commenters\' supplemental
    comments. Based on those provisions, and in particular the technical
    screens contained in the SGIP, NRECA states that, \"while it still
    believes that 20 MW is too large a generator to be considered
    \'small,\' .... \[Joint Commenters\'\] SGIA and SGIP will work for
    all generators up to that size.\"[^48]

74. Cummins argues that the 20 MW size limit would result in more
    widespread use of on-site Small Generating Facilities.

    **Commission Conclusion**

75. We agree with commenters that generator size does matter when
    evaluating the effect of the Small Generating Facility on the
    Transmission Provider\'s electric system. However, we are keeping
    the 20 MW size limit for Small Generating Facilities because the
    interconnection studies and screens will identify any safety and
    reliability problems. In particular, the screens we adopt in the
    SGIP are supported by small generators, state regulators, and
    Transmission Provider representatives such as EEI and NRECA, as
    being appropriate to evaluate the safety and reliability of
    interconnections of Small Generating Facilities that are eligible
    for screening. We believe the higher threshold will remove barriers
    to the development of a greater number of Small Generating
    Facilities and promote the development of innovative small
    generation technologies.

    **Increasing the Capacity of an Existing Small Generating
    Facility**[]{#__RefHeading___Toc103479268 .anchor}

76. The Small Generator Interconnection NOPR proposed to evaluate
    increases in capacity to existing Small Generating Facilities using
    the total capacity of the modified facility, and the Commission
    invited comments on whether the proposal was reasonable.

    **Comments**

77. Several Transmission Providers[^49] support the NOPR\'s proposal.
    They add that if, for example, the capacity of an existing 18 MW
    Small Generating Facility were to be increased by 5 MW, the
    resulting 23 MW facility should be evaluated under the LGIP. This
    would keep the Interconnection Customer from gaming the system by
    incrementally increasing the size of an existing Small Generating
    Facility so that the capacity addition does not exceed the 20 MW
    maximum, even though the ultimate capacity of the facility does. BPA
    and ISO New England state that processing the Interconnection
    Request for such an expansion on the basis of the total capacity
    would better protect the safety and reliability of the Transmission
    Provider\'s electric system. Tangibl, on the other hand, argues that
    evaluating the Interconnection Request based on the total increased
    capacity of the Small Generating Facility would discourage such
    increases and hinder the increased entry of generators into the
    energy markets.

    **Commission Conclusion**

78. We are persuaded by BPA and ISO New England that when an existing
    Small Generating Facility is expanded, the Interconnection Request
    should be evaluated based on the total capacity of the facility as
    opposed to the incremental amount of the expansion. Similarly, an
    existing Large Generator seeking to increase its capacity by less
    than 20 MW would also have to follow the Large Generator rule,
    because the total capacity of the expanded facility would be more
    than 20 MW. Section 4.10.1 of the SGIP reflects this conclusion.

    **Evaluating the Generating Facility Based on Less Than Its Maximum
    Rated Capacity**

    []{#__RefHeading___Toc103479269 .anchor}

79. In the Small Generator Interconnection NOPR, the Commission sought
    comments on whether the maximum capacity of the Small Generating
    Facility should be used to evaluate the Interconnection Request when
    the Interconnection Customer specified an output level below the
    facility\'s maximum capability. For example, the Commission asked
    whether an Interconnection Request for a generating facility with a
    maximum capacity of 22 MW but seeking an interconnection for only 20
    MW (and agreeing to restrict delivery to the Transmission
    Provider\'s Transmission System to that level) should be evaluated
    under the SGIP or the LGIP.

    **Comments**

80. Several Transmission Providers[^50] argue that the Interconnection
    Request should be evaluated on the basis of the maximum capacity of
    the Small Generating Facility to ensure that safety and reliability
    are not jeopardized. They argue that the Commission should not allow
    a 22 MW generator to be treated as a 20 MW generator based on a
    promise by the Interconnection Customer that it will never generate
    more than 20 MW. This would result in an additional administrative
    burden on the Commission or market monitors. They also argue that
    evaluating the Small Generating Facility at less than its maximum
    rated capacity would not ensure that Interconnection Facilities and
    Upgrades are properly designed and installed.

81. BPA argues that evaluating a Small Generating Facility on the basis
    of maximum rated capacity would prevent gaming by an Interconnection
    Customer and would prevent it from submitting a request to
    interconnect its Small Generating Facility at a lower capacity when
    it really intend to operate the facility at a higher capacity.
    Further, evaluating a Small Generating Facility based on its maximum
    operational capacity would avoid the need to perform a reevaluation
    each time the Interconnection Customer seeks to operate at a higher
    output level.

82. Likewise, NYTO claims that even if a Small Generating Facility
    supplies local load and delivers only half of its output, it still
    contributes its full fault current to the electric system if there
    is an electrical fault. Also, stability analysis is based on the
    full physical characteristics of the facility, such as maximum power
    capability and rotation inertia. It further argues that if the
    Commission adopts a value other than the maximum capability of the
    Small Generating Facility, the Interconnection Customer could
    \"forum shop\" between the Large and Small Generating Facility
    interconnection provisions to get the \"best deal.\"

83. On the other hand, Allegheny states that if the Interconnection
    Customer is willing to accept the economic risks of its decision to
    limit the output of its generating facility, the Interconnection
    Request should be evaluated at the lower capacity.

84. American Forest, Cummins, Nevada Power, NRECA, and Tangibl also
    state that the Interconnection Request should be evaluated on the
    basis of requested capacity, not the maximum capability of the
    generator, if the Interconnection Customer commits to restrict the
    output. American Forest says that this is important for generators
    that consume most of their electrical output on-site in various
    manufacturing processes and export only a small fraction of their
    output. In its supplemental comments, Small Generator Coalition
    proposes a special set of tests that could be used to determine
    whether these kinds of configurations jeopardize safety and
    reliability.

    **Commission Conclusion**

85. We are persuaded that the Interconnection Request should be
    evaluated based on the Small Generating Facility\'s maximum rated
    capacity. We agree with commenters that evaluating the proposed
    interconnection at less than the maximum rated capacity of the
    generating facility does not ensure that proper protective equipment
    is designed and installed and the safety and reliability of the
    Transmission Provider\'s electric system can be maintained.

86. Nevada Power and other commenters propose that the Interconnection
    Request be evaluated on the basis of requested capacity if the
    Interconnection Customer agrees to restrict the output of its
    facility. We agree with NYTO, however, that even if the Small
    Generating Facility delivers only a portion of its capability, it
    still contributes its full fault current to the Transmission
    Provider\'s electric system if there is an electrical fault.
    Therefore, the maximum capacity of the Small Generating Facility
    should be used to evaluate the Interconnection Request
    ([See]{.underline} section 4.10.3 of the SGIP).

    **Evaluating Small Generating Facilities with Multiple Points of
    Interconnection**[]{#__RefHeading___Toc103479270 .anchor}

87. The Small Generator Interconnection NOPR invited comments on whether
    Small Generating Facilities with multiple Points of Interconnection
    (such as for a wind farm or an industrial cogeneration project
    serving multiple facilities) should be treated as separate projects
    or as a single project for queuing and interconnection study
    purposes.

    **Comments**

88. BPA, CA ISO, ISO New England, and Tangibl argue that Small
    Generating Facilities with multiple Points of Interconnection should
    be treated as a single project for queuing and interconnection study
    purposes. BPA states that this promotes greater efficiency and
    accuracy because the effects of all the generators can be evaluated
    in one study. According to commenters, evaluating each Point of
    Interconnection as a discrete facility may not account for the
    aggregate effects when multiple generation resources are
    interconnected.

89. Tangibl recommends adopting PJM\'s approach of one Interconnection
    Request for each Point of Interconnection. Tangibl states that the
    Interconnection Customer should aggregate the capacity of the
    multiple wind or solar projects that lie in close proximity to one
    another. However, for geographically dispersed wind or solar
    projects, it recommends that the project developer be able to ask
    the Transmission Provider to treat each project individually for
    interconnection study purposes.

90. Central Maine, Idaho Power, and others argue that evaluating
    Interconnection Requests based upon a single Point of
    Interconnection may produce flawed results because it may identify
    Upgrades incorrectly.

91. NYTO recommends that the Transmission Provider have the option,
    subject to Good Utility Practice, to either treat such projects
    separately for queuing and interconnection study purposes, or as a
    single Point of Interconnection. This is because each proposed Point
    of Interconnection presents numerous technical, operational, and
    reliability issues.

    **Commission Conclusion**

92. We adopt NYTO\'s proposal for the reasons cited by NYTO.  The
    Transmission Provider\'s evaluation of a project with multiple
    Points of Interconnection should be performed, using Good Utility
    Practice, based on the project's unique engineering and geographic
    needs.

93. **Dispute Resolution**[]{#__RefHeading___Toc103479271 .anchor}
    **(Proposed SGIA Article 8 and Proposed SGIP Section 2.11)**[^51] --
    The Commission proposed adopting the same dispute resolution
    procedures contained in the LGIA and LGIP. This was a departure from
    Joint Commenters\' proposal submitted in response to the ANOPR which
    obliged the Commission to supply technical experts to resolve
    disputes between the Parties.

    **Comments**

94. Commenters were split as to which type of dispute resolution
    procedures should be adopted by the Commission. Small generator
    proponents generally support allowing either Party to require
    binding arbitration, while Transmission Providers generally oppose
    such provisions. However, all commenters stress the need for quick
    and cost-effective dispute resolution.

95. CT DPUC argues that the procedures in the Small Generator
    Interconnection NOPR are too cumbersome and that state commissions
    are best positioned to resolve disputes in a fair manner, especially
    disputes over dual use facilities.

96. NRECA and BPA support adopting the dispute resolution procedures in
    the LGIA. However, BPA opposes binding arbitration and asserts that
    the Parties should keep whatever appeal rights they have.

97. Small Generator Coalition argues that most Interconnection Customers
    that own Small Generating Facilities do not have the resources to
    enter into protracted dispute resolution procedures with the larger
    Transmission Provider. It argues that complex dispute resolution
    procedures may discourage Small Generating Facilities from seeking
    to interconnect with Commission-jurisdictional facilities. Small
    Generator Coalition questions why the Commission would propose
    retreating from the ANOPR consensus result. It fears that
    Transmission Providers will simply refuse to submit to arbitration,
    forcing an Interconnection Customer to engage in expensive and
    undefined litigation. This is particularly true for owners of Small
    Generating Facilities no larger than 2 MW.

98. AEP proposes that either Party be able to require binding
    arbitration. It states that this approach is consistent with the
    consensus reached during the ANOPR process. Cummins agrees,
    asserting that otherwise one Party can obstruct the process. It
    points out that Interconnection Customers often lack the financial
    resources to pursue their rights before the Commission or in court,
    and need access to low-cost, binding dispute resolution procedures.

99. American Forest proposes allowing the Parties to agree on other
    arbitration procedures if they want to further tailor the procedures
    to the needs of the specific Parties. It claims that this is the
    approach common in the industry.

100. Midwest ISO recommends that where an RTO has Commission-approved
     dispute resolution procedures, it be allowed to apply those
     procedures to interconnection disputes.

101. NARUC requests that the Commission adopt the dispute resolution
     provisions found in its Model. It argues that \"\[e\]ach State
     already has in place a variety of avenues for dispute resolution
     oriented to protect the interests of the retail customer, ranging
     from a simple phone call to a State commission or consumer advocate
     \'consumer hotline\' to a full-blown complaint proceeding conducted
     by the State Commission.\"[^52] Specifically, the NARUC Model
     states that \"\[i\]f a dispute arises at any time during these
     procedures \[the Parties\] may seek immediate resolution through
     complaint procedures available\" through the state regulatory
     commission.[^53] The Model (1) states that the Interconnection
     Customer\'s Queue Position is not to be affected by its decision to
     pursue dispute resolution, (2) allows either Party to require
     binding arbitration, (3) allows the Parties to request that the
     state regulatory agency appoint a \"technical master\" to conduct
     the dispute

     resolution process, and (4) states that \"where possible, dispute
     resolution will be conducted in an informal, expeditious manner in
     order to reach resolution with minimal costs and delay. When
     appropriate and available, the dispute resolution may be conducted
     by phone or through Internet communications.\"[^54]

102. Joint Commenters, in its supplemental comments, proposes that the
     Commission\'s Dispute Resolution Service (FERC DRS) assist Parties
     in resolving their disputes. Under Joint Commenters\' proposal, one
     Party would give the other Party written notice that they have
     reached an impasse. As soon as two days afterwards, either Party
     may consult with FERC DRS for guidance on how best to resolve the
     dispute. FERC DRS may provide the Parties with a neutral venue to
     work out their dispute or may recommend alternative avenues of
     dispute resolution including, but not limited to, mediation,
     settlement judge talks, early neutral evaluation, or arbitration.
     The Parties could agree to make such outcomes binding, but would
     not be required to so agree, or even to participate in alternative
     dispute resolution procedures before FERC DRS.

     **Commission Conclusion**

103. We are adopting a dispute resolution provision for both the SGIP
     and SGIA that closely resembles the consensus recommendation of
     Joint Commenters. As the widely disparate recommendations show,
     different types of interconnection disputes require different types
     of dispute resolution procedures. Small Generator Coalition and
     others emphasize the need to avoid expensive and time consuming
     arbitration provisions. According to these commenters, if a project
     is forced to go to arbitration, it will likely never be built.
     Instead, Joint Commenters reached consensus on a set of principles
     designed to encourage the Transmission Provider and the
     Interconnection Customer to use fast and low cost alternative
     dispute resolution procedures to work through their differences.

104. Because the nature of the disputes that may arise are so varied,
     this approach will allow FERC DRS to make specific recommendations
     to the Parties designed to resolve the dispute quickly and
     inexpensively. In some cases, FERC DRS may simply provide the
     Parties a neutral venue to discuss their differences. In other
     cases, FERC DRS may recommend that the Parties put their case
     before a settlement judge or technical master for either mediation
     or arbitration. The Parties are free to specify whether the outcome
     of this alternative dispute resolution is binding.

105. As recommended by Joint Commenters, we will not mandate that the
     Parties use the FERC DRS\' resources. Alternative dispute
     resolution is, by its nature, a collaborative and voluntary
     process. However, both Parties must work in good faith to resolve
     their disputes. Additionally, the provision specifies that each
     Party is responsible for paying one-half of the cost of a neutral
     third-party employed to assist in settling the dispute.

106. We agree with CT DPUC, NARUC, and Joint Commenters (in its
     supplemental comments) that a state regulatory agency may often be
     the best place to quickly resolve a dispute. As mentioned above,
     the FERC DRS is well-equipped to recommend to Parties the best
     avenue for resolving a dispute. In many cases, that may be a state
     regulatory agency, if that body is willing to mediate or arbitrate
     the dispute.[^55]

107. While we are allowing Parties to select a dispute resolution
     process, we count on FERC DRS to ensure that both Parties are
     treated fairly. Thus, we disagree with American Forest that the
     Parties should be able to deviate from the established dispute
     resolution procedures without Commission guidance or oversight.
     While flexibility is important, as many commenters have pointed
     out, the Parties are rarely on an equal footing. Thus, we will
     scrutinize the process to ensure that Interconnection Customers are
     treated fairly, especially by non-independent Transmission
     Providers.

108. In response to Midwest ISO\'s request to include ISO-specific
     dispute resolution rules, under the independent entity variation,
     it and other independent Transmission Providers may propose such a
     plan in their compliance filings.

109. **Confidentiality**[]{#__RefHeading___Toc103479272 .anchor}
     **(Proposed SGIA Article 7 and Proposed SGIP Section 2.11)** --
     These provisions detailed the rights and responsibilities of each
     Party to keep any Confidential Information shared during the
     interconnection process.

     **Comments**

110. Avista and Idaho Power assert that the confidentiality provisions
     should give state regulators conducting an investigation the same
     access to confidential information as is provided to the Commission
     when it conducts an investigation. Avista also requests that the
     Commission address recent rulings by the Internal Revenue Service
     applicable to confidential transactions. Similarly, NARUC is
     concerned that the proposed confidentiality provisions might
     prevent state regulators from getting the information they need in
     the course of conducting an investigation. The NARUC Model SGIP
     includes a confidentiality provision that is similar to that
     proposed in the Small Generator Interconnection NOPR. The NARUC
     Model SGIA simply leaves a place holder to be filled in by the
     Parties.

111. Southern Company argues that Proposed SGIA article 7.1 should
     specify that information supplied \"as part of this
     \[interconnection\] agreement\" be confidential rather than
     information supplied \"prior to execution of this agreement.\" It
     also says that Proposed SGIA article 7.12 allows a broader class of
     information to qualify for confidential treatment than does article
     7.1, and proposes deleting article 7.12. Finally, article 7.4
     should be revised to prohibit the Interconnection Customer from
     sharing Confidential Information with \"potential purchasers or
     assignees of the Interconnection Customer.\"

112. In its supplemental comments, Joint Commenters propose the
     following provision in lieu of the proposal:

     Confidential Information is as defined in this Agreement but does
     not include information previously in the public domain, required
     to be publicly submitted or divulged by Governmental Authorities
     (after notice to the other party and after exhausting any
     opportunity to oppose such publication or release), or necessary to
     be divulged in an action to enforce this agreement. Each party
     receiving Confidential Information shall hold such information in
     confidence and shall not disclose it to any third party nor to the
     public without the prior written authorization from the party
     providing that information, except to fulfill obligations under
     this agreement, or to fulfill legal or regulatory requirements.
     Each party shall employ at least the same standard of care to
     protect Confidential Information obtained from the other party as
     it employs to protect its own Confidential Information. Each party
     is entitled to equitable relief, by injunction or otherwise, to
     enforce its rights under this provision to prevent the release of
     Confidential Information without bond or proof of damages, and may
     seek other remedies available at law or in equity for breach of
     this provision.

     **Commission Conclusion**

113. We are adopting confidentiality provisions in both the SGIP and
     SGIA that closely resemble those proposed by Joint Commenters.
     While the provisions we adopt here are shorter than those in the
     LGIP and LGIA, they are similar in content.

114. To clarify the Commission\'s right to otherwise Confidential
     Information during an investigation, we include an SGIA provision
     similar to LGIA article 22.1.10.[^56] This addition also clarifies
     that a Party is not prohibited from disclosing Confidential
     Information to a state regulatory body where the state regulatory
     body has the authority to request the information.

115. We deny Southern Company\'s request to remove proposed language
     allowing the Interconnection Customer to share Confidential
     Information with potential assignees and financers. The
     Interconnection Customer must be able to share such information to
     secure financing and remain competitive. However, we are modifying
     the provision to specify that any such person receiving
     Confidential Information agree to abide by the same confidentiality
     rules as the Parties.[^57] We agree with Southern Company that
     confidentiality should apply to all information shared between the
     Parties; however, its proposal is obviated by the new language.

116. **Keeping the Small Generator Interconnection Rules Current**
     []{#__RefHeading___Toc103479273 .anchor}-- The Small Generator
     Interconnection NOPR did not envision that the SGIP and SGIA would
     be periodically revised.

     **Comment**

117. In its supplemental comments, Small Generator Coalition asks the
     Commission to adopt a mechanism to allow periodic revisiting of its
     interconnection rules as the industry evolves. It proposes that the
     Commission encourage or charter a stakeholder committee to meet
     periodically to consider and recommend consensus proposals for
     changes.

     **Commission Conclusion**

118. We commend the persistence of the Joint Commenters who met on
     numerous occasions over the duration of this proceeding to aid the
     Commission in its decision-making. As one can see in the contents
     of this Final Rule, those negotiations have been very successful.
     We believe Small Generator Coalition\'s proposal has merit. We ask
     the Joint Commenters to take the lead in this process, and
     encourage interested entities to continue to work together on small
     generator interconnection issues. We are asking this informal group
     to meet biennially, beginning two years from the issuance of this
     order, to consider and recommend consensus proposals for changes in
     the Commission's rules for small generator interconnection. The
     Commission will provide appropriate resources to facilitate the
     process. To the extent that this group identifies needed changes,
     they may file a petition to amend the Commission\'s regulations.
     The Commission will review the petition and, if appropriate, notice
     that petition for public comment.

     **D. Issues Related to the Interconnection
     Request**[]{#__RefHeading___Toc103479274 .anchor}

119. The Interconnection Request is the application form that the
     Interconnection Customer uses to start the process of
     interconnecting its Small Generating Facility with the Transmission
     Provider\'s Transmission System. The issues discussed below either
     did not arise in the Large Generator Interconnection proceeding or
     we conclude that a different conclusion should apply to Small
     Generating Facilities.

120. **Processing Fees and Study
     Deposits**[]{#__RefHeading___Toc103479275 .anchor} **--** The
     Proposed SGIP set out a fixed processing fee schedule for
     processing all Interconnection Requests. The amount of the fee was
     to be tied to the size of the Small Generating Facility. Small
     Generating Facilities no larger than 2 MW in size would be charged
     the greater of (1) \$0.50/KVA rating, or \$100 for single phase
     generators no larger than 25 kVA or (2) \$500 for generators larger
     than 25 kVA. The fee for a Small Generating Facility larger than 2
     MW but no larger than 10 MW would be \$1,000, and the fee for one
     larger than 10 MW would be \$2,000. In addition, if the Small
     Generating Facility was to be evaluated using the interconnection
     studies, the Interconnection Customer would pay a deposit prior to
     each study that would be applied to the Transmission Provider\'s
     actual costs of performing the study.

     **Comments**

121. NARUC urges that the processing fee be cost-based so that there is
     no subsidization by either the Transmission Provider or the
     Interconnection Customer.

122. NRECA generally supports a fixed processing fee approach, but says
     that the proposed fees are unrelated to the actual cost of
     conducting the analysis under the screens. It asks the Commission
     to let each Transmission Provider file fees that are designed to
     recover the actual cost of conducting the analysis under the
     screens.

123. NYTO asks the Commission to clarify that the proposed fee covers
     administrative and engineering costs not covered by other fees.
     PacifiCorp states that it does not appear that the owner of a Small
     Generating Facility no larger than 2 MW would pay any fee other
     than the fee to conduct the analysis under the screens. It asks the
     Commission to require the owner of such a generator to pay the
     actual cost of interconnection, if any, beyond the processing fee.

124. Southern Company states that the proposed processing fee schedule
     conflicts with the deposit provisions of the proposed
     interconnection study agreements. It argues that a Small Generating
     Facility interconnecting at the transmission level should submit an
     interconnection feasibility study deposit rather than the
     application fee because it appears that the processing fee is a
     charge for conducting the analysis under the screens. Southern
     Company also states that evaluating an Interconnection Request for
     a non-certified Small Generating Facility requires time and effort,
     and the Interconnection Customer should pay twice the processing
     fee assessed to the owner of a certified Small Generating Facility.

     **Commission Conclusion**

125. Under this Final Rule, the Interconnection Customer shall submit
     with its Interconnection Request a processing fee or feasibility
     study deposit, but not both, depending on how the Interconnection
     Request is to be evaluated. If it is to be evaluated using the
     Study Process, which usually includes a scoping meeting and
     feasibility, system impact, and facilities studies, the
     Interconnection Customer shall make a deposit towards the cost of
     the feasibility study at the time the Interconnection Request is
     submitted to the Transmission Provider. The amount of the deposit
     is the lesser of 50 percent of the good faith estimated feasibility
     study costs or \$1,000. If the Interconnection Request is to be
     evaluated using the Fast Track Process, it is to be accompanied by
     a \$500 processing fee. If the Interconnection Request is to be
     evaluated using the 10 kW Inverter Process, it is to be accompanied
     by a \$100 processing fee.

126. The purpose of the \$100 and \$500 processing fees is to recover
     the Transmission Provider\'s costs of evaluating Interconnection
     Requests under the 10 kW Inverter Process and Fast Track Process,
     respectively. This approach to fees is simple, easy to administer,
     and gives many Interconnection Customers the cost certainty they
     need to move forward with their projects.  However, because
     administratively fixed fees will sometimes either under- or
     over-recover a particular Transmission Provider\'s costs, we will
     allow the Transmission Provider to charge a cost-based fee for
     processing Interconnection Requests if it has first made an
     appropriate rate filing with appropriate detailed cost
     justification under FPA section 205.[^58] If the Transmission
     Provider decides to revise its processing fee

     schedule through a rate filing, the revised fees would, of course,
     apply prospectively to all new Interconnection Requests under the
     Fast Track Process or the 10 kW Inverter Process. Otherwise, the
     processing fees in the SGIP will serve as a default.

127. Given our concerns about the need for many Interconnection
     Customers to know beforehand the costs they will incur for the
     evaluation of their Interconnection Request under the screens, we
     will disallow formula rates or true up provisions in any rate
     submission.  The cost support for the filed fixed processing fee
     schedule (designed in a manner similar to the processing fees in
     the SGIP) shall reflect the Transmission Provider\'s costs for
     processing Interconnection Requests under the Fast Track and the 10
     kW Inverter Processes, as it would for the embedded cost based
     pricing of any other jurisdictional service.

128. Southern Company\'s first comment highlights an unintended
     inconsistency in the NOPR. To clarify, the fixed processing fee
     schedule delineated above is only for submissions under the10 kW
     Inverter Process and the Fast Track Process which use the technical
     screens.  A submission under the Study Process instead will include
     a deposit towards the Transmission Provider\'s cost of performing
     the feasibility study, not both a deposit and a processing fee.
     However, an Interconnection Customer whose proposed interconnection
     fails the Fast Track Process or the 10 kW Inverter Process and is
     then evaluated under the Study Process would pay both the fixed
     processing fee with the initial submission and then a feasibility
     study deposit before the Study Process begins.

129. **Receipt Confirmation and Requests for Additional
     Data**[]{#__RefHeading___Toc103479276 .anchor} -- Proposed SGIP
     sections 3.2 and 4.2 govern the submission and receipt of the
     Interconnection Customer\'s Interconnection Request.

**Comments**

130. Central Maine argues that the Transmission Provider should be able
     to use alternative methods to mail, such as fax and overnight
     delivery services, to tell the Interconnection Customer that it has
     received the Interconnection Request. It also asks that the
     Commission increase the Transmission Provider\'s notification time
     period from ten to fifteen Business Days. Central Maine and EEI
     note that the Interconnection Customer does not have a deadline to
     supply missing information. They recommend that the Commission
     establish ten Business Days as the deadline and to state that
     failure to provide such information within that time will result in
     the Interconnection Request being deemed withdrawn.

**Commission Conclusion**

131. We agree that the Transmission Provider may use alternate methods
     of confirming receipt of the Interconnection Request. The
     notification requirement is needed because it provides a date
     certain for affirming that the Transmission Provider has received
     the Interconnection Request. We also decline to increase the time
     by which the Interconnection Customer must be told whether the
     Interconnection Request is complete. Ten Business Days is
     sufficient time for the Transmission Provider to make an initial
     assessment as to whether the requisite information has been
     provided; an in-depth evaluation of the project is not required
     during this period. However, we agree with Central Maine and EEI
     that the Proposed SGIP does not address when the Interconnection
     Customer must furnish the missing information. Accordingly, the
     SGIP provides that the Interconnection Customer has ten Business
     Days after receipt of the notice to submit the missing information
     or to provide an explanation as to why extension of time is needed
     to provide such information. If the Interconnection Customer does
     not provide the missing information or a request for an extension
     of time within the deadline, the Interconnection Request shall be
     deemed withdrawn.

132. **Interconnection Products and Service
     Options**[]{#__RefHeading___Toc103479277 .anchor} -- The Proposed
     Interconnection Request would have directed the Interconnection
     Customer to state whether it intends to participate as a \"Network
     Resource,\" \"Energy-Only Resource,\" \"Non-Exporting Resource
     Participating in a Wholesale Market,\" or \"Other.\"

**Comments**

133. Alabama PSC, EEI, Mississippi PSC, Southern Company, and others are
     concerned that the Interconnection Request could be construed to
     mean that a Small Generating Facility is eligible for the same
     Network Resource Interconnection Service that Order No. 2003 makes
     available to Large Generating Facilities. They argue that this
     service should not be provided to a Small Generating Facility. For
     example, Alabama PSC and Mississippi PSC argue that a Small
     Generating Facility does not meet the basic prerequisites to
     receive a \"network\" type of service. They state that Small
     Generating Facilities almost universally interconnect with either
     \"distribution\" or sub-transmission facilities that are not
     \"networked\" but are radial in nature. The costs to make such
     facilities networked to provide such a service would be
     prohibitive. Southern Company asks that the references to resource
     options be deleted. TAPS states that the Small Generator
     Interconnection NOPR correctly dispenses with Order No. 2003\'s
     Network Resource Interconnection Service, which TAPS claims is
     incompatible with Network Integration Transmission Service under
     the OATT.

134. Taking the opposite view, National Grid states that the Commission
     should establish two interconnection products for Small Generating
     Facilities, arguing that Energy Resource Interconnection Service
     and Network Resource Interconnection Service are just as important
     for a Small Generating Facility as they are for a Large Generating
     Facility. National Grid states that Network Resource
     Interconnection Service has important market implications for new
     resources, because only generating facilities that meet this
     interconnection standard should qualify for installed capacity
     credits. It argues that Small Generating Facilities should have the
     option of being studied as deliverable network resources so that
     they may be eligible for such credits. If the Commission does not
     mandate two separate interconnection products for Small Generating
     Facilities, National Grid requests that, at a minimum, the single
     interconnection product ensure deliverability of generating
     facility output, consistent with the Commission's ruling in [New
     England]{.underline} with respect to large generator
     interconnections.[^59]

135. NARUC asks the Commission to remove the category \"non-exporting
     resource participating in a wholesale market\" from the
     Interconnection Request. It notes that the Interconnection Request
     instructs the Interconnection Customer to declare its intention to
     sell electricity at wholesale in interstate commerce. However, the
     phrase \"non-exporting resource participating in a wholesale
     market,\" which is used nowhere else in the Small Generator
     Interconnection NOPR, raises unnecessary questions and extends its
     reach far beyond its stated intention.

136. PacifiCorp states that none of these service categories is defined
     in the Proposed SGIP and that the significance of each designation
     is unknown. It argues that the different service options must be
     defined in the SGIP and that the additional information needed to
     permit a Transmission Provider to conduct studies must be provided.
     PacifiCorp asks the Commission to explain the significance of
     \"Non-Exporting Resource Participating in a Wholesale Market\" and
     \"Other.\" It adds that there should be an opportunity for comment
     on the workability of these proposals and on what information a
     Transmission Provider may need to provide this kind of
     interconnection service.

137. SoCal Edison seeks clarification that, to interconnect a Small
     Generating Facility with a Distribution System, the Transmission
     Provider must study deliverability[^60] on the system, even if no
     delivery service is sought on either the Transmission or
     Distribution System. In studying distribution-level
     interconnections, the Small Generating Facility is assumed to be
     running at maximum output and the power is flowing onto the
     directly attached distribution facility. SoCal Edison argues that
     there is no way to study an interconnection with the Distribution
     System without assuming power flows on that Distribution System.

138. SoCal Edison further argues that, unlike an energy resource on a
     Transmission System, the generator cannot for safety and
     reliability reasons opt to generate only when distribution
     \"capacity\" is available because the characteristics of a
     Distribution System (i.e., radial) differ from those of a
     Transmission System (i.e., network). Given how a Distribution
     System operates, the provision of distribution interconnection
     service in the absence of a wholesale distribution service request
     is a meaningless exercise, and there are considerable efficiencies
     in requesting and studying the two services at the same time. Also,
     SoCal Edison is concerned that some Interconnection Customers may
     not realize that a separate rate may be charged to use the
     Distribution System in addition to the Transmission System. It
     states that the Commission should clarify that both interconnection
     and wholesale delivery service may be required. Although SoCal
     Edison

     does not believe that the Commission needs to require that
     wholesale distribution service and distribution-level
     interconnection service be provided only on a bundled basis, it
     asks the Commission to permit \"bundled\" applications like those
     under SoCal Edison\'s Wholesale Distribution Access Tariff.

     **Commission Conclusion**

139. We clarify that the resource options listed in the Small Generator
     Interconnection NOPR\'s Interconnection Request are not
     interconnection service options. Rather, they are merely the
     possible ways the Interconnection Customer may use its Small
     Generating Facility once delivery service begins. The purpose of
     this information is to give the Transmission Provider an early
     indication of how the Small Generating Facility is likely to
     operate. The one interconnection service that the Commission
     proposed to make available to the Small Generating Facility is
     similar to the Energy Resource Interconnection Service that is
     offered under the LGIA. Nevertheless, based on the comments, we are
     concerned that requesting service-related information in the
     Interconnection Request could lead to misunderstanding. Because the
     information is related to the delivery component of transmission
     service, not interconnection service, it is not needed in the
     SGIP\'s Interconnection Request form. Therefore, we are removing
     this information from the Interconnection Request. This should
     address the concerns of most commenters.

140. In response to National Grid, we note that the LGIA\'s more
     expansive Network Resource Interconnection Service is intended to
     give the Interconnection Customer broad access to the backbone of
     the Transmission Provider\'s Transmission System. In essence, it
     allows the generating facility to pre-qualify as a Network Resource
     for any Network Customer on the Transmission System and, as
     National Grid notes, may make it eligible for installed capacity
     credits. Because Network Resource Interconnection Service entails
     high technical standards, we expect that an Interconnection
     Customer, particularly one interconnecting at a lower voltage,
     would rarely find this service to be efficient or practical.
     Nevertheless, we do not want to preclude it from choosing this
     option. If it wishes to interconnect its Small Generating Facility
     using Network Resource Interconnection Service, it may do so.
     However, it must request interconnection under the LGIP and execute
     the LGIA.

141. In response to SoCal Edison\'s request for clarification, we note
     that the SGIP lets the Transmission Provider study the potential
     impacts of the proposed interconnection on the Distribution System.
     Also, we clarify that nothing in this Final Rule (which concerns
     interconnection service only) prevents the Transmission Provider
     from evaluating the Interconnection Request and requests for
     wholesale distribution service and transmission delivery service
     simultaneously. However, the Transmission Provider may not require
     the Interconnection Customer to request wholesale distribution
     service or transmission delivery service as a condition for
     granting a request for interconnection service. We expect the
     Transmission Provider to explain to the Interconnection Customer
     what delivery services may be needed to meet its needs.

142. **Ministerial Changes to the Interconnection
     Request**[]{#__RefHeading___Toc103479278 .anchor} -- The Proposed
     Interconnection Request was crafted largely by Joint Commenters in
     response to the ANOPR. It is similar in many respects to the NARUC
     Model. Joint Commenters in its supplemental comments submitted
     ministerial changes to the Proposed Interconnection Request. Other
     commenters[^61] also seek changes to the Interconnection Request,
     most reflecting misplaced or missing technical information. The
     Interconnection Request we adopt in this Final Rule largely tracks
     the NARUC Model version and also reflects many of the changes
     proposed by the commenters.

     **E. Issues Related to the SGIP**[]{#__RefHeading___Toc103479279
     .anchor}

143. **Using Voltage Level to Determine Which Procedures
     Apply**[]{#__RefHeading___Toc103479280 .anchor} **--** The Proposed
     SGIP divided Interconnection Requests into two groups for initial
     processing based on the voltage level of the interconnection.
     Interconnections to High-Voltage (at or above 69 kV) would be
     evaluated using the interconnection studies. Interconnection to
     Low-Voltage (below 69 kV) would be processed differently depending
     upon the size and the certification status of the Small Generating
     Facility as explained below. An Interconnection Request for a
     certified Small Generating Facility no larger than 2 MW
     interconnecting at Low-Voltage would be evaluated using
     super-expedited screening criteria; an Interconnection Request for
     a Small Generating Facility no larger than 10 MW interconnecting at
     Low-Voltage would be evaluated using expedited screening criteria;
     and an Interconnection Request for a Small Generating Facility
     larger than 10 MW but no larger than 20 MW interconnecting at
     Low-Voltage would be evaluated using the interconnection studies.
     If an Interconnection Request did not pass the super-expedited
     screening criteria or expedited screening criteria, it would be
     evaluated using interconnection studies.

     **Comments**

144. Several commenters[^62] object to using voltage level to
     distinguish which review process initially applies to an
     Interconnection Request. They argue that the distinction should be
     based on whether the Small Generating Facility is being
     interconnected with distribution or transmission facilities. The
     decision should be consistent with the physical facilities and
     operational realities of the electric system. They also contend
     that electric system configurations vary widely in terms of voltage
     levels and that the effect of an interconnection is not necessarily
     determined by voltage, but also by location and size of the Small
     Generating Facility. In addition, they state that this distinction
     was not a part of the ANOPR proposal and that using voltage to
     distinguish which set of procedures applies is confusing.

145. In its supplemental comments, Joint Commenters propose using
     whether the proposed interconnection is with a transmission line
     (i.e., interconnections with transmission lines may not be
     evaluated using the technical screens) to determine whether screens
     may be used to evaluate the proposed interconnection.

     **Commission Conclusion**

146. For the reasons given above, we agree with commenters that
     interconnection voltage should not be used as a determinative
     factor for whether the Interconnection Request may be evaluated
     using the technical screens. Instead, we are adopting the technical
     screens proposed by Joint Commenters in its supplemental comments.
     The SGIP specifies that an Interconnection Request for a certified
     Small Generating Facility no larger than 2 MW shall be evaluated
     using the technical screens, either under the Fast Track Process or
     the 10 kW Inverter Process, whichever applies. Under the first
     provision of the screens, SGIP section 2.2.1.1, the proposed Small
     Generating Facility's Point of Interconnection must be on a portion
     of the Transmission Provider's Distribution System that is subject
     to the Tariff.[^63]

147. **Certification of the Small Generating Facility (Proposed SGIP
     Section 3.1)**[]{#__RefHeading___Toc103479281 .anchor} -- In the
     Small Generator Interconnection NOPR, the Commission proposed that
     Interconnection Requests for certified generators no larger than 2
     MW would be reviewed using the super-expedited screening criteria
     that employed technical screens. The Commission also noted that
     Joint Commenters (in its response to the ANOPR) preferred that the
     Commission itself implement a single, uniform, nationwide process
     for the certification of Small Generating Facility equipment
     packages no larger than 2 MW.[^64] The Commission proposed,
     however, that this function instead be performed by an
     industry-recognized testing organization. In addition, the
     Commission requested comments as to whether IEEE 1547 (Standard for
     Interconnecting Distributed Resources with Electric Power Systems),
     together with other technical industry documents, could be the
     basis for a national certification standard.

> **Comments**

148. Commenters generally agree with the value of having a certification
     process for Small Generating Facilities. They believe that such a
     process can speed interconnection and eliminate the need to
     \"reinvent the wheel\" each time an interconnection is made. In
     general, commenters agree that IEEE 1547, in conjunction with other
     standards, could be the basis for a certification standard.

149. NYTO requests that the Commission adopt the process and registry
     proposal described in the November 12, 2002 Joint Commenters
     filing. That would have the Commission maintain a list of certified
     equipment and to centralize the registry function. It claims that
     this would provide certainty to the industry as to which equipment
     has been certified and would avoid the development of competing and
     potentially inconsistent lists of certified equipment, which could
     lead to disputes and slow down the interconnection process.

150. The NARUC Model certification provision relies on Nationally
     Recognized Testing Laboratories (NRTL) to test and certify the
     safety of electrical equipment used for the production of
     electricity. That provision, which was developed for use by state
     regulators, requires that the NRTL be used by the state regulatory
     authority or approved by the U.S. Department of Energy.

151. American Forest and others state that if the Commission chooses not
     to certify and maintain a registry of equipment, it should
     establish and oversee a stakeholder process for the development of
     certification criteria. Without the Commission\'s involvement, the
     process of establishing certification standards will languish.

152. Cummins and others, however, argue that a nationally recognized
     testing laboratory and agencies like the Department of Energy
     should oversee the certification process. They also note that a
     national testing laboratory, such as Underwriter Laboratories,
     typically not only tests and verifies the performance of prototype
     equipment, but also provides follow-up services to verify that
     production equipment is designed and manufactured to the same
     standards as the tested equipment.

153. Ameren and others complain that the NOPR does not explain what
     industry operational and safety standards are applicable. Likewise,
     the NOPR does not specify what is needed to qualify as a national
     testing laboratory. They claim that leaving these issues open could
     lead to unnecessary or improper testing. They recommend that the
     Commission (1) adopt a specific set of standards for operation and
     safety requirements that are continually updated to meet current
     safety and reliability requirements set forth by NERC or the
     regional reliability councils, and (2) maintain a list of qualified
     national testing laboratories.

154. Allegheny Energy argues that certification guarantees the safety
     and reliability of the equipment in a stand-alone mode only, but
     not safety and reliability when the equipment becomes part of an
     integrated system.

155. Joint Commenters, in its supplemental comments, proposes a
     consensus equipment certification provision that it states was
     developed under a stakeholder process convened by the U.S.
     Department of Energy\'s Office of Electric Transmission and
     Distribution. The participants in the process included Joint
     Commenter members representing small generator interests, state
     regulators, and Transmission Providers, as well as experts from the
     electrical equipment manufacturing industry and testing
     laboratories. Joint Commenters\' proposed certification provision
     provides that Small Generating Facility equipment shall be
     considered certified if (1) it has been tested in accordance with
     industry standards for continuous utility interactive operation in
     compliance with the appropriate codes and standards by any NRTL
     recognized by the United States Occupational Safety and Health
     Administration to test and certify interconnection equipment
     pursuant to the relevant codes and standards, (2) it has been
     labeled and is publicly listed by such NRTL at the time the
     Interconnection Request is made, and (3) such NRTL makes readily
     available for verification all test standards and procedures it
     utilized in performing such equipment certification and, with
     consumer approval, the test data itself.

> **Commission Conclusion**

156. We agree with Cummins that nationally recognized laboratories
     should oversee the certification process and maintain registries of
     certified equipment. A NRTL not only tests and verifies the
     performance of prototypes, but it provides follow-up services to
     verify that production equipment is designed and manufactured to
     the same standards as the tested equipment. In this Final Rule, we
     are adopting Joint Commenters\' proposal. This certification
     provision was vetted by a diverse group of stakeholders and is
     fundamentally consistent with the Proposed SGIP as well as the
     provision contained in the NARUC Model. We are especially
     encouraged by the report from Joint Commenters that one well-known
     NRTL intends to begin the certification of equipment as soon as the
     summer of 2005. This should hasten the development of certified
     Small Generating Facilities no larger than 2 MW under the Fast
     Track and 10 kW Inverter Processes. The certification provision we
     adopt in this Final Rule is contained in Attachments 3 and 4 of the
     SGIP.

157. Finally, we acknowledge Allegheny Energy\'s concerns. Electric
     system safety and reliability issues are to be addressed when the
     proposed interconnection of the certified equipment is evaluated
     under the Fast Track Process or the 10 kW Inverter Process.

158. **Super-Expedited Procedures (Proposed SGIP Section 3) and
     Expedited Procedures (Proposed SGIP Section
     4.3**)[^65][]{#__RefHeading___Toc103479282 .anchor} **--** In the
     NOPR, proposed SGIP section 3 stated that if the proposed Small
     Generating Facility is certified, no larger than 2 MW, and the
     interconnection is with Low-Voltage facilities, the interconnection
     would be evaluated using super-expedited screens. Proposed SGIP
     section 4.3 stated that if the proposed Small Generating Facility
     is no larger than 10 MW and the interconnection is with Low-Voltage
     facilities, the interconnection would be evaluated using expedited
     screens. Proposed SGIP section 4.3 also provided that the expedited
     screens would be used to evaluate proposed interconnections that
     failed the super-expedited screens.

159. The NOPR proposed that if the Transmission Provider determines that
     the proposed interconnection fails the super-expedited screens and
     is not satisfied that the Small Generating Facility can be
     interconnected safely and reliably, the Interconnection Customer
     can pay for an additional review. The review would not exceed six
     hours and would determine whether minor modifications to the
     Transmission Provider\'s electric system (e.g., changing meters,
     fuses, relay settings) could enable the interconnection to be made
     safely and reliably. If the results of the review were positive and
     the Interconnection Customer agreed to pay for these minor
     modifications, the Transmission Provider would tender an executable
     SGIA to the Interconnection Customer.

     **Comments**

160. Joint Commenters, Small Generator Coalition, and NARUC recommend
     that the Commission require the use of screens to evaluate
     Interconnection Requests. NARUC and Small Generator Coalition
     initially proposed using two sets of screens. However, Joint
     Commenters (which includes both NARUC and Small Generator
     Coalition) now recommends adopting a single set of screens that
     serves the same purpose as the two initially proposed.

161. Several commenters[^66] asked that the screens be clarified,
     modified, or eliminated. EEI recommended that the screens be
     available only for interconnection with radial facilities.

162. Cinergy, EEI, Idaho Power, NYTO, and others maintain that even if
     the Small Generating Facility is certified and passes the screens,
     there is no assurance that safety and reliability or the quality of
     service is not degraded as a result of the interconnection. Cinergy
     and EEI argue the rule should require a showing that the
     interconnection does not degrade safety and reliability.

163. BPA and Central Maine oppose limiting the additional review to six
     hours, arguing that each interconnection is unique.

164. PJM argues that the Final Rule should not allow screens to be used
     in lieu of the feasibility study. It claims that while screens
     allow a project to be expedited, they do not necessarily provide
     the type of information needed by the Interconnection Customer to
     determine whether the project is viable (e.g., information
     concerning the estimated cost of interconnection or the effects on
     other projects).

165. BPA claims that it is unreasonable to hold the Transmission
     Provider to stringent deadlines without establishing corresponding
     deadlines for the Interconnection Customer. MISO and BPA contend
     that the timelines do not give the Transmission Provider sufficient
     time to review the Interconnection Request. MISO proposes that the
     Transmission Provider be permitted to notify the Interconnection
     Customer if it is unable to meet the target date, along with the
     reasons for delay.

166. NRECA and others ask the Commission to reduce the maximum size of a
     facility that may be evaluated under the screens to as small as 3
     kW. In its supplemental comments, Small Generator Coalition argues
     against imposing any size limits.

167. Southern Company argues that certain base case assumptions are
     necessary for an accurate representation of the electric system
     when an Interconnection Request is evaluated under screens. It
     would like the evaluation to include all pending higher-queued
     Interconnection Requests because only then could the effect of an
     Interconnection Request be truly determined.

**Commission Conclusion**

168. In SGIP section 2.2.1, we are adopting a single set of screens
     submitted by Joint Commenters in its supplemental comments, with
     minor editorial changes. These are the screens that would be
     applied in the Fast Track and the 10 kW Inverter Processes. We are
     adopting only one set of screens rather than the two in the NARUC
     Model and the Small Generator Interconnection NOPR. The individual
     screening criteria in this set are very similar to those in the
     NARUC Model and closely track both those contained in the Small
     Generator Interconnection NOPR and those proposed by Joint
     Commenters in the ANOPR process.

169. The NOPR did not contain a screen that would permit interconnection
     with a secondary network[^67] and Joint Commenters were unable to
     agree on one. We are also not adopting any additional screen that
     would permit interconnection with a secondary network in this Final
     Rule.

170. We are deleting \"and must comply with all requirements of approved
     industry standards for interconnection technical specifications and
     requirements\" from one of Joint Commenters\' proposed screens
     because this language is redundant; a Small Generating Facility
     that is being evaluated under the Fast Track Process or 10 kW
     Inverter Process must meet the codes, standards, and certification
     requirements of Attachments 3 and 4 of the SGIP.

171. Concerns raised by commenters that screens do not accurately
     reflect the true effect of the interconnection on safety and
     reliability are unfounded. We believe the thresholds used in the
     screens to be conservative and that there is negligible chance that
     a proposed interconnection could pass the screens and actually
     impact the safety and reliability of the Transmission Provider\'s
     electric system. These thresholds have been vetted by Transmission
     Providers, small generator developers, and representatives of state
     regulators alike.

172. We reject Small Generator Coalition\'s argument that there should
     be no size restrictions for Small Generating Facilities whose
     interconnections may be evaluated using the screens. We are
     retaining the proposed 2 MW threshold for certified generators as a
     critical eligibility criterion for using the screens. It helps
     ensure the safety and reliability of the Transmission Provider\'s
     electric system. Small Generator Coalition, together with a number
     of Transmission Providers and representatives of state regulatory
     agencies, vetted the threshold when submitting the package of
     screens through Joint Commenters\' supplemental comments.

173. In response to objections to the NOPR\'s expedited screening
     procedures, the Final Rule SGIP does not include any screens for
     Small Generating Facilities larger than 2 MW. Accordingly, only a
     request to interconnect a certified Small Generating Facility no
     larger than 2 MW shall be evaluated using the screens. A request to
     interconnect a Small Generating Facility larger than 2 MW or a
     Small Generating Facility of any size that is not certified shall
     be evaluated using the Study Process.

174. BPA and others oppose limiting the additional review to six hours.
     We are eliminating this restriction.[^68] The SGIP includes a
     customer options meeting where the Transmission Provider may
     propose modifications to the proposed interconnection or the Small
     Generating Facility itself, or perform a supplemental review if the
     Interconnection Customer agrees to pay for it. This allows the
     Transmission Provider to determine the modifications needed to
     accommodate the interconnection without the need for detailed and
     more costly interconnection studies.

175. Southern Company and Joint Commenters (in its supplemental
     comments) argue that the Transmission Provider should be allowed to
     consider the effects of all pending higher-queued Interconnection
     Requests when evaluating the Interconnection Request under the
     screens. We agree.

176. **Queuing Priority (Proposed SGIP Section
     4.4)**[]{#__RefHeading___Toc103479283 .anchor} -- In the NOPR, the
     Commission proposed that each Transmission Provider maintain a
     single queue per geographic area. A queue lists Interconnection
     Requests in the order in which they are received. The Queue
     Position determines the order of performing interconnection
     studies, if required, and the Interconnection Customer\'s cost
     responsibility for any Upgrades to the Transmission Provider\'s
     electric system. In Order No. 2003, the Commission decided that the
     Transmission Provider should maintain a single integrated queue per
     geographic region. However, RTOs and ISOs have flexibility to
     propose queues and queuing rules designed to meet their regional
     needs.[^69] We are adopting the same provision here, for the same
     reasons. Accordingly, there is no need to separately address again
     the same comments raised in this proceeding on that issue.

> **Comments**

177. Small Generator Coalition requests that the Commission establish
     separate queues for Large and Small Generating Facilities. Failing
     that, the Commission should clarify that the interconnection study
     periods identified in the SGIP are binding without regard to the
     Queue Position of other generating facilities. Alternatively, Small
     Generating Facilities should be clustered for study purposes within
     a given time frame (e.g., 90 days). It states that requiring a
     single queue for all generating facilities undercuts whatever
     progress has been made in interconnecting Small Generator
     Facilities. Small Generator Coalition, Solar Turbines, and others
     state that, in light of their relatively simple interconnection
     requirements, use of off-the-shelf equipment, and minimal effects
     on the Transmission Provider\'s electric system, Small Generating
     Facilities should be able to be interconnected quickly. They
     complain that the interconnection can be delayed by higher-queued
     Large Generating Facilities that require longer, more frequent, and
     more expensive interconnection studies and restudies.

> **Commission Conclusion**

178. We disagree with Small Generator Coalition that a single queue is
     unfavorable to Small Generating Facilities. Although Queue Position
     determines the order of the interconnection studies and the cost
     responsibility for the Network Upgrades necessary to accommodate
     the interconnection, it does not determine the order in which the
     interconnections are completed.

179. For many Transmission Providers, the requirement to maintain two
     queues could actually delay, rather than speed up, the
     interconnection process. Thus, we are requiring a Transmission
     Provider to use a single queue for all Generating Facilities,
     regardless of size. Also, the SGIP allows Small Generating
     Facilities to be interconnected without going through the Study
     Process if they pass the screens. However, under the independent
     entity variation available to RTOs and ISOs under this Final Rule,
     such entities may propose multiple queues in their compliance
     filings.[^70]

180. Small Generator Coalition is correct that a non-clustering
     Transmission Provider must meet all deadlines established in the
     SGIP without regard to queue position or queue-related delays.

181. We reiterate that clustering is the Commission\'s preferred method
     for conducting interconnection studies, and should be seriously
     considered by all Transmission Providers.[^71] Clustering of
     studies allows the Transmission Provider to study multiple
     Interconnection Requests simultaneously, thereby maximizing the
     effectiveness of its staff. Clustering may also reduce
     interconnection study and Upgrade costs; for example, multiple
     Interconnection Customers can share the cost of Upgrades.

182. **Scoping Meeting (Proposed SGIP Section
     4.5)**[]{#__RefHeading___Toc103479284 .anchor} -- Proposed SGIP
     section 4.5 would require the Parties to hold a scoping meeting
     within ten Business Days after the Interconnection Request is
     deemed complete by the Transmission Provider. The purpose of the
     meeting is to review the characteristics of the Transmission
     Provider\'s electric system, discuss the technical aspects of the
     proposed interconnection, and review existing

     studies and the results of the application of the technical
     screens, if applicable. If the Parties agree that a feasibility
     study is needed, the Transmission Provider would provide the
     Interconnection Customer with a feasibility study agreement.

     **Comments**

183. Central Maine asks that the Transmission Owner also be included in
     the scoping meeting. Small Generator Coalition asks that the
     provision be revised to allow the Parties to conduct the scoping
     meeting by telephone.

     **Commission Conclusion**

184. In the SGIP, Transmission Provider is defined to include both the
     Transmission Provider and Transmission Owner, when they are
     separate entities. Accordingly, the Transmission Owner may attend
     the scoping meeting. Also, there was nothing in the Proposed SGIP
     that mandates that the scoping meeting be held face-to-face. We
     encourage the Parties to conduct the interconnection process in the
     most expeditious manner possible and to take advantage of
     telephone, fax, and e-mail. Finally, as in Order No. 2003-A, we are
     requiring that any scoping meeting between the Transmission
     Provider and an affiliate be announced publicly and transcribed,
     with the transcripts made available upon request for a period of
     three years.[^72] While the Transmission Provider may redact
     portions of the transcripts deemed to be commercially sensitive or
     containing Critical Energy Infrastructure Information, the
     Commission will decide which redacted portions are to be made
     public.

185. **Interconnection Studies (Proposed SGIP Sections 4.6, 4.7, and
     4.8)**[]{#__RefHeading___Toc103479285 .anchor} -- Proposed SGIP
     sections 4.6, 4.7, and 4.8 and the associated study agreements
     described the feasibility, system impact, and facilities studies
     (collectively, interconnection studies) and the Interconnection
     Customer\'s cost responsibility for each study. For a Small
     Generating Facility larger than 2 MW but no larger than 10 MW
     interconnecting at Low-Voltage, the Proposed SGIP would first
     evaluate the proposed interconnection using expedited screens.
     However, if the Transmission Provider believed that the
     interconnection would undermine safety and reliability even though
     the proposed interconnection passed the screens, the Transmission
     Provider would pay for the feasibility study if that study
     subsequently identified no adverse system impact. The cost of the
     system impact and facilities studies, however, would always be paid
     by the Interconnection Customer.

     **Comments -- Study Cost
     Obligations**[]{#__RefHeading___Toc103479286 .anchor}

186. Central Maine, Exelon, and PacifiCorp argue that the
     Interconnection Customer should always pay for interconnection
     studies, regardless of the conclusions reached. Small Generator
     Coalition maintains that the Transmission Provider should pay for
     the feasibility study only if it shows no adverse impact.

**Commission Conclusion**

187. The Interconnection Customer should pay for all of the
     interconnection studies, regardless of the conclusions reached,
     because it is unreasonable to shift this cost to other transmission
     customers that do not benefit from the studies, which is what would
     occur if the Transmission Provider were to pay for them. The
     Transmission Provider should, of course, use existing studies
     instead of performing additional analyses to reduce costs for the
     Interconnection Customer, whenever possible. The Interconnection
     Customer is not to be charged for such existing studies; however,
     it is responsible for costs associated with any new study and any
     modification to an existing study that is reasonably necessary to
     evaluate the proposed interconnection.

**Comments -- Study Requirements**[]{#__RefHeading___Toc103479287
.anchor}

188. PJM and Southern Company argue that a system impact study should
     always be performed to detect adverse impacts that may not have
     been detected in the feasibility study. Small Generator Coalition
     argues that in many situations only a feasibility study or a system
     impact study is needed, but not both; Parties should be able to
     agree to skip the feasibility study. PacifiCorp states that, for a
     small project, the feasibility study is not much different from the
     system impact study and recommends that the former be eliminated.
     SoCal Edison argues that the provisions of the SGIP dealing with
     interconnection studies should refer to the distribution provider,
     if applicable, and the Transmission Provider. Bureau of Reclamation
     asks the Commission to clarify that the Transmission Provider
     should perform flicker and voltage drop studies.

**Commission Conclusion**

189. We agree that, on occasion, there may be some overlap between the
     feasibility study and the system impact study. For a small project,
     the distinction may not be enough to require that both studies be
     performed. In such cases, it may be reasonable to skip the
     feasibility study entirely. Therefore, as the Commission did for
     Large Generating Facilities in Order No. 2003-A, we are allowing
     the Parties to skip the feasibility study upon mutual agreement. As
     to SoCal Edison\'s comment, we do not see any need to include the
     term \"distribution provider\" when referring to SGIP provisions.
     Transmission Provider is already defined as \"\[t\]he public
     utility (or its designated agent) that owns, controls, or operates
     transmission or distribution facilities used for the transmission
     of electricity in interstate commerce and provides transmission
     service under the Tariff.\" As to Bureau of Reclamation\'s request
     for clarification, voltage drop, voltage limit violation, and
     grounding studies are indeed included in the study process.

**Comments -- Study Deadlines and
Restudy**[]{#__RefHeading___Toc103479288 .anchor}

190. Southern Company, PG&E, and others contend that the proposed
     interconnection study deadlines are too short. NARUC proposes
     giving the Transmission Provider 30 Business Days to complete the
     feasibility study, 30 Business Days to complete the distribution
     system impact study, 45 Business Days to complete the transmission
     system impact study, 30 Business Days to complete the facilities
     study when no Upgrades are required, and 45 Business Days to
     complete the facilities study when Upgrades are required.

191. PacifiCorp states that a restudy provision should be included in
     the SGIP so that the Interconnection Request could be restudied if
     a higher-queued Interconnection Customer drops out. It argues that
     the LGIP included a restudy provision for each of the three
     studies.

**Commission Conclusion**

192. We are adopting the deadlines proposed by NARUC and incorporating
     them in the interconnection study agreements. They strike a good
     balance, allowing sufficient time to complete the studies while
     ensuring that Small Generating Facilities can be interconnected
     within a reasonable time. Also, as noted above, with the exception
     of payment provisions, we are replacing \"calendar days\" with
     \"Business Days\" in the SGIP and SGIA. However, where appropriate,
     we are revising the number of days to correspond to the actual
     passage of time.

193. We disagree that a restudy provision is needed in the SGIP.  The
     very purpose of the Small Generator Final Rule is to expedite
     interconnections of Small Generating Facilities by removing
     unnecessary delays.  While a restudy provision in the LGIP context
     is meaningful because system conditions may change between
     completion of a particular study and the Parties\' signing the
     LGIA, it is unlikely that any significant change in system
     conditions will occur that was not foreseen by the Transmission
     Provider at the time of study because the SGIP has a much shorter
     timeline.

     **Comments -- Post-Operational Evaluation of the
     Interconnection**[]{#__RefHeading___Toc103479289 .anchor}

194. PacifiCorp argues that, after the Small Generating Facility is
     operational, an interconnection may cause problems that were
     unforeseen when the project was initially evaluated. For example,
     wind generators may need to fine tune their reactive power output.
     Also, because the certification and screening processes are new,
     the Transmission Provider should be permitted to perform
     post-interconnection reviews and adjustments, including additional
     Upgrades, if necessary, to be paid for by the Interconnection
     Customer.

> **Commission Conclusion**

195. The purpose of the evaluation processes in the SGIP is to determine
     the effect the interconnection will have on the Transmission
     Provider\'s electric system. Such evaluations are also performed to
     ascertain the Interconnection Customer\'s cost responsibility for
     Interconnection Facilities and Upgrades. We reject PacifiCorp\'s
     proposal because accepting it would make determination of cost
     responsibility open-ended and create uncertainty for the
     Interconnection Customer. Should unforeseen problems arise, the
     Parties may make a filing with the Commission and request expedited
     consideration.

196. **Execution of the SGIA**[]{#__RefHeading___Toc103479290 .anchor}
     -- Although the Proposed SGIP required the Transmission Provider to
     deliver an executable SGIA to the Interconnection Customer within a
     time certain, the Interconnection Customer had no deadline to sign
     and return the document to the Transmission Provider.

     **Comment**

197. In its supplemental comments, Joint Commenters propose that the
     Interconnection Customer have 30 Business Days to sign and return
     the SGIA.

     **Commission Conclusion**

198. We adopt Joint Commenters\' proposal. The Transmission Provider
     needs to know whether the proposed project will go forward. Giving
     the Interconnection Customer a deadline within which to act gives
     the Transmission Provider the certainty it needs for system
     planning purposes. The SGIP states that, after receiving an
     interconnection agreement from the Transmission Provider, the
     Interconnection Customer shall have 30 Business Days or another
     mutually agreeable timeframe to sign and return the SGIA, or
     request that the Transmission Provider file an unexecuted SGIA with
     the Commission. If that is not done, the Interconnection Request
     shall be deemed withdrawn.

> **F. Issues Related to the SGIA**[]{#__RefHeading___Toc103479291
> .anchor}

199. **Responsibilities of the Parties (Proposed SGIA Article
     2.2)**[]{#__RefHeading___Toc103479292 .anchor} -- Article 2.2 of
     the Proposed SGIA set out each Party\'s responsibilities under the
     SGIA. It included the obligation of the Interconnection Customer to
     interconnect, operate, and construct its facilities in a safe
     manner and to follow Good Utility Practice. It would similarly
     require the Transmission Provider to operate its electric system in
     a safe and reliable manner.

     **Comments**

200. BPA asserts that Proposed SGIA article 2.2 should require the
     Interconnection Customer to abide by national and regional
     reliability rules, such as those developed by NERC and the Western
     Electricity Coordinating Council, that are generally applicable to
     all generators in a control area or geographic region. Furthermore,
     according to BPA, the interconnection agreement should require the
     Interconnection Customer to abide by any technical requirements
     established by the Transmission Provider to govern the safe
     interconnection of generating facilities.

201. NARUC offers alternative language laying out the responsibilities
     of the Parties, consistent with its Model. Specifically, NARUC
     proposes replacing article 2.2 with the following:

     Each Party will, at its own cost and expense, operate, maintain,
     repair, and inspect, and shall be fully responsible for the
     facility or facilities which it now or hereafter may own or lease
     unless otherwise specified in Exhibit A. Maintenance of
     Interconnection Customer\'s Small Resource and interconnection
     facilities shall be performed in accordance with the applicable
     manufacturer\'s recommended maintenance schedule.

     The Parties agree to cause their facilities or systems to be
     constructed in accordance with specifications provided by the
     National Electrical Safety Code, the National Electric Code, and as
     approved by the American National Standards Institute, and
     interconnected in accordance with the Institute of Electrical and
     Electronics Engineers standards where applicable.

     Interconnection Provider and Interconnection Customer shall each be
     responsible for the safe installation, maintenance, repair and
     condition of their respective lines and appurtenances on their
     respective sides of the Point Of Common Coupling. The
     Interconnection Provider or the Interconnection Customer, as
     appropriate, shall provide interconnection facilities that
     adequately protect the Interconnection Provider\'s distribution
     system, personnel, and other persons from damage and injury. The
     allocation of responsibility for the design, installation,
     operation, maintenance and ownership of the Interconnection
     Facilities shall be made part of this agreement as Exhibit C.

202. Avista states that \"the Interconnection Customer should be
     required not only to construct its generating facility in
     accordance with operating requirements to be set forth in Appendix
     4 to the Proposed SGIA, but also to maintain and operate its
     \[Small Generating Facility\] in accordance with such operating
     requirements.\"[^73]

203. Nevada Power asserts that the IEEE 1547 standards referred to in
     Proposed SGIA article 2.2.4 were never designed to be applied to
     generating facilities larger than 10 MW and that in fact \"there is
     no extant national standard that can be reasonably applied to
     govern the Interconnection Facilities for Generating Facilities
     greater than ten megawatts.\"[^74] Instead, Nevada Power proposes
     that until a national standard is developed to address this 10-20
     megawatt gap, the Commission modify article 2.2.4 to read:

     Interconnection Customer agrees to cause its facilities or systems
     to be constructed 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, Operating Requirements[, and, where the
     Generating Facility will have a capacity greater than ten
     megawatts, the Transmission Provider\'s applicable Interconnection
     Facility standards]{.underline} in effect at the time of
     construction . . . .\[[^75]\]

204. PacifiCorp notes that the Proposed SGIA assumes that the
     Interconnection Customer and the Transmission Provider are each
     responsible for the maintenance of equipment on its side of the
     point of change of ownership. But as a practical matter, more
     flexibility is needed because non-utility companies cannot usually
     maintain certain equipment, such as communications equipment, that
     is critical to the protection of the Transmission Provider\'s
     electric system. Moreover, the Transmission Provider often owns and
     maintains revenue meters on the customer\'s side of the point of
     change of ownership. Therefore, argues PacifiCorp, the SGIA should
     clarify that unless provided otherwise in an attachment, each Party
     is responsible for the equipment on its side of the point of change
     of ownership.

205. Small Generator Coalition requests that the Commission restrict the
     ability of the Transmission Provider to impose additional technical
     requirements on the Small Generating Facility. Otherwise, it fears
     that Interconnection Customers will be subjected to additional
     requirements under the guise of reliability rules that make it
     difficult to interconnect in a cost-effective manner. On the other
     hand, Southern Company contends that the standards for operating in
     parallel should be codified in the SGIA. This way, the Transmission
     Provider can then confirm that all the requirements are met before
     granting the authorization to operate.

206. In its supplemental comments, Joint Commenters recommends several
     changes to Proposed SGIA article 2.2. Specifically, Joint
     Commenters recommend clarifying that the Transmission Provider must
     [coordinate]{.underline} with an Affected System operator to
     complete the interconnection, but need not [negotiate]{.underline}
     on behalf of the Interconnection Customer. Joint Commenters also
     propose changing the last sentence of proposed article 2.2.4 to
     read:

     Interconnection Customer agrees to design, install, maintain, and
     operate, or cause the design, installation, maintenance, and
     operation of the Generating Facility [and Interconnection Customer
     Interconnection Facility]{.underline} so as to reasonably minimize
     the likelihood of a disturbance, originating on [such]{.underline}
     equipment affecting or impairing the system or equipment of
     Transmission Provider, or Affected Systems.\[[^76]\]

     **Commission Conclusion**

207. We are adopting a version of this provision that is based on the
     NARUC Model and Joint Commenters\' proposals. Redrafting article
     2.2 as requested by commenters clarifies the rights and
     responsibilities of the Parties and aids them in better
     understanding their roles in the interconnection process.

208. Several commenters also ask the Commission to clarify the right of
     the Transmission Provider to include supplemental \"Interconnection
     Guidelines,\" either in the SGIA or as an attachment to it. As the
     Commission stated in Order No. 2003-A, the Transmission Provider
     may include supplemental interconnection requirements if (1) they
     are authorized by the applicable reliability council and (2) the
     Transmission Provider imposes such requirements on itself and all
     other Interconnection Customers, including its affiliates.[^77] We
     see no reason to depart from this standard. The Commission has
     consistently held that an Interconnection Customer must adhere to
     established reliability practices within the control area with
     which it is interconnecting.[^78] The same would be true for
     including supplemental guidelines for generators larger than 10 MW,
     as requested by Nevada Power.

209. In response to Nevada Power\'s comments about the applicability of
     the IEEE 1547 standard to generating facilities no larger than 10
     MW, we note that the SGIA states that this standard is required
     only \"where applicable.\"

210. The SGIA also addresses PacifiCorp\'s concerns over using the point
     of change of ownership as the basis for establishing the Parties\'
     respective roles and allows the Parties to specify their respective
     roles in SGIA Attachment 2.

211. **Metering (Proposed SGIA Article
     2.4)**[]{#__RefHeading___Toc103479293 .anchor} -- Proposed SGIA
     article 2.4 would specify that the Interconnection Customer is
     responsible for the Transmission Provider\'s reasonable cost for
     the purchase, installation, operation, maintenance, testing,
     repair, and replacement of any metering and data acquisition
     equipment. It also would require that the Interconnection
     Customer\'s metering equipment conform to applicable industry rules
     and operating requirements.

     **Comment**

212. CA ISO argues that Proposed SGIA article 2.4 should require any
     Small Generating Facility larger than 1 MW to provide real-time
     telemetry to the Transmission Provider to better maintain
     reliability and meet regional requirements.

     **Commission Conclusion**

213. We are not requiring Small Generating Facilities to provide
     real-time telemetry because doing so may hamper their development
     and we are not convinced that it is necessary in every instance.
     However, if regional reliability requirements dictate real-time
     telemetry for Small Generating Facilities, we expect the
     Interconnection Customer to meet such requirements.

214. **Equipment Testing and Inspection (Proposed SGIA Article
     3.1)**[]{#__RefHeading___Toc103479294 .anchor} **--** Proposed SGIA
     article 3.1 described the pre-operational testing and inspection
     requirements for the Small Generating Facility.

     **Comments**

215. Central Maine argues that the Interconnection Customer should
     periodically test the Small Generating Facility and Interconnection
     Facilities after they achieve commercial operation and that the
     Transmission Provider should be allowed to witness such testing.
     The purpose of such testing is to ensure that the Interconnection
     Customer\'s equipment is operating properly. Southern Company
     argues that the Interconnection Customer should pay the
     Transmission Provider\'s expenses for such pre-operational testing.

     **Commission Conclusion**

216. We decline to expand the provisions of this article to require
     generically that every Interconnection Customer perform periodic
     testing of its Small Generating Facility, regardless of
     circumstances. To so do would be burdensome on the Interconnection
     Customer, costly, and potentially allow a self-interested
     Transmission Provider to impose multiple rounds of costly testing
     on competing generators. However, should the Transmission Provider
     believe in good faith that the Small Generating Facility or the
     Interconnection Facilities is affecting safety and reliability, the
     Transmission Provider may, upon advance written notice, require the
     Interconnection Customer to perform reasonable additional
     post-operational testing. The Transmission Provider may witness

     such testing. The Transmission Provider and the Interconnection
     Customer shall be responsible for their own staff, equipment, and
     other costs associated with the testing and inspection.

217. **Right of Access (Proposed SGIA Article
     3.3)**[]{#__RefHeading___Toc103479295 .anchor} -- The Proposed SGIA
     would give the Transmission Provider access to land owned or
     controlled by the Interconnection Customer to construct
     Interconnection Facilities or for other specified purposes.

     **Comment**

218. NARUC urges the Commission to adopt the following right of access
     provision from its Model:

> Upon reasonable notice, the Interconnection Provider may send a
> qualified person to the premises of the Interconnection Customer at or
> immediately before the time the Small Resource first produces energy
> to inspect the interconnection, and observe the commissioning of the
> Small Resource (including any required testing), startup, and
> operation for a period of up to no more than three days after initial
> start-up of the unit. In addition, the Interconnection Customer shall
> notify the Interconnection Provider at least seven days before
> conducting any on-site Verification Testing of the Small Resource.
>
> Following the initial inspection process described above, at
> reasonable hours, and upon reasonable notice, or at any time without
> notice in the event of an emergency or hazardous condition,
> Interconnection Provider shall have access to Interconnection
> Customer\'s premises for any reasonable purpose in connection with the
> performance of the obligations imposed on it by this Agreement or if
> necessary to meet its legal obligation to provide service to its
> \[customers\].

**Commission Conclusion**

219. We largely adopt NARUC\'s proposal. It uses the concepts found in
     the Small Generator Interconnection NOPR, but shortens and
     simplifies the provisions. However, we are adding that each Party
     is responsible for its own staff, equipment, and other costs in
     carrying out this provision.

220. **Term of Agreement (Proposed SGIA Article
     4.2)**[]{#__RefHeading___Toc103479296 .anchor} -- Proposed SGIA
     article 4.2 would require that the interconnection agreement remain
     in effect for ten years, or longer by request, and that it can be
     automatically renewed for each successive one year period
     thereafter.

     **Comments**

221. BPA argues that the interconnection agreement should remain in
     effect as long as the Small Generating Facility remains
     interconnected, subject to the termination provision of the SGIA or
     as agreed to by the Parties. The article unnecessarily requires the
     Parties to negotiate a follow-on agreement after ten years.

222. Central Maine requests that the SGIA terminate after a set number
     of years agreed to by the Parties. It states that the provision is
     unacceptable because it allows the Interconnection Customer to
     unilaterally select the term of the interconnection agreement.

     **Commission Conclusion**

223. We deny BPA\'s and Central Maine\'s requests to revise the term of
     the interconnection agreement. These issues were addressed in Order
     No. 2003, and neither commenter raises any new arguments here.[^79]

224. **Termination (Proposed SGIA Article 4.3) and Default (Proposed
     SGIA Article 6.17)**[]{#__RefHeading___Toc103479297 .anchor} **--**
     Proposed article 4.3.1 would grant the Interconnection Customer the
     right to terminate the SGIA at any time by giving 30 days written
     notice. Proposed article 4.3.2 would allow the Transmission
     Provider to terminate the interconnection agreement if a material
     change in law or regulations would either prevent performance of
     the interconnection agreement or impose on the Transmission
     Provider substantial additional costs that are not reimbursed by
     another entity. Proposed article 6.17 described when a Default
     takes place and the Parties\' right to cure upon notice of a
     Default. Because these provisions are closely related, we discuss
     them together.

     **Comments**

225. Several commenters ask the Commission to grant the Transmission
     Provider termination rights comparable to those given the
     Interconnection Customer.[^80] PG&E and Southern Company request
     that the Transmission Provider have the right to terminate the
     interconnection agreement if the Small Generating Facility is
     either shut down or abandoned. Southern Company asks that the
     Transmission Provider be allowed to terminate the agreement if the
     Small Generating Facility either does not begin commercial
     operation or is inactive for three years. Absent changes to this
     provision, the only remedy available to the Transmission Provider
     is to file an application to terminate with the Commission.

226. Central Maine, Joint Commenters, and PacifiCorp ask that if the
     Interconnection Customer terminates the SGIA, neither the
     Transmission Provider nor its customers should have to pay the
     costs of termination, including the cost of site restoration.
     Central Maine says these costs should be paid by the
     Interconnection Customer if it defaults on the interconnection
     agreement. PacifiCorp requests that the SGIA require the
     Interconnection Customer to pay any outstanding costs under the
     SGIP or SGIA during the 30 day notice period, or else termination
     shall not become effective. Joint Commenters also propose including
     a provision specifying that a Party remains liable for expenses
     incurred under the SGIA even after it has terminated. Central Maine
     states that certain critical provisions, such as access,
     confidentiality, invoicing, limitation of liability, and
     indemnification, should survive any expiration or earlier
     termination of an agreement.

227. NARUC urges the Commission to adopt its Model interconnection
     agreement, which allows the Interconnection Customer to terminate
     the agreement for any reason, including default, provided 60 days\'
     written notice is given. Alternatively, the Transmission Provider
     may terminate the agreement if the Small Generating Facility does
     not generate energy in parallel with the Transmission Provider\'s
     Transmission System by the later of two years from the date of the
     agreement or 12 months after interconnection is completed.

228. NARUC also requests clarification that the Transmission Provider
     may terminate the interconnection agreement for Default. Both NARUC
     and Joint Commenters propose adding a provision specifying that a
     Transmission Provider may terminate the SGIA if there is a material
     change in a rule or statute concerning interconnection and parallel
     operation of the Small Generating Facility that would impose
     additional costs on the Transmission Provider. Finally, the NARUC
     Model clarifies that termination does not relieve either Party of
     its obligations to the other Party.

229. Central Maine and NYTO ask the Commission to clarify the difference
     between \"Default\" and \"Breach,\" as it did in the LGIA.
     Specifically, Central Maine states that a Breach, if uncured,
     becomes a Default and may result in termination.

     **Commission Conclusion**

230. As Order No. 2003 stated, there is no reason to allow the
     Transmission Provider to terminate the interconnection agreement if
     the Interconnection Customer has met all its obligations.[^81] As
     we have noted elsewhere in this Final Rule, the interests of a
     Transmission Provider may be adverse to those of the
     Interconnection Customer, and it has an incentive to discriminate
     against the Interconnection Customer. The Interconnection
     Customer\'s business decision not to operate its Small Generating
     Facility for an extended period of time should not result in the
     loss of its rights under the SGIA.

231. We adopt NARUC\'s proposal that a Party be given 60 calendar days
     in which to cure a Default once notified that it is in Default. If
     at the end of the 60 calendar days, the Default continues to exist,
     the non-defaulting Party may terminate the interconnection
     agreement. This is consistent with the Commission\'s regulations
     that require an entity to notify the Commission of the proposed
     cancellation or termination of a contract at least 60 calendar days
     before the cancellation or termination is proposed to take effect.
     However, to allow for situations where 60 calendar days are not
     sufficient time to cure the default, the SGIA allows up to six
     months in which to cure the Default so long as the Party
     \"continuously and diligently\" works towards curing the Default.

232. Joint Commenters and Central Maine propose provisions that address
     the cost responsibility of the Parties if the SGIA is terminated.
     Both the Termination and Default provisions now clarify that the
     Parties\' financial obligations and other responsibilities survive
     the termination of the SGIA. The SGIA also addresses PacifiCorp\'s
     concern that the Interconnection Customer would be able to
     terminate the interconnection agreement and escape financial
     responsibility for costs it has already incurred.

233. The Proposed SGIA included a provision allowing the Transmission
     Provider to terminate the SGIA should there be a regulatory change
     that would impose additional costs on the Transmission Provider.
     Consistent with the LGIA, we are not including such a provision in
     the SGIA Should a significant regulatory change take place, the
     Transmission Provider may request termination of the
     interconnection agreement under section 205 of the FPA.

234. Central Maine and NYTO are correct that the term \"breach\" does
     not appear in the SGIA. Upon discovering a Default, the
     non-defaulting Party gives notice of the Default to the defaulting
     Party. The defaulting Party then has time to cure the Default. If
     it does not do so, the SGIA may then be terminated. We are revising
     the SGIA accordingly.

235. **Emergency Conditions (Proposed SGIA Article
     4.4.1)**[]{#__RefHeading___Toc103479298 .anchor} -- Proposed SGIA
     article 4.4.1 would give the Transmission Provider the right to
     immediately suspend interconnection service and temporarily
     disconnect the Small Generating Facility under Emergency
     Conditions.

**Comment**

236. SoCal Edison proposes adding the term \"Distribution Provider\'s
     Distribution System\" to each place where the definition of
     Emergency Condition says \"Transmission Provider\'s Transmission
     System.\"[^82]

     **Commission Conclusion**

237. The owner of the Commission-jurisdictional facility with which the
     Interconnection Customer interconnects is the \"Transmission
     Provider\" regardless of how the facility may be classified by the
     Transmission Provider. As defined by this Final Rule,
     \"Transmission Provider\" means \"the public utility . . . that
     owns, controls, or operates transmission [or]{.underline}
     distribution facilities used for the transmission of electricity in
     interstate commerce and provides transmission service under the
     Tariff\" (emphasis added). The change suggested by SoCal Edison
     would be redundant.[^83]

238. **Temporary Disconnection -- Routine Maintenance, Construction, and
     Repair (Proposed SGIA Article 4.4.2) and Forced Outages (Proposed
     SGIA Article 4.4.3)**[]{#__RefHeading___Toc103479299 .anchor} --
     Proposed SGIA article 4.4.2 would require that the Transmission
     Provider give five Business Days\' notice before interrupting
     interconnection service, curtailing the output of the Small
     Generating Facility, or temporarily disconnecting the Small
     Generating Facility for routine maintenance, construction, and
     repairs. Proposed SGIA article 4.4.3 would give the Transmission
     Provider the right to suspend interconnection service to make
     repairs during forced outages. It would also require the
     Transmission Provider to give the Interconnection Customer written
     documentation to explain the circumstances of the disconnection if
     prior notice was not given. Both provisions would require the
     Transmission Provider to use its best efforts to coordinate
     disconnections, curtailments, and forced outages with the
     Interconnection Customer.

     **Comments**

239. PG&E states that it has thousands of small solar projects
     interconnected with its \"Distribution System\" and requests that
     the five Business Day notice requirement be waived for distribution
     level generators because it would interfere with a Distribution
     System owner\'s ability to work on its facilities.

240. Empire District argues that it should not take five days to shut
     down a Small Generating Facility. If some minimum notice is
     required, it should apply only to Small Generating Facilities
     larger than 2 MW. Empire District also questions the need for an
     \"individual notice\" to every generator and whether it is really
     necessary to notify the operators of small certified units under
     100 kW in size. If individual notifications are required, the
     Interconnection Customer should have a method in place whereby
     \"nearly instantaneous, two-way communication\" (notification and
     verification of receipt of notice) can be made within 24 hours.

241. EEI, PacifiCorp, and Southern Company ask that the term
     \"reasonable efforts\" be used instead of \"best efforts\" in
     Proposed SGIA articles 4.4.2 and 4.4.3, noting that \"reasonable
     efforts\" was used in the ANOPR consensus document.

242. EEI and PacifiCorp ask the Commission to clarify that the
     Transmission Provider must provide written documentation to the
     Interconnection Customer only when the latter requests it.

     **Commission Conclusion**

243. We are not convinced that a five Business Day notice is unduly
     burdensome to the Transmission Provider or that it should apply
     only to Small Generating Facilities larger than 2 MW. Even if PG&E
     has thousands of small solar projects interconnected with its
     Distribution System subject to an OATT, as it states, it is highly
     unlikely that it will ever have to provide notice to all of them
     simultaneously.

244. We agree that the term \"reasonable efforts\" should be used
     instead of \"best efforts\" in the SGIA. We are making this change
     throughout the SGIA.

245. Finally, we are persuaded that written documentation need be
     provided only upon request by the Interconnection Customer, and the
     SGIA reflects this change.

246. **Temporary Disconnection -- Adverse Operating Effects (Proposed
     SGIA Article 4.4.4)**[]{#__RefHeading___Toc103479300 .anchor} --
     Proposed SGIA article 4.4.4 said that after being notified that its
     Small Generating Facility may degrade the reliability of the
     Transmission Provider\'s electric system, the Interconnection
     Customer must be given reasonable time to make necessary
     corrections. If it does not make the corrections within that time,
     the Transmission Provider must provide a second notice to the
     Interconnection Customer stating that the Small Generating Facility
     may be disconnected in five Business Days.

**Comments**

247. Several commenters[^84] contend that the five day notice period is
     unreasonable, restricts the Transmission Provider\'s ability to
     respond to reliability concerns, and could be misinterpreted to
     mean that an Interconnection Customer whose Small Generating
     Facility is causing adverse operating conditions has priority over
     other customers.

248. EEI recommends that the last sentence of Proposed SGIA article
     4.4.4 be revised to read: \"Transmission Provider shall provide
     Interconnection Customer notice of such disconnection within a
     reasonable time period, unless the provisions of article 4.4.1
     \[Emergency Conditions\] apply.\"

249. National Grid states that some form of advance notice and the
     ability to cure is generally reasonable before disconnection;
     however, such steps cannot be mandated all the time. It proposes
     language giving the Transmission Provider the right to take
     unilateral action to avoid service disruptions to other customers
     or damage to facilities caused by the Small Generating Facility.

250. According to Small Generator Coalition, the Transmission Provider
     should notify the Interconnection Customer if, based on sound
     engineering judgment, it concludes that adverse operating
     conditions exist.

> **Commission Conclusion**

251. This article applies only if the Transmission Provider determines
     that the Small Generating Facility [may]{.underline} adversely
     affect its electric system and the Interconnection Customer has
     failed to take the necessary remedial action within the time
     specified by the Transmission Provider. We are not convinced that
     the notice period is too long, could endanger reliability or
     safety, or unnecessarily expose the Transmission Provider to
     liability claims when damage and disruption to its electric system
     is imminent. There could be legitimate reasons for the
     Interconnection Customer not to make the necessary corrections
     within the allotted time (e.g., replacement parts are on back
     order). SGIA article 3.4.1 provides that the Transmission Provider
     may declare an emergency and disconnect the Small Generating
     Facility if there is an imminent threat to its electric system,
     which provides the Interconnection Customer with ample incentive to
     promptly

     resolve any adverse operating effects. Accordingly, we reject the
     request to eliminate the notification period from this article.
     However, we are revising this provision to specify that no notice
     is necessary in order to resolve an Emergency Condition.

252. We agree with Small Generator Coalition that the Transmission
     Provider should immediately notify the Interconnection Customer
     when operation of the Small Generating Facility may cause
     disruption or deterioration of service to other customers and that
     this finding must be based on and supported by sound engineering
     principles. We also stress that all documentation supporting the
     problem must be provided to the Interconnection Customer upon
     request.

253. **Temporary Disconnection -- Modification of the Generating
     Facility (Proposed SGIA Article
     4.4.5)**[]{#__RefHeading___Toc103479301 .anchor} -- Proposed SGIA
     article 4.4.5 would require the Interconnection Customer to secure
     written authorization from the Transmission Provider before making
     any material modification to the Small Generating Facility, or it
     can be disconnected.

**Comment**

254. EEI recommends that the phrase \"material modification\" be
     replaced with \"modification.\" This revised language is used in
     LGIA article 5.19.2.

     **Commission Conclusion**

255. We agree with EEI that the term \"material modification\" could be
     ambiguous. Accordingly, we are revising this article to provide
     that Transmission Provider written approval is required before the
     Interconnection Customer may modify its Small Generating Facility
     in such a way that could materially impact the safety or
     reliability of the Transmission Provider\'s electric system. We are
     also requiring that any modifications be done according to Good
     Utility Practice.

256. **Temporary Disconnection -- Reconnection (Proposed SGIA Article
     4.4.6)**[]{#__RefHeading___Toc103479302 .anchor} -- Proposed SGIA
     article 4.4.6 would require the Parties to cooperate with each
     other to restore the Small Generating Facility, the Interconnection
     Facilities, and the Transmission Provider\'s electric system to
     their normal operating state as soon as reasonably practicable
     following any temporary disconnection.

     **Comments**

257. Southern Company contends that this article should state that
     restoration is required only when the events causing the temporary
     disconnection are over. Small Generator Coalition asks that the
     provision use \"interruption and curtailment\" instead of
     \"reduction.\"

258. In its supplemental comments, Joint Commenters propose the
     following alternative language: \"the Parties shall cooperate with
     each other to restore the Generating Facility, Interconnection
     Facilities, and Transmission Provider\'s Transmission System to
     their normal operating state as soon as reasonably practicable
     following a temporary disconnection.\"

     **Commission Conclusion**

259. We are adopting the proposed language submitted by Joint Commenters
     because it removes unnecessary jargon and simply requires that the
     Parties work to restore normal interconnection service as quickly
     as possible. This language addresses Southern Company\'s and Small
     Generator Coalition\'s concerns as well.

260. **Financial Security Arrangements (Proposed SGIA Article
     5.2)**[]{#__RefHeading___Toc103479303 .anchor} -- Proposed SGIA
     article 5.2 provided that the Interconnection Customer provide
     financial security to the Transmission Provider for the
     construction of Interconnection Facilities or Upgrades through a
     guarantee, surety bond, letter of credit, or other form of credit
     that meets certain standards. The type of financial security
     arrangement and issuing entity would have to be reasonably
     acceptable to the Transmission Provider and have (1) terms and
     conditions that guarantee payment up to an agreed upon amount, (2)
     a reasonable date of expiration, (3) be issued at least 20 days
     before construction, and (4) be consistent with the Uniform
     Commercial Code of the jurisdiction where the Point of
     Interconnection is located.

     **Comments**

261. PacifiCorp argues that this article does not refer to design costs.
     It asserts that this could lead to unnecessary confusion over
     whether design costs should be included with procurement, resulting
     in the burden of design costs falling on the Transmission Provider
     and its customers.

262. Southern Company offers proposed changes to provide protection for
     the Transmission Owner and the Transmission Provider. It asks the
     Commission to delete any references to surety bonds as an
     acceptable form of payment on the grounds that they are not
     specifically mentioned in the OATT and are not generally accepted
     as a form of payment. It also requests that the SGIA state clearly
     that the terms of any letter of credit, guarantee or other security
     must be reasonably acceptable to the Transmission Provider.

263. In an effort to avoid fraudulent conveyance issues or problems with
     the enforcement of any guarantee through bankruptcy procedures,
     Southern Company proposes that the parent of the Interconnection
     Customer (if any) serve as the source of any guarantee,
     specifically excluding affiliates from proposing any guarantee.
     Additionally, any proposed guarantor should have a credit rating of
     BBB+ to protect against rapid credit downgrades.

264. Southern Company also argues that the dollar-for-dollar reduction
     of security as payments are made to the Transmission Provider is
     arbitrary and capricious and imposes risks under bankruptcy and
     fraudulent conveyance law upon the Transmission Provider. At a
     minimum, the Commission should not require that security be reduced
     until the expiration of any potential bankruptcy preference period.
     Southern Company also asks the Commission to clarify that credit
     support is not to be reduced by payments made to the Transmission
     Provider that are unrelated to the actions designated in this
     article. It also proposes the expansion of credit to cover all
     other obligations of the Interconnection Customer under the
     interconnection agreement.

265. Finally, NYTO proposes that the Interconnection Customer
     demonstrate its creditworthiness in its Interconnection Request.

> **Commission Conclusion**

266. We agree with PacifiCorp that design costs are a part of the
     development process that should be covered and are including such a
     provision in the SGIA.

267. While Southern Company opposes using surety bonds as an acceptable
     form of payment, we are following in this Final Rule the same
     approach taken in the LGIA, which states that the Interconnection
     Customer has the right to select a form of security that is
     acceptable to the Transmission Provider and consistent with
     commercial practices.[^85] Because SGIA article 6.3 grants the
     Transmission Provider the discretion to reject a form of security
     (if it is reasonable to do so), we reject Southern Company\'s
     proposal to eliminate the surety bond as an acceptable form of
     credit. Giving the Interconnection Customer a choice of security is
     not unreasonable.[^86] Furthermore, granting the Transmission
     Provider absolute discretion on what forms of security to allow
     would provide too great an opportunity to erect hurdles to new
     small generation.[^87]

268. For the same reasons, we reject Southern Company\'s proposals
     to (1) limit the source of any guarantee to a parent of the
     Interconnection Customer and (2) require any proposed guarantor to
     have a credit rating of BBB+. These are hurdles that could be
     exploited to discourage Small Generating Facilities. The SGIA
     grants the Transmission Provider the discretion to reject a form,
     source, or issuing entity of security only if doing so is
     reasonable. Giving the Transmission Provider absolute discretion on
     these choices would create too great an opportunity for
     exploitation.

269. We are requiring the reduction of the security amount on a
     dollar-for-dollar basis as payments are made because this protects
     the Interconnection Customer against providing too much security
     while ensuring that the Transmission Provider is sufficiently
     protected against its real cost exposure.[^88] We recognize that
     reducing the security as the Interconnection Customer pays its
     bills may cause a small increase in risk to the Transmission
     Provider, but the chilling effect of requiring the Interconnection
     Customer to maintain the full security during the length of the
     interconnection process would seriously discourage new small
     generation.

270. We clarify that credit support is not to be reduced by payments
     made to the Transmission Provider that are unrelated to the actions
     listed in this article. In response to NYTO, we note that the
     Interconnection Customer is already required to give appropriate
     financial guarantees before the Transmission Provider begins
     construction. Thus, the Interconnection Customer need not
     demonstrate its creditworthiness when it submits its
     Interconnection Request.

271. **Milestones (Proposed SGIA Article
     5.3)**[]{#__RefHeading___Toc103479304 .anchor} -- Proposed SGIA
     article 5.3 stated that the Parties are to agree on milestones that
     each Party is responsible for meeting. These milestones are part of
     the interconnection agreement. Article 5.3 further specified that
     if either Party does not meet a milestone, it must compensate the
     other Party for its losses (i.e., pay liquidated damages).

     **Comments**

272. Several commenters ask the Commission to remove references to
     liquidated damages from the SGIA. Others claim that the Commission
     lacks the legal authority to impose liquidated damages.

273. EEI seeks the elimination of this article entirely. The provision
     is vague and confusing because conflicting milestone requirements
     appear in other areas of the Proposed SGIA and Proposed SGIP. NYTO
     contends that Appendix 3 of the Proposed SGIA, which requires the
     Parties to list agreed upon milestones, is unnecessary.

274. Midwest ISO requests that the Commission adopt the same liquidated
     damages clause as in the LGIA. It states that this will make the
     large and small generator tariff provisions consistent.

275. PacifiCorp requests that Proposed SGIA articles 5.3.1 and 5.3.2 be
     deleted. It contends that the accomplishment of milestones should
     be subject to a \"reasonable efforts\" or \"good faith efforts\"
     standard rather than liquidated damages being applied. As a matter
     of policy, good faith efforts should not be penalized, since the
     Transmission Provider does not profit from interconnections.

276. In its supplemental comments, Joint Commenters suggest replacing
     this provision in its entirety. The proposed replacement requires
     the Parties to agree to extend milestone deadlines if the milestone
     was missed in \"reasonable good faith.\" However, the Party
     affected by the failure to meet a milestone is not required to
     agree to an extension if:

     \(1\) it will suffer significant uncompensated economic or
     operational harm from the delay and believes that the delay is not
     or was not unavoidable, (2) attainment of the same milestone has
     previously been delayed, or (3) it has reason to believe that the
     delay in meeting the milestone is intentional or unwarranted
     notwithstanding the circumstances explained by the party proposing
     the amendment.

277. Joint Commenters also suggest making the provision bilateral and
     removing the monetary penalty for missing a milestone.
     Additionally, Joint Commenters would require the Party missing the
     milestone to fully explain to the other Party why the milestone was
     missed. Finally, Joint Commenters propose adding a statement that
     any dispute as to this provision should be resolved according to
     the dispute resolution portions of the SGIA.

     **Commission Conclusion**

278. This Final Rule adopts many concepts proposed by Joint Commenters,
     including the notice provisions and the preference that the Parties
     agree to extend deadlines instead of declaring that the other Party
     has defaulted on the SGIA.

279. Regarding Joint Commenters\' proposal to add a statement regarding
     dispute resolution, such a statement is not needed because the
     SGIA\'s dispute resolution provision applies to the entire
     document.

280. We reject PacifiCorp\'s proposal to delete SGIA milestone
     provisions. These provisions provide a single reference to the
     relevant milestones. They will assist the Parties and will minimize
     disagreements. Removing them would create uncertainty for the
     Parties.

281. Because we are not imposing in this Final Rule a financial penalty
     on the Transmission Provider for missing milestones, there is no
     need to discuss commenters\' arguments on that issue.

282. **Billing and Payment (Proposed SGIA Article
     5.4)**[]{#__RefHeading___Toc103479305 .anchor} -- Proposed SGIA
     article 5.4 would provide that billing and payment obligations are
     to be performed under the terms of the SGIA.

> **Comments**

283. PacifiCorp requests that this article be revised to include billing
     and payment requirements for Distribution Upgrades or Network
     Upgrades. It also states that billing and payment for miscellaneous
     costs, such as restudy costs, should be addressed.

> **Commission Conclusion**

284. We agree with PacifiCorp in part and are revising this article to
     clarify that billing and payment requirements are for Distribution
     Upgrades and Network Upgrades. However, we see no need to identify
     specific miscellaneous costs because the obligations listed in SGIA
     article 6.1 are for services rendered, which already includes such
     costs.

285. **Billing Procedure for Interconnection Facilities Construction
     (Proposed SGIA Article 5.4.1) and Final Accounting (Proposed SGIA
     Article 5.4.2)**[]{#__RefHeading___Toc103479306 .anchor} -- Under
     Proposed SGIA article 5.4.1, the Transmission Provider would bill
     monthly for expenditures for the design, engineering and
     construction of, or for other charges related to, Interconnection
     Facilities. The Interconnection Customer would remit payment within
     30 calendar days after receipt of the bill.

286. Proposed SGIA article 5.4.2 would require that the Transmission
     Provider submit a final accounting report to the Interconnection
     Customer within 45 calendar days after installing the Transmission
     Provider\'s Interconnection Facilities.

> **Comments**

287. PacifiCorp suggests that Proposed SGIA article 5.4.1 also include
     procurement costs. Small Generator Coalition argues that
     alternative arrangements for payment of the bill should be allowed
     if the Parties agree. With respect to Proposed SGIA article 5.4.2,
     numerous commenters[^89] argue that 45 calendar days is not enough
     time for the Transmission Provider to prepare a final accounting
     report. They offer an array of alternative deadlines ranging from
     60 Business Days to 90 days after the Small Generating Facility
     begins commercial operation. BPA complains that there is not a
     similar deadline for any additional payments owed by the
     Interconnection Customer. It proposes that any unpaid bill must be
     paid within 30 days after the bill is submitted by the Transmission
     Provider.

> **Commission Conclusion**

288. We agree with PacifiCorp that procurement costs should be included.
     We are also revising the provision to allow the Parties to make
     other reasonable payment arrangements should they agree to do so,
     as requested by Small Generator Coalition.

289. While we agree with commenters that the proposed deadline for
     submitting the final accounting report may be too short, tying it
     to commercial operation of the Small Generating Facility is
     unrealistic because that event may happen long after construction
     is complete. A more realistic deadline, and one that provides
     sufficient time for the Transmission Provider to compile the
     expenditures and process the final accounting report, is three
     months from the date construction of the facilities is completed.
     We are so revising this provision.

290. BPA is correct that proposed SGIA article 5.4.2 did not include a
     deadline for the Interconnection Customer to pay its final
     accounting bill. We are including in the SGIA 30 calendar days for
     the Interconnection Customer to make payment to the Transmission
     Provider.

291. Finally, we are consolidating Proposed LGIA articles 5.2, 5.3, and
     5.4 because they are so closely related. The new article is
     entitled \"Billing, Payment, Milestones, and Financial Security.\"

292. **Assignment (Proposed SGIA Article
     6.5)**[]{#__RefHeading___Toc103479307 .anchor} -- Proposed SGIA
     article 6.5 would allow the Parties to assign their rights under
     the interconnection agreement to others under certain
     circumstances.

     **Comments**

293. Southern Company contends that the proposed assignment provision
     unreasonably allows one Party to freely assign its rights to an
     affiliate without consent from the other Party. It argues that this
     subjects the Transmission Provider to unnecessary risk from which
     it cannot protect itself by requiring that the assignee have a
     credit rating equivalent to that of the assignor; Transmission
     Providers typically rely on guarantees or letters of credit, which
     are personal to the obligor and would likely not cover the
     assignee. Bureau of Reclamation emphasizes that its policies allow
     assignment of an interconnection agreement only if both Parties
     agree to the assignment and the assignor agrees to remain bound by
     the original terms of the SGIA.

294. Southern Company also argues that it is unreasonable to make the
     Transmission Provider get the Interconnection Customer\'s agreement
     before it can assign the interconnection agreement as collateral,
     while at the same time allowing the Interconnection Customer to
     assign the interconnection agreement as collateral without the
     Transmission Provider\'s permission. Southern Company contends that
     such assignments could unfairly deprive the Transmission Provider
     of the right to require the assignee or purchaser in foreclosure to
     assume the obligations of the assignor and to fulfill performance.
     In addition, the Transmission Provider could lose the right to
     require collateral assignees to cure Defaults of the assignor,
     thereby allowing assignees or purchasers in foreclosure to gain
     greater rights under the interconnection agreement than would have
     been permitted to the original Interconnection Customer. The
     requirement that notice of collateral assignment be provided by the
     secured party, trustee, or mortgagee is unworkable, as there would
     be no enforceable penalties for breach of this obligation. Not only
     do these parties lack contractual privity with the Transmission
     Provider, but they are also not typically subject to Commission
     jurisdiction.

295. Southern Company contends that this article should provide
     Transmission Providers and Transmission Owners indemnification
     rights for any losses, costs, and expenses they may incur in
     connection with assignments or foreclosures. In addition, Southern
     Company seeks clarification of the conditions under which the
     Transmission Provider must recognize foreclosure rights and
     assignments. The provision as written could expose the Transmission
     Provider to uncompensated risks, forcing its native load to bear
     the costs.

296. Small Generator Coalition requests that this article allow the
     Interconnection Customer to assign its rights and obligations under
     the interconnection agreement without consent of the Transmission
     Provider if the Interconnection Customer sells or transfers the
     Small Generating Facility and the real property on which it is
     located.

297. NARUC urges adoption of its Model interconnection agreement
     language, which allows assignment by the Interconnection Customer
     in two situations. First, assignment may be made to a corporation
     or other limited liability entity upon the consent of the
     Transmission Provider. Such consent is not to be withheld unless
     the Transmission Provider \"can demonstrate that the corporate
     entity is not reasonably capable of performing the obligations of
     the assigning Interconnection Customer.\" Second, the
     Interconnection Customer may assign the interconnection agreement
     to a person who is either the \"owner, lessee, or is otherwise
     responsible for the Small \[Generating Facility\].\"

298. In its supplemental comments, Joint Commenters recommend two
     changes to the Proposed SGIA: (1) deleting the sentence requiring
     the assignee to notify the other Party before exercising its
     assignment rights and (2) requiring the assigning Party to give the
     other Party 15 days to object to an assignment.

     **Commission Conclusion**

299. The assignment provision proposed by Joint Commenters is similar to
     the provision in the Small Generator NOPR. However, Joint
     Commenters propose two minor changes that we will adopt. First,
     Joint Commenters propose to remove a very technical sentence
     relating to financing from the provision that is not well suited to
     smaller projects. Second, Joint Commenters require that a Party
     seeking to assign the SGIA merely inform the other Party of the
     pending assignment. Should the Party not object, the assignment may
     go forward. If the Party does object, then the remainder of the
     provision will apply. Making these changes to the assignment
     provision should reduce the administrative burden on the Parties
     without diminishing their substantive rights.

300. In Order No. 2003-A,[^90] the Commission modified the assignment
     provision of the LGIA in order to address Southern Company\'s
     concerns relating to protecting native load customers.  We make
     corresponding changes here, clarifying that (1) an Interconnection
     Customer assigning its rights under the SGIA is required to notify
     the Transmission Provider of the assignment and (2) an assignee is
     responsible for meeting the same insurance and financial security
     obligations as a normal Interconnection Customer upon exercising
     its right of assignment.[^91] This is in addition to a sentence
     specifying that \"an assignment under this provision shall not
     relieve a Party of its obligations . . . .\" We also make various
     editorial changes that make the provision easier to read. Southern
     also requests that a Transmission Provider be allowed to assign the
     interconnection agreement as collateral. We reject that request for
     the same reasons discussed in Order No. 2003-A.[^92]

301. **Insurance (Proposed SGIA Article
     6.16)**[]{#__RefHeading___Toc103479308 .anchor} -- In the Small
     Generator Interconnection NOPR, the Commission asked whether
     insurance should be required for Small Generating Facility
     interconnections and if so, how much. While the Proposed SGIA
     itself contained insurance provisions, the Commission did not
     specify dollar amounts and requested proposals from commenters. The
     Commission also requested comments on three specific issues. First,
     should insurance coverage vary with the size of the facility?
     Should, for example, a 20 MW Small Generating Facility be subject
     to higher coverage amounts than a 10 MW facility, which itself
     would be subject to higher coverage amounts than a 5 MW facility?
     Second, should coverage types and amounts vary according to the
     type of generator so that, for example, solar or wind facilities
     would require different insurance coverage than gas-fired
     facilities? Third, should there be a size cutoff that would exempt
     certain facilities from some insurance requirements?

     **Comments**

302. The NARUC Model, while not requiring insurance, proposes that state
     regulators recommend that every Interconnection Customer \"protect
     itself with insurance or other suitable financial instrument
     sufficient to meet its construction, operating and liability
     responsibilities. . . .\"[^93]

303. NARUC argues that the Commission\'s proposal to require seven
     different types of insurance is excessive and makes federal
     interconnection rules incompatible with state rules. The very act
     of requiring insurance would drive up prices because insurance
     companies would then have a captive market that [must]{.underline}
     have insurance. Workers\' compensation and automobile insurance are
     already required by state law; accordingly, they should not be
     mandated by the federal government. NARUC also asserts that state
     regulators will have more flexibility to assure low insurance rates
     if this Final Rule does not require insurance. Finally, NARUC
     reports that while California requires insurance for most projects,
     the majority of other states (including New York, Texas, and Ohio)
     do not. Therefore, requiring insurance would be inconsistent with
     the practice in most states.

304. NYPSC reports that its own efforts to establish minimum insurance
     requirements were unsuccessful. While it recognizes the risk Small
     Generating Facilities pose to the Transmission Provider, mandatory
     insurance \"created a substantial barrier to the proliferation of
     distributed generation units.\"[^94] The biggest barrier to entry
     is not the cost of insurance (though that is a factor), but the
     fact that insurance is unavailable at any price in many situations.
     Insurance companies are not yet familiar with the risks posed by
     the interconnection of Small Generating Facilities and often will
     not insure them. NYPSC instead proposes allowing the market to
     determine insurance requirements. It reports that the market has at
     least partially responded to this need, creating insurance pools to
     spread the risk to multiple entities. It also notes that
     manufacturers sometimes bundle insurance coverage along with the
     equipment.

305. ISO New England recognizes that smaller generators generally pose
     less risk than larger ones, but argues that the level of risk
     should be evaluated on a case-by-case basis. This Final Rule should
     let an independent Transmission Provider waive the insurance
     requirement if it determines that the project poses little risk to
     its electric system. For many smaller facilities, the liability,
     indemnity, and insurance requirements typically required of larger
     facilities may cost too much. Likewise, MISO supports making the
     amount of insurance required a function of the risk of the
     particular interconnection. However, MISO also supports
     establishing minimum standard insurance requirements (although it
     does not offer specific amounts).

306. Some Transmission Providers[^95] want the Commission to keep the
     proposed insurance limits. Central Maine and NYTO, among others,
     point out that most small projects would not have the financial
     resources to pay any judgment against them and argue that insurance
     is necessary to protect the interests of the Transmission Provider,
     and ultimately, its customers. EEI favors using the same insurance
     limits as the LGIA.

307. AEP also argues that there is no reason why standard insurance
     provisions should be different for a 1 MW facility than for a 20 MW
     facility. Likewise, Allegheny Energy, Central Maine, NYTO, and
     others argue that even a very small generating facility can damage
     the Transmission Provider\'s electric system.

308. Empire District, Nevada Power, NRECA, and PG&E assert that the
     amount of insurance required should vary with generator size. As
     NRECA puts it, \"a residential consumer installing a 3 kW Small
     Generating Facility should not have to acquire \$1 million in
     insurance . . . .\"[^96] Even so, NRECA states that it would oppose
     any attempt to create a minimum megawatt threshold below which
     insurance would not be required.

309. PG&E states that California has long required insurance for all
     projects larger than 10 kW and that this requirement has not
     noticeably dampened the market for on-site Small Generating
     Facilities.

310. While Nevada Power agrees that solar and wind projects present less
     risk than does a traditional gas-fired generator, it opposes
     insurance requirements that differ by fuel type. The market already
     recognizes these reduced risks by charging proportionately less for
     some types of insurance than others. NRECA also opposes
     distinguishing between different fuel types, arguing that this is
     only one of many factors that determine a project\'s risk.

311. In contrast, Tangibl supports basing the required amount of
     insurance on the type of generator being interconnected. It argues
     that the risks posed by Small Generating Facilities are largely
     environmental, such as fuel spills. Tangibl also argues that Small
     Generating Facilities pose less risk than do large generators
     because the former need smaller amounts of fuel to be stored on
     site. This risk is even less for renewable sources such as wind or
     solar.

312. Nevada Power says that knowing how much insurance is going to be
     required at the outset of the project is important to its success.

313. While AEP supports including standard insurance terms in this Final
     Rule, the Parties should be able to negotiate additional terms if
     warranted by the physical characteristics of the project. NRECA
     argues for permitting the Transmission Provider to determine the
     necessary level of insurance on a case-by-case basis.

314. Cinergy also argues for increased flexibility. It would let the
     Transmission Provider reduce or eliminate the required insurance
     provisions on a case-by-case basis if it believes in good faith
     that the full amount of insurance is not required to safeguard its
     interests. Cinergy also argues that this Final Rule should provide
     a mechanism for dealing with insurance requirements that simply do
     not apply to a given generator, such as requiring workers\'
     compensation insurance for a generator that does not have any
     on-site employees.

315. National Grid proposes that the Commission not set required levels
     of insurance, and instead leave it to the Transmission Provider and
     state law. It points out that several states have, or are in the
     process of developing, specific insurance requirements for Small
     Generating Facilities. The Commission should not second-guess the
     attempt of various states to encourage on-site Small Generating
     Facilities. Specifically, National Grid points to a proposal
     developed by a working group of the Massachusetts Public Utilities
     Commission that proposes varying levels of insurance depending on
     the capacity of the project.[^97]

316. NYTO makes a similar request, arguing that the Transmission
     Provider should be allowed to fill in specific insurance amounts
     based on state law, established local practice or, absent those,
     its own business judgment.

317. Avista states that the Parties should be allowed to negotiate
     alternative mechanisms such as self-insurance. It argues that even
     a Transmission Provider facing financial difficulty can always
     raise rates to cover any potential liability. Southern Company also
     proposes revisions to clarify the meaning of this article.

318. NRECA, while it supports the Commission\'s insurance proposal,
     opposes making the provision bilateral. It argues that the
     Transmission Provider\'s operation of its electric system does not
     create any greater risk to the Interconnection Customer than to any
     other customer. The interconnection of the Small Generating
     Facility, on the other hand, increases the risks to the
     Transmission Provider. Furthermore, according to NRECA, most
     Transmission Providers are already required to either self-insure
     or otherwise carry insurance sufficient to cover any liability that
     may arise from operation of their electric systems, so requiring
     further insurance is duplicative.

319. Empire District supports requiring the Transmission Provider to be
     named as an additional insured for generators larger than 5 or 10
     kW, while Avista opposes such a size-related requirement.

320. Avista notes that workers\' compensation requirements vary
     significantly by state. It argues that the Commission should not
     attempt to federally preempt these long-standing practices.
     According to Avista and Nevada Power, the interconnection agreement
     should simply require compliance by each Party with the applicable
     state workers\' compensation laws.

321. Cinergy states that while insurance may be a significant barrier to
     entry for some Interconnection Customers, the Commission should
     heed the insurance market\'s independent assessment of the risk of
     a particular project. Fundamental economic principles require
     Interconnection Customers to bear the costs of the risks they
     impose on third parties, and there is no sound basis for the
     Commission to shift that cost to the Transmission Provider and its
     customers. Nevada Power and NRECA make similar arguments. NRECA
     also argues that if Interconnection Customers do not have
     insurance, insurance companies will be forced to raise the cost of
     insurance for Transmission Providers, and that in turn will be paid
     by all users of the Transmission System.

322. Small Generator Coalition, like most commenters representing Small
     Generating Facilities, argues that purchasing insurance is a
     business decision and that the level and nature of the insurance
     should be established by each business according to its needs, not
     mandated by the federal government. It argues that requiring
     insurance would create a major barrier to small generator
     interconnections and would prevent utility customers (as opposed to
     commercial generation projects) from pursuing interconnection
     because the administrative and financial barriers to entry would
     simply be too great. It asserts that the insurance requirements for
     a small wind turbine should be less than for a nuclear power plant
     or other large generator. Small Generator Coalition is particularly
     vehement in its

     opposition to insurance requirements for projects under 2 MW in
     size. Overall, Small Generator Coalition supports NARUC\'s comments
     and asks the Commission to use the NARUC Model in lieu of the
     Proposed SGIA.

323. Small Generator Coalition states that if the Commission does
     include insurance requirements in its Final Rule, it should exempt
     facilities no larger than 2 MW and require only \$1 million in
     general liability insurance for projects 2 MW or larger.

324. In general, Transmission Providers support requiring an insurance
     regime with larger policy limits and a broad array of coverage.
     Interconnection Customers and NARUC generally support requiring
     smaller amounts of insurance or none at all. Southern Company
     proposes revisions to Proposed SGIA article 6.16.11 to clarify the
     conditions under which one Party must notify the other of accidents
     and injuries arising out of the interconnection agreement.

325. Central Maine proposes requiring the following policies: \$1
     million in employer\'s liability and workers\' compensation
     insurance; \$1 million in Commercial General Liability Insurance
     (with a \$2 million aggregate combined limit); comprehensive
     automobile liability insurance of \$1 million (with a \$2 million
     aggregate combined limit); and an additional \$1 million in excess
     public liability insurance (with a \$5 million aggregate cap).

326. Nevada Power proposes requiring \$1 million in general liability
     coverage from projects greater than or equal to 200 kW and
     \$500,000 if the project is no larger than 200 kW. It also proposes
     requiring excess public liability insurance of \$10 million if the
     facility is greater than or equal to 10 MW in size (\$10 million
     aggregate); \$5 million for projects between 5 and 10 MW (\$5
     million aggregate); \$2 million for projects between 200 kW and 5
     MW (\$2 million aggregate); and none for projects less than 200 kW.

327. Southern Company is in favor of requiring a flat level of coverage
     for all Small Generating Facilities, regardless of size, and
     proposes requiring \$1 million workers\' compensation insurance
     (\$1 million aggregate); \$2 million general liability insurance
     (\$6 million aggregate); \$2 million comprehensive automobile
     liability insurance; and \$10 million excess public liability
     insurance (\$10 million aggregate).

328. Tangibl proposes differing levels of insurance requirements based
     on both size and type of the generator. For solar or wind
     generators, Tangibl proposes requiring \$2 million in insurance for
     facilities larger than 10 MW; non-solar or wind facilities larger
     than 10 MW would maintain \$4 million. However, for facilities no
     larger than 10MW, Tangibl proposes \$500,000 in workers\'
     compensation insurance; \$1 million Commercial General Liability
     Insurance (\$2 million aggregate); \$1 million comprehensive
     automobile insurance (\$1 million aggregate); and \$5 million
     excess public liability insurance (\$5 million aggregate).

329. SoCal Edison urges the Commission to adopt the same insurance
     requirements that the California Public Utilities Commission (CPUC)
     requires, asserting that California\'s extensive experience with
     small generators should serve as a model for the Commission.
     Specifically, California\'s Rule 21 requires general liability
     coverage in the amount of \$2 million for projects larger than 100
     kW; \$1 million for projects larger than 20 kW and no larger than
     100 kW; and \$500,000 for projects no larger than 20 kW. Rule 21
     also creates a special reduced insurance requirement of \$200,000
     for facilities no larger than 10 kW associated with a retail
     customer. Rule 21 exempts some classes of solar and wind generators
     from its insurance requirements entirely, and provides for waiver
     of the insurance requirements for some small residential
     interconnections if insurance is not easily obtainable.

330. In its supplemental comments, Joint Commenters proposes requiring
     the Interconnection Customer to maintain insurance in an amount
     \"sufficient to insure against all reasonably foreseeable direct
     liabilities given the size and nature of the generating equipment
     being interconnected, the interconnection itself, and the
     characteristics of the system to which the interconnection is
     made.\" It also specifies that the provision shall not require the
     Interconnection Customer to obtain additional insurance if the
     insurance it already has is sufficient. The Interconnection
     Customer is required to document its insurance coverage no later
     than ten days before the anticipated commercial operation date of
     the Small Generating Facility, and afterwards as requested by the
     Transmission Provider. The proposed provision also allows the
     Interconnection Customer to self insure when appropriate and
     requires the Transmission Provider to maintain insurance
     \"consistent with the Transmission Provider\'s commercial
     practice.\" While Joint Commenters were able to reach consensus on
     the insurance requirement for most Small Generating Facilities,
     they were not able to reach consensus on the issue of insurance
     requirements for inverter-based generators no larger than 10 kW.

     **Commission Conclusion**

331. The wide range of insurance recommendations points out the
     difficulties in establishing a set dollar amount or type of
     insurance appropriate to every Small Generating Facility. Insurance
     can add significant costs to a Small Generating Facility and may
     affect the project\'s economic feasibility. Nevertheless, a
     mismanaged interconnection can harm the Transmission Provider\'s
     electric system and affect power customers, potentially subjecting
     the Parties to liability.

332. We adopt in its entirety Joint Commenters\' proposal, which
     reflects appropriate compromises regarding this diversity of
     insurance needs. We are pleased that such a diverse group of
     stakeholders could reach consensus on this difficult issue.

333. The level of risk in interconnecting a 50 kW photovoltaic system
     with the Transmission Provider\'s Transmission System is very
     different from the risk involved in interconnecting a 10 MW
     generator. Mandating that the Interconnection Customer maintain a
     reasonable amount of insurance based on the specific
     characteristics of its interconnection avoids the
     one-size-misfits-all problem and addresses the differing needs of
     different Interconnection Customers and Transmission Providers.

334. Joint Commenters, however, could not reach consensus on any
     insurance provision for certified inverter-based generators no
     larger than 10 kW. Commenters have convinced us that the risk of
     interconnecting these small inverter-based generators is low and we
     therefore decline to impose a generic insurance requirement in this
     Final Rule.[^98] Instead, we adopt the approach proposed by NARUC
     which is that each Party be required to \"follow all applicable
     insurance requirements imposed by the state in which the Point of
     Interconnection is located. All insurance policies must be
     maintained with insurers authorized to do business in that state.\"
     Given that most generators of this size and type will be
     interconnecting with state-jurisdictional facilities, it makes
     sense to coordinate our approach with the approach recommended by
     NARUC. This will also avoid forum shopping. This is also similar to
     the approach adopted in Order No. 2003-A, which deferred to state
     insurance laws rather than imposing specific dollar amounts for
     these types of insurance.[^99]

335. However, because any uninsured risk will fall squarely on the
     Transmission Provider\'s customers, who would effectively subsidize
     the costs of the interconnection, we reject proposals that we
     completely waive insurance requirement. Several commenters also
     advise the Commission to leave the issue of insurance to state
     regulators. While this

     makes sense for small inverter-based generators, for larger Small
     Generating Facilities, having insurance requirements vary by state
     would hamper our effort to promulgate national small generator
     interconnection standards.

336. Cinergy asks that the Transmission Provider be allowed to waive or
     reduce insurance requirements for a given project if it concludes
     that it poses little risk to its electric system. The provision
     proposed by Joint Commenters would allow this type of flexibility.
     If the Parties agree that the interconnection is safe, then they
     can agree that insurance is not necessary. However, Transmission
     Providers must waive or reduce the insurance requirements on a
     non-discriminatory basis that does not favor affiliated facilities.

337. We also clarify that an RTO or ISO may propose additional or
     different insurance requirements under the independent entity
     variation provision contained in this Final Rule.

338. **Reservation of Rights (Proposed SGIA Article
     6.20)**[]{#__RefHeading___Toc103479309 .anchor} -- Some commenters
     pointed out that Proposed SGIA article 6.20 contained a
     typographical error, which we are correcting.

339. **Signatures and Parties to the SGIA (Proposed SGIA Article
     9)**[]{#__RefHeading___Toc103479310 .anchor} -- Proposed SGIA
     article 9 required both the Transmission Provider and the
     Transmission Owner to sign the interconnection agreement. This is
     the same approach taken in Order No. 2003.[^100] In an RTO or ISO
     where the Transmission Provider is not the Transmission Owner, the
     RTO\'s or ISO\'s compliance filing may propose a modified
     interconnection agreement that provides the Transmission Provider
     and Transmission Owner different rights and obligations.

     **Comments**

340. ISO New England supports the approach taken in Order No. 2003,
     allowing Transmission Owners and Transmission Providers to propose
     a modified interconnection agreement when the Transmission Provider
     is an entity distinct from the Transmission Owner. It contends that
     this approach is necessary if the Commission wishes to establish a
     single interconnection agreement for a region encompassed by an RTO
     or ISO.

341. NYISO argues that the SGIA should assign certain basic
     responsibilities to either the Transmission Owner or Transmission
     Provider.

342. Midwest ISO asserts that it is the RTO\'s role as an independent
     entity \"to ferret out unnecessary studies or inappropriate
     contingencies.\"[^101] However, it argues that the \"NOPR\'s
     failure to fully distinguish between a transmission provider and
     transmission owner belies the independence of the RTO,\"[^102] and
     both it and other commenters[^103] request clarification of the
     respective roles of the RTO and the Transmission Owner.

343. National Grid argues that defining \"Transmission Provider\" to
     include both the Transmission Provider and the Transmission Owner
     confuses the issue and adds ambiguity into the interconnection
     process. The Commission should clearly define the role of each
     Party. National Grid also notes that the Small Generator
     Interconnection NOPR did not account for the role of stand-alone
     distribution companies.

344. Central Maine asks the Commission to clarify that the Transmission
     Owner (or distribution company, where applicable) must sign the
     interconnection agreement and to clarify whether the Transmission
     Provider needs to be a Party to the agreement. It asserts that the
     division of functions between the Transmission Owner and the
     Transmission Provider varies by region and depends on the role that
     the RTO or ISO plays in the region. A request for interconnection
     with a Distribution System may require that a distribution company
     be a Party to the interconnection agreement, in lieu of a
     Transmission Owner or Transmission Provider. Central Maine
     concludes that the standard interconnection agreement resulting
     from this proceeding must ultimately be a contract between the
     Interconnection Customer and the entity that owns the Transmission
     System (i.e., the Transmission Owner or the distribution company).

345. In RTO or ISO regions, if the Commission determines that the
     Transmission Provider must also sign the interconnection agreement,
     Central Maine asks the Commission to clarify that, under section
     205 of the FPA, the Transmission Owner has the right to file the
     agreement, consistent with [Atlantic City Electric Co., et al. v.
     FERC]{.underline}, 329 F.3d 856, 858-59 (D.C. Cir. 2003)
     (explaining that while an ISO may have certain FPA section 205
     rights, the individual utility also has FPA section 205 rights).
     Central Maine also says that the Transmission Owner, not the
     Transmission Provider, has the right to file executed or unexecuted
     interconnection agreements.

346. In lieu of requiring the signatures of both the Transmission Owner
     and the Transmission Provider, EEI contends that the Commission
     should require the signature only of the Transmission Owner.
     Additionally, the Commission should encourage ISOs and RTOs with
     operational roles that cause this distinction to clearly delineate
     the rights and responsibilities in their operations agreements and
     protocols. The interconnection agreement can specifically refer to
     the OATT already approved by the Commission, thereby eliminating
     the need to have both a separate agreement between the Transmission
     Provider and the Interconnection Customer and a three-party
     agreement.

347. PG&E argues that RTOs and ISOs do not need to become Parties to
     interconnection agreements for distribution level projects because
     such entities only operate transmission systems. These entities
     have very little interest in the smallest projects interconnected
     with Distribution Systems and therefore, should not be the ones to
     receive Interconnection Requests or maintain the queue for
     distribution level interconnections. The Commission should
     designate the distribution provider to fulfill these roles.

348. NYTO asserts that since an independent RTO or ISO has no right to
     bind a Transmission Owner, the RTO or ISO should not sign the
     interconnection agreement.

     **Commission Conclusion**

349. As in Order No. 2003, we are requiring three-party agreements in
     areas where the Transmission Provider and Transmission Operator are
     different entities.[^104] In other regions of the country where the
     Transmission Provider and the Transmission Owner are the same
     entity, there is no need for a second signature block.[^105]

350. Given that RTOs and ISOs have distinct characteristics and
     challenges, we have permitted each RTO or ISO to propose, on
     compliance, an interconnection procedures document and agreement
     tailored to its individual needs.[^106] Such proposals should
     allocate to each entity the appropriate rights and obligations. As
     the Order No. 2003 compliance process demonstrated, the
     Transmission Provider and Transmission Owner are capable of
     dividing responsibility among themselves.

351. Finally, Central Maine asks the Commission to specify that, under
     section 205 of the FPA, the Transmission Owner, not the
     Transmission Provider, must file the interconnection agreement.
     This is an issue better resolved on a case-by-case basis through
     the compliance process. It would be premature to conclude that in
     all circumstances the Transmission Owner, and not the Transmission
     Provider, has the right to file the interconnection agreement.

352. **Liability**[]{#__RefHeading___Toc103479311 .anchor} -- In the
     Proposed SGIA, the Commission proposed including provisions in the
     SGIA governing the apportionment of liability between the Parties.
     These provisions (indemnity, consequential damages, and Force
     Majeure) were similar to the provisions in the LGIA. The Commission
     requested comments on whether Small Generating Facilities should be
     treated differently from Large Generating Facilities with respect
     to liability. We discuss our general approach to the liability
     provisions first, followed by a more detailed discussion of each
     provision.

     **General Approach**[]{#__RefHeading___Toc103479312 .anchor}

     **Comments**

353. In general, Transmission Providers support liability provisions
     similar to those in the LGIA, arguing that interconnecting a Small
     Generating Facility raises as many safety and reliability issues as
     interconnecting a Large Generating Facility.[^107]

354. Small Generator Coalition and NARUC generally argue that these
     provisions should be tailored specifically to Small Generating
     Facilities, arguing that the Proposed SGIA was simply too
     complicated for many Small Generating Facilities. They first argue
     that a Small Generating Facility poses less danger to the
     Transmission Provider\'s electric system than a Large Generating
     Facility. Second, they argue that imposing liability provisions
     similar to those in the LGIA on Small Generating Facilities would
     be a major financial barrier to entry and deter the development of
     new Small Generating Facilities. Third, they point out that the
     Transmission Provider has an incentive to include onerous liability
     provisions in the SGIA to deter competition.

355. ISO New England similarly argues that Small Generating Facilities
     do not present the same risks as do Large Generating Facilities. It
     asks the Commission to permit independent entities to determine, on
     a case-by-case basis, whether to waive or relax the liability
     provisions for individual generators.

356. Avista asks the Commission to follow [Midwest Independent System
     Operator, Inc., et al]{.underline}., 100 FERC ¶ 61,144 (2002),
     which allows the Parties to propose customized liability
     limitations. It argues that the August 14, 2003 Northeast Blackout
     is evidence of the need for a comprehensive look at liability
     limitations. Avista argues that the interconnection agreement
     should have a savings clause to let an RTO conform the liability
     and dispute resolution provisions (and possibly others) to the
     standards and procedures being implemented by the RTO. Otherwise,
     the Commission\'s rule could unnecessarily grandfather inconsistent
     provisions.[^108] For example, the Agreement Limiting Liability
     Among Western Interconnected Systems (\"WIS Agreement\")[^109]
     should continue to be an option for generators and utilities.
     Avista argues that the SGIA should have a savings clause for the
     WIS Agreement.

     **Commission Conclusion**

357. Many commenters, including NARUC and independent entities like ISO
     New England, agree that the Commission should modify the proposed
     liability provisions for Small Generating Facilities in this Final
     Rule. We agree that the provisions can generally be simplified
     without increasing the liability of any Party. The liability
     provisions adopted here use many of the proposals made by NARUC and
     other commenters. They address the Transmission Provider\'s need to
     protect its electric system while removing unreasonable barriers to
     entry for Interconnection Customers.

358. We agree with ISO New England that an independent Transmission
     Provider (via the independent entity variation standard) may
     propose on compliance to evaluate each Interconnection Request on a
     case-by-case basis and fashion liability requirements that are
     suitable to that particular entity.

359. We deny Avista\'s request for caps on the amount of liability the
     Transmission Provider may be subject to, or that we allow it to
     develop its own liability rules.[^110] The liability rules
     discussed in the interconnection context are distinct from the
     liability rules in the rest of the OATT.[^111] In the
     interconnection context, the indemnity provision is two-sided (or
     three-sided, in the case of an independent Transmission Provider).
     This means that the indemnity provisions found in the SGIA are very
     different than the indemnity provisions found in the OATT. Many of
     Avista\'s comments have more to do with the liability provisions
     found in the transmission portions of the OATT than they do with
     interconnection. While we agree that liability protection is
     important, this rulemaking is not the place to decide such an
     issue. We also deny Avista\'s request to insert a savings clause
     into the liability provision. Avista has not explained how the
     Transmission Provider\'s participation in the WIS Agreement would
     be affected by this Final Rule. If Avista wishes, it may seek to
     include such a provision on compliance under the \"consistent with
     or superior to\" standard.

     **Consequential Damages (Proposed SGIA Article
     6.19**)[]{#__RefHeading___Toc103479313 .anchor}

360. Proposed SGIA article 6.19 used the LGIA consequential damages
     provision, which states that neither Party is liable to the other
     for special or consequential damages except as expressly provided
     for in the interconnection agreement.

     **Comments**

361. Central Iowa Coop is concerned that the phrase \"\[o\]ther than as
     expressly provided for in this agreement\" could make the Parties
     subject to consequential damages when read in conjunction with the
     indemnification provision in Proposed SGIA article 6.13. It asks
     the Commission to clarify that the bar against consequential
     damages applies in all circumstances, except when the Parties have
     reached an express agreement to the contrary.

362. Central Maine asks the Commission to clarify that indemnity
     payments to a third party are not consequential damages.

363. NARUC proposes that the Commission adopt its Model language, which
     is less complicated than the proposed provision. Specifically,
     NARUC proposes replacing Proposed SGIA article 6.19 with a generic
     statement at the beginning of the liability article:

> Each Party\'s liability to the other Party for any loss, cost, claim,
> injury, liability, or expense, including reasonable attorney\'s fees,
> relating to or arising from any act or omission in its performance of
> this agreement, shall be limited to the amount of direct damage
> actually incurred. In no event shall either Party be liable to the
> other Party for any indirect, special, consequential, or punitive
> damages of any kind whatsoever.

**Commission Conclusion**

364. We retain the provision as proposed. This is a contractual term and
     no commenter has convinced us that it is necessary to deviate from
     the approach taken in Order No. 2003.

365. Several commenters appear to have misunderstood the relationship
     between the indemnity and consequential damages provisions in the
     Proposed SGIA. The bar against consequential damages does not apply
     in the indemnity context. Instead, the indemnification of one Party
     by another is comprehensive, and the indemnifying Party is
     responsible for all of the indemnified Party\'s costs, regardless
     of whether those costs are compensatory or punitive. While the
     consequential damages provision adopted in this Final Rule prevents
     one [Party]{.underline} from seeking consequential damages against
     [another Party]{.underline}, the purpose of the indemnification
     provision is different; it protects the indemnified Party from
     liability to third parties (those who are not Parties to the
     interconnection agreement). Requiring the indemnifying Party to
     reimburse the indemnified Party for, say, only compensatory damages
     and not punitive damages would not make the indemnified Party
     whole. We are adding language to the beginning of the indemnity
     section to make this clear.

     **Indemnity (Proposed SGIA Article
     6.13)**[]{#__RefHeading___Toc103479314 .anchor}

366. Indemnification is compensating another for a loss suffered due to
     a third party\'s act or default.[^112] The Proposed SGIA contained
     indemnity provisions similar to those contained in the LGIA. The
     proposal would require the Transmission Provider and the
     Interconnection Customer to indemnify each other for any damages,
     losses, claims, and obligations by or to third parties arising from
     performance of the Transmission Provider\'s or Interconnection
     Customer\'s obligations under the interconnection agreement on
     behalf of the other contracting party. Indemnity protection would
     include the amount of the indemnified Party\'s loss, net of any
     insurance recovery, but would not apply where there is gross
     negligence or intentional wrongdoing. The proposed provision also
     set forth detailed procedures for pursuing an indemnity claim and
     allowed recovery of legal costs in some cases.

**Comments**

367. AEP, BPA, Idaho Power, and Nevada Power generally agree that Small
     and Large Generating Facilities should be treated consistently with
     respect to indemnity protections.

368. Central Iowa Coop, Georgia Transmission, and NYTO request that the
     Commission replace the mutual indemnity provision with a one-way
     indemnity provision in favor of the Transmission Provider. They
     argue that the Transmission Provider receives no benefit from an
     interconnection, but does face additional safety, reliability, and
     power quality concerns as a result of it. To require the
     Transmission Provider to indemnify the Interconnection Customer
     unfairly shifts the costs and risks to the Transmission Provider\'s
     other customers.

369. Central Maine contends that Proposed SGIA article 6.13 should not
     exclude \"insurance or other recovery\" from amounts owed to an
     indemnified party. It argues that this is commercially unreasonable
     and undermines the very intent of the indemnity provision.

370. ISO New England argues that applying the liability provisions
     contained in the LGIA to Small Generating Facilities is
     unreasonable because the risks associated with interconnecting the
     latter are not comparable to those associated with interconnecting
     Large Generating Facilities. The Commission should permit
     independent entities such as RTOs and ISOs to determine, on a
     case-by-case basis, whether a waiver or relaxation of the indemnity
     provisions used for Large Generating Facilities should be permitted
     based on the actual risk the Small Generating Facility presents.
     Permitting this type of flexibility would minimize the cost of
     interconnection and ensure adequate protection for the Transmission
     Provider.

371. Southern Company argues that the proposed indemnity provision is
     not workable. The provision requires each Party to indemnify the
     other for damages arising out of such other Party\'s \"performance
     of obligations under this Agreement on behalf of the indemnifying
     Party.\"[^113] It argues that it is unclear whether the indemnity
     provision would ever apply because the Parties do not perform
     obligations on behalf of each other at all. It proposes that each
     Party indemnify the other from any liabilities or damages resulting
     from activities on the indemnifying Party\'s own side of the point
     of change of ownership. Additionally, each Party should indemnify
     the other for the indemnifying Party\'s failure to adhere to
     operating requirements and for breaches of the interconnection
     agreement. Southern Company also takes issue with the provision\'s
     limitation of expenses paid for the legal defense of an indemnified
     Party. If an indemnified Party has additional legal defenses, the
     proposed article requires the indemnifying Party to pay for only
     one attorney.[^114] Southern Company requests that the Commission
     revise the provision to require the payment of the indemnified
     party\'s reasonable legal expenses.

372. In its Model interconnection agreement, NARUC proposes a different
     approach to indemnity. There, the Transmission Provider and the
     Interconnection Customer would assume liability and indemnify each
     other for claims and expenses resulting from their own negligence
     as it relates to the design, construction, and operation of their
     facilities. A Party indemnifies the other only for claims brought
     by claimants who could directly recover from the Party itself.
     Indemnity for both Parties includes monetary losses, reasonable
     legal fees for defending a third party action, damages related to
     the death/injury of a third party, damages to the Party\'s property
     or property of a third party, and damages for disruption of a third
     party\'s business. Neither the Transmission Provider nor the
     Interconnection Customer assumes liability for consequential,
     special, incidental, or punitive damages, and neither is
     responsible for disruption of the other\'s business or for the
     costs and expenses of pursuing legal action against the other.

**Commission Conclusion**

373. We are adopting a streamlined indemnity provision in this Final
     Rule.

374. Several commenters appear to have misunderstood the relation
     between the proposed indemnity provision and the bar against
     consequential damages provision (now called Limitation of
     Liability). We are therefore including in the SGIA an explanation
     that claims under the indemnity provision are exempt from the bar
     against consequential damages contained in the Limitation of
     Liability provision.

375. Many of the comments addressing indemnity are identical to those
     addressed in Order No. 2003 and do not argue that Small Generating
     Facilities should be treated differently from Large Generating
     Facilities. We will not repeat the discussion in those orders. For
     instance, the Commission addressed comments about the bilateral
     nature of the provision in Order No. 2003 at P 637, and comments on
     which side of the Point of Interconnection work is conducted in
     Order No. 2003 at P 638.

376. Because the purpose of indemnification is to pay another for actual
     losses, the exclusion of \"insurance or other recovery\" from
     amounts owed to an indemnified Party does not undermine the intent
     of this provision, as Central Maine argues. Forcing an indemnifying
     Party to pay damages already covered under an insurance policy
     would allow the indemnified Party to profit at the expense of the
     indemnifying Party. Excluding insurance and other recoverable
     amounts avoids overcompensating an indemnified Party.

377. In response to Southern Company\'s request that the provision cover
     an indemnifying Party\'s failure to meet operating requirements or
     its breach of the SGIA, we note that it covers damages from actions
     or inactions under the interconnection agreement. However, in
     response to Southern Company\'s comments, we are modifying the
     provision to add: \"arising out of or resulting from the other
     Party\'s actions or failure to meet its obligations under this
     SGIA.\"

     **Force Majeure (Proposed SGIA Article
     6.14**)[]{#__RefHeading___Toc103479315 .anchor}

378. Proposed SGIA article 6.14 provided that no Party is considered to
     be in default with respect to contractual obligations, other than
     payment of money due, if it is prevented from fulfilling such
     obligations by a Force Majeure event. The affected Party is to
     exercise due diligence to remove the disability and provide
     adequate notice to the other Party. These provisions are consistent
     with those in the LGIA. The Commission requested comments
     concerning whether a different approach should be taken for Small
     Generating Facilities.

     **Comments**

379. AEP, BPA, Idaho Power, and Nevada Power generally agree that all
     generating facilities should be treated the same with respect to
     Force Majeure. AEP argues that because Force Majeure can happen for
     either type of interconnection, there is no reason that the
     contractual protection should differ according to generator size.
     Nevada Power contends that consistent treatment does not interfere
     with having a simplified and expedited interconnection process for
     Small Generating Facilities.

380. While NARUC\'s Model and the Proposed SGIA included similar Force
     Majeure clauses, NARUC recommends that the Commission remove the
     statement that economic hardship is not considered a Force Majeure
     Event. It also proposes that the Commission require that an
     affected Party use \"reasonable efforts\" instead of \"due
     diligence\" to resume

     its performance as soon as possible. Additionally, NARUC proposes
     changing the definition of Force Majeure to include events that
     \"the affected Party is unable to prevent or provide against by
     exercising reasonable diligence.\"[^115]

     **Commission Conclusion**

381. We agree with NARUC that some modification to the Proposed SGIA is
     needed and we are adopting a Force Majeure clause that melds the
     best aspects of NARUC\'s and the Commission\'s proposals. For
     instance, this Final Rule provision allows the Party asserting the
     Force Majeure Event to call or write to the other Party to make the
     required notification. Easy notification ensures that both Parties
     know of a Force Majeure Event as soon as possible.

382. We are not adopting all of NARUC\'s proposals, however. The NARUC
     Model would not allow a Party to invoke Force Majeure if it could
     have prevented the event through the exercise of \"reasonable
     diligence.\" Our SGIA uses the terms \"negligence\" and
     \"intentional wrongdoing,\" which are commonly accepted legal
     terms.

383. Finally, we are moving the definition of Force Majeure Event to the
     body of the SGIA from an appendix.

384. **Reactive Power**[]{#__RefHeading___Toc103479316 .anchor} **--**
     The Proposed SGIA did not include a separate provision for reactive
     power; however, the LGIA does.

     **Comments**

385. CA ISO and Southern Company ask the Commission to include a
     provision for reactive power in the interconnection agreement. CA
     ISO argues that this provision is essential for the reliability of
     the Western Interconnection because the entire region is afflicted
     by voltage instability. A Small Generating Facility interconnecting
     at the transmission level should meet the reactive power
     requirements of the CA ISO tariff and abide by reactive power
     dispatch instructions from the control area operator. Moreover, a
     Small Generating Facility interconnecting at the \"distribution\"
     level should meet reactive power requirements specified in the
     Wholesale Distribution Access Tariff and abide by any reactive
     power dispatch instructions from the Distribution System operator.

386. Southern Company notes that the LGIA has a reactive power provision
     and argues that one should be included in the SGIA as well.
     Otherwise, a Small Generating Facility could become a burden on the
     Transmission Provider\'s electric system. The Transmission Provider
     should be provided real-time information on the status and output
     of each generator to ensure safe and reliable operation.

     **Commission Conclusion**

387. We are requiring the Interconnection Customer\'s Small Generating
     Facility to maintain a power factor within the range of 0.95
     leading to 0.95 lagging, unless the Transmission Provider
     establishes and the Commission approves different requirements that
     apply to all similarly situated generators. There is no reactive
     power requirement for wind powered Small Generating Facilities.

388. **Generator Balancing Requirements**[]{#__RefHeading___Toc103479317
     .anchor} **--** The Proposed SGIA did not include a separate
     generator balancing provision.

     **Comment**

389. Southern Company argues that the SGIA should include provisions for
     generator balancing service, and presents several arguments in
     support of its position.

     **Commission Conclusion**

390. In Order No. 2003-A, the Commission determined that generator
     balancing service is more closely related to delivery service than
     to interconnection service, and because delivery service
     requirements are addressed elsewhere in the OATT, the balancing
     service requirement need not appear in the interconnection
     agreement. On rehearing, the Commission in Order No. 2003-B did not
     add a generator balancing service provision to the LGIA, but it did
     permit the Transmission Provider to include a provision for
     generator balancing service in individual interconnection
     agreements. We reach the same conclusion here.[^116] Any such
     provision should be tailored to the Parties\' specific
     circumstances and is subject to Commission approval.

391. **Appendices to the SGIA**[]{#__RefHeading___Toc103479318 .anchor}
     **--** The Proposed SGIA included five appendices (called
     attachments in the Final Rule SGIA) that set forth technical and
     operating information, including: (1) a description and statement
     of the costs of the Small Generating Facility, Interconnection
     Facilities, and metering equipment; (2) a one-line diagram
     depicting the Small Generating Facility, Interconnection
     Facilities, metering equipment and Upgrades; (3) project
     milestones; (4) additional operating requirements for the
     Transmission Provider\'s electric system and Affected Systems
     needed to support the Interconnection Customer\'s needs; and (5)
     the Transmission Provider\'s description of its Network Upgrades
     and Distribution Upgrades and a best estimate of their costs.

**Comments**

392. Central Maine and NYTO state that these appendices would require
     information that is not needed. They ask that the appendices
     include only: (1) Small Generating Facility description, (2)
     one-line diagram, (3) description of the Interconnection
     Facilities, (4) operation and maintenance (O&M) costs, and (5)
     operating procedures. They state that additional operating
     procedures may have to be developed with input from the
     Transmission Owner and the Interconnection Customer to ensure
     system integrity and reliability.

     **Commission Conclusion**

393. We are not persuaded that any change in the appendices is
     warranted. With the exception of O&M costs, all the items that
     Central Maine and NYTO would have us include in the appendices are
     already there. We agree with Central Maine and NYTO that additional
     operating procedures with input from both the Transmission Provider
     and the Interconnection Customer may be needed, and we encourage
     such efforts. The treatment of O&M costs is discussed in more
     detail in Part II.H below (Responsibility for Operation and
     Maintenance Costs).

     **G. The 10 kW Inverter Process**[]{#__RefHeading___Toc103479319
     .anchor}

394. In the Small Generator Interconnection NOPR, the Proposed SGIP
     included a default interconnection Study Process for Small
     Generating Facilities and a simplified procedure that used
     technical screens for certified Small Generating Facilities no
     larger than 2 MW. The Proposed SGIA, however, would be used for the
     interconnection of all Small Generating Facilities, up to and
     including 20 MW in size. The NOPR did not include a separate
     procedures document or interconnection agreement for very small
     generators, although some commenters urged, in comments submitted
     in response to the ANOPR, that 0-50 kW facilities (especially
     facilities that use inverters to convert the direct current output
     of the generator to alternating current) need a separate and
     simpler process than other generators.

**Comments**

395. Some commenters argue that the Proposed SGIP and Proposed SGIA are
     too complicated for very small Interconnection Customers. Small
     Generator Coalition states that unless the Commission is willing to
     modify the NOPR in fundamental ways, many of its members believe
     that development of Small Generating Facilities would be better
     served if the NOPR were simply withdrawn. It claims that, under the
     Proposed SGIP and Proposed SGIA, the only method by which even a
     small photovoltaic system, say 10 kW, could interconnect with the
     Transmission Provider is to follow the same process that would
     apply to generators 1,000 times larger. It asks the Commission to
     \"recognize the simplicity of the very smallest generators and
     \[to\] include an exception for small inverter-based systems.\"
     Plug Power, also representing small generator interests, states
     that a special process should be adopted for very small generators
     because their interconnection requirements are fundamentally
     different from those of larger facilities. Moreover, adopting
     simpler requirements would foster the growth of \"plug and play\"
     equipment.

396. NRECA, which represents a wide variety of cooperative utilities
     that interconnect with small generators, states that it has adopted
     special procedures for evaluating very small generators because
     they generally interconnect at low voltage and have different
     technical requirements from larger ones.

397. Some state regulatory authorities already have a simplified process
     for very small generators. NJ BPU points out that it has adopted
     simplified procedures for qualified very small inverter-based
     generators. NARUC, in its updated Model, supports a simplified
     Interconnection Request (application) for very small generators.

398. Joint Commenters submits in its supplemental comments a streamlined
     process for certified inverter-based generators no larger than 10
     kW. This consists of a simplified Interconnection Request,
     simplified procedures, and a brief set of terms and conditions
     (that is essentially a highly simplified interconnection agreement
     ) -- all contained in a single document. This Joint Commenter
     proposal consists of the following steps: (1) the Interconnection
     Customer completes an abbreviated Interconnection Request and signs
     the terms and conditions when it submits its Interconnection
     Request to the Transmission Provider; (2) the Transmission Provider
     uses the Fast Track Process technical screens to evaluate the
     Interconnection Request; (3) if the proposed interconnection passes
     the technical screens, the Transmission Provider approves the
     application; (4) once the Interconnection Customer\'s equipment has
     been installed, it sends a certificate of completion to the
     Transmission Provider; and (5) the Transmission Provider then
     inspects the equipment installation and, if satisfied that it is
     safe for operation, authorizes the interconnection.

**Commission Conclusion**

399. The comments demonstrate a near universal agreement of the need for
     special provisions for very small generators, a need that is being
     met at least in part by some state regulatory authorities. We agree
     with the commenters who state that the Proposed SGIP and Proposed
     SGIA are too complicated for very small generators, and we
     recognize the desire to accommodate their interconnection needs.
     However, a single document tailored for the needs of the smallest
     generators would be unsuitable for the interconnection of larger
     small generators; their technical evaluations and their legal
     rights and responsibilities must be set out in greater detail.

400. We conclude that a balanced response to the comments is to issue
     two sets of documents -- an SGIP and SGIA that serve the needs of
     most small generators, and a simplified document that meets the
     needs of very small generators.

401. Joint Commenters\' proposed process for the interconnection of very
     small generators, which enjoys broad support from a variety of
     stakeholder interests, is simple to implement while ensuring the
     safety and reliability of the Transmission Provider\'s electric
     system. Accordingly, we are adopting it in this Final Rule with
     minor modification under the name \"10 kW Inverter Process.\" The
     simplified 10 kW Inverter Process consists of an Interconnection
     Request, simplified procedures, and a brief set of terms and
     conditions applicable to inverter-based 0-10 kW generators. It is
     included as Attachment 5 to the SGIP. This \"all-in-one\" document
     combines the attributes of both an interconnection procedures
     document and an interconnection agreement. We are including it in
     the SGIP because it is the SGIP that the Interconnection Customer
     will first encounter in the process of interconnecting its Small
     Generating Facility with the Transmission Provider. A flowchart
     showing the 10 kW Inverter Process may be found in Appendix D of
     this Final Rule.

402. The 10 kW Inverter Process is user friendly and a straightforward
     interconnection should be accomplished in short order. To
     accelerate the process, by signing the application at the time of
     submission, the Interconnection Customer executes what essentially
     is an interconnection agreement, in the form of standard terms and
     conditions with which it agrees. This eliminates the additional
     step of signing an interconnection agreement if the proposed
     interconnection passes the screens.

403. The 10 kW Inverter Process, by its very name, applies only to
     equipment that is interconnected with the Transmission Provider\'s
     electric system through an inverter. Inverter-based equipment has a
     very small likelihood of causing safety and reliability concerns on
     the Transmission Provider\'s electric system because it can quickly
     disconnect from the electric system when a disturbance occurs.
     Nonetheless, while the 10 kW Inverter Process should facilitate the
     interconnection of this class of Small Generating Facilities, the
     technical requirements for interconnection are just as rigid as
     those for all Small Generating Facilities up to 2 MW in size that
     elect to use the Fast Track Process. Specifically, they must be
     certified by a Nationally Recognized Testing Laboratory and the
     proposed interconnection must pass the technical screens.
     Consequently, interconnections will not be permitted if they
     jeopardize the safety and reliability of the Transmission
     Provider\'s electric system.

404. Although the Interconnection Customer signs an abbreviated set of
     terms and conditions when it submits its Interconnection Request
     under the 10 kW Inverter Process, it is a legal instrument
     nonetheless. Its provisions are consistent with the SGIA. Should a
     dispute arise, we encourage the Parties to use this rulemaking for
     assistance in interpreting the terms and conditions of the 10 kW
     Inverter Process. Moreover, because the intent of the terms and
     conditions in this document are the same as those of the SGIA, no
     separate discussion of them is necessary here again in this Final
     Rule.

405. The 10 kW Inverter Process is quick, inexpensive, and user
     friendly. Including it in this Final Rule removes barriers to the
     development and interconnection of this class of Small Generating
     Facilities, both at the federal and state jurisdiction levels. Its
     adoption should promote standardization of interconnection rules
     across the nation. We encourage states that do not have
     interconnection procedures for very small generators to consider
     using this as a model for their own rules.

     **H. Other Significant Issues**[]{#__RefHeading___Toc103479320
     .anchor}

406. A number of issues, such as interconnection pricing policy,
     variations permitted for independent transmission entities, and
     legal issues such as liquidated damages, transcend individual
     provisions of the SGIP and SGIA. Accordingly, we address them
     below.

> **Pricing/Cost Recovery for Interconnection Facilities and Upgrades
> (Proposed SGIA Article 5.1)**[]{#__RefHeading___Toc103479321 .anchor}

407. In the Small Generator Interconnection NOPR, the Commission
     proposed to retain its then existing pricing policy for the
     interconnection of a Generating Facility with a Transmission System
     that is operated by a non-independent entity. That policy, as set
     forth in Order No. 2003, was to allocate the costs of the new or
     upgraded transmission facilities based on a locational test:
     whether they are at or beyond the Point of Interconnection.
     Facilities that are on the Small Generating Facility\'s side of the
     Point of Interconnection would be considered Interconnection
     Facilities, while those that are at or beyond the Point of
     Interconnection would be considered Network Upgrades. The
     Interconnection Customer would be directly assigned the costs of
     all Interconnection Facilities because they are sole use
     facilities. The Interconnection Customer would initially fund the
     Network Upgrades required for the interconnection unless the
     Transmission Provider chooses to pay for them itself. However, the
     Interconnection Customer would be entitled to a refund equal to the
     total amount paid to the Transmission Provider and the Affected
     System operator, if any, for Network Upgrades, including any
     tax-related payments. Order No. 2003 called for these refunds to be
     paid to the Interconnection Customer, with interest, as credits on
     a dollar-for-dollar basis for the non-usage sensitive portion[^117]
     of transmission charges, as payments are made under the
     Transmission Provider\'s tariff and the Affected System\'s tariff
     for any transmission services taken by the Interconnection Customer
     on the respective systems, whether or not the Generating Facility
     is the source of the power being transmitted.[^118] Order No. 2003
     permitted the Interconnection Customer, Transmission Provider, and
     Affected System operator to adopt any alternative payment schedule
     that is mutually agreeable provided all amounts paid by the
     Interconnection Customer for Network Upgrades are refunded, with
     interest, within five years of the generating facility\'s
     commercial operation date.[^119] The Interconnection Customer would
     be allowed to assign its refund rights to any person.

408. Because a Small Generating Facility may interconnect with a
     Transmission Provider\'s Distribution System subject to an OATT in
     order to make a sale of electricity at wholesale in interstate
     commerce, the Small Generator Interconnection NOPR also addressed
     cost recovery for Distribution Upgrades at or beyond the Point of
     Interconnection.[^120] Consistent with Order No. 2003, the
     Commission proposed that the costs of Distribution Upgrades be
     directly assigned to the Interconnection Customer because
     Distribution Upgrades do not generally benefit all users.

409. The Commission sought comments on whether this approach should also
     apply to Small Generating Facilities. The Commission also invited
     commenters to recount their recent experiences with interconnecting
     small generators with the \"Distribution System,\" in particular
     the process for determining whether Distribution Upgrades are
     necessary, and the cost assignment of those Upgrades.

410. For a Transmission Provider that is an independent entity, such as
     an RTO or ISO, the Commission\'s policy, as adopted in Order No.
     2003, is to allow more pricing flexibility, subject to Commission
     approval. Also in Order No. 2003, we permitted a Regional State
     Committee to establish criteria that an independent entity would
     use to determine which Network Upgrades should be subject to
     \"participant funding.\" Order No. 2003 also permitted, for a
     period of transition to the start of RTO or ISO operations, not to
     exceed a year, participant funding to be used for Network Upgrades
     as soon as an independent entity has been approved by the
     Commission and the affected states. In the

     Small Generator Interconnection NOPR, the Commission proposed to
     adopt the same policies for Small Generating Facilities that
     interconnect with a Transmission System operated by an independent
     entity. The Commission sought comments on this approach.

411. In the Small Generator Interconnection NOPR, the Commission also
     proposed certain pricing provisions that are consistent with, but
     have no direct parallel with, the Order No. 2003 pricing
     provisions. The Proposed SGIA provided that costs associated with
     Interconnection Facilities could be shared with other entities that
     may benefit from such facilities by agreement of the
     Interconnection Customer, such other entities, and the Transmission
     Provider. It also proposed that, if the Parties agree that the
     Small Generating Facility benefits the Transmission Provider\'s
     electric system, the Interconnection Customer\'s cost
     responsibility for the Transmission Provider\'s Interconnection
     Facilities or Upgrades would be reduced. The benefits would have to
     be measurable and verifiable. Where there are multiple
     Interconnection Requests and each requires Network Upgrades,
     Interconnection Customers would be assigned costs or benefits
     separately if effects can be attributed to different projects.
     Where such attribution is not possible, Interconnection Customers
     would share costs or benefits in proportion to their projected
     Small Generating Facility capacities.

     **Pricing Comments that the Commission Already Addressed in the
     Large Generator Interconnection
     Proceeding**[]{#__RefHeading___Toc103479322 .anchor}

     **Comments**

412. Several commenters object to various features of the Commission\'s
     current interconnection pricing policy, presenting arguments that
     the Commission has addressed in Order No. 2003. For example,
     Alabama PSC and others argue that prohibiting the direct assignment
     of the cost of Network Upgrades means that native load customers
     subsidize the cost of Network Upgrades that benefit only the
     Interconnection Customer. They argue that this may also cause the
     Interconnection Customer to make inefficient siting decisions.
     Mississippi PSC objects to the requirement that the Transmission
     Provider pay interest on unused credits and that it make a lump sum
     payment to the Interconnection Customer for credits that remain
     unused after five years. Alabama PSC argues that transmission
     credits should be provided only for Network Upgrades that provide a
     system benefit and only when the Small Generating Facility is the
     source of power for the transaction.

413. NRECA argues that if a merchant generator has not committed to
     serve network and native load customers within the Transmission
     Provider\'s footprint on a long-term

     basis, the generator and the Transmission Provider\'s own
     generators are not comparable. It asserts that credits are
     appropriate only where the Small Generating Facility is committed
     to customers in the Transmission Provider\'s footprint.

414. Central Maine requests clarification that transmission credits
     should be required only when the Interconnection Customer is taking
     and paying for transmission service on the Transmission System on
     which the Network Upgrade was made for the output of its facility.
     Central Maine also requests clarification that cost responsibility
     for Network Upgrades required by an Affected System is consistent
     with cost responsibility for Network Upgrades required by the
     Transmission Owner with whom an Interconnection Customer is
     directly interconnecting; that is, that transmission credits are
     required only when the Interconnection Customer takes and pays for
     transmission service from the Transmission Owner or Affected System
     for the output of its facility. It also asks that the contractual
     provisions concerning cost responsibility and payment obligations
     among Affected Systems and Interconnection Customers be in a
     separate agreement, not in the interconnection agreement.

415. Avista, Alabama PSC, and Mississippi PSC argue that allowing
     pricing flexibility to an independent Transmission Provider such as
     an RTO or ISO is unduly discriminatory. They state that this policy
     penalizes the retail customers of the non-independent Transmission
     Provider because it forces them to bear the cost of Network
     Upgrades that benefit only the Interconnection Customer. Idaho
     Power argues that having different pricing for an independent and a
     non-independent Transmission Provider is bad public policy,
     arbitrary and capricious, and discriminatory. TAPS states that the
     NOPR incorrectly proposes participant funding for Upgrades to a
     Transmission System operated by an independent entity.

     **Commission Conclusion**

416. All of the comments summarized above relate to the Commission\'s
     general pricing policy, and each was discussed in Order No.
     2003.[^121] We adopt here the general conclusions adopted in those
     orders. However, those orders did not address the specific question
     of whether the Commission\'s general interconnection pricing policy
     is suitable for Small Generating Facilities. Several commenters
     raise this question, and we address their comments below.

> **Applicability of the Commission\'s Interconnection Pricing Policy to
> the Interconnection of Small Generating
> Facilities**[]{#__RefHeading___Toc103479323 .anchor}

**Comments**

417. Several commenters support the use of the Commission\'s current
     interconnection pricing policy. Western supports the Commission\'s
     proposal to have the Interconnection Customer initially fund
     interconnections and associated Transmission System improvements
     and states that this approach is consistent with the budgetary
     realities that

     Western faces. Georgia PSC agrees that Interconnection Facilities
     are sole use facilities and, accordingly, should be directly
     assigned to (paid for by) the Interconnection Customer.

418. Nevada Power states that interconnection pricing policies must be
     consistent for both Small and Large Generating Facilities to avoid
     the possibility of pricing manipulation. It opposes credits for
     facilities that do not increase transfer capability, but states
     that the requirement that the Interconnection Customer initially
     fund the Network Upgrade costs is an important safeguard to ensure
     that the Transmission Provider and other customers do not subsidize
     what would otherwise be an uneconomic project. SoCal Edison states
     that the Small Generator Interconnection NOPR correctly mirrors the
     Large Generator Final Rule with respect to the pricing policies for
     Network Upgrades and sole use Interconnection Facilities. BPA
     generally supports consistency between pricing for Small and Large
     Generating Facility interconnections, provided the Commission
     clearly articulates the physical boundary between Interconnection
     Facilities and Network Upgrades.

419. AEP and Midwest ISO agree that an independent Transmission Provider
     should be allowed interconnection pricing policy flexibility,
     subject to Commission approval. Midwest ISO states that few
     circumstances would warrant an approach for Small Generating
     Facilities that differs from the approach that an RTO would
     establish for a Large Generating Facility. A common approach makes
     good business sense, assures comparability and makes the
     interconnection process more effective. Also, BPA generally
     supports RTO pricing flexibility, provided it does not conflict
     with an RTO\'s obligations under its governing agreements.

420. Cummins, however, argues that the Commission should adopt different
     pricing rules for Small Generating Facilities because the
     Commission\'s current policy gives the Transmission Provider the
     discretion to place a huge cost burden on the Small Generating
     Facility. These costs may even exceed the installation and
     operating costs of a Small Generating Facility, completely
     destroying project economics. Cummins argues that this problem can
     be addressed only by specific performance standards (which Cummins
     does not describe) that only the Commission can establish. Also, if
     the Interconnection Customer is deemed to be the only beneficiary
     of the Upgrade or interconnection, the five year refund mechanism
     would be of no benefit, as the project would not go forward.

421. The Small Generator Interconnection NOPR asked for specific
     examples of situations where a Transmission Provider has seemingly
     applied excessive fees for Upgrades. Cummins describes two examples
     that highlight its concerns:

     A manufacturer installed a 300 kW synchronous generator and
     cogeneration system, and provided the interconnection equipment
     specified by the \[Transmission Provider\]. The system was approved
     by the \[Transmission Provider\] and went into successful
     operation. When the owner decided to expand the facility to include
     a second 300 kW generator, they were informed that the distribution
     system would need upgrades that would cost in excess of \$140,000.
     On further investigation, it was learned that the upgrades included
     only \"block closing\" provisions on a recloser. This device is
     effectively a simple voltage sensing relay that would interconnect
     into the existing infrastructure at a substation. After intensive
     negotiations and investigations, the customer was able to get the
     cost reduced to under \$50,000, and the project went forward. The
     \$50,000 cost was still far more than the upgrade should have cost,
     but the customer was forced to pay it because the generator was key
     to the viability of the customer\'s business. This represented a
     10% increase in the overall project.

     In another case, a customer installed a 2 MW synchronous generator
     with equipment that allowed it to parallel with the utility for
     1/10^th^ of a second. The equipment included timer functions that
     prevented the machine from staying in parallel for more than 1
     second, as required by local rules. The \[Transmission Provider\],
     unsatisfied with the \"quality\" or \"performance\" of the relay in
     the customer\'s device, forced the customer to install a new relay
     costing over \$2,000 for the 1 second time function. This was an
     excessively expensive piece \[of\] equipment to perform a simple
     operation; however the Interconnection Customer needed the
     equipment to operate, and had to pay the price.

422. Small Generator Coalition argues that the Small Generator
     Interconnection NOPR\'s cost allocation provisions appear to
     guarantee pancaked wheeling charges on energy produced by Small
     Generating Facilities, contrary to the Commission\'s goal of
     eliminating such pancaking.[^122]

423. MidAmerican states that a Commission rule requiring a Transmission
     Provider to pay any interconnection-related costs could supersede
     state policy and also would affect the ability of states to set
     retail rates following well-established cost causation principles.
     MidAmerican argues that the rules should permit the Transmission
     Provider to directly assign all costs to the Interconnection
     Customer unless that violates state regulatory policy.

     **Commission Conclusion**

424. We recognize that the Interconnection Facilities, Distribution
     Upgrades, and Network Upgrades required to interconnect a generator
     can be costly. Indeed, such costs can be a significant portion of
     the total project costs. Nevertheless, each Generating Facility,
     whether large or small, must bear its fair share of the cost of the
     facilities and Upgrades from which it benefits; otherwise, the
     facility simply does not make economic sense.

425. To this end, the Small Generator Interconnection NOPR proposed to
     apply to Small Generating Facility interconnections the same
     pricing policy that the Commission adopted for Large Generating
     Facilities in Order No. 2003. Among other things, this means that
     the Interconnection Customer must bear the cost of necessary
     Interconnection Facilities and Distribution Upgrades. Also, the
     Interconnection Customer must initially fund the cost of Network
     Upgrades, but is entitled to credits against its charges for
     transmission delivery service equal to the amount funded, plus
     interest. None of the arguments presented here convinces us that
     the policies adopted in Order No. 2003 should not also apply to
     Small Generating Facility interconnections. In particular, contrary
     to the assertions of Cummins and Small Generator Coalition, we do
     not view the policy as creating rate pancaking or an undue burden
     for the Small Generating Facility. Thus, we adopt the Order No.
     2003 pricing policies for small generator interconnections in this
     Final Rule.

426. With regard to Cummins\'s concern that the Transmission Provider
     may be able to force the Small Generating Facility to bear
     unreasonable costs, we note that our principal purpose in adopting
     a standardized procedures document and agreement for generator
     interconnections, and making them part of the Transmission
     Provider\'s tariff, is to eliminate much of the opportunity for the
     Transmission Provider to act in this manner. Indeed, adoption of
     this Final Rule should greatly reduce the likelihood of the two
     negative experiences that Cummins describes, if indeed the cost
     were unreasonable.

427. In response to MidAmerican, this Final Rule applies only to
     generator interconnections that are under the jurisdiction of the
     Commission. It does not apply where we do not have jurisdiction.
     Although state regulators or other rate-making authorities may
     model their own policies after those adopted herein, or the similar
     NARUC Model, they are free to establish whatever rules for
     determining cost responsibility that they deem reasonable for
     interconnections under their jurisdiction.

428. The Commission modified and clarified its pricing policy for Large
     Generator Interconnections in Order Nos. 2003-A and 2003-B, which
     were issued after the Small Generator Interconnection NOPR in this
     proceeding. Upon review of the revisions to the Commission\'s
     pricing policy included in those orders, we conclude that they
     should apply to the interconnection of Small Generating Facilities
     as well. Therefore, we are revising the Proposed SGIA to reflect
     our current interconnection pricing policy as modified by Order
     Nos. 2003-A and 2003-B. (See articles 4 and 5 of the SGIA)

     **Implementation of the Interconnection Pricing Policy for Small
     Generating Facilities**[]{#__RefHeading___Toc103479324 .anchor}

     **Comments**

429. Midwest ISO notes that Chart 1 of the Proposed SGIP shows a
     difference between the Point of Interconnection and the \"point of
     common coupling\"[^123] and says that equipment Upgrades may
     sometimes be needed between these two points. Midwest ISO asks who
     is to be responsible for such Upgrades and whether transmission
     service credits will be provided to the Interconnection Customer if
     it finances the Upgrades.

430. Empire District agrees that Upgrades that are directly assigned,
     such as radial extensions to the generator, should not be paid for
     (or reimbursable to the Interconnection Customer) by the
     Transmission Provider. In addition, it states that interconnection
     costs should be treated in a manner similar to the crediting
     methods used by the Southwest Power Pool (which Empire District
     does not describe).

431. Many commenters support the Commission\'s proposal to directly
     assign the cost of Distribution Upgrades to the Interconnection
     Customer.[^124] For example, AEP states that a Distribution Upgrade
     that is required to accommodate the proposed generator does not
     benefit all users; rather, its sole purpose is to accommodate one
     customer. AEP contends, therefore, that it is entirely reasonable
     for the Interconnection Customer to be responsible for the cost of
     the Distribution Upgrade. Cinergy states that such responsibility
     follows from the radial nature of the Distribution System and is
     consistent with the LGIA. Baltimore G&E states that the Commission
     must guarantee that distribution utilities receive full cost
     recovery from interconnecting Small Generating Facilities to avoid
     subsidization by retail customers.

432. Nevada Power agrees that the cost of Distribution Upgrades should
     be directly assigned to the Interconnection Customer, but is
     concerned that Proposed SGIA article 5.1.3 does not adequately
     protect the Transmission Provider from having to bear such costs.
     This article could be construed to say that wholesale transactions
     by the Interconnection Customer change the segment of the
     distribution facilities to which the Interconnection Customer
     connects into transmission facilities. Nevada Power argues that the
     Proposed SGIA definition of Transmission System illustrates this
     concern: \"Transmission System shall mean the facilities owned,
     controlled or operated by the Transmission Provider or Transmission
     Owner that are used to provide transmission service under the
     Tariff.\" An inference can be drawn that what was previously a
     distribution facility is now a transmission facility because it
     provides transmission service, and is therefore subject to the
     crediting process. To address this concern, Nevada Power proposes
     specific changes to Proposed SGIA article 5.1.3.

433. SoCal Edison notes that in the Small Generator Interconnection
     NOPR, Distribution Upgrades and Network Upgrades are both defined
     as being at or beyond the Point of Interconnection. Distribution
     Upgrades are defined as upgrades to the Distribution System, while
     Network Upgrades are defined as upgrades to the Transmission
     System. However, \"Transmission System\" is defined to include any
     facility, be it transmission or distribution, that is subject to an
     OATT. Therefore, SoCal Edison contends that because \"Transmission
     System\" is defined to include portions of the Distribution System,
     the definition of Network Upgrades (in combination with other
     provisions of the SGIP and SGIA) is confusing. SoCal Edison argues
     that keeping the terms Transmission System and Distribution System
     distinct is crucial. For this reason, the definition of
     Transmission System needs to exclude distribution facilities, which
     facilities already are included in the term Distribution System.

434. In a similar vein, PacifiCorp argues that the definition of Network
     Upgrades must be revised to prevent it from being applied to
     Upgrades to a Transmission Provider\'s Distribution System. The
     Proposed SGIA\'s definition of Network Upgrades could be read to
     include Upgrades to radial feeders or other facilities that are
     part of the Transmission Provider\'s Distribution System. In
     PacifiCorp\'s view, Network Upgrades should include only Upgrades
     to networked transmission or sub-transmission facilities. Any
     Upgrades to radial feeders or other facilities that make up the
     Transmission Provider\'s Distribution System should be paid for by
     the Interconnection Customer without credits.

435. PSE&G states that the definition of Network Upgrades should be
     modified as follows: \"\[Network Upgrades\] shall mean the
     additions, modifications and upgrades...required (strike out \"at
     or\") beyond the point at which the Interconnection Customer
     interconnects to the Transmission Provider\'s or Transmission
     Owner\'s or distribution owner\'s (strike out \"Transmission\" and
     add \"Distribution\") System to accommodate the Generating
     Facility...\"

436. NRECA states that the Commission has an important role in
     determining whether facilities are distribution or transmission.
     The Commission should apply the seven-factor test where there are
     disputes and should not in doing so give undue deference to state
     or public utility classifications of facilities. As shown by cases
     such as [Arkansas Power & Light]{.underline},[^125] the Commission
     may conclude that a facility serves a transmission function even if
     it is lower voltage and serves a few end-use customers, if the
     predominant use of the facility is to provide wholesale
     transmission service.

437. In addition, NRECA seeks clarification of the NOPR\'s statement
     that \"if a proposed interconnection passes either the
     super-expedited screening procedures or the expedited screening
     procedures, the Interconnection Customer would have no cost
     responsibility for Upgrades.\" NRECA contends that this contradicts
     article 5.1.3 of the Proposed SGIA (Distribution Upgrades), and
     thus is inconsistent with the Commission\'s proposal to require
     Distribution Upgrades to be directly assigned to the
     Interconnection Customer.

     Furthermore, the statement would shift costs from the
     Interconnection Customer to utilities and their other customers.
     Also, Cummins says that the proposal runs counter to, or may
     confuse the application of, screens that would expedite the
     interconnection process.

438. Small Generator Coalition states that although Proposed SGIA
     article 5.1.5 gives the Interconnection Customer an opportunity to
     demonstrate benefits to the Transmission Provider\'s electric
     system that would reduce the Interconnection Customer\'s costs, the
     NOPR\'s discussion of Distribution Upgrades at P 72 appears to rule
     out any cost reductions for Distribution Upgrades. In addition,
     Small Generator Coalition argues that ambiguous NOPR provisions may
     permit Transmission Owners to require the Interconnection Customer
     to pay for Network Upgrades with no compensation to the
     Interconnection Customer or consideration of network benefits.
     Because downstream resources can benefit system reliability, Small
     Generator Coalition argues that the Commission\'s rule should
     allocate Upgrade costs according to benefits to all portions of an
     affected Transmission System, including facilities operating at
     distribution voltages.

439. Alabama PSC and Mississippi PSC argue that distribution facilities
     should be directly assigned. However, because the Commission lacks
     jurisdiction over distribution facilities, cost responsibility for
     Distribution Upgrades is an issue for state regulators to address.

440. Midwest ISO notes that Proposed SGIA article 5.1.5 provides that if
     the Parties agree that the Small Generating Facility benefits the
     Transmission Provider\'s electric system, the Interconnection
     Customer\'s cost responsibility may be reduced accordingly. The
     Small Generator Interconnection NOPR says that, if multiple
     facilities are involved, pro rata allocation of the costs or
     benefits must be made. These provisions appear to conflict with the
     NOPR\'s proposal at P 71, which allows an RTO flexibility with
     respect to interconnection pricing.

     **Commission Conclusion**

441. With reference to Chart 1 of the Proposed SGIP, Midwest ISO asks
     who is responsible for the cost of Upgrades between the point of
     common coupling and the Point of Interconnection. Chart 1 was in
     error. The Point of Interconnection is the point identified as the
     point of common coupling, which is the point in the diagram where
     the Interconnection Facilities connect to the Transmission
     Provider\'s Distribution System subject to an OATT. Thus, the
     Upgrades to which Midwest ISO refers are in fact Interconnection
     Facilities, and their cost is directly assigned to the
     Interconnection Customer.

442. In response to Empire District, we confirm that radial extensions
     to the Small Generating Facility are to be directly assigned to the
     Interconnection Customer if they are Interconnection Facilities;
     that is, if the radial line is a sole use facility located between
     the Small Generating Facility and the Point of Interconnection, its
     cost is directly assigned to the Interconnection Customer. Also,
     Empire District recommends that the Commission adopt a crediting
     policy that is similar to the methods set forth by the Southwest
     Power Pool. However, Empire District does not explain how its
     recommended methods differ from or are better than those proposed
     in the NOPR.

443. In order to eliminate the confusion expressed by Nevada Power,
     SoCal Edison and others about the distinction between Distribution
     Upgrades and Network Upgrades, we are adding the following sentence
     to the definition of Network Upgrades: \"Network Upgrades do not
     include Distribution Upgrades.\"

444. NRECA seeks clarification of the Small Generator Interconnection
     NOPR\'s statement that \"if a proposed interconnection passes
     either the super-expedited screening procedures or the expedited
     screening procedures, the Interconnection Customer would have no
     cost responsibility for Upgrades.\" The issue of who pays for an
     Upgrade in the case of a proposed interconnection passing all the
     screens is moot because one of the provisions of SGIP section 2.2.1
     is a requirement to pass a screen that the interconnection must not
     require an Upgrade.

445. Small Generator Coalition is concerned that the Proposed SGIA may
     assign to the Interconnection Customer cost responsibility for
     Interconnection Facilities in a way that gives no recognition to
     the benefits that the Interconnection Facilities may bring to the
     Transmission Provider's electric system. In response, we clarify
     that the Interconnection Customer is responsible for the cost of
     Interconnection Facilities except when such cost is shared with
     other entities that may benefit from the Interconnection Facilities
     by agreement of the Interconnection Customer, the other entities,
     and the Transmission Provider. This provision for cost sharing is
     included in SGIA article 4.1.1.

446. Small Generator Coalition also asks about sharing cost
     responsibility for Distribution Upgrades and initial funding
     responsibility for Network Upgrades. The Interconnection Customer
     is responsible for the upfront funding of Network Upgrades unless
     the Transmission Provider elects to provide the upfront funding
     itself. This payment option is included in SGIA article 5.2.
     However, we are not adopting the explicit

     cost sharing provisions of Proposed SGIA article 5.1.5 relating to
     Distribution Upgrades because they are not consistent with Order
     No. 2003 which specified that all Distribution Upgrades shall be
     directly assigned to the Interconnection Customer.[^126]

447. In response to Midwest ISO, we clarify that we are allowing
     flexibility for the pricing that an independent Transmission
     Provider may propose to adopt, subject to Commission approval,
     under the \"independent entity\" variation. Accordingly, an
     independent Transmission Provider may propose a pricing method that
     differs from what this Final Rule otherwise requires.

448. Alabama PSC and Mississippi PSC assert that cost responsibility for
     Distribution Upgrades is beyond the scope of the Commission\'s
     authority. As explained above, the Commission\'s assertion of
     jurisdiction here is no broader than in Order No. 888. This Final
     Rule applies to interconnections with a Transmission System or with
     a Distribution System subject to an OATT for the purpose of making
     wholesale sales. The Commission\'s authority over such
     interconnections with Distribution Systems, for the purposes of
     making a wholesale sale of electricity in interstate commerce,
     includes allocating the cost of all of the Transmission Provider's
     Upgrades needed to effect the interconnection.. Otherwise, the
     Commission could not ensure that the costs incurred to provide a
     jurisdictional service are allocated appropriately. The pricing
     policy for Distribution Upgrades directly assigns costs to the
     Interconnection Customer so there is no impact on retail customers
     of the Distribution System.

     **Responsibility for Operation and Maintenance
     Costs**[]{#__RefHeading___Toc103479325 .anchor}

449. Proposed SGIA article 5.1.4 stated that the Interconnection
     Customer is responsible for the operating and maintenance costs
     associated with the Interconnection Facilities that it owns as well
     as those owned by the Transmission Provider. The Proposed SGIA did
     not assign responsibility for O&M costs associated with Network
     Upgrades or Distribution Upgrades.

     **Comments**

450. Central Maine and NYTO ask the Commission to clarify that the
     Interconnection Customer is responsible for ongoing O&M costs
     associated with Network Upgrades when the Interconnection Customer
     does not take and pay for transmission service for the output of
     its Small Generating Facility.

451. Southern Company contends that Proposed SGIA article 5.1.4
     contemplates that the Interconnection Customer is responsible for
     all reasonable expenses associated with operating and maintaining
     its own Interconnection Facilities and the Transmission Provider\'s
     Interconnection Facilities, but it is unclear whether all
     applicable O&M costs are covered. It notes that LGIA article 10.5
     does not limit O&M cost recovery to the Transmission Provider\'s
     Interconnection Facilities, but explicitly provides that the
     Interconnection Customer is responsible for all reasonable O&M
     costs. Therefore, Southern Company proposes to revise article 5.1.4
     to include Distribution Upgrades so as to ensure that all
     appropriate O&M costs are included.

452. Robert L. Carrey contends that the Interconnection Customer should
     pay only the O&M costs of the Interconnection Facilities built on
     its behalf. He argues that the Interconnection Customer should not
     have to pay for routine O&M costs where no Interconnection Customer
     and Transmission Provider share the same poles and rights-of-way.

     **Commission Conclusion**

453. The Commission has long held that O&M costs associated with Network
     Upgrades cannot be directly assigned to the Interconnection
     Customer, because Network Upgrades are part of the integrated
     transmission system from which all transmission users benefit.
     [^127] Therefore, we deny the requests of Central Maine and NYTO
     that the Commission require the Interconnection Customer to pay O&M
     costs associated with Network Upgrades.[^128]

454. While the SGIA authorizes the Transmission Provider to collect O&M
     costs associated with Interconnection Facilities, this Final Rule
     does not contain a rate recovery mechanism for collecting those
     costs, because such costs will vary from case to case. Therefore,
     if a Transmission Provider wishes, it may propose and justify its
     rate to recover such costs under section 205 of the FPA.[^129] In
     response to Southern Company, a Transmission Provider may make a
     similar filing to recover from the Interconnection Customer an
     appropriate share of any Commission-jurisdictional component of the
     O&M costs of Distribution Upgrades. Absent Commission approval of
     such a rate schedule, the Transmission Provider may not collect
     Commission-jurisdictional O&M costs associated with Interconnection
     Facilities or Distribution Upgrades.

455. In response to Mr. Carrey, the Transmission Provider is free to
     propose to recover these expenses in any manner it sees fit;
     however, the Commission will approve the Transmission Provider\'s
     proposed rate if it is shown to be just and reasonable and not
     unduly discriminatory or preferential.

     **Responsibility for the Construction of
     Upgrades**[]{#__RefHeading___Toc103479326 .anchor}

456. Proposed SGIA article 5.1.2 stated that the Transmission Provider
     or Transmission Owner shall design, procure, construct, install,
     and own the Network Upgrades.

     **Comments**

457. PacifiCorp states that the Parties should be permitted to agree
     that the Network Upgrades will be built by the Interconnection
     Customer on its land. This could facilitate a faster
     interconnection. In addition, Proposed SGIA article 3.3 should be
     revised to give the Transmission Provider the right to inspect,
     operate, or maintain Network Upgrades on the Interconnection
     Customer\'s land.

458. AMP-Ohio states that, in the region where its members\'
     Distribution Systems are located, the Transmission Provider would
     be an RTO. It notes that Proposed SGIA article 5.1.3 stated that
     the \"Transmission Provider or Transmission \[Owner\] shall design,
     procure, construct, install, and own the distribution Upgrades...\"
     AMP-Ohio is concerned that this article could be construed to allow
     the RTO to own and operate piecemeal sections of a member\'s
     electric system. The Commission should clarify that one entity
     cannot assert the right to own a portion of another\'s electric
     system.

     **Commission Conclusion**

459. In response to PacifiCorp, neither Proposed SGIA article 5.1.2 nor
     article 5.1.3 precluded the Parties from agreeing that the
     Interconnection Customer may construct Network Upgrades or
     Distribution Upgrades on its own land. Nevertheless, we make this
     option explicit in SGIA articles 4.2 and 5.2. PacifiCorp\'s
     proposed revisions to Proposed SGIA article 3.3 are addressed above
     in our discussion of that article.

460. In response to AMP-Ohio, we clarify that this Final Rule does not
     authorize any entity, including the Transmission Provider, to own a
     portion of another entity\'s Transmission System without the
     permission of the Transmission Owner.

     **Miscellaneous Pricing Issues**[]{#__RefHeading___Toc103479327
     .anchor}

     **Comments**

461. PacifiCorp notes that Proposed SGIA article 5.1.2.1 would permit a
     refund to an Interconnection Customer whose Small Generating
     Facility does not achieve commercial operation, if another customer
     uses the Network Upgrades for which the first Interconnection
     Customer paid. PacifiCorp asks that this provision specify that a
     refund is available only if the second Interconnection Customer
     actually requires the Network Upgrades for its Small Generating
     Facility.

462. TAPS states that the NOPR does not make the Transmission Provider
     remove its own Interconnection Facilities from rate base.

     **Commission Conclusion**

463. We agree with PacifiCorp that the first Interconnection Customer
     should not receive a refund of amounts it has advanced for Network
     Upgrades unless the later Interconnection Customer\'s Small
     Generating Facility actually would have required the construction
     of the Network Upgrades. However we believe that the SGIA, as
     written, makes this clear. To make a change to this provision would
     imply that it means something different from the similar provision
     adopted in the LGIA, and that is not our intent, therefore we
     decline to accept PacifiCorp's proposed modification.

464. With regard to the issue that TAPS raises, the Commission addressed
     this matter in Order No. 2003. There the Commission required the
     Transmission Provider to remove from transmission rates the costs
     of Interconnection Facilities constructed by the Transmission
     Provider after March 15, 2000 to interconnect generating facilities
     owned by the Transmission Provider on the effective date of the
     Final Rule in the Large Generator Interconnection proceeding.[^130]
     The Commission\'s conclusion about the need for the Transmission
     Provider to remove its own Interconnection Facilities from rate
     base was not intended to be limited to Large Generating Facilities.
     We clarify here that it applies to all of the Transmission
     Provider\'s Interconnection Facilities, regardless of the size of
     the associated generating facility.

     **Commission Jurisdiction under the Federal Power
     Act**[]{#__RefHeading___Toc103479328 .anchor}

465. Sections 205 and 206 of the FPA require the Commission to remedy
     undue discrimination by public utilities. In Order No. 888, the
     Commission found that public utilities owning or controlling
     jurisdictional transmission facilities had the incentive to engage
     in, and had engaged in, unduly discriminatory practices.[^131]
     Because interconnection is an element of transmission service that
     must be provided under the OATT, the Commission in Order No. 2003
     established generic interconnection terms and procedures under its
     authority to remedy undue discrimination under sections 205 and
     206.[^132] The Small Generator Interconnection NOPR proposed that
     its jurisdictional reach would be identical to Order No. 2003.

> **Comments**

466. NARUC, NRECA, several state regulatory commissions,[^133] and
     others[^134] argue that the Small Generator Interconnection NOPR
     unlawfully encroaches upon the jurisdiction of the states by
     proposing to regulate interconnections with \"local distribution\"
     facilities.

467. Many of the commenters opposing the Commission\'s exercise of
     jurisdiction over facilities used both for
     Commission-jurisdictional and for state-jurisdictional transactions
     (\"dual-use\" facilities) cite [Detroit Edison]{.underline}.[^135]
     They appear to have read [Detroit Edison]{.underline} as forbidding
     the exercise of federal jurisdiction over any facilities used to
     any degree to distribute bundled power to end-users at retail,
     regardless of whether those facilities are also used for
     transactions that are under the Commission\'s jurisdiction.[^136]
     Other commenters, including Small Generator Coalition and SoCal
     Edison,[^137] assert that nothing in [Detroit Edison]{.underline}
     prevents the Commission from asserting jurisdiction over all
     interconnections made to facilitate Commission-jurisdictional
     activities.

468. Interconnections with \"distribution\" facilities, argues Alabama
     PSC, should be exclusively state-jurisdictional. It argues that
     \"the Courts have long recognized and enforced the State\'s primacy
     over the regulation of distribution facilities.\"[^138] CPUC makes
     a similar argument, stating that:

     federal law was meant to supplement -- and not to supplant -- state
     regulation of those utilities. The FPA was enacted to fill in gaps
     not covered by state regulation, not as a mechanism for avoiding
     state regulation of public utilities. In enacting the FPA, Congress
     did not purport to exercise all of the authority it might have
     exercised under the Commerce Clause, because its intention was to
     preserve, not override, state regulatory jurisdiction.\[[^139]\]

469. Alabama PSC, Mississippi PSC, and Southern Company also cite the
     preemption doctrine (that federal preemption of state law is not to
     be assumed unless Congress expresses a clear intent to do so) as
     another reason why the Commission is not permitted to exercise
     jurisdiction over \"distribution\" facilities. \"To the contrary,\"
     Alabama PSC argues, \"the FPA expressly provides that FERC does not
     have such jurisdiction.\"[^140]

470. CT PUC asks the Commission to clarify that this Final Rule does not
     preempt state regulatory authority with respect to electric
     distribution company regulation, environmental protection
     (including Clean Air Act permitting), fire and building safety
     regulation, etc., as these may apply to Small Generating Facility
     interconnections with \"distribution\" facilities.

471. Idaho Power states that \"\[t\]he \'dual use\' theory leaves the
     \"distribution\" facility owner that is trying to design an
     efficient and reliable \"distribution\" system in the untenable
     position of having two masters attempting to control the same
     physical line for differing purposes.\"[^141]

472. PacifiCorp cites forum shopping concerns and suggests that a Small
     Generating Facility interconnecting as a Qualifying Facility (QF)
     to a dual use facility could receive different treatment depending
     on whether it sells its output to the host utility under the Public
     Utility Regulatory Policies Act of 1978 (PURPA)[^142] or to a
     customer other than the host utility. In the first instance, the
     interconnection would be state-jurisdictional; in the second,
     Commission-jurisdictional. PacifiCorp asserts that this is a
     confusing outcome and could be avoided if the Commission disclaims
     jurisdiction over low voltage and dual use facilities.

473. Small Generator Coalition argues that not asserting jurisdiction
     over all interconnections made to facilitate
     Commission-jurisdictional activities means adopting a
     circuit-by-circuit approach to jurisdiction. This would be contrary
     to the Commission\'s approach taken in a variety of contexts,
     including assignment of system losses[^143] and recovery of fixed
     costs[^144] on a system-wide basis. Further, if the Commission
     allows a Transmission Provider to refuse interconnections with the
     low-voltage \"distribution\" portions of its system not already
     used for jurisdictional transactions, \"small resource development
     would be inhibited if not eliminated.\"[^145] Transmission
     Providers could \"pick and choose among interconnection applicants
     based on any criteria they elected to employ.\"[^146] Finally,
     Small Generator Coalition argues that the Commission adequately
     recognizes state jurisdiction by claiming jurisdiction over only
     interconnections with \"distribution\" facilities that are used for
     wholesale transactions.

474. NRECA argues that, as more and more distributed generators
     participate in the wholesale market, \"many if not most
     distribution facilities will carry a few wholesale
     electrons.\"[^147] Indeed, \"many if not most distribution
     facilities will become subject to Commission jurisdiction. The
     jurisdictional divide between the Federal Government and the States
     that Congress clearly intended in the FPA will have
     collapsed.\"[^148] Baltimore G&E asks the Commission to explain how
     it will avoid a \"chicken and egg\" situation where the
     jurisdictional status of a particular facility would change after
     the interconnection takes place.

475. Solar Turbines expresses concern that \"\[a\] utility apparently
     need merely deny that a particular line is currently being used for
     any transmission of power in interstate commerce or for any sales
     for resale, and can then refuse to accept an application for
     interconnection to that specific facility\"[^149] and requests that
     the Commission clarify what the Interconnection Customer should do
     if it finds itself in such a situation.

476. MidAmerican asks whether this Final Rule would apply to a net
     metering arrangement that allows a Small Generating Facility to net
     only a portion of its output and resell the remainder to the host
     utility. It also asks what happens if it sells the non-net metered
     portion of its output to a third party.

477. Avista asks the Commission to address the effect of [Detroit
     Edison]{.underline} on an interconnection for a purpose other than
     to \"engage in sale for resale in interstate commerce or to
     transmit electricity in interstate commerce.\" Avista
     differentiates \"load interconnections\" from \"generator
     interconnections,\" which are interconnections made to export
     power. It requests clarification that a load interconnection to a
     dual use facility is an exclusively state-jurisdictional
     interconnection \"except if and to the extent there is an OATT on
     file by the owner of the facilities that makes available new
     Commission-jurisdictional service over those facilities.\"[^150]
     Absent such a clarification, Avista argues that \"uncontrolled
     deregulation of service at the distribution level may occur, since
     any new load can seek to characterize its service as \'wholesale\'
     by inserting a \'sham utility\' between the customer and the
     incumbent utility.\"[^151] Avista states that FPA section 212(h)
     already prohibits \"sham wholesale transactions\"[^152] and argues
     that \"the Commission has determined that Section 212(h) only
     applies to transmission orders, not interconnection

     requests.\"[^153] Without such a clarification, Avista fears that
     load interconnections with dual use facilities could be used to
     force otherwise non-Commission-jurisdictional \"distribution\"
     facilities into Commission-jurisdictional status.

478. USCHPA and Solar Turbines ask the Commission to exert jurisdiction
     over all load interconnections. Additionally, many cogeneration
     projects, USCHPA asserts, make sporadic sales of power when the
     economics favor doing so. Such projects should not be denied the
     benefits of standardized interconnection rules simply because their
     sales into the wholesale energy marketplace are sporadic. Solar
     Turbines argues that the needs of Small Generating Facilities are
     different and that there are good reasons to depart from the large
     generator precedent in this rulemaking. Specifically, Small
     Generating Facilities are more likely to be near to load, while
     Large Generating Facilities are more likely to be far from their
     load.

479. Midwest ISO argues that [all]{.underline} interconnections with
     \"distribution\" facilities within an RTO or ISO to sell power at
     wholesale should be processed under a single set of rules. This
     would include both state- and Commission-jurisdictional facilities.
     Midwest ISO remarks that regardless of \"\[w\]hether the physical
     requirements of the interconnection come under the RTO\'s purview,
     the generating facility\'s operation will\" come under the RTO\'s
     jurisdiction. Therefore, the RTO should be able to \"evaluate the
     proposed interconnection with the generating facility\'s subsequent
     operation in mind.\"[^154]

480. Finally, several comments address whether the use of a 69 kV cutoff
     in the SGIP affects the Commission\'s jurisdiction.

**Commission Conclusion**

481. The Commission\'s assertion of jurisdiction in this Final Rule is
     identical to the jurisdiction asserted in Order Nos. 2003 and 888
     and upheld by the Supreme Court in [New York v. FERC]{.underline}.
     Just as the Commission stated in Order No. 2003-A:

     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.\[[^155]\]

482. Many commenters seek clarification of issues (particularly related
     to the [Detroit Edison]{.underline} case) that were discussed at
     length in Order Nos. 2003-A and 2003-B, which were issued after
     comments on the Small Generator Interconnection NOPR were
     due.[^156] Since the jurisdiction asserted in this Final Rule is
     identical to that asserted in Order No. 2003, we adopt here our
     discussion from those orders rather than repeat the same
     information.

483. However, several commenters focused on how the jurisdictional
     issues raised by small generator interconnections may differ from
     those raised in the Large Generator Interconnection rulemaking.
     Additionally, some commenters raised issues in this proceeding that
     were not addressed in Order Nos. 2003-A or 2003-B. These issues we
     discuss in more detail below.

484. We disagree with Alabama PSC, Mississippi PSC, and Southern Company
     that the Commission is evading FPA section 201(b)(1) or preempting
     state law. In [New York v. FERC]{.underline}, the U.S. Supreme
     Court approved the Commission\'s assertion of jurisdiction in Order
     No. 888.[^157] The applicability of this Final Rule is identical to
     the applicability of Order No. 888.

485. CT PUC is correct that this Final Rule in no way alters the
     permitting and other environmental requirements applicable to
     Interconnection Customers. Nor does this Final Rule affect any
     other state police powers.

486. NRECA asserts that while there are now relatively few Small
     Generating Facility interconnections that are
     Commission-jurisdictional, that number will increase as time
     passes. Small Generator Coalition complains that the number of
     lower voltage Commission-jurisdictional facilities is too small.
     Ultimately, however, the Commission\'s jurisdiction does not rest
     on how common dual use facilities may be or how many
     interconnections are Commission-jurisdictional.

487. Baltimore G&E asks if the jurisdictional status of a facility would
     change after an interconnection takes place. Whether a facility is
     subject to this rule depends on whether it is subject to an OATT at
     the time the Interconnection Request is filed. The use of a
     facility and thus its inclusion in an OATT can change over time.
     Nothing in this Final Rule (or Order No. 2003) alters the status of
     any facility.

488. Avista is correct that some interconnections are made simply to
     [receive]{.underline} power from the electric system. These \"load
     interconnections\" are not subject to this Final Rule.

489. In response to USCHPA\'s concern over Interconnection Customers who
     may wish to make sporadic sales of power into the marketplace, we
     clarify that there is no requirement that an Interconnection
     Customer\'s participation in the wholesale marketplace be constant.
     An Interconnection Customer is free to request interconnection
     service and then wait until the economics are favorable before
     actually making a wholesale sale.

490. In response to Midwest ISO\'s desire to process all
     interconnections (whether to Commission-jurisdictional or
     non-Commission-jurisdictional facilities) under its tariff, we note
     that the Commission does not have the authority to order states to
     use Midwest ISO\'s tariff to process interconnections with state or
     other non-jurisdictional facilities. However, we encourage the
     states and others to use the Commission\'s interconnection rule or
     the NARUC Model as a starting point for developing their own
     interconnection rules.

491. Many commenters also address the legality of the Small Generator
     Interconnection NOPR\'s proposed use of 69 kV to determine whether
     portions of the SGIP would apply. Since the Commission has
     abandoned this distinction in this Final Rule, these arguments are
     moot.

> **Arguments that the Commission Should Delay or Abandon the Small
> Generator Interconnection Rulemaking**[]{#__RefHeading___Toc103479329
> .anchor}

492. Several commenters argue that the Proposed SGIP and Proposed SGIA
     are too complicated for small entities and would create a barrier
     to entry. Some commenters argue that the Commission should delay
     issuing a Final Rule and allow the various states and other
     entities to develop their own model rules. Others disagree.[^158]

493. This Final Rule includes several provisions to address these
     concerns. First, we are adopting a separate
     application/procedures/terms and conditions document for very small
     certified inverter-based Small Generating Facilities. This is a big
     step in facilitating quick interconnections at very little cost, as
     long as they can be made safely and without harming reliability. We
     are also simplifying many SGIA provisions at the request of
     commenters. This Final Rule borrows liberally from NARUC\'s Model
     interconnection rules, which are simpler than the Small Generator
     Interconnection NOPR.

494. We address below specific comments relating to our decision to
     proceed with this Final Rule. We have divided commenters\'
     arguments into three sections: (1) arguments that the Commission
     should defer to the states to deal with small generator
     interconnections; (2) arguments that the Commission\'s NOPR is too
     complex; and (3) arguments that the Commission should adopt a
     policy statement or model rules instead of a Final Rule.

     **Arguments in Favor of Deferring to the States on Small Generator
     Interconnections**[]{#__RefHeading___Toc103479330 .anchor}

     **Comments**

495. NARUC proposes that the Commission adopt its Model, arguing that it
     \"would offer the greatest possibility of consistency between
     Federal and State interconnection policies\"[^159] It explains that
     \"the NARUC Model was developed by melding the best practices of
     existing State distributed generation interconnection
     programs.\"[^160] NARUC argues in its supplemental comments that
     state programs are successful and that imposing an unnecessary
     layer of federal regulation will be disruptive to small generator
     developers and customers. Commission action can only create
     confusion and impede project development. Because states have
     better insight into local operating, planning, safety, reliability,
     and adequacy needs and conditions, they are in the best position to
     address the interconnection of small generators, regardless of what
     those generators may do with the output from their facilities or
     where they are interconnected. At bottom, NARUC urges the
     Commission to take no action on the Small Generator Interconnection
     NOPR. In the alternative, if the Commission implements small
     generator interconnection rules, it should grandfather existing
     state interconnection programs and the interconnections
     accomplished under such programs, and include a mechanism for
     granting deference to future state small generator interconnection
     programs.

496. CPUC states that California, New York, Ohio, and Texas all have
     interconnection procedures applicable to their state-regulated
     utility \"distribution\" systems.[^161] Because one third of the
     country\'s population already lives in states with standard
     interconnection rules, there is no need for Commission action. It
     also contends that (1) existing California interconnection rules
     meet the needs of small generators seeking to connect to
     state-jurisdictional utility \"distribution\" systems, (2)
     California procedures already provide small generators with
     one-stop shopping, and (3) there is no \"actual or legitimate need
     for FERC assistance to cover interconnections to
     state-jurisdictional facilities in states where distributed
     generation interconnection rules are already in place.\"[^162]

497. Furthermore, CPUC argues, only state-specific interconnection rules
     can account for \"regional practices.\" As an example, CPUC\'s
     rules allow it to exempt small Transmission Providers, but the
     Small Generator Interconnection NOPR lacks such needed
     flexibility.[^163] In sum, CPUC questions the need for the
     Commission\'s proposal

     and asserts that \"there is no legitimate public policy basis for
     the assertion of FERC jurisdiction over small generators that would
     result if the FERC proposal were adopted.\"[^164]

498. In contrast, Cummins argues that the Commission should assert
     jurisdiction over all interconnections, regardless of whether the
     interconnection is with a Commission-jurisdictional facility.
     Cummins argues that, although Small Generating Facilities often
     connect at the \"distribution\" level, their effects can be felt on
     the Transmission System. It explains that, because Small Generating
     Facilities can relieve congestion on crowded transmission
     facilities, the effect of even on-site Small Generating Facilities
     is felt beyond the Point of Interconnection. Thus, it is important
     that the Commission use all its jurisdictional authority to apply
     this rule as broadly as possible. And, where the Commission does
     not have jurisdiction, Cummins encourages state regulators to
     develop interconnection rules that are consistent with this Final
     Rule.

499. Plug Power claims that by not proposing standards applicable to
     interconnections with distribution facilities, the Commission\'s
     interconnection rules will not help small generators. Further, the
     rules proposed in the NOPR are inferior to those already in place
     in several states.

500. EEI urges the Commission to work with states to better define the
     state-federal role in small generator interconnections. According
     to EEI, this approach would provide both Interconnection Customers
     and Transmission Providers with clear guidance as to which rules
     apply to which interconnections. Finally, EEI states that, with
     certain modifications, the interconnection procedures document and
     agreement could be a model for use by both federal and state
     authorities to process small generator Interconnection Requests.

501. CT DPUC, while supporting the Commission\'s efforts, argues that
     this Final Rule should not lead to a loss of state jurisdiction.

     **Commission Conclusion**

502. We agree with commenters that general consistency between the
     Commission\'s interconnection procedures document and agreement and
     those of the states will be helpful to removing roadblocks to the
     interconnection of small generators. To a large extent, this Final
     Rule harmonizes state and federal practices by adopting many of the
     provisions proposed by NARUC and Joint Commenters. This Final Rule
     adopts interconnection rules that are largely consistent with the
     \"best practices\" interconnection rules proposed by NARUC. By
     doing so, we hope to minimize the federal-state division and
     promote consistent, nationwide interconnection rules.[^165] We hope
     that states that do not currently have interconnection rules for
     small generators will look to the documents presented in this Final
     Rule and the NARUC Model as guides for their own rules. To
     grandfather existing state interconnection programs and grant
     deference to future state small generator interconnection programs
     would not fulfill the Commission's statutory mandate to regulate
     jurisdictional activities, of which generator interconnection is
     one. However, as discussed elsewhere, the all-in-one document for
     certified inverter-based generators no larger than 10 kW should go
     a long way towards harmonizing state-federal interconnection
     practices for this class of generators.

503. Our hope is that states may find these interconnection rules
     helpful in formulating their own interconnection processes. In
     particular, we hope the Fast Track and 10 kW Inverter Processes
     will prove helpful as starting points from which to develop their
     own procedures and agreements.

504. The concerns of CPUC and several other commenters that the
     Commission is claiming jurisdiction over interconnections with
     non-Commission jurisdictional facilities are addressed elsewhere in
     more detail.

     **Arguments that the NOPR Is Too
     Complex**[]{#__RefHeading___Toc103479331 .anchor}

     **Comments**

505. CPUC argues that the Proposed SGIA and Proposed SGIP are too
     complicated for small Interconnection Customers, especially the
     smallest, to use. Small Generator Coalition argues that unless the
     Commission is willing to modify the NOPR in fundamental ways, many
     of its members believe that development of Small Generating
     Facilities would be better served if the NOPR were simply
     withdrawn. According to Small Generator Coalition, the NOPR\'s
     framing of

     interconnection issues as a competition between maintaining system
     reliability and encouraging small resources is wholly
     inappropriate, and it gives disproportionate weight to the
     reliability \'concerns\' of transmission/distribution owners with
     generating units of their own. That system reliability must not be
     compromised goes without saying, but the need for system
     reliability does not compete with the goal of encouraging small
     resource development via affordable and clear interconnection terms
     and conditions. The compatibility of small resources with the grid
     was proven long ago -- there are literally thousands of such small
     resources in place and operating in the United States, safely
     interconnected with the grid (such as the solar array on the roof
     of the Commission\'s own office building).\[[^166]\]

506. Small Generator Coalition says that on-site Small Generating
     Facilities actually enhance electric system reliability, and that
     complex technical provisions should therefore not be required.

507. Plug Power asserts that unless the Commission adopts a simpler
     SGIA, the Commission\'s rulemaking will not help to reach national
     interconnection standards.[^167] Of particular concern to Plug
     Power are the Proposed SGIA\'s insurance requirements and what Plug
     Power terms its open-ended cost provisions.

508. CT DPUC urges the Commission to adopt rules that are not
     unnecessarily complicated to administer.

     **Commission Conclusion**

509. We agree with commenters that the Small Generator Interconnection
     NOPR contained some provisions that were overly complicated for
     many Small Generating Facility interconnections. Wherever possible,
     we have simplified the SGIP and SGIA. And, for very small certified
     Small Generating Facilities, this Final Rule includes the highly
     simplified 10 kW Inverter Process.

     **Arguments in Favor of a Non-Binding Model
     Rule**[]{#__RefHeading___Toc103479332 .anchor}

     **Comments**

510. CPUC states that it would support Commission efforts to establish
     non-binding guidelines, or a model rule, for use by states that
     have not yet adopted their own standards.

511. NARUC comments that any standard interconnection procedures
     document and agreement issued by the Commission that disclaims
     jurisdiction over \"local distribution\" facilities has limited
     applicability. It also claims that states are better situated to
     handle small generator interconnections, and having two competing
     interconnection regimes for small generator interconnections would
     be confusing. NARUC therefore also urges the Commission to adopt a
     policy statement instead of a binding rule.

     **Commission Conclusion**

512. We conclude that as much standardization as possible of the rates,
     terms, and conditions of jurisdictional interconnection service
     will help eliminate undue discrimination. A non-binding policy
     statement would not end this undue discrimination. Further, not
     regulating jurisdictional interconnections would leave a regulatory
     gap where neither the states nor the Commission held sway. A gap of
     this sort would make it more difficult for Interconnection
     Customers wanting to interconnect and would in fact, leave them
     worse off than the owners of Large Generating Facilities.

513. This Final Rule both fulfills the Commission\'s duty to remedy
     undue discrimination when covered by this rule and, when not
     covered by this rule, provides a model that state regulators may
     wish to use as a starting point for developing their own procedures
     and agreement. We hope that the SGIP and SGIA we adopt in this
     Final Rule are a step towards having a seamless interconnection
     process where interconnections with federal-jurisdictional
     facilities and state-jurisdictional facilities will be handled in a
     similar fashion. By doing so, we intend to avoid the very
     federal-state clashes NARUC anticipates.

     **Issues Relating to Qualifying
     Facilities**[]{#__RefHeading___Toc103479333 .anchor}

514. The NOPR did not address the issue of how QFs would be impacted by
     the small generator rulemaking.

**Comments**

515. EEI and PacifiCorp ask the Commission to clarify that a QF that is
     not selling at wholesale, other than to a host utility under PURPA,
     should seek interconnection service through state procedures, not
     through Commission procedures. PacifiCorp states that the PURPA
     regulatory scheme for QFs involves considerable deference to state
     regulation with regard to the interconnection of QFs to
     state-regulated utilities. The Iowa Utilities Board agrees and
     asserts that this Final Rule should say that states have authority
     to establish standards for the interconnection of QFs. To avoid
     confusion, PacifiCorp proposes that the SGIP state clearly that a
     Small Generating Facility with QF status or one seeking such status
     is not eligible for interconnection under the Commission\'s rule.
     PacifiCorp recommends amending the Interconnection Request so that
     the Interconnection Customer must certify that it does not intend
     to seek QF status. If it then seeks QF status, PacifiCorp proposes
     to require a review of the interconnection to determine whether it
     meets state interconnection standards for QFs. The Interconnection
     Customer would also pay any costs incurred by the Transmission
     Provider that a QF would have paid, if such costs would not be
     recovered by the Transmission Provider under the SGIP.

**Commission Conclusion**

516. The Commission has regulations that govern a QF\'s interconnection
     with most electric utilities in the United States,[^168] including
     normally non-jurisdictional utilities.[^169] When an electric
     utility is required to interconnect under section 292.303 of the
     Commission\'s regulations, that is, when it purchases the QF\'s
     total output, the state has authority over the interconnection and
     the allocation of interconnection costs.[^170] But when an electric
     utility interconnecting with a QF does not purchase all of the
     QF\'s output

     and instead transmits the QF\'s power in interstate commerce, the
     Commission exercises jurisdiction over the rates, terms, and
     conditions affecting or related to such service, such as
     interconnections.[^171]

517. The Commission thus exercises jurisdiction over a QF\'s
     interconnection if the QF\'s owner sells any of the QF\'s output to
     an entity other than the electric utility directly interconnected
     with the QF. This Final Rule applies when the owner of the QF seeks
     interconnection with a facility subject to the OATT to sell any of
     the output of the QF to a third party. This applies to a new QF
     that plans to sell any of its output to a third party and to an
     existing QF interconnected with an electric utility or on-site
     customer that decides in the future to sell any of its output to a
     third party. States continue to exercise authority over QF
     interconnections when the owner of the QF sells the output of the
     QF only to the interconnected utility or to on-site customers.

518. PacifiCorp\'s proposal that the Commission require the
     Interconnection Customer to certify that it does not intend to seek
     QF status is unnecessary. This Final Rule only applies when the
     interconnection is subject to the Commission\'s jurisdiction. Other
     rules apply if the generator seeks to interconnect as a QF.
     PacifiCorp has provided no convincing rationale why this proposed
     amendment is necessary for this rulemaking.

     **Taxes**[]{#__RefHeading___Toc103479334 .anchor}

519. The NOPR did not explicitly address the potential taxation of
     payments made by the Interconnection Customer to the Transmission
     Provider for Interconnection Facilities and Upgrades.

     **Comments**

520. A few commenters urge the Commission to address taxes. They argue
     that the Commission should adopt an approach similar to that taken
     in the LGIA so that any taxes incurred by the Transmission Provider
     are not shifted to its customers.

521. Because payments received for Upgrades by the Transmission Provider
     may be taxed, EEI and Ameren ask the Commission to clarify how the
     Transmission Provider will recover those tax payments. Further, EEI
     argues that additional financial security may be required because
     such facilities could be jurisdictional to either the Commission or
     state utility commissions. Additional financial security would
     ensure that the utility is not forced to recover such costs from
     its entire customer base. EEI proposes that the following sentence
     be added to Proposed SGIA article 5.2: \"\[The\] Transmission
     Provider may request additional financial security to cover tax
     liabilities that it may incur as a result of a transaction being
     deemed by the Internal Revenue Service to have been a taxable
     event, for example, when an Interconnection Customer terminates a
     signed Interconnection Agreement.\"

522. Southern Company proposes a tax provision modeled after the ANOPR
     consensus documents. Under Proposed SGIA article 5.1.2.1, the
     refunds paid to the Interconnection Customer through transmission
     credits include \"any tax gross-up or other tax-related payments\"
     in connection with Network Upgrades required for interconnection.
     It argues that if the Interconnection Customer receives
     transmission credits for such payments, all other transmission
     customers will have to bear the tax liability created by the
     Interconnection Customer. Transmission credits should be provided
     to the Interconnection Customer for the cost of installing
     facilities only if those costs may facilitate transmission delivery
     service. Any tax gross-up paid by the Interconnection Customer
     would not facilitate transmission delivery service, but instead
     would be a tax liability created solely by the interconnection.
     Moreover, requiring the refund through credits of taxes paid, plus
     interest, would force the Transmission Provider to pay the full
     carrying cost of income taxes on the Interconnection Customer\'s
     assets with no means of recouping the expenditure.

> **Commission Conclusion**

523. The commenters are correct that payments received for Upgrades by
     the Transmission Provider may be taxed under certain circumstances.
     If construction of Upgrades is necessary, any associated taxes are
     to be handled consistent with Commission precedent and applicable
     tax rules and regulations. In particular, the Parties should then
     look to the LGIA\'s tax framework.[^172] We also reiterate that it
     is Commission policy that each Party must cooperate with the other
     Party to maintain the Transmission Provider\'s tax exempt status,
     where applicable.

     **OATT Reciprocity Requirements**

524. The Small Generator Interconnection NOPR did not propose any
     changes to the existing reciprocity policy; accordingly, the Small
     Generator Interconnection NOPR did not discuss it.

     **Comments**

525. NRECA states that it \"applauds the Commission\'s decision to apply
     the reciprocity provision in the OATT and the reciprocity policy
     articulated in Order No. 888 \[and\] appreciates the sensitivity
     the Commission has demonstrated to the needs of non-jurisdictional
     service providers.\"[^173] However, it remains concerned that
     non-public utilities may be discouraged from interconnecting new
     generation out of fear that such an interconnection will make them
     subject to the jurisdiction of the Commission. To avoid this, NRECA
     advocates the creation of a safe harbor for non-jurisdictional
     entities that want to interconnect new generation, yet maintain
     their non-jurisdictional status. NRECA points to several Commission
     natural gas decisions that it asserts provide precedent for
     creating a safe harbor of the type it proposes. NRECA also states
     that the Commission could achieve the same result by ordering an
     interconnection under section 211 of the FPA.

526. AMP-Ohio and LADWP ask the Commission to clarify that the
     reciprocity condition applies only to the public utility over whose
     system the non-public utility takes transmission service. They also
     ask the Commission to clarify that there is no reciprocity
     obligation on the part of a non-public utility that owns only
     distribution facilities, not transmission facilities. The effect of
     most small generators is felt at the distribution level, LADWP
     argues, and these interconnections are more likely to affect retail
     customers. SMUD makes a similar argument.

527. PacifiCorp requests that the Commission clarify that if a public
     utility is forced to offer interconnection service on its
     distribution lines to a non-public utility under the reciprocity
     condition, then the public utility must be offered similar rights
     to interconnect with the non-public utility. PacifiCorp argues that

     \[b\]ecause many non-jurisdictional utilities own distribution
     systems that they do not consider \'transmission,\' even when the
     corresponding system of a public utility is considered transmission
     by the Commission, the potential for discriminatory impact is real.
     At a minimum, the definition of a non-jurisdictional utility\'s
     \'transmission facilities\' should be modified to include any
     distribution facility that would be considered \'transmission\' if
     it were owned by a jurisdictional utility.\[[^174]\]

528. SMUD asks if reciprocity applies when the Interconnection Customer
     seeks to connect at distribution voltage to the non-jurisdictional
     utility and proposes to engage in sales for resale. It also asks if
     reciprocity applies differently for non-jurisdictional utilities
     seeking bilateral agreements with public utilities than to
     non-jurisdictional utilities seeking approval of safe harbor
     tariffs.

529. NRECA asks the Commission to clarify that a non-jurisdictional
     utility is not required to offer interconnection service if doing
     so would jeopardize its tax-exempt status.

530. Finally, Bureau of Reclamation, BPA, and others assert that as
     federal agencies, they are not able to comply with all of the
     provisions of the Proposed SGIP and SGIA. For instance, BPA says
     its contracts must accommodate the Freedom of Information Act and
     that it could not comply with all aspects of the Commission\'s
     proposed confidentiality provisions. BPA and Bureau of Reclamation
     request clarification that they are not required to comply with
     these provisions.

     **Commission Conclusion**

531. Most of the comments focus on whether interconnections with
     \"distribution\" systems are subject to the reciprocity condition.
     The answer is, to satisfy the reciprocity condition of Order No.
     888, a non-public utility must offer to a public utility with an
     OATT service comparable to that offered to its own or affiliated
     Interconnection Customers.[^175]

532. PacifiCorp is correct that what the facility is termed by its owner
     does not affect its jurisdictional status. The reciprocity
     condition would apply to any facility used to offer services that
     would be Commission-jurisdictional if the non-public utility were a
     public utility.

     []{#__RefHeading___Toc103479335 .anchor}

533. The reciprocity requirement in Order No. 888 permits a public
     utility to require, as a condition of providing open access service
     to a non-public utility that owns, controls, or operates
     transmission facilities, that the non-public utility provide
     reciprocal transmission service. In Order No. 2003-A, the
     Commission explained that the reciprocity provision applies to
     Interconnection Service in the same way.[^176]

534. There are three ways a non-public utility may satisfy the
     reciprocity provision.[^177] First, it may provide service under a
     Commission-approved \"safe harbor\" tariff -- a tariff that the
     Commission has determined offers truly open access service. Second,
     it may provide service to a public utility under a bilateral
     agreement that satisfies its reciprocity obligation. Third, the
     non-public utility may ask the public utility to waive the
     reciprocity condition.

535. A non-public utility that has a \"safe harbor\" tariff that is
     modeled on the OATT must add to that tariff an interconnection
     procedures document and interconnection agreement that either are
     modeled on the OATT interconnection procedures document and
     agreement or are otherwise found to offer truly open access service
     if it wishes to continue to qualify for \"safe harbor\"
     treatment.[^178] A non-public utility that owns, controls, or
     operates transmission, has not filed with the Commission a \"safe
     harbor\" tariff, and seeks transmission service from a public
     utility that invokes the reciprocity provision must either satisfy
     its reciprocity obligation under a bilateral agreement or ask the
     public utility to waive the OATT reciprocity condition.

536. This Final Rule does not modify the Commission\'s reciprocity
     policy as laid out in Order Nos. 888 and 2003.

537. LADWP also states that there are relatively few
     Commission-jurisdictional Small Generating Facility
     interconnections and urges the Commission not to apply its
     reciprocity

     policy in the small generator context. The fact that there may be
     relatively few interconnections subject to this Final Rule does not
     justify abandoning long-standing reciprocity policy.

538. As the Commission determined in Order Nos. 888[^179] and
     2003-A,[^180] reciprocal service is not required if providing such
     service would jeopardize the tax-exempt status or bond status of
     the non-public utility.

539. As to BPA and Bureau of Reclamation\'s comments, we reiterate that
     reciprocity does not require federal entities to provide services
     or sign contracts that they cannot legally enter into. If such
     entities choose to amend their safe harbor tariffs on compliance,
     they may propose modifications to the SGIP and SGIA that address
     their concerns.

540. Finally, we deny NRECA\'s proposed safe harbor provision. As it
     notes, section 211 of the FPA already allows a non-public utility
     to safeguard its non-jurisdictional status. We see no need to fix a
     system that does not appear to be broken.

     **Coordination with Affected
     Systems**[]{#__RefHeading___Toc103479336 .anchor}

541. An Affected System is an electric system other than the
     Transmission Provider that may be affected by the proposed
     interconnection. In the Small Generator Interconnection NOPR, the
     Commission proposed to treat coordination between the Transmission
     Provider, Interconnection Customer, and any Affected Systems the
     same way as in the LGIA. Order Nos. 2003 and 2003-A required the
     Transmission Provider to coordinate with an Affected System. The
     Commission requested comments on whether there are any issues
     specific to Small Generating Facilities that necessitate a
     different policy.

     **Comments**

542. While no commenters present any arguments on this issue specific to
     the small generator context, some discuss the Affected System
     provision in terms of Distribution Systems.

     **Commission Conclusion**

543. We are adopting an Affected System provision comparable to the one
     in the LGIP and LGIA. Regarding the comments addressing the
     Affected System provision in terms of Distribution Systems subject
     to an OATT, we note that the definition of Affected System includes
     not only transmission facilities. The definition is more inclusive;
     it is \"an electric system . . . that may be affected by the
     proposed interconnection.\" Thus, an Affected System may be any
     type of electric system.[^181]

     **I. Compliance Issues**[]{#__RefHeading___Toc103479337 .anchor}

     **Amendments to the Transmission Provider\'s OATT**

544. In this Final Rule, we are requiring all public utilities that own,
     control, or operate interstate transmission facilities to adopt the
     SGIP and SGIA, but are using a process different from the one used
     in Order No. 2003. On the effective date of Order No. 2003, the
     OATT of each Transmission Provider was deemed to have included the
     LGIP and LGIA.[^182] On the effective date of this Final Rule, as
     in Order No. 2003,[^183] the OATTs of all non-independent
     Transmission Providers are deemed revised to include the Final Rule
     SGIP and SGIA. But unlike the Order No. 2003 process, where the
     Commission directed Transmission Providers to make ministerial
     filings to include the LGIP and LGIA in their next filings with the
     Commission, here the Commission will require no formal amendment
     until compliance is due in the Commission\'s rulemaking on
     Electronic Tariff Filings.[^184] This means that a non-independent
     Transmission Provider that wishes to adopt the SGIP and SGIA
     (without variations) into its OATT need not formally add the
     documents to its OATT until it submits a compliance filing in
     response to the Commission\'s pending Electronic Tariff Filings
     rulemaking. A non-independent Transmission Provider that decides to
     take this option nevertheless must apply the SGIP and SGIA to any
     request for small generator interconnection that it receives after
     the effective date of this Final Rule, but before it complies with
     the rulemaking on Electronic Tariff Filings. The compliance
     obligation is different for non-independent Transmission Providers
     that seek variations from the Final Rule documents, as discussed
     further below.

[]{#__RefHeading___Toc103479338 .anchor}

545. If an RTO or ISO wishes to adopt the SGIP and SGIA into its OATT,
     it may also await compliance with the Electronic Tariff Filings
     rulemaking before formally adding the documents to its OATT. But
     the RTO or ISO should notify the Commission by the effective date
     of this Final Rule that it will adopt the Final Rule documents and
     that requests for interconnection of Small Generating Facilities
     will be subject to the SGIP and SGIA in the interim period. An RTO
     or ISO that does not adopt the SGIP and SGIA will have additional
     time to submit its compliance filings to allow for the stakeholder
     process and other measures that must be taken before an RTO or ISO
     adopts tariff changes. Therefore, an RTO or ISO that seeks
     variations will have an additional 90 days to submit its compliance
     filing. As in the Order No. 2003 proceeding, until the Commission
     acts on the compliance filing of an RTO or ISO that seeks
     variations, the RTO\'s or ISO\'s existing Commission-approved
     interconnection procedures and agreement remain in effect.

     **Variations from the Final Rule**[]{#__RefHeading___Toc103479339
     .anchor}

546. As in Order No. 2003, the Commission will consider two categories
     of variations from the Final Rule submitted by a non-independent
     Transmission Provider.[^185] First, the Commission will consider
     \"regional reliability variations\" that track established
     reliability requirements (i.e., requirements approved by the
     applicable regional reliability council). Any request for a
     \"regional reliability variation\" must be supported by references
     to

     established reliability requirements,[^186] 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. Blanket statements that a variation meets the standard
     or clarifies the Final Rule provision are not sufficient. Any
     request for application of this standard will be considered under
     FPA section 205 and must be supported by arguments explaining how
     each variation meets the standard.

547. Requests for regional reliability variations are due on the
     effective date of this Final Rule. Requests for \"consistent with
     or superior to\" variations may be submitted on or after the
     effective date of the Final Rule. We note that the \"consistent
     with or superior to\" standard is difficult to meet because the
     burden of showing that a variation is \"consistent with or superior
     to\" the relevant provision or provisions in the Final Rule
     document is significant.

548. Any request for a variation should be accompanied by a request to
     include the complete SGIP and SGIA into the Transmission
     Provider\'s OATT. The Commission will consider incomplete any
     request for a variation that does not also propose to append to the
     Transmission Provider\'s OATT the complete SGIP and SGIA. As
     explained above, an RTO or ISO will have 90 additional days (for a
     total of 150 days) to submit a compliance filing. That compliance
     filing must contain all proposed independent entity variations.

549. With respect to an RTO or ISO, at the time its compliance filing is
     made, as explained in Order No. 2003, the Commission will allow it
     to seek \"independent entity variations\" from the Final Rule
     pricing and non-pricing provisions.[^187] The RTO or ISO should
     explain the basis for each variation.

550. Finally, for a non-independent Transmission Provider that belongs
     to an RTO or ISO, the RTO\'s or ISO\'s Commission-approved
     standards 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]{.underline} under the operational control of the RTO
     or ISO is to be conducted according to the non-independent
     Transmission Provider\'s procedures and agreement. 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 from the RTO or ISO\'s
     OATT). To clarify, if a non-independent Transmission Provider
     belongs to an RTO or ISO, but keeps operational control of some
     jurisdictional facilities, and those facilities are not subject to
     the interconnection procedures under the OATT of the RTO or ISO,
     then the non-independent Transmission Provider must have a separate
     set of interconnection procedures and agreement applicable to these
     facilities. To address the confusion that may arise from having
     inconsistent interconnection procedures and agreements applicable
     within an RTO or ISO region, we allow a non-independent
     Transmission Provider that keeps control over some jurisdictional
     facilities to subject these facilities to an RTO- or ISO-controlled
     interconnection process. In such instance, the non-independent
     Transmission Provider must agree to transfer to the RTO or ISO
     control over the significant aspects of the interconnection
     process, including the performance of all interconnection studies
     and cost determinations applicable to Network Upgrades.[^188]

     **Interconnection Requests Submitted Prior to the Effective Date of
     this Final Rule and Grandfathering of Existing Interconnection
     Agreements**[]{#__RefHeading___Toc103479340 .anchor}

551. The grandfathering of existing agreements was not specifically
     addressed in the Small Generator Interconnection NOPR; however, the
     Commission did request comments on whether generic Commission
     policies applicable to Large Generating Facilities (such as
     grandfathering) should be applied to Small Generating Facilities.

     **Comments**

552. American Forest and National Grid seek clarification that small
     generators that are already interconnected are not subject to this
     rulemaking. To avoid unintended barriers to Small Generating
     Facilities, they urge the Commission to follow the Order No. 2003
     approach for grandfathering. American Forest states that generators
     should not have to undergo this new interconnection process,
     particularly where the generating facilities that are already
     interconnected have not changed their physical operations.

553. California Wind Energy requests that, as in Order No. 2003,
     contract conversion of pre-existing interconnection contracts with
     former QFs should not trigger an obligation under this Final Rule
     to file an Interconnection Request because a change in contract
     status alone does not affect a generator\'s demand on the electric
     system. It also seeks clarification that, when the QF\'s
     interconnection agreement provides for greater capacity than what
     is to be sold to the interconnecting utility under the PURPA power
     purchase contract, upon contract conversion, the former QF should
     not have to submit an Interconnection Request if the transmission
     requirements are consistent with those provided for in the prior
     agreement.

554. Finally, if the Commission adopts the approach used in Order No.
     2003, California Wind Energy requests that the Commission clarify
     when a change in a QF\'s contract status triggers an obligation to
     file a new Interconnection Request. It notes that Order No. 2003
     states that the owner of a QF formerly interconnected with a
     Transmission System has no obligation to file an Interconnection
     Request when its contract status changes if the output of its
     generator \"will be substantially the same as before.\"[^189]
     California Wind Energy asserts that the term \"output\" leaves
     ambiguous the effect of the Commission\'s criteria on projects that
     are to be repowered after contract conversion. It explains that
     when a QF repowers, it increases energy production while
     maintaining its maximum megawatt output. California Wind Energy
     seeks clarification that when a small generator increases energy
     production as a result of a post-PURPA contract repower, and there
     is no meaningful change in the generator\'s maximum output, there
     is no obligation to file a new Interconnection Request.

     **Commission Conclusion**

555. As in Order No. 2003, the Commission is not requiring changes to
     interconnection agreements filed with the Commission before the
     effective date of this Final Rule. Interconnection agreements
     submitted for approval by the Commission before the effective date
     of this Final Rule are grandfathered and will not be rejected
     outright for failing to conform to the SGIA. Small Generating
     Facilities already interconnected that have not changed their
     physical operations in such a way as to require a new
     Interconnection Request are not subject to this rulemaking.

556. We also note that the Small Generator NOPR did not address what
     happens to Interconnection Customers whose Interconnection Requests
     are pending at the time this Final Rule goes into effect. LGIP
     section 5 addresses how such interconnections are to be processed,
     and we adopt a shortened version of that provision in the SGIP as
     well. The new section 1.7 clarifies that nothing in this Final Rule
     is intended to affect an Interconnection Customer\'s Queue Position
     assigned prior to the effective date of this rule. It also states
     that the Parties shall continue to process any executed
     interconnection study agreements (or study agreements that have
     been filed unexecuted with the Commission) once this Final Rule
     becomes effective. However, we will require that any new
     interconnection study agreement entered into after this Final Rule
     becomes effective follow the [pro forma]{.underline} study
     agreements contained in the SGIP. Any accommodation needed to
     process such Interconnection Requests (i.e., should the pre- and
     post- Final Rule study processes be significantly different) should
     be filed with the Commission and will be evaluated on a
     case-by-case basis.

557. If an interconnection agreement has been executed prior to the
     effective date of this Final Rule, then no additional steps need to
     be taken. We agree with the commenters that an existing
     Interconnection Customer whose Small Generating Facility is already
     interconnected should not have to undergo a new interconnection
     process.

558. We also reiterate that a change in an Interconnection Customer\'s
     contract status does not, by itself, trigger an obligation to file
     an Interconnection Request. As the Commission noted in Order Nos.
     2003 and 2003-A, a former QF interconnected with a Transmission
     System that sells electric energy at wholesale in interstate
     commerce need not submit an Interconnection Request if it
     represents that the output of the generating facility is
     substantially the same as before.[^190] Under the Commission\'s
     regulations,[^191] a QF must provide electric energy to its
     interconnecting utility much like the interconnecting utility\'s
     other network resources because the utility must purchase the QF\'s
     power to displace its own generation. When the owner of a QF that
     was formerly interconnected with a Transmission System seeks to
     sell energy at wholesale and represents that the output of its
     generator will be substantially the same after conversion, it would
     be unreasonable for a Transmission Provider to require the former
     QF to join the interconnection queue.

559. California Wind Energy also asks the Commission to clarify that a
     plant repowering at the time of contract conversion that does not
     increase plant capacity will not trigger an obligation to file an
     Interconnection Request. We clarify that a contract conversion that
     does not affect a generator\'s demands on the Transmission System
     does not trigger an obligation to file. When a QF\'s existing
     interconnection agreement provides for capacity greater than the
     capacity sold by the QF to the interconnecting utility under the
     PURPA power purchase contract, the QF\'s contract conversion will
     not trigger an obligation to file an Interconnection Request if its
     transmission requirements are consistent with the capacity provided
     for in the existing interconnection agreement.

     **Order No. 2001 and the Filing of Interconnection
     Agreements**[]{#__RefHeading___Toc103479341 .anchor}

560. Order No. 2001[^192] revised how traditional public utilities and
     power marketers must satisfy their obligation, under section 205 of
     the FPA and Part 35 of the Commission\'s regulations, to file
     agreements with the Commission.[^193] Public utilities that have
     standard forms of agreement in their OATTs, cost-based power sales
     tariffs, or tariffs for other generally applicable services no
     longer need to file conforming service agreements with the
     Commission. The filing requirement for conforming agreements (those
     that follow the standard form) is now satisfied by filing the
     standard form of agreement and an Electronic Quarterly Report.
     Order No. 2001 also lifted the requirement that Parties to an
     expiring conforming agreement file a notice of cancellation or a
     cancellation tariff sheet with the Commission. The public utility
     may simply remove the agreement from its Electric Quarterly Report
     in the quarter after it terminates.

561. Non-conforming agreements, which are agreements for transmission,
     cost-based power sales or other generally applicable services that
     do not conform to a standard form of agreement in a public
     utility\'s tariff, must continue to be filed with the Commission
     for approval before going into effect. This category includes
     unexecuted agreements and agreements that do not precisely match
     the standard form of agreement.

562. Order No. 2003 explained that, under Order No. 2001, if an
     interconnection agreement conforms to a Commission-approved
     standard form of interconnection agreement, the Transmission
     Provider does not have to file it with the Commission, but must
     report it in its Electric Quarterly Reports. The same filing rules
     will apply to non-conforming SGIAs as for non-conforming LGIAs.
     However, an interconnection agreement that does not precisely match
     the Transmission Provider\'s Commission-approved standard
     interconnection agreements or that is unexecuted must be filed in
     its entirety. The Transmission Provider shall clearly show where
     the filed agreement does not conform to its standard
     interconnection agreement through red-lining and strike-out and
     justify the basis for the nonconformance.

     **III. Information Collection
     Statement**[]{#__RefHeading___Toc103479342 .anchor}

563. The Office of Management and Budget (OMB) regulations require that
     OMB approve certain reporting and record keeping (collections of
     information) imposed by an agency.[^194] The information collection
     requirements in this Final Rule are identified under the Commission
     data collection, FERC-516A \"Standardization of Small Generator
     Interconnection Agreements and Procedures.\" Under section 3507(d)
     of the Paperwork Reduction Act of 1995,[^195] the proposed
     reporting requirements in the subject rulemaking will be submitted
     to OMB for review. Interested persons may obtain information on the
     reporting requirements by contacting the Federal Energy Regulatory
     Commission, 888 First Street, NE, Washington, D.C. 20426
     (Attention: Michael Miller, Office of the Executive Director,
     202-502-8415) or from the Office of Management and Budget
     (Attention: Desk Officer for the Federal Energy Regulatory
     Commission, fax: 202-395-7285, e-mail:[mailto:](mailto:)
     oira_submission@omb.eop.gov).

564. The \"public protection\" provision of the Paperwork Reduction
     Act[^196] requires each agency to display a currently valid OMB
     control number and inform respondents that a response is not
     required unless the information collection displays a valid OMB
     control number on each information collection. This provision has
     two legal effects: (1) it creates a legal responsibility for the
     agency; and (2) it provides an affirmative legal defense for
     respondents if the information collection is imposed on respondents
     by the Commission through regulation or administrative means in
     order to satisfy a legal authority or responsibility of the
     Commission. If the Commission should fail to display an OMB control
     number, then it is the Commission not the respondent who is in
     violation of the law. "Display" is defined as publishing the OMB
     control number in regulations, guidelines or other issuances in the
     [Federal Register (]{.underline}for example, in the preamble or
     regulatory text for the final rule containing the information
     collection).[^197] Therefore, the Commission may not conduct or
     sponsor, and a person is not required to respond to a collection of
     information unless the information collection displays a valid OMB
     control number.

565. **Public Reporting Burden**: The Commission did not receive
     specific comments concerning its burden estimates and uses the same
     estimates here in the Final Rule. Comments on the substantive
     issues raised in the NOPR are addressed elsewhere in the Final
     Rule.

  --------------- -------------- -------------- -------------- --------------
  Data Collection No. of         No. of         Hours Per      Total Annual
                  Respondents    Responses      Response       Hours

  FERC-516A                                                    

  SGIPs & SGIAs   238            1              25             5,950

  Recordkeeping   238            1              2              476

  Totals                                                       6,426
  --------------- -------------- -------------- -------------- --------------

Total Annual Hours for Collection: 5,950 (reporting) \[238 respondents x
1 x 25 hours\] + 476 hours (recordkeeping ) \[238 hours x 1 filing x 2
hours to retain interconnection documents\] = 6,426.[^198]

566. **Information Collection Costs**: The Commission sought comments
     about the time needed to comply with these requirements. No
     comments were received. Staffing requirements to review and modify
     existing SGIPs and SGIAs = \$309,400 \[238 respondents x \$1,300
     (25 hours @ \$52 hourly rate)\]. To be added to this cost are the
     annualized costs for operations and management (238 respondents x
     \$34 \[2 hours @ \$17 hourly rate for recordkeeping\] or \$8,092)).
     Total costs of \$317,492 for preparing filings for modification of
     the OATT and for recordkeeping of interconnection documents. There
     will be a one-time start up cost to comply with these requirements
     for the procedures and agreements and then an additional cost to
     maintain them.[^199]

     **Titles**: FERC-516A \"Standardization of Small Generator
     Interconnection Agreements and Procedures

     **Action**: Revision of Currently Approved Collection of
     Information

     **OMB Control Nos**: 1902-0203.

     **Respondents**: Business or other for profit.

     **Frequency of Responses**: One occasion.

     **Necessity of Information**: The Final Rule revises the reporting
     requirements contained in 18 CFR Part 35. The Commission
     promulgates a standardized SGIP and SGIA that public utilities must
     adopt. As noted in the Final Rule, adopting these procedures and
     agreement will (1) reduce interconnection costs and time for the
     owners of Small Generating Facilities and Transmission Providers
     alike; (2) limit opportunities for Transmission Providers to favor
     their own generation; (3) facilitate market entry for generation
     competitors; and (4) encourage needed investment in generator and
     transmission infrastructure.

567. Interconnection plays a growing, crucial role in bringing
     generation into the market to meet the needs of electricity
     customers. However, requests for interconnection frequently result
     in complex technical disputes about interconnection feasibility,
     cost and cost responsibility. The Commission expects that a
     standardized SGIP and SGIA will reduce interconnection costs and
     time for Interconnection Customers and Transmission Providers,
     resolve most interconnection disputes, minimize opportunities for
     undue discrimination, foster increased development of economic
     generation, and improve system reliability.

568. For information on the requirements, submitting comments on the
     collection of information and the associated burden estimates
     including suggestions for reducing this burden, please send your
     comments to the Federal Energy Regulatory Commission, 888 First
     Street, NE, Washington, D.C. 20426 (Attention: Michael Miller,
     Office of the Executive Director, 202-502-8415) or send comments to
     the Office of Management and Budget (Attention: Desk Officer for
     the Federal Energy Regulatory Commission, fax: 202-395-7285, e-mail
     oira_submission@omb.eop.gov).

     **IV. Environmental Impact
     Statement**[]{#__RefHeading___Toc103479343 .anchor}

569. Commission regulations require that an environmental assessment or
     an environmental impact statement be prepared for any Commission
     action that may have a significant adverse effect on the human
     environment.[^200] No environmental consideration is necessary for
     the promulgation of a rule that is clarifying, corrective, or
     procedural or does not substantially change the effect of
     legislation or regulations being amended,[^201] and also for
     information gathering, analysis, and dissemination.[^202] The Final
     Rule updates Part 35 of the Commission\'s regulations and does not
     substantially change the effect of the underlying legislation or
     the regulations being revised or eliminated. In addition, the Final
     Rule involves information gathering, analysis, and dissemination.
     Therefore, this Final Rule falls within categorical exemptions
     provided in the Commission\'s regulations. Consequently, neither an
     environmental impact statement nor an environmental assessment is
     required.

570. While some Small Generating Facilities, such as reciprocating
     engines, may produce more pollution, others, such as photovoltaics
     and fuel cells, produce significantly less air, water and noise
     pollution than do new central station technologies. Others, such as
     micro-turbines, provide opportunities to reduce emissions by
     improving the efficiency with which energy is consumed, through
     improved heat rates and combined heat and power applications. Small
     Generating Facilities may eliminate the need to run older, more
     polluting generating units and reduce power line losses. As one of
     the goals of this rule is to allow interconnection of Small
     Generating Facilities that can provide environmental and economic
     benefits, this rule will benefit customers by providing alternative
     generation sources.

     **V. Regulatory Flexibility Act**

     []{#__RefHeading___Toc103479344 .anchor}

571. The Regulatory Flexibility Act (RFA)[^203] requires that a
     rulemaking contain either a description and analysis of the effect
     that the proposed rule will have on small entities or a
     certification that the rule will not have a significant economic
     impact on a substantial number of small entities. However, the RFA
     does not define "significant" or "substantial" instead leaving it
     up to any agency to determine the impacts of its regulations on
     small entities. In the NOPR, the Commission stated that the
     proposed regulations would impose requirements only on interstate
     Transmission Providers, which are not small businesses. The
     Commission certified that the proposed regulations would not have a
     significant adverse impact on a substantial number of small
     entities. In making its certification, the Commission determined
     that the rule applies only to public utilities that own, control,
     or operate facilities for transmitting electric energy in
     interstate commerce and not to electric utilities per se. Small
     entities that believe this rule will have a significant impact on
     them may apply to the Commission for waivers.

     **Comments**

572. NRECA questions this certification. NRECA argues that to lessen the
     impact of this rule on small entities, the Commission should: \"(1)
     Provide a durable blanket waiver of the NOPR requirements to all
     currently FPA-jurisdictional utilities, that qualify as \'small\'
     public utilities under the Small Business Administration (SBA)
     utility size standards, and (2) provide a safe harbor for all
     \'small\' non-jurisdictional providers that want to work with
     consumers to interconnect generation, but want to maintain their
     non-jurisdictional status.\"

     **Commission Conclusion**

573. We are applying the same standards to any entity seeking a waiver
     of the requirements of this Final Rule. Because the possible
     scenarios under which small entities may seek waivers are diverse,
     they are not susceptible to resolution on a generic basis, and we
     are requiring applications and fact-specific determinations in each
     instance. The Commission does not have jurisdiction over non-public
     utilities\' rate, terms and conditions of transmission service
     under sections 205 and 206 of the FPA, and Order No. 888 does not
     require that non-public utilities file open access transmission
     tariffs. In addition, under the waiver provisions of Order No. 888,
     small non-public utilities may seek waiver from the reciprocity
     provision. This waiver policy follows the SBA definition of a small
     utility.[^204] The SBA defines a small electric utility as one that
     disposes of 4 MWh or less of electric energy in a given year.[^205]

574. We disagree with NRECA that this Final Rule will have a significant
     economic effect on a substantial number of small entities. Of the
     931 electric cooperatives in the 47 states across the country, 686
     receive financial assistance from the U.S. Department of
     Agriculture and therefore are not subject to the Commission's
     jurisdiction.[^206] Of the 67 members of NRECA who have generation
     and transmission facilities, only 34 electric cooperatives are
     subject to the Commission's jurisdiction. They are only a small
     subset of the entities considered when determining a significant
     impact on a substantial number of small entities. Within the subset
     of 34 entities, only a few own, control, or operate interstate
     transmission facilities.

575. As NRECA noted in its comments, the Commission has an important
     role in determining whether facilities are distribution or
     transmission, and as the Commission noted elsewhere in this Final
     Rule, the only facilities that are already subject to a
     Transmission's Provider's OATT are covered by this rule and apply
     only to a small percentage of small generator interconnections. The
     Commission recognizes that most small generators will interconnect
     with facilities that are not subject to the OATT.

576. However, in drafting this rule the Commission has followed the
     provisions of both the RFA and the Paperwork Reduction Act to
     consider the potential impact of regulations on small business and
     other small entities. Specifically, the RFA directs agencies to
     consider four regulatory alternatives to be considered in a
     rulemaking to lessen the impact on small entities: tiering or
     establishment of different compliance or reporting requirements for
     small entities, classification, consolidation, clarification or
     simplification of compliance and reporting requirements,
     performance rather than design standards, and exemptions. The
     Commission has adopted both tiering, and classification and
     simplification when developing technical accelerated procedures to
     apply to interconnections that will have no adverse effect on the
     Transmission Provider's electric system. By the use of tiering, the
     Commission is creating three ways to evaluate Interconnection
     Requests that can be applied to size and operating conditions of a
     small generating facility. As noted earlier, all Small Generating
     Facilities are subject to the Study Process, but in order to
     expedite the process and reduce the requirements on facilities
     smaller than 2 MW, technical screens were developed for certified
     Small Generating Facilities no larger than 2 MW (Fast Track) and
     certified inverter-based Small Generating Facilities no larger than
     10 kW (10 kW Inverter Process). The latter process was further
     simplified as it does not use an SGIA, instead using an all-in-one
     document that includes the application form, interconnection
     procedures, and terms and conditions. In addition, many provisions
     of the SGIA are based on the NARUC Model which in turn is based on
     the experience of several states for implementing interconnections.

577. A core issue has been whether standards could be developed that
     will allow for a cost effective interconnection solution without
     jeopardizing the safety and reliability of the Transmission System.
     One study showed that the typical cost of interconnection ranges
     from \$50/kW -- \$200/kW depending on the size of the generating
     facility, application and utility requirements.[^207] By
     simplifying both the interconnection procedures document and
     interconnection agreement, the costs of small generating facilities
     should be reduced, equipment manufacturers will be able to operate
     from a single set of technical specifications, and seamless
     procedures will be in place that do not jeopardize the safety and
     reliability of the Transmission System.

     **VI. Document Availability**[]{#__RefHeading___Toc103479345
     .anchor}

578. In addition to publishing the full text of this document in the
     [Federal Register]{.underline}, the Commission provides all
     interested persons an opportunity to obtain this document from the
     Public Reference Room during normal business hours (8:30 a.m. to
     5:00 p.m. Eastern Time) at 888 First Street, N.E., Room 2A,
     Washington, D.C. The full text of this document is also available
     electronically from the Commission\'s eLibrary system (formerly
     called FERRIS) in PDF and Microsoft Word format for viewing,
     printing, and downloading. eLibrary may be accessed through the
     Commission\'s Home Page (http://www.ferc.gov). To access this
     document in eLibrary, type \"RM02-1-\" in the docket number field
     and specify a date range that includes this document\'s issuance
     date.

579. User assistance is available for eLibrary and the Commission\'s
     website during normal business hours from our Help Line at
     202-502-8222 or the Public Reference Room at 202-502-8371 Press 0,
     TTY 202-502-8659. E-Mail the Public Reference Room at
     public.referenceroom@ferc.gov.

     **VII. Effective Date And Congressional
     Notification**[]{#__RefHeading___Toc103479346 .anchor}

580. This Final Rule will take effect on \[insert date that is 60 days
     after date of publication in the FEDERAL REGISTER\]. The Commission
     has determined, with the concurrence of the Administrator of the
     Office of Information and Regulatory Affairs of the Office of
     Management and Budget, that this rule is not a \"major rule\"
     within the meaning of section 251 of the Small Business Regulatory
     Enforcement Fairness Act of 1996.[^208] The Commission will submit
     the Final Rule to both houses of Congress and the General
     Accounting Office.[^209]

[List of Subjects in 18 CFR Part 35]{.underline}

581. Electric power rates, Electric utilities, Reporting and
     recordkeeping requirements.

     By the Commission.

     ( S E A L )

     Magalie R. Salas,

     Secretary.

In consideration of the foregoing, the Commission revises part 35,
Chapter I, Title 18 of the Code of Federal Regulations, as follows.

**PART 35 B FILING OF RATE SCHEDULES**

1\. The authority citation for part 35 continues to read as follows:

**Authority**: 16 U.S.C. § 791a-825r, §§ 2601-2645; 31 U.S.C. § 9701; 42
U.S.C. §§ 7101-7352.

2\. In § 35.28, the heading of paragraph (f) is revised, the first
sentences of currently existing paragraphs (f)(1), (f)(1)(i),
(f)(1)(ii), (f)(2), (f)(3) and (f)(3)(i) are revised, a new paragraph
(f)(1)(ii) is added, currently existing paragraph (f)(1)(ii) is
renumbered to account for new paragraph (f)(1)(ii), and paragraphs
(f)(4), (f)(4)(i), and (f)(4)(ii) are added, all to read as follows:

§ 35.28 [Non-discriminatory open access transmission
tariff]{.underline}.

\* \* \* \* \*

\(f\) [Standard generator interconnection procedures and
agreements]{.underline}.

\(1\) Every public utility that is required to have on file a
non-discriminatory open access transmission tariff under this section
must amend such tariff by adding the standard interconnection procedures
and agreement contained in Order No. 2003, FERC Stats. & Regs. & 31,146
(Final Rule on Generator Interconnection) and the standard small
generator interconnection procedures and agreement contained in Order
No. 2006, FERC Stats. & Regs. ¶ \_\_\_\_\_ (Final Rule on Small
Generator Interconnection), or such other interconnection procedures and
agreements as may be approved by the Commission consistent with Order
No. 2003, FERC Stats. & Regs. & 31,146 (Final Rule on Generator
Interconnection) and Order No. 2006, FERC Stats. & Regs. ¶ \_\_\_\_\_
(Final Rule on Small Generator Interconnection).

\(i\) The amendment to implement the Final Rule on Generator
Interconnection required by the preceding subsection must be filed no
later than January 20, 2004.

\(ii\) The amendment to implement the Final Rule on Small Generator
Interconnection required by the preceding subsection must be filed no
later than \[insert date 60 days after publication in the FEDERAL
REGISTER\].

\(iii\) Any public utility that seeks a deviation from the standard
interconnection procedures and agreement contained in Order No. 2003,
FERC Stats. & Regs. & 31,146 (Final Rule on Generator Interconnection)
or the standard small generator interconnection procedures and agreement
contained in Order No. 2006, FERC Stats. & Regs. ¶ \_\_\_\_\_ (Final
Rule on Small Generator Interconnection), must demonstrate that the
deviation is consistent with the principles of either Order No. 2003,
FERC Stats. & Regs. & 31,146 (Final Rule on Generator Interconnection)
or Order No. 2006, FERC Stats. & Regs. ¶ \_\_\_\_\_ (Final Rule on Small
Generator Interconnection).

\(2\) The non-public utility procedures for tariff reciprocity
compliance described in paragraph (e) of this section are applicable to
the standard interconnection procedures and agreements.

\(3\) A public utility subject to the requirements of this paragraph
pertaining to the Final Rule on Generator Interconnection may file a
request for waiver of all or part of the requirements of this paragraph,
for good cause shown. An application for waiver must be filed either:

\(i\) No later than January 20, 2004, or

\(ii\) No later than 60 days prior to the time the public utility would
otherwise have to comply with the requirements of this paragraph.

\(4\) A public utility subject to the requirements of this paragraph
pertaining to the Final Rule on Small Generator Interconnection may file
a request for waiver of all or part of the requirements of this
paragraph, for good cause shown. An application for waiver must be filed
either:

\(i\) No later than \[insert date 60 days after publication in the
FEDERAL REGISTER\], or

\(ii\) No later than 60 days prior to the time the public utility would
otherwise have to comply with the requirements of this paragraph.

The following Appendices will not be published in the [Code of Federal
Regulations]{.underline}.

[]{#AppendixA .anchor}**Appendix A**

**Commenter Acronyms**[^210]

**AEP** -- American Electric Power System

**Alabama PSC** -- Alabama Public Service Commission

**Allegheny Energy** -- Allegheny Energy Supply Company, LLC and
Allegheny Power

**Ameren** -- Ameren Services Company

**American Forest** -- American Forest & Paper Association and the
Process Gas Consumers Group

**AMP-Ohio** -- American Municipal Power -- Ohio, Inc.

**Avista** -- Avista Corp. and Puget Sound Energy, Inc.

**Baltimore G&E** -- Baltimore Gas and Electric Company

**BPA** -- Bonneville Power Administration, U.S. Department of Energy

**Bureau of Reclamation** -- Bureau of Reclamation, U.S. Department of
Interior

**CA ISO** -- California ISO

**California Wind Energy** -- California Wind Energy Association

**Capstone** -- Capstone Turbine Corp.

**Central Iowa Coop** -- Central Iowa Power Cooperative and Corn Belt
Power Cooperative

**Central Maine** -- Central Maine Power Company, New York State
Electric & Gas Corporation, and Rochester Gas & Electric Corporation

**Cinergy** -- Cinergy Services, Inc.

**Consumers** -- Consumers Energy Company

**CPUC** -- California Public Utilities Commission

**CT DPUC** -- Connecticut Department of Public Utility Control

**Cummins** -- Cummins, Inc.

**EEI** -- Edison Electric Institute

**Empire District** -- Empire District Electric Co.

**Encorp** -- Encorp, Inc.

**Exelon** -- Exelon Generation Company, LLC, Commonwealth Edison
Company, PECO Energy Company, and Sithe Energies, Inc.

**FERC DRS** -- Dispute Resolution Service, Federal Energy Regulatory
Commission

**Florida PSC** -- Florida Public Service Commission

**Garwin McNeilus** -- Mr. Garwin McNeilus

**Georgia PSC** -- Georgia Public Service Commission

**Georgia Transmission** -- Georgia Transmission Corporation

**Idaho Power** -- Idaho Power Company

**Iowa Utilities Board** -- Iowa Utilities Board

**ISO New England** -- ISO New England

**Joint Commenters** -- National Association of Regulatory Utility
Commissioners, Small Generator Coalition (members listed below),
American Public Power Association (who did not participate in the filing
of supplemental comments), National Rural Electric Cooperative
Association, and Edison Electric Institute

**LADWP** -- Los Angeles Department of Water and Power

**Massachusetts DTE** -- Massachusetts Department of Telecommunications
and Energy

**MidAmerican** -- MidAmerican Energy Company

**Midwest ISO** -- Midwest Independent Transmission System Operator,
Inc.

**Minnesota PUC** -- Minnesota Public Utilities Commission and the
Minnesota Department of Commerce

**Mississippi PSC** -- Mississippi Public Service Commission

**NARUC** -- National Association of Regulatory Utility Commissioners

**National Grid** -- National Grid USA

**NEMA** -- National Electrical Manufacturers Association

**NEPOOL Participants** -- New England Power Pool Participants Committee

**Nevada Power** -- Nevada Power Company and Sierra Pacific Power
Company

**NJ BPU** -- New Jersey Board of Public Utilities

**North Carolina Commission** -- North Carolina Utilities Commission and
the Public Staff of the North Carolina Utilities Commission

**NorthWestern Energy** -- NorthWestern Energy

**NRECA** -- National Rural Electric Cooperative Association

**NYISO** -- New York Independent System Operator, Inc.

**NYPSC** -- New York State Public Service Commission

**NYTO** -- Central Hudson Gas and Electric Corp., Consolidated Edison
Company of New York, Inc., Long Island Power Authority, New York Power
Authority, New York State Electric and Gas Corp., Orange and Rockland
Utilities, Inc., and Rochester Gas and Electric Corp.

**Ohio PUC** -- Public Utilities Commission of Ohio

**PacifiCorp** -- PacifiCorp

**PG&E** -- Pacific Gas and Electric Company

**PJM** -- PJM Interconnection, L.L.C.

**Plug Power** -- Plug Power, Inc.

**Progress Energy** -- Progress Energy, Inc., Carolina Power and Light
Co., and Florida Power Corp.

**PSE&G** -- Public Service Electric and Gas Company

**Robert L. Carey** -- Mr. Robert L. Carey

**RW Beck** -- R.W. Beck, Inc.

**Small Generator Coalition** -- American Council for an Energy
Efficient Economy; American Solar Energy Society; American Wind Energy
Association; BP Solar; Citizens Action Coalition of Indiana; Coffman
Electrical Equipment; Cummins Power Generation; Elliott Energy Systems;
Encorp; Environmental Law & Policy Center; Kyocera Solar, Inc.; MAN
Turbomachinery, Inc.; Natural Resources Defense Council;
Northeast-Midwest Institute; Northwest Energy Coalition; Pace Energy
Program; Pennsylvania Energy Project; Plug Power, Inc.; Power Equipment
Associates; PowerLight Corporation; RWE SCHOTT Solar, Inc.; Shepherd
Advisors; Solar Energy Industries Association; Spire Solar, Inc.; U.S.
Combined Heat and Power Association; and University of Oregon Solar
Radiation Monitoring Laboratory.

**SMUD** -- Sacramento Municipal Utility District

**SoCal Edison** -- Southern California Edison Company

**Solar Turbines** -- Solar Turbines, Inc.

**Southern Company** -- Southern Company Services, Inc.

**SW TDU Group** -- Southwest Transmission Dependent Utility Group
(Aguila Irrigation District, Ak-Chin Electric Utility Authority, Buckeye
Water Conservation and Drainage District, Central Arizona Water
Conservation District, Electrical District No. 3, Electrical District
No. 4, Electrical District No. 5, Electrical District No. 6, Electrical
District No. 7, Electrical District No. 8, Harquahala Valley Power
District, Maricopa County Municipal Water District No. 1, McMullen
Valley Water Conservation and Drainage District, City of Needles,
Roosevelt Irrigation District, City of Safford, Tonopah Irrigation
District, Wellton-Mohawk Irrigation and Drainage District)

**Tangibl** -- Tangibl, LLC

**TAPS** -- Transmission Access Policy Study Group

**TDU Systems** -- Transmission Dependent Utility Systems (Alabama
Electric Cooperative, Inc.; Arkansas Electric Cooperative Corporation;
Golden Spread Electric Cooperative; Kansas Electric Power Cooperative,
Inc.; Old Dominion Electric Cooperative; and Seminole Electric
Cooperative, Inc.)

**USCHPA** -- U.S. Combined Heat and Power Association

**Western** -- Western Area Power Administration

**Commenters Who Filed in Response to the Commission\'s**

**Request for Supplemental Comments**

**CT DPUC** -- Connecticut Department of Public Utility Control

**FERC DRS** -- Dispute Resolution Service, Federal Energy Regulatory
Commission

**Joint Commenters** -- National Association of Regulatory Utility
Commissioners, Small Generator Coalition (members listed above),
National Rural Electric Cooperative Association, and Edison Electric
Institute (American Public Power Association did not participate in the
filing of supplemental comments)

**Massachusetts DTE** -- Massachusetts Department of Telecommunications
and Energy

**Minnesota PUC** -- Minnesota Public Utilities Commission and the
Minnesota Department of Commerce

**National Grid** -- National Grid USA

**NJ BPU** -- New Jersey Board of Public Utilities

**North Carolina Commission** -- North Carolina Utilities Commission and
the Public Staff of the North Carolina Utilities Commission

**NRECA** -- National Rural Electric Cooperative Association

**Ohio PUC** -- Public Utilities Commission of Ohio

**PJM** -- PJM Interconnection, L.L.C.

**Small Generator Coalition** (members listed above)

**USCHPA** -- U.S. Combined Heat and Power Association

**Appendix B**

[]{#appendixb .anchor}**Flow Chart for Interconnecting a Small
Generating**

**Facility Using the \"Study Process\"**

**Appendix C**

[]{#appendixc .anchor}**Flow Chart for Interconnecting a Certified Small
Generating**

**Facility No Larger than 2 MW Using the \"Fast Track Process\"**

**Appendix D**

[]{#appendixd .anchor}**Flow Chart for Interconnecting a Certified
Inverter-Based**

**Small Generating Facility No Larger than 10 kW**

**Using the \"10 kW Inverter Process\"**

[^1]: 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 Federal
    Power Act (FPA). 16 U.S.C. § 824(e) (2000). A non-public utility
    that seeks voluntary compliance with the reciprocity condition of an
    open access transmission tariff may satisfy that condition by
    adopting these procedures and agreement.

[^2]: Standardization of Generator Interconnection Agreements and
    Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats.
    & Regs. ¶ 31,146 (2003) (Order No. 2003), [order on
    reh\'g]{.underline}, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004),
    FERC Stats. & Regs. ¶ 31,160 (2004) (Order No. 2003-A), [order on
    reh\'g]{.underline}, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005),
    FERC Stats. & Regs. ¶ 31,171 (2005), [reh\'g pending]{.underline}
    (Order No. 2003-B). [See also]{.underline} Notice Clarifying
    Compliance Procedures, 106 FERC ¶ 61,009 (2004). We refer to the
    large generator interconnection rulemaking as Order No. 2003
    throughout this document. The Order No. 2003 Large Generator
    Interconnection

    Agreement and Large Generator Interconnection Procedures, as amended
    by Order Nos. 2003-A and 2003-B, are referred to in this Final Rule
    as the LGIA and the LGIP, respectively.

[^3]: Capitalized terms used in this Final Rule have the meanings
    specified in the Glossaries of Terms or the text of the Small
    Generator Interconnection Procedures (SGIP) or the Small Generator
    Interconnection Agreement (SGIA). Small Generating Facility means
    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.
    A Small Generating Facility is a device used for the production of
    electricity having a capacity of no more than 20 MW. The
    interconnection process formally begins with the Interconnection
    Customer submitting an application for interconnection, called an
    Interconnection Request, to the Transmission Provider.

    We are omitting from the SGIP and SGIA glossaries terms that are
    defined through their use in the documents themselves or are in such
    common use in the industry that a definition is unnecessary. Many
    terms that were capitalized in the Small Generator Interconnection
    Notice of Proposed Rulemaking are therefore not capitalized in this
    Preamble, SGIP, and SGIA.

    The documents put forward in the Small Generator Interconnection
    NOPR are called the \"Proposed SGIP\" and the \"Proposed SGIA\" in
    this Preamble. The documents that are being adopted in this Final
    Rule for inclusion in a Transmission Provider\'s OATT are called
    simply the SGIP and SGIA. Provisions of the SGIP are referred to as
    \"sections\" and provisions of the SGIA are referred to as
    \"articles.\"

[^4]: 16 U.S.C. §§ 824d and 824e (2000).

[^5]: Compliance procedures are discussed in Part II.I, below.

[^6]: A Small Generating Facility equipment package is considered
    certified if it has been submitted, tested, and listed by a
    nationally recognized testing and certification laboratory. The
    Small Generator Interconnection NOPR used the term \"precertified\"
    to describe such a facility. We adopt in this Final Rule the term
    \"certified\" to be consistent with industry usage. To avoid further
    confusion, we also use \"certified\" when describing the Small
    Generator Interconnection NOPR. [See]{.underline} the SGIP,
    especially Attachments 3 and 4.

[^7]: An inverter is a device that converts the direct current voltage
    and current of a DC generator to alternating voltage and current.
    For example, the output of a solar panel is direct current. The
    solar panel\'s output must be converted by an inverter to
    alternating current before it can be interconnected with a
    utility\'s alternating current electric system.

[^8]: [See]{.underline} [Detroit Edison v. FERC]{.underline}, 334 F.3d
    48 (D.C. Cir. 2003) ([Detroit Edison]{.underline}).  There, the
    court explained that:

    > When a local distribution facility is used to delivery \[sic\]
    > energy to an unbundled retail customer, FERC lacks any statutory
    > authority, and the state has jurisdiction over that transaction. 
    > By contrast, when a local distribution facility is used in a
    > wholesale transaction, FERC has jurisdiction over that transaction
    > pursuant to its wholesale jurisdiction under FPA § 201(b)(1).  In
    > sum, FERC has jurisdiction over all interstate transmission
    > service and over all wholesale service, but FERC has no
    > jurisdiction over unbundled retail distribution service -- i.e.,
    > unbundled retail service over local distribution facilities.

    [Id.]{.underline} at 51 (citations omitted).

[^9]: [See]{.underline} [Detroit Edison]{.underline}, 334 F.3d at 51.
    (\"For our purposes, the most important result of these
    jurisdictional determinations is that customers can take any
    FERC-jurisdictional service under a utility's open access tariff,
    which the utility is required to file with FERC. Customers must take
    non FERC-jurisdictional service, such as unbundled retail
    distribution, under a state tariff.\")

[^10]: 16 U.S.C. § 824 (2000).

[^11]: 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, 61 FR 21540 (May 10, 1996), FERC Stats. &
    Regs. & 31,036 (1996), [order on reh\'g]{.underline}, Order No.
    888‑A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. & 31,048
    (1997), [order on reh\'g]{.underline}, Order No. 888‑B, 81 FERC
    & 61,248 (1997), [order on reh\'g]{.underline}, Order No. 888‑C , 82
    FERC & 61,046 (1998), [aff\'d in part sub nom.]{.underline}
    [Transmission Access Policy Study Group v. FERC]{.underline}, 225
    F.3d 667 (D.C. Cir. 2000), [aff\'d sub nom.]{.underline} [New York
    v. FERC]{.underline}, 535 U.S. 1 (2002) ([TAPS v.
    FERC]{.underline}).

[^12]: Regional Transmission Organizations, Order No. 2000, 65 FR 810
    (Jan. 6, 2000), FERC Stats. & Regs. & 31,089 (1999), [order on
    reh\'g]{.underline}, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000),
    FERC Stats. & Regs. & 31,092 (2000), [aff\'d sub nom.]{.underline}
    [Public Util. Dist. No. 1 v. FERC]{.underline}, 272 F.3d 607 (D.C.
    Cir. 2001).

[^13]: [See]{.underline} Order No. 2003 [passim.]{.underline}

[^14]: [Gulf States Utils. Co. v. FPC]{.underline}, 411 U.S. 747, 758-59
    (1973); [see]{.underline} [City of Huntingburg v. FPC]{.underline},
    498 F.2d 778, 783-84 (D.C. Cir. 1974) (noting the Commission\'s duty
    to consider the potential anticompetitive effects of a proposed
    interconnection agreement).

[^15]: Order No. 888 at 31,679-84; Order No. 888-A at 30,209-10.

[^16]: Order No. 888 at 31,668-73, 31,676-79; Order No. 888-A at
    30,201-12; [TAPS v. FERC]{.underline} at 687-88.

[^17]: [New York v. FERC]{.underline}, 535 U.S. 1 (2002).

[^18]: Order No. 888-A, FERC Stats. & Regs & 31,048 at 30,230-31.

[^19]: Tennessee Power Co. ([Tennessee Power]{.underline}), 90 FERC &
    61,238 at 61,761 (2000), [reh\'g denied]{.underline}, 91 FERC &
    61,271 (2000).

[^20]: [See]{.underline}, [e.g.]{.underline}, Commonwealth Edison Co.,
    91 FERC & 61,083 (2000).

[^21]: **^?^** Order No. 2003 at P 10.

[^22]: Standardizing Generator Interconnection Agreements and
    Procedures, Advance Notice of Proposed Rulemaking, 66 FR 55140 (Nov.
    1, 2001), FERC Stats. & Regs. & 35,540 (2002).

[^23]: Standardization of Generator Interconnection Agreements and
    Procedures, Notice of Proposed Rulemaking, 67 FR 22250 (May 2,
    2002), FERC Stats. & Regs. & 32,560 (2002).

[^24]: Those commenters included the Solar Energy Industries
    Association, the U.S. Fuel Cell Council, the American Solar Energy
    Society, the U.S. Combined Heat and Power Association, the
    International District Energy Association, and the American Wind
    Energy Association.

[^25]: Standardization of Small Generator Interconnection Agreements and
    Procedures, Advance Notice of Proposed Rulemaking, 67 FR 54749 (Aug.
    26, 2002), FERC Stats. & Regs. & 35,544 (2002).

[^26]: This group refers to itself as the Coalition. However, in this
    Final Rule we shall refer to the group as \"Joint Commenters\" to
    distinguish it from the similarly named Small Generator Coalition.
    With the exception of these early references to Joint Commenters\'
    comments submitted in response to the ANOPR, all references in the
    remainder of this Preamble to Joint Commenters are to its
    supplemental comments. Joint Commenters did not file initial
    comments in response to the Small Generator Interconnection NOPR,
    only supplemental comments. Joint Commenters is a diverse group of
    stakeholders that includes:

    over 25 small generator trade groups, promoters, and equipment
    manufacturers, who refer to themselves collectively as the \"Small
    Generator Coalition,\"

    state regulatory agencies represented by the National Association of
    Regulatory Utility Commissioners,

    American Public Power Association (which did not participate in the
    filing of Joint Commenters\' supplemental comments), and

    Transmission Providers represented by Edison Electric Institute
    (EEI) and National Rural Electric Cooperative Association (NRECA)

    A list of commenter acronyms may be found in Appendix A.

[^27]: Standardization of Small Generator Interconnection Agreements and
    Procedures, Notice of Proposed Rulemaking, 60 FR 49974 (Aug. 19,
    2003), FERC Stats. & Regs. & 32,572 (2003) (Small Generator
    Interconnection NOPR).

[^28]: [See, e.g.]{.underline}, Proposed SGIA articles 4.1, 5.1.2,
    5.1.2.1, 5.2, 6.1-6.9, 6.12-6.20, 7, and 8.

[^29]: NARUC members had participated in the ANOPR discussions fostered
    by the Commission; there was much similarity between the provisions
    of the NARUC Model and the Small Generator Interconnection NOPR.

[^30]: [See]{.underline} Notice of Request for Supplemental Comments, 69
    FR 51024 (Aug. 17, 2004). The Commission then granted two extensions
    of time at the request of Joint Commenters. [See]{.underline}
    Notices issued on September 30, 2004 and November 30, 2004 in Docket
    No. RM02-12-000.

[^31]: CT DPUC, Minnesota PUC, and Massachusetts DTE submitted copies of
    their recently enacted small generator interconnection rules.

[^32]: The supplemental commenters are listed in Appendix A.

[^33]: Order No. 2003-A at P 407, n. 86.

[^34]: [Id.]{.underline}

[^35]: Interconnection for Wind Energy and Other Alternative
    Technologies, Notice of Proposed Rulemaking, 70 FR 4791 (Jan. 31,
    2005) ([Wind NOPR]{.underline}).

[^36]: Comments addressing issues filed in other dockets (for instance,
    the Wind NOPR) are not part of this proceeding even if they were
    cross-filed in Docket No. RM02-12-000.

[^37]: Note that the scope and payment provisions of the feasibility,
    system impact, and facilities studies are contained in the actual
    study agreements which are included as Attachments 6, 7, and 8 to
    the SGIP, not section 3 of the SGIP.

[^38]: Flowcharts depicting interconnection procedures are presented in
    Appendices B (Study Process), C (Fast Track Process), and D (10 kW
    Inverter Process).

[^39]: 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.

[^40]: The Study Process is similar to the LGIP. However, we expect that
    the interconnection of a Small Generating Facility will take
    substantially less time and cost substantially less than a Large
    Generating Facility.

[^41]: Southern Company at 19.

[^42]: BPA at 3.

[^43]: [Id.]{.underline}

[^44]: Nevada Power at 4.

[^45]: Nevada Power at 4-5.

[^46]: The 10 kW Inverter Process is largely based on the work of the
    Massachusetts DTE and its stakeholders group.

[^47]: IEEE Standard 1547, approved in June 2003, is the Institute of
    Electrical and Electronics Engineers\' standard for interconnecting
    distributed resources with electric power systems. The standard
    applies only to generating equipment no larger than 10 MW.

[^48]: NRECA Supplemental Comments at 5. NRECA also \"believes that the
    screens adopted for review of generators up to 2 MW in capacity
    reasonably consider the impact that generators of those sizes will
    have on distribution systems.\" [Id.]{.underline} The technical
    screens of which NRECA speaks are the same screens adopted in this
    Final Rule.

[^49]: [E.g.]{.underline}, BPA, ISO-New England, NRECA, NYTO, PG&E, and
    Western.

[^50]: [E.g.]{.underline}, AEP, Ameren, Avista, BPA, CA ISO, Central
    Maine, MidAmerican, MISO, NYTO, PG&E, SoCal Edison, and Western.

[^51]: In the remainder of this Preamble, \"Proposed SGIA Article xxx\"
    refers to a numbered article in the Small Generator Interconnection
    NOPR, not the SGIA adopted in this Final Rule. The same follows for
    references to the Proposed SGIP. This is because the numbering of
    the SGIP and SGIA does not follow the Proposed SGIP and SGIA.

[^52]: NARUC at 12-13.

[^53]: NARUC Model at F.

[^54]: [Id.]{.underline}

[^55]: The Commission does not require states to serve a dispute
    resolution function; it lacks the statutory authority to do so.
    However, because commenters argue that state participation could be
    beneficial, we encourage states that have the expertise, resources,
    and interest to help resolve these disputes as they arise.

[^56]: [See]{.underline} Order No. 2003-A at P 486.

[^57]: [Id.]{.underline} at P 490.

[^58]: 16 U.S.C. § 824d (2000); [see also]{.underline} 18 CFR § 35.12
    (2004).

[^59]: New England Power Pool ([New England]{.underline}), 109 FERC ¶
    61,155 at P 43-44 (2004).

[^60]: Deliverability refers to the ability of the electric system to
    accept the Small Generating Facility\'s output without regard to the
    ultimate point of delivery.

[^61]: [E.g.]{.underline}, Bureau of Reclamation, Central Maine,
    Cummins, EEI, Joint Commenters, Northwestern Energy, NYTO,
    PacifiCorp, PG&E, and Small Generator Coalition.

[^62]: [E.g.]{.underline}, CA ISO, EEI, Idaho Power, PG&E, PSE&G, SoCal
    Edison, and Southern Company.

[^63]: **^?^** As noted above, \"transmission\" is both an engineering
    term of art and a term used in the FPA. As used in the technical
    screens, \"transmission\" is used in the engineering sense, not in a
    jurisdictional sense. Likewise, references in other technical
    screens to \"radial distribution circuits,\" \"3-phase primary
    distribution lines,\" and other uses of the word distribution are
    used in an engineering sense, not in a jurisdictional sense. In no
    case do we intend that this Final Rule applies to
    non-Commission-jurisdictional facilities.

[^64]: A \"certified\" Small Generating Facility is one that has been
    certified by a nationally recognized laboratory before the
    Interconnection Request is submitted to the Transmission Provider.
    Such a facility is said to be \"certified\" for purposes of the
    interconnection process.

[^65]: In the Small Generator Interconnection NOPR, the term
    Super-Expedited Procedure referred to the process that used the
    super-expedited screens and Expedited Procedure referred to the
    process that used the expedited screens. In this Final Rule, we are
    adopting only one set of screens, which are used in both the Fast
    Track Process and the 10 kW Inverter Process.

[^66]: [E.g.]{.underline}, Ameren, BPA, Bureau of Reclamation, Central
    Maine, Cinergy, EEI, Exelon, MISO, NRECA, NYPSC, NYTO, PG&E, PJM,
    and Southern Company.

[^67]: A secondary network is a type of distribution system that is
    generally used in large metropolitan areas that are densely
    populated in order to provide high reliability of service to
    multiple customers. (Source: *Standard Handbook for Electrical
    Engineers*, 11^th^ edition, Donald Fink, McGraw Hill Book Company)

[^68]: In the Proposed SGIP, the Commission termed this \"additional
    review.\" In the SGIP, we adopt the NARUC Model\'s term
    \"supplemental review.\"

[^69]: Order No. 2003 at P 147.

[^70]: [See]{.underline} Order No. 2003 at P 185.

[^71]: [Id.]{.underline} at P 155.

[^72]: Order No. 2003-A at P 101-107.

[^73]: Avista at 14.

[^74]: Nevada Power at 15.

[^75]: [Id.]{.underline} (Emphasis added to show the new language
    proposed by Nevada Power.)

[^76]: Emphasis added to show the language proposed by the Joint
    Commenters.

[^77]: Order No. 2003-A at P 399.

[^78]: [See]{.underline}, [e.g.]{.underline}, Order No. 2003-A at P 44,
    Order No. 2003 at P 823, and Order No. 888 at 31,770.

[^79]: Order No. 2003 at P 302-304.

[^80]: [See]{.underline}, [e.g.]{.underline}, BPA, Central Maine, PG&E,
    and Southern Company.

[^81]: Order No. 2003 at P 313.

[^82]: SoCal Edison does not give any rationale for its proposed change,
    only modified tariff sheets.

[^83]: If the Small Generating Facility is interconnected with
    nonjurisdictional lines, then this Final Rule does not reach the
    issue of whether a jurisdictional Transmission Provider may
    disconnect the Small Generating Facility in an emergency. The
    Transmission Provider would have to deal with the non-jurisdictional
    utility.

[^84]: [E.g.]{.underline}, Ameren, EEI, National Grid, PacifiCorp, PG&E,
    and Southern Company.

[^85]: Order No. 2003 at P 597.

[^86]: [See]{.underline} Florida Power & Light Company, 98 FERC ¶ 61,
    226 at 61,893-94, [reh\'g granted in part on other]{.underline}
    g[rounds]{.underline}, 99 FERC ¶ 61,318 (2002); Florida Power &
    Light Company, 98 FERC ¶ 61,324 at 62,358-59 (noting that the
    Transmission Provider\'s practice of limiting interconnection
    customers to a letter of credit is unreasonable), [reh\'g rejected
    as moot]{.underline}, 100 FERC ¶ 61,094 (2002).

[^87]: Southwest Power Pool, Inc., 100 FERC ¶ 61,096 at P 12 (2002).

[^88]: [See]{.underline} Order No. 2003 at P 264.

[^89]: [E.g.]{.underline}, BPA, Central Maine, NYTO, PGE, and Southern
    Company.

[^90]: [See]{.underline} Order No. 2003-A at P 470.

[^91]: [See]{.underline} [Id.]{.underline} P 471.

[^92]: [See]{.underline} [Id.]{.underline} P 475.

[^93]: NARUC Model -- Interconnection Agreement at article 7.

[^94]: NYPSC at 9.

[^95]: [E.g.]{.underline}, AEP, Allegheny Energy, Avista, BPA, Central
    Maine, Cinergy, EEI, NRECA, NYTO, and Southern Company.

[^96]: NRECA at 34.

[^97]: The proposal requires no insurance for projects smaller than 10
    kW; \$500,000 for projects between 10 kW and 100 kW (\$500,000
    aggregate); \$1 million for projects between 100 kW and 1 MW (\$1
    million aggregate); \$2 million for projects larger than 1 MW and no
    larger than 5 MW (\$5 million aggregate); and \$5 million for
    projects larger than 5 MW (\$5 million aggregate). [See]{.underline}
    National Grid Comments, Appendix A (citing Tariff to Accompany
    Proposed Uniform Standards for Interconnecting Distributed
    Generation in Massachusetts, Submitted by the Distributed Generation
    Interconnection Collaborative to the Massachusetts Department of
    Telecommunications and Energy in Compliance with DTE Order No.
    02-38-A (May 15, 2003)).

[^98]: [See]{.underline}, [e.g.]{.underline}, Cinergy, Empire District,
    ISO New England, NRECA, NYPSC, PG&E, and Small Generator Coalition.
    [But see]{.underline}, [e.g.]{.underline}, AEP, Central Maine, EEI,
    NYTO, and Southern Company.

[^99]: [See]{.underline} Order No. 2003-A at P 462.

[^100]: Order No. 2003 at P 909.

[^101]: Midwest ISO at 6.

[^102]: [Id.]{.underline}

[^103]: [E.g.]{.underline}, NYTO and PG&E.

[^104]: Order No. 2003 at P 909.

[^105]: We note that whether a public utility characterizes itself as a
    \"transmission\" provider or a \"distribution\" provider does not
    matter, since the Transmission Provider is defined to be the
    \"public utility . . . that owns, controls, or operates transmission
    or distribution facilities used for the transmission of electricity
    in interstate commerce and provides transmission service under the
    Tariff.\"

[^106]: Order No. 2003 at P 909.

[^107]: For instance, AEP, BPA, EEI, and Nevada Power argue that the
    LGIA and the SGIA should be consistent. Nevada Power argues that
    such provisions would not discourage well-run generators from
    interconnecting with the Transmission Provider.

[^108]: Avista at 18[.]{.underline}

[^109]: \"The WIS Agreement . . . is a multi-lateral agreement among
    parties in the Pacific Northwest that operates to limit liability
    among the signatories.\" [Id.]{.underline}

[^110]: In Puget Sound Energy, Inc., 107 FERC ¶ 61,287 (2004), the
    Commission denied a request by Puget Sound to include the WIS
    Agreement in its tariff because Puget Sound did not explain why such
    inclusion was \"consistent with or superior to\" the
    [pro]{.underline} [forma]{.underline} OATT. However, the Commission
    did not foreclose the possibility that a WIS Agreement member may be
    able to make such a showing in a future compliance filing.

[^111]: Order No. 2003 at P 636 (\"Commenters have convinced us that
    interconnection presents a greater risk of liability than exists for
    the provision of transmission service and that, therefore, the OATT
    indemnity provision is not suitable in the interconnection
    context.\")

[^112]: Black\'s Law Dictionary 772 (7^th^ ed. 1999).

[^113]: Southern Company at 34.

[^114]: [See]{.underline} Proposed SGIA article 6.13.

[^115]: NARUC Model -- Definitions.

[^116]: Order No. 2003-B at P 72-75.

[^117]: Non-usage sensitive transmission charges include all
    transmission charges except those for items that vary with the
    amount of power transmitted, such as congestion charges, line
    losses, and Ancillary Services.

[^118]: In Order No. 2003-A, this policy was revised to make credits
    available only for transmission service that has the generating
    facility as the source of the power transmitted.

[^119]: The five year refund period was subsequently changed to 20 years
    in Order No. 2003-B.

[^120]: The costs of all Interconnection Facilities, whether owned by
    the Interconnection Customer or the Transmission Provider, are
    directly assigned to the Interconnection Customer.

[^121]: [See]{.underline} Order No. 2003 at P 675-750, Order No. 2003-A
    at P 562-697, and Order No. 2003-B at P 15-57.

[^122]: By \"pancaking,\" we presume that Small Generator Coalition is
    referring to the possibility that the Interconnection Customer may
    be required to pay for Distribution Upgrades and to make an up-front
    payment for Network Upgrades.

[^123]: The term \"Point of Common Coupling\" is not used in the SGIP
    and SGIA.

[^124]: [See]{.underline}, [e.g.]{.underline}, AEP, Alabama PSC,
    Baltimore G&E, Central Maine, Cinergy, Consumers, MidAmerican,
    Mississippi PSC, Nevada Power, NRECA, and SoCal Edison.

[^125]: [Arkansas Power & Light Co. v. FPC]{.underline}, 368 F. 2d 376
    (8th Cir. 1966) ([Arkansas Power & Light]{.underline}).

[^126]: [See]{.underline} LGIA article 11.3 (\"The Interconnection
    Customer shall be responsible for all costs related to Distribution
    Upgrades.\")

[^127]: [See]{.underline}, [e.g.]{.underline}, PJM Interconnection,
    L.L.C., 109 FERC ¶ 61,326 (2004) (holding that O&M costs associated
    with Network Upgrades may not be directly assigned to the
    Interconnection Customer). We note, however, that the Transmission
    Provider may propose to recover the cost of Network Upgrades from
    the Interconnection Customer through an incremental transmission
    rate. In that case, the Commission would entertain a proposal to
    include in the incremental rate O&M costs associated with the
    Network Upgrades. Order No. 2003-B at P 57.

[^128]: This issue was discussed at P 421-424 of Order No. 2003-A.

[^129]: 16 U.S.C. § 824d (2000); [see also]{.underline} 18 CFR § 35.12
    (2004).

[^130]: [See]{.underline} Order No. 2003 at P 744 and Order No. 2003-A
    at P 663.

[^131]: Order No. 888 at 31,679-84; Order No. 888-A at 30,209-10.

[^132]: Order No. 2003 at P 18-20.

[^133]: [E.g.]{.underline}, Alabama PSC, CPUC, CT PUC, Florida PSC, Iowa
    Utilities Board, Mississippi PSC, North Carolina Commission, and
    NYPSC.

[^134]: [E.g.]{.underline}, Baltimore G&E, Central Maine, Consumers,
    EEI, Idaho Power, PacifiCorp, Progress Energy, and Southern Company.

[^135]: Shortly before comments were due in this docket, the D.C.
    Circuit issued [Detroit Edison v. FERC]{.underline}, 334 F.3d 48
    (D.C. Cir. 2003) ([Detroit Edison]{.underline}). Since then, the
    Commission has issued both Order Nos. 2003-A (at P 705 [et
    seq.]{.underline}) and 2003-B (at P 14), which discuss [Detroit
    Edison]{.underline} at length.

[^136]: Alabama PSC at 4-5 ([citing]{.underline} 16 U.S.C. § 824(b)
    (2003), which states that \"\[t\]he Commission . . . shall not have
    jurisdiction . . . over facilities used in local distribution . . .
    .\")

[^137]: [Id.]{.underline} at 10 (emphasis in original).

[^138]: [Id.]{.underline} at 5 ([citing]{.underline} [Southern Co.
    Services, Inc. v. FCC]{.underline}, 293 F.3d 1338, 1344 (11th Cir.
    2002)).

[^139]: CPUC at 8 ([citing]{.underline} [Conn. Light & Power Co. v.
    FPC]{.underline}, 324 U.S. 515, 529-30 (1945)).

[^140]: Alabama PSC at 6 ([citing]{.underline} 16 U.S.C. § 824(b)).

[^141]: Idaho Power at 3.

[^142]: 16 U.S.C. § 824a-3 (2004).

[^143]: Small Generator Coalition at 37 ([citing]{.underline} [Northern
    States Power Co. v. FERC]{.underline}, 30 F.3d 177 (D. C. Cir.
    1994)).

[^144]: [Id.]{.underline} ([citing]{.underline} [Fort Pierce Utilities
    Authority v. FERC]{.underline}, 730 F.2d 778, 782 (D.C. Cir. 1984)).

[^145]: [Id.]{.underline} at 39.

[^146]: [Id.]{.underline} at 39.

[^147]: NRECA at 41.

[^148]: [Id.]{.underline}

[^149]: Solar Turbines at 4.

[^150]: Avista at 9.

[^151]: [Id.]{.underline} at 9-10 (citing, [e.g.]{.underline}, [Snake
    River Valley Elec. Ass\'n v. PacifiCorp]{.underline}, 238 F.3d 1189
    (9th Cir. 2001)).

[^152]: 16 U.S.C. § 824k(h) (2000).

[^153]: Avista at 9-10 ([citing]{.underline} Laguna Irrigation District,
    95 FERC ¶ 61,305 (2001), [aff\'d sub nom.]{.underline} [Pacific Gas
    & Electric Co. v. FERC]{.underline}, 44 Fed. Appx. 170 (9th Cir.
    2002) (unpublished opinion); City of Corona v. Southern California
    Edison Co., 101 FERC ¶ 61,240 at 62,025-026 (2002)).

[^154]: Midwest ISO at 6.

[^155]: Order No. 2003-A at P 700.

[^156]: [See]{.underline} Order No. 2003-A at P 698 [et
    seq.]{.underline} and Order No. 2003-B at P 12 [et seq.]{.underline}

[^157]: [New York v. FERC]{.underline}, 535 U.S. 1 (2002).

[^158]: CT DPUC at 1 (\"The CT DPUC generally supports the effort by the
    Commission to initiate standardization of interconnection agreements
    and procedures . . . .\"); [see also]{.underline} Cummins at 1 (\"We
    strongly support the Commission\'s continued work in this area.\")

[^159]: NARUC at 18.

[^160]: [Id.]{.underline} at 8.

[^161]: Virginia, Massachusetts, and other states also have small
    generator interconnection rules.

[^162]: CPUC at 16.

[^163]: [Id.]{.underline} at 18.

[^164]: [Id.]{.underline} at 15.

[^165]: A particular state\'s interconnection rules may also differ from
    the NARUC Model.

[^166]: Small Generator Coalition at 7-8.

[^167]: Plug Power at 3.

[^168]: 18 CFR §§ 292.303, 292.306 (2004).

[^169]: The absence of interstate commerce in Alaska, Hawaii, and
    portions of Texas and Maine, and Puerto Rico is not germane to the
    Commission\'s jurisdiction over QF matters under PURPA.
    [See]{.underline} 16 U.S.C. § 2602 (2000).

[^170]: [See]{.underline} Western Massachusetts Electric Co., 61 FERC ¶
    61,182 at 61,661-62 (1992), [aff\'d sub nom.]{.underline} [Western
    Massachusetts Electric Co. v. FERC]{.underline}, 165 F.3d. 922, 926
    (D.C. Cir. 1999).

[^171]: [Id.]{.underline} at 61,661-62. The Commission further clarified
    that \"\[t\]he fact that the facilities used to support the
    jurisdictional service might also be used to provide various
    nonjurisdictional services, such as back-up and maintenance power
    for a QF, does not vest state regulatory authorities with authority
    to regulate matters subject to the Commission\'s exclusive
    jurisdiction.\" [Id.]{.underline} at 61,662.

[^172]: [See]{.underline}, [e.g.]{.underline}, LGIA articles 5.17 and
    5.18 and Order No. 2003-A at P 324 [et seq.]{.underline}

[^173]: NRECA at 57.

[^174]: PacifiCorp at 2-3.

[^175]: Order No. 2003-A at P 775.

[^176]: [See]{.underline} Order No. 2003-A at P 760 [et
    seq.]{.underline}

[^177]: [Id.]{.underline} at P 761.

[^178]: [Id.]{.underline}

[^179]: Order No. 888 at 31,762, n.499.

[^180]: Order No. 2003-A at P 782.

[^181]: We note that, similar to when the Affected System is a
    non-jurisdictional entity, the Commission does not have to have
    jurisdiction over the Affected System in order for the
    interconnection to proceed. [See]{.underline} Order No. 2003-A at P
    114-115.

[^182]: Order No. 2003 at P 910.

[^183]: [See]{.underline} Standardization of Generator Interconnection
    Agreements and Procedures, Notice Clarifying Compliance Procedures,
    106 FERC ¶ 61,009 at P 2 (2004).

[^184]: Electronic Tariff Filings, Notice of Proposed Rulemaking, 69 FR
    43929 (July 23, 2004), FERC Stats. & Regs., Proposed Regulations, ¶
    32,575 (July 8, 2004)

[^185]: Order No. 2003 at P 824-25.

[^186]: [See also]{.underline} New York Independent System Operator,
    Inc., 108 FERC ¶ 61,159 at P 95 (2004), [reh\'g
    pending]{.underline}.

[^187]: Order No. 2003 at P 827.

[^188]: [See]{.underline} Order No. 2003-B at P 80.

[^189]: Order No. 2003 at P 815.

[^190]: Order No. 2003 at P 815.

[^191]: 18 CFR § 292.303 (2004).

[^192]: Revised Public Utility Filing Requirements, Order No. 2001, 67
    FR 31043 (May 8, 2002), FERC Stats. & Regs. & 31,127 (2002); [reh\'g
    denied]{.underline}, Order 2001-A, 100 FERC & 61,074 (2002);
    [reconsideration and clarification denied]{.underline}, Order No.
    2001-B, 100 FERC & 61,342 (2002); [further order]{.underline}, Order
    No. 2001-C, 101 FERC & 61,314 (2002).

[^193]: Order No. 2001 pointed out that Part 35 of the Commission\'s
    regulations does not make a distinction between an interconnection
    agreement and other agreements for service that must be filed under
    the Commission\'s regulations. Order No. 2001, therefore, said that
    if an interconnection agreement conforms to a Commission-approved
    [standard]{.underline} form of interconnection agreement, the
    utility does not have to file it, but must report it in the Electric
    Quarterly Reports. It also stated that the requirement to file
    contract data and transaction data begins with the first Electric
    Quarterly Report filed after service begins under an agreement, and
    continues until the Electric Quarterly Report filed after it expires
    or by order of the Commission. However, an interconnection agreement
    that does not precisely match the Transmission Provider\'s approved
    interconnection agreement or that is unexecuted must be filed with
    the Commission. The Transmission Provider must clearly show where
    the agreement does not conform to its standard interconnection
    agreement, preferably through red-lining and strike-out.

[^194]: 5 CFR § 1320.11 (2004).

[^195]: 44 U.S.C. § 3507(d) (2000).

[^196]: 44 U.S.C. § 3512; 5 CFR § 1320.5(b); 5 CFR § 1320.6(a).

[^197]: See 1 CFR § 21.35 and 5 CFR § 1320.3(f)(3).

[^198]: Adjustments made to reflect an increase in the number of
    respondents from the estimates in the Small Generator
    Interconnection NOPR.

[^199]: Adjusted figures to reflect an increase in the number of
    respondents.

[^200]: Regulations Implementing National Environmental Policy Act,
    Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs.
    & 30,783 (1987).

[^201]: 18 CFR § 380.4(a)(2)(ii) (2004).

[^202]: 18 CFR § 380.4(a)(5) (2004).

[^203]: 5 U.S.C. § 601-612 (2000).

[^204]: [See]{.underline} 5 U.S.C. § 601(3) and § 601(6) and 15 U.S.C. §
    632(a).

[^205]: [See]{.underline} 13 CFR § 121.601.

[^206]: Source: Rural Utilities Service, U.S. Department of Agriculture,
    <http://www.usdagov.rus/electric/borrowers/index.htm>. April, 2005.

[^207]: Source: Arthur D. Little, [Distribution Generation: System
    Interfaces]{.underline}, Arthur D. Little, Inc., Cambridge,
    Massachusetts, 1999.

[^208]: 5 U.S.C. § 804(2) (2000).

[^209]: 5 U.S.C. § 801(a)(1)(A) (2000).

[^210]: This list includes commenters who filed in response to the
    request for comments in the Notice of Proposed Rulemaking, the
    August 12, 2004 Request for Supplemental Comments, or both.
    Commenters who responded to the Request for Supplemental Comments
    are also listed separately at the end of this appendix.