Standardization of Generator Interconnection Agreements and Procedures, 37661-37669 [05-12870]

Download as PDF Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations List of Subjects in 14 CFR Part 39 Air transportation, Aircraft, Aviation safety, Safety. Adoption of the Amendment Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows: I PART 39—AIRWORTHINESS DIRECTIVES 1. The authority citation for part 39 continues to read as follows: I Authority: 49 U.S.C. 106(g), 40113, 44701. § 39.13 [Amended] 2. The FAA amends § 39.13 by adding the following new airworthiness directive (AD): I 2005–13–40 Boeing: Amendment 39–14177. Docket No. FAA–2005–20355; Directorate Identifier 2004–NM–198–AD. Effective Date (a) This AD becomes effective August 4, 2005. Affected ADs (b) None. Applicability: (c) This AD applies to Boeing Model 727, 727C, 727–100, 727– 100C, 727–200, and 727–200F series airplanes; certificated in any category; equipped with an auxiliary fuel tank having a fuel pump installed. Unsafe Condition (d) This AD was prompted by a design review of the fuel pump installation, which revealed a potential unsafe condition related to the auxiliary fuel tank(s). We are issuing this AD to prevent dry operation of the fuel pumps for the auxiliary fuel tank, which could create a potential ignition source inside the auxiliary fuel tank that could result in a fire or explosion of the auxiliary fuel tank. Compliance: (e) You are responsible for having the actions required by this AD performed within the compliance times specified, unless the actions have already been done. Airplane Flight Manual (AFM) Revision (f) Within 30 days after the effective date of this AD, revise the Limitations section of the Boeing 727 AFM to contain the following information. This may be done by inserting a copy of this AD in the AFM. ‘‘Auxiliary Tank Fuel Pumps Auxiliary tank fuel pump switches must be positioned ‘OFF’ unless the auxiliary tank(s) contain fuel. Auxiliary tank(s) fuel pumps must be ‘OFF’ unless personnel are available in the flight deck to monitor low pressure lights. When established in a level attitude at cruise, if the auxiliary tank(s) contain usable fuel and the auxiliary tank(s) pump switches are ‘OFF,’ the auxiliary tank(s) pump switches should be positioned ‘ON’ again. VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 Each auxiliary tank fuel pump switch must be positioned ‘OFF’ without delay, for all conditions including takeoff and climb, when the respective auxiliary tank fuel pump low pressure light illuminates.’’ Note 1: When text identical to that in paragraph (f) of this AD has been included in the general revisions of the AFM, the general revisions may be inserted into the AFM, and the copy of this AD may be removed from the AFM. Alternative Methods of Compliance (AMOCs) (g) The Manager, Seattle Aircraft Certification Office, FAA, has the authority to approve AMOCs for this AD, if requested in accordance with the procedures found in 14 CFR 39.19. Material Incorporated by Reference (h) None. Issued in Renton, Washington, on June 21, 2005. Ali Bahrami, Manager, Transport Airplane Directorate, Aircraft Certification Service. [FR Doc. 05–12844 Filed 6–29–05; 8:45 am] BILLING CODE 4910–13–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM02–1–006; Order No. 2003– C] Standardization of Generator Interconnection Agreements and Procedures Issued June 16, 2005. Federal Energy Regulatory Commission, DOE. ACTION: Order on rehearing. AGENCY: SUMMARY: The Federal Energy Regulatory Commission (Commission) affirms, with certain clarifications, the fundamental determinations in Order No. 2003–B. EFFECTIVE DATE: July 18, 2005. FOR FURTHER INFORMATION CONTACT: Patrick Rooney (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502– 6205. Roland Wentworth (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502–8262. Michael G. Henry (Legal Information), Office of the General Counsel, Federal PO 00000 Frm 00015 Fmt 4700 Sfmt 4700 37661 Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502–8532. SUPPLEMENTARY INFORMATION: Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher, and Suedeen G. Kelly. I. Introduction and Summary 1. In this order, we affirm, with certain clarifications, Order No. 2003– B,1 which, together with Order Nos. 2003 and 2003–A, governs interconnection of large generators to the transmission grid. The pro forma Large Generator Interconnection Procedures (LGIP) and Large Generator Interconnection Agreement (LGIA) required in those orders help prevent undue discrimination, preserve the reliability of the nation’s transmission system, and lower prices for customers by allowing a variety of generation resources to compete in wholesale electricity markets. At its core, the Commission’s orders ensure that all Generating Facilities that will make sales for resale of electric energy in interstate commerce are offered Interconnection Service on comparable terms. These orders benefit customers by establishing the just and reasonable terms and conditions for interconnecting to the transmission grid, while ensuring that reliability is protected. 2. This order on rehearing reaffirms or clarifies the Commission’s policies on the recovery of Network Upgrade costs and non-pricing policies. For example, it reaffirms the 20-year reimbursement policy for Network Upgrade costs and clarifies the Commission’s policy regarding credits for Network Upgrades as it applies to Affected System Operators and jointly owned transmission facilities. The order also clarifies the Commission’s jurisdiction under the Federal Power Act 2 to apply this Final Rule and further explains the Transmission Provider’s payment obligation for reactive power supplied by an Interconnection Customer. 3. This order takes effect 30 days after issuance by the Commission. As with the Order No. 2003 compliance process, the Commission will deem the open access transmission tariff (OATT) of each non-independent Transmission 1 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, Order No. 2003–A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ¶ 31,160 (2004) (Order No. 2003–A), order on reh’g, Order No. 2003–B, 70 FR 265 (Jan. 4, 2005), FERC Stats. & Regs. ¶ 31,171 (2005) (Order No. 2003–B). See also Notice Clarifying Compliance Procedures, 106 FERC ¶ 61,009 (2004). 2 16 U.S.C. 791a–825r (2000). E:\FR\FM\30JNR1.SGM 30JNR1 37662 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations Provider to be amended to adopt the clarifications to the pro forma LGIP and LGIA contained herein 30 days after issuance of this order by the Commission. And as with the Order No. 2003–B compliance process, each nonindependent Transmission Provider will be required to amend its OATT to include the LGIP and LGIA clarifications contained herein within 60 days after issuance of this order by the Commission. Also, within 60 days after issuance of this order, each independent Transmission Provider must submit revised tariff sheets incorporating its clarifications to its OATT or an explanation under the independent entity variation standard as to why it is not proposing to adopt each clarification described in this order. 4. The Commission received 12 timely requests for rehearing or for clarification of Order No. 2003–B.3 Under section 313(a) of the Federal Power Act (FPA),4 requests for rehearing of a Commission order were due within thirty days after issuance of Order No. 2003–A, i.e., no later than January 19, 2005. The Commission also received one answer from the North Carolina Electric Membership Corp. (NCEMC), which the Commission treats as yet another request for rehearing. Because this answer was submitted after the statutory 30-day rehearing deadline, it is rejected. However, the Commission will treat this late-filed request for rehearing as a request for reconsideration. 5. For a background discussion, please consult the prior orders in this proceeding.5 II. Discussion A. Pricing and Cost Recovery Provisions 1. Requirement for Full Reimbursement After 20 Years 6. In Order No. 2003, the Commission continued to require the Transmission Provider and any Affected System Operator to reimburse the Interconnection Customer for its upfront payments for Network Upgrades by means of credits against the Interconnection Customer’s transmission bills. We stated that the Interconnection Customer, 3 Requests were filed by Calpine Corporation (Calpine), Edison Electric Institute (EEI), Entergy Services, Inc. (Entergy), Georgia Transmission Corp. (Georgia Transmission), MEAG Power, National Rural Electric Cooperative Association (NRECA), Pacificorp, PSEG Companies (PSEG), Public Service Company of New Mexico (PNM), Reliant Resources, Inc. (Reliant), Southern California Edison Company (SoCal Edison), and Southern Company Services, Inc. (Southern Company). 4 16 U.S.C. 8251(a) (2000). 5 Order No. 2003 at P 5–17; Order No. 2003–B at P 5–11. VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 Transmission Provider, and Affected System Operator were permitted to adopt any alternative payment schedule that is mutually agreeable as long as all such amounts are refunded, with interest, within five years of the Commercial Operation Date of the Generating Facility. In Order No. 2003– A, we retained this general policy but removed the obligation to make a balloon payment for any unrefunded amounts after five years. In Order No. 2003–B, the Commission revised pro forma LGIA article 11.4.1 to state that, other credit and refund provisions of Order No. 2003–A notwithstanding, full reimbursement by the Transmission Provider shall not extend beyond 20 years from the Commercial Operation Date; 6 in other words, a balloon payment is required at 20 years. a. Rehearing Requests 7. Some petitioners argue that the Transmission Provider should not be required to reimburse the Interconnection Customer in full after 20 years if the Interconnection Customer has not earned enough credits (by taking delivery service) to reimburse it for the Network Upgrades.7 For example, Entergy states that this requirement is unfair to native load customers, arbitrary, and inconsistent with the Commission’s previous policies. Entergy argues that the mandatory repayment provision converts the Interconnection Customer’s upfront payment for Network Upgrade costs that are directly caused by an Interconnection Request from an investment, where the Interconnection Customer is at risk, to a loan. Southern Company claims that the Commission’s previous policy of not requiring a balloon payment and allowing transmission credits only as delivery service was taken from a particular generating facility, was arguably consistent with the Commission’s policy of allowing Transmission Providers to charge the ‘‘higher of’’ incremental or embedded costs. However, Southern Company claims that, if a full refund is always required within 20 years, this policy would be violated. 8. Conversely, other petitioners argue that 20 years is too long to wait for full reimbursement of upfront payments.8 Reliant states that the Commission erred by failing to return to the balanced crediting approach in Order No. 2003, which required the Transmission Provider to refund the balance of the Interconnection Customer’s upfront PO 00000 6 Order No. 2003–B at P 34–41. Southern Company and PacifiCorp. 8 See Reliant, Calpine and PSEG. 7 Entergy, Frm 00016 Fmt 4700 Sfmt 4700 payment within five years. Reliant argues that the 20-year reimbursement requirement does not provide incentives for proper siting decisions, and actually raises costs for the very customers the Commission is seeking to protect. This is because the additional financing costs of a 20-year refund period raise the cost of new generators who wish to enter the market. In Reliant’s view, this creates a barrier to entry that harms competition, and thereby harms native load and other Transmission Customers. b. Commission Conclusion 9. In response to those petitioners that object to any requirement for full reimbursement on a date certain, as well as those that believe 20 years is too long to wait for reimbursement, we note that we have responded at length to many of these arguments in our previous orders. We therefore simply reiterate here our conclusion in Order No. 2003–B that our crediting and refund policy, including the 20-year reimbursement requirement, provides a reasonable balance between the objectives of promoting competition and infrastructure development, protecting the interests of Interconnection Customers, and protecting native load and other Transmission Customers.9 2. Reimbursement of Upfront Payment for Network Upgrades and Affected Systems a. Rehearing Requests 10. Several petitioners ask the Commission to clarify whether an Affected System Operator has an obligation to reimburse the Interconnection Customer by means of a 9 We remind petitioners that we continue to view the Interconnection Customer’s upfront payment for Network Upgrades as essentially a loan from the Interconnection Customer to the Transmission Provider or Affected System Operator. Although the appropriate length of the repayment period for such a loan is not a number that can be determined with great precision, we note that 20 years reflects the approximate minimum life of facilities that typically constitute Network Upgrades that generally would be needed to accommodate an Interconnection Customer’s generator interconnection. Also, the courts have recognized that the Commission sometimes must adopt a value within a range, as long as the chosen value is related to the problem being addressed. E.g., ExxonMobil Gas Marketing Co. v. FERC, 297 F.3d 1071, 1085 (D.C. Cir. 2002) (‘‘We are generally unwilling to review line-drawing performed by the Commission unless a petitioner can demonstrate that lines drawn * * * are patently unreasonable, having no relationship to the underlying regulatory problem.’’ (quotes and citation omitted)); see also Prometheus Radio Project v. FCC, 373 F.3d 372, 410 (D.C. Cir. 2004) (‘‘Deference to the Commission’s judgment is highest when assessing the rationality of the agency’s line-drawing endeavors.’’); Sinclair Broad. Group, Inc. v. FCC, 284 F.3d 148, 159 (D.C. Cir. 2002) (granting deference to an agency’s linedrawing efforts within its expertise). E:\FR\FM\30JNR1.SGM 30JNR1 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations balloon payment 20 years after the Commercial Operation Date.10 For example, NRECA asks the Commission to clarify that if credits provided by an Affected System Operator have not fully reimbursed the Interconnection Customer’s upfront payment within 20 years, the Affected System Operator is not required to make a balloon payment, but instead may continue to provide the Interconnection Customer with credits for transmission service on the Affected System until the Interconnection Customer’s entire upfront payment has been reimbursed. 11. On a related matter, NRECA also asks the Commission to clarify that, the Transmission Provider or Affected System Operator has no further obligation to reimburse the Interconnection Customer for its upfront payment if the Generating Facility ceases Commercial Operation before the Interconnection Customer has been completely reimbursed. 12. Finally, NCEMC asks the Commission to clarify the Interconnection Customer’s right to receive a refund of its upfront payment for Network Upgrades on an Affected System when the Interconnection Customer is also a Network Customer of the Affected System. NCEMC states that it intends to construct a generating facility and designate it as a network resource on the Transmission Provider’s Transmission System, where NCEMC is a network customer. Although NCEMC is also a Network Customer of the Affected System, it says that the transmission service revenues that the Affected System receives from NCEMC do not vary according to what resources are designated as Network Resources on the Affected System, but rather with NCEMC’s load. NCEMC argues that a rule that would tie credits from the Affected System to incremental charges associated with transmission service taken from the Affected System with respect to the Generating Facility is inappropriate for an Interconnection Customer that is also a Network Customer on the Affected System. b. Commission Conclusion 13. In response to NRECA, we clarify that both the Transmission Provider and an Affected System Operator need provide credits for transmission service only when the Interconnection Customer takes transmission service with the Large Generating Facility identified as the primary point of receipt of that service. We clarify that both the Transmission Provider and an Affected System Operator must provide 10 See EEI, NRECA, PNM and NCEMC. VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 the 20-year lump sum reimbursement to refund any remaining balance, even if no transmission service was taken. Although Order No. 2003–B could be read to suggest that the Affected System need only provide reimbursement for transmission service taken,11 this was not our intent. Indeed, the revised language in article 11.4.1 in Order No. 2003–B clearly subjects an Affected System Operator to the 20-year lump sum requirement.12 This is consistent with the Commission’s policy of treating a non-independent Affected System Operator the same as a non-independent Transmission Provider because both have the same incentive to frustrate the development of new, competitive generation.13 14. In response to NRECA’s second point, we clarify that the Affected System Operator, like the Transmission Provider, must reimburse the Interconnection Customer for its upfront payment even if the Generating Facility ceases Commercial Operation before the Interconnection Customer is completely reimbursed as long as the Interconnection Agreement between the Interconnection Customer and the Transmission Provider remains in full force and effect.14 15. In response to NCEMC, we note that, because the circumstances that NCEMC describes are highly factspecific, and we do not know all the relevant facts, they are not appropriately addressed in a rulemaking. Therefore, we will not attempt to answer NCEMC’s request for clarification in this order on rehearing, and will address the issue if it arises in a specific proceeding. 3. Reimbursement Obligation of the Operator of a Jointly-Owned System 16. In Order No. 2003–B, the Commission stated that, in the case of an Affected System that is jointly owned by public and non-public utilities, it is the responsibility of the Affected System Operator to provide the credits and to seek reimbursement for any amounts that it believes it is owed by the other owners.15 If a Transmission Provider provides transmission service on a Transmission System that is jointly owned, that Transmission Provider must follow a similar procedure. a. Rehearing Requests 17. Several petitioners ask the Commission to clarify the crediting and No. 2003–B at P 41, 42. obligation does not apply if the Affected System is a non-jurisdictional entity. 13 See Order No. 2003–A at P 636; see also Order No. 2003 at P 738. 14 See Order No. 2003–A at P 619. 15 Order No. 2003–B at P 42. PO 00000 11 Order 12 This Frm 00017 Fmt 4700 Sfmt 4700 37663 refund responsibilities of an operator of an Affected System that is jointly owned.16 For example, EEI asks the Commission to clarify that the public utility Transmission Provider’s obligation to provide transmission credits is limited to the amount of upfront payments made for Network Upgrades owned by the Transmission Provider. EEI argues that the policy in Order No. 2003–B may work when the cost recovery for jointly owned facilities is provided for under a single tariff, but it presents problems when the various joint owners each provide transmission service independently under their own separate tariffs. In addition, Georgia Transmission Corporation asks the Commission to clarify that Order No. 2003–B does not require a nonjurisdictional owner of a jointly owned transmission system to reimburse the Affected System Operator or Transmission Provider. Georgia Transmission states that such clarification would be consistent with the Commission’s statements in Order Nos. 2003 and 2003–A that ‘‘if an Affected System is a non-public utility, Order No. 2003 does not require that it provide refunds to the Interconnection Customer to satisfy the reciprocity condition.’’ b. Commission Conclusion 18. The Commission clarifies that it is not requiring every operator of a jointly owned system, whether it is a Transmission Provider or an Affected System Operator, to reimburse the Interconnection Customer for upfront payments for Network Upgrades received by the non-public utility owners of the system. The discussion in P 42 of Order No. 2003–B applies only to a situation where the operator is a public utility and has tariff administration responsibilities on behalf of the other owners. We clarify that the operator’s responsibility for flowing through credits and reimbursing the Interconnection Customer for its upfront payment does not extend beyond its normal duties as the tariff administrator. Each owner of a jointly-owned system has the financial responsibility under its own Commission-regulated tariff to provide transmission credits and final reimbursement to the Interconnection Customer for the upfront payments that the owner has received. This responsibility does not extend to a nonpublic utility transmission owner or operator, of course.17 16 See EEI, Georgia Transmission, MEAG Power, PNM, SoCal Edison, and Southern Company. 17 See, e.g., Order No. 2003 at P 843. E:\FR\FM\30JNR1.SGM 30JNR1 37664 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations 4. Credits for Transmission Service When the Generating Facility Is Not the Source 19. In Order No. 2003–B, the Commission stated that, if the Interconnection Customer or other Transmission Customer is taking firm Point-to-Point Transmission Service under the OATT with the Generating Facility as the source of the power transmitted, the customer continues to have all of the rights given by the OATT to change temporarily Points of Receipt or Delivery, if capacity is available, and is entitled to continue to receive credits toward the cost of the transmission service while doing so.18 a. Rehearing Requests 20. EEI asks the Commission to clarify that, while a Transmission Customer may temporarily change its point of receipt, it will not receive credits for transmission service that does not involve power generated from the Generating Facility. The Commission should also clarify what is meant by a ‘‘temporary’’ change to ensure that the Transmission Customer cannot use this provision to game the system and impose unwarranted costs on native load customers and other users of the system. In addition, PNM asks the Commission to clarify that sham designations of transactions through a non-operating Generating Facility are not a permitted means of obtaining transmission credits. 21. Southern Company argues that, contrary to the claims of some commenters, denying credits for transmission service when the Generating Facility is not the source of the power transmitted does not restrict any rights that the Interconnection Customer has under Order No. 888. Southern Company states that before Order No. 2003–B, Interconnection Customers were free to change points of receipt and delivery subject only to the requirements of Order No. 888. It argues that nothing in Order No. 2003 or Order No. 2003–A restricts this right. Providing Interconnection Customers with credits for redirected service does nothing to increase their ability to change delivery and receipt points. Instead, Southern Company argues, providing credits for redirected service will circumvent the native load protections adopted in Order No. 2003– A. b. Commission Conclusion 22. The Commission is not persuaded to change the policy under which the Transmission Provider must provide transmission credits during periods when the Interconnection Customer is using, in accordance with the terms of its transmission service, a secondary receipt point rather than the Generating Facility. As long as the Interconnection Customer or another entity is taking transmission service that identifies the Generating Facility as the point of receipt for that service in the original firm point-to-point transmission service request, the Interconnection Customer is entitled to a credit toward the cost of that service. The possibility that this could lead to abuse is greatly overstated. A transmission customer that elects to use a secondary point of receipt or delivery under the OATT must take such service only on a non-firm basis and at the lowest priority level. The Commission does not believe that access to this non-firm service option is sufficient to lead to abuse. Furthermore, in response to PNM, the Commission clarifies that a sham designation of a transaction through a non-operating Generating Facility is not a permitted means of obtaining transmission credits. 23. The Commission clarifies that its use of the word ‘‘temporarily’’ is intended to distinguish a request to use secondary receipt point on a non-firm basis as permitted under the tariff from a request to change the point of receipt on a firm basis. 5. Implementing the ‘‘Higher Of’’ Policy 24. In Order No. 2003–B, we stated that our interconnection pricing policy continues to allow the Transmission Provider to charge the Interconnection Customer a transmission rate that is the higher of the incremental cost rate for Network Upgrades required to interconnect the Generating Facility and an embedded cost rate for the entire Transmission System (including the cost of the Network Upgrades). We further stated that, if a Transmission Provider (or any other interested party) believes that, for an actual interconnection, it faces circumstances where native load and other customers are not held harmless, it should make that demonstration in an actual transmission rate filing.19 a. Rehearing Requests 25. With reference to the Commission’s second statement cited above, Southern Company claims that the Administrative Procedure Act requires that agency action be supported by substantial evidence 20 and that the Commission’s attempt to ‘‘pass the buck’’ by requiring a Transmission 19 Order 18 Order No. 2003–B at P 38. VerDate jul<14>2003 15:12 Jun 29, 2005 20 5 Jkt 205001 PO 00000 No. 2003–B at P 54–57. U.S.C. 706(2)(E) (2000). Frm 00018 Fmt 4700 Sfmt 4700 Provider to demonstrate the negative does not meet that standard. 26. In response to our statement that we are willing to look on a case-by-case basis at proposals to protect native load and other existing customers, PacifiCorp argues that administrative efficiency favors a generic rule that addresses the need to fully protect native load. In PacifiCorp’s view, it would be costly, burdensome, and inefficient to require a Transmission Provider to file a request to protect its native load every time a merchant generator signs an interconnection agreement without having executed a service agreement for transmission delivery service of sufficient duration to cover the cost of Network Upgrades. b. Commission Conclusion 27. The Commission reiterates that the appropriate ratemaking approach to ensure that native load and other customers are held harmless depends on the particular set of facts that result in native load and other customers allegedly not being held harmless. For example, it may depend on the particular circumstances of the Interconnection Customer, its Generating Facility and location, and transmission interconnection service that is requested (Energy Resource Interconnection Service or Network Resource Interconnection Service), the tariff status of the power buyer (pointto-point or Network Integration Transmission Service), and the relationship if any of the Interconnection Customer to the transmission tariff service customer. This is a ratemaking question that does not lend itself to a generic solution. Furthermore, supporting an agency action by substantial evidence requires facts in some cases, so that case-specific, fact-based determinations are sometimes necessary instead of generic theoretical solutions. B. Other Issues 1. Scoping Meeting 28. In Order No. 2003–B, the Commission rejected Southern’s argument that the LGIP section 3.4 requirement to keep the identity of the Interconnection Customer confidential conflicts with the Transmission Provider’s obligation in LGIP section 3.3.4 to reveal in a notice any meeting the Transmission Provider conducts with an affiliated Interconnection Customer. The Commission explained that the requirement to disclose Affiliate meetings resulted from the Commission’s attempt to balance the need to treat affiliated and nonaffiliated E:\FR\FM\30JNR1.SGM 30JNR1 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations Interconnection Customers alike with the need to make Order No. 2003 conform to the established Code of Conduct and Standards of Conduct requirements.21 between the Interconnection Customer and Transmission Provider results in less harm than if there were no safeguards at all. a. Request for Rehearing 29. On rehearing, Southern again argues that Order No. 2003–B discriminates against affiliates of a Transmission Provider because requiring disclosure of their identities and confidential information will benefit competitors. Southern argues that while the Commission attempts to justify this disparate treatment by claiming that affiliated and nonaffiliated generators are not similarly situated, they are similarly situated in that for both of them, revealing the identity of the Interconnection Customer would put that customer ‘‘at a competitive disadvantage and its project at risk.’’ 22 Southern then cites Federal court precedent saying that the Commission cannot treat similarly situated customers in a non-comparable manner.23 31. In Order No. 2003–B, the Commission reaffirmed the decision in Order No. 2003–A to eliminate from the pro forma LGIA a provision requiring the Interconnection Customer to make generator balancing service arrangements (before submitting a schedule for delivery service) that identify the Interconnection Customer’s Generating Facility as the Point of Receipt for the scheduled delivery. Order No. 2003–B at P 74–75. We removed the requirement because generator balancing is an ancillary service that is part of delivery service, not interconnection service. Recognizing that some Transmission Providers may prefer to include a balancing provision in an interconnection agreement rather than in a separate agreement, the Commission explained that the Transmission Provider may do so in individual interconnection agreements tailored to the Parties’ specific circumstances and subject to Commission approval. b. Commission Conclusion 30. Contrary to Southern’s argument, the Commission concludes that the disparate treatment here is justified because of concerns about affiliate abuse. As explained in Order Nos. 2003–A and 2003–B,24 this measure allows Transmission Providers and their affiliates to share confidential information, but with safeguards that provide the public with notice of any meetings with affiliated Interconnection Customers and the opportunity to review a transcript. The affiliate relationship is a factual difference that justifies the different treatment here.25 Additional safeguards are needed to ensure against affiliate abuse.26 The Commission reaffirms its conclusion that revealing the affiliate relationship 21 Order No. 2003–B at P 137. Order No. 2003 at P 114. 23 Town of Norwood v. FERC, 202 F.3d 392, 402 (1st Cir. 2000). 24 See Order No. 2003 A at P 107; Order No. 2003–B at P 136. 25 See Public Service Co. of Indiana v. FERC, 575 F.2d 1204, 1212 (7th Cir. 1978); Cities of Bethany v. FERC, 727 F.2d 1131, 1140 (D.C. Cir. 1984). 26 See, e.g., Entergy Services, Inc., 111 FERC ¶ 61,145 at P 10 (2005) (initiating hearing to examine the ‘‘credible concerns’’ regarding transmission market power, by failing to provide interconnections or blocking alternative generation sources); Southern Companies Energy marketing, Inc, 111 FERC ¶ 61,144 at P 16 (initiating hearing to examine the ‘‘credible concerns’’ regarding unduly preferential treatment afforded affiliates in access generation sites) (2005); see also Entergy Services, Inc., 103 FERC ¶ 61,256 at P 44–53 (initiating a hearing to examine concerns regarding affiliate dealing in a bidding process for power purchase agreements). 22 See VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 2. Generator Balancing a. Request for Rehearing 32. Southern seeks clarification that nothing in Order No. 2003–B precludes Southern’s approach in its in Docket No. ER04–1161–000, which is to include a provision in its LGIA that refers to the requirement that a generator enter into an operating agreement that outlines options for remedying imbalances, but does not prescribe specific generator balancing service or rates. 37665 because as explained in Order No. 2003–A balancing service is more closely related to transmission delivery service than interconnection service. For the same reasons, we follow that decision here. 3. Reactive Power Payments to Generator 34. Order No. 2003–B reaffirmed Order No. 2003–A’s modification to LGIA article 9.6.3 to require the Transmission Provider to pay the Interconnection Customer for reactive power the Interconnection Customer provides or absorbs only when the Transmission Provider asks the Interconnection Customer to operate its Generating Facility outside a specified power factor range (or dead band). However, if the Transmission Provider pays its own or affiliated generators for reactive power service within the specified range, it must also pay the Interconnection Customer for providing reactive power within the specified range.28 The Commission stated that although ‘‘the Transmission Provider is not ‘paying’ its own or affiliated generators directly for providing reactive power within the specified range, the owner of the generator is nonetheless being compensated for that service when the Transmission Provider includes reactive power related costs in its transmission revenue requirement.’’ 29 33. The Commission has issued an order in Docket No. ER04–1161–000 that addressed Southern’s request for clarification and rejected Southern’s proposal to include in the LGIA a reference to a balancing service agreement.27 There the Commission stated that a Transmission Provider may either adopt a stand-alone generator balancing service agreement or request the inclusion of a generator balancing service provision tailored to the Parties’ specific standards and circumstances in an individual interconnection agreement. The Commission does not include a standardized balancing provision in the LGIA, even one as limited in scope as Southern proposes, a. Requests for Rehearing 35. Southern and PNM take issue with the Commission’s statement in Order No. 2003–B that when a Transmission Provider is required to provide Reactive Power under Schedule 2 of its OATT, and charges for that service, it is thereby paying its own generators for reactive power within the established range, thus triggering a responsibility to pay the Interconnection Customer in the same manner. 36. Southern argues that this is incorrect because Schedule 2 only allows the Transmission Provider to be paid for reactive power from ‘‘generation sources.’’ The revenue requirements associated with such generation are not recovered in a transmission revenue requirement (hence the need for a Schedule 2 charge separate from the OATT transmission delivery charges). Furthermore, even if this statement is clarified to be a reference to a Transmission Provider receiving compensation for its generator-supplied reactive power costs 27 Southern Company Services, Inc., 111 FERC ¶ 61,004 at P 16 (2005), reh’g on other grounds pending. 28 Order No. 2003–A at P 416; Order No. 2003– B at P 114. 29 Order No. 2003–B at P 119. b. Commission Conclusion PO 00000 Frm 00019 Fmt 4700 Sfmt 4700 E:\FR\FM\30JNR1.SGM 30JNR1 37666 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations in its Schedule 2 charge, Southern continues, that would be incorrect as well. It would be wrong because, at least in the case of the Southern Companies, the dollars received for Schedule 2 service do not go to the generators or to the Transmission Provider, but instead are treated as revenue credits to reduce the costs that retail customers would otherwise have to pay. As a result, the beneficiaries of Schedule 2 revenues are retail customers, not the Transmission Provider or its generators. Paying Interconnection Customers for providing this service would give them an unfair advantage over Transmission Providers in the form of additional revenue. 37. PNM agrees that if a Transmission Provider must pay Interconnection Customers for reactive power within the deadband, it will need to recover that cost as part of its Schedule 2 revenue requirement. The result will be an unwarranted windfall to Interconnection Customers, higher costs for Transmission Customers, and increased filing burdens for public utility Transmission Providers. 38. PNM and Southern also argue that a service obligation distinguishes the Transmission Provider from the Interconnection Customer. They note that a Transmission Provider must plan, construct, and operate its generation at all times to meet the system’s localized power and voltage requirements. Unlike the Transmission Provider, an Interconnection Customer constructs its generation in the location best meeting its own needs. Southern argues that an Interconnection Customer’s generator is simply not ‘‘comparable’’ to a Transmission Provider’s generator for purposes of supplying reactive power. 39. Southern notes that Order Nos. 888–A and 888–B explained that a generator must have to be available and under the Transmission Provider’s control (so that it reduces the Transmission Provider’s reactive power investment requirements) in order to be entitled to compensation. Since the Interconnection Customer’s generators are not under the Transmission Provider’s control, the Transmission Provider cannot rely on those generators to reduce its investment in reactive power facilities necessary to satisfy its system’s needs (as it can for its own generators). 40. Alternatively, PNM requests that the Commission clarify procedures by which Transmission Providers can pass through as part of their Schedule 2 revenue requirement any amounts that they are required to pay Interconnection Customers for reactive power within the specified power range. VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 41. PNM also requests that the Commission explain what it means when it states that nothing in LGIA Article 9.6.3 ‘‘disturbs any present arrangements for reactive power compensation.’’ Order No. 2003–B at P 121. PNM supports applying the policy to new interconnection agreements and grandfathering existing agreements. b. Commission Conclusion 42. We disagree with Southern’s and PNM’s argument that the Commission should base its decision on what the Transmission Provider does with the revenues from providing reactive power within the established range. The Commission is less concerned with the flow of these revenues than with the unduly discriminatory treatment of nonaffiliated Interconnection Customers that provide this important system service. We therefore reiterate that if the Transmission Provider’s affiliate receives a payment for providing this service within the specified range, then payments must be made to nonaffiliated Interconnection Customers for providing the service. Because the nonaffiliates are providing an important service, we disagree with PNM that such payments would result in a windfall to them. 43. Although the Transmission Provider’s or its affiliate’s generators may be required to operate when others are not, this distinction in availability is not so significant as to eliminate the need to compensate other generators. With respect to Southern’s assertion that the Interconnection Customer’s generators are not under the Transmission Provider’s control, Order No. 2003–B clarified 30 that while the Transmission Provider cannot demand that the Interconnection Customer operate its Generating Facility solely to provide reactive power, it may require the Interconnection Customer to provide reactive power from time to time when its Generating facility is in operation. The requirement to pay exists only as long as the Generating Facility follows the Transmission Provider’s reactive power instructions. This is a sufficient level of control to warrant compensation for providing reactive power as described in Order Nos. 888–A and 888–B. 44. In response to PNM’s requests for clarification, although we do not agree that selecting the best sources of reactive power from available generators should necessarily increase reactive power costs—indeed, it may lower such costs—a Transmission Provider may propose to incorporate in its rates any PO 00000 30 Order No. 2003–B at P 118. Frm 00020 Fmt 4700 Sfmt 4700 such increase in Schedule 2 amounts. At that time the Commission will consider alternatives for recovery of these charges.31 45. Finally, Order No. 2003 does not abrogate existing agreements,32 and we reiterate that existing agreements for reactive power compensation need not be amended to incorporate our policy on reactive power payments for newly interconnecting generators. 4. Interest Rate Applied to Nonjurisdictional Entities 46. LGIA Article 11.4.1 requires that the repayment for Network Upgrades shall include interest calculated in accordance with the Commission’s regulations. Order No. 2003–B clarified that the interest rate is in 18 CFR § 35.19a(a)(2)(iii). a. Request for Rehearing 47. NRECA argues that that interest rate is not appropriate for nonjurisdictional utilities that are ‘‘subject to’’ the Interconnection Rule due to the Commission’s reciprocity condition. The Commission’s interest rate bears no relationship to a non-jurisdictional utility’s cost of borrowing, NRECA explains, and it provides a windfall to the Interconnection Customer at the expense of a non-jurisdictional utility’s consumers. b. Commission Conclusion 48. We clarify that a nonjurisdictional entity subject to the reciprocity condition need not adhere to the crediting policy for Transmission Providers in Order No. 2003, including the payment of interest,33 unless it applies this same crediting policy to its own generation. Order No. 2003–A clarified that for rate matters, the reciprocity condition only requires comparability.34 Therefore, interest (at the Commission’s or some other interest rate) would be payable only if it is payable (at the same interest rate) to the non-jurisdictional entity’s own or affiliated generators, if any. 5. Jurisdiction 49. Order No. 2003–B corrected a misstatement in Order No. 2003–A and reiterated that if an Interconnection Customer seeks to interconnect with a 31 Commission staff has begun a general inquiry into reactive power pricing reform; see Principles for Efficient and Reliable Reactive Power Supply and Consumption, Docket No. AD05–1–000 (February 4, 2005) and the discussion at the Commission meeting on December 15, 2004. 32 See Order No. 2003 at P 911. 33 In its request for rehearing, NRECA refers to an interest rate that the Commission corrected in Order No. 2003–B. 34 Order No. 2003–A at 777. E:\FR\FM\30JNR1.SGM 30JNR1 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations dual use facility (i.e., a facility that is used for both wholesale and retail sales) to make a wholesale sale, then Order No. 2003 applies because that facility is subject to an OATT.35 Request for Rehearing 50. SoCal Edison argues that the Commission must exercise jurisdiction over all wholesale generator interconnections, including those to ‘‘local distribution’’ facilities never previously used by wholesale customers. SoCal Edison says that the Commission incorrectly asserts that there are three categories of facilities (transmission, ‘‘local distribution,’’ and dual use) when only two actually exist (transmission and ‘‘local distribution’’). SoCal Edison says that a D.C. Circuit opinion finds that only two categories exist, and wholesale service over ‘‘local distribution’’ facilities is Commissionjurisdictional.36 SoCal Edison concludes that because all interconnections to distribution facilities are to ‘‘local distribution’’ facilities, all such interconnections should be treated the same for jurisdictional purposes, and jurisdiction should depend solely on whether the generator makes sales at wholesale. SoCal Edison therefore requests that the Commission rule that it has jurisdiction over all interconnections to ‘‘local distribution’’ facilities for the purpose of making wholesale sales. Commission Conclusion 51. We disagree with SoCal Edison that we should assert jurisdiction over all interconnections that could be used for wholesale sales, including the situation in which the Interconnection Customer seeks to interconnect to a ‘‘local distribution’’ facility being used exclusively for retail sales and thus is not available for service under an OATT at the time the Interconnection Request is made. In Order No. 2003, the Commission explained that the rule applies to interconnections to the facilities of a public utility’s Transmission System that, at the time the interconnection is requested, may be used either to transmit electric energy in interstate commerce or to sell electric energy at wholesale in interstate commerce pursuant to a Commission 35 Order No. 2003–B at P14. Edison cites Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C. Cir. 2003) (‘‘[W]hen 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).’’) and DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 2005) (applying a two category analysis). 36 SoCal VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 filed OATT.37 Thus, our assertion of jurisdiction over interconnections rested on two grounds: first, and primarily, our FPA jurisdiction over ‘‘transmission’’ facilities, which may be used for wholesale sales or unbundled retail sales and which are subject to an OATT; and, second, our FPA jurisdiction over wholesale sales which require the use of ‘‘local distribution’’ facilities and thus such facilities become subject to an OATT for purposes of the wholesale sales. We concluded that applying our interconnection rules to facilities already subject to an OATT would properly respect the jurisdictional bounds recognized by the courts in upholding Order No. 888 and subsequent cases.38 To adopt SoCal Edison’s position and interpret our authority more broadly, however, would allow a potential wholesale seller to cause the involuntary conversion of a facility previously used exclusively for state-jurisdictional interconnections and delivery, and subject to the exclusive jurisdiction of the state, into a facility also subject to the Commission’s interconnection jurisdiction—a result that we believe crosses the jurisdictional line established by Congress in the FPA. 52. FPA section 201(b)(1) gives the Commission the authority to regulate ‘‘all facilities’’ used for transmission and for the wholesale sale of electric energy in interstate commerce.39 The same FPA section denies the Commission jurisdiction ‘‘over facilities used in local distribution’’ except as specifically provided in Parts II and III of the FPA.40 The Court of Appeals for the D.C. Circuit recently explained this provision as meaning that, if a wholesale sale of electric energy in interstate commerce is 37 Order No. 2003 at P 804. Pursuant to Order No. 888, as upheld by the courts, facilities subject to an OATT are ‘‘transmission’’ facilities and facilities used for wholesale sales, whether labeled ‘‘transmission,’’ ‘‘distribution,’’ or ‘‘local distribution.’’ 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 at 31,969, 31,980 (1996), order on reh’g, Order No. 888–A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000) (TAPS v. FERC), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002); see TAPS v. FERC, 225 F.3d at 696 (noting that the Commission’s ‘‘assertion of jurisdiction over all wholesale transmissions, regardless of the nature of the facility, is clearly within the scope of its statutory authority’’). 38 See Detroit Edison Co. v. FERC, 334 F.3d 48 (D.C. Cir. 2003); DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 2005). 39 16 U.S.C. 824a(b)(1) (2000). 40 Id. PO 00000 Frm 00021 Fmt 4700 Sfmt 4700 37667 occurring, the Commission has jurisdiction over the transaction or service, even if the transaction occurs over a ‘‘local distribution’’ facility.41 53. When a ‘‘local distribution’’ facility is used to transmit energy sold at wholesale as well as energy sold at retail, we previously have called this a ‘‘dual use’’ facility because it is used both for sales subject to Commission jurisdiction and for sales subject to state jurisdiction.42 Under Order No. 2003, if such a facility is subject to wholesale open access under an OATT at the time the Interconnection Request is made, and the interconnection will connect a generator to a facility that would be used to facilitate a wholesale sale, Order No. 2003 applies and the interconnection must be subject to Commission-approved terms and conditions. Because the Commission’s authority to regulate in this circumstance is limited to the wholesale transaction, we conclude that we do not have the authority to directly regulate the facility that is used to transmit the energy being sold at wholesale. In other words, while the Commission may regulate the entire transmission component (rates, terms and conditions) of the wholesale transaction—whether the facilities used to transmit are labeled ‘‘transmission’’ or ‘‘local distribution’’— it may not regulate the ‘‘local distribution’’ facility itself, which remains state-jurisdictional. We believe this properly respects the boundaries drawn in the FPA. 6. Wind Power Exemption 54. Order No. 2003–A exempted wind generators from the power factor design criteria requirement in article 9.6.1, because as nonsynchronous generators, it would be difficult for these generators 41 Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C. Cir. 2003); accord Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 696 (D.C. Cir. 2000) (TAPS) (noting that ‘‘FERC’s assertion of jurisdiction over all wholesale transmissions, regardless of the nature of the facility, is clearly within the scope of its statutory authority,’’ and that the statute and case law support the proposition that the Commission has the authority to regulate ‘‘all aspects’’ of wholesale transactions). 42 We note that the DTE court rejected DTE’s attempt to use the dual use facility or dual function rationale. DTE Energy Co. v. FERC, 394 F.3d 954, 962–63 (D.C. Cir. 2005). The court, however, did not address ‘‘dual use’’ as it applies to the Commission’s authority to regulate wholesale sales. Also, when a ‘‘dual use’’ facility is involved in a wholesale sale, we do not claim jurisdiction over the facility itself, just the wholesale sale transaction occurring over that facility. See Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C. Cir. 2003) (explaining that the Commission has jurisdiction ‘‘over all wholesale service,’’ including wholesale transactions that occur over ‘‘local distribution’’ facilities). E:\FR\FM\30JNR1.SGM 30JNR1 37668 Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations to maintain the required power factor.43 On rehearing, in response to SoCal Edison’s argument that wind generators should not be exempt, the Commission in Order No. 2003–B explained that it was examining the issue as part of an ongoing proceeding on technical requirements applicable to wind. The Commission stated that until the other proceeding was resolved, it would continue the exemption for wind generators. Request for Rehearing 55. SoCal Edison again asks that the Commission not exempt wind generators from the power factor requirement citing reliability and safety consequences. It also asks that the Commission not await the resolution of the issue in the wind rulemaking and instead adopt an interim standard that removes the exemption. Commission Conclusion 56. We note that after SoCal Edison submitted its rehearing request, the Commission issued the Final Rule on Interconnection for Wind Energy and Other Alternative Technologies, which requires large wind plants to provide reactive power, if needed, under the same technical criteria applicable to conventional large generating facilities.44 Therefore, SoCal Edison’s request is moot. 7. ‘‘At or Beyond’’ Rule a. Request for Rehearing 57. Southern argues although Order No. 2003–B did not specifically refer to the ‘‘at or beyond’’ rule, it reaffirmed the primary holdings of Order Nos. 2003 and 2003–A, which did. It argues that in Order No. 2003–B, the Commission failed to note that its ‘‘at or beyond’’ rule had recently been vacated by the D.C. Circuit in Entergy Services, Inc. v. FERC, 391 F.3d 1240 (D.C. Cir. 2004). No. 2003–A at P 407 n.85. for Wind Energy, Order No. 661, 111 FERC ¶ 61,353 (2005). Accordingly, Southern concludes, the ‘‘at or beyond’’ rule in this proceeding is a legal nullity, and the Commission’s continued adherence to that policy in this proceeding is inappropriate. b. Commission Conclusion 58. We note that the court in Entergy Services did not question the Commission’s authority to apply an ‘‘at or beyond’’ rule; it simply sought an explanation that harmonized the ‘‘at or beyond’’ rule with Commission precedent. Moreover, the Commission has issued an order on remand explaining that facilities at the point of interconnection are network facilities.45 Therefore, Southern’s argument is moot. III. Ministerial Changes to the Pro Forma LGIP and LGIA 59. Since Order No. 2003–B was issued, we have identified certain sections of the LGIP and articles of the LGIA that require modification. Because of the ministerial nature of these changes, no further discussion is needed. The changes are included in Appendix A. IV. Compliance 60. This order takes effect 30 days after issuance by the Commission. As with the Order No. 2003 compliance process, the Commission will deem the OATT of each non-independent Transmission Provider to be amended to adopt the clarifications to the pro forma LGIP and LGIA contained in Appendix A herein on the effective date of this order. A non-independent Transmission Provider should submit revised tariff sheets incorporating the clarifications in Appendix A within 60 days after the issuance of this order. Within the same time frame, each RTO or ISO also must submit either revised tariff sheets incorporating the clarifications in Appendix A, or an explanation under the independent entity variation 43 Order 44 Interconnection VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 45 Nevada Power Co., 111 FERC ¶ 61,161 at P 16 (2005). PO 00000 Frm 00022 Fmt 4700 Sfmt 4700 standard as to why it does not propose to adopt each change. V. Document Availability 61. In addition to publishing the full text of this document in the Federal Register, 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 p.m. Eastern Time) at 888 First Street, NE., Room 2A, Washington, DC. 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. 62. 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. VI. Effective Date 63. Changes to Order Nos. 2003, 2003–A and 2003–B made in this order on rehearing will become effective 30 days after issuance by the Commission. List of Subjects 18 CFR Part 35 Electric power rates, Electric utilities, Reporting and recordkeeping requirements. By the Commission. Commissioner Brownell dissenting in part with a separate statement attached. Linda Mitry, Deputy Secretary. The Appendices will not be published in the Code of Federal Regulations. E:\FR\FM\30JNR1.SGM 30JNR1 Nora Mead BROWNELL, Commissioner dissenting in part: DEPARTMENT OF HOMELAND SECURITY For the reasons I articulated in my partial dissent to Order No. 2003–B, I would have granted rehearing and reinstated the original provision in Order No. 2003 that ensured Interconnection Customers full reimbursement of their up-front funding of Network Upgrades within five years. Therefore, I dissent from this portion of today’s order. Bureau of Customs and Border Protection Nora Mead Brownell [FR Doc. 05–12870 Filed 6–29–05; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF THE TREASURY 19 CFR Part 181 [CBP Dec. 05–24] RIN 1505–AB41 Tariff Treatment Related to Disassembly Operations Under the North American Free Trade Agreement Customs and Border Protection, Department of Homeland Security. ACTION: Final rule. AGENCY: VerDate jul<14>2003 15:12 Jun 29, 2005 Jkt 205001 PO 00000 Frm 00023 Fmt 4700 Sfmt 4700 37669 SUMMARY: This document adopts as a final rule, with some changes, proposed amendments to the Customs and Border Protection (‘‘CBP’’) Regulations concerning the North American Free Trade Agreement (‘‘the NAFTA’’). The regulatory changes interpret the term ‘‘production’’ to include disassembly and clarify that components recovered from the disassembly of used goods in a NAFTA country are entitled to NAFTA originating status when imported into the United States provided that the recovered components satisfy the applicable NAFTA rule of origin requirements. DATES: Effective August 1, 2005. FOR FURTHER INFORMATION CONTACT: Shari Suzuki, International Agreements Staff, Office of Regulations and Rulings, (202) 572–8818. E:\FR\FM\30JNR1.SGM 30JNR1 ER30JN05.000</GPH> Federal Register / Vol. 70, No. 125 / Thursday, June 30, 2005 / Rules and Regulations

Agencies

[Federal Register Volume 70, Number 125 (Thursday, June 30, 2005)]
[Rules and Regulations]
[Pages 37661-37669]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-12870]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM02-1-006; Order No. 2003-C]


Standardization of Generator Interconnection Agreements and 
Procedures

Issued June 16, 2005.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Order on rehearing.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) affirms, 
with certain clarifications, the fundamental determinations in Order 
No. 2003-B.

EFFECTIVE DATE: July 18, 2005.

FOR FURTHER INFORMATION CONTACT:

Patrick Rooney (Technical Information), Office of Markets, Tariffs and 
Rates, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-6205.
Roland Wentworth (Technical Information), Office of Markets, Tariffs 
and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8262.
Michael G. Henry (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8532.

SUPPLEMENTARY INFORMATION:
Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, 
Joseph T. Kelliher, and Suedeen G. Kelly.

I. Introduction and Summary

    1. In this order, we affirm, with certain clarifications, Order No. 
2003-B,\1\ which, together with Order Nos. 2003 and 2003-A, governs 
interconnection of large generators to the transmission grid. The pro 
forma Large Generator Interconnection Procedures (LGIP) and Large 
Generator Interconnection Agreement (LGIA) required in those orders 
help prevent undue discrimination, preserve the reliability of the 
nation's transmission system, and lower prices for customers by 
allowing a variety of generation resources to compete in wholesale 
electricity markets. At its core, the Commission's orders ensure that 
all Generating Facilities that will make sales for resale of electric 
energy in interstate commerce are offered Interconnection Service on 
comparable terms. These orders benefit customers by establishing the 
just and reasonable terms and conditions for interconnecting to the 
transmission grid, while ensuring that reliability is protected.
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    \1\ 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, Order No. 
2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160 
(2004) (Order No. 2003-A), order on reh'g, Order No. 2003-B, 70 FR 
265 (Jan. 4, 2005), FERC Stats. & Regs. ] 31,171 (2005) (Order No. 
2003-B). See also Notice Clarifying Compliance Procedures, 106 FERC 
] 61,009 (2004).
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    2. This order on rehearing reaffirms or clarifies the Commission's 
policies on the recovery of Network Upgrade costs and non-pricing 
policies. For example, it reaffirms the 20-year reimbursement policy 
for Network Upgrade costs and clarifies the Commission's policy 
regarding credits for Network Upgrades as it applies to Affected System 
Operators and jointly owned transmission facilities. The order also 
clarifies the Commission's jurisdiction under the Federal Power Act \2\ 
to apply this Final Rule and further explains the Transmission 
Provider's payment obligation for reactive power supplied by an 
Interconnection Customer.
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    \2\ 16 U.S.C. 791a-825r (2000).
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    3. This order takes effect 30 days after issuance by the 
Commission. As with the Order No. 2003 compliance process, the 
Commission will deem the open access transmission tariff (OATT) of each 
non-independent Transmission

[[Page 37662]]

Provider to be amended to adopt the clarifications to the pro forma 
LGIP and LGIA contained herein 30 days after issuance of this order by 
the Commission. And as with the Order No. 2003-B compliance process, 
each non-independent Transmission Provider will be required to amend 
its OATT to include the LGIP and LGIA clarifications contained herein 
within 60 days after issuance of this order by the Commission. Also, 
within 60 days after issuance of this order, each independent 
Transmission Provider must submit revised tariff sheets incorporating 
its clarifications to its OATT or an explanation under the independent 
entity variation standard as to why it is not proposing to adopt each 
clarification described in this order.
    4. The Commission received 12 timely requests for rehearing or for 
clarification of Order No. 2003-B.\3\ Under section 313(a) of the 
Federal Power Act (FPA),\4\ requests for rehearing of a Commission 
order were due within thirty days after issuance of Order No. 2003-A, 
i.e., no later than January 19, 2005. The Commission also received one 
answer from the North Carolina Electric Membership Corp. (NCEMC), which 
the Commission treats as yet another request for rehearing. Because 
this answer was submitted after the statutory 30-day rehearing 
deadline, it is rejected. However, the Commission will treat this late-
filed request for rehearing as a request for reconsideration.
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    \3\ Requests were filed by Calpine Corporation (Calpine), Edison 
Electric Institute (EEI), Entergy Services, Inc. (Entergy), Georgia 
Transmission Corp. (Georgia Transmission), MEAG Power, National 
Rural Electric Cooperative Association (NRECA), Pacificorp, PSEG 
Companies (PSEG), Public Service Company of New Mexico (PNM), 
Reliant Resources, Inc. (Reliant), Southern California Edison 
Company (SoCal Edison), and Southern Company Services, Inc. 
(Southern Company).
    \4\ 16 U.S.C. 8251(a) (2000).
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    5. For a background discussion, please consult the prior orders in 
this proceeding.\5\
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    \5\ Order No. 2003 at P 5-17; Order No. 2003-B at P 5-11.
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II. Discussion

A. Pricing and Cost Recovery Provisions

1. Requirement for Full Reimbursement After 20 Years
    6. In Order No. 2003, the Commission continued to require the 
Transmission Provider and any Affected System Operator to reimburse the 
Interconnection Customer for its upfront payments for Network Upgrades 
by means of credits against the Interconnection Customer's transmission 
bills. We stated that the Interconnection Customer, Transmission 
Provider, and Affected System Operator were permitted to adopt any 
alternative payment schedule that is mutually agreeable as long as all 
such amounts are refunded, with interest, within five years of the 
Commercial Operation Date of the Generating Facility. In Order No. 
2003-A, we retained this general policy but removed the obligation to 
make a balloon payment for any unrefunded amounts after five years. In 
Order No. 2003-B, the Commission revised pro forma LGIA article 11.4.1 
to state that, other credit and refund provisions of Order No. 2003-A 
notwithstanding, full reimbursement by the Transmission Provider shall 
not extend beyond 20 years from the Commercial Operation Date; \6\ in 
other words, a balloon payment is required at 20 years.
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    \6\ Order No. 2003-B at P 34-41.
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a. Rehearing Requests

    7. Some petitioners argue that the Transmission Provider should not 
be required to reimburse the Interconnection Customer in full after 20 
years if the Interconnection Customer has not earned enough credits (by 
taking delivery service) to reimburse it for the Network Upgrades.\7\ 
For example, Entergy states that this requirement is unfair to native 
load customers, arbitrary, and inconsistent with the Commission's 
previous policies. Entergy argues that the mandatory repayment 
provision converts the Interconnection Customer's upfront payment for 
Network Upgrade costs that are directly caused by an Interconnection 
Request from an investment, where the Interconnection Customer is at 
risk, to a loan. Southern Company claims that the Commission's previous 
policy of not requiring a balloon payment and allowing transmission 
credits only as delivery service was taken from a particular generating 
facility, was arguably consistent with the Commission's policy of 
allowing Transmission Providers to charge the ``higher of'' incremental 
or embedded costs. However, Southern Company claims that, if a full 
refund is always required within 20 years, this policy would be 
violated.
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    \7\ Entergy, Southern Company and PacifiCorp.
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    8. Conversely, other petitioners argue that 20 years is too long to 
wait for full reimbursement of upfront payments.\8\ Reliant states that 
the Commission erred by failing to return to the balanced crediting 
approach in Order No. 2003, which required the Transmission Provider to 
refund the balance of the Interconnection Customer's upfront payment 
within five years. Reliant argues that the 20-year reimbursement 
requirement does not provide incentives for proper siting decisions, 
and actually raises costs for the very customers the Commission is 
seeking to protect. This is because the additional financing costs of a 
20-year refund period raise the cost of new generators who wish to 
enter the market. In Reliant's view, this creates a barrier to entry 
that harms competition, and thereby harms native load and other 
Transmission Customers.
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    \8\ See Reliant, Calpine and PSEG.
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b. Commission Conclusion

    9. In response to those petitioners that object to any requirement 
for full reimbursement on a date certain, as well as those that believe 
20 years is too long to wait for reimbursement, we note that we have 
responded at length to many of these arguments in our previous orders. 
We therefore simply reiterate here our conclusion in Order No. 2003-B 
that our crediting and refund policy, including the 20-year 
reimbursement requirement, provides a reasonable balance between the 
objectives of promoting competition and infrastructure development, 
protecting the interests of Interconnection Customers, and protecting 
native load and other Transmission Customers.\9\
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    \9\ We remind petitioners that we continue to view the 
Interconnection Customer's upfront payment for Network Upgrades as 
essentially a loan from the Interconnection Customer to the 
Transmission Provider or Affected System Operator. Although the 
appropriate length of the repayment period for such a loan is not a 
number that can be determined with great precision, we note that 20 
years reflects the approximate minimum life of facilities that 
typically constitute Network Upgrades that generally would be needed 
to accommodate an Interconnection Customer's generator 
interconnection. Also, the courts have recognized that the 
Commission sometimes must adopt a value within a range, as long as 
the chosen value is related to the problem being addressed. E.g., 
ExxonMobil Gas Marketing Co. v. FERC, 297 F.3d 1071, 1085 (D.C. Cir. 
2002) (``We are generally unwilling to review line-drawing performed 
by the Commission unless a petitioner can demonstrate that lines 
drawn * * * are patently unreasonable, having no relationship to the 
underlying regulatory problem.'' (quotes and citation omitted)); see 
also Prometheus Radio Project v. FCC, 373 F.3d 372, 410 (D.C. Cir. 
2004) (``Deference to the Commission's judgment is highest when 
assessing the rationality of the agency's line-drawing 
endeavors.''); Sinclair Broad. Group, Inc. v. FCC, 284 F.3d 148, 159 
(D.C. Cir. 2002) (granting deference to an agency's line-drawing 
efforts within its expertise).
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2. Reimbursement of Upfront Payment for Network Upgrades and Affected 
Systems

a. Rehearing Requests

    10. Several petitioners ask the Commission to clarify whether an 
Affected System Operator has an obligation to reimburse the 
Interconnection Customer by means of a

[[Page 37663]]

balloon payment 20 years after the Commercial Operation Date.\10\ For 
example, NRECA asks the Commission to clarify that if credits provided 
by an Affected System Operator have not fully reimbursed the 
Interconnection Customer's upfront payment within 20 years, the 
Affected System Operator is not required to make a balloon payment, but 
instead may continue to provide the Interconnection Customer with 
credits for transmission service on the Affected System until the 
Interconnection Customer's entire upfront payment has been reimbursed.
---------------------------------------------------------------------------

    \10\ See EEI, NRECA, PNM and NCEMC.
---------------------------------------------------------------------------

    11. On a related matter, NRECA also asks the Commission to clarify 
that, the Transmission Provider or Affected System Operator has no 
further obligation to reimburse the Interconnection Customer for its 
upfront payment if the Generating Facility ceases Commercial Operation 
before the Interconnection Customer has been completely reimbursed.
    12. Finally, NCEMC asks the Commission to clarify the 
Interconnection Customer's right to receive a refund of its upfront 
payment for Network Upgrades on an Affected System when the 
Interconnection Customer is also a Network Customer of the Affected 
System. NCEMC states that it intends to construct a generating facility 
and designate it as a network resource on the Transmission Provider's 
Transmission System, where NCEMC is a network customer. Although NCEMC 
is also a Network Customer of the Affected System, it says that the 
transmission service revenues that the Affected System receives from 
NCEMC do not vary according to what resources are designated as Network 
Resources on the Affected System, but rather with NCEMC's load. NCEMC 
argues that a rule that would tie credits from the Affected System to 
incremental charges associated with transmission service taken from the 
Affected System with respect to the Generating Facility is 
inappropriate for an Interconnection Customer that is also a Network 
Customer on the Affected System.

b. Commission Conclusion

    13. In response to NRECA, we clarify that both the Transmission 
Provider and an Affected System Operator need provide credits for 
transmission service only when the Interconnection Customer takes 
transmission service with the Large Generating Facility identified as 
the primary point of receipt of that service. We clarify that both the 
Transmission Provider and an Affected System Operator must provide the 
20-year lump sum reimbursement to refund any remaining balance, even if 
no transmission service was taken. Although Order No. 2003-B could be 
read to suggest that the Affected System need only provide 
reimbursement for transmission service taken,\11\ this was not our 
intent. Indeed, the revised language in article 11.4.1 in Order No. 
2003-B clearly subjects an Affected System Operator to the 20-year lump 
sum requirement.\12\ This is consistent with the Commission's policy of 
treating a non-independent Affected System Operator the same as a non-
independent Transmission Provider because both have the same incentive 
to frustrate the development of new, competitive generation.\13\
---------------------------------------------------------------------------

    \11\ Order No. 2003-B at P 41, 42.
    \12\ This obligation does not apply if the Affected System is a 
non-jurisdictional entity.
    \13\ See Order No. 2003-A at P 636; see also Order No. 2003 at P 
738.
---------------------------------------------------------------------------

    14. In response to NRECA's second point, we clarify that the 
Affected System Operator, like the Transmission Provider, must 
reimburse the Interconnection Customer for its upfront payment even if 
the Generating Facility ceases Commercial Operation before the 
Interconnection Customer is completely reimbursed as long as the 
Interconnection Agreement between the Interconnection Customer and the 
Transmission Provider remains in full force and effect.\14\
---------------------------------------------------------------------------

    \14\ See Order No. 2003-A at P 619.
---------------------------------------------------------------------------

    15. In response to NCEMC, we note that, because the circumstances 
that NCEMC describes are highly fact-specific, and we do not know all 
the relevant facts, they are not appropriately addressed in a 
rulemaking. Therefore, we will not attempt to answer NCEMC's request 
for clarification in this order on rehearing, and will address the 
issue if it arises in a specific proceeding.
3. Reimbursement Obligation of the Operator of a Jointly-Owned System
    16. In Order No. 2003-B, the Commission stated that, in the case of 
an Affected System that is jointly owned by public and non-public 
utilities, it is the responsibility of the Affected System Operator to 
provide the credits and to seek reimbursement for any amounts that it 
believes it is owed by the other owners.\15\ If a Transmission Provider 
provides transmission service on a Transmission System that is jointly 
owned, that Transmission Provider must follow a similar procedure.
---------------------------------------------------------------------------

    \15\ Order No. 2003-B at P 42.
---------------------------------------------------------------------------

a. Rehearing Requests

    17. Several petitioners ask the Commission to clarify the crediting 
and refund responsibilities of an operator of an Affected System that 
is jointly owned.\16\ For example, EEI asks the Commission to clarify 
that the public utility Transmission Provider's obligation to provide 
transmission credits is limited to the amount of upfront payments made 
for Network Upgrades owned by the Transmission Provider. EEI argues 
that the policy in Order No. 2003-B may work when the cost recovery for 
jointly owned facilities is provided for under a single tariff, but it 
presents problems when the various joint owners each provide 
transmission service independently under their own separate tariffs. In 
addition, Georgia Transmission Corporation asks the Commission to 
clarify that Order No. 2003-B does not require a non-jurisdictional 
owner of a jointly owned transmission system to reimburse the Affected 
System Operator or Transmission Provider. Georgia Transmission states 
that such clarification would be consistent with the Commission's 
statements in Order Nos. 2003 and 2003-A that ``if an Affected System 
is a non-public utility, Order No. 2003 does not require that it 
provide refunds to the Interconnection Customer to satisfy the 
reciprocity condition.''
---------------------------------------------------------------------------

    \16\ See EEI, Georgia Transmission, MEAG Power, PNM, SoCal 
Edison, and Southern Company.
---------------------------------------------------------------------------

b. Commission Conclusion

    18. The Commission clarifies that it is not requiring every 
operator of a jointly owned system, whether it is a Transmission 
Provider or an Affected System Operator, to reimburse the 
Interconnection Customer for upfront payments for Network Upgrades 
received by the non-public utility owners of the system. The discussion 
in P 42 of Order No. 2003-B applies only to a situation where the 
operator is a public utility and has tariff administration 
responsibilities on behalf of the other owners. We clarify that the 
operator's responsibility for flowing through credits and reimbursing 
the Interconnection Customer for its upfront payment does not extend 
beyond its normal duties as the tariff administrator. Each owner of a 
jointly-owned system has the financial responsibility under its own 
Commission-regulated tariff to provide transmission credits and final 
reimbursement to the Interconnection Customer for the upfront payments 
that the owner has received. This responsibility does not extend to a 
non-public utility transmission owner or operator, of course.\17\
---------------------------------------------------------------------------

    \17\ See, e.g., Order No. 2003 at P 843.

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

[[Page 37664]]

4. Credits for Transmission Service When the Generating Facility Is Not 
the Source
    19. In Order No. 2003-B, the Commission stated that, if the 
Interconnection Customer or other Transmission Customer is taking firm 
Point-to-Point Transmission Service under the OATT with the Generating 
Facility as the source of the power transmitted, the customer continues 
to have all of the rights given by the OATT to change temporarily 
Points of Receipt or Delivery, if capacity is available, and is 
entitled to continue to receive credits toward the cost of the 
transmission service while doing so.\18\
---------------------------------------------------------------------------

    \18\ Order No. 2003-B at P 38.
---------------------------------------------------------------------------

a. Rehearing Requests

    20. EEI asks the Commission to clarify that, while a Transmission 
Customer may temporarily change its point of receipt, it will not 
receive credits for transmission service that does not involve power 
generated from the Generating Facility. The Commission should also 
clarify what is meant by a ``temporary'' change to ensure that the 
Transmission Customer cannot use this provision to game the system and 
impose unwarranted costs on native load customers and other users of 
the system. In addition, PNM asks the Commission to clarify that sham 
designations of transactions through a non-operating Generating 
Facility are not a permitted means of obtaining transmission credits.
    21. Southern Company argues that, contrary to the claims of some 
commenters, denying credits for transmission service when the 
Generating Facility is not the source of the power transmitted does not 
restrict any rights that the Interconnection Customer has under Order 
No. 888. Southern Company states that before Order No. 2003-B, 
Interconnection Customers were free to change points of receipt and 
delivery subject only to the requirements of Order No. 888. It argues 
that nothing in Order No. 2003 or Order No. 2003-A restricts this 
right. Providing Interconnection Customers with credits for redirected 
service does nothing to increase their ability to change delivery and 
receipt points. Instead, Southern Company argues, providing credits for 
redirected service will circumvent the native load protections adopted 
in Order No. 2003-A.

b. Commission Conclusion

    22. The Commission is not persuaded to change the policy under 
which the Transmission Provider must provide transmission credits 
during periods when the Interconnection Customer is using, in 
accordance with the terms of its transmission service, a secondary 
receipt point rather than the Generating Facility. As long as the 
Interconnection Customer or another entity is taking transmission 
service that identifies the Generating Facility as the point of receipt 
for that service in the original firm point-to-point transmission 
service request, the Interconnection Customer is entitled to a credit 
toward the cost of that service. The possibility that this could lead 
to abuse is greatly overstated. A transmission customer that elects to 
use a secondary point of receipt or delivery under the OATT must take 
such service only on a non-firm basis and at the lowest priority level. 
The Commission does not believe that access to this non-firm service 
option is sufficient to lead to abuse. Furthermore, in response to PNM, 
the Commission clarifies that a sham designation of a transaction 
through a non-operating Generating Facility is not a permitted means of 
obtaining transmission credits.
    23. The Commission clarifies that its use of the word 
``temporarily'' is intended to distinguish a request to use secondary 
receipt point on a non-firm basis as permitted under the tariff from a 
request to change the point of receipt on a firm basis.
5. Implementing the ``Higher Of'' Policy
    24. In Order No. 2003-B, we stated that our interconnection pricing 
policy continues to allow the Transmission Provider to charge the 
Interconnection Customer a transmission rate that is the higher of the 
incremental cost rate for Network Upgrades required to interconnect the 
Generating Facility and an embedded cost rate for the entire 
Transmission System (including the cost of the Network Upgrades). We 
further stated that, if a Transmission Provider (or any other 
interested party) believes that, for an actual interconnection, it 
faces circumstances where native load and other customers are not held 
harmless, it should make that demonstration in an actual transmission 
rate filing.\19\
---------------------------------------------------------------------------

    \19\ Order No. 2003-B at P 54-57.
---------------------------------------------------------------------------

a. Rehearing Requests

    25. With reference to the Commission's second statement cited 
above, Southern Company claims that the Administrative Procedure Act 
requires that agency action be supported by substantial evidence \20\ 
and that the Commission's attempt to ``pass the buck'' by requiring a 
Transmission Provider to demonstrate the negative does not meet that 
standard.
---------------------------------------------------------------------------

    \20\ 5 U.S.C. 706(2)(E) (2000).
---------------------------------------------------------------------------

    26. In response to our statement that we are willing to look on a 
case-by-case basis at proposals to protect native load and other 
existing customers, PacifiCorp argues that administrative efficiency 
favors a generic rule that addresses the need to fully protect native 
load. In PacifiCorp's view, it would be costly, burdensome, and 
inefficient to require a Transmission Provider to file a request to 
protect its native load every time a merchant generator signs an 
interconnection agreement without having executed a service agreement 
for transmission delivery service of sufficient duration to cover the 
cost of Network Upgrades.

b. Commission Conclusion

    27. The Commission reiterates that the appropriate ratemaking 
approach to ensure that native load and other customers are held 
harmless depends on the particular set of facts that result in native 
load and other customers allegedly not being held harmless. For 
example, it may depend on the particular circumstances of the 
Interconnection Customer, its Generating Facility and location, and 
transmission interconnection service that is requested (Energy Resource 
Interconnection Service or Network Resource Interconnection Service), 
the tariff status of the power buyer (point-to-point or Network 
Integration Transmission Service), and the relationship if any of the 
Interconnection Customer to the transmission tariff service customer. 
This is a ratemaking question that does not lend itself to a generic 
solution. Furthermore, supporting an agency action by substantial 
evidence requires facts in some cases, so that case-specific, fact-
based determinations are sometimes necessary instead of generic 
theoretical solutions.

B. Other Issues

1. Scoping Meeting
    28. In Order No. 2003-B, the Commission rejected Southern's 
argument that the LGIP section 3.4 requirement to keep the identity of 
the Interconnection Customer confidential conflicts with the 
Transmission Provider's obligation in LGIP section 3.3.4 to reveal in a 
notice any meeting the Transmission Provider conducts with an 
affiliated Interconnection Customer. The Commission explained that the 
requirement to disclose Affiliate meetings resulted from the 
Commission's attempt to balance the need to treat affiliated and 
nonaffiliated

[[Page 37665]]

Interconnection Customers alike with the need to make Order No. 2003 
conform to the established Code of Conduct and Standards of Conduct 
requirements.\21\
---------------------------------------------------------------------------

    \21\ Order No. 2003-B at P 137.
---------------------------------------------------------------------------

a. Request for Rehearing

    29. On rehearing, Southern again argues that Order No. 2003-B 
discriminates against affiliates of a Transmission Provider because 
requiring disclosure of their identities and confidential information 
will benefit competitors. Southern argues that while the Commission 
attempts to justify this disparate treatment by claiming that 
affiliated and non-affiliated generators are not similarly situated, 
they are similarly situated in that for both of them, revealing the 
identity of the Interconnection Customer would put that customer ``at a 
competitive disadvantage and its project at risk.'' \22\ Southern then 
cites Federal court precedent saying that the Commission cannot treat 
similarly situated customers in a non-comparable manner.\23\
---------------------------------------------------------------------------

    \22\ See Order No. 2003 at P 114.
    \23\ Town of Norwood v. FERC, 202 F.3d 392, 402 (1st Cir. 2000).
---------------------------------------------------------------------------

b. Commission Conclusion

    30. Contrary to Southern's argument, the Commission concludes that 
the disparate treatment here is justified because of concerns about 
affiliate abuse. As explained in Order Nos. 2003-A and 2003-B,\24\ this 
measure allows Transmission Providers and their affiliates to share 
confidential information, but with safeguards that provide the public 
with notice of any meetings with affiliated Interconnection Customers 
and the opportunity to review a transcript. The affiliate relationship 
is a factual difference that justifies the different treatment 
here.\25\ Additional safeguards are needed to ensure against affiliate 
abuse.\26\ The Commission reaffirms its conclusion that revealing the 
affiliate relationship between the Interconnection Customer and 
Transmission Provider results in less harm than if there were no 
safeguards at all.
---------------------------------------------------------------------------

    \24\ See Order No. 2003 A at P 107; Order No. 2003-B at P 136.
    \25\ See Public Service Co. of Indiana v. FERC, 575 F.2d 1204, 
1212 (7th Cir. 1978); Cities of Bethany v. FERC, 727 F.2d 1131, 1140 
(D.C. Cir. 1984).
    \26\ See, e.g., Entergy Services, Inc., 111 FERC ] 61,145 at P 
10 (2005) (initiating hearing to examine the ``credible concerns'' 
regarding transmission market power, by failing to provide 
interconnections or blocking alternative generation sources); 
Southern Companies Energy marketing, Inc, 111 FERC ] 61,144 at P 16 
(initiating hearing to examine the ``credible concerns'' regarding 
unduly preferential treatment afforded affiliates in access 
generation sites) (2005); see also Entergy Services, Inc., 103 FERC 
] 61,256 at P 44-53 (initiating a hearing to examine concerns 
regarding affiliate dealing in a bidding process for power purchase 
agreements).
---------------------------------------------------------------------------

2. Generator Balancing
    31. In Order No. 2003-B, the Commission reaffirmed the decision in 
Order No. 2003-A to eliminate from the pro forma LGIA a provision 
requiring the Interconnection Customer to make generator balancing 
service arrangements (before submitting a schedule for delivery 
service) that identify the Interconnection Customer's Generating 
Facility as the Point of Receipt for the scheduled delivery. Order No. 
2003-B at P 74-75. We removed the requirement because generator 
balancing is an ancillary service that is part of delivery service, not 
interconnection service. Recognizing that some Transmission Providers 
may prefer to include a balancing provision in an interconnection 
agreement rather than in a separate agreement, the Commission explained 
that the Transmission Provider may do so in individual interconnection 
agreements tailored to the Parties' specific circumstances and subject 
to Commission approval.

a. Request for Rehearing

    32. Southern seeks clarification that nothing in Order No. 2003-B 
precludes Southern's approach in its in Docket No. ER04-1161-000, which 
is to include a provision in its LGIA that refers to the requirement 
that a generator enter into an operating agreement that outlines 
options for remedying imbalances, but does not prescribe specific 
generator balancing service or rates.

b. Commission Conclusion

    33. The Commission has issued an order in Docket No. ER04-1161-000 
that addressed Southern's request for clarification and rejected 
Southern's proposal to include in the LGIA a reference to a balancing 
service agreement.\27\ There the Commission stated that a Transmission 
Provider may either adopt a stand-alone generator balancing service 
agreement or request the inclusion of a generator balancing service 
provision tailored to the Parties' specific standards and circumstances 
in an individual interconnection agreement. The Commission does not 
include a standardized balancing provision in the LGIA, even one as 
limited in scope as Southern proposes, because as explained in Order 
No. 2003-A balancing service is more closely related to transmission 
delivery service than interconnection service. For the same reasons, we 
follow that decision here.
---------------------------------------------------------------------------

    \27\ Southern Company Services, Inc., 111 FERC ] 61,004 at P 16 
(2005), reh'g on other grounds pending.
---------------------------------------------------------------------------

3. Reactive Power Payments to Generator
    34. Order No. 2003-B reaffirmed Order No. 2003-A's modification to 
LGIA article 9.6.3 to require the Transmission Provider to pay the 
Interconnection Customer for reactive power the Interconnection 
Customer provides or absorbs only when the Transmission Provider asks 
the Interconnection Customer to operate its Generating Facility outside 
a specified power factor range (or dead band). However, if the 
Transmission Provider pays its own or affiliated generators for 
reactive power service within the specified range, it must also pay the 
Interconnection Customer for providing reactive power within the 
specified range.\28\ The Commission stated that although ``the 
Transmission Provider is not `paying' its own or affiliated generators 
directly for providing reactive power within the specified range, the 
owner of the generator is nonetheless being compensated for that 
service when the Transmission Provider includes reactive power related 
costs in its transmission revenue requirement.'' \29\
---------------------------------------------------------------------------

    \28\ Order No. 2003-A at P 416; Order No. 2003-B at P 114.
    \29\ Order No. 2003-B at P 119.
---------------------------------------------------------------------------

a. Requests for Rehearing

    35. Southern and PNM take issue with the Commission's statement in 
Order No. 2003-B that when a Transmission Provider is required to 
provide Reactive Power under Schedule 2 of its OATT, and charges for 
that service, it is thereby paying its own generators for reactive 
power within the established range, thus triggering a responsibility to 
pay the Interconnection Customer in the same manner.
    36. Southern argues that this is incorrect because Schedule 2 only 
allows the Transmission Provider to be paid for reactive power from 
``generation sources.'' The revenue requirements associated with such 
generation are not recovered in a transmission revenue requirement 
(hence the need for a Schedule 2 charge separate from the OATT 
transmission delivery charges). Furthermore, even if this statement is 
clarified to be a reference to a Transmission Provider receiving 
compensation for its generator-supplied reactive power costs

[[Page 37666]]

in its Schedule 2 charge, Southern continues, that would be incorrect 
as well. It would be wrong because, at least in the case of the 
Southern Companies, the dollars received for Schedule 2 service do not 
go to the generators or to the Transmission Provider, but instead are 
treated as revenue credits to reduce the costs that retail customers 
would otherwise have to pay. As a result, the beneficiaries of Schedule 
2 revenues are retail customers, not the Transmission Provider or its 
generators. Paying Interconnection Customers for providing this service 
would give them an unfair advantage over Transmission Providers in the 
form of additional revenue.
    37. PNM agrees that if a Transmission Provider must pay 
Interconnection Customers for reactive power within the deadband, it 
will need to recover that cost as part of its Schedule 2 revenue 
requirement. The result will be an unwarranted windfall to 
Interconnection Customers, higher costs for Transmission Customers, and 
increased filing burdens for public utility Transmission Providers.
    38. PNM and Southern also argue that a service obligation 
distinguishes the Transmission Provider from the Interconnection 
Customer. They note that a Transmission Provider must plan, construct, 
and operate its generation at all times to meet the system's localized 
power and voltage requirements. Unlike the Transmission Provider, an 
Interconnection Customer constructs its generation in the location best 
meeting its own needs. Southern argues that an Interconnection 
Customer's generator is simply not ``comparable'' to a Transmission 
Provider's generator for purposes of supplying reactive power.
    39. Southern notes that Order Nos. 888-A and 888-B explained that a 
generator must have to be available and under the Transmission 
Provider's control (so that it reduces the Transmission Provider's 
reactive power investment requirements) in order to be entitled to 
compensation. Since the Interconnection Customer's generators are not 
under the Transmission Provider's control, the Transmission Provider 
cannot rely on those generators to reduce its investment in reactive 
power facilities necessary to satisfy its system's needs (as it can for 
its own generators).
    40. Alternatively, PNM requests that the Commission clarify 
procedures by which Transmission Providers can pass through as part of 
their Schedule 2 revenue requirement any amounts that they are required 
to pay Interconnection Customers for reactive power within the 
specified power range.
    41. PNM also requests that the Commission explain what it means 
when it states that nothing in LGIA Article 9.6.3 ``disturbs any 
present arrangements for reactive power compensation.'' Order No. 2003-
B at P 121. PNM supports applying the policy to new interconnection 
agreements and grandfathering existing agreements.

 b. Commission Conclusion

    42. We disagree with Southern's and PNM's argument that the 
Commission should base its decision on what the Transmission Provider 
does with the revenues from providing reactive power within the 
established range. The Commission is less concerned with the flow of 
these revenues than with the unduly discriminatory treatment of non-
affiliated Interconnection Customers that provide this important system 
service. We therefore reiterate that if the Transmission Provider's 
affiliate receives a payment for providing this service within the 
specified range, then payments must be made to non-affiliated 
Interconnection Customers for providing the service. Because the non-
affiliates are providing an important service, we disagree with PNM 
that such payments would result in a windfall to them.
    43. Although the Transmission Provider's or its affiliate's 
generators may be required to operate when others are not, this 
distinction in availability is not so significant as to eliminate the 
need to compensate other generators. With respect to Southern's 
assertion that the Interconnection Customer's generators are not under 
the Transmission Provider's control, Order No. 2003-B clarified \30\ 
that while the Transmission Provider cannot demand that the 
Interconnection Customer operate its Generating Facility solely to 
provide reactive power, it may require the Interconnection Customer to 
provide reactive power from time to time when its Generating facility 
is in operation. The requirement to pay exists only as long as the 
Generating Facility follows the Transmission Provider's reactive power 
instructions. This is a sufficient level of control to warrant 
compensation for providing reactive power as described in Order Nos. 
888-A and 888-B.
---------------------------------------------------------------------------

    \30\ Order No. 2003-B at P 118.
---------------------------------------------------------------------------

    44. In response to PNM's requests for clarification, although we do 
not agree that selecting the best sources of reactive power from 
available generators should necessarily increase reactive power costs--
indeed, it may lower such costs--a Transmission Provider may propose to 
incorporate in its rates any such increase in Schedule 2 amounts. At 
that time the Commission will consider alternatives for recovery of 
these charges.\31\
---------------------------------------------------------------------------

    \31\ Commission staff has begun a general inquiry into reactive 
power pricing reform; see Principles for Efficient and Reliable 
Reactive Power Supply and Consumption, Docket No. AD05-1-000 
(February 4, 2005) and the discussion at the Commission meeting on 
December 15, 2004.
---------------------------------------------------------------------------

    45. Finally, Order No. 2003 does not abrogate existing 
agreements,\32\ and we reiterate that existing agreements for reactive 
power compensation need not be amended to incorporate our policy on 
reactive power payments for newly interconnecting generators.
---------------------------------------------------------------------------

    \32\ See Order No. 2003 at P 911.
---------------------------------------------------------------------------

4. Interest Rate Applied to Non-jurisdictional Entities
    46. LGIA Article 11.4.1 requires that the repayment for Network 
Upgrades shall include interest calculated in accordance with the 
Commission's regulations. Order No. 2003-B clarified that the interest 
rate is in 18 CFR Sec.  35.19a(a)(2)(iii).

a. Request for Rehearing

    47. NRECA argues that that interest rate is not appropriate for 
non-jurisdictional utilities that are ``subject to'' the 
Interconnection Rule due to the Commission's reciprocity condition. The 
Commission's interest rate bears no relationship to a non-
jurisdictional utility's cost of borrowing, NRECA explains, and it 
provides a windfall to the Interconnection Customer at the expense of a 
non-jurisdictional utility's consumers.

b. Commission Conclusion

    48. We clarify that a non-jurisdictional entity subject to the 
reciprocity condition need not adhere to the crediting policy for 
Transmission Providers in Order No. 2003, including the payment of 
interest,\33\ unless it applies this same crediting policy to its own 
generation. Order No. 2003-A clarified that for rate matters, the 
reciprocity condition only requires comparability.\34\ Therefore, 
interest (at the Commission's or some other interest rate) would be 
payable only if it is payable (at the same interest rate) to the non-
jurisdictional entity's own or affiliated generators, if any.
---------------------------------------------------------------------------

    \33\ In its request for rehearing, NRECA refers to an interest 
rate that the Commission corrected in Order No. 2003-B.
    \34\ Order No. 2003-A at 777.
---------------------------------------------------------------------------

5. Jurisdiction
    49. Order No. 2003-B corrected a misstatement in Order No. 2003-A 
and reiterated that if an Interconnection Customer seeks to 
interconnect with a

[[Page 37667]]

dual use facility (i.e., a facility that is used for both wholesale and 
retail sales) to make a wholesale sale, then Order No. 2003 applies 
because that facility is subject to an OATT.\35\
---------------------------------------------------------------------------

    \35\ Order No. 2003-B at P14.
---------------------------------------------------------------------------

Request for Rehearing

    50. SoCal Edison argues that the Commission must exercise 
jurisdiction over all wholesale generator interconnections, including 
those to ``local distribution'' facilities never previously used by 
wholesale customers. SoCal Edison says that the Commission incorrectly 
asserts that there are three categories of facilities (transmission, 
``local distribution,'' and dual use) when only two actually exist 
(transmission and ``local distribution''). SoCal Edison says that a 
D.C. Circuit opinion finds that only two categories exist, and 
wholesale service over ``local distribution'' facilities is Commission-
jurisdictional.\36\ SoCal Edison concludes that because all 
interconnections to distribution facilities are to ``local 
distribution'' facilities, all such interconnections should be treated 
the same for jurisdictional purposes, and jurisdiction should depend 
solely on whether the generator makes sales at wholesale. SoCal Edison 
therefore requests that the Commission rule that it has jurisdiction 
over all interconnections to ``local distribution'' facilities for the 
purpose of making wholesale sales.
---------------------------------------------------------------------------

    \36\ SoCal Edison cites Detroit Edison Co. v. FERC, 334 F.3d 48, 
51 (D.C. Cir. 2003) (``[W]hen a local distribution facility is used 
in a wholesale transaction, FERC has jurisdiction over that 
transaction pursuant to its wholesale jurisdiction under FPA Sec.  
201(b)(1).'') and DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 
2005) (applying a two category analysis).
---------------------------------------------------------------------------

Commission Conclusion

    51. We disagree with SoCal Edison that we should assert 
jurisdiction over all interconnections that could be used for wholesale 
sales, including the situation in which the Interconnection Customer 
seeks to interconnect to a ``local distribution'' facility being used 
exclusively for retail sales and thus is not available for service 
under an OATT at the time the Interconnection Request is made. In Order 
No. 2003, the Commission explained that the rule applies to 
interconnections to the facilities of a public utility's Transmission 
System that, at the time the interconnection is requested, may be used 
either to transmit electric energy in interstate commerce or to sell 
electric energy at wholesale in interstate commerce pursuant to a 
Commission filed OATT.\37\ Thus, our assertion of jurisdiction over 
interconnections rested on two grounds: first, and primarily, our FPA 
jurisdiction over ``transmission'' facilities, which may be used for 
wholesale sales or unbundled retail sales and which are subject to an 
OATT; and, second, our FPA jurisdiction over wholesale sales which 
require the use of ``local distribution'' facilities and thus such 
facilities become subject to an OATT for purposes of the wholesale 
sales. We concluded that applying our interconnection rules to 
facilities already subject to an OATT would properly respect the 
jurisdictional bounds recognized by the courts in upholding Order No. 
888 and subsequent cases.\38\ To adopt SoCal Edison's position and 
interpret our authority more broadly, however, would allow a potential 
wholesale seller to cause the involuntary conversion of a facility 
previously used exclusively for state-jurisdictional interconnections 
and delivery, and subject to the exclusive jurisdiction of the state, 
into a facility also subject to the Commission's interconnection 
jurisdiction--a result that we believe crosses the jurisdictional line 
established by Congress in the FPA.
---------------------------------------------------------------------------

    \37\ Order No. 2003 at P 804. Pursuant to Order No. 888, as 
upheld by the courts, facilities subject to an OATT are 
``transmission'' facilities and facilities used for wholesale sales, 
whether labeled ``transmission,'' ``distribution,'' or ``local 
distribution.'' 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 at 31,969, 31,980 (1996), order on reh'g, Order No. 
888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048 
(1997), order on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), 
order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in 
relevant part sub nom. Transmission Access Policy Study Group v. 
FERC, 225 F.3d 667 (D.C. Cir. 2000) (TAPS v. FERC), aff'd sub nom. 
New York v. FERC, 535 U.S. 1 (2002); see TAPS v. FERC, 225 F.3d at 
696 (noting that the Commission's ``assertion of jurisdiction over 
all wholesale transmissions, regardless of the nature of the 
facility, is clearly within the scope of its statutory authority'').
    \38\ See Detroit Edison Co. v. FERC, 334 F.3d 48 (D.C. Cir. 
2003); DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 2005).
---------------------------------------------------------------------------

    52. FPA section 201(b)(1) gives the Commission the authority to 
regulate ``all facilities'' used for transmission and for the wholesale 
sale of electric energy in interstate commerce.\39\ The same FPA 
section denies the Commission jurisdiction ``over facilities used in 
local distribution'' except as specifically provided in Parts II and 
III of the FPA.\40\ The Court of Appeals for the D.C. Circuit recently 
explained this provision as meaning that, if a wholesale sale of 
electric energy in interstate commerce is occurring, the Commission has 
jurisdiction over the transaction or service, even if the transaction 
occurs over a ``local distribution'' facility.\41\
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    \39\ 16 U.S.C. 824a(b)(1) (2000).
    \40\ Id.
    \41\ Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C. Cir. 
2003); accord Transmission Access Policy Study Group v. FERC, 225 
F.3d 667, 696 (D.C. Cir. 2000) (TAPS) (noting that ``FERC's 
assertion of jurisdiction over all wholesale transmissions, 
regardless of the nature of the facility, is clearly within the 
scope of its statutory authority,'' and that the statute and case 
law support the proposition that the Commission has the authority to 
regulate ``all aspects'' of wholesale transactions).
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    53. When a ``local distribution'' facility is used to transmit 
energy sold at wholesale as well as energy sold at retail, we 
previously have called this a ``dual use'' facility because it is used 
both for sales subject to Commission jurisdiction and for sales subject 
to state jurisdiction.\42\ Under Order No. 2003, if such a facility is 
subject to wholesale open access under an OATT at the time the 
Interconnection Request is made, and the interconnection will connect a 
generator to a facility that would be used to facilitate a wholesale 
sale, Order No. 2003 applies and the interconnection must be subject to 
Commission-approved terms and conditions. Because the Commission's 
authority to regulate in this circumstance is limited to the wholesale 
transaction, we conclude that we do not have the authority to directly 
regulate the facility that is used to transmit the energy being sold at 
wholesale. In other words, while the Commission may regulate the entire 
transmission component (rates, terms and conditions) of the wholesale 
transaction--whether the facilities used to transmit are labeled 
``transmission'' or ``local distribution''--it may not regulate the 
``local distribution'' facility itself, which remains state-
jurisdictional. We believe this properly respects the boundaries drawn 
in the FPA.
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    \42\ We note that the DTE court rejected DTE's attempt to use 
the dual use facility or dual function rationale. DTE Energy Co. v. 
FERC, 394 F.3d 954, 962-63 (D.C. Cir. 2005). The court, however, did 
not address ``dual use'' as it applies to the Commission's authority 
to regulate wholesale sales. Also, when a ``dual use'' facility is 
involved in a wholesale sale, we do not claim jurisdiction over the 
facility itself, just the wholesale sale transaction occurring over 
that facility. See Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C. 
Cir. 2003) (explaining that the Commission has jurisdiction ``over 
all wholesale service,'' including wholesale transactions that occur 
over ``local distribution'' facilities).
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6. Wind Power Exemption
    54. Order No. 2003-A exempted wind generators from the power factor 
design criteria requirement in article 9.6.1, because as nonsynchronous 
generators, it would be difficult for these generators

[[Page 37668]]

to maintain the required power factor.\43\ On rehearing, in response to 
SoCal Edison's argument that wind generators should not be exempt, the 
Commission in Order No. 2003-B explained that it was examining the 
issue as part of an ongoing proceeding on technical requirements 
applicable to wind. The Commission stated that until the other 
proceeding was resolved, it would continue the exemption for wind 
generators.
---------------------------------------------------------------------------

    \43\ Order No. 2003-A at P 407 n.85.
---------------------------------------------------------------------------

Request for Rehearing

    55. SoCal Edison again asks that the Commission not exempt wind 
generators from the power factor requirement citing reliability and 
safety consequences. It also asks that the Commission not await the 
resolution of the issue in the wind rulemaking and instead adopt an 
interim standard that removes the exemption.

Commission Conclusion

    56. We note that after SoCal Edison submitted its rehearing 
request, the Commission issued the Final Rule on Interconnection for 
Wind Energy and Other Alternative Technologies, which requires large 
wind plants to provide reactive power, if needed, under the same 
technical criteria applicable to conventional large generating 
facilities.\44\ Therefore, SoCal Edison's request is moot.
---------------------------------------------------------------------------

    \44\ Interconnection for Wind Energy, Order No. 661, 111 FERC ] 
61,353 (2005).
---------------------------------------------------------------------------

7. ``At or Beyond'' Rule

a. Request for Rehearing

    57. Southern argues although Order No. 2003-B did not specifically 
refer to the ``at or beyond'' rule, it reaffirmed the primary holdings 
of Order Nos. 2003 and 2003-A, which did. It argues that in Order No. 
2003-B, the Commission failed to note that its ``at or beyond'' rule 
had recently been vacated by the D.C. Circuit in Entergy Services, Inc. 
v. FERC, 391 F.3d 1240 (D.C. Cir. 2004). Accordingly, Southern 
concludes, the ``at or beyond'' rule in this proceeding is a legal 
nullity, and the Commission's continued adherence to that policy in 
this proceeding is inappropriate.

b. Commission Conclusion

    58. We note that the court in Entergy Services did not question the 
Commission's authority to apply an ``at or beyond'' rule; it simply 
sought an explanation that harmonized the ``at or beyond'' rule with 
Commission precedent. Moreover, the Commission has issued an order on 
remand explaining that facilities at the point of interconnection are 
network facilities.\45\ Therefore, Southern's argument is moot.
---------------------------------------------------------------------------

    \45\ Nevada Power Co., 111 FERC ] 61,161 at P 16 (2005).
---------------------------------------------------------------------------

III. Ministerial Changes to the Pro Forma LGIP and LGIA

    59. Since Order No. 2003-B was issued, we have identified certain 
sections of the LGIP and articles of the LGIA that require 
modification. Because of the ministerial nature of these changes, no 
further discussion is needed. The changes are included in Appendix A.

IV. Compliance

    60. This order takes effect 30 days after issuance by the 
Commission. As with the Order No. 2003 compliance process, the 
Commission will deem the OATT of each non-independent Transmission 
Provider to be amended to adopt the clarifications to the pro forma 
LGIP and LGIA contained in Appendix A herein on the effective date of 
this order. A non-independent Transmission Provider should submit 
revised tariff sheets incorporating the clarifications in Appendix A 
within 60 days after the issuance of this order. Within the same time 
frame, each RTO or ISO also must submit either revised tariff sheets 
incorporating the clarifications in Appendix A, or an explanation under 
the independent entity variation standard as to why it does not propose 
to adopt each change.

V. Document Availability

    61. In addition to publishing the full text of this document in the 
Federal Register, 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 p.m. Eastern Time) at 888 
First Street, NE., Room 2A, Washington, DC. 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.
    62. 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.

VI. Effective Date

    63. Changes to Order Nos. 2003, 2003-A and 2003-B made in this 
order on rehearing will become effective 30 days after issuance by the 
Commission.

List of Subjects 18 CFR Part 35

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


    By the Commission. Commissioner Brownell dissenting in part with 
a separate statement attached.
Linda Mitry,
Deputy Secretary.
    The Appendices will not be published in the Code of Federal 
Regulations.


[[Page 37669]]


[GRAPHIC] [TIFF OMITTED] TR30JN05.000

Nora Mead BROWNELL, Commissioner dissenting in part:

    For the reasons I articulated in my partial dissent to Order No. 
2003-B, I would have granted rehearing and reinstated the original 
provision in Order No. 2003 that ensured Interconnection Customers full 
reimbursement of their up-front funding of Network Upgrades within five 
years. Therefore, I dissent from this portion of today's order.

Nora Mead Brownell
[FR Doc. 05-12870 Filed 6-29-05; 8:45 am]
BILLING CODE 6717-01-P