Skip to Content


Standardization of Generator Interconnection Agreements and Procedures

Document Details

Information about this document as published in the Federal Register.

Published Document

This document has been published in the Federal Register. Use the PDF linked in the document sidebar for the official electronic format.

Start Preamble Issued June 16, 2005.


Federal Energy Regulatory Commission, DOE.


Order on rehearing.


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


July 18, 2005.

Start Further Info


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.

End Further Info End Preamble Start Supplemental 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 Start Printed Page 37662Provider 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.

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, 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 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 Start Printed Page 37663balloon 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 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 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.

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.”

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]

Start Printed 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]

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 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 (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 Start Printed Page 37665Interconnection Customers alike with the need to make Order No. 2003 conform to the established Code of Conduct and Standards of Conduct requirements.[21]

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]

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.

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.

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]

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 Start Printed Page 37666in 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.

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]

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 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 § 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.

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 Start Printed Page 37667dual 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 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.

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.

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]

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 Start Printed Page 37668to 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). 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 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 ( 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

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.

Start List of Subjects

List of Subjects 18 CFR Part 35

  • Electric power rates
  • Electric utilities
  • Reporting and recordkeeping requirements
End List of Subjects Start Signature

By the Commission. Commissioner Brownell dissenting in part with a separate statement attached.

Linda Mitry,

Deputy Secretary.

End Signature

The Appendices will not be published in the Code of Federal Regulations.

Start Printed Page 37669

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

End Supplemental Information


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).

Back to Citation

2.  16 U.S.C. 791a-825r (2000).

Back to Citation

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).

Back to Citation

5.  Order No. 2003 at P 5-17; Order No. 2003-B at P 5-11.

Back to Citation

6.  Order No. 2003-B at P 34-41.

Back to Citation

7.  Entergy, Southern Company and PacifiCorp.

Back to Citation

8.  See Reliant, Calpine and PSEG.

Back to Citation

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).

Back to Citation

10.  See EEI, NRECA, PNM and NCEMC.

Back to Citation

11.  Order No. 2003-B at P 41, 42.

Back to Citation

12.  This obligation does not apply if the Affected System is a non-jurisdictional entity.

Back to Citation

13.  See Order No. 2003-A at P 636; see also Order No. 2003 at P 738.

Back to Citation

14.  See Order No. 2003-A at P 619.

Back to Citation

15.  Order No. 2003-B at P 42.

Back to Citation

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

Back to Citation

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

Back to Citation

18.  Order No. 2003-B at P 38.

Back to Citation

19.  Order No. 2003-B at P 54-57.

Back to Citation

20.  5 U.S.C. 706(2)(E) (2000).

Back to Citation

21.  Order No. 2003-B at P 137.

Back to Citation

22.  See Order No. 2003 at P 114.

Back to Citation

23.  Town of Norwood v. FERC, 202 F.3d 392, 402 (1st Cir. 2000).

Back to Citation

24.  See Order No. 2003 A at P 107; Order No. 2003-B at P 136.

Back to Citation

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).

Back to Citation

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).

Back to Citation

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

Back to Citation

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

Back to Citation

29.  Order No. 2003-B at P 119.

Back to Citation

30.  Order No. 2003-B at P 118.

Back to Citation

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.

Back to Citation

32.  See Order No. 2003 at P 911.

Back to Citation

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

Back to Citation

34.  Order No. 2003-A at 777.

Back to Citation

35.  Order No. 2003-B at P14.

Back to Citation

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 § 201(b)(1).”) and DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 2005) (applying a two category analysis).

Back to Citation

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”).

Back to Citation

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).

Back to Citation

39.  16 U.S.C. 824a(b)(1) (2000).

Back to Citation

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).

Back to Citation

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).

Back to Citation

43.  Order No. 2003-A at P 407 n.85.

Back to Citation

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

Back to Citation

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

Back to Citation

[FR Doc. 05-12870 Filed 6-29-05; 8:45 am]