05-15. Standardization of Generator Interconnection Agreements and Procedures

December 20, 2004.

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Order on rehearing and directing compliance.

SUMMARY:

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

Effective Date:

January 19, 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, [phone];

Roland Wentworth (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone];

P. Kumar Agarwal (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone];

Michael G. Henry (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction and Summary

II. Background

III. Discussion

A. Jurisdiction

B. Pricing and Cost Recovery Provisions

1. Transmission Credits

2. Credits Under Change in Ownership

3. Protecting Native Load and Other Existing Transmission Customers

4. Interconnection Products and Services

5. Generator Balancing Service Arrangements

C. Independent Transmission Provider Obligations

D. Issues Related to the Large Generator Interconnection Agreement

1. Stand Alone Network Upgrades

2. Permits and Licensing Requirements

3. Tax Issues

a. Security Requirements

b. Elimination of the Interconnection Customer's Right to Contest or Appeal Taxes

c. Transmission Credits for Tax Payments

4. Applicable Reliability Council Operating Requirements

5. Power Factor Design Criteria

6. Payment for Reactive Power

7. Security

8. Assignment

9. Disclosure of Confidential Information

E. Issues Related to the Large Generator Interconnection Procedures

1. Scoping Meeting and OASIS Posting

F. Ministerial Changes to the Pro Forma LGIP and LGIA

G. Compliance

IV. Information Collection Statement

V. Regulatory Flexibility Act Certification

VI. Document Availability

VII. Effective Date

Appendix A—Petitioner Acronyms

Appendix B—Changes to the Pro Forma LGIP and LGIA

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

Order on Rehearing and Directing Compliance

I. Introduction and Summary

1. In this order, we affirm, with certain clarifications, the fundamental determinations made in Order Nos. 2003^[1] and 2003-A.^[2] Adopting the pro forma Large Generator Interconnection Procedures (LGIP) and Large Generator Interconnection Agreement (LGIA) will help prevent undue discrimination, preserve the reliability of the nation's transmission system, and lower prices for customers by increasing the number and variety of generation resources competing in wholesale electricity markets. At its core, the Commission's interconnection policy enunciated in this series of orders ensures that all Generating Facilities are offered Interconnection Service on comparable terms.

2. This order reaffirms that an important objective of the Commission's pricing policy is the protection of the Transmission Provider's existing Transmission Customers, including native load, from subsidizing Network Upgrades required to interconnect merchant generators. This order also reaffirms the Order No. 2003-A crediting policy for Network Upgrades. Order No. 2003-A gave the Transmission Provider the option, after five years from the Commercial Operation Date of the Interconnection Customer's Generating Facility, of either fully reimbursing the Interconnection Customer for its upfront payment for Network Upgrades or continuing to make dollar-for-dollar credits against charges for Transmission Service. Order No. 2003-A provided no date certain for full reimbursement of the upfront payment.

3. On rehearing, petitioners ^[3] argue that a date certain is needed for a variety of reasons. In particular, they state that a date certain is needed to make the crediting policy consistent with the notion that the upfront payment is primarily a mechanism for financing Network Upgrades. This order addresses their concerns by clarifying that if the Transmission Provider chooses not to fully reimburse the Interconnection Customer after five years, it must continue to provide dollar-for-dollar credits to the Interconnection Customer, or develop an alternative schedule that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not previously repaid. However, full reimbursement shall not extend beyond twenty (20) years from the Commercial Operation Date.

4. 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 Provider to be amended to adopt the revisions to the pro forma LGIP and LGIA contained herein on the effective date of this order. Unlike the Order No. 2003 compliance process, however, each non-independent Transmission Provider will be required to amend its OATT to include the LGIP and LGIA revisions 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 revisions to its OATT or an explanation under the independent entity variation standard as to why it is not proposing to adopt each change described in this order.

II. Background

5. Order No. 2003 required all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file standard procedures and a standard agreement for interconnecting Generating Facilities capable of producing more than 20 megawatts of power (Large Generators) to their Transmission Systems.^[4] Order No. 2003 also required that all such public utilities modify their OATTs to include the pro forma LGIP and LGIA.

6. Order No. 2003 stated that interconnection plays a crucial role in bringing generation into national energy markets to meet the growing needs of customers and to obtain for customers the benefits of increased competition. It noted that the then-existing interconnection process was fraught with delays and lack of standardization that discouraged merchant generators from entering the energy marketplace, in turn stifling the growth of competitive energy markets. It concluded that the delays and lack of standardization inherent in the then-current system undermined the ability of generators to compete in the market and provided an unfair advantage to utilities that own both transmission and generation facilities. As a result, the Commission concluded that there was a pressing need for a single, uniformly applicable set of procedures and agreements to govern the process of interconnecting a Large Generator to a Transmission Provider's Transmission System.^[5]

7. Order No. 2003-A affirmed the legal and policy conclusions on which Order No. 2003 was based. It held that Order No. 2003 did not expand the Commission's jurisdiction beyond that asserted in Order No. 888 and upheld in court.^[6] For example, it reaffirmed that Order No. 2003 applies only to an interconnection with a public utility's Transmission System that, at the time the interconnection is requested, is used either to transmit electric energy in interstate commerce or to deliver electric energy sold at wholesale in interstate commerce under a Commission-filed OATT. It also reaffirmed that dual use facilities (those used both for wholesale and retail transactions) are subject to Order No. 2003 (1) if the facilities are subject to an OATT on file with the Commission when the Interconnection Request is submitted and (2) the interconnection will facilitate a wholesale sale.

8. Order No. 2003-A also generally affirmed the pricing policy adopted in Order No. 2003 for the recovery of the costs of Network Upgrades associated with an interconnection.^[7] That is, the Commission's existing pricing policy continues to apply to a non-independent Transmission Provider, but an independent Transmission Provider such as a Regional Transmission Organization (RTO) or an Independent System Operator (ISO) has greater flexibility to propose a customized pricing policy to fit its circumstances. It also reaffirmed that all Distribution Upgrades (upgrades to the Transmission Provider's “distribution” or lower voltage facilities that are subject to an OATT) are to be paid for by the Interconnection Customer without reimbursement (direct assignment).

9. In addition, Order No. 2003-A clarified that, consistent with the Commission's transmission ratemaking policy, a non-independent Transmission Provider continues to have the option to charge the Interconnection Customer a transmission rate that is the “higher of” an average embedded cost (rolled-in) rate or an incremental cost rate for the Network Upgrades needed for the interconnection. It also explained that incremental pricing is not the same as direct assignment.

10. Order No. 2003-A reiterated that, unless the Transmission Provider and the Interconnection Customer agree otherwise, the Interconnection Customer must initially fund the cost of any Network Upgrades used to interconnect its Generating Facility with a non-independent Transmission Provider's Transmission System. The Transmission Provider must then reimburse the Interconnection Customer on a dollar-for-dollar basis, with interest. This reimbursement is in the form of credits against the rates the Interconnection Customer pays for the delivery component of Transmission Service. In Order No. 2003-A, however, the Commission granted rehearing on two aspects of the mechanics of crediting. First, Order No. 2003-A required the Transmission Provider to provide credits to the Interconnection Customer only against transmission delivery service taken from the interconnecting Generating Facility, as opposed to Transmission Service taken elsewhere on the Transmission System. Second, it eliminated the requirement that transmission credits be refunded at the end of five years from the Commercial Operation Date of the Generating Facility and instead gave the Transmission Provider the option of either (1) reimbursing the Interconnection Customer for the remaining balance of the upfront payment, plus accrued interest, five years from the Commercial Operation Date of the Generating Facility or (2) continuing to provide credits until the upfront payment has been repaid, with accrued interest. Order No. 2003-A also eliminated the requirement that any Affected System Operator refund the Interconnection Customer's upfront payments for Network Upgrades built on the Affected System as a consequence of the interconnection of the Generating Facility, and instead required the Affected System to provide credits toward the Interconnection Customer's upfront payment only when Transmission Service is taken by the Interconnection Customer on the Affected System.

11. Order No. 2003-A also clarified that neither Energy Resource Interconnection Service (ERIS) nor Network Resource Interconnection Service (NRIS) guarantees delivery service. It explained that while both services give the Interconnection Customer the capability to deliver the output of its Generating Facility into the Transmission System at the Point of Interconnection, neither allows the Interconnection Customer the right to withdraw power at any particular Point of Delivery. It also clarified that when an Interconnection Customer wants to deliver the output of its Generating Facility to a particular load (or set of loads), regardless of whether it has chosen ERIS or NRIS, it may simultaneously request Network Interconnection Transmission Service or Point-to-Point Transmission Service under the OATT. Order No. 2003-A also clarified that NRIS is not the same as or a substitute for Network Integration Transmission Service under the OATT.

III. Discussion

A. Jurisdiction

Rehearing Requests

12. SoCal Edison claims that in Order No. 2003-A the Commission rejected its argument that all interconnections of generators intending to sell power to “wholesale entities,” except interconnections of Qualifying Facilities that will sell all of their output to host utilities under the Public Utilities Regulatory Policy Act of 1978,^[8] should be subject to Commission jurisdiction. In particular, SoCal Edison objects to the Commission's explanation that states have jurisdiction over an interconnection when the facility with which the Generating Facility is being interconnected is not subject to a Commission-approved OATT at the time the Interconnection Request is submitted, even if the Interconnection Customer intends to make a jurisdictional wholesale sale.^[9] This conclusion is legally erroneous and a significant departure from established policy and precedent.

13. SoCal Edison further argues that Order No. 888 states that wholesale transmission is within the Commission's exclusive jurisdiction. It cites to TAPS v. FERC, where the Supreme Court affirmed Order No. 888.^[10] Because interconnection is a form of Transmission Service, it should not matter whether an interconnection is with a facility that is subject to an OATT or already in use by a wholesale customer. Furthermore, SoCal Edison claims that it “can cite to myriad orders involving its distribution system alone where [the Commission] accepted jurisdiction under Section 205 over the interconnection of generation to distribution facilities used at the time by no other wholesale customers but the interconnecting generator.”

Commission Conclusion

14. The passage in Order No. 2003-A that SoCal Edison objects to states as follows: “States will retain jurisdiction over interconnection to dual use facilities when * * * the facility is not subject to a Commission-approved OATT at the time the Interconnection Request is made, even if the Interconnection Customer intends to make a jurisdictional wholesale sale.”^[11] This statement was in error. We grant rehearing to clarify that this statement was based on the false premise that a dual use facility may not be subject to an OATT at the time the Interconnection Request is made. In fact, a facility may be considered dual use only if it serves both state- and Commission-jurisdictional functions at the time the Interconnection Request is submitted. As a result, a dual use facility must be subject to an OATT. And if an Interconnection Customer seeks to interconnect with a dual use facility to make a wholesale sale, that interconnection will be subject to Order No. 2003. This is consistent with Order No. 2003 and other statements in Order No. 2003-A, where the Commission stated that an interconnection with dual use “distribution” facilities ^[12] that already serve a Commission-jurisdictional transmission function (and are subject to an OATT) for the purpose of facilitating a jurisdictional wholesale sale of electricity is subject to Order No. 2003.^[13] In conclusion, Order No. 2003-A incorrectly suggested that a state regulatory agency would have jurisdiction over an interconnection with a dual use facility when the Interconnection Customer intends to make a jurisdictional wholesale sale. Because this is the only statement on which SoCal Edison's request for rehearing is based, there is no need to address its other arguments.

B. Pricing and Cost Recovery Provisions

1. Transmission Credits

15. In Order No. 2003-A, the Commission noted that requiring the Transmission Provider to provide the Interconnection Customer with credits against transmission service unrelated to the Generating Facility, and to fully reimburse the Interconnection Customer after only five years, tends to shift risk from the entity in control of the investment (i.e., the Interconnection Customer) to native load and other Transmission Customers. The Commission stated that this shifting of risk may result in inefficient siting decisions, and may require native load or other Transmission Customers to bear the cost of the Network Upgrades when the Interconnection Customer takes little additional transmission service with the new Generating Facility as the source, or where the Interconnection Customer elects to retire the Generating Facility early. Therefore, to place an appropriate level of risk on the Interconnection Customer, the Commission in Order No. 2003-A revised the Final Rule policy (1) to make credits available only for transmission service that has the Generating Facility as the source of the power transmitted, and (2) to eliminate the guarantee of full reimbursement of the upfront payment in five years.

Rehearing Requests

16. Several petitioners object to the revisions made in Order No. 2003-A.^[14] Specifically, they argue that the Commission (1) should not have limited the applicability of credits to transmission service that has the Generating Facility as the source, (2) should not have given the Transmission Provider the option to fully reimburse the Interconnection Customer's upfront payment, plus interest, after five years, or to continue to provide credits to the Interconnection Customer until the total of all credits equals the Interconnection Customer's initial payment for the Network Upgrades plus interest, and (3) should not have excused an Affected System from having to provide credits except when transmission service is taken on the Affected System and has the Generating Facility as the source.

17. Calpine states that in Order No. 2003-A, the Commission has destroyed the balance and fairness of the Order No. 2003 policies.^[15] It argues that the Commission is now obligating the Interconnection Customer to finance Network Upgrades under terms that virtually guarantee that the Interconnection Customer will not be made whole for its upfront funding.

18. Reliant, PSEG, and Intergen state that, contrary to the Commission's stated rationale, the revised crediting rules will not cause the Interconnection Customer to make more efficient siting decisions, and they are not needed to protect native load or other Transmission Customers from bearing the costs of Network Upgrades if the Generating Facility is retired early. Intergen objects to the new policies for a number of reasons. First, Network Upgrade costs cannot influence siting decisions because the costs are typically unknown when siting decisions are made. Second, the Interconnection Customer must take multiple factors into consideration when making siting decisions. For example, the Interconnection Customer must consider the ability to access particular markets, fuel and water supply access, air quality issues, tax issues, and zoning issues, among other things. Third, because a Generating Facility is a multi-hundred million dollar investment, the Interconnection Customer has tremendous risk exposure, and adding a few million dollars in Network Upgrade costs will not shift the risk of commercial infeasibility or poor siting decisions to others. Fourth, oversight by state regulatory authorities is an important constraint on where the Interconnection Customer chooses to site its facility. Fifth, the amount of Network Upgrades needed is directly tied to the condition in which the Transmission Provider keeps its Transmission System. If the Transmission Provider has been properly upgrading and expanding its facilities, then fewer Network Upgrades are likely to be needed. Also, Reliant claims that continuing to require that the Interconnection Customer fund the Network Upgrade costs upfront mitigates any lack of incentive that the Interconnection Customer may otherwise have to make efficient siting decisions.

19. With regard to the need to protect native load and other transmission customers, Intergen states that an Interconnection Customer has strong incentives to maximize its use of the Transmission System, since it makes money only when it sells the output of its Generating Facility. Even under a worst case scenario, in which all Network Upgrade costs are assigned to existing customers, they would not suffer a significant rate increase. Intergen argues that concerns about native load customers being harmed by early retirements are overblown and do not recognize the significant benefits of increased competition in the generation market.

20. PSEG states that, by allowing the full reimbursement of upfront payments to be delayed beyond the five-year period, the Commission is discouraging development of RTOs. What will happen, for example, to an Interconnection Customer's transmission credits when the non-independent Transmission Provider to which it is interconnected joins an RTO? PSEG argues that permitting generators to “cash out” their credits on a date certain would alleviate these complexities and engender a smoother transition to an RTO system in which the interconnecting generator receives well-defined property rights rather than credits. Also, Intergen states that allowing the time for repayment to be extended indefinitely is inconsistent with the Commission's underlying “financing” policy for Network Upgrades and forces the Interconnection Customer to bear the full costs of a below-market interest rate.

21. Calpine points out that there are also Transmission Systems where the Interconnection Customer does not directly pay for transmission service. As a result, the Interconnection Customer does not receive a bill for transmission services to which credits can be applied. This is the situation, for example, in the California ISO, where load pays for transmission service. However, under Order No. 2003-A, the dollar-for-dollar offset against transmission service payments is the only way explicitly provided to receive transmission credits, and this might allow someone to argue that credits need not be paid in areas such as California. Under the Order No. 2003 language in article 11.4.1 of the pro forma LGIA, this argument could not have been made because that provision required that all upfront payments for Network Upgrades had to be refunded within five years, and the Parties had to agree on a mechanism to do so. Because Order No. 2003-A dropped the mandatory five-year repayment provision, there is no explicit provision as to how an Interconnection Customer that does not pay directly for transmission service is to receive its credits. Therefore, Calpine proposes adding the following sentence to article 11.4.1 of the LGIA:

In the event there is not a direct payment to Transmission Provider or Affected System Operator for transmission service to deliver power from the Large Generating Facility against which a repayment credit may be used, Transmission Provider, Affected System Operator and Interconnection Customer shall agree on a repayment schedule that would be comparable to one where transmission service was directly paid for, or such other mutually agreeable schedule.

22. Reliant and others state that the Commission departed from the balanced approach of Order No. 2003 by deciding that transmission credits must be given by the Transmission Provider only for transmission service that has the Generating Facility as the source of the power transmitted. Reliant argues that certain Generating Facilities, such as peakers, require transmission service on a very limited schedule and, as a result, owners of such facilities may find it difficult to recover the sums advanced to the Transmission Provider under Order No. 2003-A. Reliant claims that the new policy creates a barrier to entry for exactly the type of facility needed during tight supply conditions.

23. Reliant and Intergen argue that the Commission's new policy on credits effectively takes away a fundamental right that Order No. 888 provided to the Transmission Customer. That is, the use of credits for any service taken on a Transmission Provider's system must be equated to the right of a Transmission Customer to change its Point of Receipt or Point of Delivery under Point-to-Point Transmission Service. If the Transmission Provider can provide service from the new points, it grants the service with no additional charge to the Transmission Customer. Petitioners argue that, similarly, the Transmission Customer should be allowed to use its credits at alternate points of receipt or delivery without paying an additional charge to the Transmission Provider.

24. Intergen states that Order No. 2003 mitigated adverse cost impacts by giving the Interconnection Customer flexibility in determining how best to use the credits it received for the costs of Network Upgrades. The ability to transfer credits to other entities for which the Generating Facility is not the source of the power transmitted may be crucial for an Interconnection Customer that must meet its debt obligations, but has limited ability to acquire transmission service or sell its output. Also, because the interest accruing on the credits does not fully compensate the Interconnection Customer for its upfront payment, an Interconnection Customer has a strong incentive to transfer the credits to another entity that can use the credits immediately.

25. TAPS states that a problem would arise if a Transmission Provider were to seek to restrict credits to a Network Customer by basing the credits on the energy output, rather than the capacity, of a Generating Facility used as a Network Resource. TAPS asks the Commission to revise or clarify Order No. 2003-A to provide that a Network Customer that designates an interconnecting Generating Facility as a Network Resource will receive credits based on the full capacity of the Network Resource (or the amount reserved by the Network Customer if it is less), not just the energy delivered from the resource.

26. EPSA states that if the Commission retains the policy of limiting credits to transmission service that has the Generating Facility as the source, there are several issues that must be clarified. First, the Commission should clarify that credits will be applied to the total reservation payment for any service obtained to support the delivery of the generator, whether or not energy is scheduled in any particular hour of the reservation period and whether or not the power customers take advantage of the options to use alternative receipt or delivery points provided under the pro forma OATT to all point-to-point customers. Second, the Commission should clarify that credits will be applied to network services whenever a Network Customer designates the Generating Facility as a Network Resource or substitute resource, regardless of whether the Generating Facility produces energy during each hour of the designation. Finally, EPSA asks the Commission to clarify that credits must be provided by the Transmission Provider when it designates the Generating Facility as a Network Resource or substitute resource for meeting its native load requirements, whether or not the Transmission Provider actually enters into a service agreement under the OATT.

27. TAPS states that changes described in P 675 of Order No. 2003-A suggest that only credits equal to the OATT's embedded cost rates must be provided, even if the Transmission Provider charges an incremental transmission rate.^[16] The Rule should be revised or clarified to address this discrepancy. A Transmission Provider that seeks transmission charges based on the incremental cost of Network Upgrades should be required to provide the Interconnection Customer that paid for those upgrades upfront with credits applied against the full amount of the incremental transmission charges, until the Interconnection Customer's upfront payment, plus interest, has been completely reimbursed.

28. PSEG states that under Order No. 2003-A, a non-independent Transmission Provider may have an incentive to “tack on” unnecessary Network Upgrade requirements (for which ultimate compensation to the generator has now been made considerably less certain) or not to build Network Upgrades that would allow transmission service to be taken from the Generating Facility (for which credits would have to be given). PSEG claims that this will discourage the construction of new generation and create incentives for preferential treatment of affiliated generation.

29. Intergen states that unlike merchant units, the Transmission Provider's generating facilities never had to pay the upfront costs of their Network Upgrades. Thus, Transmission Provider facilities never had to assume any of the risks associated with Network Upgrades that the merchant generators do. To mitigate these competitive disadvantages, Intergen asserts that the Commission should allow the Interconnection Customer to receive credits for service sourcing at points other than the Generating Facility.

30. PSEG argues that Network Upgrades benefit the entire Transmission System, and this common benefit is what distinguishes Network Upgrades from sole use facilities. The Interconnection Customer's financing of investment in the network of a non-independent Affected System benefits all Network Customers and all network transactions. It is unduly discriminatory to limit the Interconnection Customer's recovery of the funds it advances for Network Upgrades on an Affected System simply because the Interconnection Customer is unable to make direct use of them.

31. EPSA urges the Commission to reverse its decision to modify the crediting policy with respect to Network Upgrades funded by an Interconnection Customer on an Affected System. A Generating Facility will be less likely to use transmission service on an Affected System than on the Transmission System to which it is interconnected, and this will unreasonably delay repayment. This is especially true in the West, where network facilities affected by an interconnection are often jointly owned by a number of Transmission Providers. These Transmission Providers are often far removed from the Transmission Provider to which the Generation Facility is interconnected. According to EPSA, an Interconnection Customer is unlikely to take transmission service on the Transmission System of a Transmission Provider that jointly owns these affected facilities. Therefore, the Interconnection Customer will have little ability to use the credits to which it is entitled.

Commission Conclusion

32. In Order No. 2003-A, the Commission revised the rules governing transmission credits to place the Interconnection Customer at greater risk for the cost of Network Upgrades occasioned by the Interconnection Request. The Commission was concerned that to do otherwise would not lead to efficient siting decisions and would not adequately protect native load and other Transmission Customers from having to bear Network Upgrade costs if the Generating Facility were to retire early. In their arguments opposing the modifications, Intergen and others state that the cost of Network Upgrades is typically small compared to the cost of the Generating Facility and that the Interconnection Customer will often embark on a project even though Network Upgrade costs are unknown. This suggests that placing the risk for the cost of Network Upgrades on the Interconnection Customer does not place a significant burden on the Interconnection Customer and thus is completely appropriate. Also, Intergen states that the Interconnection Customer has a strong incentive to maximize its use of the Transmission System because it only makes money if it is selling output from its Generating Facility. The crediting policy, however, reinforces that incentive by linking transmission credits directly to the output of the Generating Facility.

33. We strongly encourage policies that promote efficient investment decisions and protect native load and other Transmission Customers from having to bear the burden of the Interconnection Customer's Network Upgrade costs. Given these concerns, we continue to find that the Order No. 2003-A crediting policy 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.

34. Intergen states that extending the reimbursement timeframe indefinitely is inconsistent with the Commission's determination that the upfront payment is merely a mechanism for financing the cost of the Network Upgrades. In addition, PSEG states that the indefinite timeframe will make the transition to RTO development more complex, and Calpine claims that an uncertain timeframe for reimbursement will create problems in areas such as California where the Interconnection Customer does not receive directly a bill for transmission service to which credits can be applied.

35. These petitioners make valid points. To address the Interconnection Customer's need for a date certain for reimbursement of its upfront payment, we are specifying what the Transmission Provider must do if it elects not to return to the Interconnection Customer any portion of its upfront payment that remains due at the end of five years. Specifically, in order to provide a definite end date for reimbursement that is not to be exceeded, we are revising pro forma LGIA article 11.4.1 to state that full reimbursement shall not extend beyond twenty (20) years from the Commercial Operation Date. The portion of this article that describes the Transmission Provider's second repayment option now reads as follows:

(2) declare in writing that Transmission Provider or Affected System Operator will continue to provide payments to Interconnection Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, or develop an alternative schedule that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not previously repaid; however, full reimbursement shall not extend beyond twenty (20) years from the Commercial Operation Date.

36. All other crediting rules remain the same. This change addresses Intergen's concern that Order No. 2003-A's removal of a date certain for the repayment of Network Upgrade costs was inconsistent with the notion that the upfront payment is, in essence, a loan to the Transmission Provider designed to facilitate construction of the Network Upgrades. The change also addresses PSEG's concern that the lack of a date certain might create an obstacle to the development of an RTO, which may require the Interconnection Customer's upfront payment to be converted into financial transmission rights. Finally, the change addresses Calpine's concern that, in the absence of a date certain for repayment of Network Upgrade costs, a Transmission Provider could conclude that credits need not be repaid in areas where the Interconnection Customer does not pay directly for transmission service. We further clarify that the Interconnection Customer is entitled to full reimbursement for its upfront payment and the period for reimbursement may not be longer than the period that would be required if the Interconnection Customer paid for transmission service directly and received credits on a dollar-for-dollar basis, or 20 years, whichever is less. In short, the imposition of a 20-year date certain does not mean that the Commission is switching from reimbursing through credits to reimbursing over 20 years. Rather, if credits have not fully reimbursed the upfront payment within 20 years, there will be a balloon payment at the end of year 20.

37. Reliant argues that the owner of a Generating Facility, such as a peaker, that requires transmission service on a limited schedule may find it difficult or impossible to recover its upfront payment under the Commission's rules as revised by Order No. 2003-A. We disagree. Any Interconnection Customer whose Generating Facility is used as intended, whether or not it is a peaker, normally will be required to take Firm Point-to-Point Transmission Service or Network Integration Transmission Service and therefore will have ample opportunity to use its transmission credits to obtain reimbursement of its upfront payment. Furthermore, reimbursement of any upfront payment must occur no later than 20 years after the Commercial Operation Date.

38. Reliant and Intergen argue that limiting credits to transmission service taken with the Generating Facility as the source takes away the Transmission Customer's fundamental right under Order No. 888 to change its Point of Receipt or Point of Delivery under Point-to-Point Transmission Service without additional charge if the Transmission Provider is able to grant the service at the alternate points. Also, Intergen argues that the ability to transfer credits may be crucial for an Interconnection Customer that must meet debt obligations but is constrained in its ability to acquire transmission service. The new policy does not revoke any rights provided by Order No. 888. 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 under 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.

39. TAPS and EPSA ask the Commission to revise or clarify Order No. 2003-A to provide that a Network Customer that designates a Generating Facility as a Network Resource will receive credits based on the full capacity of the Network Resource (or the amount reserved by the Network Customer if it is less), not just the energy delivered from the resource. We clarify that when a Generating Facility is designated as a Network Resource or a substitute resource, the Interconnection Customer is entitled to credits for the full amount of the reserved capacity of the Generating Facility regardless of the amount of energy that is scheduled for delivery in any particular hour. Also, TAPS states that changes to the Final Rule described in P 675 of Order No. 2003-A suggest that only credits equal to the Tariff's embedded cost rates would be provided, even if the Transmission Provider chooses to charge an incremental cost rate. We clarify that, if the Transmission Provider chooses to charge an incremental cost rate, the Interconnection Customer is entitled to receive credits, on a dollar-for-dollar basis, at the incremental rate.

40. PSEG states that the new rules may provide a non-independent Transmission Provider with an incentive to “tack on” unnecessary Network Upgrades or omit necessary Network Upgrades. Also, Intergen claims that, unlike a merchant developer, the Transmission Provider never had to assume for its Generating Facilities any of the risks associated with Network Upgrades, and this places the merchant developer at a competitive disadvantage. We disagree. The Commission's crediting policy assigns risk and cost responsibility in a reasonable manner and applies to Interconnection Requests by entities affiliated with the Transmission Provider and to Interconnection Requests by unaffiliated merchant generators. We reiterate that the Transmission Provider has an obligation to apply our interconnection policy in a non-discriminatory manner to all new Interconnection Requests, whether the Generating Facility is owned by the Transmission Provider, its Affiliate, or a merchant developer.

41. EPSA and PSEG are concerned that the Interconnection Customer may be unable to recoup upfront payments for Network Upgrades that are constructed on an Affected System. We note that taking transmission service on an Affected System is entirely at the option of the Interconnection Customer. Whether or not the Interconnection Customer exercises its option, the Network Upgrades on the Affected System benefit the Interconnection Customer by making the minimum transmission additions necessary for it to interconnect safely and reliably, as well as by facilitating access to customers and markets that are outside the Transmission Provider's electric system. Furthermore, if the Interconnection Customer were to be reimbursed by the Affected System Operator for the cost of the Network Upgrades without ever taking service on the Affected System, other Transmission Customers on the Affected System would have to bear the cost instead. This would create a disincentive for the Affected System to construct the Network Upgrades necessary for the Interconnection Customer to interconnect, a problem that would be particularly difficult to address if the Affected System were not a public utility.

42. In addition, EPSA states that when an Affected System is jointly owned, an Interconnection Customer is unlikely to take transmission service on the Transmission System of a Transmission Provider that is far removed from the Affected System on which Network Upgrades had to be constructed. We clarify that the Affected System Operator must provide the Interconnection Customer with credits for transmission service taken on the Affected System until the Interconnection Customer's entire upfront payment has been reimbursed. In the case of an Affected System that is jointly owned, 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. We note that this problem is not unique to an Affected System. If a Transmission Provider provides transmission service on a Transmission System that is jointly owned, that Transmission Provider must follow a similar procedure.

2. Credits Under Change in Ownership

Rehearing Requests

43. Cinergy requests clarification of LGIA article 11.4.1, which states that if the Generating Facility fails to achieve commercial operation, but it or another Generating Facility is later constructed and uses the Network Upgrades, the Transmission Provider and the Affected System Operator shall at that time reimburse the Interconnection Customer for the amounts advanced for Network Upgrades. Specifically, where a Generating Facility fails to achieve commercial operation, Cinergy argues that it would be difficult for a Transmission Provider to determine who would be entitled to any eventual credit for the costs of Network Upgrades. This is significant because, given the uncertain state of the energy industry, the original entity constructing the Generating Facility could have been either purchased in whole or in part by another company, bankrupt, or simply no longer be in existence. Cinergy argues that the obligation to keep track of who should receive such reimbursement, if any, should not lie with the Transmission Provider but rather with the Interconnection Customer or its successors.

44. In addition, Cinergy states that article 11.4.1 is not clear as to whether interest accrues on the upfront payment made by an Interconnection Customer whose Generating Facility fails to achieve commercial operation. Cinergy argues that interest should not accrue during what could possibly be an extended period of time where the upgrades remain idle, unused by either another Generating Facility or the Transmission Provider. Cinergy asks the Commission to clarify article 11.4.1 accordingly.

Commission Conclusion

45. We agree with Cinergy that, when a Generating Facility does not achieve commercial operation, the responsibility for keeping track of the entity that is entitled to receive any transmission credits that may be due should lie with the Interconnection Customer, or with any successor entity that may later construct a Generating Facility that makes use of the Network Upgrades. Therefore, we are adding the following sentence to the final paragraph of LGIA article 11.4.1: “Before any such reimbursement can occur, the Interconnection Customer, or the entity that ultimately constructs the Generating Facility, if different, is responsible for identifying the entity to which reimbursement must be made.”

46. With regard to the accrual of interest on upfront payments in cases where the Generating Facility fails to achieve commercial operation, we clarify that interest continues to accrue provided the interconnection agreement remains in effect. Interest does not accrue after an interconnection agreement has been terminated by either Party or during any period in which no interconnection agreement is in effect.

3. Protecting Native Load and Other Existing Transmission Customers

Rehearing Requests

47. SWTransco and Southern Company argue that the Commission's interconnection pricing policy, in certain circumstances, would not protect native load and other customers from bearing the cost of Network Upgrades required for interconnection.^[17] Moreover, these petitioners argue that a policy of allowing the Transmission Provider to charge the higher of an incremental rate or an embedded cost rate does not always protect other customers from subsidizing the Interconnection Customer.

48. SWTransco states that to leave the other Transmission Customers no worse off in certain situations, it is necessary to charge the Interconnection Customer not only the Network Upgrade costs, but also the share of the rolled-in costs attributable to any Generating Facility that is displaced by the new Generating Facility. Also, Southern Company states that charging the Interconnection Customer only an incremental rate would not cover the Generating Facility's use of the rest of the Transmission System.

49. Southern Company states that to truly prevent subsidies, the Commission must either (1) allow the direct assignment of Interconnection Facilities and NRIS facilities (because they do not provide a system benefit) and require the generator (or its customer) to pay the embedded transmission rate for delivery service or (2) allow all Transmission Providers to implement participant funding. Southern Company agrees that any disputes regarding participant funding determinations may need to be resolved by an independent entity, but asserts that, in the absence of an RTO or other independent entity, the Commission is well equipped (and, indeed, charged under sections 205 and 206 of the Federal Power Act) to resolve such disputes.

50. Southern Company states that the subsidization issue is generally not a concern if the Generating Facility is designated a Network Resource of the Transmission Provider, or of its Network Customers, contemporaneously with the execution of its interconnection agreement. Southern Company argues that the subsidization issue arises mainly when a merchant generator has no long-term reservations for transmission delivery service from its plant contemporaneously with the execution of the interconnection agreement, or when the Interconnection Customer and the Transmission Customer are different entities.

51. On a related matter, some petitioners ask for guidance regarding the implementation of incremental pricing in the context of generator interconnections. For example, NRECA seeks answers to the following questions. Over what period of time should the incremental costs be presumed to be amortized? If the Interconnection Customer has only a short-term contract for the output of the Generating Facility, should the costs be amortized over that short period? If the Interconnection Customer has only a short-term contract for the output of the Generating Facility, but the Transmission Customer that requests delivery of the Generating Facility's power is taking service under a long-term transmission contract, should the cost of the Network Upgrades be amortized over the length of the transmission contract? Should the cost of Network Upgrades be amortized over their useful life?

52. SWTransco claims that the interconnection procedures and agreement in Order No. 2003-A do not appear to contain mechanics sufficient to allow the pricing concept to be implemented. Southern Company argues that the Transmission Provider will not be able to calculate an incremental rate with any certainty because it often has no reasonable idea regarding the amount of the delivery service that might ultimately be taken from the facility (or which entities will actually be requesting any such delivery service) or the duration of any such service. This is because, in Southern Company's experience, merchant generators normally do not seek interconnection and transmission delivery services at the same time. At a minimum, the Commission must clarify how the incremental pricing calculation could be performed for a merchant generator that does not make a request for transmission delivery service at the time of the execution of the interconnection agreement or when the Interconnection Customer and the Transmission Customer are separate entities.

53. TAPS states that it is unclear from Order No. 2003-A whether or how the Commission intends that incremental pricing would be applied to network Transmission Customers, given the load ratio share pricing required by the OATT.

Commission Conclusion

54. Order No. 2003-A clarified that the Commission was not abandoning any of the fundamental principles that have long guided its transmission pricing policy. The Commission's 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 or an embedded cost rate for the entire Transmission System (including the cost of the Network Upgrades). Order No. 2003-A emphasized that this “higher of” policy ensures that other Transmission Customers, including the Transmission Provider's native load, will not subsidize Network Upgrades required to interconnect merchant generation.

55. On rehearing, petitioners raise concerns regarding the implementation of this policy and whether other customers are protected from having to bear the costs of Network Upgrades under all circumstances. Petitioners argue that they can devise certain hypothetical cases in which the Transmission Provider must either impose some new transmission costs on existing customers or violate the Commission's prohibition against “and” pricing.

56. In response to these petitioners, we first reaffirm that an important objective of our interconnection pricing policy continues to be the protection of existing Transmission Customers, including the Transmission Provider's native load, from adverse rate implications associated with Interconnection Facilities and Network Upgrades required to interconnect a new Generating Facility. Despite the unsupported hypothetical generalizations of some petitioners, we have not been presented with any evidence that native load and other Transmission Customers cannot be held harmless under our existing pricing policy. If a Transmission Provider (or an existing Transmission Customer) 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. The Transmission Provider must explain the facts of the case and the assumptions on which its calculation is based and provide evidentiary support. While we cannot envision any circumstances where our existing pricing policy will not fully protect native load and other Transmission Customers, we are willing to consider alternative pricing proposals under the facts of a specific case. We emphasize that the Transmission Provider bears the full burden of showing that any such proposal is just and reasonable and not unduly discriminatory or preferential, and is appropriate under the circumstances.

57. Similarly, with regard to the calculation of incremental rates, we are not prescribing generic rules at this time. Rather, we invite the Transmission Provider, in the context of an actual interconnection agreement or transmission rate filing, to propose a calculation method that assigns appropriate cost responsibility to the Interconnection Customer and is consistent with applicable Commission policy and precedent.

4. Interconnection Products and Services

Rehearing Requests

58. Some petitioners seek clarification of the provisions of Order No. 2003-A governing NRIS and ERIS.

59. NRECA requests that the Commission clarify that, consistent with the OATT (1) only Interconnection Customers that are load serving entities may request Network Integration Transmission Service under a Transmission Provider's OATT, and (2) only Network Customers can designate Network Resources.

60. TAPS asserts that, as clarified in Order No. 2003-A, the unique feature of NRIS has nothing to do with being a “Network Resource,” which is defined by the OATT as a resource designated by a Network Customer under Network Integration Transmission Service. Rather, NRIS provides assurance that even absent any transmission service, “the Generating Facility, as well as other generating facilities in the same electrical area, can be operated at peak load,” and that the output of the Generating Facility will not be “bottled up” under such conditions. The name “Network Resource Interconnection Service,” therefore, is misleading. TAPS recommends an alternative name, such as “Enhanced Interconnection Service,” that more accurately describes this Interconnection Service.

61. Also, TAPS states that the references to “other Network Resources” in LGIA articles 4.1.2.1 and 4.1.2.2 and LGIP section 3 are particularly confusing, because as noted above, “Network Resource” is defined as a resource designated under Network Integration Transmission Service. In other words, the references to “other” Network Resources assume something that has not necessarily happened in the case of resources taking NRIS.

62. TAPS states that article 4.1.2.2 suggests that generators taking NRIS are different from generators taking ERIS with respect to their ability to be designated as Network Resources. Specifically, the introductory sentences of article 4.1.1.2, especially if read in conjunction with LGIA article 4.1.2.2, suggest that NRIS is the preferred route to obtaining a Network Resource designation under the OATT. Although the preamble of Order No. 2003-A otherwise makes clear that a resource with ERIS may be designated as a Network Resource, it confusingly states elsewhere that “Network Resource Interconnection Service makes it possible for the Generating Facility to be designated as a Network Resource.”

63. Similarly, TAPS states that LGIA article 4.1.1.1 and LGIP section 3.2.2.1 continue to describe ERIS as providing “as available” access, without restricting application of that limit, i.e., without adding language such as “unless combined with Network Integration Transmission Service or Firm Point-to-Point Transmission Service,” which would be consistent with the preamble of Order No. 2003-A. TAPS is concerned that LGIP section 3 lacks any reference to the ability of an ERIS customer to obtain anything other than “as available” transmission service. The Commission should modify LGIP section 3 and LGIA articles 4.1.1.1, 4.1.1.2, and 4.1.2.2 to eliminate any confusion.

64. EPSA states that the Commission has introduced some uncertainty as to the additional studies or additional upgrades that might be associated with NRIS. It asks the Commission to clarify that any references to such studies or upgrades apply only to optional upgrades to reduce congestion or to customer-specific delivery issues, not to upgrades related to the designation of a NRIS generator as a Network Resource. If the Commission does not clarify that the Interconnection Customer's responsibility to pay for additional studies and upgrades is to be limited to the circumstances described above, EPSA requests rehearing on this issue. EPSA also urges the Commission to require Transmission Providers to include in their compliance filings the protocols and procedures they will use to determine when additional studies or upgrades are needed.

65. Intergen asserts that the studies associated with NRIS and with Network Integration Transmission Service are essentially identical. Thus, a NRIS customer and a Network Integration Transmission Service customer should build the same Network Upgrades. However, Intergen interprets the clarification in Order No. 2003-A to mean that the NRIS customer will not receive any delivery assurances despite the fact that it is fronting the costs of the Network Upgrades needed to permit Network Integration Transmission Service. The Commission's statement that the Interconnection Customer's Generating Facility may have to be restudied and pay for additional upgrades once it is designated as a Network Resource, according to Intergen, eviscerates the value of NRIS.

66. In addition, Intergen states that, if the Network Integration Transmission Service studies reveal that the Interconnection Customer cannot acquire Network Integration Transmission Service without significant upgrades, and the Interconnection Customer cannot use its credits for service sourcing elsewhere on the Transmission Provider's Transmission System, the credits could be “locked” into a facility that cannot move its power. Intergen asks for further clarification or rehearing of this aspect of Order No. 2003-A. Intergen also asks the Commission to clarify that, because NRIS uses studies similar to those used to determine whether Network Integration Transmission Service is available, and because the Interconnection Customer is paying for the upgrades associated with those studies, an NRIS generator does not need to be restudied and does not need to construct additional Network Upgrades when designated as a Network Resource.

67. NRECA states that NERC and others had stressed in earlier comments to the Commission that the requirement in LGIP section 3.2.2.2 that the Transmission Provider study the Transmission System “at peak load, under a variety of severely stressed conditions * * *.” was insufficient to ensure the reliability of the Transmission System. Order No. 2003-A failed to address NERC's concern over the wording of section 3.2.2.2 of the LGIP. NRECA argues that, although the Commission indicates that it will allow a Transmission Provider to petition for changes to the study criteria subject to the “consistent with or superior to” standard, such an ad hoc approach to this important reliability issue is insufficient. It notes that Order No. 2003-A indicated that a threshold requirement for obtaining the Commission's permission to deviate from the pro forma LGIP will be whether there is an accepted regional practice addressing this issue. However, NRECA claims that in many regions there is no such established practice. Consequently, a Transmission Provider in such regions would be barred from making the necessary changes to the NRIS study criteria.

Commission Conclusion

68. Most of the questions and concerns raised by petitioners concerning interconnection products and services were fully addressed in Order No. 2003-A, and we will not repeat those conclusions here. We remind petitioners that, to gain a full understanding of Order No. 2003-A's treatment of NRIS and ERIS, the preamble, LGIP and LGIA must be read together. To include all of the relevant preamble discussion in the LGIP and LGIA would make those documents unwieldy.

69. In response to TAPS's concerns about the descriptions of NRIS and ERIS and the relationship between NRIS, ERIS and Network Integration Transmission Service, we note that the Commission addressed these matters in detail at P 530-537 of Order No. 2003-A. Also, we disagree with TAPS's assertion that the name “Network Resource Interconnection Service” is misleading. The name is suitable given that the principal purpose of the service is to allow the Generating Facility to qualify for designation as a Network Resource by a Network Customer. However, we agree that the use of the word “other” as a modifier of “Network Resources” in LGIP sections 1 and 3.2.2.1 and LGIA articles 1 and 4.1.2.2 is confusing. Therefore, we are eliminating it from those sections and articles. In response to NRECA, we clarify that we are not changing the requirement of Order No. 888 that only a load serving entity can become a Network Customer and only a Network Customer can designate a Generating Facility as a Network Resource.

70. In response to EPSA's and Intergen's concerns that an Interconnection Customer taking NRIS may be required to pay for additional studies and additional upgrades to have the Generating Facility designated as a Network Resource, we note that the Commission addressed this matter at P 544-545 of Order No. 2003-A; no further response is needed.

71. NRECA argues that the study criteria for NRIS are insufficient, and is concerned that the Commission will not allow a Transmission Provider to adopt different criteria if there is no established practice addressing this issue in the Transmission Provider's region. Our experience with the Order No. 2003 and Order No. 2003-A compliance filings leads us to agree with NRECA that the orders' requirements regarding the Transmission Provider's use of alternative NRIS study criteria are unnecessarily burdensome. In their compliance filings, a number of Transmission Providers proposed to modify the NRIS study criteria to allow them to study the Transmission System under non-peak load conditions. Some of these Transmission Providers supported their requests with references to criteria documented in their reliability region's planning standards, while others explained that the use of their proposed criteria is a generally accepted regional practice. The Commission generally accepted these proposals subject to certain conditions.^[18] Based on our experience with these compliance filings, we now conclude that it is no longer necessary to require the Transmission Provider that wishes to include non-peak load criteria in its NRIS study process to demonstrate that the use of such study criteria is consistent with or superior to the requirements of pro forma LGIP section 3.2.2.2. Rather, we will allow the non-independent Transmission Provider to adopt study criteria that consider non-peak load conditions if the Transmission Provider, upon request by the Interconnection Customer, agrees to provide the Interconnection Customer with a written justification for doing so. We emphasize, however, that the Transmission Provider must provide comparable service; that is, it must study non-peak conditions for the interconnection of its own and its affiliates' Generating Facilities on the same basis that it studies non-peak conditions for the non-affiliated Interconnection Customer. To implement this change, we are inserting the following sentences after the first sentence of LGIP section 3.2.2.2:

The Transmission Provider may also study the Transmission System under non-peak load conditions. However, upon request by the Interconnection Customer, the Transmission Provider must explain in writing to the Interconnection Customer why the study of non-peak load conditions is required for reliability purposes.

This should simplify the compliance process and satisfy NRECA's concerns.^[19]

5. Generator Balancing Service Arrangements

72. In Order No. 2003-A, the Commission deleted article 4.3 from the pro forma LGIA, thereby eliminating any reference in the LGIA to the Interconnection Customer's obligation to make generator balancing service arrangements before submitting a schedule for delivery service that identifies the Interconnection Customer's Generating Facility as the Point of Receipt for the scheduled delivery.^[20]

Rehearing Requests

73. NRECA and Southern Company argue that Order No. 2003-A is at odds with Order No. 888-A, which anticipated that generator balancing service arrangements would be included in the interconnection agreement.

Commission Conclusion

74. We disagree with NRECA and Southern Company. While it is true that Order No. 888-A indicated that the Commission expected the interconnection agreement to include a provision for generator balancing service arrangements, it also included the following:

This agreement will be tailored to the parties' specific standards and circumstances, and, although such arrangements must not be unduly preferential or discriminatory (e.g., must be comparable for all wholesale sellers, including the transmission provider's own wholesale sales), we prefer not to set these standards generically.^[21]

75. The policies as set forth in Order No. 888-A remain unchanged. Thus, we are not including a provision for generator balancing service arrangements in the pro forma LGIA. However, we recognize that some Transmission Providers may prefer to include such a provision in the interconnection agreement that it enters into with the Interconnection Customer, rather than in a separate agreement. Therefore, we are permitting the Transmission Provider to include a provision for generator balancing service arrangements in individual interconnection agreements. Such provisions should be tailored to the Parties' specific standards and circumstances, and are subject to Commission approval.

C. Independent Transmission Provider Obligations

76. Order No. 2003-A provided that if a non-independent Transmission Owner's transmission facilities are under the operational control of an RTO or ISO, the RTO's or ISO's Commission-approved standards and procedures govern all interconnections with those facilities. It also provided that a non-independent Transmission Owner that belongs to an RTO or ISO but has operational control over some of its Transmission System must have its own set of interconnection agreements and procedures separate from the RTO's or ISO's that govern interconnections with the portions of its Transmission System over which it retains operational control.

Rehearing Requests

77. NYISO asks the Commission to not apply the pro forma LGIP and LGIA to certain facilities under New York Transmission Owners' (NYTO) control for the period between January 20, 2004, which was the date that non-independent Transmission Providers were required to adopt the pro forma LGIP and LGIA, and Commission action on NYISO's compliance filing, which occurred August 6, 2004.

78. TAPS states that Order No. 2003-A suggested that a non-independent Transmission Owner that is a member of an RTO or ISO could have its own tariff for interconnections with transmission facilities over which it retains operational control.^[22] According to TAPS, the Commission should make clear that where the Interconnection Service is necessary to effectuate service under the OATT of an RTO that has operational control of transmission facilities owned by a non-independent Transmission Owner, that Transmission Owner may not layer on a separate set of interconnection procedures and agreements for facilities over which it maintains operational control. TAPS contends that such layering is inconsistent with Order No. 2003-A and Commission precedent, which provide that the RTO or ISO must offer “one-stop shopping” for interconnection.^[23] At a minimum, TAPS continues, the Commission should subject any non-independent Transmission Owner within an RTO to a heavy burden to demonstrate why an Interconnection Customer should be unable to obtain through the RTO or ISO the necessary interconnection with the Transmission Owner's facilities that are not subject to the RTO's operational control.

Commission Conclusion

79. NYISO's concerns have been mooted by the Commission's orders in response to compliance filings submitted by the New York utilities.^[24] Accordingly, there is no need to address them here.

80. In response to TAPS, we clarify that a Transmission Owner that belongs to an RTO or ISO cannot require a separate set of interconnection procedures or agreement for interconnection with facilities within the RTO's or ISO's operational control; i.e., a transmission facility cannot be governed by two separate sets of interconnection procedures and agreements . If the Transmission Owner retains operational control of some jurisdictional facilities, and those facilities are not subject to the interconnection procedures under the OATT of the RTO or ISO,^[25] then the Transmission Owner must have a separate set of interconnection procedures and agreement applicable to these facilities. An Interconnection Customer seeking to interconnect with the facilities within the Transmission Owner's operational control will be subject only to the Transmission Owner's interconnection agreement and procedures. We acknowledge that this may create inconsistent interconnection procedures and agreements within a region controlled by an RTO or ISO, or result in confusion as to which interconnections procedures and agreement applies to the facilities to which the Interconnection Customer wishes to interconnect. To address this issue, we are allowing a Transmission Owner that retains control over some jurisdictional facilities to subject these facilities to an RTO- or ISO-controlled interconnection process. In such instance, the Transmission Owner must agree to transfer to the RTO or ISO control over the significant aspects of the interconnection process under the Transmission Owner's OATT interconnection process, including the performance of all Interconnection Studies and cost determinations applicable to Network Upgrades.^[26] Even under this modified approach, there should be only one applicable interconnection agreement and one set of procedures for each Interconnection Request for a Commission-jurisdictional interconnection.

D. Issues Related to the Large Generator Interconnection Agreement

1. Stand Alone Network Upgrades

81. LGIA article 5.2 in Order No. 2003 provided, among other things, that the Interconnection Customer assumes responsibility for the design, procurement, and construction of Stand Alone Network Upgrades, the Interconnection Customer shall transfer control of such upgrades to the Transmission Provider. Order No. 2003-A revised LGIA article 5.2 to provide that “[u]nless Parties otherwise agree, Interconnection Customer shall transfer ownership of Transmission Provider's Interconnection Facilities and Stand Alone Network Upgrades to Transmission Provider.” ^[27]

Rehearing Request

82. NRECA seeks clarification that if a transmission-owning Interconnection Customer is a load serving entity that has the right to own or operate the Transmission Provider's Interconnection Facilities or Stand Alone Network Upgrades under existing state or other law or under pre-existing contracts, Order No. 2003-A does not supersede such pre-existing contractual or legal/regulatory rights in a way that would bar such a load serving entity from retaining ownership.

83. TAPS makes similar arguments. It argues that while it may be reasonable for the Transmission Provider to operate and control the Interconnection Facilities and Stand Alone Network Upgrades constructed by the Interconnection Customer, compelling the Interconnection Customer to give up ownership contributes to monopolization of transmission ownership. Allowing Interconnection Customers that are load serving entities to retain ownership does not mean that operation and control of the Transmission System will be fragmented or that reliability will be compromised; indeed, some TAPS members already own transmission facilities. TAPS further notes that while Order No. 2003-A states that allowing the Interconnection Customer to retain ownership is “inconsistent with existing Commission precedent,” ^[28] it does not cite to the precedent.

84. TAPS further argues that where an Interconnection Customer has constructed Interconnection Facilities and Stand Alone Network Upgrades, the customer should have the option of owning the facilities and receiving a lease payment or other credit recognizing the contribution that the facilities make to the Transmission System (e.g., as a credit for customer-owned facilities consistent with section 30.9 of the pro forma OATT). Allowing transmission dependent utilities to retain ownership takes advantage of these utilities' solid credit, reduces regulatory conflicts, and facilitates siting through joint planning and ownership of the Transmission System.

Commission Conclusion

85. Under ordinary circumstances, the Transmission Provider assumes the risk and responsibility for reliably operating its Transmission System. Giving the Interconnection Customer the option of owning Transmission Provider's Interconnection Facilities or Stand Alone Network Upgrades without the Transmission Provider's consent raises reliability and liability issues arising from the operation of these types of facilities by an entity not responsible for the rest of the Transmission System.^[29] While TAPS highlights some of the benefits that might result from giving the Interconnection Customer the unilateral option of owning the Transmission Provider's Interconnection Facilities or Stand Alone Network Upgrades, on balance, the risks outweigh the benefits.

86. In response to NRECA, Order No. 2003-A did not supersede pre-existing contractual or legal rights that would bar a load serving entity from retaining ownership of any Transmission Provider's Interconnection Facilities or Stand Alone Network Upgrades it constructs. Such pre-existing agreements are grandfathered and are not subject to Order No. 2003.

2. Permits and Licensing Requirements

87. Order No. 2003 required the Transmission Provider to provide the Interconnection Customer with permitting assistance for the Generating Facility.^[30] Order No. 2003-A did not change this provision.

Rehearing Request

88. Cinergy notes that Order No. 2003-A rejected its request for rehearing which argued that the Commission should restrict this requirement to the permitting of the Transmission Provider or Transmission Owner's Interconnection Facilities or Network Upgrades.^[31] Cinergy requests clarification that, consistent with LGIA article 5.13, which addresses efforts by the Transmission Provider on behalf of the Interconnection Customer regarding lands of other property owners, the costs for any permitting assistance provided per the provisions of LGIA article 5.14 shall be the responsibility of the Interconnection Customer.

Commission Conclusion

89. Although Cinergy's argument is untimely and should have been presented in response to Order No. 2003, we will address the argument to provide clarification. Cinergy points to article 5.13, where the Commission requires the Interconnection Customer to pay for the Transmission Provider's efforts to obtain access to the lands of other property owners; however, the assistance provided under article 5.14 is different. This is because article 5.13 requires the Transmission Provider to participate, on the Interconnection Customer's behalf, in a process that may include lengthy and contentious proceedings and eminent domain proceedings.^[32] Article 5.14, on the other hand, requires that the Parties merely assist and cooperate in good faith in their efforts to secure the necessary permits. Such assistance is reciprocal and imposes costs to be borne by each Party. The Commission considers these costs a cost of doing business and is not requiring compensation.

90. Article 5.14 contains language suggesting that the Parties should amend their interconnection agreement to “specify the allocation of the responsibilities” to obtain permits, licenses, and authorizations. Because article 14.1 already contains language addressing the Parties' rights and responsibilities, we are amending article 5.14 to eliminate the suggestion that Parties should amend their interconnection agreement to allocate these responsibilities.

3. Tax Issues

a. Security Requirements

91. Order No. 2003 allowed the Transmission Provider to require the Interconnection Customer to provide security, but not after the former receives a private letter ruling from the Internal Revenue Service (IRS) determining that the payments from the Interconnection Customer to the Transmission Provider are not taxable as income to the Transmission Provider. Order No. 2003-A revised the policy and allowed the Transmission Provider to require security even if it secures such a ruling.^[33]

Rehearing Requests

92. Southern Company argues that the security requirement, which should reflect the cost consequences of any current tax liability as of January 1 of each year, is impractical and may leave the Transmission Provider with inadequate security. The IRS determines income based on the fair market value, which will be based on all facts at the time the “subsequent taxable event” takes place.^[34] Southern Company argues that it will be impractical to quantify a security amount that will approximate the fluctuating current tax liabilities as of January 1 of each year because the amount of recognizable income cannot be estimated when the interconnection agreement is signed. The new policy could leave the Transmission Provider at risk if the “cost consequences” are underestimated. Therefore, the Commission should restore the original Order No. 2003 language that allowed the Transmission Provider to require security based on estimated, maximum tax liability. Alternatively, additional clarification is needed on the correct methodology for calculating the security that the Transmission Provider may demand from the Interconnection Customer to determine the “current income tax liability as of January 1 of each year.”

93. Southern Company also argues that the pro forma OATT and its own OATT require that appropriate security be provided and maintained.^[35] It argues that the phrase “and maintain” should be added to LGIA article 5.17.3 to clarify that security not only must be provided, but also maintained.

94. EPSA argues that the Commission should not extend the Transmission Provider's right to require security beyond the point in time when a favorable private letter ruling from the IRS is obtained. Receipt of such a letter ruling significantly reduces the already small risk of tax liability, and thus, the need for security. As an example of the costs associated with the policy, EPSA explains that requiring the Interconnection Customer to post a $3 million credit (assuming a 30 percent tax gross-up ^[36] rate on a $10 million interconnection) would have an ongoing cost of $20,000 to $60,000 per year to secure the risk. The Commission should restore the Order No. 2003 policy. This would be consistent with the rulings in Order No. 2003-A that the security should track the cost consequences of current tax liability over time and that the security should be eliminated if the Transmission Provider collects an indemnification payment from the Interconnection Customer to cover the taxes payable.

Commission Conclusion

95. Order No. 2003-A concluded that it was unreasonable to allow the Transmission Provider to require security for the maximum amount of potential tax liability.^[37] Providing some security helps to address the risk that the Interconnection Customer will not be able to fulfill its full indemnification obligations should the interconnection credits be deemed taxable at some future time. Because the potential tax liability will change over time, it is reasonable that the required level of security also change over time. As Southern notes, there may be a situation where the amount of the payment for Interconnection Facilities deemed taxable can be based on the fair value of the property transferred under IRS policy or procedure. If so, the Interconnection Customer can be asked to pay the Transmission Provider only the present value of the cost consequences of the current tax liability based on that fair value, which also can change over time. The possibility that the potential tax payment may be based on the fair value of the property instead of some other measure does not justify allowing a security requirement to be imposed in excess of the cost consequences of the potential current tax liability determined as of January 1 of each year. Southern's request for rehearing on this point is denied. We, therefore, reiterate that it is excessive to require that an Interconnection Customer maintain security equal to the maximum theoretical tax liability calculated at the outset of the agreement.

96. Although Southern Company's argument is untimely and should have been presented in response to Order No. 2003, we will address the argument to provide clarification. Article 5.17.3 allows the Transmission Provider to require the Interconnection Customer to provide security for Interconnection Facilities “in an amount equal to the cost consequences of any current tax liability under” article 5.17. We believe it is unnecessary to specify that such security be “maintained” because this requirement is implicit in the provision's reference to “current tax liability.”

97. Order No. 2003-A explained that the security for tax liability in LGIA article 5.17.3 protects the Transmission Provider against the possibility that the IRS will change its policy or that there will be a subsequent taxable event.^[38] A private letter ruling from the IRS does not address these risks. While the ruling may show that the IRS does not currently consider these payments taxable, the risk remains that the IRS may change its policy or there will be a subsequent taxable event. Thus, we reject EPSA's request for rehearing.

b. Elimination of the Interconnection Customer's Right To Contest or Appeal Taxes

98. Order No. 2003 gave the Interconnection Customer the right to appeal, protest, seek abatement of, or otherwise protest a Government Authority's determination that payments made to the Transmission Provider are income subject to taxation. Order No. 2003-A gave to the Transmission Provider in LGIA articles 5.17.7 and 5.17.9 the sole discretion to protest such a determination.

Rehearing Requests

99. EPSA argues that the Commission should not have eliminated the Interconnection Customer's right to contest or appeal taxes for which the Interconnection Customer is ultimately liable. A Transmission Provider with multiple controversial tax matters might be able to trade off a concession on one matter for relief on another. In such a case, the Transmission Provider would have a fiduciary responsibility to its shareholders to concede to the IRS a tax issue for which it is fully indemnified. Also, the Interconnection Customer's obligation to pay for any tax controversies pursued on its behalf should ensure that it will not force the Transmission Provider to undertake frivolous contests and appeals.

100. Southern Company notes that although the Commission agreed that the Interconnection Customer's settlement obligation in LGIA article 5.17.7 should be subject to a tax gross-up to fully compensate the Transmission Provider for income taxes, it did not amend the article to confirm this intention.

Commission Conclusion

101. Order No. 2003-A allowed the Transmission Provider to determine whether and how to contest a Governmental Authority's tax determination.^[39] This is reasonable because otherwise the Interconnection Customer could force the Transmission Provider to pursue a claim that the Transmission Provider does not believe is valid. Allowing the Interconnection Customer to participate in the appeal process,^[40] however, should help to counteract the Transmission Provider's ability to negotiate with the IRS in a manner detrimental to the Interconnection Customer's interest.

102. We are amending LGIA article 5.17.7 in response to Southern Company's comment.

c. Transmission Credits for Tax Payments

103. Order No. 2003 provided that, if the Transmission Provider requires the Interconnection Customer to pay a tax gross-up, it will refund all tax gross-up amounts as transmission credits. Order No. 2003-A amended article 11.4.1 to clarify that the Transmission Provider need refund only the tax gross-up amounts associated with Network Upgrades.^[41]

Rehearing Request

104. Southern Company repeats the argument it made in response to Order No. 2003 that requiring the Transmission Provider to provide transmission credits for tax gross-up or other related tax payments in connection with Network Upgrades forces retail customers to subsidize the Interconnection Customer.

Commission Conclusion

105. Order No. 2003-A excepted from the total dollars refundable as transmission credits any amount related to the tax gross-up for Interconnection Facilities.^[42] Order No. 2003-A distinguished tax payments related to Network Upgrades from tax payments related to Interconnection Facilities.^[43] Because the tax payments related to Interconnection Facilities are not ultimately recoverable in transmission rates, the Interconnection Customer must reimburse the Transmission Provider for these payments to make the Transmission Provider whole. For this reason, pro forma LGIA article 11.4.1 excludes from the refundable total any costs related to tax payments for Interconnection Facilities. And because all costs associated with Network Upgrades are recoverable through transmission rates, including the cost of funding any related current tax liability, the Transmission Provider should refund to the Interconnection Customer as transmission credits those tax gross-up or other related tax payments initially funded by the Interconnection Customer.^[44]

4. Applicable Reliability Council Operating Requirements

106. LGIA article 9.1 requires the Interconnection Customer and the Transmission Provider to comply with the Applicable Reliability Council operating requirements. The Transmission Provider may impose supplemental interconnection requirements not specifically required by the Applicable Reliability Council, particularly those related to system protection and safety, if the Applicable Reliability Council requirements specifically allow such requirements. The Transmission Provider must also impose such requirements on itself and all other Interconnection Customers, including its Affiliates.

Rehearing Request

107. NRECA complains that the Transmission Provider's inability to impose supplemental interconnection requirements if they are not referenced in the Applicable Reliability Council documents creates significant risks to the safety and reliability of the Transmission Provider's Transmission System.

Commission Conclusion

108. We deny NRECA's request for rehearing. Order No. 2003-A stated that most operational requirements are already contained in or referenced in the Applicable Reliability Council's standards. Where such operational requirements are not specifically contained in or referenced in those standards, we strongly encourage the Transmission Provider to seek to have such requirements codified. As provided in Order No. 2003-A, the Transmission Provider is free to propose variations, provided that it can demonstrate that they are consistent with or superior to the pro forma LGIP.

5. Power Factor Design Criteria

109. LGIA article 9.6.1 requires the Interconnection Customer to design the Generating Facility to maintain a power factor at the Point of Interconnection within the range of 0.95 leading to 0.95 lagging, unless the Transmission Provider establishes different requirements that apply to all generators in its Control Area on a comparable basis. This provision does not apply to wind generators.

Rehearing Request

110. SoCal Edison argues that wind generators should not be exempted from the power factor requirement. Such an exemption may lead to uncontrolled voltage problems. It also contends that one commenter misled the Commission when it asserted that wind generators are unable to meet the power factor requirement; wind generating facilities have been able to meet this requirement for many years.

Commission Conclusion

111. Order No. 2003-A adopted Appendix G of the LGIA (Requirements of Generators Relying on Newer Technologies) as a placeholder for future interconnection requirements specific to wind and other alternative technologies.^[45] The Commission included Appendix G in the LGIA because (1) a particular LGIA or LGIP requirement might not be suitable for those technologies and (2) those technologies might call for a slightly different approach to interconnection. This includes the power factor design criteria requirement in LGIA article 9.6.1.

112. On September 24, 2004, Commission staff held a conference to discuss the technical requirements for the interconnection of wind generators and other alternative technologies, the needs of transmission operators for voltage support from large wind farms, and the need for creating specific requirements in Appendix G to accommodate their interconnection.^[46] Among other things, the conferees spoke about whether the power factor design criteria in Order No. 2003-A are reasonable for these technologies. The Commission is still evaluating the transcript of the conference and comments filed afterwards. Until the Commission decides how to proceed based upon the record in that proceeding, it will continue to exempt wind generators from the power factor design criteria in LGIA article 9.6.1.

6. Payment for Reactive Power

113. LGIA article 9.6.3 requires the Transmission Provider to pay the Interconnection Customer for reactive power the Interconnection Customer provides or absorbs when the Transmission Provider asks the Interconnection Customer to operate its Generating Facility outside a specified power factor range, provided that if it pays its own or affiliated generators for reactive power service within the specified range, it must also pay the Interconnection Customer. Payments are to be under the Interconnection Customer's rate on file with the Commission, unless service is under a Commission-approved RTO or ISO tariff. Order 2003-A clarified that there is nothing in LGIA article 9.6.3 that requires the Interconnection Customer to run its Generating Facility solely to provide reactive power to the Transmission Provider simply because it has an interconnection agreement with the Transmission Provider.

Rehearing Requests

114. The Commission stated in Order No. 2003-A that there is nothing in LGIA article 9.6.3 that requires the Interconnection Customer to run its Generating Facility solely to provide reactive power to the Transmission Provider simply because it has an interconnection agreement with the Transmission Provider. AEP notes that in Order No. 2003, the Commission agreed with Calpine “* * * that if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range it must also pay the Interconnection Customer.” These two statements are inconsistent, claims AEP. The Transmission Provider is required to offer “Reactive Power and Voltage Control from Generation Resources Service” (Schedule 2 Service) under Order No. 888. The Transmission Provider thus has a responsibility to keep its own generators on line and be able to provide reactive power to allow delivery service on demand anywhere on its electric system. AEP notes that the Transmission Provider is generally paid for providing this service to retail customers through a bundled rate. The cost of providing this service to wholesale customers is recovered through transmission rates—not through a payment to the Transmission Provider's generators, as Calpine had suggested. In contrast, the Interconnection Customer has no such obligation. AEP asks the Commission to clarify that a Transmission Provider that is required to provide Schedule 2 Service, and that charges for it accordingly, is not “paying its own generators” for reactive power within the established range and thus triggering a responsibility to pay the Interconnection Customer in the same manner.

115. AEP also seeks clarification that Order No. 2003-A does not prejudge the manner in which the Interconnection Customer should be paid for providing reactive power service.

116. Calpine, EPSA, and PSEG argue that the Interconnection Customer's right to be paid for providing reactive power should not hinge on whether the Transmission Provider pays its own or its Affiliate's generators. They contend that their generators provide reactive power service that is similar to Schedule 2 Service and, therefore, they should receive comparable compensation. They argue that they should be paid for reactive power provided, whether within or outside of the established power factor range. They also argue that the Interconnection Customer incurs an opportunity cost when its Generating Facility must provide reactive power when it reduces real power output. Finally, they state that some regions have mechanisms to compensate for providing reactive power ^[47] and seek clarification that LGIA article 9.6.3 will not disturb those arrangements.

117. Reliant states that Order No. 2003-A was an improvement over Order No. 2003. However, it contends that the Commission should reinstate the Advance Notice of Proposed Rulemaking (ANOPR) language, which provided that an Interconnection Customer could file a tariff with the Commission to secure compensation for reactive power service. Reliant states that the ANOPR language is balanced and negotiated.

Commission Conclusion

118. We disagree with AEP's assertion that there is a contradiction in the Commission's clarifications in Order No. 2003-A. The intent of the first clarification was to ensure that the Transmission Provider could not demand that the Interconnection Customer operate its Generating Facility solely to provide reactive power. The Interconnection Customer, however, may be required by the Transmission Provider to provide reactive power from time to time when its Generating Facility is in operation.

119. As to the second clarification, we further clarify that while 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. Therefore, the “trigger” to compensate the Interconnection Customer for providing this service is not eliminated, as AEP argues. We require that an Interconnection Customer be treated comparably with the Transmission Provider and its Affiliates. Accordingly, we are requiring the Transmission Provider to pay the Interconnection Customer for providing reactive power within the specified range if the Transmission Provider so pays its own generators or those of its Affiliates.

120. We also clarify that Order No. 2003-A does not prejudge how the Interconnection Customer is to be compensated for providing reactive power. LGIP article 9.6.3, as revised in Order No. 2003-A, states that such payments are to be provided under a filed rate schedule unless service is provided under a Commission-approved RTO or ISO tariff.

121. We also clarify that there is nothing in LGIA article 9.6.3 that disturbs any present arrangements for reactive power compensation.

122. In response to Reliant, we decline to substitute the referenced ANOPR language because the ANOPR language was, at best, vague.

7. Security

123. LGIA article 11.5 requires the Interconnection Customer, among other things, to provide a form of security “reasonably acceptable to Transmission Provider” and “consistent with the Uniform Commercial Code.” The security shall be “in an amount sufficient to cover the costs for constructing, procuring and installing the applicable portion of Transmission Provider's Interconnection Facilities, Network Upgrades, or Distribution Upgrades and shall be reduced on a dollar-for-dollar basis for payments made to Transmission Provider for these purposes.”

Rehearing Request

124. Southern Company argues that LGIA article 11.5 should include an obligation to maintain security. Requiring the amount of security to be automatically and immediately reduced on a dollar-for-dollar basis for payments made to the Transmission Provider under the interconnection agreement is arbitrary and discriminatory, as it ignores the risk this imposes on the Transmission Provider under bankruptcy law. Specifically, section 547 of the U.S. Bankruptcy Code provides that a Debtor in Possession or a Bankruptcy Trustee may avoid preferential transfers made by the bankrupt entity on or within 90 days before the filing of the relevant bankruptcy petition. If payments to the Transmission Provider could be deemed “preferential,” the Transmission Provider needs the protection given by the security required under article 11.5 to be maintained and not reduced until such payment is not subject to being avoided, set aside, or returned under section 547. Language to this effect should be added to article 11.5; otherwise the Transmission Provider would have no reasonable prospect of being repaid for any payments required to be returned or set aside under bankruptcy law, and the Transmission Provider would also incur legal expenses associated with the defense of such claims.

Commission Conclusion

125. We reject Southern Company's requests for rehearing. Although Southern Company's argument regarding the maintenance of security is untimely and should have been raised in response to Order No. 2003, we will address the argument here to provide clarification. The change Southern Company proposes is unnecessary. Article 11.5 already requires the security provided by the Interconnection Customer to be “sufficient to cover” the relevant costs and that a letter of credit or surety bond specify “a reasonable expiration date.” ^[48] Therefore, Southern Company's concern that an Interconnection Customer would not be required to maintain the security is misplaced, as the article requires that “sufficient” security be maintained for a “reasonable” period of time.

126. Southern Company's arguments regarding bankruptcy were presented and rejected in Order No. 2003-A,^[49] and Southern Company offers no new arguments.

8. Assignment

127. LGIA article 19.1 provides that the written consent of the non-assigning party is ordinarily required to assign the interconnection agreement. However, the Interconnection Customer may assign the agreement, without the consent of the Transmission Provider, for collateral security purposes to aid in financing the Generating Facility (i.e., collateral assignment).

Rehearing Request

128. Southern Company argues that several revisions to LGIA article 19.1 are needed to conform to the Uniform Commercial Code and to the OATT. It seeks clarification that a party is not relieved of its obligations if another party assigns the agreement. It adds that the Interconnection Customer only has the right to assign the interconnection agreement to another eligible customer. Southern Company proposes that the Commission revise article 19.1 to subject the collateral assignment of the agreement to the prior written consent of the Transmission Provider if the collateral assignee is not an eligible customer. Such consent is a suitable way for the Transmission Provider to (1) obtain the collateral assignee's agreement and (2) transfer the interconnection agreement in a foreclosure sale only to an eligible customer.

129. Southern Company also argues that the Commission should revise LGIA article 19.1 to address risks associated with adverse claims and multiple assignments of the Interconnection Customer's rights. It states that the exercise of assignment rights by an assignee should be made subject to the Transmission Provider not having received a contrary court order or notice of an unresolved contrary claim. Otherwise, the Transmission Provider could be in violation of a court order or have to resolve which claimant is legally entitled to exercise assignment rights. Southern Company further claims that this requirement is superior to the pro forma LGIA in that it helps assure that the proper assignee receives the benefits of the LGIA and that a Transmission Provider does not incorrectly recognize an improper or subordinate assignee as being entitled to the Interconnection Customer's rights under the LGIA.

130. Southern Company also proposes that the Transmission Provider have the right to require the collateral assignee or its purchaser in foreclosure to assume the interconnection agreement and also cure any existing defaults before receiving the benefits of an assignee. It states that if a defaulting Interconnection Customer had not assigned its rights, the Transmission Provider would be free to require the Interconnection Customer to either cure its defaults or terminate the agreement. This “perform” or “get out of the queue” policy benefits competing Interconnection Customers and potential competitors. The Transmission Provider should not have to provide service to a collateral assignee or purchaser in foreclosure if uncured defaults exist or amounts are owed in arrears after the application of any security provided to the Transmission Provider by the assignor. Southern Company argues that to rule otherwise could result in discrimination against the Transmission Provider and other Interconnection Customers in the queue or desiring to join the queue if the Transmission Provider continues to provide service, despite not being made whole.

Commission Conclusion

131. LGIA article 19.1 already states that an assignment does not relieve a Party of its obligations under the interconnection agreement. As to Southern Company's concern about the assignee being an eligible customer, article 19.1 already requires that the assignee have the “legal authority and operational ability to satisfy the obligations of the assigning Party.” This ensures that the assignee is able to meet the obligations under the agreement. And if the assignee is unable to meet the obligations, article 19.1 requires the assignor to fulfill the obligations under the agreement. We are not requiring that the assignee be an “Eligible Customer” under Southern Company's OATT because Southern Company has not explained why this designation should be required of an assignee of an interconnection agreement. In response to Southern Company's arguments regarding collateral assignment and the assignment of debts, the Commission rejected these arguments in Order No. 2003-A,^[50] and Southern Company has offered no new information or arguments that prompt us to change that conclusion.

9. Disclosure of Confidential Information

132. LGIA article 22.1.10 provides that a Party must provide any information requested by the Commission or its staff, including Confidential Information. Order No. 2003-A modified article 22 to require a Party to provide requested information to a state regulator conducting a confidential investigation, even if the Party otherwise would be required to maintain this information in confidence.^[51]

Rehearing Request

133. EPSA notes that Order No. 2003-A revised LGIA articles 22.1.10 and 22.1.11, deleting the requirement that a Party be notified when another Party receives a request from a state regulator for Confidential Information.^[52] EPSA states that it has no objection to state regulators receiving Confidential Information to which they are entitled, but argues that fundamental fairness and due process should preclude the secret release of Confidential Information. The issue of providing state regulators with access to Confidential Information is under discussion in other forums and, EPSA concludes, any policy developed in this proceeding should be consistent with how the issue is addressed elsewhere. As an example of one forum, EPSA notes that the PJM Electricity Markets Committee (EMC) held several stakeholder meetings to develop the principles under which state regulators should be given access to Confidential Information. The principles developed by the EMC with the input of the state commissions, and which the PJM Members Committee approved, address a wide range of issues and require notice of the request to the Party that provided the Confidential Information. The Commission should reverse the conclusion reached in Order No. 2003-A and, consistent with the PJM approach, return to its Order No. 2003 policy of requiring notice to a Party before another Party releases Confidential Information.

Commission Conclusion

134. We deny EPSA's rehearing request, but provide clarification. In Order No. 2003-A, the Commission explained that it was deleting the requirement that a Party be notified when another Party receives a request for Confidential Information from a state regulator because a state regulator should have the same rights to Confidential Information as this Commission. We clarify here that the state regulator has the right to request Confidential Information from one Party (without notification to the other Party) only when the state commission has the legal authority to do so. The pro forma LGIA should not be interpreted as granting states access to Confidential Information where the state lacks authority under state law. Nor should the pro forma LGIA be interpreted as barring or limiting a state's access to information, or the procedures through which a state may request such information, where such access is permitted under state law. We are modifying article 22.1.10 to clarify this point. As for EPSA's argument regarding PJM, under the “independent entity variation” standard, an RTO like PJM has greater flexibility to propose variations from the pro forma LGIP and LGIA, including variations to those provisions applicable to the release of Confidential Information to states. As a result, the RTO or ISO may propose to treat Confidential Information differently from the approach taken in Order No. 2003, to better suit regional needs.

E. Issues Related to the Large Generator Interconnection Procedures

1. Scoping Meeting and OASIS Posting

135. LGIP section 3.3.4 requires the Transmission Provider and the Interconnection Customer to hold a Scoping Meeting within 30 Calendar Days from receipt of the Interconnection Request to discuss the proposed interconnection. If the Transmission Provider intends to hold a Scoping Meeting with an Affiliate, it is required to announce the meeting on its OASIS site, transcribe the Scoping Meeting, and make copies of the transcript available to the public upon request. LGIP section 3.4 requires the Transmission Provider to post on its OASIS a list of all Interconnection Requests. It must post information such as the location of the interconnection and the Generating Facility's projected In-Service Date. The list is not to disclose the identity of the Interconnection Customer until the latter executes an interconnection agreement.

Rehearing Request

136. Southern Company claims that the requirement in LGIP section 3.4 to not disclose the identity of the Interconnection Customer on OASIS conflicts with the requirement to give notice of a meeting with an Affiliate. The requirement to disclose the identity of the Affiliate is discriminatory because it does not apply to other competitors. This puts the Affiliate at a competitive disadvantage. Southern Company also claims that the requirement to notice Scoping Meetings with the Affiliate conflicts with LGIP section 3.4, which requires that the identity of the Interconnection Customer not be disclosed until the Interconnection Customer has executed an interconnection agreement. It asks that the notice and transcript requirements be eliminated or that the Commission require all Scoping Meetings to be noticed and transcribed.

Commission Conclusion

137. We deny Southern Company's request for rehearing. An affiliated Interconnection Customer and one that is not an Affiliate of the Transmission Provider are not similarly situated. That is, of course, one of the reasons the Commission created the Code of Conduct ^[53] and Standards of Conduct ^[54] for affiliated Interconnection Customers. Order No. 2003-A balanced the need to treat affiliated and nonaffiliated Interconnection Customers alike with the need to adhere to the Code of Conduct and Standards of Conduct requirements. Finally, we agree with Southern Company that there is a conflict between sections 3.3.4 and 3.4 of the pro forma LGIP, and are revising the latter to show that the restriction of section 3.4 (not to disclose the identity of the Interconnection Customer) does not apply to an affiliated Interconnection Customer.

F. Ministerial Changes to the Pro Forma LGIP and LGIA

138. Since Order No. 2003-A 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 B, which also reports changes to the pro forma LGIP and LGIA that reflect conclusions in this order.

G. Compliance

139. 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 revisions to the pro forma LGIP and LGIA contained herein on the effective date of this order. The Order No. 2003 compliance process also required each non-independent Transmission Provider to make a ministerial filing to include its pro forma LGIP and LGIA in its next filing with the Commission. But because it has taken longer than anticipated for all non-independent Transmission Providers to make the necessary changes to their OATTs, here we adopt different compliance procedure. We are requiring all public utilities that own, control, or operate interstate transmission facilities to adopt the revisions to the pro forma LGIP and pro forma LGIA that appear in this order within 60 days after the issuance of this order by the Commission. A non-independent Transmission Provider that already has amended its OATT to add the pro forma LGIP and pro forma LGIA should submit revised tariff sheets incorporating the changes contained in this order. A non-independent Transmission Provider that has not yet made the ministerial filing to reflect the fact that its OATT now follows Order No. 2003, or that has not yet filed the revisions to the pro forma LGIP or LGIA that appeared in Order No. 2003-A, must take the necessary steps to ensure that its OATT contains the pro forma LGIP and pro forma LGIA including the revisions in this order within 60 days after issuance of this order by the Commission. Within the same time frame, each RTO or ISO also must submit either revised tariff sheets incorporating changes contained in this order, or an explanation under the independent entity variation standard as to why it is not adopting each change.

140. Also, in Order No. 2003 the Commission required that for any non-conforming LGIAs submitted for approval, the Transmission Provider “should clearly indicate where the agreement does not conform to its standard Interconnection Agreement, preferably through red-lining and strikeout.” ^[55] We clarify here that each Transmission Provider submitting a non-conforming agreement for Commission approval must explain its justification for each nonconforming provision and provide a redline document comparing the nonconforming agreement to the effective pro forma LGIA.

IV. Information Collection Statement

141. Order No. 2003-B contains information collection requirements for which the Commission obtained approval from the Office of Management and Budget (OMB).^[56] Given that this order makes only minor changes to Order Nos. 2003 and 2003-A, OMB approval for this order is not necessary. However, the Commission will send a copy of this order to OMB for informational purposes.

V. Regulatory Flexibility Act Certification

142. The Regulatory Flexibility Act (RFA) ^[57] requires rulemakings to contain either (1) a description and analysis of the effect that the proposed or Final Rule will have on small entities or (2) a certification that the rule will not have a significant economic effect on a substantial number of small entities. In Order Nos. 2003 and 2003-A, the Commission certified that the Final Rule would not have a significant economic effect on a substantial number of small entities.^[58]

Rehearing Request

143. NRECA repeats the argument made previously that the Commission has underestimated the number of utilities affected by Order No. 2003. It asks the Commission to clarify that a cooperative with an existing Order No. 888 waiver will not lose that waiver as soon as it receives an Interconnection Request. It also requests clarification that if an Interconnection Customer seeks Interconnection Service from a small utility that believes that it would be overly burdened by the requirements of Order Nos. 2003 and 2003-A, the small utility may seek waiver of those requirements from the Commission.

Commission Conclusion

144. The Commission stated in Order No. 2003 that it is sympathetic to the needs of small entities.^[59] However, NRECA raises no new arguments that it did not raise in its rehearing request to Order No. 2003. We therefore reject its assertion that the Commission's RFA analysis was unrealistic.^[60]

145. As to its request for clarification, NRECA is correct that an entity may at any time request waiver of the Commission's regulations. However, as the Commission stated in Order No. 2003, waivers must be made on a case-by-case basis.^[61] Absent the granting of such a waiver request, however, NRECA is correct that a request for jurisdictional service (including Interconnection Service) would mean that a utility with a conditional waiver of Order No. 888 would lose that waiver.

VI. Document Availability

146. 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.

147. User assistance is available for eLibrary and the Commission's Web site 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 [e-mail]

VII. Effective Date

148. Changes to Order Nos. 2003 and 2003-A made in this order on rehearing will become effective on January 19, 2005.

Regulatory Text

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.

Appendix A

Petitioner Acronyms

AEP—American Electric Power Service Corp.

Calpine—Calpine Corporation

Cinergy—Cinergy Services, Inc.

EPSA—Electric Power Supply Association

Intergen—Intergen Services, Inc. and Tenaska, Inc.

NRECA—National Rural Electric Cooperative Association

NYISO—New York Independent System Operator, Inc. and the New York Transmission Owners

PSEG—PSEG Companies and GWF Energy LLC

Reliant—Reliant Resources, Inc.

SoCal Edison—Southern California Edison Company

Southern Company—Southern Company Services, Inc.

SWTransco—Southwest Transmission Cooperative, Inc.

TAPS—Transmission Access Policy Study Group

Appendix B

Changes To The Pro Forma LGIP and LGIA

Large Generator Interconnection Procedures (LGIP)
Section 1—Definition of “Force Majeure”	Change “caused” to “cause”.
Section 1—Definition of Network Resource Interconnection Service	Change “in the same manner as all other Network Resources” to “in the same manner as Network Resources”.
Section 3.2.2.1	Remove two instances of “all other” in this section: “Transmission Provider must conduct the necessary studies and construct the Network Upgrades needed to integrate the Large Generating Facility (1) in a manner comparable to that in which Transmission Provider integrates its generating facilities to serve native load customers; or (2) in an ISO or RTO with market based congestion management, in the same manner as Network Resources. Network Resource Interconnection Service allows Interconnection Customer 's Large Generating Facility to be designated as a Network Resource, up to the Large Generating Facility's full output, on the same basis as existing Network Resources interconnected to Transmission Provider's Transmission System, and to be studied as a Network Resource on the assumption that such a designation will occur.”
Section 3.2.2.2	At the end of this section, add the following text: “The Transmission Provider may also study the Transmission System under non-peak load conditions. However, upon request by the Interconnection Customer, the Transmission Provider must explain in writing to the Interconnection Customer why the study of non-peak load conditions is required for reliability purposes.”
Section 3.4	In the third sentence, change “The list will not * * *” to “Except in the case of an Affiliate, the list will not * * *”
Section 5.2	In the second sentence, change text to read: “* * * to the Interconnection Customer, as appropriate.”
Section 7.2	In the third paragraph, second sentence, change text to read: “For the purpose of this section 7.2, * * *
Section 7.6	Change the first sentence to read: “If Re-Study of the Interconnection System Impact Study is required due to a higher queued project dropping out of the queue, or a modification of a higher queued project subject to Section 4.4, or re-designation of the Point of Interconnection pursuant to section 7.2 Transmission Provider shall notify Interconnection Customer in writing.”
Section 9	In the second paragraph, second sentence, change “party” to “Party.”
Section 11.1	In the second sentence, change “” Interconnection Customer shall tender a draft LGIA, together with draft appendices completed to the extent practicable” to “” Transmission Provider shall tender a draft LGIA, together with draft appendices.”
Section 11.2	In the third sentence, change “* * * tender of the LGIA pursuant to section 11.1 * * *” to “* * * tender of the draft LGIA pursuant to section 11.1 * * *” In the fifth sentence, change “* * * section 13.5 within sixty days of tender of completed draft of the LGIA appendices” to “* * * section 13.5 within sixty (60) Calendar Days of tender of draft LGIA.”
Section 13.4	In the second paragraph, change the reference to “OATT” to “Tariff.”
Section 13.6.2	In the first sentence, change the text to read: “* * * within thirty (30) Calendar Days of receipt. * * *” In the second sentence, change “OATT” to “Tariff.”
Large Generator Interconnection Agreement (LGIA)
Article 1—Definition of “Force Majeure”	Change “caused” to “cause”.
Article 1—Definition of Network Resource Interconnection Service	Change “in the same manner as all other Network Resources” to “in the same manner as Network Resources”.
Recitals	Change the last word from “(OATT)” to “(Tariff).”
Article 4.1.2.2	Remove “other” from the following sentence in the first paragraph: “Although Network Resource Interconnection Service does not convey a reservation of transmission service, any Network Customer under the Tariff can utilize its network service under the Tariff to obtain delivery of energy from the interconnected Interconnection Customer's Large Generating Facility in the same manner as it accesses Network Resources.” Remove “all other” from the following sentence in the second paragraph: “In the event of transmission constraints on Transmission Provider's Transmission System, Interconnection Customer's Large Generating Facility shall be subject to the applicable congestion management procedures in Transmission Provider's Transmission System in the same manner as Network Resources.”
Article 5.14	Delete the first two sentences of this article and replace them with the following sentence: “Transmission Provider or Transmission Owner and Interconnection Customer shall cooperate with each other in good faith in obtaining all permits, licenses, and authorizations that are necessary to accomplish the interconnection in compliance with Applicable Laws and Regulations.”
Article 5.17.7	In the second paragraph, before the last sentence, add this new sentence: “The settlement amount shall be calculated on a fully grossed-up basis to cover any related cost consequences of the current tax liability.”
Article 5.17.8(ii)	Add the word “interest” to the beginning of this subsection, revising it to read: “(ii) interest on any amount paid * * * Reference to 18 CFR 35.19a(a)(2)(ii) should be changed to 18 CFR 35.19a(a)(2)(iii).
Article 11.4.1	In the second paragraph of this article, replace “(2) declare in writing that Transmission Provider or Affected System Operator will continue to provide payments to Interconnection Customer pursuant to this subparagraph until all amounts advanced for Network Upgrades have been repaid.” with “(2) declare in writing that Transmission Provider or Affected System Operator will continue to provide payments to Interconnection Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, or develop an alternative schedule that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not previously repaid; however, full reimbursement shall not extend beyond twenty (20) years from the Commercial Operation Date.” Add the following sentence to the last paragraph of this article: “Before any such reimbursement can occur, the Interconnection Customer, or the entity that ultimately constructs the Generating Facility, if different, is responsible for identifying the entity to which reimbursement must be made.” Reference to 18 CFR 35.19a(a)(2)(ii) should be changed to 18 CFR 35.19a(a)(2)(iii).
Article 18.1	Capitalize each reference to “Indemnifying Party.”
Article 18.3.5	Revise the second sentence to read “* * * thirty (30) Calendar Days advance written notice * * *”
Article 18.3.6	In the first sentence, change “polices” to “policies.”
Article 19.1	In the second sentence, change “party's” to “Party's.”
Article 22.1.10	Revise the last sentence to read: “Requests from a state regulatory body conducting a confidential investigation shall be treated in a similar manner if consistent with the applicable state rules and regulations.”
Article 28.1.2	In the first sentence, change “party” to “Party.”

Nora Mead BROWNELL, Commissioner dissenting in part:

On rehearing of Order No. 2003, the Commission made three critical revisions to the procedures by which Interconnection Customers obtain cost recovery for their up-front funding of Network Upgrades. Specifically, the Commission eliminated the following key protections afforded to Interconnection Customers: (1) The ability to apply credits to transmission service taken from sources other than the specific interconnecting generating facility; (2) the ability to obtain full reimbursement within five years; and (3) the ability to obtain reimbursement for upgrades made to adjacent transmission systems (so-called “Affected Systems”) on which the Interconnection Customer does not take transmission service. I am now convinced that the Commission erred in making these revisions, and that today's order, by making the minor modification of requiring full reimbursement after twenty years, does not go far enough to correct that error.

In Order No. 2003-A, the Commission's primary justification for modifying the cost recovery provisions was that the changes were necessary to ensure that Interconnection Customers make efficient decisions on where to site their generating facilities. Rehearing petitioners make a convincing argument that there is no reason to believe that these modifications will have any appreciable effect on siting decisions, which are driven by state and local siting regulations and fuel accessibility needs. Instead of attempting to rebut this argument or develop a substitute rationale, the majority simply treats petitioners' argument as an admission that Network Upgrade costs are small and, therefore, concludes that Interconnection Customers have no basis to complain about bearing those costs. However, the relative size of Network Upgrade costs compared to other siting costs is irrelevant to whether it is fair to put Interconnection Customers at substantial risk of never obtaining full reimbursement for upgrades that benefit all customers.

The Commission has been quite explicit that up-front payment of Network Upgrades costs by an Interconnection Customer is simply a “financing mechanism that is designed to facilitate the efficient construction of Network Upgrades,” and is “not a rate for interconnection or transmission service.” ^[1] As the Commission explained in Order No. 2003-A, “the Transmission Provider's right to charge for transmission service at the higher of an embedded cost rate, or an incremental rate designed to recover the cost of the Network Upgrades, provides the Transmission Provider with a cost recovery mechanism that ensures that native load and other transmission customers will not subsidize service to the Interconnection Customer.” ^[2] The primary purpose of having the Interconnection Customer finance the Network Upgrades was to alleviate any delay that might result if the Transmission Provider were forced to secure funding.^[3]

The issue, then, is whether we have exposed the Interconnection Customer to undue risk in its role as financier of Network Upgrades that benefit the system as a whole. I believe that we have. Therefore, I would grant rehearing and return to the cost recovery policies we announced in Order No. 2003.

Nora Mead Brownell

Footnotes

1.  Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, Final Rule, 68 FR 49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146 (2003.)

2.  Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003-A, Order on Rehearing, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ¶ 31,160 (2004).

3.  Thirteen petitioners filed requests for rehearing of Order No. 2003-A. See Appendix A.

4.  Provisions of the LGIP are referred to as “sections,” whereas provisions of the LGIA are referred to as “articles.” Capitalized terms used in this order have the meanings specified in section 1 of the pro forma LGIP and article 1 of the LGIA, as amended herein, or the OATT. Generating Facility means the device for which the Interconnection Customer has requested interconnection. The owner of the Generating Facility is the Interconnection Customer. The entity with which the Generating Facility is interconnecting is the Transmission Provider. A Large Generator is any energy resource having a capacity of more than 20 megawatts, or the owner of such a resource.

5.  In another rulemaking, the Commission proposed a separate set of procedures and an agreement applicable to Small Generators (defined as any energy resource having a capacity of no larger than 20 MW, or the owner of such a resource) that seek to interconnect with facilities of jurisdictional Transmission Providers that are already subject to an OATT. See Standardization of Small Generator Interconnection Agreements and Procedures, Notice of Proposed Rulemaking, 60 FR 49974 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 32,572 (2003).

6.  Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, 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), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002) (TAPS v. FERC).

7.  Network Upgrades reside on the Transmission Provider's side of the Point of Interconnection with the Transmission Provider's Transmission System.

8.  16 U.S.C. 2601 et seq. (2000).

9.  Order No. 2003-A at P 735.

10.  See also Detroit Edison Co. v. FERC, 334 F. 3d 48, 51 (D.C. Cir. 2003).

11.  Order No. 2003-A at P 735.

12.  As explained in Order No. 2003 at P 803, the term “distribution” is usually used to refer to lower voltage lines that are not networked and that carry power in one direction. The term “local distribution” is a legal term, and under Section 201(b)(1) of the FPA, the Commission lacks jurisdiction over “local distribution” facilities. The court in Detroit Edison Co. v. FERC, 334 F.3d 48 (D.C. Cir. 2003) (Detroit Edison), used the terms “distribution” and “local distribution” interchangeably. The court recognized that certain “distribution” and “local distribution” interchangeably. The court recognized that certain “distribution” facilities serve a dual use function (i.e., they are used for both wholesale and retail sales) and that there could be Commission-jurisdictional uses of “local distribution” facilities; in such cse, the court viewed the Commission's jurisdiction as extending only tot he use of the facilities for purposes of the wholesale transaction. Detroit Edison, 334 F.3d at 51. Consistent with Detroit Edison, the Final Rule applies to a dual use facility only if the facility is already part of a Commission-filed OATT and the interconnection is for the purpose of making a jurisdictional sale of electric energy for resale in interstate commerce.

We note that some facilities labeled by a utility as “distribution” may actually carry out a transmission rather than a local distribution function and thus would be subject to Commission jurisdiction for accommodating wholesale as well as unbundled retail transactions. In this circumstance, we do not view the label as controlling.

13.  Order No. 2003 at P 804; Order No. 2003-A at P 730, 736.

14.  See, e.g., Calpine, EPSA, Integen, PSEG, and Reliant.

15.  Calpine also states that, as a member of EPSA, it endorses and supports EPSA's request for rehearing of Order No. 2003-A.

16.  Paragraph 675 stated that credits are to be applied in full to reservation charges set forth in OATT schedule 7—Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service, schedule 8—Non-Firm Point-to-Point Transmission Service, and to the basic transmission charges based on Attachment H-Annual Transmission Revenue Requirement for Network Integration Transmission Service.

17.  Southern Company states that its request for rehearing does not specifically address all of the requirements and issues in Order No. 2003-A that it addressed in its Request for Rehearing filed in response to Order No. 2003. Therefore, instead of restating all of the arguments made in the request for rehearing, Southern Company incorporates them by reference. Because the FPA requires that applications for rehearing “set forth specifically the ground or grounds upon which such application is based, “set forth specifically the ground or grounds upon which such application is based, “16 U.S.C. § 8251 (2000), Southern Company's arguments from its request for rehearing of Order No. 2003 have been considered in this order only to the extent the arguments were specifically presented in its request for rehearing of Order No. 2003-A.

18.  See, e.g., Southern Company Services, Inc., 107 FERC ¶ 61,317, order on reh'g and compliance, 109 FERC ¶ 61,014 (2004); South Carolina Electric & Gas Co., 108 FERC ¶ 61,018 (2004); Florida Power & Light Co., 108 FERC ¶ 61,239 (2004).

19.  See also infra Part III.D.4 (explaining that a non-independent Transmission Provider on compliance may propose additional operating requirements that are not codified or referencedinit Applicable Reliability council's standards.)

20.  Order No. 2003-A at P 663-667.

21.  Order No. 888-A at 30,230.

22.  Order No. 2003-A at P 53.

23.  Id. at P 785; see also Delmarva Power & Light Company, 106 FERC ¶ 61,290 (2004) (addressing load-side interconnections).

24.  New York Independent System Operator, Inc., 108 FERC ¶ 61,159 (2004), reh'g_pending (NYISO); ISO New England, 109 FERC ¶ 61,147 (2004).

25.  For example, the RTO or ISO conducts all studies, determines costs, identifies necessary Network Upgrades, and controls all aspects of the interconnection process.

26.  See New England Power Pool, 109 FERC ¶ 61,155 at P 27, 74 (2004); see also NYISO at P 123-124. In NYISO, the Commission conditionally waived the requirement that the Transmission Owners adopt the pro forma LGIP and LGIA for transmission facilities over which Transmission Owners retained operational control. Waiver was granted due in part to the commitment by the Transmission Owners to relinquish operational control over the relevant facilities to the RTO or ISO upon Commission issuance of the NYISO order.

27.  Order No. 2003-A, LGIA article 5.2(9).

28.  Order No. 2003 at P 230.

29.  See, e.g., Virginia Electric & Power Co., 94 FERC ¶ 61,164 at 61,589 (2001) (explaining that it is appropriate for the Transmission Provider to construct and own Transmission System facilities, but stopping short of requiring ownership by the Transmission Provider), order on remand on other grounds sub nom. American Electric Power Service Corp., 99 FERC ¶ 61,177 (2002), order on clarification, 100 FERC ¶ 61,150 (2002); Cambridge Electric Light Co., 96 FERC ¶ 61,205 at 61,874 (2001) (refusing to require generator ownership of certain Interconnection Facilities because of questions of reliability and liability).

30.  LGIA article 5.14.

31.  Order No. 2003-A at P 303.

32.  Order No. 2003 at P 251; Order No. 2003-A at P 300.

33.  Order No. 2003-A at P 343-344.

34.  A “subsequent taxable event” is an occurrence that makes taxable payments a Transmission Provider had concluded were not taxable; it creates a current tax liability for the Transmission Provider.

35.  Citing pro forma OATT section 11, Southern Company OATT section 11(b).

36.  A tax gross-up for income taxes is a dollar amount calculated to determine the Interconnection Customer's payment needed to indemnify the Transmission Provider for any current tax liability associated with payments the Interconnection Customer makes for the Transmission Provider's Interconnection Facilities and Network Upgrades.

37.  Order No. 2003-A at P 343.

38.  Id. at P 344.

39.  Id. at P 372.

40.  LGIA article 5.17.7 requires the Transmission Provider to keep the Interconnection Customer informed of the contest's progress, to consider in good faith the Interconnection Customer's suggestions about conducting the contest, and to reasonably permit the Interconnection Customer or its representative to attend contest proceedings. The Transmission Provider may also agree to settle only after obtaining either the Interconnection Customer's consent or written advice from a nationally recognized tax counsel who is reasonably acceptable to the Interconnection Customer.

41.  Order No. 2003-A at P 351.

42.  LGIA article 11.4.1.

43.  Order No. 2003-A at P 338-341.

44.  See id. at P. 341.

45.  Order No. 2003-A at fn 85.

46.  Interconnection for Wind Energy and Other Alternative Technologies, Docket No. PL04-15-000; Standardization of Small Generator Interconnection Agreements and Procedures, Docket No. RM02-12-000; and Standardizing Generator Interconnection Agreements and Procedures, Docket Nos. RM02-1-001, RM002-1-005.

47.  E.g., PJM, NYISO, and ISO New England.

48.  See LGIA article 11.5, 11.5.2, and 11.5.3.

49.  Order No. 2003-A at P 428, 431.

50.  Id. at P 475, 476.

51.  Id. at P 486.

52.  Id.

53.  The Code of Conduct is imposed on a case-by-case basis when the Commission grants market-based rate authorization. Generally, the Code of Conduct contains a provision that all market information shared between the publicly utility (i.e., Transmission Provider) and the Affiliate is to be disclosed simultaneously to the public. See, e.g., Northeast Utilities Service Company, 87 FERC ¶ 61,063 at 61,276 (1999).

54.  Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 69134 (Dec. 11, 2003), FERC Stats. & Regs., Regulations Preambles ¶ 31,155 (2003), order on reh'g, Order No. 2004-A, 69 FR 23562 (Apr. 29, 2004), III FERC Stats. & Regs. ¶ 31,161 (2004), 107 FERC ¶ 61,032 (2004), order on reh'g, Order No. 2004-B, 69 FR 48371 (Aug. 10, 2004), III FERC Stats & Regs. ¶ 31,166 (2004), 108 FERC ¶ 61,118 (2004).

55.  Order No. 2003 at P 915.

56.  The OMB Control Number for this collection of information is 1902-0096.

57.  5 U.S.C. 601-612

58.  Order No. 2003 at P 924; Order No. 2003-A at P 792.

59.  See Order No. 2003 at P 830.

60.  See, e.g., Order No. 2003-A at P 789 et seq.

61.  Order No. 2003 at P 830-831.

1.  Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003-A, Order on Rehearing, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ¶ 31,160 at P 612 (2004).

2.  Id. at P 613.

3.  See, e.g., id.