FERC Filings
COMMENTS OF THE ELECTRIC POWER SUPPLY ASSOCIATION re: STANDARDIZATION OF GENERATOR INTERCONNECTION AGREEMENTS AND PROCEDURES
COMMENTS
A. Regional Differences
The NOPR states that the Commission will entertain proposals to depart from the IA and IPs to account for regional variations, but require that the specific need for such departures be provided in the proponent’s NOPR comments. The Commission notes that it followed this approach with respect to the pro forma Open Access Transmission Tariff (“OATT”) established in Order No. 888.
Consistent with its actions in Order No. 888 with respect to the pro forma OATT, the Commission should require all Transmission Providers to adhere to the Final Rule, including those that operate as Independent System Operators and should avoid differences among regions with respect to its IA and IPs. Otherwise, the Commission’s goal to standardize interconnection practices will be defeated. All regions were represented in the ANOPR process that developed the Consensus IA and IPs and, as the Commission observed in the NOPR, the parties claiming the need for regional variations did not provide any specific “regional” concerns presented by the consensus documents. More importantly though, any proposal to reflect a specific regional difference is best left to the compliance phase of this proceeding. Any Transmission Provider will then have an opportunity to propose one or more regional variations that it believes should be reflected in its particular IA and IPs.
In short, EPSA recommends that the Commission follow the approach adopted in Order No. 888 and require proponents of deviations to demonstrate that they are consistent with or superior to the standardized IA and IPs. The proposed IA and IPs will ensure that certain basic requirements are reflected in interconnection practices. While it is appropriate that parties be allowed to propose alternative interconnection arrangements, they should not be allowed to propose deviations that diminish the basic requirements. In any event, to the extent that parties suggest departures from the IA and the IPs to accommodate regional differences, all parties must have the opportunity to respond.
B. Refunds of Payments for Network Upgrades Should Not be Tied to the Transmission Service for a Specific Unit
EPSA supports the Commission’s decision to treat the repayment rights known as “transmission credits” as refundable deposits. By giving Generators cash refund rights with respect to payments to build Network Upgrades, instead of credits for transmission service, the NOPR better reflects that load, rather than the Generator, typically obtains transmission services. Moreover, by recognizing that Generators do not normally purchase transmission services on the network, the Commission will hopefully have put to rest, in the large majority of cases, the tax issues surrounding contributions in aid of construction (“CIAC’s”) which have plagued the industry and distorted interconnection costs for more than two years.
If payments to build Network Upgrades are to result in cash refund rights rather than rights to transmission service, the question still remains: What payments for transmission services will entitle the Generator to have its payments to build Network Upgrades refunded? Section 11.4.1 of the IA adopts the proposed language of the Consensus IA, and requires Transmission Providers to provide refunds “as payments are made under the Transmission Provider Tariff for transmission services with respect to the Facility.” This language, as noted above, addresses the CIAC tax issue by making it clear that the Generator will not be the transmission services customer of the Transmission Provider. However, the use of the phrase “with respect to the Facility” may unnecessarily limit the scope of transmission services which entitle the Generator to refunds, particularly as compared to the formulation the Commission set forth in the issuance of the ANOPR. In Attachment B to the ANOPR, the Commission provided that:
The transmission rates through which [transmission] credit[s] will be applied will include rates for all transmission service utilized by the Generator after the date of the interconnection. Such service will include not only new point to point service taken by the Generator from the location of its new facility, but also any other transmission service taken by that Generator from the Transmission Provider. In addition, the credit will be applied to the rates for any transmission service, including both point to point and network service, used by loads to deliver the output of the new facility to their location.
Section 11.4.1 of the IA was intended to address the potential tax issue, and not to restrict the scope of payments for services for which a refund should be required. Accordingly, Section 11.4.1 of the IA should be modified by adding to the end of the first sentence: “, including services taken by Generator’s customer or marketing affiliate or agent, and without regard to whether such customer or marketing affiliate or agent redirects its point-to-point transmission service or utilizes secondary resources under its network integration transmission service.” This language would cover, for example, the situation where a Generator is temporarily offline, but purchases power from another source to cover its commitments to its customers. Those customers will still be purchasing transmission services on the network, and they will still be the Generator’s customers, even if no power is flowing from the facility. EPSA urges that the Commission clarify the scope of the phrase, “with respect to the Facility,” as set forth above, to avoid needless controversy on this issue in the future.
Moreover, EPSA believes that, consistent with the above, the Commission should eliminate the tie between the cash refund and service from a specific facility in Section 11.4.1. The Generator’s up front payment is akin to a loan for which it will be paid back in the form of credits. Thus, there should be no connection between the loan repayment/credits and the specific Generator on whose behalf the loan was paid. The credits are a substitute for the dollars invested in the upgrades, and not for the transmission service that the investing/interconnecting Generator might request in the future. Hence, the repayment of the investment, in the form of credits against future transmission service, should not be tied to whatever actual service is taken by the specific interconnecting Generator. If, for example, an independent power producer made the investment on behalf of one of its future plants, the repayment (in the form of credits) should go to the independent producer to use however it wishes. At a minimum, the independent producer should be able to tie its reimbursement to any transaction that involves any of that producer’s facilities, not just the facility which paid for the upgrade.
In addition, the point of the crediting policy is to mirror the economics that would result under FERC’s traditional roll-in policy. Required upgrades are rolled-in when they are part of the integrated network and presumed, therefore, to provide “system” benefits. The crediting approach is in lieu of the Transmission Provider paying for the upgrades itself and recovering its investment through its embedded transmission rates. Thus, if the credits are the form of repayment for upgrade costs, and if these costs are being repaid because of the system benefits that resulted from their having been incurred, then the credits should be usable for any transmission (system) service, whether requested by the interconnecting Generator or some other party to whom the interconnecting Generator assigns the credits. Indeed, since the credits unquestionably can be used in connection with any transmission service that is taken by the interconnecting Generator wholly without reference to whether the particular upgrades (for which the investment was made) also were, or would actually be, required for such transmission (as opposed to interconnection) service, it makes no more sense to associate those credits with a specific Generator than it does to associate the upgrades with a particular type of transmission service. Thus, the Commission should not tie the refund of amounts advanced for Network Upgrades to transmission service from a specific facility and should modify Section 11.4.1 as set forth above.
Finally, this modification will also eliminate an inconsistency between the proposed crediting policy and the ability of firm point-to-point customers to redirect their transactions to use receipt and delivery points other than those contemplated by the initial reservation and to reassign their reservations to any party, regardless of whether that party intends to redirect its transaction to use other points on the system. The only difference between the interconnecting Generator and the firm point-to-point customer is that the interconnecting Generator is required to make payments in advance of any delivery commitment by the transmission owner, while the point-to-point customer is not required to make payments until the initial delivery transaction is reserved. This provides no basis for offering inferior redirect and reassignment provisions to interconnecting Generators that fund upgrades in advance of making delivery arrangements.
C. Interest on Amounts Advanced for Network Upgrades
Section 11.4.1 of the IA provides that “[a]ny refund shall include interest calculated in accordance with the methodology set forth in FERC’s regulations at 18 C.F.R. § 35.19a(a)(2)(iii) from the date of any payment for Network Upgrades through the date on which the Generator receives a refund of such payment pursuant to this subparagraph.” EPSA maintains that the interest rate paid to Generators pursuant to Section 11.4.1 should be equivalent to the rate of return (“ROR”) that the Transmission Provider would receive if it were to build the facilities itself. The Commission requires interest to recognize that the Generator is financing the Network Upgrades, and allowing the Transmission Provider to avoid having to obtain financing through conventional means. If the Transmission Provider were to build the project itself, it would receive a ROR applicable to such project. On the other hand, the interest rate established under the Commission’s regulations is based on the cost of Treasury bonds and, unlike this ROR, would not reflect the actual financing cost that would either have been incurred by the Transmission Provider, or that actually was incurred by the Generator.
The interest rate paid to a Generator for funding Network Upgrades should reflect the Generator’s actual financing costs. Because any effort to determine the Generator’s actual cost of capital undoubtedly would be controversial, EPSA believes that the Commission should use, as a conservative proxy for the Generator’s cost of capital, the Transmission Owner’s ROR (as reflected in the Transmission Owner’s OATT rates). This will avoid the litigation that would be inevitable if the Commission were to attempt to determine the Generator’s actual cost of capital and it ensures that customers will not face higher financing costs when the Generator funds the project instead of the Transmission Owner doing so.
D. Pricing
EPSA believes that it is premature for the Commission to decide, in this rulemaking proceeding, what system, if any, would replace the current policy of providing transmission credits when SMD is implemented. There are simply too many unknowns concerning SMD implementation. Among the issues that must first be resolved in order to evaluate this question are: how will transmission rights be allocated; will these transmission rights be subject to a mandatory auction mechanism, what will be the geographic scope of the RTO; what rights will interconnecting Generators have to access the market; will Generators be required to pay access fees for any transactions (e.g., exports, through or hub transactions); will there be a capacity obligation; and will the SMD apply under each Transmission Owner’s OATT or under an RTO OATT. Moreover, the structure and independence of RTOs, which the Commission recognized would be key to any decision to abandon credits, is in flux, particularly in the West and Southeast. As a result, and particularly since no compelling reasons have been submitted to the contrary, the Commission should defer making any determination on its crediting policy that will replace a Generator’s receiving refunds in lieu of transmission credits for network upgrades.
Finally, EPSA agrees with the Commission’s proposal to require all Transmission Providers to adhere to the Final Rule, including those that presently operate as Independent System Operators (“ISOs”), and requests that the Commission make this explicit in the proposed regulations. While it will be necessary to consider whether different pricing approaches reasonably could apply within an independent RTO which is operating in full compliance with the Commission’s SMD, no sufficient basis has been presented to justify distinguishing between ISOs from individual transmission owners at this time, or to abandon the Commission’s long-standing and currently effective “or” pricing policy for any transactions, ISO or otherwise.
E. Coordination with Third-Party Systems
There are two main issues involved with coordinating interconnection study and construction activities with Third Party systems (“Affected Systems”): (1) how to ensure that the Affected System Operator cooperates at all, particularly when it is not subject to the Commission’s jurisdiction under Sections 205 and 206 of the Federal Power Act and (2) the tax implications when Network Upgrades are constructed on the Affected System.
1. Ensuring Affected Systems Cooperate
During the ANOPR process, Transmission Providers and Generators did not reach agreement concerning the extent to which the Transmission Provider must coordinate with Third Party systems. Transmission Providers suggested only that “Reasonable Efforts” be undertaken to coordinate with Third Party systems. Generators wanted Transmission Providers and Affected System Operators to be jointly responsible for coordinating and performing all necessary studies.
The NOPR properly adopts the Generators’ position. It is not clear, however, how these obligations will be enforced, particularly when the Affected System Operator is a nonjurisdictional power authority, cooperative or municipality. One option would be to vigorously and expeditiously enforce the reciprocity provisions set forth in the NOPR. In the NOPR, the Commission said.
[w]e found in Tennessee that interconnection service is an element of transmission service that must be offered under the terms of the Transmission’s Provider’s OATT, and the IP and IA will be added to the OATT, we find that interconnection service also will be subject to this reciprocity requirement. Although we do not have direct authority to require non-public utilities to make interconnection service generally available, we have the ability and the obligation to ensure that all aspects of open access transmission are as widely available as possible and that the implementation of this rulemaking does not result in competitive disadvantage to public utilities. Thus, we propose that the reciprocity provision apply to interconnection as well, and that any non-public utility that wishes either to take advantage of, or to continue to take advantage of, open access on a public utility’s transmission system, must adopt the IA and IP into its own reciprocity service.
Consistent with the reciprocity provisions and the Commission’s decision that Transmission Providers and the Affected System Operators must cooperate, the Commission should amend Section 3.5 of the Standardized Study Procedures to add the following sentence at the end:
To the extent that the Affected System Operator is not a public utility, failure to comply with this section shall constitute a violation of the reciprocity obligations of the Commission’s open access requirements.
Moreover, the Commission should require Affected System Operators to abide by the same time line and the same obligations as the Transmission Provider in performing the various interconnection tasks as well as the Commission’s pricing policies, including credits. Finally, the Commission should require Transmission Providers to inform the Commission if an Affected System Operator fails to cooperate.
2. Tax Implications
The tax rights and obligations of transmission owners in Affected Systems should also be clarified. Article 5.14 of the IA contains a comprehensive set of rights and obligations which ensure both that Transmission Owners are adequately indemnified against the tax risks associated with payments to build Interconnection Facilities and Network Upgrades, and that Generators will not be held liable for taxes that ultimately are not due. When Network Upgrades are built in Affected Systems (“Affected System Upgrades”), the ultimate owners of such upgrades will be subject to the same tax risks as Transmission Owners under an IA, and Generators who are required to pay for Affected System Upgrades will have the same concerns as they have in an IA about obtaining refunds for tax gross-up payments. Although not normally a party to the IA, the owner of Affected System Upgrades will nevertheless be the potential taxpayer, and it will also be the only party able to contest the taxability of such payments, to receive a refund from the IRS for any overpayment of tax, or to seek a private letter ruling to determine if the costs of the Affected System Upgrades are taxable.
The Commission has previously acknowledged that a Generator should not be required to pay the taxes of a transmission owner unless the Generator is entitled to a refund in the event it is determined that the amounts paid for Interconnection Facilities and Network Upgrades are not subject to tax. If the transmission owner in an Affected System is not a party to the Generator’s IA, the Generator will have no means to enforce its right to a refund of any amounts it has previously paid for taxes which are not ultimately due.
Accordingly, EPSA urges the Commission to adopt the approach already found in Section 5.14.9 of the IA, and to add the following sentence at the end of Section 3.5 of the IPs:
If and to the extent a Generator is required to pay for Network Upgrades on any Affected System, as defined in Section 1.1 (including that of the Transmission Provider), the Transmission Owner or Owners who receive payments for such Network Upgrades shall enter into one or more agreements with such Generator with respect to taxes and transmission credits, containing terms substantially identical to those in Article 5.14 and similar to those in Article 11.4 of the Standard Generator Interconnection and Operating Agreement.
F. Tax Indemnity for Subsequent Taxable Events
Although EPSA generally supports the tax provisions proposed by the Commission in Article 5.14 of the IA, EPSA believes the NOPR IA should have retained Section 5.16.5 of the Consensus IA, which dealt with “Subsequent Taxable Events.” When the tax professionals representing Generators and Transmission Providers negotiated the provisions found in Section 5.16 of the Consensus IA (the “Consensus Tax Provisions”), they recognized that, even if the initial payments to build interconnection facilities were not taxable because the transaction fell within the “safe harbor” of Internal Revenue Service (“IRS”) Notice 2001-82, it was theoretically possible that later events could cause the IRS to take the position that a deemed taxable transfer had occurred. Generators believed that this is extremely unlikely to occur, but were willing to indemnify Transmission Providers in the event that it does.
The language agreed to in Section 5.16.5 of the Consensus IA provided that the Generator’s obligation to indemnify the Transmission Provider could be triggered by a subsequent taxable event, if it occurred during the ten-year period following the initial payment or transfer. In the remote circumstance that the requirements of IRS Notice 2001-82 were violated in a year after the initial transfer, and the Transmission Provider was required to pay taxes as a result, the language included in Section 5.16.5 of the Consensus IA provided that the Transmission Provider would look to the Generator for payment. However, Section 5.16.5 also provided that the obligation to provide indemnification with respect to subsequent taxable events would last only for ten years and that no security would be required.
The general indemnification in Section 5.14.3, on the other hand, was never intended to address the possibility of such subsequent taxable events. In particular, the language following “provided, however” at the end of the first sentence of Section 5.16.3 of the Consensus IA reflects the Generators’ concession that the application of IRS Notice 2001-82 might not be clear in all circumstances, and that Transmission Providers could reasonably require security to protect themselves against the potential tax risk until ambiguities about the Notice are resolved, for example, through a private letter ruling. The requirement to provide security with respect to the initial transfer or payment was agreed to by Generators because its duration was expected to be limited, given the Generator’s ability to obtain a private letter ruling if the law was unclear, at which time the need for security would expire and any tax gross-up costs already paid would be refunded. Section 5.16.3 was not intended to require Generators to post security indefinitely against the remote risk of a change in circumstances which might potentially become a subsequent taxable event. For example, the potential tax liability on a $10 million interconnection, assuming a 30% tax gross-up rate, would initially be $3 million and would decline over time with respect to subsequent taxable events. Requiring the Generator to post a letter of credit for $3 million for the indefinite future would have an ongoing cost in the neighborhood of $20,000/year to $60,000/year, to secure a risk with a likelihood believed to be less than 0.5%. Absent the ability to obtain insurance, whose cost could be reasonably related to the actual amount of risk, the only foreseeable result of requiring Generators to post security with respect to the potential for subsequent taxable events would be to unnecessarily and unreasonably drive up the cost of interconnection.
The tax provisions contained in Section 5.16 of the Consensus IA were negotiated by tax professionals representing all sides of the electric industry and include concessions and compromises on the part of both Generators and Transmission Providers. In the NOPR, the Commission recognized that the Consensus Tax Provisions represented a balance between competing interests. If Section 5.14.3 of the IA were read to permit Transmission Owners to insist on security indefinitely, to protect against the remote possibility of a change in circumstances that might become a subsequent taxable event, the balance reflected in the Consensus Tax Provisions would be upset. Hence, EPSA urges the Commission to adopt the provisions found in Section 5.16.5 of the Consensus IA, but to continue to exclude the Transmission Owner modifications to the Consensus Tax Provision found at the end of that section.
G. Availability of Network Resource Interconnection Service
Consistent with EPSA’s recommendations during the ANOPR process, the IA and IPs provide for two interconnection service products: Energy Resource Interconnection Service and Network Resource Interconnection Service (“NRIS”). The NOPR is not clear whether Generators with existing interconnection agreements will be eligible for NRIS and in the Final Rule, the Commission should explicitly state that NRIS is not restricted to new or expanded capacity. Existing Generators operating under existing interconnection agreements should have the opportunity to request that the Transmission Provider conduct studies and construct Network Upgrades as necessary to provide NRIS. If existing Generators are willing to pay for the applicable studies and the necessary upgrades, there is no reason why they should not be eligible to receive NRIS. Any agreement to provide NRIS could be included as a supplement to an existing interconnection agreement. Similarly, generators already in the interconnection queue should have the ability to make a separate application requesting NRIS.
H. Security
GIA Sections 11.5 and 11.5.1 are virtually identical provisions providing that prior to commencement of procurement, installation or construction of discrete Transmission Provider Interconnection Facilities/Network Upgrades projects, the Generator must provide the Transmission Provider with a reasonably acceptable form of security. These sections should be revised to (1) allow the Generator to provide security on a rolling six month basis based on the estimated amount of the Transmission Provider’s cost exposure at each six month interval; and (2) consolidate Section 11.5 with Section 11.5.1 to eliminate duplication and, in the event that the Commission does not adopt EPSA’s proposal for a rolling security requirement, provide that security is due thirty (30) Calendar Days before commencement of procurement, installation or construction.
First, the Generator should only be required to provide security pursuant to Section 11.5.1 on a rolling six month basis and such security should be limited to the estimated amount of the Transmission Provider’s cost exposure at each six month interval. This will insure that the security costs imposed on the Generator are reasonable at any particular time. EPSA recognizes that the Commission’s current policy requires Generators to provide security for the entire cost of the project prior to the beginning of construction, regardless of the Transmission Provider’s exposure to costs at that time. Such a policy is acceptable for any small projects that a Generator must fund. However, increasingly Generators are being asked to fund significant Network Upgrades. In that event, the time when such security is required can have a significant cost impact. Annually, such security generally costs approximately 1.5% for each million dollars of security obtained. This significant cost is completely unjustified when the Transmission Provider is not incurring any expenses and where it has no concern that it will not be reimbursed for the costs it incurs. Generators should only be required to provide security for the Transmission Provider’s actual cost exposure. As such, the Commission should provide that at each six month interval of a project, the Generator must provide security based on the Transmission Provider’s estimated cost exposure at that time.
Second, in the event that the Commission does not adopt EPSA’s proposal for a rolling six month security requirement, the Commission should consolidate Section 11.5 with Section 11.5.1 due to the duplicative nature of the provisions and, in doing so, adopt the thirty (30) Calendar Day period for obtaining security in Section 11.5.1 rather than the ninety (90) day period in Section 11.5. Since the provision of security is tied to the actual procurement, installation or construction activities, there is no reason to require that the security be in place three months before any costs are incurred. As such, the thirty (30) Calendar Day advance period set forth in Section 11.5.1 sufficiently protects the Transmission Provider.
I. Third Parties Conducting Studies
Section 13.4 of the IPs provides that a Generator may require a Transmission Provider to utilize a reasonably acceptable Third Party to conduct an interconnection study: 1) if the Generator and Transmission Provider disagree as to the estimated time to complete an interconnection study, 2) if the Generator receives notice that the Transmission Provider will not complete an interconnection study within the applicable timeframe for such activity, or 3) if the Generator receives neither the interconnection study nor such notice within the applicable timeframe.
EPSA supports the option to use Third Parties to conduct interconnection studies but believes Generators should be permitted to exercise such an option at any time, subject to the conditions set forth below, rather than be limited to the three opportunities listed in the NOPR. As limited, the NOPR falls short of providing the flexibility that Generators need to ensure that interconnection studies will be completed on schedule. As drafted, the NOPR exposes Generators to the risk of unnecessary delay because a triggering event must occur (e.g., the Transmission Provider fails to meet its deadlines) before a Generator can utilize a Third Party to perform studies. Moreover, even after the triggering event occurs, the Transmission Provider still has thirty (30) days to comply with the Generator’s request to utilize a Third Party. This is too much time from the initiation of the study to when a Generator is informed that the study might be delayed.
Transmission Providers may express concern that the Third Party contractor may not complete the studies in the same fashion or quality that the Transmission Provider might complete such studies. To address such concerns EPSA proposes the following conditions for using a Third Party contractor.
• The Third Party contractor must be acceptable to the Transmission Provider.
• The Generator must be responsible for the costs associated with using the Third Party contractor.
• The Third Party contractor must rely on the information provided by the Transmission Provider and work under the direction of the Transmission Provider.
With these conditions, Transmission Providers are protected since the studies prepared will be prepared in the same fashion and quality as if the Transmission Provider prepared the studies. Thus, Generators should have the option of requiring the Transmission Provider to utilize a Third Party contractor to perform studies at any time.
J. Liquidated Damages
In the NOPR, the Commission proposed liquidated damage provisions in Section 5.1 of the IA. As the Commission notes, both Transmission Providers and Generators supported this provision and thus it should be retained. The Commission also proposed a liquidated damage provision in the IPs supported by Generators. Section 13.5 states in part:
In the event that the Transmission Provider fails to meet any of its obligations under these Interconnection Procedures, and fails to remedy any failure within fifteen (15) Business Days, the Transmission Provider shall pay the Generator liquidated damages. Any liquidated damages paid by the Transmission Provider to the Generator shall be an amount equal to 1% of the actual cost of the applicable study costs (including any third party study costs), per day. However in no event shall the total liquidated damages exceed 50% of the actual costs of the applicable stud(ies).
A Generator entering into an IP must have some means to incent completion of studies in a timely manner. The liquidated damage provisions provide Transmission Providers with proper incentives, while ensuring that the potential penalties are not onerous (i.e., there are daily limits of 1% of the cost of the study and a cap on the total liquidated damages imposed equal to 50% of the study cost). As such, Section 13.5 of the proposed procedures is reasonable, and EPSA believes it should be retained.