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Order Accepting Filing, Requiring Compliance Filing Accepting and Suspending Proposed Tariff Sheets, and Establishing Hearing Procedures

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Start Preamble Issued May 31, 2005.

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

Allegheny Power System Operating Companies: Monongahela Power Company, Potomac Edison Company, and West Penn Power Company, all d/b/a Allegheny Power; PHI Operating Companies: Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company; Baltimore Gas and Electric Company; Jersey Central Power & Light Company; Metropolitan Edison Company; PECO Energy Company; Pennsylvania Electric Company; PPL Electric Utilities Corporation; Public Service Electric and Gas Company; Rockland Electric Company; and UGI Utilities, Inc.

PJM Interconnection, L.L.C.

Baltimore Gas and Electric Company; and Pepco Holdings Inc. Operating Affiliates: Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company

PJM Interconnection, LLC

1. In this order, the Commission acts on three filings related to PJM Interconnection, LLC's (PJM) Regional Transmission Expansion Plan (RTEP) process. With respect to the filing in Docket No. ER04-156-006, which proposes to continue PJM's current modified zonal rate design, we are establishing a hearing under section 206 of the Federal Power Act (FPA) [1] to examine the justness and reasonableness of continuing PJM's modified zonal rate design. We accept the tariff sheets filed by certain PJM transmission owners (the PJM TOs) in Docket No. ER05-513-000, subject to further compliance filing, to establish the general methodology for recovery of costs incurred under the RTEP process. And we accept and suspend, to become effective June 1, 2005, subject to refund and to the outcome of a hearing, the filing by another group of TOs in Docket No. ER05-515-000 to establish a formula rate for recovery of transmission costs, including RTEP costs. This order benefits customers by providing the needed infrastructure to support robust competitive markets and allows PJM's TOs timely recovery of just and reasonable rates for new transmission infrastructure.

Start Printed Page 34459

Background

2. PJM provides Point-to-Point service, Network Integration Transmission service, and a variety of ancillary services over its transmission system. PJM's existing modified zonal or “license plate” rate design is based on zonal transmission rates for the geographic zone delineated by each TO's transmission facilities and the customer loads within each transmission zone,[2] and rates for Network Integration and Point-to-Point customers are both based on the embedded costs of a TO's transmission facilities. The rates for each TO's transmission zone generally remain in effect until it is amended by the TO or modified by the Commission.

3. PJM also conducts its RTEP process, under which it identifies and designates upgrades to the systems of its TOs that are required to be constructed to maintain reliability and enhance competition. Previously, the PJM transmission owners had filed a new Schedule 12A to PJM's tariff to recover the costs of transmission enhancements designated by PJM pursuant to its RTEP. By order issued January 2, 2004 in Docket No. ER04-156-000,[3] the Commission accepted and suspended the proposed Schedule 12A subject to refund, initiated a hearing and instituted an investigation pursuant to section 206 of the FPA. Ultimately, the Commission accepted a settlement agreement in that docket which required that: (1) The PJM parties address by January 31, 2005, whether the existing zonal rate design within PJM should be changed after May 31, 2005, and if so, what new rate design should be considered, and (2) the settling parties make a future filing addressing the harmonization of existing transmission rates with new transmission investment recovery proposals.[4]

4. This order address three filings related to the recovery of the costs of upgrades designated through PJM's RTEP process. First, in Docket No. ER04-156-006, the PJM Settling Parties [5] propose to fulfill the first settlement requirement by proposing to continue a zonal rate design for the PJM footprint. Second, in Docket No. ER05-513-000, the PJM parties propose to fulfill the second settlement requirement settlement by submitting revisions to Schedule 12 of the PJM Open Access Transmission Tariff (OATT) to establish the procedures by which the PJM TOs may, if they choose, recover the costs incurred in constructing new transmission facilities. Third, in Docket No. ER05-515-000, Baltimore Gas and Electric Company, Inc., Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company, (jointly, PHI TOs) submit tariff sheets to implement a transmission cost of service formula rate for determining the PHI TOs' wholesale revenue requirements.

A. Docket No. ER04-156-006

5. The PJM Settling Parties state that, pursuant to their obligation under the May 26 Settlement, they propose that PJM's existing rate design not be changed at this time. The PJM Settling Parties state that currently, PJM's rate design is subject to the outcome of several ongoing proceedings:

  • In Docket No. EL02-111-000, et al., the Commission is considering the long-term pricing structure (LTPS) for transmission between PJM and the Midwest Independent Transmission System Operator, Inc. (Midwest ISO).[6]
  • In its November 18 Order, the Commission eliminated regional through and out rates between PJM and Midwest ISO, continued the existing PJM and Midwest ISO rates, and imposed transitional Seams Elimination Charge/Cost Adjustments/Assignments (SECA) charges through March 31, 2006, but further stated in that order that it was not altering “the obligation of PJM Parties to file on or before January 31, 2005, a reevaluation of the rate design for intra-RTO [Regional Transmission Organization] service and a proposed rate design to take effect on June 1, 2005.” [7]
  • The Commission has directed the PJM and Midwest RTOs and their transmission owners to make a filing at least six months before February 1, 2008, to reevaluate the fixed cost recovery policies for pricing transmission service between the two RTOs and propose a rate design to take effect February 1, 2008.[8]

6. Because of these proceedings, the PJM Settling Parties propose that the existing modified zonal rate design should be retained until the rate design within PJM can be considered as part of a wider regional evaluation. The PJM TOs argue that retaining the existing rate design will enhance rate stability, reduce uncertainty, and avoid unintended consequences, particularly at a time when the following region-wide changes are underway:

  • The elimination of through and out rates between PJM and Midwest ISO, subject to the LTPS proceeding, and implementation of the SECA charge;
  • The development of a joint and common market with Midwest ISO; and
  • The cost allocation to customers of new transmission facilities that are built in one RTO but provide some benefits to customers in another RTO.

7. They explain that retaining the existing rate design will permit the impacts of the changes already underway to be better understood and accommodated. For example, they note that PJM's OATT Schedule No. 12 is already transitioning away from a pure license plate rate design because it provides for separate cost assignments of new facilities to the customers or Start Printed Page 34460zones that will benefit from these facilities. Further, over time, this “modified zonal rate design” will evolve as some level of new facilities costs is allocated away from the zone of the transmission owner that builds the facilities and to the zone of the benefiting customers. The PJM Settling Parties also claim that retaining the existing rate design will give them the ability to coordinate consideration of any alternative rate design with the Midwest ISO transmission owners, and that a consistent and common rate design will facilitate the Commission's goal of creating a PJM-Midwest ISO joint and common market.[9]

8. The PJM Settling Parties also advise that there is no alternative to the modified zonal rate design that is agreeable to all or even a majority of the PJM Parties at this time, and that continuation of the existing rate design is not opposed by most PJM stakeholders based on the stakeholder process required by the settlement reached in Docket No. ER04-156-000.[10] For the reasons discussed above, the PJM Settling Parties believe that it would be premature to change the intra-PJM modified zonal rate design at this time, and request that PJM be permitted to develop a new rate design, or explain why the modified rate design remains sound, in tandem with the similar evaluation of the Midwest ISO rate design to be in place by February 1, 2008.

B. Docket No. ER05-513-000

9. The PJM TOs [11] submitted revisions to Schedule 12 of the PJM OATT to establish the procedures by which the PJM TOs may recover the costs incurred in constructing new transmission facilities. The PJM TOs propose three options that each PJM TO may select to recover the costs incurred in construction of new transmission facilities. A PJM TO may elect:

  • Not to seek to recover the costs of new transmission facility construction from customers until such time that it proposes to revise its zonal transmission rates generally [Option 1];
  • To file to establish a revenue requirement to recover the cost of constructing a specific new transmission facility pursuant to section 205 of the FPA and the Commission's rules and regulations, without revising its zonal transmission rates generally [Option 2]; or
  • To establish the revenue requirement for new transmission facilities it constructs through the operation of a formula rate that is also applicable to its zonal revenue requirement, so that both the revenue requirement associated with RTEP projects and the revenue requirement for the TO's existing facilities will be determined through the formula [Option 3]. Under Option 3, the formula rate for the RTEP project will be collected separately from the rate for the TO's existing facilities.[12]

10. The PJM TOs request that the Commission grant waiver to permit them to file one day prior to the Commission's 120-day maximum notice period.[13] In support of waiver of the notice period, the PJM Parties note that the Settlement provided that the instant filing would be made by January 31, 2005, to become effective on June 1, 2005.

C. Docket No. ER05-515-000

11. Baltimore Gas and Electric (BGE) and the public utility operating affiliates of Pepco Holdings, Inc. (PHI): Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (Delmarva), and Atlantic City Electric (ACE) (jointly referred to as PHI TOs) filed proposed tariff sheets reflecting a new formula rate for determining the TOs' annual wholesale revenue requirement as set forth in Attachment H to PJM's OATT.[14] The PHI TOs explain that the formula rate is only for them and it is not intended to affect the rates in Attachment H for any other TO's transmission zone.[15]

12. The formula rate will calculate the rate for Network Integration Transmission Service (NITS) at 69 kV and higher voltage facilities. The PHI TOs propose to reflect in their rates: (i) their most recent historical FERC Form 1 costs and (ii) new transmission additions that have gone into service or cost projections of new transmission additions that are expected to go into service in the current year.[16] The formula is proposed to apply to rate periods commencing each year on June 1 and continuing through May 31 of the succeeding year. Thus, on or before April 30, 2005, the PHI TOs will populate the formula inputs to include actual 2004 FERC Form 1 data, plus new transmission additions that are expected to go into service in 2005, and the results will be posted on PJM's Web site. The PHI TOs explain that this timing will enable them to use actual Form 1 data from the preceding calendar year, and to calculate true-ups for all costs, including the one component of the formula that will consist of projections—i.e., transmission additions that are planned to go into service during the year of each rate update. They explain further that the projects that they anticipate constructing will be either (a) projects required by the PJM RTEP, or (b) if not in the RTEP, explained in the formula's supporting statements. Moreover, the formula will be trued-up annually to include actual plant additions for the relevant period, with interest as specified in section 35.19(a) of the Commission's regulations. Accordingly, the PHI TOs propose that the NITS rates posted on April 30, 2005 will become effective on June 1, 2005. To the extent that the June 1 effective date requires waiver of the Commission's notice requirements under section 35.3,[17] the PHI TOs respectfully request such waiver.

13. The PHI TOs note that they have twice attempted to deal with the question of rate recovery for new transmission investments in filings that were intended to implement PJM's RTEP process. First in Docket No. ER03-738-000, and thereafter in Docket No. ER04-156-000, the PHI TOs proposed that a single return on common equity be made applicable to all of the PJM TOs at this time.[18] The PHI TOs advise that their proposed base return on equity (ROE) of 12.4 percent (before incentives) is supported by a Commission-approved discounted cash flow (DCF) model applied to their proxy group of Northeast transmission owning utilities and will be used in the individual capital structures of the PHI TOs. In addition, they note that the Commission has already held in two Start Printed Page 34461separate dockets that the 50 basis point adder is warranted for all PJM TOs because the TOs have already given up operational control of their transmission facilities to PJM.[19]

14. The PHI TOs are also proposing to apply a 100 basis point adder for new transmission investment that is placed in service in accordance with the RTEP process. The PHI TOs state that according to the testimony of their witness Dr. Avera, the proposed base ROE, the 100 basis point adder, and the 50 point RTO membership adder all fall within the zone of reasonableness as determined by an accepted Discounted Cash Flow (DCF) analysis.

15. The PHI TOs advise that they are including abbreviated Statements AA through BL in support of this filing and they request waivers of section 35.13 of the regulations,[20] including waiving the full Period I and Period II data, and 35.13(a)(2)(iv) to determine if and the extent to which a proposed change constitutes a rate increase based on Period I-Period II rates and billing determinants. In support of waiver, they note that the revenue requirements resulting from the formula will be derived using the billing determinants published annually by PJM.

Notice of Filings and Responsive Pleadings

16. Notice of the filings in Docket Nos. ER04-156-006, ER05-513-000, and ER05-515-000 was published in the Federal Register,[21] with comments, protests, or interventions due on or before February 22, 2005. Motions to intervene or motions for late intervention were filed by the entities listed in Attachment A to this order.[22] In Docket No. ER04-156-006, the PJM Settling Parties and COST filed answers. In Docket No. ER05-513-000, answers were filed by COST and the PJM TOs. In Docket No. ER05-515-000, answers were filed by COST, ODEC and the Easton Utilities Commission, and the PHI TOs filed two answers.

A. Docket No. ER04-156-006

1. Endorsements and Protest of Modified Zonal Rate Design

17. PJM ICC and Joint Consumer Advocates generally support the PJM Parties' proposal to retain existing modified zonal rates, because this approach avoids potentially significant cost shifting and issues with levelization of transmission rates that would arise should PJM's current rate design be accepted.[23] Joint Consumer Advocates state that considering the significant costs shifts that already attendant to the SECA rate design, that the Commission accepted in Midwest Independent Transmission Operator, Inc., et al.,[24] maintaining existing license plate rates provides stability during this transition period resulting from the elimination of regional through and out rates. Joint Consumer Advocates point out that this stability is an essential element of the rate structure approved by the Commission in Docket Nos. EL02-111-000 et al.

18. ODEC protests the proposal to permit separate rates of the PHI Operating Companies within PJM's modified zonal rate design. ODEC states that it does not protest the modified zonal rate, but rather the proposal to continue separate rates for each of the PHI Operating Companies in Docket No. ER05-515-000 and states that the filing in ER04-156-006 will continue the separate modified zonal rates for these three PHI Operating Companies. ODEC states that PHI Operating Companies have failed to justify their continued departure from a single rate. ODEC requests that the Commission reject this aspect of the proposal, or, in the alternative, include the issue in the proceedings in Docket No ER05-515-000.

19. AEP protests the existing modified zonal rate design because it believes that waiting until February 2008 for the PJM and Midwest RTOs' LTPS process to implement a regional rate design is too long. AEP notes that Schedule 6 of the PJM Operating Agreement and Schedule 12 of the PJM Tariff will directly assign costs across zones and will arguably regionalize the cost of new facilities in PJM. However, AEP notes that the costs of the Extra High Voltage (EHV) facilities (500 kV and above) are spread among the preexisting PJM members, but complains that the status quo proposal would not extend that same treatment to the substantial EHV transmission owned by AEP and other new entrants. AEP advises that the majority of costs will stay within a single zone based on the expansions planned for 2005, 2006 and 2007.[25] AEP's also advises that prior to the elimination of out and through rates as of December 1, 2004 in the LTPS proceeding, AEP was able to collect up to 40 percent of its costs associated with its transmission facilities from external transactions.[26] AEP complains that apart from a short SECA surcharge lasting only through March 2006, no regionalization of costs has been forthcoming from that proceeding. AEP also complains that a substantial gap exists between SECA expiration in March 2006 and any chance for regionalization of rate design in 2008.[27] Accordingly, and because things have significantly changed since the May 26, 2004 Settlement, AEP requests that the Commission suspend and investigate the status quo proposal, and set the matter for hearing.

B. Docket No. ER05-513-000

1. Harmonization

20. COST, Joint Consumers Advocates, DE PSC, Municipalities and PPANJ contend that the PJM Parties have not complied with the Commission's directives to harmonize the rate treatment of new and existing facilities. COST states that it understands harmonization to mean that there will be no over-recovery of costs when the existing rates and any proposed new rates are in effect simultaneously, i.e., that the existing and new rates together produce overall charges that are just and reasonable.

21. Joint Consumer Advocates protest the TOs' attempt to bring an overbroad category of new transmission investment within Schedule 12, stating that new transmission investment that has not been subject to the regional planning process or approved by PJM should be excluded from recovery under Schedule 12. DE PSC points out that the proposed three-option Schedule 12 would allow a TO to recover incremental transmission costs, file piecemeal surcharge requests, or file formula rates without making a single filing to the Commission, and that while it would support a formula rate for PHI, Start Printed Page 34462which serves many Delaware customers, that is just and reasonable, DE PSC is mindful of the fact that PHI may switch to these other options under Schedule 12.

22. With respect to Option 1, COST contends that the Commission's January 16, 2004 order on rehearing in Docket No. ER04-156-002[28] was premised on the understanding that the Applicant TOs would be revisiting their existing rates in conjunction with the January 31, 2005 filings and that Option 1 fails to consider whether the TO's existing rates are just and reasonable. COST maintains that when an Applicant TO is willing to forgo revenues associated with new facilities, that establishes a prima facie presumption that the TO is over-earning under its current rates.

23. COST, Joint Consumer Advocates and DE PSC contend that Option 2 does not accomplish the goal of harmonization, because it fails to consider both the rates in Schedule 12 and the TOs' old base rates, and therefore violates the Commission's longstanding policy against ad hoc and piecemeal ratemaking.[29]

24. COST admits that Option 3 could accomplish harmonization in theory, and commends the few PJM TOs who are pursuing it. Nevertheless, COST and Joint Consumer Advocates contend that the proposed surcharge-then-revenue-credit mechanism does not harmonize with the RTEP cost allocation process and does nothing to ensure that the existing rates of those customers paying the surcharge have been harmonized, especially when those existing rates are already over-recovering costs. COST and NCEMC state that “Responsible Customer” zones to which new facility costs are allocated should be filed with the Commission, not merely posted on the PJM web site. NCEMC states that not filing such designations with the Commission deprives such “Responsible Customers” of an opportunity for Commission review of whether such designation would result in unjust and unreasonable rates.

2. Other Issues

25. COST and NCEMC advise that the PJM Parties are proposing to delete the requirement that Schedule 12 designate the “Responsible Customer” that must pay the Transmission Enhancement Charge, which deprives the “Responsible Customers” of an opportunity for review by this Commission of such designation and contradicts PJM's August 25, 2003 compliance filing in Docket Nos. ER03-738 and RT01-2, which assured the stakeholders that those designations would be subject to this Commission's review. COST explains that some Responsible Customers are not members of PJM and, for such customers, filing of the “Responsible Customer” designation with this Commission is essential.

26. Detroit Edison and Wisconsin Electric are also concerned that certain language in the newly-filed Schedule 12 (b) could be read to impose certain costs on customers outside of PJM, and protest this language to the extent that it permits PJM to impose charges in MISO and elsewhere outside the PJM footprint. Furthermore, Detroit Edison states that the Commission required in the November 18 Order that PJM, MISO, and their transmission owners “develop a proposal for allocating to the customers in each RTO the cost of new transmission facilities that are built in one RTO but provide benefits to customers in the other RTO.” Detroit Edison states that the Commission thus recognized that the development of any cross-border transmission pricing in the Combined Region must include parties from both PJM and MISO.

C. Docket No. ER05-515-000

1. Rate of Return on Equity

27. The majority of protestors contend that the proposed 12.4 percent ROE is excessive and that the PHI TOs have not shown it to be just and reasonable. As an initial matter, COST, Joint Consumer Advocates, DEMEC, the Municipalities and PPANJ complain that the proposed ROE of 12.4 percent is based what the PHI TOs' own witness identifies as an “adjusted” midpoint return on equity of 11.5 percent, which includes an unprecedented 90 basis point adjustment that projects increases in yields on 10 year Treasury notes. Municipalities and Joint Consumer Advocates note that this sort of projection is not shared by other analysts.

28. COST, DEMEC and Municipalities assert that the PHI TOs consultant's unreasonable proxy group parameters and composition must be set for full evidentiary investigation and hearing.

2. ROE Incentive Adders

29. Protestors contend that the inclusion of a 50 basis point adder and a 100 basis point adder, which are not tied to performance, have not been justified, should not be approved, and would not result in just and reasonable rates. Protestors note that in a prior proceeding the Commission directed the TOs to support why the 100 basis point adder is needed to incent investment in transmission facilities and to address whether the proposed adder should apply to all types of transmission expansion or if it should be more narrowly focused on transmission expansions that utilize innovative technologies that result in lower costs, and that the TOs have failed to demonstrate why their incentive rates are necessary. Municipalities and Joint Consumer Advocates further state that the PHI TOs' requested 50 basis point adder did not have any bearing on the PHI TOs' decision to join PJM, and that PJM's current TOs sought PJM membership years ago based on the understanding that membership alone would compensate them enough to justify the costs of participation. Because of this, Municipalities and Joint Consumer Advocates state that approving the 50 basis point adder incentive would serve no useful purpose, nor would it provide customers with any additional benefits. Joint Consumer Advocates state that further, the basis point adders distort the cost benefit analysis and evaluation of alternative competitive solutions by either not being included in the analysis, or imposing additional costs on the solution.

30. COST also contends that the filing is inconsistent in its treatment of capital structure costs and securitization debt. Specifically, COST states that PHI TOs have improperly sought to exclude stranded cost securitization bonds from Atlantic City Electric's (ACE) capital structure.

3. Other Revenue-Related Issues

31. COST and Municipalities state that the TOs' proposal to retain fifty percent of the revenues received from “secondary uses” of the transmission assets (such as rents from telecommunications equipment), rather than netting their entire secondary use revenue to their transmission cost of service, is unjust and unreasonable, since it forces ratepayers to pay for the full costs of these transmission facilities plus a substantial return, while the TOs alternately receive additional revenues on these same facilities already paid for by the ratepayer

32. DE PSC complains that the PHI formula does not assure the proper functionalization of costs such as generation step-up transformers, capacitors and reactive equipment. DE PSC also points out that revenues from secondary uses of transmission assets Start Printed Page 34463should be credited in full to costs, but are not credited in the proposed PHI formula.

33. Municipalities and Joint Consumer Advocates state that the formula is flawed because it does not clearly exclude cost recovery for non-transmission plant items such as generation interconnection equipment, dual purpose substations, or non-utility business expenses. Municipalities also complain that the basis of the projected rate divisors used in the formula rates appears in none of the filings, and the source is simply indicated as “PJM Data”. Municipals state that this reference is too vague to satisfy the criteria for a formula rate that the data can be immediately auditable.

34. FirstEnergy Companies supports the PHI formula, but states that it would be inappropriate for FirstEnergy Companies to adopt a similar rate design because: (1) Their zonal stakeholders are not in favor of a change to a formula rate, (2) there is no Commission precedent that indicates that adoption of a formula rate is mandatory, and (3) under the PJM Tariff and the TOs' Agreement, each transmission owner has the right under section 205 of the FPA to propose to change its zonal rate and therefore, the PHI formula rate should have no effect as to the rate design of the remaining PJM zones.

35. PPANJ asserts that the proposed formula fails to compensate for the use of customer-owned transmission plant. PPANJ states that its member Vineland Municipal Electric Utility (VMEU) owns transmission facilities that are integrated with those of ACE and provide benefits to ACE and the PJM system, and that VMEU agreed to allow its transmission facilities to be dispatched by PJM, but the formula proposed by ACE does not provide for any credit to VMEU for the cost of VMEU's facilities. PPANJ asserts that this omission violates the Commission's policy that customers are entitled to a credit for certain transmission plant under the control of the RTO, which requirement is included in the PJM OATT,[30] and that the Commission has recently interpreted this section as requiring credit for customer-owned transmission facilities that are integrated with those of the transmission provider.[31]

36. Protestors state that the proposed formula rate must have customer safeguards in order to produce just and reasonable results. DEMEC contends that adequate customer safeguards are necessary in order to assure transparency in the proposed formula rate and to ensure that all affected entities are afforded adequate due process. Further, if the formula rate proposal is accepted for filing, COST requests that the Commission require the adoption of its procedural protocols to give affected customers an adequate opportunity to review and verify that the appropriate amounts are being input to the formula. Municipalities argue that the TOs should be required to notify their customers of specific accounting changes and policies that may ultimately affect the rate charged. NCEMC expresses concern that the proposed formula rate permits the PHI TOs to recover incremental transmission investment without requiring them to file to revise their Network Integration Transmission Service rates reflecting this change. NCEMC states that this approach may result an over-recovery of costs and may result in a transmission customer paying both a portion of the incremental transmission investment and the embedded cost transmission rate, which would be inconsistent with the Commission's long-standing prohibition against “and” pricing.[32]

4. Waiver of Filing Requirements

37. COST, DEMEC, DE PSC, Municipalities and PPANJ oppose the request for waiver of Period I and Period II cost of service information. Municipalities, COST and DEMC argue that they cannot fully assess the proposed formula because neither Docket Nos. ER05-513 nor ER05-515 includes sufficient data. Specifically, they note that the TOs are proposing a major change in how rates are set but that ER05-513 includes only a concept with no data and ER05-515 contains limited and stale data for the year prior to the proposed effectiveness of the formula.[33] COST and DEMEC also note that many of inputs to the formula come not directly from the Form 1 filings, but from adjustments to those numbers as evidenced by the multitude of “notes” to the formula. Municipalities request that the Commission require the TOs to submit annual informational filings for the rate year reflecting the most accurate, available data providing, inter alia, information supporting the data not otherwise available in the FERC Form 1,[34] and not merely post the results on PJM's website. COST and DE PSC assert that the Commission should reject the formula rate filings, or in the alternative, set them for hearing.

Discussion

A. Procedural Matters

38. Pursuant to Rule 214 of the Commission's Rules of Practice and Procedure, 18 CFR 385.214 (2003), the notices of intervention and the timely, unopposed motions to intervene serve to make the intervenors parties to this proceeding. Given the early stage of this proceeding, the absence of any undue prejudice or delay, and their interest in this proceeding, we grant the untimely, unopposed motions to intervene. Rule 213(a)(2) of the Commission's Rules of Practice and Procedure, 18 CFR 385.213(a) (2) (2003), prohibits an answer to a protest unless otherwise permitted by the decisional authority. We are not persuaded to allow the answers, and accordingly we will reject them.

B. Analysis

1. Docket No. ER04-156-006

39. The PJM Settling Parties have made the compliance filing required by our order, and seek continuation of PJM's current zonal rate design. However, the Commission has previously recognized that in an RTO or ISO environment, it is no longer clear that a zonal rate design is necessarily just and reasonable. We recently found, in evaluating two competing rate proposals for a new transmission rate design to supersede through and out rates, that neither proposal, including the zonal rate design, had been shown to be just and reasonable and might be unjust and unreasonable.[35]

Start Printed Page 34464

40. We also view the arguments put forward by AEP as potentially demonstrating that modified zonal rates are, in fact, not just and reasonable in a situation such as that faced by AEP and other new PJM entrants now. AEP alleges that it has provided significant new 500 kv transmission capacity to the PJM system, and it anticipates that under modified zonal rates the majority of costs for that contribution will be recovered from load in AEP's transmission zone, despite the fact that it is now serving all PJM members. AEP further alleges that, once the SECA mechanism previously adopted by the Commission expires,[36] it will no longer be able to collect a significant portion of the charges for external transactions that it is now recovering through the SECA.

41. The Commission therefore finds, pursuant to its authority under section 206, that PJM's current modified zonal rate design may not be just and reasonable, and may be unjust, unreasonable, unduly discriminatory or preferential or otherwise unlawful. We therefore set PJM's modified zonal rate design for hearing, and we will require PJM and all of its TO members (not just the PJM Settling Parties who made the filing in Docket No. ER04-156-006) to address the justness and reasonableness of the zonal rate design in that hearing.

42. Pursuant to section 206(b) of the FPA, the Commission must establish a refund effective date that is no earlier than 60 days after the publication of notice of the Commission's intent to institute a proceeding, and no later than five months subsequent to the expiration of the 60-day period. The Commission will establish a refund effective date of 60 days from publication of notice of the Commission's initiation of a hearing. The Commission is also required by section 206 to indicate when it expects to issue a final order. The Commission expects to issue a final order in this section 206 investigation within 180 days of the date this order issues.[37]

2. Docket No. ER05-513-000

43. The Commission will accept the PJM TOs' filing in Docket No. ER05-513-000, to become effective on June 1, 2005. This filing establishes general parameters under which TOs can file to recover the costs of reliability expansions. Protesters have raised questions primarily with respect to Option Two, insofar as this option will enable TOs to file to recover only the costs of RTEP expansions.

44. In their protests regarding the PJM TOs' Option Two, the protesters argue, in essence, that Option Two would not harmonize a TO's revenue recovery for its existing facilities with its revenue recovery for a new project built through the RTEP process, in that the combination of these two methods of revenue recovery could create a potential for over-recovery of the TO's overall costs for all of its facilities, and that there can be no rate proposal for the recovery of the costs of new transmission investment without an examination of whether the existing transmission rates already recover more than the applicant's cost to provide service over its existing facilities.

45. The Commission will accept Option Two, because, this option provides full recovery of all reasonably incurred costs related to the regulated solutions and development undertaken pursuant to the PJM RTEP process and it provides the necessary incentives for transmission owners to build RTEP upgrades quickly, which will benefit all customers.[38] In a recent order regarding the New York Independent System Operator (NYISO), we accepted a rate mechanism that is limited to the recovery of transmission-related costs incurred to meet a reliability need included in New York's Comprehensive Reliability Plan, separate from the transmission service charge and the transmission adjustment charged.[39] This option also is consistent with our April 2004 Policy Statement on Matters Related to Bulk Power System Reliability, in which we assured public utilities that the Commission will stand by its policy to approve applications to recover prudently incurred costs necessary to ensure bulk electric system reliability.[40]

46. Protesters object to this option because of a concern that it may permit certain transmission owners to continue to overrecover their cost-of-service. However, this option provides just and reasonable cost recovery for the RTEP upgrades, and provide the necessary incentive for TOs to complete quickly the construction of RTEP projects that are essential to the efficient operation of PJM. As we said in the NYISO proceeding, if a concern arises regarding over-recovery of transmission costs, such parties are free to seek relief by filing a complaint with the Commission pursuant to section 206 of the FPA.[41]

47. In adopting Option 2, however, we recognize that we do not have before us an actual proposal as to how costs will be recovered under this option. Depending on the form of such a filing, we may need to impose certain reporting requirements or true-up mechanisms with respect to such a filing.

48. Additionally, while we accept Option Three, we will require the PJM TOs to make a compliance filing, within 30 days of the date of this order, providing that any TO selecting Option Three must also make an informational filing with the Commission one year from the date its formula rates go into service, and each year thereafter, providing a detailed list of the costs it has incurred, and the revenues it has received, to provide service.

49. Finally, we will also order the PJM TOs to make a compliance filing, within 30 days of the date of this order, restoring the requirement that under Schedule 12, PJM must designate the “Responsible Customer” that must pay the Transmission Enhancement Charge in such a way as to allow customers to obtain Commission review of those designations.

3. Docket No. ER05-515-000

50. Our preliminary analysis indicates the PHI TOs' filing in Docket No. ER05-515 has not been shown to be just and reasonable, and may be unjust, unreasonable, unduly discriminatory or preferential or otherwise unlawful. Accordingly, we will accept that filing and nominally suspend it to become effective on June 1, 2005, subject to refund, as requested, and subject to the outcome of a hearing.Start Printed Page 34465

51. In West Texas Utilities Company,[42] the Commission explained that when its preliminary examination indicates that the proposed rates may be unjust and unreasonable, and may be substantially excessive, as defined in West Texas, the Commission would generally impose a five-month suspension. It is recognized, however, that shorter suspensions may be warranted in circumstances where suspension for the maximum period may lead to harsh and inequitable results.[43] Such circumstances exist here where the Commission has, in fact, urged transmission owners to move from stated rates to formula rates, and where customers would also benefit from the incentive provided by these rate changes to the PHI TOs to commence construction of RTEP upgrades. Accordingly, the Commission will exercise its discretion to suspend the revisions to the PHI TOs' rates for a nominal period and permit the rates to become effective June 1, 2005, subject to refund and the outcome of the hearing established in this order.

52. As noted above, protesters raise numerous issues regarding the reasonableness of the proposed rates that are best addressed in the hearing we order below. At the hearing, the PHI TOs will be required to support and justify the justness and reasonableness of their proposal.

53. Among the issues that we are setting for hearing are the request for the 100 basis point transmission investment ROE adder and the 50 basis point adder for RTO membership, and we here provide specific directives for the parties to address with regard to these two issues. The Sponsoring TOs have provided support for the 100 basis point adder for all transmission facilities constructed under the RTEP. Consistent with our rehearing order in ISO New England,[44] we direct the parties and the presiding judge to develop a record, in this case, addressing the pros and cons of applying a 100 basis point adder for investments that, among other things: (i) Are approved through the RTEP process; (ii) are capable of being installed relatively quickly; (iii) include the use of improved materials that allow significant increases in transfer capacity using existing rights-of-way and structures; (iv) utilize equipment that allows greater control of energy flows, enabling greater use of existing facilities; (v) has sophisticated monitoring and communication equipment that allows real-time rating of transmission facilities, facilitating greater use of existing transmission facilities; or (vi) is a new technology and/or innovation that will increase regional transfer capability.

54. With regard to the 50 basis point adder for RTO membership, we note that in a prior order regarding ISO New England, we recognized the need to provide appropriate incentives for transmission expansions in RTOs, and granted the New England Transmission Owners a 50 basis point adder on their ROE for Regional Network Service (RNS) revenue.[45] Here, however, as the protesters point out, PJM's current TOs became PJM members many years ago, so that the 50 basis point adder will not specifically serve as an incentive to those TOs to join an RTO. We therefore direct the parties to consider at hearing whether an adder is appropriate here.

55. In Docket No. ER05-515-000, the PHI TOs request waiver of Statements AA through BL and waivers of section 35.13 of the regulations,[46] including waiver the full Period I and Period II, and 35.13(a)(2)(iv) to determine if a proposed change constitutes a rate increase based on Period I-Period II rates and billing determinants. Protestors request that the Commission deny waiver of the cost-of-service statements required under 18 CFR § 35.13. They also state that they need customer protection mechanisms to ensure adequate review of the inputs to formula and request that the Commission direct the PHI TOs to file the April 30, 2005, rate update with the Commission.

56. We will grant waiver of our requirements as to the filing of the requirement of section 35.13 to provide full Period I and Period II data, and 35.13(a)(2)(iv). The filing by the PHI TOs is to establish a formula rate using Form 1 data and, therefore, it is not clear that full Period I and Period II data are needed to evaluate this proposal. However, to the extent that parties at the hearing can show the relevance of additional information to the evaluation of this proposal, the ALJ can provide appropriate discovery of such information.

57. The applicants seek waiver of the requirement that rates be filed 120 days prior to the proposed effective date, stating in support that the settlement in Docket No. ER04-156 provided specifically that any section 205 rate filing would become effective on June 1, 2005. The early filing provided all parties with additional time to review the filings. The Commission will grant the requested waiver.

The Commission orders:

Docket No. ER04-156-000

(A) The Commission accepts the PJM Settling Parties' filing in Docket No. ER04-156-000 as satisfying those parties' obligation to reevaluate the PJM rate design.

Docket No. ER05-513-000

(B) The Commission accepts the PJM TOs' filing in Docket No. ER05-513-000, to become effective June 1, 2005, subject to the conditions and compliance obligations discussed in the body of the order.

(C) The Commission further requires the PJM TOs to make a filing within 30 days of the date of this order, providing that, as discussed above, any transmission owner selecting Option Three must make an informational filing with the Commission one year from the date its formula rates go into service, and each year thereafter, providing a detailed list of the costs it has incurred, and the revenues it has received, to provide service.

Docket No. ER05-515-000

(D) In Docket No. ER05-515-015, the PHI TOs' proposed Schedule 12 and Attachments H-1, H-2, H-3 and H-9 to PJM's OATT are hereby accepted for filing and suspended to become effective on June 1, 2005, subject to refund, and to the outcome of a hearing, as discussed in the body of the order.

(E) The Commission will grant waiver of the requirement that parties file new rates no more than 120 days before the rates go into effect.

(F) The Commission grants waiver of the requirement of section 35.13 to provide full Period I and Period II data, and 35.13(a)(2)(iv) to determine if and the extent to which a proposed change constitutes a rate increase based on Period I-Period II rates and billing determinants.

(G) Pursuant to the authority contained in and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by section 402(a) of the Department of Energy Organization Act and by the Start Printed Page 34466Federal Power Act, particularly sections 205 and 206 thereof, and pursuant to the Commission's Rules of Practice and Procedure and the regulations under the Federal Power Act (18 CFR Chapter I), a public hearing shall be held in Docket No. ER05-515-000 concerning the justness and reasonableness of proposed formula rates in Attachment H to the PJM OATT, as discussed in the body of this order.

(H) A presiding administrative law judge, to be designated by the Chief Administrative Law Judge, shall convene a prehearing conference in the Docket No. ER05-515-000 proceedings, to be held within approximately fifteen (15) days from the date of this order, in a hearing room of the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, D.C. 20426. Such conference shall be held for the purpose of establishing a procedural schedule. The presiding judge is authorized to establish procedural dates and to rule on all motions (except motions to dismiss), as provided in the Commission's Rules of Practice and Procedure.

Docket No. EL05-121-000

(I) Pursuant to the authority contained in and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by section 402(a) of the Department of Energy Organization Act and by the Federal Power Act, particularly sections 205 and 206 thereof, and pursuant to the Commission's Rules of Practice and Procedure and the regulations under the Federal Power Act (18 CFR Chapter I), a public hearing shall be held in Docket No. EL05-121-000 concerning the justness and reasonableness of PJM's modified zonal rates, as discussed in the body of this order.

(J) A presiding administrative law judge, to be designated by the Chief Administrative Law Judge, shall convene a prehearing conference in the Docket No. EL05-121-000 proceedings, to be held within approximately fifteen (15) days from the date of this order, in a hearing room of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426. Such conference shall be held for the purpose of establishing a procedural schedule. The presiding judge is authorized to establish procedural dates and to rule on all motions (except motions to dismiss), as provided in the Commission's Rules of Practice and Procedure.

(K) Any interested person desiring to be heard in the proceedings in Docket No. EL05-121-000 should file a notice of intervention or motion to intervene with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Rule 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.214) within 21 days of the date PJM makes the filing directed in Paragraph (B) above.

(L) The Secretary is directed to publish a copy of this order in the Federal Register.

(M) The refund effective date established pursuant to section 206(b) of the FPA will be 60 days following publication of this order in the Federal Register as discussed in Ordering Paragraph (L) above.

By the Commission. Chairman Wood concurring in part with a separate statement attached. Commissioner Kelliher dissenting in part with a separate statement attached. Commissioner Kelly dissenting in part with a separate statement to be issued later.

Start Signature

Linda Mitry,

Deputy Secretary.

End Signature

Appendix A

Docket No. ER04-156-006

Interventions

Maryland Public Service Commission

Public Utilities Commission of Ohio

PJM Interconnection, LLC

Exelon Corporation

Allegheny Energy Supply Company, LLC

International Steel Group, Inc.

North Carolina Electric Membership Corporation

Borough of Chambersburg, Pennsylvania

D.C. Public Service Commission

Consumers Energy Company (Consumers)

Dominion Virginia Power (Dominion)

Comments/Protests

PJM Industrial Consumer Coalition (PJM ICC)

Pennsylvania Office of Consumer Advocate, Maryland Office of People's

Counsel, and the Office of the People's Counsel for the District of Columbia (Joint Consumer Advocates)

Delaware Public Service Commission (DE PSC)

Old Dominion Electric Cooperative (ODEC)

The Detroit Edison Company (Detroit Edison)

Exelon Corporation

Customers and Officials for Sensible Transmission (COST);

Allegheny Electric Cooperative, Inc,

American Municipal Power-Ohio

Blue Ridge Power Agency

Borough of Chambersburg, Pennsylvania

Central Virginia Electric Cooperative

City of Dowagiac, Michigan

City of Hagerstown, Maryland

City of Sturgis, Michigan

Craig-Botetourt Electric Cooperative

Delaware Municipal Electric Corporation, Inc.

Delaware Public Service Commission

Harrison Rural Electrification Association

Indiana Municipal Power Agency

Old Dominion Electric Cooperative

PJM Industrial Consumer Coalition

Public Power Association of New Jersey

Southern Maryland Electric Cooperative

Town of Easton, Maryland

Town of Front Royal, Virginia

Town of Thurmont, Maryland

Town of Williamsport, Maryland

Virginia Municipal Electric Association No. 1

American Electric Power Service Corporation (collectively AEP)

Appalachian Power Company, Columbus Southern Power Company,

Indiana Michigan Power Company, Kentucky Power Company, Kingsport

Power Company, Ohio Power Company, and Wheeling Power Company

Docket No. ER05-513-000

Interventions

Maryland Public Service Commission

Public Utilities Commission of Ohio

PJM Interconnection, LLC

Allegheny Energy Supply Company, LLC

International Steel Group, Inc.

Borough of Chambersburg, Pennsylvania

Consumers

PJM Industrial Customer Coalition

D.C. Public Service Commission

Pennsylvania Public Utilities Commission

PEPCO Holdings, Inc., and its operating affiliates; Potomac Electric Power Company, Atlantic City Electric Company, Delmarva Power & Light Company (PHI Companies)

UGI Utilities, Inc.

PPL Electric Utilities Corporation (PPL)

New Jersey Board of Public Utilities (NJBPU)

Muni-Coop Coalition;

Blue Ridge Power Agency

Central Virginia Electric Cooperative

City of Dowagiac, Michigan

City of Sturgis, Michigan

Craig-Botetourt Electric Cooperative

Harrison Rural Electrification Association

Indiana Municipal Power Agency

Old Dominion Electric Cooperative

Virginia Municipal Electric Association No. 1

International Steel Group

ODEC

FirstEnergy Companies (Jersey Central Power & Light Company, Metropolitan Edison Company, Pennsylvania Electric Company)

Dominion Virginia Power (Dominion)

Baltimore Gas and Electric Company

Comments/Protests

Joint Consumer Advocates

DE PSC

North Carolina Electric Membership Corporation

American Municipal Power—Ohio, Inc. (AMP Ohio)

Southern Maryland Electric Cooperative

North Carolina Electric Membership Corporation (NCEMC)

Wisconsin Electric Power Company

Detroit Edison

City and Towns of Hagerstown, Thurmont, and Williamsport, Maryland, and Town of Front Royal, Virginia (Municipalities)

Delaware Municipal Electric Corporation (DEMEC)

Maryland Office of People's CounselStart Printed Page 34467

Easton Utilities

Public Power Association of New Jersey (PPANJ)

Customers and Officials for Sensible Transmission (COST);

Allegheny Electric Cooperative, Inc,

American Municipal Power-Ohio

Blue Ridge Power Agency

Borough of Chambersburg, Pennsylvania

Central Virginia Electric Cooperative

City of Dowagiac, Michigan

City of Hagerstown, Maryland

City of Sturgis, Michigan

Craig-Botetourt Electric Cooperative

Delaware Municipal Electric Corporation, Inc.

Delaware Public Service Commission

Harrison Rural Electrification Association

Indiana Municipal Power Agency

Old Dominion Electric Cooperative

PJM Industrial Consumer Coalition

Public Power Association of New Jersey

Southern Maryland Electric Cooperative

Town of Easton, Maryland

Town of Front Royal, Virginia

Town of Thurmont, Maryland

Town of Williamsport, Maryland

Virginia Municipal Electric Association No. 1

Docket No. ER05-515-000

Interventions

Maryland Public Service Commission

Exelon Corporation

PJM Interconnection, L.L.C.

Pennsylvania Public Utilities Commission

PPL Electric Utilities Corporation

Rockland Electric Company

Allegheny Energy Supply Company

Public Utilities Commission of Ohio

Allegheny Power

PJMICC

D.C. Public Service Commission

Borough of Chambersburg, Pennsylvania

Muni-Coop Coalition

PSEG Companies

UGI Utilities, Inc.

ISG Sparrows Point/International Steel

NJBPU

Virginia State Corporation Commission

Wisconsin Electric Power Company

New Jersey Ratepayer Advocate

Constellation Energy Commodities Group

Dominion

Comments/Protests

Southern Maryland Electric Company*

Allegheny Electric Cooperative*

FirstEnergy Companies

DEMEC

DE PSC

Detroit Edison

Municipalities

Joint Consumer Advocates

Maryland Office of People's Counsel

ODEC

Easton Utilities*

COST

PPANJ

WOOD, Chairman, concurring in part:

In Docket No. ER05-513, I believe that a better policy outcome would have been for the Commission to show a strong preference for formula rates, similar to the Parties' proposed Option Three. Under Option Three, formula rates will decrease as existing assets depreciate and the rates will increase when TOs construct new transmission assets (and this is exactly how all TOs in the Midwest ISO recover the costs incurred in the construction of new facilities.) One major benefit of formula rates is that they provide TOs with a relatively simple way to recover new transmission investment in the year that the facility is placed in service, without having to wait for the next rate case, while efficiently protecting customers from overcharges by reflecting decreased costs (due, for example, to depreciation of existing plant). However, since the Three Option proposal set forth by the PJM TOs is not unjust or unreasonable per se, I will concur with respect to this issue.

In Docket No. ER05-515, the issue of the 50 basis point adder is a policy determination which, unlike the situation of the Midwest ISO in Docket No. ER02-485, has had proper notice and received substantial commentary from parties to this proceeding. Based on these pleadings, I believe that the existing record supports the 50 basis point adder for RTO membership without having to reexamine this issue in a hearing. However, since some parties have raised general questions about the adder, I see no harm to err on the side of caution and to permit further inquiry into the 50 basis point adder at the hearing. For these reasons, I concur on this issue.

Pat Wood, III,

Chairman.

Joseph T. KELLIHER, Commissioner dissenting in part:

I disagree with the Commission's decision to set the PHI TOs' request for a 50 basis point adder for RTO membership for hearing insofar as the proposal would extend the incentive to existing members of PJM. The purported purpose behind the 50 basis point adder is to provide an incentive for transmission owners to join an RTO.[47] However, under the proposal, the 50 basis point adder would be given not only to new PJM members, but also to transmission owners who were already members of PJM when this policy was announced. I fail to see how granting a 50 basis point adder to existing members of PJM, some of whom joined over fifty years ago, accomplishes the goal of creating an incentive for new members to join. Self-evidently, a 50 basis point adder is not necessary to entice existing members of PJM to join, since they already are members. Nor do I see any nexus between providing an incentive to longstanding members of PJM and the goal of providing an incentive for non-members to join an RTO. Instead, this strikes me as merely providing a windfall to existing members of PJM, many of whom decided long ago to sign up as members.

In my view, the PHI TOs have failed to demonstrate the justness and reasonableness of providing longstanding PJM members with a 50 basis point adder that is designed to serve as an incentive for other transmission owners to join the RTO, and I see no point in setting the matter for hearing on the issue of whether the proposal is appropriate here. I would reject the proposal outright. Accordingly, I dissent in part from the order.

Joseph T. Kelliher.

End Preamble

Footnotes

2.  See Midwest Independent Transmission System Operator, Inc., 109 FERC ¶ 61,168 at P 10 n.14 (November 18 Order) (“Under a license plate rate design, the RTO's footprint is segregated into a number of transmission pricing zones, typically based on the boundaries of individual transmission owners or groups of transmission owners, and customers taking transmission service for delivery to load within the RTO pay a rate based on the embedded cost of the transmission facilities in the transmission pricing zone where the load is located. Thus, under license plate rates, customers serving load within the RTO pay for the embedded cost of the transmission facilities in the local transmission pricing zone and receive reciprocal access to the entire regional grid”).

Additionally, PJM notes that, while currently the costs of existing facilities in each transmission owner's geographic zone are recovered from the load in that zone, in the future, facilities constructed under the PJM Regional Transmission Expansion Plan process may be located in one zone, but the costs of those facilities may be allocated to load in other zones. Thus, PJM asserts, its rate design is no longer a “pure” license plate rate design, but more accurately described as a modified zonal rate design. PJM January 31, 2005 filing in Docket No. ER04-156-006 at 2.

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3.  Allegheny Power System Operating Companies, et al., 106 FERC ¶ 61,003 (2004) (January 2 Order).

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4.  This settlement (May 26 Settlement) was accepted by Commission order issued on August 9, 2004, in Allegheny Power Sys. Operating Companies, et al., 108 FERC ¶ 61,167 (2004) (August 9 Order).

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5.  For the purposes of this proceeding, the PJM Settling Parties shall be the following: Allegheny Power System Operating Companies: Monongahela Power Company, Potomac Edison Company, and West Penn Power Company, all d/b/a Allegheny Power; the following PHI Operating Companies: Potomac Electric Power Company; Delmarva Power & Light Company; Atlantic City Electric Company; and Baltimore Gas and Electric Company, Jersey Central Power & Light Company; Metropolitan Edison Company; PECO Energy Company; Pennsylvania Electric Company; PPL Electric Utilities Corporation; Public Service Electric and Gas Company; Rockland Electric Company; and UGI Utilities, Inc. and PJM Interconnection, L.L.C.

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6.  The long term pricing structure (LTPS) proceeding addresses the existing regional through and out rates (RTOR) between the Midwest ISO and PJM. In its November 18 Order at PP 61 and 62, the Commission eliminated rates for new RTOR service effective December 1, 2004, and approved use of license plate rates for pricing RTOR service between Midwest ISO and PJM through January 31, 2008. Since the eliminated RTOR rates resulted in lost revenues to transmission owners, this action was accompanied by a Seams Elimination Charge/Cost Adjustment/Assignment (SECA) charge. See Midwest Independent Transmission System Operator, Inc., et al., 105 FERC ¶ 61,212 (2003).

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7.  November 18 Order at P 42.

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8.  Id. at P 62.

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9.  Citing PJM Interconnection, L.L.C., et al., 109 FERC ¶ 61,094 at P16 (2004).

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10.  Section 3(C) of the May 26 Settlement.

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11.  In addition to those PJM TOs above, this filing would govern future rate filings by all of the PJM TOs that are listed in Attachment L to PJM's Tariff, including American Electric Power Service Corporation, Commonwealth Edison Company, Dayton Power and Light Company, Virginia Power and Light Company, and Duquesne Light Company.

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12.  See PJM's Tariff, proposed Schedule 12—Appendix A. Specifically, Transmission Enhancement Charges for RTEP projects can be the product of a section 205 filing under Option Two, or the application of the formula rate to the costs of the required Transmission Enhancement pursuant to Option 3.

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14.  The proposed formula is comprised of PJM Tariff sheets that are designated as PJM Tariff, Attachments Nos. H-1 for ACE, H-2 for BGE, H-3 for Delmarva, and H-9 for Pepco.

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15.  The PHI TOs note that “the formula rate proposed here will provide a timely and effective means to “harmonize” the costs of new facilities with a company's embedded transmission revenue requirements.” PHI TOs' filing, transmittal letter at 3. We therefore assume that, effectively, the PHI TOs are electing Option 3, of the three options set forth in the PJM TOs' filing in Docket No. ER05-513.

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18.  PJM Interconnection, L.L.C., 104 FERC ¶ 61,124 at P 72 (2003) (RTEP Order).

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19.  Id. at P 74.

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21.  70 FR 797-798 (2005).

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22.  The comments and protests filed by certain of those parties will be discussed below.

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23.  “A levelized rate is designed to recover all capital costs through a uniform, nonvarying payment over the life of the asset, just as a traditional home mortgage payment does.” Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,193 (1999), order on reh'g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), appeal dismissed sub. nom. Public Utility District No. 1 v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

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24.  109 FERC ¶ 61,168 (2004).

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25.  According to AEP, the Commission has presently approved $1.66 billion of revenue requirements for PJM and, with Total RTEP Baseline Reinforcements of $574 million, AEP estimates that the revenue requirement associated with these additions is $20 million or less than 2 percent of total revenue requirements (see attachment to AEP protest).

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26.  According to AEP's filing in Docket No. ER05-751-000, AEP projects SECA revenue of $163.8 million for 2005.

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27.  According to AEP, the Commission has consistently indicated that license plate pricing should be regarded as a temporary expedient pending the development of a regional rate design.

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28.  Allegheny Power System Operating Companies, 106 FERC ¶ 61,016 (2004).

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29.  Citing, Carolina Power & Light Co. v. FERC, 860 F.2d 1097 (D.C. Circuit), and Florida Power and Light Co. v. City of Miami, 92 F.2d 180, 183 (5th Cir 1938) (Federal appellate court rejecting a proposal to add new facilities costs atop an existing point-in-time rate base).

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30.  Citing Section 30.9 of the PJM Tariff.

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31.  PPANJ cites to Southwest Power Pool, Inc. 108 FERC 61,078 (2004) at Par. 19, order on remand from East Texas Electric Cooperative, Inc. v. FERC, 331 F. 3d. 131 (D.C. Cir. 2003) (“The Commission stated that the intent of section 30.9 of the pro forma tariff was that, for a customer to be eligible for a credit, its facilities must not only be integrated with the transmission provider's system, but must also provide additional benefits to the transmission grid in terms of capability and reliability, and be relied upon for the coordinated operation of the grid”).

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32.  NCEMC cites Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act, FERC Stats. and Regs. ¶ 31,005, at 31,146 (1994).

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33.  E.g., Municipalities advise that the TOs admit that the data is not accurate for at least one who will undergo substantial reclassification. Citing ER05-515-000 transmittal letter, n.8.

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34.  Citing Southern Company Services, 99 FERC ¶ 61,069 (2002) (requiring projections of formula rate billing determinants and revenues); Florida Power & Light Co., 67 FERC ¶ 61,326 at p. 62.147 (1994) (requiring filing of Period I and Period II data to adopt formula rates).

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35.  Midwest Independent Transmission System Operator, 110 FERC ¶ 61,107 at P 3 (2005), citing November 18 Order. See also New PJM Companies, 108 FERC ¶ 61,140 at P 40 (2004) (“the Commission has accepted license plate rate designs for new RTO entrants on a transitional basis, and * * * we [recently] reaffirmed our commitment to retaining revenue neutrality for companies that join RTOs. This does not mean, however, that the Commission must find any license plate rate, or any rate mechanism submitted by a company with proposed revisions to their cost of service just and reasonable simply because the company claims that it maintains revenue neutrality”).

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36.  In an order issued on November 30, 2004, the Commission expanded AEP's, ComEd's and DP&L's ability to recover lost revenues resulting from the integration with PJM through the SECA transition methodology, which expires on March 31, 2006. Midwest Independent Transmission System Operator, Inc., 109 FERC ¶ 61,243 at P 9 (2004) (November 30 Order).

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37.  The Commission is not consolidating this proceeding, which involves PJM's internatl rate design, with the LTPS proceeding in Docket No. EL02-111-000, which addresses rate design between PJM and MISO. However, if the parties believe that these proceedings are interrelated, either for purposes of settlement or hearing, they can file motions for consolidation of proceedings before the Administrative Law Judge (ALJ) in each proceeding.

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38.  The filing in Docket No. ER05-513-000 does not address the question of ROE adders with respect to Option Two, and the Commission therefore will not address here whether such adders are appropriate in light of the incentive already provided by Option Two to construct upgrades.

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39.  New York Independent System Operator, Inc., 109 FERC ¶ 61,372 at P 28 (2004), order on reh'g, 111 FERC ¶ 61,182.

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40.  Policy Statement On Matters Related To Bulk Power System Reliability, 107 FERC ¶ 61,052 (2004).

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41.  See New York Independent System Operator, 111 FERC ¶ 61,182 at P 24 (2005).

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42.  18 FERC ¶ 61,189, at 61,374 (1982) (West Texas).

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43.  California Independent System Operator Corporation, 105 FERC ¶ 61,406 (2003).

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44.  Id. at P 206.

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45.  ISO New England, 106 FERC ¶ 61,280 at P 245-46 (ISO-NE) (2004) (“We agree with the ROE Filers that their voluntary proposal to establish RTO-NE and their commitment to transfer the day-to-day operational control authority over their transmission facilities to RTO-NE, warrants a 50 basis point incentive adder to the ROE component recovered in RTO-NE's transmission rates for Regional Network service. Accordingly, we will accept this incentive adder with respect to these facilities without suspension or hearing”), order on reh'g, 109 FERC ¶ 61,147 (2004).

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47.  Proposed Pricing Policy for Efficient Operation and Expansion of the Transmission Grid, 102 FERC ¶ 61,032 at P 24 (2003) (“Under this proposed policy, any entity that transfers operational control of transmission facilities to a Commission-approved RTO would qualify for an incentive adder of 50 basis points on its ROE for all such facilities transferred.”).

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[FR Doc. 05-11596 Filed 6-13-05; 8:45 am]

BILLING CODE 6717-01-P