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UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Maine Public Utilities Commission, et al., )
v. ) Docket No. EL03-222-000
ISO New England, Inc., )
In accordance with Rule 213 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission (“Commission” or “FERC”), 18 C.F.R. § 385.213 (2003), the Maine Public Utilities Commission, the Maine Public Advocate, the Rhode Island Public Utilities Commission, the Rhode Island Division of Public Utilities and Carriers, the Rhode Island Attorney General, Pinpoint Power, NRG Energy, Inc. and Gen Power, LLC (collectively, “Coalition Supporting Beneficiary Funding” or “Coalition”) hereby answer the requests to dismiss their August 21, 2003 Complaint in the captioned proceeding. In addition, the Coalition requests leave to respond to the answer filed by the New England Power Pool and ISO New England, Inc. (“NEPOOL”) as well as the protests and comments submitted by other participants in opposition to the Complaint.
Pursuant to Rule 213, the Coalition is entitled to answer the parties requesting the Commission to dismiss the complaint. With respect to NEPOOL’s Answer and the protests and other adverse comments filed in response to the Complaint, Commission Rule 213(a)(2) generally proscribes the filing of an answer to answers or protests “unless otherwise ordered by the decisional authority.” 18 C.F.R. § 385.213(a)(2) (2002). The Commission will accept answers to answers upon a showing of good cause. See Midcoast Interstate Transmission, Inc., 83 FERC ¶ 61,195 at p. 61,829 (1998). The Commission has found good cause to exist where an additional answer will assist in clarifying and explaining the issues in the case and help to frame the issues in dispute. See, e.g., Chesapeake Panhandle Ltd. P’ship v. Natural Gas Pipeline of America, 92 FERC ¶ 61,082 at p. 61,348 (2000). Good cause exists to consider the instant answer, as it will assist in clarifying and explaining the issues in dispute.
NEPOOL, CTDPUC, NU and National Grid ask the Commission to dismiss the Coalition Complaint because they claim it addresses the same issues that will be addressed in Docket No. ER03-1141 (NEPOOL’s filing of the TCA Amendments). Their requests should be rejected. The Coalition Complaint asks the Commission to find that the current methodology is unjust and unreasonable (a finding the Commission has implicitly made in previous orders) and to replace it with the Coalition proposal. The relief sought by the Coalition is thus the proper subject of a complaint. By filing a complaint, the Coalition ensured that all interested persons would have notice of and an opportunity to comment on their proposal. See Louisiana Power and Light Co., 50 FERC ¶ 61,040 at pp. 61,062-3 (1990). However, if the Commission believes that consolidation of the Complaint with Docket No. ER03-1141 would contribute to the efficient processing of these cases; the Coalition has no objection to these cases being consolidated as long as the Coalition proposal is considered as an alternative to the current methodology, as well as the TCA amendments.
B. Claims That Reliability And Economic Upgrades That Meet A kV Threshold Provide System Wide Benefits Remain Unsupported
NEPOOL and others state that, by definition, “Reliability and Economic” upgrades provide system wide benefits, because the current and proposed definitions of reliability and economic upgrade say it is so. NEPOOL thus assumes away any need to support the statement in the definition of reliability upgrade that reliability upgrades are necessary to ensure the continued reliability of the NEPOOL system. It is clear from the NEPOOL Tariff reliability upgrade definition (which remains unchanged from the current definition in the NEPOOL Tariff), however, that the definition includes upgrades that provide predominantly local benefits:
Those additions and upgrades not required by the interconnection of a generator that are nonetheless necessary to ensure the continued reliability of the NEPOOL system, taking into account load growth and known resource changes, and include those upgrades necessary to provide acceptable stability response, short circuit capability and system voltage levels, and those facilities required to provide adequate thermal capability and local voltage levels that cannot otherwise be achieved with reasonable assumptions for certain amounts of generation being unavailable (due to maintenance or forced outages) for purposes of long-term planning studies. Good Utility Practice, applicable reliability principles, guidelines, criteria, rules, procedures and standards of NERC and NPCCC and any of their successors, applicable publicly available local reliability criteria, and the NEPOOL System Rules, as they may be amended from time to time, required to maintain reliability in evaluating proposed Reliability Upgrades.
NEPOOL OATT § 1.106 (emphasis added).
This definition makes clear that any project that is needed to address local reliability needs is by definition determined to ensure the continued reliability of the NEPOOL system. Far from proving that projects that are socialized under the current and proposed methodology provide system wide benefits, NEPOOL simply points out tariff language that makes this assumption. Thus NEPOOL’s explanation is entirely circular. NEPOOL and others cannot simply define away the need to show that there are significant and quantifiable reliability benefits to all areas of NEPOOL that are at least as great as the benefits provided to the local area. In fact, RTEP and local siting decisions support the opposite conclusion: that most projects address local reliability or economic concerns and thus predominantly benefit local areas.
C. The Current System, Like The Proposed TCA Amendments, Results In Broad Socialization Notwithstanding The Various Classifications Of Upgrades
Some protestors (NU and National Grid) argue that the Coalition Complaint overstates the extent to which the current system and the proposed TCA Amendments result in broad socialization of transmission upgrades. Despite the many distinctions that are made under the current and proposed methodology, however, the result is that virtually every proposed upgrade that meets the threshold kV requirement and other non-voltage criteria will receive socialized cost treatment. For example, the ISO has stated that under the proposed TCA amendments, every project recommended in RTEP-02 would be considered a reliability upgrade and would receive socialized cost treatment. Similarly, the draft RTEP-03 states:
RTEP-03 identifies nearly 40 regulated transmission projects throughout New England. Some of these have been planned, some are proposed, and some are in the early stages of development. These latter projects do not yet have cost estimates associated with them. The transmission upgrades for which estimates are available are expected cost a minimum of $1.4 billion. Of this figure, 85 million is for new projects identified in RTEP-03. All projects listed are needed to maintain power system reliability.
Draft RTEP-03 Executive Summary. While the current cost methodology and the proposed TCA Amendments may have numerous categories of upgrades, the number is unimportant as long as the process works to funnel all projects that meet the kV threshold (and are not radial lines) into the broad category of projects that are socialized. For example, the likelihood of any project fitting into the voluntary funding (which under the TCA Amendments is called participant funding) category is certain to be very small, because in the absence of someone volunteering to pay for an upgrade, the project costs will be subsidized. In fact, the option for voluntary funding has been in the NEPOOL Tariff for several years along with the socialization default methodology, but no entity has ever selected this option. Further, the criteria under which a project is classified as a reliability upgrade are so broad as to include any project that may have predominantly local reliability benefits. See NEPOOL OATT § 1.106. Parties who suggest that socialization is not the rule but the exception under the current system or the proposed TCA Amendments either misunderstand the way the methodology is meant to work or are trying to present a less than forthright picture of the current methodology or the proposed TCA Amendments.
D. The CTDPUC Claim That The Coalition And Dr. Hogan Failed To Consider The Effect Of The Proposed Upgrades And Other Costs On The Connecticut Economy Relies On Unsupported Allegations And Sidesteps The Issues Raised By The Complaint
The CTDPUC confronts the Commission with a parade of costs allegedly borne by Connecticut designed to convince the Commission that the entire cost of their proposed upgrades should be spread across the entire pool. First, without a hearing and a chance to contest these allegations, the Commission cannot reasonably rely on these claimed burdens as a basis for its decision. For example, the CTDPUC suggests that Locational ICAP (LICAP) will cost Connecticut consumers $450 million a year. This figure, however, is simply the high end of a very broad range of projected costs: the low end of the range is $4 million a year. Further, the CTDPUC has provided no evidence to support its allegation that LMP will cost it an additional $220 million annually, nor is it clear whether these LMPs can be hedged using FTRs and will be mitigated by the allocation of ARR revenues.
Second, the CTDPUC fails to point out that these costs (whatever the proper figures are) are more likely substitutes for one another rather than cumulative. For example, once the annualized local portion of the upgrade is applied to Connecticut consumers’ local transmission rates (once the upgrades are complete), LMPs are likely to have decreased, largely as a result of the transmission upgrades themselves. Further, it is not clear that the cost of RMR contracts or emergency generator contracts will continue once the transmission upgrades are built. Finally, the ISO has indicated that RMR costs and LICAP costs would not be charged at the same time since LICAP is a substitute for RMR contracts.
Third, and most important, the fact that Connecticut is experiencing higher costs indicates that it is precisely Connecticut that has the problem, and will benefit from the solution. Accordingly, it is Connecticut that should assume cost responsibility for the steps that may be necessary to reduce these costs. Whether these actions are demand response, generation siting or transmission construction, or a combination of actions, the locational pricing system is sending the proper signals. That Connecticut is now responding to these high costs by siting transmission (as opposed to some other approach) does not alter the fundamentally local character of the problem. Put another way, its is certainly not obvious why, if the problem to be addressed is high cost or reliability concerns for Connecticut consumers, the rest of New England should be taxed to pay for the solution.
E. Claims That The Coalition Proposal Is Arbitrary Only Serve To Underscore The Unreasonableness Of Socializing 100 Percent Of Transmission Upgrades
Some protestors claim that the 75 /25 percent allocation proposed by the Coalition is arbitrary because the Coalition does not compare the proposal to (1) a possible 50/50 allocation (NU and CTDPUC) or (2) a 25/75 percent allocation (NU). These claims have no merit. The Coalition had no obligation to compare its proposal to other cost allocation methodologies that were not on the table for discussion. The 50/50 cost allocation proposed by the MPUC and the RIPUC was not accepted by NEPOOL and no one has formally proposed the 25/75 split. The only methodology before the Commission is the current and proposed 100 percent socialization of upgrades and the Coalition’s proposed 75/25 split. The 100 percent socialization methodology, as the Commission has noted in previous orders, fails to adhere to cost causation principles and is inconsistent with LMP because it does not allocate costs to those who are the primary beneficiaries of the upgrades. The same would be true of a 25/75 split, because most of the costs would continue to be socialized.
The Coalition proposal gives the benefit of the doubt to those who claim that eventually everyone will benefit from an upgrade. The Coalition proposal errs, if at all, in allowing a substantial percentage of costs to be socialized when there is no empirical showing that areas other than the primary beneficiary areas benefit from upgrades sufficiently to warrant that 25 percent of the cost of the project should be spread across the entire pool. What is clearly arbitrary is to suggest that all of the costs of a project be rolled in without being able to specify the degree to which the whole region will benefit, when primary beneficiaries of a project are identified through local siting process and the RTEP.
NEPOOL’s insistence on 100 percent socialization puts it at odds with the methodology in PJM and NYISO. While that alone does not make NEPOOL’s current or similar proposed cost methodology unreasonable, it provides a useful comparison when protestors claim that it is arbitrary to allocate the majority of the costs of upgrades to primary beneficiaries of the upgrade. The NEPOOL proposal appears to suggest that since it cannot pinpoint or quantify how much the region will benefit in comparison to local beneficiaries, 100 percent of the costs of the project should be spread across the region. The Coalition proposal more logically suggests that if one set of beneficiaries can be identified and other possible benefits are vague or unquantifiable, all or most of the costs should be allocated to the identifiable beneficiary.
F. The Justness And Reasonableness Of The 100 Percent Socialization Methodology Cannot Be Determined By Simply Counting Heads
NEPOOL argues that the Commission should be swayed by the fact that the Beneficiary Funding proposal was rejected by NEPOOL in favor of the TCA Amendments’ 100 percent socialization proposal. The Commission should reject this invitation to determine the justness and reasonableness of a proposal by counting heads. For example, in Tejas Power Corporation v. FERC, 908 F.2d 988 (D.C. Cir. 1990), the D.C. Circuit found that the Commission was not justified in relying upon the buyers’ agreement to a settlement or to the absence of opposition by the state commissions in determining that an agreement was in the public interest. The D.C. Circuit faulted the Commission for failing to “look beyond the benefits that it foresees for the pipeline and its LDC customers in order to determine whether any benefits or harm might accrue to the LDC’s downstream consumers who, presumably, will bear the cost of the GIC [Gas Inventory Charge].” Id. at 1003. See also, Exxon Company, U.S.A. v. FERC, 182 F.3d 30, 50 (D.C. Cir. 1999) (FERC cannot simply take a head count in resolving contested settlements; “[p]arties raising legitimate legal objections cannot be overlooked simply because they are out numbered.”). Simply because 100 percent socialization was favored by a majority of parties with monetary interests does not make the NEPOOL proposal just and reasonable. Neither does the ISO’s support of this proposal require its approval. See, ISO New England, Inc., 93 FERC ¶ 61,290 (2000) (rejecting ICAP deficiency charge filed by ISO-NE and supported by both ISO-NE and by a majority of NEPOOL stakeholders), remanded on other grounds, Central Maine Power Co. v. FERC, 252 F.3d 34 (1st Cir. 2001).
The Commission must determine whether the Complaint’s 75/25 percent beneficiary funding proposal or a 100 percent socialization proposal is the most consistent with competitive markets, and is equitable for all consumers. In short, the Commission must weigh the Coalition’s beneficiary funding proposal against the current and proposed 100 percent socialization proposal and determine whether the current system is unjust and unreasonable (a determination it has implicitly made in earlier orders) and whether the Coalition’s proposal is a just and reasonable replacement for the current (and proposed) flawed methodology.
NEPOOL also claims that the proposal must be rejected because there is insufficient detail. Lack of tariff language in a proposal, however, has never been a barrier to approval. Such language is typically ordered in a compliance filing. See, e.g., Electrical Dist. No. 1 v. FERC, 774 F.2d 490, 492-93 (D.C. Cir. 1985). Further, any party can contest the compliance filing to assert that it is inconsistent with the Commission’s direction.
G. Contrary To Protestors’ Claims, There Is No Insurmountable Obstacle To Identifying Beneficiaries
Protestors raise the specter of long and complex litigation to determine primary beneficiaries. This specter is both illusory and fundamentally irrelevant. The Connecticut projects are a perfect example. RTEP-02 indicates that the purpose of the upgrade is to improve severe reliability problems in Southwest Connecticut. The siting board decision reaches the same conclusion:
The Independent System Operator of New England, (ISO-NE) further reinforced the reality that SWCT is vulnerable to losing transmission and local generation. Local generation in SWCT is about 40 years in age and the present owners (NRG) have notified ISO-NE that certain generators would be retired. While this action could jeopardize the need for electric resources to SWCT and the State, ISO-NE warns that the existing 115-kV transmission system in the SWCT area is inadequate to deliver the energy necessary to meet demand on a peak day. In the last two years, ISO-NE has studied and concluded there is a need for up to 300 MW for the summer of 2003 above existing generation and transmission resources serving the SWCT area. Thus, ISO-NE issued Requests for Proposals seeking between 100 and 300MW of load reduction and/or emergency generation in the SWCT area. Consequently, ISO-NE recommends a 345-kV transmission line as a solution for energy delivery in SWCT.
Connecticut Siting Council, Docket No. 217, Opinion, July 14, 2003. And even those who claim beneficiaries cannot be identified make different claims when trying to justify the project to Connecticut consumers. For example, Connecticut Light & Power witness Roger Zaklukiewicz testified before the Connecticut Siting Council in support of the proposed Phase One project:
The proposed line will both meet the immediate need for additional transmission capacity and provide a critical component of a long-term solution for Southwestern Connecticut’s reliability and congestion problems.
* * *
Moreover, we anticipate that the congestion cost saving of building the loop will be significantly greater than its construction cost, thereby reducing the cost of electricity in Connecticut from what it would otherwise be.
The proposal is not intended to provide a means of “siphoning” power to “high price markets,” as some have said. It is intended to end the electric isolation of Southwestern Connecticut and integrate it into the state and regional grids. Such regional integration serves our state well. For most hours of the year, Connecticut is expected to be a net importer of electric energy and will continue to be after its 345-kV loop is completed.
Testimony of Roger Zaklukiewicz in Connecticut Siting Council, Docket No. 217 (emphasis added) (excerpts attached). See also, Written Comments of the United Illuminating Company in CTDPUC Investigation of NEPOOL Standard Market Design, Docket No. 03-02-16, March 18, 2003 (“Transmission infrastructure as planned in the Southwest Connecticut Transmission Reliability Project is necessary to provide Connecticut a reliable and economic supply of electricity”).
H. Primary Beneficiary Cost Allocation Does Not Require A “Now And Forever” Identification Of Primary Beneficiaries
CMEC asserts that the Coalition proposal is flawed because “it is difficult (or impossible) to determine now and forever the “primary beneficiaries “ of a proposed new or upgraded transmission facility” because in their view (1) a project that provides parallel looped capability benefits the entire grid (presumably to the same degree that it benefits a local area) and (2) the identity of primary beneficiaries may change over time.
The notion that a cost allocation methodology must identify all beneficiaries for the life of the project is unrealistic and inconsistent with the manner in which the need for the project is determined. The determination of need for the project is based on carefully researched projections of future needs, costs and other factors. Thus, for example, the Connecticut Siting Council determined that the Phase I project was needed to address reliability and congestion problems in Connecticut. In determining that this project was necessary to address these local needs, the Siting Council was aware that conditions could change in such a way as to reduce need for the project. As stated in the Complaint, “[t]here is no more justification for saying that beneficiaries should not pay for the cost of a project because in hindsight there may be other potential beneficiaries than there is to say that a project should not get built because in hindsight, projections made about the need for the upgrade may turn out to be incorrect.” Complaint at 22-23; see also, Statement of William Hogan at 5 (uncertainty about whether benefits will change over time does not require socialization of transmission upgrade costs).
CMEC also suggests that the option of a possible reopener “pose[s] unacceptable risk to investor confidence and customer rate stability.” CMEC Protest at 6. However, it does not explain what the risk is or why it is unacceptable. If 75 percent of the Southwest Connecticut Upgrade costs were allocated to Connecticut consumers, the costs would go into the utility’s local tariff. If at a later date more of the costs are socialized, the utility would not be paid any less; it would simply be paid through a different mechanism. Further, if rate stability is the concern, ratepayers in both the current beneficiary category as well as the possible but as yet unidentified beneficiary category would benefit from a reopener provision. The current beneficiary category would benefit from a reopener if the identities of the beneficiaries really do change after a period of time. The as-yet unidentified future beneficiary category also benefits from a reopener because ratepayers in that category are not paying hundreds of millions of dollars to pay for projects on the off chance that some day the project may benefit them. They will pay only if the project does actually benefit them.
Finally, these arguments ignore the fact that allocating 25 percent of the costs to the entire pool anticipates the possibility that some time over the life of the project, other areas may benefit from an upgrade.
I. The Coalition Does Not Oppose The Construction Of Transmission Upgrades But Rather Seeks To Have The Costs Of Such Upgrades Allocated In A Fair, Equitable Manner That Is Consistent With Competitive Markets
United Illuminating accuses the Maine and Rhode Island state agencies that are part of the Coalition of opposing the construction of transmission upgrades that would make “locked in” generation in these states available to the rest of New England. UI is incorrect. First, even a cursory reading of the Complaint reveals that the Coalition in no way seeks to oppose or prevent the construction of transmission upgrades. Second, the ISO has itself acknowledged that transmission line upgrades to increase export limits from Maine are likely not economic. RTEP-02 states:
Increasing export limits from the Maine Sub-Area was forecast to result in minimal congestion reduction. While the locked-in generation condition continues in the Maine Sub Areas, the economic benefits of alleviating the condition have been minimized for the near-term due primarily to the development of a large amount of less expensive generation in other Sub-Areas.
RTEP-02 at 10.
Nor will the Coalition proposal result in upgrades not being built if the upgrades are economic. See Protest of Braintree Electric Light Department, Reading Municipal Light Department and Taunton Municipal Lighting Plant. Simply because $1.4 billion of projects are proposed does not mean that local beneficiaries of the projects should not or would not pay for them if they are the most economic solution to the local economic or reliability problem. In fact, the largest project, the $700 million Connecticut upgrade is proposed for the most affluent region in New England. There is no reason to believe that the Connecticut upgrades would not be built if Connecticut ratepayers have to pay for most of the cost of the project, rather than just 25 percent. As stated in the Complaint, the Coalition proposal is more likely to ensure that projects are built because it will remove the incentive for consumers to oppose projects that would increase their costs but provide no benefits to them. The Commission has also recognized that beneficiary funding will help to reduce opposition to transmission projects. See, Remedying Undue Discrimination Through Open Access Transmission Service and Standard Market Design, Notice of Proposed Rulemaking 67 FR 55,451 (August 29, 2002), FERC Stats. & Regs. ¶ 32563 at P.195 (2002). Finally, the point of the Coalition complaint is that areas that will benefit from an upgrade should weigh the true cost of the project against the alternatives, rather than a small portion of the cost against the alternatives.
J. Claims That The Coalition Complaint Collaterally Attacks The December 20 Order Are Without Merit Because Rehearing Of That Order Is Pending
The CTDPUC and others claim that the Coalition Proposal collaterally attacks the Commission’s December 20, 2003 Order in Docket No. ER02-2330. In fact, Requests for Clarification or Rehearing of the Commission’s December 20 Order are still pending. The Commission has not left the December 20 Order “intact,” as suggested by the CTDPUC; rather it deferred ruling on the MPUC, RIPUC and others’ requests for clarification or rehearing because an agreement by the state commissions might have made rehearing unnecessary. Since there was ultimately no such agreement, the Commission still must consider the issues raised in the MPUC and RIPUC request for clarification or rehearing (and other requests for rehearing such as that filed by Central Maine Power Company (“CMP”)). In fact, as pointed out in the MPUC’s protest to NEPOOL and ISO-NE’s compliance filing of July 28, 2003, the Commission’s June 6, 2003, Order appears to recognize the arguments made by the MPUC and others that socializing all of the SWCT upgrades is inequitable. In one of the ordering paragraphs the Commission contained the following direction:
Within 30 days of the date of this order, ISO-NE and/or NEPOOL must file a proposal for a stakeholder process to determine an appropriate set of transmission upgrades for SWCT to receive socialized cost treatment, and an appropriate percentage of the costs of each such project to be socialized, as discussed above.
June 6 Order, Ordering Paragraph C. This ordering paragraph is consistent with the clarification sought by the MPUC and RIPUC that to the degree the Commission sought to moderate the impact of LMP on Connecticut consumers, it should consider what percentage of specific proposed upgrades should be socialized given consideration of a number of factors, including:
a careful assessment of the expected increase in Connecticut consumers’ congestion costs, the amount of SWCT congestion costs that has already been spread across New England during the four-year transition period, and the degree to which cost congestion-reducing SWCT upgrades are already being spread across the New England region.
MPUC and RIPUC Request for Clarification or in the Alternative Request for Rehearing.
The Connecticut DPUC also suggests that the Coalition proposal is inconsistent with the December 20 Order because under the proposal “only a minute portion” of the Southwest Connecticut upgrades would be socialized. While as discussed above, the CTDPUC reliance on the December 20 Order is misplaced because clarification and rehearing of the Commission’s December 20 Order is pending, the CTDPUC’s mischaracterization of the Coalition proposal should not stand. Under the Coalition proposal, as much as $175 million of the Connecticut upgrades might be socialized. Even the affluent residents of Southwest Connecticut probably would not characterize $175 million as a “minute” amount.
K. A Comparison With The PJM Methodology Favors The Coalition Proposal
NU cites the Commission’s decision in PJM as support for its claim that socialization of upgrades is consistent with Locational Marginal Pricing. However, NU ignores the fundamental difference between the PJM methodology and the current and proposed NEPOOL methodology. In PJM Interconnection, LLC., 104 FERC ¶ 61,124 (2003) (“PJM”), the Commission approved a methodology that assigned the cost of the project to those zones or sub-zones that would benefit from the project. The PJM methodology specifically requires PJM, for each project, to “independently determine and designate the market participant(s) who benefit from and therefore should pay for the transmission expansion.” PJM, 104 FERC ¶ 61,124, P.12. Thus, under the PJM methodology, if PJM directs a transmission owner to construct an upgrade, this action does not distort market signals because the areas that will benefit are those that will pay for the upgrade. Thus, there is an incentive for such local areas to reduce demand or site generation, since consumers in these areas otherwise will pay for the cost of an upgrade (if PJM determines that the cost of the upgrade is lower than the unhedgeable congestion costs). Under the current and proposed NEPOOL methodology, however, market signals are distorted, because if consumers in an area do not reduce demand and do not site generation, consumers in other areas will subsidize the cost of a transmission solution to the local economic or reliability problem.
National Grid suggests that LMP is not meant to provide price signals for the construction of transmission. It asserts that if that were one of the purposes of LMP, then “the absence of transmission construction is itself evidence that such upgrades are needed or ‘the market’ would have provided for it.” While it is true that merchant projects are rare, this only illustrates the point made by both Dr. Patton and Dr. Hogan that some transmission projects are too “lumpy” to be suitable for merchant investment. However, both Dr. Patton’s and Dr. Hogan’s analysis discussing the relationship between cost allocation and competitive markets support the beneficiary funding methodology proposed by the Coalition. For example, Dr. Patton states:
[t]he third principle I would recommend is that the costs be allocated to the participants that would be expected to be the highest value user of the new CRRs created by the investment. This principle would generally support allocating the costs to the Participants serving the load in the areas where congestion would be reduced by the investment, assuming that the CRRs have higher value as a hedge for loads against future congestion than as a speculative financial instrument. For investments made largely to meet reliability requirements, the analogous principle is that costs should be allocated to the areas whose reliability requirements are satisfied by the investment.
Patton Report at 5 (emphasis added). Similarly Dr. Hogan states . “The goal of regulated transmission cost allocation should be to approximate a market-like outcome.” Hogan Statement at 6. In addition, Dr. Hogan notes that “regulation need not require equal cost sharing.” Id. at 5.
Finally, National Grid’s theories are inconsistent with the Commission’s own findings on this issue:
The Commission will grant the Maine Commission’s request. Now that NEPOOL is implementing LMP, parties will be able to see more readily which areas would most benefit from transmission upgrades, and what party or parties will most benefit. It is, therefore, appropriate to require those parties to bear the costs of these new upgrades.
ISO New England, Inc., 100 FERC ¶ 61,287 at 62,286 (2002). National Grid’s theory, thus is at odds with both the Commission’s and noted economists’ analysis. Instead, Commission analysis, and that of Dr. Patton and Dr. Hogan support the Coalition’s beneficiary funding proposal.
L. The “Gold Plating” Of The Connecticut Project Shows How The Current Methodology Encourages Local Entities To Choose An Uneconomic Alternative
The CTDPUC misunderstands the significance of the Connecticut Siting Council’s approval of the project with the additional costs for having underground lines. It assures the Commission that there is no cause for concern with such decisions because the additional costs will not be socialized if ISO-NE determines that the cost of placing the lines underground is a “local cost” under proposed schedule 12C (a finding that under the proposed TCA amendments, the CTDPUC and others may contest). The CTDPUC, however, misses the significance of the Siting Council’s decision to “gold plate” the Phase One project. The Coalition has not claimed that the costs of undergrounding would be socialized. Rather, the Coalition’s point is that subsidization of the project enabled Connecticut to pay for the undergrounding “upgrade.” The Siting Council’s determination to “gold plate” the project was strongly influenced by their perception that Connecticut ratepayers would have to pay only a small portion of the cost of the upgrade. Thus, instead of encouraging the most economically efficient approach, the subsidization of project costs by those that will not benefit from the project allows those that will benefit choose to add additional costs to the project. As the MPUC and RIPUC Request for Clarification or Rehearing of the December 20 Order noted:
A recent Report issued by the Working Group on Southwest Connecticut and the Task Force on Long Island Sound confirms that to the extent the December 20, Order is read to socialize all the costs of the transmission upgrade it confers a windfall on SWCT consumers. The report suggests that if the costs of the project are socialized, the incremental cost of placing “the entire 345 kV Bethel-Norwalk line underground would cost the average residential ratepayer about $0.21/month in the first year of operation, equivalent to an 8% increase in CL &P’s transmission rate, but less than 1% of the current Connecticut electric rate.” Comprehensive Assessment and Report, Part I, Energy Resources and Infrastructure of Southwest Connecticut at 133 (emphasis added). The implication is that if ratepayers in other New England states pay the lion’s share of the $600 million dollar cost of the overhead 345 kV line, Connecticut consumers could afford to pay the incremental costs of having underground lines. The inequity of such a result is immediately apparent. Consumers in less affluent areas will be footing the bill of an upgrade that will not benefit them, will cost far in excess of the impact of LMP and will allow the affluent residents of SWCT to be able to “afford” the “gold-plated” option.
New England Power Pool, Docket Nos. ER02-2330-001, et al., Motion for Clarification or Rehearing of Maine Public Utilities Commission, et al. at 13, n.7 (January 21, 2003). Under the Coalition proposal, this inequitable result will be avoided.
M. The Effective Date Requested By The Coalition Is Consistent With The Federal Power Act
NU asserts that the Coalition’s proposed effective date would violate section 206 of the FPA, which establishes as the earliest refund effective date 60 days from the filing of the complaint. This provision does not bar the establishment of the effective date sought by the Coalition.
Making the Coalition’s proposal effective either on the March 1, 2003 date of the implementation of Standard Market Design in New England or alternatively on the date of the filing of the complaint does not require the issuance of any retroactive refunds. The cost of projects generally is not included in the NEPOOL Regional Network Tariff until the project is completed. Thus, for any project that was not under construction either as of March 1, 2003 or August 21, 2003, the cost of the project will not appear in rates until well after the earliest statutory refund effective date.
NU also argues that the Coalition’s proposed effective date, “would disrupt parties’ expectations,” and would also disrupt projects that “are already in progress.” NU Protest at 24. According to NU, market participants have already made economic decisions based on the Commission’s December 20 Order that any cost allocation mechanism would be applied prospectively. First, any reliance on the December 20 Order’s discussion of prospective application is misplaced because clarification and or rehearing of this aspect of the December 20 Order is pending. The MPUC and the RIPUC argued in their Request for Clarification or Rehearing that the term “prospectively” should be clarified to apply to any project not under construction as of the March 1, 2003 date of SMD implementation in New England. All parties had received more than adequate notice that the cost allocation methodology would be revised upon the implementation of SMD in New England. Further, NU does not specify what economic decisions were made that could not be revisited if the Commission implemented the Coalition’s proposal effective on the date(s) requested. The Commission should reject Protestors’ unsupported allegations of economic harm that would result from implementing the Coalition Proposal The Coalition’s requested effective date does not result in any retroactive change to the clearing price or any request for refunds. Cf., New York Independent System Operator, Inc., 91 FERC ¶ 61,218 at 61,804 (2000) (the Commission refused to change prices retroactively, because customers could not effectively revisit their economic decisions in these circumstances – there is no way for buyers and sellers to retroactively alter their conduct”). Moreover, the new rule does not affect recovery by the transmission utility of the cost of the project. It is simply recovered through a different tariff.
The Coalition Supporting Beneficiary Funding asks the Commission to deny the requests to dismiss its August 21, 2003 Complaint, seeks leave to file this answer and reiterates the request for relief contained in the Complaint.
_/s/ Lisa Fink__________________
Lisa Fink RHODE ISLAND PUBLIC UTILITIES
State of Maine COMMISSION
Public Utilities Commission RHODE ISLAND DIVISION OF PUBLIC
242 State Street UTILITIES AND CARRIERS
18 State House Station RHODE ISLAND ATTORNEY GENERAL
By their Attorneys,
__/s/ Paul J. Roberti______________
PATRICK C. LYNCH
PAUL J. ROBERTI (R.I. Bar No. 4447)
Assistant Attorney General
Chief, Regulatory Unit
DEPARTMENT OF ATTORNEY GENERAL
150 South Main Street
Providence, RI 02903
Tel: (401) 274-4400
Fax: (401) 222-3016
_/s/ Stephen Ward_________________ _/s/Thomas E. Atkins_________
Stephen Ward Thomas E. Atkins
Public Advocate Pinpoint Power
112 State House Station 440 Commercial Street
Augusta, ME 04333 Boston, MA 02109
_/s/ Paul Savage________________ _/s/ John A. O’Leary___________________
Paul Savage John A. O’Leary
Director of Federal Regulatory Affairs Vice Chairman and Managing Director
NRG Energy Inc. Gen Power, LLC
901 Marquette, Suite 2300 1040 Great Plain Avenue
Minneapolis, MN 59402-3265 Needham, MA 02492
 Requests to dismiss the Coalition’s Complaint were submitted by NEPOOL, the Connecticut Department of Public Utility Control (“CTDPUC”), National Grid USA (“National Grid”) and Northeast Utilities Service Company (“NU”).
 In addition to NEPOOL’s Answer, the Coalition responds herein to the comments and protests filed by Braintree Electric Light Department, Reading Municipal Light Department and Taunton Municipal Lighting Plant, CTDPUC, the Connecticut Municipal Electric Cooperative (“CMEC”), United Illuminating Co. (“UI”), National Grid and NU.
 The broad definition of reliability upgrade is used by ISO-NE to categorize all of the RTEP approved or recommended projects as reliability upgrades which under the current and proposed methodology would receive socialized cost treatment because they all meet the current and proposed kV threshold and meet the other minimum requirements (accommodate two way traffic, etc). ISO-NE has stated that all of the RTEP-02 projects would qualify as reliability upgrades and RTEP-03 states that all of the RTEP-03 recommended projects, the price tag of which will significantly exceed the known amount of $1.4 billion, “are needed to maintain power system reliability.” RTEP-03 Executive Summary.
 Similarly, the TCA amendments determine that there are regional benefits to economic upgrades by simply building that determination into the definition of economic upgrade:
Economic Upgrade: Those additions and upgrades that are not related to the interconnection of a generator, and in the System Operator’s determination, are designed to reduce bulk power system costs to load system wide, where the net present value of the reduction in bulk power costs to load system-wide exceeds the net present value of the cost of the transmission addition or upgrade. For purposes of this definition, the term “bulk power system costs to load system-wide” includes but is not limited to the costs of energy, capacity, reserves, losses and impacts on bilateral prices for electricity.
In other, words, to qualify as an economic upgrade, the only showing that needs to be made is that one area benefits sufficiently to meet the test, even if other areas costs are not reduced or are increased by the upgrade. However, because the definition says that such a project reduces bulk power costs system wide, it must do so. As a practical matter, the definition of economic upgrade is of less importance because every RTEP project to date qualifies as a reliability upgrade.
 National Grid and NU assert that the non-voltage criteria further narrows the category of projects that will receive socialized cost treatment. However, the exclusion of radial lines from socialized cost treatment as is provided for in both the current methodology and the proposed TCA Amendments does not provide any significant limitation. None of the more than $1.4 billion projects currently recommended through the RTEP process would be excluded under these criteria and in fact, as discussed above, all would be eligible for socialized cost treatment. Further, the non-voltage criteria do not demonstrate that ratepayers in all areas of New England will benefit from the project. Again, Connecticut provides a good example. The fact that the Connecticut upgrades will make it easier for Connecticut to import power and will address Connecticut’s reliability problems does not provide any demonstrable benefits to Maine and Rhode Island consumers in spite of the fact that these facilities meet the non-voltage criteria under the current system and the proposed TCA Amendments. Further, NU’s and National Grid’s analogy to the highway system proves too much. The integrated nature of the transmission system does not stop at the border of control areas as the recent blackout demonstrates. Thus, under the highway analogy, there should be a national tax to pay for transmission upgrades. More important, however, the integrated nature of the national transmission system does not change the fact that there are local beneficiaries of transmission upgrades and that the siting board decisions and the RTEP identify these local beneficiaries. Protestors have failed to demonstrate that the integrated nature of the transmission system results in benefits to all areas of New England that equal or outweigh the demonstrated local benefits of RTEP projects.
 Of course, the Coalition does not suggest that 25% is the only allocation that would allocate most of the costs to the primary beneficiaries. Whether socializing 10%, 15% or 25% or even 35% best allocates most of the costs to primary beneficiaries is a matter within the discretion of the Commission. What would clearly be arbitrary is to allocate all or most of the costs to the entire region when there is no showing that other areas benefit to the same degree as the local beneficiaries of the project.
 Interestingly, the CTDPUC was the only state public utility commission that protested the Coalition proposal.
 See, RTEP-02 § 11.4 (stating in relevant part):
Although Phase I and Phase II result in little NEPOOL wide LOLE improvement and little reduction in forecasted congestion costs, those reliability and congestion analysis modeling efforts do not reflect the myriad problems internal to SWCT that this project is designed to solve.
Id. (emphasis added).
 The Coalition recognizes, of course, that parties seeking approval from state and local siting authorities are likely to stress state and local benefits. What is striking with respect to SWCT, however, is the consistent theme of every analysis that the primary problem to be solved is the particular problem of SWCT’s relative isolation from the rest of New England.
 NU’s protest mischaracterizes the Complaint. It states “Even the Complainants acknowledge ‘the fact that NEPOOL has an integrated bulk power market,’ and that over time all consumers will benefit to a certain extent from a transmission upgrade. “In fact,” the Coalition stated, “Unlike the current system, the proposal outlined herein provides a method for allocating cost to load that benefits from the project while taking into account concerns that over time, it is possible that a project may benefit areas beyond the primary beneficiaries identified in the Regional Transmission Expansion Plan (RTEP).” Complaint at 2. This statement is significantly different from the way it was characterized by NU.
 Interestingly, Connecticut points out that its GSP in current millions of dollars exceeds the combined GSPs for Maine Rhode Island, New Hampshire and Vermont, CTDPUC Motion to Dismiss and Protest at 16, but fails to make the connection between this high relative GSP and the need to support this economic activity by paying for upgrades. The CTDPUC does not suggest in any way that the consumers in other New England states benefit from Connecticut’s high GSP. In fact, consumers in Maine and Rhode Island do not receive the benefits of Connecticut’s high GSP and therefore should not be asked to subsidize the costs of upgrades that result from a productive economy.
 For example, the Connecticut municipal utilities’ aggregated share of the socialized cost of an upgrade is about one percent. The same is true for the Massachusetts municipal utilities.
 In its request for rehearing, CMP also pointed out that the Commission’s finding of what was equitable failed to consider the equity of socializing the costs of an upgrade which will provide benefits in lowered costs only to Connecticut consumers but will increase costs to Maine consumers who would be required to subsidize the cost of the upgrade. See CMP Request for Rehearing.
 As the Commission must also be aware, Connecticut’s per capita income is the highest in the country and Fairfield County in SWCT is among the 10 wealthiest counties in the country in terms of per capita income. Bureau of Economic Analysis (September 2002). In addition, Connecticut has the highest residential average monthly consumption (711 kwh per month) of the six New England States. In comparison, the average monthly residential consumption of the other New England states ranges from 479 kWh for Maine to 599 kWh for Vermont. Energy Information Administration Electric Sales and Revenue 2000, Table 1, US Average Monthly Bill By Sector, Census Division and State, 2000. In a June 2002 report, the CTDPUC acknowledged “[i]t is generally accepted that strong economic growth in SWCT and the proliferation of air conditioning in residential and commercial settings is driving the peak demand for electricity. The installation of air conditioning is commonplace in remodeling and new construction and this trend is expected to continue.” CT Report on Shortages at 6. If the Commission backs away from its commitment to allowing market forces to drive economic behavior under these circumstances, it is difficult to imagine that commitment ever being honored. Further, there is nothing equitable about forcing less affluent consumers to pay for the high levels of consumption of their wealthier neighbors.