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New England Power Pool and ISO New England Inc.




Docket Nos. ER03-1141-002 and EL03-222-002 (not consolidated)





Pursuant to the Commission's November 4, 2003 and November 17, 2003 public notices, the Maine Public Utilities Commission (MPUC), Pinpoint Power, the Rhode Island Attorney General, the Rhode Island Public Utilities Commission, the Rhode Island Division of Public Utilities and Carriers, the Maine Public Advocate, NRG Energy, Inc. and Gen Power, LLC, all intervenors herein (collectively "Coalition Supporting Beneficiary Funding" or "Coalition"), hereby submit comments on the data responses filed jointly by the New England Power Pool (NEPOOL) and ISO New England (ISO-NE) (hereinafter collectively referred to as "NEPOOL") on October 29, 2003.  Specifically, the Coalition observes that the responses support the Coalition's contentions that (1) there is no significant difference between the current methodology which the Commission has found to be flawed and the proposed TCA amendments; (2) there is no basis for grandfathering the current socialization cost allocation methodology for projects not under construction as of the date of Standard Market Design (SMD) implementation or alternatively the filing date of the Coalition Complaint; and (3) there is no opportunity to challenge before the Commission the inclusion of a project in the RTEP or the determination to socialize the costs of the upgrade.  In addition, the Coalition addresses specific failings in the Data Responses.

I.                  BACKGROUND

On July 31, 2003, NEPOOL filed proposed amendments to the NEPOOL Tariff and the Restated NEPOOL Agreement to implement a proposal for transmission cost allocation (TCA Amendments).  On August 21, 2003, the Maine Public Utilities Commission, the Rhode Island Public Utilities Commission, the Rhode Island Division of Public Utilities and Carriers, the Rhode Island Attorney General, the Maine Public Advocate, Pinpoint Power, NRG Energy, Inc and Gen Power, LLC (collectively referred to as the "Coalition Supporting Beneficiary Funding" or "Coalition") filed a protest to the proposed TCA Amendments.  Also on August 21, 2003, the Coalition filed a Complaint against ISO-NE and NEPOOL proposing to replace the current cost allocation methodology with a new methodology that allocates the majority of upgrade costs to the primary beneficiary while allowing a smaller percentage (25 percent) of upgrade costs to be spread across the region.

On September 29, 2003, the Commission requested additional information from NEPOOL and ISO-NE that it found was required "in order for the Commission to have sufficient information to process [the NEPOOL-ISO TCA Amendment] filing."  The same questions were issued in the Coalition Complaint docket, Docket No. EL03-222-000.  On October 29, 2003, as corrected on November 6, 2003, ISO-NE and NEPOOL (hereinafter NEPOOL) filed responses to the questions.

II.               ARGUMENT

A.                The Data Responses Confirm that Under the Proposed TCA Amendments as well as the Current Cost Allocation Methodology Virtually Every Proposed Upgrade Will Receive Socialized Cost Treatment.

In its TCA filing and answers to protests, NEPOOL and other proponents of the TCA amendments assure the Commission that the TCA proposal does not provide for the socialization of the costs of virtually all upgrades.  However, NEPOOL's data responses prove that the opposite is true.  They also prove that the proposed methodology is not different from the current methodology which the Commission has found to be flawed in an LMP environment.

In response to Data Request 1(a), NEPOOL admits that all of the projects in RTEP-02 and RTEP-03 (which have an estimated cost of more than $1.3 billion) are deemed to be reliability upgrades, and thus receive socialized cost treatment under both the current and the proposed TCA Amendment methodology.[1]  Thus, as the Coalition stated in its protest, the proposed TCA Amendment's various categories of upgrades are meaningless because virtually any project will qualify as a reliability upgrade and receive socialized cost treatment.

Further, NEPOOL states that the TCA Amendments should be approved because they reflect the status quo even though, in numerous orders, the Commission found the current cost allocation methodology inconsistent with an LMP system and required NEPOOL to file a new cost allocation methodology consistent with LMP.  For example, in response to the Commission's Data Request No. 7 about the provision to challenge the ISO's determination of localized cost and about whether there is a "concomitant procedure for challenging the System Operator's determination of regional costs," NEPOOL explains that there is no concomitant right to challenge the ISO's determination of regional costs because the current tariff does not provide this opportunity.  This is no answer at all where the Commission has found the current methodology to be unsatisfactory in an LMP environment.  NEPOOL cannot reasonably defend a default allocation methodology as being consistent with past practice when the Commission has repeatedly declared that past practice inconsistent with LMP.[2]

Because NEPOOL has failed to justify either the current system or the nearly identical proposed TCA amendments, and the Commission has already found the current system to be unreasonable in an LMP environment, the Commission should replace these flawed methodologies with the fair and workable one proposed by the Coalition.

B.                The Data Responses Confirm That There Is No Rational Basis For Grandfathering The Current Socialization Cost Allocation Methodology For Projects That Were Not Under Construction As Of March 1, 2003 Or Alternatively The Filing Date Of The Coalition Complaint.

In its Data Response 1(b), when asked to provide estimates of localized costs associated with projects in the RTEP02 report, NEPOOL states that "[i]n many cases engineering and design has not progressed sufficiently, or projects that are alternatives have not been fully evaluated from a technical standpoint, to allow an accurate and meaningful estimate to be provided."  Data Response at p.4.  Further, NEPOOL acknowledges that where projects do have preliminary cost estimates, these estimates are "subject to substantial change over the course of actual siting, engineering and construction."  These statements support the Coalition position that there is no rational basis to grandfather all of the projects in RTEP-02 because many of the projects are only in their preliminary stages and have no cost estimates or only preliminary cost estimates associated with them.  NEPOOL has failed to show that any project listed in RTEP-02 would not be built simply because parties that benefit are required to pay a larger share of the costs.[3]

C.                NEPOOL's Response Regarding Localized Cost Determinations Discloses the Loopholes in the Localized Cost Provisions.

In its Data Request 3, the Commission asked NEPOOL:

With regard to the estimated total cost of phases I and II of the SWCT 345 KV project (RTEP-02 Ref. 4.26), how much of the estimated costs are related to burying transmission lines?  Would the costs of burying the lines be subject to regional cost support or localized costs?

NEPOOL's response gives a preview of all the arguments that will be made in favor of socializing the incremental amount of the cost of underground lines over the cost of overhead lines.  NEPOOL states:

Additionally, the "costs of burying the lines" referenced in the question are not necessarily incremental.  Underground construction for a portion or all of a project may be no more costly, or indeed may be less expensive, than overhead construction depending on timing, environmental effects, technical viability, routing considerations (that may require the acquisition of real estate), and the impact a given route may have on the community, local businesses and residences.  For this reason, the case-by-case Schedule 12C cost review discussed above is the most appropriate means of determining whether costs should be regionalized or localized.  As an example, Northeast Utilities and The United Illuminating Company have recently submitted a siting application in Connecticut for Phase II (Middletown to Norwalk) in which the cost estimates for the proposed project (which includes an approximately 24 mile section that would be constructed underground) are lower than the cost estimates for the Companies' two alternative project routes, each of which would have a smaller amount of undergrounding than the proposed route.  The Companies would need to substantiate costs in the schedule 12C cost review process to enable ISO-NE to determine whether the costs should be regionalized.

Response at 11.  NEPOOL's failure to explain that the cost is more than 100 million dollars higher than the original proposed estimate for Phase II in RTEP-02 (which may not have envisioned any underground lines) underscores NEPOOL and ISO's bias in favor of regionalizing costs.  This bias may prevent the ISO from making a fair decision in determining whether costs should be localized or regionalized.[4]  Moreover, as the Coalition has shown before, blanket socialization will encourage parties to "gold plate" their projects, because a greater portion of the costs will be borne by those who will obtain little or no benefit.  Only where those who most need the facility are responsible for the majority of the costs will proponents act aggressively to minimize costs.

D.                NEPOOL's Response Discloses that There is No Process to Challenge the Inclusion of a Project in Regional Rates.

Data Request No. 7 notes that the System Operator's determination of localized costs can be challenged under NEPOOL procedures, as well as under Section 206 of the FPA and asks whether "there is a concomitant procedure for challenging the System Operator's determination of regional costs."  NEPOOL explains in its data response that there is no concomitant procedure either for "ISO-NE's determination of needed upgrades" or "the associated cost allocation."  NEPOOL Response to Data Request No. 7 at p. 13.  Thus, the only means to challenge the inclusion of a project in regional rates is through the RTEP process.  This explanation reveals an additional flaw in the current methodology and proposed TCA Amendments.  As long as a project meets the broad definition of a reliability upgrade (see NEPOOL Data Response 1(d) at p.4), its cost will be regionalized.  The only basis under the current methodology and the TCA amendments to challenge the proposed inclusion of a project in regional rates is to challenge the

ISO's determination that the project is necessary.  However, there is no forum for challenging the ISO's final RTEP determination because the RTEP is never filed at the Commission as a section 205 filing.  Instead, costs simply get added to the formula rate which is filed at FERC only for informational purposes.  Thus, the current and proposed methodology set up a "Catch 22" situation in which there is no opportunity to challenge (1) the RTEP determination or (2) the inclusion of the costs of a project when the formula rate filing is made because the inclusion is permitted under the cost allocation methodology that is set forth in the OATT.  (NEPOOL Response at 13.)  Accordingly, the current and proposed methodology does not permit any dissenting voices or any Commission review unless the dissent is against a decision to localize a portion of upgrade costs.

This lopsided process effectively insulates from normal Commission scrutiny decisions about the allocation of more than a billion dollars of network upgrade costs.  Not only is the result fundamentally unfair, it contravenes Commission policy governing the permissible scope of a formula rate.  Here, the formula assures that whatever costs are classified, in the System Operator's discretion, as reliability upgrades or are not determined by it to be localized are, by default, regionalized.  This is inconsistent with Commission policy barring the inclusion in formula rates of costs that involve an "exercise of judgment."  In such cases, the Commission has "require[d] separate Commission scrutiny" of the costs in a Section 205 filing.  Florida Power & Light Co., FERC 74 61,038 at 61,092 (1996) (explaining why changes in depreciation rates could not be tracked through a formula rate).  It should require such scrutiny here.[5]

E.                 Other Shortcomings of NEPOOL's Data Responses

1.                 Data Request No. 8.

In response to Data Request No. 8, NEPOOL should be required to identify "the eight other projects that have been proposed in the Maine-New Hampshire areas that address a mix of thermal, voltage, stability and operating concerns due to the tightly integrated nature of the power system, and that would have the ancillary effect of mitigating conditions on the system that themselves may serve to exacerbate the constraint in Southern Maine."  NEPOOL should also be required to provide the costs of those projects and to state whether a cost-benefit analysis was done for any of the ten projects referenced in the answer.  Finally, it should disclose how the costs of the projects would be allocated under the TCA Amendments.

2.                 Data Request 2.

The estimates given in response to the Commission's request to determine the rate impact of RTEP-02 projects are understated by unknown amounts.  NEPOOL candidly admits that many projects are not even sufficiently developed to have a price estimate and that many price estimates will be significantly revised as the project gets close to construction.  Thus, the levels of increases stated in response to Schedule 2, while significant as they stand, are significantly understated.


For the reasons stated above, and for all the reasons set forth in the Coalition protest to the TCA amendments and the Coalition Complaint, the Commission should reject the proposed TCA amendments and replace the current cost allocation methodology with the methodology proposed in the Coalition Complaint.


Respectfully submitted,


s/Lisa Fink



Lisa Fink

State of Maine

Public Utilities Commission

242 State Street

18 State House Station

(207) 287-1389






By their Attorneys,


Harvey L. Reiter

John E. McCaffrey

Stinson Morrison Hecker LLP

1150  18th Street, NW, Suite 800

Washington, DC  20036

(202) 785-9100





PAUL J. ROBERTI (R.I. Bar No. 4447)

Assistant Attorney General

Chief, Regulatory Unit


150 South Main Street

Providence, RI  02903

Tel: (401) 274-4400

Fax: (401) 222-3016







Stephen Ward

Public Advocate

112 State House Station

Augusta, ME  04333


Thomas E. Atkins

Pinpoint Power

440 Commercial Street

Boston, MA  02109







Paul Savage

Director of Federal Regulatory Affairs

NRG Energy Inc.

901 Marquette, Suite 2300

Minneapolis, MN  59402-3265



John A. O'Leary

Vice Chairman and Managing Director

Gen Power, LLC

1040 Great Plain Avenue

Needham, MA  02492



I hereby certify that I have this day served a copy of the foregoing document by first-class mail upon each party on the official service list compiled by the Secretary in this proceeding.

Dated at Washington, D.C., this 19th day of November, 2003

/s/ Harvey L. Reiter_______

Harvey L. Reiter


WDCDOCS 121444v1


[1] In explaining the change of classification of several projects from an economic upgrade to a reliability upgrade, NEPOOL points to an earlier Commission decision rejecting the distinction between reliability and economic upgrades as a valid distinction for cost allocation purposes.  We agree that often projects address local reliability and economic concerns.  Where we differ from NEPOOL is in NEPOOL's belief that it is impossible or even difficult to identify the primary local beneficiaries of upgrades (whether the upgrades are classified as a reliability or an economic upgrade).  See Statement of William Hogan at 8-9 (local beneficiaries of reliability upgrades can be easily identified especially where possible load shedding is an alternative to the investment).  Interestingly, there appears to be little difficulty identifying local beneficiaries of RFPs for load response and supplemental generation resources for reliability purposes as is demonstrated by a recently developed NEPOOL market rule which will allocate to the local area whose reliability needs the RFP is designed to address the costs of generation and load response selected through such an RFP.

[2] NEPOOL's reliance on the Commission's statement that it would not "preclude" at the time of the December 20, 2003 rehearing 0rder any cost allocation methodology that is reached by consensus does not lessen the weight of the Commission's prior orders finding the current system to be flawed.  The Commission's statement, in fact, expressly identifies socialization as a deviation from its cost allocation principles.  101 FERC 61,344 at P.51 (2002).

[3] In fact, NEPOOL's claim that there is no cost benefit analysis required for reliability upgrades militates against a conclusion that changing the cost allocation methodology for a listed project would disrupt the project.  If the reliability of a local area must be assured at any cost, then requiring beneficiaries to pay their fair share should not have any disrupting effect on the project.

[4] Indeed, the ISO's flat rejection in the stakeholder process of any proposal that did not provide for broad socialization of upgrade costs reduces the ISO's credibility on issues relating to transmission cost allocation.

[5] NEPOOL defends the TCA Amendments' failure to provide for any Commission review of ISO's determination to socialize upgrade costs by claiming that "the goal was to avoid the case-by-case scrutiny of transmission projects that has led to the delay of needed transmission."  NEPOOL Response at 13.  NEPOOL's premise that FERC's case-by-case scrutiny has led to delays of needed transmission is incorrect.  As NEPOOL points out, the current provisions do not provide for any Commission review of these projects on a case-by-case basis.  Because there has been no case-by-case Commission review of transmission projects under the current methodology, any delay of needed transmission projects cannot be blamed on such a review process.