Skip Maine state header navigation

Agencies | Online Services | Help


ISO New England Inc.




Docket No. RT04-2-000

Bangor Hydro-Electric Company


Docket No. ER04-116-000




Central Maine Power Company






NSTAR Electric & Gas Corporation,

on behalf of its affiliates:




  Boston Edison Company



  Commonwealth Electric Company



  Cambridge Electric Light Company



  Canal Electric Company






New England Power Company



Northeast Utilities Service Company,



on behalf of its operating company affiliates:



  The Connecticut Light and Power Company



  Western Massachusetts Electric Company



  Public Service Company of New Hampshire



  Holyoke Power and Electric Company



  Holyoke Water Power Company






The United Illuminating Company






Vermont Electric Power Company










  Pursuant to Rule Nos. 211 and 214 of the Commission’s Rules of Practice and Procedure, 18 C.F.R. § 385.211 and 214, and the Commission’s notices in these dockets dated November 12 and 19, 2003, the New England Conference of Public Utilities Commissioners or “NECPUC” move to intervene in this proceeding and protest certain features of the underlying filing in the case.[1]  NECPUC is a not-for-profit corporation comprising public utility commissioners of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.  Formed fifty years ago and funded by the New England states, NECPUC’s mission is the promotion of regional cooperation and effective communication on all public utility matters affecting New England. As a representative of New England’s interests concerning the electric industry, NECPUC has a vital stake in the operation of the New England power markets. [2]

  NECPUC has long been an avid proponent before the Commission of a vibrant, independent regional organization in the service of a competitive marketplace.[3]  It is NECPUC’s position that while many features of the filing in this case are well-conceived and would represent an improvement over the status quo, the filing will, in a number of respects, compromise the proposed RTO’s independence and adversely affect the competitive markets the RTO is designed to foster.  NECPUC believes, however, that with the modifications requested below, the October 31 Filing will advance the Commission’s and NECPUC’s vision for a functional competitive market in New England.

  The October 31 Filing would improve the status quo in several ways.  To begin with, as the Filing Parties acknowledge,[4] the ISO has been existing under a “vendor-type” arrangement with NEPOOL, pursuant to a series of short-term extensions of its agreement.  Daily concern for renewal of the organization’s concession has an obvious impact on the organization’s independence and stability.  While it requires modification, the October 31 proposal is a substantial improvement, since it establishes an institutional structure that is not dependent on NEPOOL’s periodic blessing. 

Existing procedures under the current ISO/NEPOOL structure for handling changes to the terms and conditions of service under the NEPOOL OATT and the rates for such service are also problematic, and the October 31 Filing would again be a step forward.  In contrast with the requirements of Order No. 2000, the ISO is hampered in the exercise of control over the terms, conditions and rates under which it offers service.  Under current arrangements, control over changes to the NEPOOL OATT is largely given to NEPOOL participants, while the ISO’s opportunity to file to change market rules is limited to instances in which existing rules have a substantial and adverse impact on reliability, security or competitive markets.[5]  The October 31 Filing makes substantial improvements in this area, although again it needs modification in certain significant respects.

NECPUC believes that the Commission should condition its approval of the filing on the parties making several modifications.  First, the filing should be conditioned on modification of provisions in the TOA governing section 205 filing rights to better reflect Order No. 2000.  While NECPUC is mindful of the court’s decision in Atlantic City Electric Co. v. FERC,[6] the Commission has nevertheless made it clear that RTO proponents voluntarily seeking Commission approval must still comply with the requirements of Order No. 2000.[7]  NECPUC is not averse to a negotiated resolution of Section 205 rights that deviates somewhat from Order No. 2000.  But the resolution of these issues must ensure that such rights as are invested in the TOs do not compromise the RTO’s independence.  NECPUC notes, specifically, that as currently structured, following a five-year moratorium, Section 3.04(h) of the Transmission Operator Agreement (“TOA”) provides the TOs with the right to file to change cost allocation, and the Regional State Committee (“RSC”) may respond with a competing filing.  NECPUC asks the Commission to ensure, at a minimum, that the RSC has the right to file to change rates independent of any action taken by the TOs.  Further, in the event the RSC is either not constituted or has decided to decline this role, NECPUC should be entitled to act, as the representative of the New England public utility commissions.  As to rate design changes, NECPUC notes that Section 3.04(b) of the TOA cedes principal authority to the TOs, while providing the RTO with the right to file for changes only where it believes markets or system reliability will otherwise be substantially and adversely impacted.  Here again, a more balanced approach would entitle the RSC or RTO to file proposed rate design changes under FPA section 205, either to initiate changes or to put forth alternatives to changes proposed by the TOs.

Second, NECPUC requests that the Commission condition its approval of the filing upon the removal of  Mobile-Sierra[8] protection from certain key provisions.  See Section 11.04(c) of the TOA. NECPUC finds these provisions particularly objectionable to the extent they govern: (1) the parties’ FPA section 205 rights; (2)  system planning and expansion; (3) TO withdrawal from the RTO; and (4) the rights conferred upon Independent Transmission Companies (“ITCs”).  In fact, as argued below, NECPUC sees no place at all in the TOA for provisions governing system planning and expansion, or the rights and constitution of an ITC.  Matters relating to system planning and expansion should be exclusively governed by the RTO tariff, and an ITC’s rights and responsibilities should be addressed in a separate proceeding. 

Further, NECPUC asks the Commission to broaden the RTO’s ability to reschedule transmission outages planned by the TOs in the event such outages threaten the competitive markets or economic efficiency. 

Finally, NECPUC asks the Commission to condition its approval upon modification of the provisions governing termination and withdrawal.  NECPUC objects to the provisions in Section 10 of the TOA which call for the Commission to make a “public interest” finding within the meaning of the Mobile-Sierra Doctrine before it may prohibit a TO from withdrawing from the RTO.  In addition to putting unreasonable limits on the Commission’s authority, that provision would severely compromise the RTO’s independence through the persistent threat of departures, and it would endanger ongoing service which the RTO is contractually obligated to provide.[9]

NECPUC is not opposed to limited settlement discussions, taking place in New England, in an effort to resolve these outstanding issues.  The Filing Parties note correctly (Cover Letter, p. 17) that discussions were held among the parties prior to October 31 and that certain changes were consequently made to the proposed documents.  The concessions that were made, however, failed to resolve the core issues raised here.  If the parties are to engage in further fruitful discussion, NECPUC suggests that a tight time frame be established in order to focus the parties’ attention and limit the expense of the endeavor.  Further, to limit needless discussion, the Commission should not refrain from issuing an order resolving the issues joined by this and other protests.


  NECPUC hereby moves to intervene in this proceeding.  As the representative of state public utility commissions throughout New England, NECPUC has a vital interest in the outcome of this case. Correspondence and communications concerning this docket should be directed, on NECPUC’s behalf, to:

Paul G. Afonso, President

New England Conference of Public

Utilities Commissioners, Inc.

One South Station

Second Floor

Boston, MA  02110

  Tel: (617) 305-3500

  Fax: (617) 345-9102


Harvey L. Reiter

John E. McCaffrey

Stinson Morrison Hecker, L.L.P.

1150 18th Street, N.W.

Washington, D.C. 20036

  Tel:  (202)785-9100

  Fax: (202)785-9163 







a)      The RTO Brings Needed Organizational Change

Since its inception, ISO-NE has operated under a series of amendments to an “interim contract” with NEPOOL to operate the transmission system and administer the competitive wholesale market.  The proposed evolution from a structure in which ISO-NE is an agent of market participants is extremely positive, and is a critical reason for NECPUC’s support of an RTO.  The organizational change will provide stability and a clear designation of authority, and it will place market issues squarely in the hands of a financially disinterested entity rather than with market participants.

b)      The RTO Board Selection Terms are an Acceptable Compromise

NECPUC supports the proposal for selection and retention of the RTO Board of Directors.  Board selection ultimately rests with the RTO, though stakeholders are provided two distinct roles in seating the Board: participation in a Nominating Committee and advisory votes on the slate the Nominating Committee develops.  NECPUC had urged more limited stakeholder participation in the Nominating Committee and no voting on the slate that is developed.  However, we find the terms proposed by ISO-NE for the stakeholders’ role on the Nominating Committee and two rounds of advisory votes on a slate of Directors to be an acceptable compromise.  Further expansion of the Nominating Committee or more rounds of voting, however, runs the risk of rendering the process so unwieldy and time-consuming that good candidates may be lost and the independence of the Board compromised.

c)      The Provision of “Jump Ball” Rights to Market Participants for Presenting in Limited Circumstances Alternative Market Rule Proposals Provides a Good Balance Between RTO Independence and Meaningful Input from Market Participants. 


Although NECPUC takes issue with a number of the proposed provisions governing changes to the rates, terms and conditions of service under FPA Section 205, as discussed below, it strongly supports the reflection in TOA Section 3.04(c) and Section II of the Participants’ Agreement of the Commission-directed change that the Independent System Operator (or in this case RTO) should have the sole authority for filing changes to market rules under FPA section 205.[10]  This does not mean, however, that stakeholders are without a voice.  They will have full input regarding the development and implementation of market rules. The technical committees will continue to be a vital part of the evolution and operation of the transmission system and competitive wholesale market, and they will have the opportunity to have a strongly supported Market Participant view considered by the Commission under the same standard as the RTO proposal.

NECPUC believes it is critical that the RTO have § 205 rights over market issues, but supports the “jump ball” proposal in the Participants Agreement.  In the event an alternative to the RTO is supported by 80% or more of the participants, the RTO proposal and the participants’ alternative would both be filed by the RTO as §205 filings.[11]  The Commission would be free to evaluate the two alternatives on an equal footing and could select the best proposal, or portions of each proposal, when evaluating a market change.  See, Participants Agreement, § 11.



a)      The Commission Should Condition Its Approval of the RTO Filing on a Reallocation of the Section 205 Rights for Rate Design



  The Commission should reject those portions of the TOA that allocate Section 205 rights for rate design to the TOs without any opportunity for either the RTO or the RSC to file a competing proposal under the Section 205 standard or to initiate rate design changes.  Providing the Transmission Owners the exclusive right to initiate rate design changes under  Section 205  gives the utilities a “head start” over any other party, and the extension of this right exclusively to the Transmission Owners  could compromise sound market development. 

Order 2000 changes the traditional arrangements in place when the Federal Power Act was enacted. Order 2000 envisions that the transmission owning utility will transfer its operational authority over its assets to the RTO and that the RTO, rather than the transmission owning utility, has the responsibility to operate the system reliably and the wholesale electric markets competitively.  In Order 2000, the Commission found that the RTO will not have the requisite level of independence unless it has “exclusive and independent authority under [FPA Section 205] to propose rates, terms and conditions of transmission service provided over the facilities it operates.”  18 C.F.R. § 35.34(j)(l)(iii).[12]  The rate provisions in Order 2000 were upheld in Snohomish,  specifically on the ground that utility membership in an RTO is voluntary.[13]  If they do choose to do so, “they would not be involuntarily ceding any claimed statutory rights, but rather voluntarily waiving them.”[14]

While Order 2000 supports the notion that Section 205 filing rights with respect to rate design should reside with the RTO, an alternative approach, to which NECPUC  could agree, would be to vest shared filing rights in the TOs and the RSC.  We raise this for two reasons.  First, the TOA already vests in the RSC the right to put forth alternative proposals with respect to the allocation of the costs of transmission upgrades, and thus, it would be consistent with that approach to give the RSC a similar role in all rate design matters.  Second, rate design issues often involve the type of policy decisions for which the RSC would seem particularly well-suited.

To elaborate, rate design issues involve two very different, although not necessarily incompatible, interests.  The first is the interest of the TOs in cost recovery.  The second is the interest of all stakeholders, including the general public, in achieving broader policy objectives, including but not limited to ensuring a competitive market.[15]  In its treatment of cost allocation, the TOA takes a creative first step toward reconciling these interests by providing for Section 205 rights to be shared by the TOs and the RSC.[16]  The problem with the TOA is that while it starts down the right path, it stops too soon in two respects.  First, it limits the jump ball to a subset of rate design issues – namely, those involving the allocation of the costs of transmission upgrades – whereas consistency and good policy would extend it to all aspects of rate design.  Second, it only allows the RSC to file a competing proposal in response to one submitted by the TOs but not to initiate changes under Section 205 when it concludes they are warranted to serve the larger public interest. 

In our view, the optimal resolution of this matter would be for the RSC to have jump ball rights with respect to all rate design issues.  Those rights should enable it both to file alternatives to TO rate design proposals and to initiate its own rate design filings to which the TOs could file alternatives.  We recognize, however, that there may be legal impediments to according these rights to the RSC absent the agreement of the TOs.  If there are to be further negotiations regarding the RTO, we believe favorable words from the Commission about this approach might help to bring it about.  If there are not to be further negotiations, or if they occur but do not produce a resolution, an alternative acceptable to NECPUC would be for the Commission to condition acceptance of the RTO filing on according full rate design jump ball rights to the RTO.  While it may not have the broad public policy perspective of the RSC, the RTO at least brings a neutral vantage point to the different interests that are often involved in designing rates.

Finally, since the RSC is still a work in progress, there needs to be an alternative to the RSC if the TOA accords the RSC jump ball rights in the rate design area and the RSC has not yet been formed or expressly declines to accept this role.  Should that be the case, we believe that NECPUC should be authorized to act in place of the RSC.[17]


b)  The Rate Design Problems in the TOA are Compounded by According Section 3.04 Mobile-Sierra Protection.


NECPUC supports the creation of a well-designed RTO as a development that can provide genuine independence in establishing, maintaining, and operating sound energy and transmission markets in New England.  For the reasons stated previously, however, it is our position that the rate design provisions in the TOA, by giving one group of financially interested participants filing rights that are vastly superior to those given to the RTO (as well as the RSC) and to other market participants, conflict with the basic objective of RTO formation.  Needless to say, according the TOA’s approach to rate design Mobile-Sierra protection only serves to lock in this imbalance, largely insulating it from change even by the Commission.  As is probably obvious, we believe strongly that the solution to this problem is to correct the TOA’s rate design flaws in accordance with our earlier recommendations, in which case the Mobile-Sierra issue would become far less significant with respect to Section 3.04.  However, the worst outcome would be for the Commission to accept a defective rate design scheme cast in Mobile-Sierra concrete. 




The Commission should condition its approval of the RTO upon removal of Mobile-Sierra protection from certain key provisions of the TOA.  TOA Section 11.04(c) specifies that absent the agreement of the parties to the TOA the standard of review for changes to a long list of the agreement’s provisions will be the “public interest” standard under the Mobile-Sierra doctrine.  The TOA extends Mobile –Sierra protection to the following sections of the Agreeement:  2.01, 2.04, 3.02, 3.03, 3.04, 3.05, 3.06, 3.07, 3.09, 3.10, 3.11, 3.13, 3.14, 4.01(g), 6.06, 6.07, 6.08, 9.01, 9.06, Sections10.01, et seq., 11.04(a)-(d), 11.05, 11.06, 11.08, 11.17, 11.19(d), and Article I, as it applies to the foregoing sections.

NECPUC believes that with all of the Mobile-Sierra protected sections outlined above, the TOA will lack needed flexibility to accommodate changes in rights and responsibilities that the Commission will inevitably find to be necessary and reasonable over time.[18]  The Commission should thus condition its approval or acceptance of the filing upon elimination of Mobile-Sierra protection from certain key sections outlined below so that the RTO, the TOs or others (market participants and regulators) may propose changes that the Commission, which is ultimately responsible for ensuring that rates are just and reasonable, can approve as needed.   

  Precedent does not support the extensive use of Mobile Sierra protection for provisions governing the structure of an RTO.  In Avista Corp., et al., 100 FERC ¶ 61,274 (2002) (September 18 Order), order granting clarification, 101 FERC  ¶ 61,034 (2002), Order on reh’g, 101 FERC ¶ 61,346 at 62,453 (2002) and Cleco Power L.L.C., et al., 101 FERC ¶ 61,008 at 61,026 (2002), the Commission rejected broad efforts by the filing transmission owners to restrict changes to RTO tariffs through the specification that tariffs would be governed by transmission owners’ agreements in the event of conflict. Parties protesting the TO proposals in these cases noted that accepting the TO proposals would establish a Mobile-Sierra bar to changes to the RTO’s rates, terms and conditions of service.  See Avista Corp., 100 FERC at 62,058.  While the Commission left the door open for the TOs to secure certain limited contractual protection for themselves, it made clear that such protection would be restricted to provisions addressing the TOs’ need to satisfy existing statutory constraints, or the unique circumstances of non-jurisdictional owners.

While we question the appropriateness of allowing Mobile-Sierra protection for any of the provisions of the TOA, we are particularly concerned with the Mobile-Sierra protection proposed for the following sections: (1) Section 3.04, relating to the balance of Section 205 rights among the parties for cost allocation and rate design; (2) Section 3.09, relating to planning and expansion; (3) Section; 10.01, relating to termination and withdrawal; and  (4) Section 10.05 and its associated schedule 10.05, relating to ITC formation.  Extending Mobile-Sierra protection to these sections is inappropriate because these provisions may require significant modifications in the future, as wholesale electric markets continue to evolve.  Removing Mobile-Sierra protection from these significant provisions would be consistent with the Commission’s own recognition that it oversees “a dynamic and evolving market where addressing yesterday’s concerns may not address tomorrow.”[19]  More specific concerns with the provisions and with Mobile-Sierra protection of these provisions are addressed in Sections 1(b), 3(e), 4, and 6 of this Protest. 



  In general, NECPUC believes that most of Section 3.09 should not be included in the TOA and should be addressed solely in the RTO’s OATT.  Planning provisions must be susceptible to evolution to meet changing conditions and new developments in the wholesale electric markets.  Planning provisions should be in the OATT so that they can be changed through a Section 205 or 206 filing without the concerns that accompany contract changes.  Protecting these provisions through contract with the TOs is particularly inappropriate because these provisions affect all market participants and stakeholders, not just the parties to the TOA.  NECPUC believes, however, that two provisions relating to planning are appropriately in the TOA as opposed to the OATT: (1) the split of authority between the RTO and the Transmission Owners regarding the RTO’s responsibility to develop the RSP and (2) the Transmission Owner’s obligation to build.

An overarching principle in system planning is that resource options should be evaluated on a resource-neutral basis, wherever possible.[20] Regulators, system operators and stakeholders should consider all solutions on their merits when assessing possible solutions to system constraints. 

Under certain circumstances, generation, distributed generation, demand response and transmission can each provide solutions to transmission congestion and reliability concerns.  There should be no presumption that transmission is the only solution, nor should terms of the planning process preclude or promote any one means of solving these problems.  These specific concerns are outlined in Section 3(a) and 3(b) below.

a)      Planning Procedures Should not be the Exclusive Domain of the RTO and Transmission Owners


The Commission should condition approval of the RTO upon the inclusion of any interested stakeholder in the dispute resolution process available to the RTO and Transmission Owners to resolve disagreements over changes to the planning process or system plan.  The October 31 Filing places within the TOA certain provisions governing the resource planning and expansion protocol for RTO-NE.  See Section 3.09 and Schedule 3.09.  The provisions in Section 3.09 are fairly limited.[21] They reference the RTO-NE planning process and allow for modification through discussion among the RTO, TOs and other stakeholders, all of which NECPUC supports. In Section 3.09(b) however, there is a further provision which grants the TOs the opportunity to take any disagreement over a modification to the planning process or system plan to dispute resolution.  Under Section 11.14, dispute resolution is limited to the RTO and TOs. Resolution of the dispute would result in a modification to the Plan, and presumably would bind all stakeholders notwithstanding their lack of input into the discussion. Excluding other stakeholders from determinations regarding planning protocols and decisions is inappropriate.

ISO-NE currently manages a planning process that produces a Regional System Plan (RSP), (previously called the Regional Transmission Expansion Plan  (RTEP)).[22]  Development of the RSP involves stakeholders from all segments of the electricity market, that is, generators, suppliers, transmission owners, transmission customers, other end users, and regulators. The RSP process has evolved over the past five years and should continue to evolve to meet changes in the regulation and operation of the wholesale electricity market.  When the process first began, for example, there was no proposed Standard Market Design and there were no Firm Transmission Rights available to hedge against congestion costs.[23]  Similarly, the demand response programs ISO-NE now operates did not exist and the notion of demand response to mitigate congestion and price spikes was in its infancy.  Within the next five years there may be more changes that further alter the analysis of system planning and expansion.  Wholly new protocols may be called for. It would not be appropriate, therefore, to “lock in” a particular set of rules that govern many stakeholders by inclusion of the terms in an agreement between only two of them.

b)      The Request for Alternative Proposals Should Not  Be in the TOA


NECPUC particularly objects to the inclusion of terms limiting the use of the Request for Alternative Proposals (RFAP) in the TOA. See, Schedule 3.09, §5.  The proper place for this section is in the OATT.  The RFAP is designed to be issued by the RTO when no proposal emerges to resolve reliability concerns.  The use of the RFAP is limited to near-term reliability needs, for which timely and financially sound proposals have not been forthcoming. The TOA would further limit the RFAP by prohibiting its issuance during the five-year moratorium (commencing on the RTO’s operations date) for any proposal that had previously been advanced.  Further, the RFAP could only be issued for generation, demand side responses and merchant facilities that could be implemented rapidly and that would provide substantial reliability benefits.  After the five-year moratorium, the RFAP could be issued according to standards then in place and found in the OATT, which may or may not have been modified by the RTO pursuant to Section 3.04(c) of the TOA. 

NECPUC does not address at this time whether these are sound conditions.  Rather, we are most concerned that for five years the use of the RFAP will be narrowly defined, without the opportunity for stakeholders to participate in the evolution of its terms.  Because the RFAP is a tool with tremendous implications for other market participants, its terms and operation should not be limited by agreement between the RTO and TOs, as would be the case if it remains a term of the TOA.



c)      The Commission Should Clarify the Provision Regarding TOs’ Right to Seek Recovery of Prudently Incurred Costs.


NECPUC requests that the Commission clarify that the TOs will have the opportunity to seek recovery of costs prudently incurred or prudently committed to be incurred in planning, siting and construction of facilities included in the RSP, but will not have a guarantee of recovery, as Schedule 3.09, Section 6.1 might otherwise be read to provide.  This opportunity to seek recovery would be allowed even in the event a facility is later removed from the RSP.  See Schedule 3.09, Section 6.1.  NECPUC notes  that some states prohibit inclusion in retail rates of any facility still under construction or otherwise not used and useful in the provision of utility service.[24]  The state public utility commissions with these statutory limitations interpret this section of the TOA to allow the TOs an opportunity to seek recovery but not to guarantee that such costs, even if prudently incurred, would be included in rates.  For states without such prohibitions, it must be clear that the opportunity to seek recovery, like the opportunity to seek recovery of costs generally, does not insulate the TO from prudence review, that is, an inquiry into whether the expenditures were prudent at the time they were incurred.  What the TOA adds, and what NECPUC accepts, is that retail regulators would not challenge the decision to pursue the project and expend funds on its behalf, if it is or had been included in the RTO’s RSP.



d)      NECPUC’s Concerns Regarding a Preliminary State Position on Siting


NECPUC is concerned about language in Schedule 3.09 regarding the TOs’ obligation to build under certain circumstances. Section 6.3 provides that if a state commission/siting authority concludes that a transmission project listed in the RSP is unlikely to be approved, the TO has no obligation to go forward. This statement, which would be non-binding, must be made in writing by the chair of the state siting authority.  If such a statement were issued, the TO would have no obligation to continue with planning, financing or siting efforts.  NECPUC is sympathetic with the TOs’ desire not to expend resources on a project that will never be approved. Issuing such a statement, however, even if on a non-binding basis, would place the regulatory authority in a position of prejudging a proposal before a record has been made. The prospect that any state siting authority chairman would, without formal process, issue a “non-binding” written statement that would undermine a utility’s obligation to build is so remote as to not require the procedures set out in Section 6.3.  In addition, a waiver of an obligation to build may eliminate a forum for a state hearing on the merits of the project.

We would suggest, as an alternative means of resolving the problem that Section 6.3 seeks to address, including a provision requiring that, to the extent they are recoverable by the utility, the costs of an unsuccessful attempt to secure authority to build a transmission project be allocated in the same manner as the costs of the project would have been allocated.  This lessens the possibility that those costs would fall on the shoulders of the customers of a single utility.

e)      Planning Provisions Should Not have Mobile-Sierra Protection


The TOA specifies Mobile-Sierra protection over Section 3.09 and accompanying Schedule 3.09, governing the planning process.  As discussed in more detail in Section 2 of the Protest herein, NECPUC believes the provisions should not be Mobile-Sierra protected because to do so would be inconsistent with the need to have the RTO adjust to an evolving market and changing conditions. 



The Commission should condition its approval of the RTO upon removal of the ITC provisions from the TOA.  At the very least, the Commission should remove Mobile-Sierra protection from this section and its accompanying schedule. There are many areas of ITC formation and function which require further development.  For example, the role of an ITC in system planning, deployment of generation, or awarding of FTRs within its footprint could affect participants outside of the ITC.  It is premature to rule on these provisions in the absence of a concrete ITC proposal before the Commission.  To address the TOs’ possible concern that they might be prevented under a Mobile-Sierra standard from revising the TOA to incorporate an ITC, the parties could expressly agree to allow a party to propose an ITC without having to meet the public interest standard for changing the TOA.

If these sections remain, they should certainly not be accorded Mobile-Sierra protection, as there is no ITC in place now. Indeed, there is not even a concrete proposal on the table.  In spite of the fact that an ITC is not even at the formative stage, the Filing Parties ask the Commission to approve provisions that lock in a “framework” for the ITC.  For example, Section 10.05(b)(ii) limits any changes to Schedule 10.05 (which sets forth the “framework” for an ITC) to a two-year window after the operations date. Further, changes in this two-year window must meet the public interest standard of review under the Mobile- Sierra Doctrine.[25]  Locking in this “framework” for the allocation of rights and responsibilities between an ITC that may in the future be proposed and an RTO is particularly inappropriate because an ITC could significantly alter the electric wholesale market in New England.  Accordingly, we request that the Commission condition its approval of the TOA upon the removal of Section 10.05 and Schedule 10.05.    Alternatively, we request that the Commission condition approval upon elimination of Mobile-Sierra protection from Section and Schedule 10.05. The Commission should also make clear in its Order that nothing in its approval of the TOA restricts it from approving an ITC with different allocations of responsibility than those that set forth in Schedule 10.05 without either (1) having to meet a public interest standard or (2) having to find schedule 10.05 to be unjust and unreasonable,. 

NECPUC is aware that the Commission has approved outlines for ITC responsibilities in the past, as well as the inclusion of language governing an ITC’s relationship with an ISO in the ISO’s OATT.[26]  What is objectionable here, by contrast, is the Filing Parties’ request to enshrine in a transmission owner agreement, protected under Mobile-Sierra, provisions governing the relationship between the RTO and an ITC that has yet even to be proposed by the TOs who would create it.  Once an ITC has been proposed, an agreement between the ITC and the ISO will take shape, and, at that time, the Commission can consider which provisions are appropriate for contractual treatment and which belong in the ISO’s or the ITC’s filed tariff.  But it would be premature, in advance of that date, to specify the parties’ relationship in the agreement now under consideration between the Participating Transmission Owners and the ISO.[27]



NECPUC asks the Commission to remove the restrictions on the RTO’s ability to reschedule a transmission outage to significantly reduce congestion costs that would result from the scheduled outage. We ask the Commission to remove these restrictions.. Because the RTO, unlike the Transmission Owners, has no possible conflict of interest in the scheduling or rescheduling of outages, it should have greater discretion in this area.

The TOA gives the RTO the authority to direct the rescheduling of Planned or

Scheduled transmission maintenance outages to accommodate reliability criteria.  It also authorizes the RTO to direct the rescheduling of an outage if “rescheduling the outage reasonably could be expected to result in “Significantly Reduced Congestion Costs for use of the RTO-NE Transmission system.”  Significantly Reduced Congestion Costs are defined in Section 3.08(b)(ii)(A) to mean a reduction in RTO-NE’s estimate of congestion costs attributable to an outage of at least $200,000 per week.  However, the RTO may reschedule an outage to significantly reduce congestion costs for that outage only once, unless an “Emergent or Unanticipated Event Occurs.”[28]  The RTO then has one additional opportunity to reschedule the outage if certain criteria are met.  These provisions may address most of the circumstances in which the RTO might seek to reschedule an outage to significantly reduce congestion costs that might otherwise be caused by the outage.  The RTO, however,  would have to seek the Transmission Owners’ permission to reschedule a third time due to an unanticipated event such as a weather condition or a generation outage.  Even if it is unlikely that this would occur, there is no reason to restrict the RTO from rescheduling if it does.  Further, it is not clear what happens if there is a disagreement over what qualifies as an “Emergent or Unanticipated Event.”  For example, it is not clear whether the RTO could require rescheduling even if the affected TO disagrees with the RTO’s assessment.  This uncertainty could lead the RTO to defer when a TO which questions the RTO’s judgment, even where a rescheduling could avoid significant congestion costs.

Giving broader rescheduling authority to the RTO is especially important because a Transmission Owner may have a conflict of interest if it or an affiliate owns generation or if, for a PTO that continues to have load serving obligations, it or an affiliate has  purchased FTRs.  In these circumstances, there is certainly the possibility that an affilate  might benefit from the outage and the Transmission Owner  would choose not to grant the RTO permission to reschedule it. 

Finally, NECPUC’s requested relief is appropriate because the affected Transmission Owner has an opportunity to recover any direct costs incurred by the Transmission Owner due to a rescheduling of a previously scheduled outage.  Thus, even if the RTO reschedules an outage and in hindsight the outage that was rescheduled would not have caused significant congestion costs, the Transmission Owners can be made whole for the direct costs incurred by the RTO’s rescheduling decision.

    Removing the restrictions on the discretion of the RTO to require rescheduling is consistent with Commission policy.  The Commission has, in several cases, recognized the importance of an RTO’s ability to reschedule outages in ensuring the health of competitive markets.  In PJM Interconnection, L.L.C., 97 FERC ¶ 61,319 (2001);  Order Addressing Compliance Filing, 99 FERC 61,170 (2002), an enforcement proceeding involving the alleged manipulation of transmission maintenance schedules and improper disclosure of such information, the Commission accepted as part of the resolution of the case a filing by PJM establishing its right to reschedule outages.  In California Independent System Operator, 91 FERC ¶ 61,341 (2000), the Commission accepted Section 3.2.3 of the California ISO’s Outage Coordination Protocol providing that no later that 5:00 a.m. of the day prior to the day upon which an outage is scheduled to commence, the ISO Outage Coordination office may cancel an approved maintenance outage where necessary to “avoid unduly significant market impacts that would arise if the outage were to proceed as scheduled.”  Section of the Cal ISO’s OATT defines an “unduly significant market impact” as “an unplanned event or circumstance…that adversely affects the competitive nature and efficient working of the ISO markets and is of such severity that a prudent operator would not have scheduled a maintenance outage of its facility if the unplanned event could be anticipated.” 

Clearly, these orders endorse the legitimate role of an RTO in policing transmission outages in order to assure a vibrant competitive marketplace.  Modifying TOA Section 3.08 as suggested above is consistent with past Commission actions and melds the filed proposal in this case with existing best practices.



The flexibility afforded by Sections 10.01, et seq. of the TOA for termination or withdrawal by the PTOs will substantially compromise the RTO’s independence and risks adversely affecting the service offered by the RTO.  These provisions must be modified to ensure that utilities seeking to terminate their relationship with the RTO must file to do so under FPA Section 205.

Section 10.01(a)(i) of the TOA specifies that PTOs may withdraw from the RTO upon notice of 180 days or more, following an initial five-year term.  Section 10.01(b) provides for PTO withdrawal from the TOA during the term of the agreement in a number of circumstances, including: (i) RTO default; (ii) the issuance of orders by the FERC indicating that RTO participation is no longer encouraged or that recovery of associated costs has been placed in doubt; (iii) the issuance of orders by FERC affecting the relative rights and responsibilities of the PTOs and the RTO in a manner deemed adverse to the PTOs; (iv) the PTO has entered into an agreement to form an ITC; and (v) the PTO has obtained authorization from FERC to join another RTO.  Section 10.01(f) specifies that any withdrawal shall be permitted unless FERC finds that termination is contrary to the public interest, as defined by the Supreme Court in Untied Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956); and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956).

The relationship of Transmission Owner termination rights to RTO independence has been recognized by FERC. [29]  Withdrawal by a PTO, once the RTO has begun providing service, will threaten ongoing transmission agreements undertaken by the RTO, along with the associated dependent merchant services.  It was clearly with these concerns in mind that the Commission, consistent with longstanding practice governing filing to terminate service, has established that notice of withdrawal from an RTO must be filed with the Commission under section 205 of the FPA, and may become effective only with approval of the Commission.

 The relationship between termination and withdrawal rights and ISO/RTO independence is, in fact, one of the ISO’s stated reasons for changing its current contractual relationship with NEPOOL to an RTO arrangement.  In the past, the approaching expiration of the Interim ISO Agreement has been used by some market participants to try to influence the ISO’s agenda on various issues.  The Commission should ensure that a similar dynamic is not created by the withdrawal and termination provisions of the TOA.  Thus, the Commission should require greater Commission oversight of termination and withdrawal. 

The Commission has recently made clear that it will consider the justness and reasonableness of such provisions in an RTO under a section 205 standard. In Guidance on Regional Transmission Organization and Independent System Operator Filing Requirements under the Federal Power Act, 104 FERC ¶ 61,248 (2003), in direct response to the Atlantic City decision, the Commission held: that in approving an RTO agreement its “consideration will extend to matters such as whether, at the outset of an RTO or ISO, member entrance and exit rights are just, reasonable and not unduly discriminatory as well as whether a specific proposed withdrawal of a participant is consistent with the FPA.”  Slip Op at 1 

Proposed Section 10.1(f) of the TOA has clearly been drawn to establish a strong presumption favoring approval of a PTO’s decision to terminate its relationship with the RTO.  Rather than placing any burden on the PTOs to establish that their departure will cause market participants no harm, the burden is placed on the Commission or challengers to demonstrate that withdrawal is contrary to the public interest, as construed under the elevated Mobile-Sierra standard.  This structure places RTO customers, market participants and public agencies seeking to preserve RTO benefits for their constituents at a distinct disadvantage as they seek to prove that the harm they and the public interest will suffer outweighs the PTOs contractual rights.

Atlantic City Electric Co. v. FERC[30]  is not inconsistent with FERC approval under section 205 of termination provisions of the TOA.  The Court in Atlantic City addressed the Commission’s claim that it could limit termination rights under its Section 203 authority.  The Atlantic City court rejected the Commission’s determination that a transmission owner’s relinquishment of operating authority to an ISO amounted to a transfer of control for purposes of section 203.[31]  However, the court expressly left open the scope of the Commission’s authority under FPA Section 205.  As the court held:

The petitioners are not disputing FERC’s authority to review their agreements at the outset and to decide, based on the evidence in the record, whether the entrance and exit rights specified therein are just and reasonable within the meaning of Section 205.  Nor do petitioners contest FERC’s authority to review a specific withdrawal under Section 205.  Rather, it is only FERC’s assertion of jurisdiction under Section 203 that is at issue.

295 F.3d at 12.

  The Court’s statement in Atlantic City, supra, is in keeping with that Court’s earlier and analogous observation that although pooling agreements are purely voluntary in the first instance, are nonetheless subject to Commission review to ensure that they are not unreasonable or unduly discriminatory. Central Iowa Power Cooperative v. FERC, 606 F.2d 1156 (D.C. Cir. 1979). Acting under FPA Section 205, the Commission would be entirely justified in requiring modification of Section 10 of the TOA in order to require the PTOs to submit a notice of termination of their relationship with the RTO, and to demonstrate that such termination is just and reasonable.  Indeed, in the very PJM case underlying the initial decision in Atlantic City -- in provisions that were not challenged in court -- the Commission insisted that the PTOs file notice of termination of their relationship with the ISO under section 205, and further provided that such termination would not be effective until approval by the Commission.[32] 

  The Commission’s reasonable insistence on its authority to approve a transmission owner’s termination of its relationship with the ISO is consistent with strong precedent providing that the termination of agreements to provide transmission and sales service requires notice and approval.  As long as fifty years ago, the Supreme Court recognized the Commission’s authority to require the continuation of service notwithstanding the termination of an agreement.[33]  The Commission has consistently applied this principle in cases involving the termination of agreements to provide transmission and sales service.[34]  The precedent is further consistent with a customer’s right of first refusal under the Order No. 888  pro forma tariff and with decisions holding that a utility’s association with a power pool or regional transmission group (“RTG”) under Section 202 of the FPA, while volitional at the outset, may be terminated only with permission of the Commission.[35]  The thread running through each of these cases, and plainly applicable here, is that the Commission has a strong and legitimate interest in ensuring continuity of service and in protecting customers against abandonment, even upon the formal termination of an agreement.

  With the strength of this precedent in mind, and with the independence of the RTO and the vitality of its ongoing service at stake, NECPUC asks the Commission to modify the TOA to require that PTOs choosing to withdraw from the organization be required to file for permission to do so under FPA Section 205, and demonstrate that their departure is just and reasonable.



NECPUC recommends that Section 3.10 of the TOA, which changes the manner in which ISO-NE currently administers its monthly settlement system, be eliminated from the TOA and be the subject of a separate proceeding after the operations date of RTO-NE.  Under the current settlement system, ISO-NE establishes for each NEPOOL member a single monthly invoice that combines the member’s transmission-related charges, administrative charges, ancillary service charges or payments, and other wholesale power market charges or payments.  The amount owed by, or owed to, a member is the net of the above charges and payments.  Section 3.10(b) calls for RTO-NE to establish for each NEPOOL member two separate invoices (or a single invoice with two sets of charges),  (1) those related to receiving transmission services (which the TOA refers to as “PTO Invoiced Amount”), and (2) other charges (which the TOA refers to as “RTO-NE Invoiced Amount”).  Section 3.10(b)(vii) states that members’ invoices “shall clearly differentiate and delineate between the PTO Invoiced Amount and the RTO-NE Invoiced Amount, and ... shall state that a Transmission Customer is not permitted to net or offset the PTO Invoiced Amount against any other charges or payments included on such invoice.”  As such, the monthly settlement system called for by Section 3.10 eliminates the “net” billing approach currently in effect, to be replaced by two sets of charges and payments to be settled separately.

Other market participants have expressed concerns about the effect of these changes.  They have suggested that the provisions included in Section 3.10 would result in transmission owners bearing less risk with respect to recovery of their transmission revenue, and other NEPOOL members bearing a corresponding level of greater risk.  NECPUC requires more information before we can reach an informed opinion regarding the merits of the changes included in Section 3.10 (i.e., whether such a redistribution of risk is appropriate, and in the best interest of consumers).  As such, NECPUC does not take a position on the proposed change in the current settlement system.  In light of the fact that the changes in the current monthly settlement system called for by Section 3.10 are not necessary for the formation of RTO-NE, and considering the substantial complexity of the issues included in the TOA that the Commission must address, NECPUC recommends that the Commission reject those provisions included in Section 3.10 that call for changes in the manner in which ISO-NE currently administers its monthly settlement system and defer consideration of the issue to another proceeding.



  The Information Policy currently in place is woefully inadequate with respect to the state commissions' ability to obtain the information they need to evaluate market issues.  The Commission should direct that the Information Policy be changed prior to the Operations Date to ensure that public utility regulatory authorities have access to all materials, including certain confidential information. 

The Participants Agreement appears to envision that no changes will be made to the Information Policy prior to adoption by the RTO and the Participants. The Participants Agreement states:

“Information Policy” shall mean the policy establishing guidelines regarding the information received, created and distributed by Participants and RTO-NE in connection with the settlement, operation and planning of the System, as the same may be amended from time to time in accordance with the provisions of this Agreement.  On the Operations Date, the Information Policy shall be substantively identical to the document entitled the “NEPOOL Information Policy” as in effect immediately preceding the Operations Date.


Participants Agreement §1. 


  The current NEPOOL Information Policy has in the past been read by some Market Participants as not permitting access by state regulators to confidential information that is collected by or developed by the ISO.  ISO-NE has failed to provide information to state commissions, claiming that the NEPOOL Information Policy prevents it from doing so.  NECPUC previously has asked the Commission to clarify that the NEPOOL Information Policy allows the ISO to disclose confidential market data such as bid data to state utility regulatory commissions if the regulatory commission issues a protective order to protect the confidential nature of the material.  Answer of the New England Conference of Public Utilities Commissioners in Support of Motion of the Maine Public Utilities Commission for Disclosure of Information, in Docket EL00-109 (November 28, 2000).  This request was never acted upon because the bid data sought on a timely basis was eventually made public after the six-month lag required by the Information Policy  Accordingly, we ask the Commission to direct the Participants and ISO-NE to revise, as follows, a portion of the text of section 3.1 of the Information Policy to make clear that any New England regulatory commission may have access to Confidential Information that is in the possession of the RTO.  The Commission should require the following change to the information policy prior to filing it on or before the RTO Operations date. 


 (a) If the information is Confidential Information, ISO New England or NEPOOL, as the case may be, will refer the request to the Furnishing Entity and will not release the requested information unless it is directed to do so by the Furnishing Entity or ordered to do so by a court or regulatory authority with jurisdiction over such matters.The Furnishing Entity shall bear any costs reasonably incurred by NEPOOL and/or ISO New England in opposing the issuance of such an order requiring disclosure of the Furnishing Entity’s Confidential Information. Notwithstanding the foregoing: (a) upon the request of a New England public utility regulatory agency commission [agency] [other than FERC or its staff, having appropriate jurisdiction], other than FERC or its staff, having appropriate jurisdiction and subject to an appropriate confidentiality order entered under such agency’s procedures sufficient to preserve the confidential nature of the information submitted, and with advance notice to the Furnishing Participant, ISO New England may submit Confidential Information to such [agency] public utility commission agency; (As proposed.)



NEPOOL Information Policy Section 3.1(1)(a).  This will clarify that the RTO may provide a New England public utility commission Confidential Information (within the meaning of the NEPOOL Information Policy) if the utility commission can protect the confidentiality of the data.  An Order directing such a change will provide needed guidance in an area that to date stakeholders have been unable to resolve. 



  The OATT provides that the through and out charges shall be eliminated in five years.  Without commenting on the appropriateness of this time period, NECPUC would respectfully remind the Commission that the question of how to fairly allocate the costs  and benefits of seams reduction in general, and the elimination of the through and out charges in particular, remains to be resolved.






  NECPUC asks the Commission to issue an order modifying the filing in this case in the manner and for the reasons articulated above,


        Respectfully submitted,


          Harvey L. Reiter

John E. McCaffrey

Stinson Morrison Hecker, L.L.P.

1150 18th Street, N.W.

Washington, D.C. 20036

          Tel:  (202)785-9100

          Fax: (202)785-9163 

Robert Sydney, General Counsel

Massachusetts Division of Energy Resources

70 Franklin Street

Boston, MA 02110-1313

(617) 727-4732


Washington, D.C.

December 8, 2003



I hereby certify that I have served the foregoing document upon the parties to the service list compiled by the Secretary of the Federal Energy Regulatory Commission in this proceeding, consistent with the Commission’s Rules of Practice and Procedure



            Jacqueline Alexander


Washington, D.C.

December 8, 2003




[1] This proceeding was initiated with a filing made on October 31, 2003 (“the October 31 Filing”) by ISO-New England (“ISO-NE”) and the New England Transmission Owners  (“TOs”) (together, the “Filing Parties”) in support of the creation of an RTO pursuant to Order No. 2000. Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 2000-A, 65 Fed. Reg. 12,088 (2000), FERC Stats. & Regs. ¶ 31,092 (2000), appeal dismissed, Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001) (Order No. 2000) (“Snohomish”).

[2]  This protest is joined by the Massachusetts Division of Energy Resources.  It is further noted that on November 6, 2003, the Massachusetts Department of Telecommunications and Energy (MDTE) conducted a Technical Conference to receive comments on the RTO-NE filing.  The following parties presented comments:  the Massachusetts Office of the Attorney General (Mass. AG), the Massachusetts Division of Energy Resources (DOER), ISO New England Inc. (ISO-NE), Western Massachusetts Electric Company (WMECo), NSTAR Electric, National Grid U.S.A., US Gen New England, Inc., TransCanada Power Marketing, Ltd. (TransCanada), Braintree Electric Light Department, Reading Municipal Light Department, Taunton Municipal Light Plant, and Fitchburg Gas and Electric Light Company (FGE).  Supplemental written comments were submitted by:  Mass. AG, DOER, ISO-NE, Massachusetts Municipal Wholesale Electric Company, TransCanada, FGE, Power Options, Inc., The Energy Consortium, and the Massachusetts Transmission Owners (Boston Edison Company, Cambridge Electric Light Company, Canal Electric Company, Commonwealth Electric Company, New England Power Company, and WMECo).  The MDTE’s positions taken in these NECPUC Comments reflect consideration of these comments received through its Technical Conference.

[3] See generally, e.g.  Bangor Hydro-Electric Co., et al., 96 FERC ¶ 61,063 (2001). 

[4] Filing Letter, p. 16. 

[5] See Section 6.17 of the ISO Agreement, cited at p. 17 of the October 31 Filing Cover Letter.  See also Bangor Hydro-Electric Co., 96 FERC ¶ 61,063 at 61,259 (2001); .

[6] 295 F.3d 1 (D.C. Cir. 2001); Order on Remand, Pennsylvania-New Jersey-Maryland Interconnection, et al., 101 FERC ¶ 61,318 (2002); Order Enforcing Mandate, Atlantic City Electric Co. v. FERC, 329 F.3d 856 (D.C. Cir. 2003).

[7] See Guidance on Regional Transmission Organization and Independent System Operator Filing Requirements under the Federal Power Act, 104 FERC ¶ 61,248 (2003).

[8]  See United Gas Pipe Line Co. v. Mobile Gas Serv., 76 S.Ct. 373 (1956); Federal Power Comm’n v. Sierra Pacific Power Co., 76 S.Ct 368 (1956).

[9] NECPUC provides additional comments below on proposals in the October 31 Filing governing payment arrangements under the TOA, the proposed Information Policy and on through and out rates. 

[10] Bangor Hydro-Electric Company, et al.,  96 FERC ¶ 61,063 at 61,259 (2001).

[11] The “jump ball” does not arise from an 80% vote against an RTO proposal, but only when 80% vote in favor of a specific alternative.

[12]  The Commission has also emphasized, and NECPUC agrees, that TOs should have the opportunity to make section 205 filings to recover their revenue requirements.

[13] 272 F.3rd at 616.

[14] Id. at 613. The D.C. Circuit Court’s decision in Atlantic City is not to the contrary.  The Atlantic City court held that under Section 203 of the FPA, the Commission may not require a transmission owner to cede its section 205 rights.  However, nothing in Atlantic City or the FPA requires the Commission to accept an RTO proposal that is inconsistent with the allocation of rights set forth in Order 2000.  In a recent issuance by the Commission, it confirmed that RTO filings such as this one made under section 205 of the FPA will “continue to be required to demonstrate that they meet the principles of Order no. 2000.” Guidance on Regional Transmission Organization and Independent System Operator Filing Requirements Under the Federal Power Act,  PL03-5-000 (September 10, 2003).  The Commission specifically stated:

In undertaking our review of such Section 205 filings, the Commission will consider whether all of the elements contained in the filed arrangements meet the principles of Order No. 2000 and are just and reasonable pursuant to Section 205 of the FPA.  Id.

[15]  As the designers of rates at the state level, we know from first-hand experience that this aspect of utility regulation can involve significant public policy considerations, including a desire to achieve compatibility with government policies in related areas. 


[16] By giving the jump ball rights to the RSC, the TOs and ISO recognize that cost allocation may implicate significant public policy issues and that the Commission will look to the RSC to be the regional voice on such issues.

[17] On September 8, 2003, the six New England Governors directed staff to file a Regional State Committee (“RSC”) proposal with FERC.  The New England governor’s Power Planning Committee Regional State Committee Working Group will finalize a proposal in consultation with ISO-NE, NEPOOL and NECPUC.  A RSC proposal will likely be filed with FERC early next year. 

[18]  FERC has stated that this  “public interest” standard would apply to changes proposed by a party to the agreement, a non-party or FERC itself. See Nevada Power Company and Sierra Pacific Power Company, 103 FERC ¶ 61,353 (2003)  While NECPUC believes that non-parties to filed agreements cannot be held to the same standard of review in challenging an agreement as are a parties to the agreement, we cannot discount the possibility that NECPUC or other parties may be faced with significant barriers to changing provisions of the TOA that at a later time turn out to be unjust and unreasonable.

[19] 105 FERC 61,218 at 15

[20] See ISO New England, et al., 91 FERC ¶ 61,311 at 61,075-76 (2000).

[21] The obligations of the TOs articulated in Section 3.09 and Schedule 3.09 of the TOA do not include any requirement or obligation on the part of the TOs to undertake transmission expansion and other transmission projects requested by market participants or other third party entities who are willing and able to fund their requests.  Certain  NECPUC members believe that such an obligation is vital if market driven transmission projects are to take place.  These states believe that since TOs are the market entities with the experience, ability and, in many cases, the exclusive rights to build transmission, they have to play the role of conduit for transmission projects identified and desired by market participants if such projects are expected to be built.  NECPUC recognizes that the TOA may not be the appropriate document and this proceeding may not be the appropriate forum for raising concerns regarding the need for this obligation.  NECPUC assumes that silence on this point in this proceeding does not preclude raising this issue at a later date, in an appropriate forum, and expressly reserves its rights, collectively and each state individually, to do so.


[22] Until 2003, ISO-NE produced a Regional Transmission Expansion Plan (RTEP).  At NECPUC’s urging, the word transmission was removed, to make clear that more than transmission should be considered when studying the needs of the system and potential solutions to its problems. 

[23] Before SMD, congestion costs were spread across the entire region. 

[24] See, e.g. New Hampshire RSA 378:30-a, the so-called Anti-CWIP statute.

[25] After two years changes can be made only to address a Commission order addressing the allocation of responsibilities between the RTO and an ITC.  Thus, even if no ITC filing is made within two years of the operations date, no change may be made to schedule 10.05 except by agreement of the parties. 

[26] See TRANSLink Transmission Co., 99 FERC ¶ 61,106 (2002); PJM Interconnection, LLC, 102 FERC ¶ 61,296 (2003). 

[27] We note that in PJM Interconnection, LLC,  102 FERC at 61,930, the Commission specifically rejected an effort even to specify in the ISO’s OATT that an agreement between an ITC and the ISO would receive Mobile-Sierra  protection. That decision  underscores  the Commission’s reasonable reluctance to prejudge any aspect of the contractual relationship between an ITC and the ISO in advance of a complete proposal.  We further note that in Cleco Power, LLC, et al., 101 FERC at 61,022, the Commission did issue a declaratory order conceptually approving an outline of ITC functions  that were presented in the context of an agreement between the sponsoring TOs and the RTO.  Yet, the Commission’s decision in that case spoke only to the merit of the outline of ITC responsibilities, and not the propriety of enshrining ITC rights and responsibilities in a TOs’ agreement. 

[28] An Emergent and Unanticipated Event is defined as “a material change in actual or projected system conditions, including a forced outage of a transmission line or a forced outage of a generating resource that could not reasonably be foreseen or a material change in projected load that could not reasonably be foreseen.

[29] See Midwest Independent System Operator, et al., 84 FERC ¶ 61,231 at 62,151; Order on Reh’g; 85 FERC ¶ 61,372 (1998); Pennsylvania-New Jersey Maryland Interconnection, et al.,, 81 FERC ¶ 61,257 at 62,264 –65 (1998).  The principles of these cases follow from the Commission’s longstanding position that termination of service is a change of service governed by Section 205. See Section 35.15 of the Commission’s regulations.  See also, Florida Power & Light Co., 3 FERC ¶ 61, 231 (1978).

[30] 295 F.3d 1 (D.C. Cir. 2001); Order on Remand, Pennsylvania-New Jersey-Maryland Interconnection, et al., 101 FERC ¶ 61,318 (2002); Order Enforcing Mandate, Atlantic City Electric Co. v. FERC, 329 F.3d 856 (D.C. Cir. 2003). 

[31] 296 F.3d at 11 – 12.

[32] 92 FERC ¶ 61,282 at 61,959 (“Under Section 205 of the FPA, transmission owners must file a notice of withdrawal and the Commission must act on the filing.  Our decision is consistent with clear precedent requiring Commission approval before withdrawal from an ISO [citations omitted].”) 

[33] See Pennsylvania Water and Power Co. v. F.P.C., 343 U.S. 414, 422-24 (1952), cited in Florida Power & Light Co., 3 FERC ¶ 61,081 at 61,231 (1978) ("before service can be terminated, the proposed termination must be shown to be consistent with the public interest.)

[34] See Louisville Gas & Electric Co.,  72 FERC ¶ 61,078 at 61,415-16 (1995); Southwestern Electric Power Co., et al, 65 FERC  ¶ 61,212 at 61,987 (1993);  and 18 C.F.R. § 35.15.

[35] See New York Power Pool, 58 F.E.R.C. ¶ 61,326 (1992); Western Regional Transmission Association, 71 FERC ¶ 61,158 at 61,525 (1994); Southwest Regional Transmission Association, 73 FERC ¶ 61,147 (1995).