Jnofflclal FERC Generated PDF of Received by FERC OSEC

Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : ER04-114-000 ~'//., %+ + % October 31, 2003 VIA MESSENGER Ms. Magalie R. Salas Secretary Federal Energy Regulatory Commission 888 First SU-eet, N.E. Washington, D.C. 20426 Re: ISO New England Inc. Filing of Revised Sheets for Capital Funding Tariff, Docket No. ER04- Dear Ms. Salas: ISO New England Inc. (the "ISO") hereby submits, pursuant to Section 205 ofthe Federal Power Act, revised tariff sheets (the "Revised Sheets") updating Attachment A of its Capital Funding Tariff ("CFT") and providing information about long-range capital projects. The Revised Sheets reflect the addition of the ISO's 2004 capital budget items (the "2004 Items") to the contingent funding mechanism specified in the CFT. These capital budget items are essential to the accomplishment of the ISO's objectives for 2004. The addition of the 2004 Items to the CFT is just and reasonable, as demonstrated herein. By way o f review and introduction, the CFT permits the ISO to collect from the NEPOOL Participants: (1) the costs of budgeted capital items, through a "Capital Funding Charge" ("CFC"), if these costs are not financed2 by the ISO; The CFT was ongmally accepted by the Commtsstonm a delegated lener order msuedApnl 25, 2001 in Docket No. ER01-1382-000,and has been revised effectiveJanuary l, 2002, August 1, 2002, and January 1, 2003. As used hereto, the term financing refers to third-partyborrowmgsfrom, or leasingan'angementswith, banks or other lendinginstitutions,rather than fundingby NEPOOL Participants. 2 . tt • ~t . . . . ] . . . . . . . % Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 (2) the remaining unamortized costs of assets financed through the ISO's capital cost financings (including financing arranged by the ISO for repayment of the NEPOOL Participants for capital items previously acquired through the effective date ofthe CFT) if that financing is terminated early or repayment is accelerated (and no replacement financing has been obtained by the ISO), through an Early Amortization Charge ("EAC"); and (3) the working capital amount required by the ISO, ifworking capital financing arranged by the ISO to meet working capital requirements is terminated early or repayment is accelerated (and no replacement financing has been obtained by the ISO), through an Early Amortization Working Capital Charge ("EAWCC"). The ISO may never need to access funds pursuant to the CFT. Based on the terms o f the CFT, if all ofthe 2004 capital costs added to Attachment A via the Revised Sheets are financed and no termination or acceleration ofthat financing occurs - no CFCs or EACs will ever be collected for these p3urposes. Financing approved by the Commission under Section 204 of the Federal Power Act, coveting the ISO s working capital needs and its 2000-2003 capital expenditures, is currently in place. As a result, no charges have been assessed to NEPOOL Participants to date under the CFT. No additional working capital borrowings are planned, because the revolving credit financing o f $15 million that is currently in place is sufficient for the ISO's needs.4 The ISO is negotiating with its current lenders for additional financing for the ISO's 2004 capital needs, and will be filing an application under Section 204 for approval of additional borrowing. The CFT is a necessary element for full self-funding o f the ISO. Self-funding of the capital items necessary for reliable operation of the bulk power system and the administration of efficient and competitive energy markets has been recognized by the Commission - specifically with respect to the ISO - as a requirement for meeting the Order 888 independence criterion for independent system operators.5 3 See letter orders, 94 FERC ¶ 62,271 and 94 FERC ¶ 62,272 (2001), 1SO New Englandlnc., 97 FERC ¶ 61,304 (2001) and ISO New England Inc., I00 FERC ¶ 61,130 (2002). 4 Working capital borrowings relates to ensuring the ISO's ability to fund day-to-dayexpenses. 5 In ils Jufie 1997 order approving the establishment of an independent system operator for New England, the Conmussion reviewed the proposed arrangernents under which the ISO would obtain the existing facilities, equipment and software and future capital assets ("Capital Assets") necessary to the conduct of its operations. See New England Power Pool, 79 FERC 1 61,374, at p. 62,590 (I 997). The Commission expressed its concern that the arrangements proposed by NEPOOL "may affect the independence of the ISO." Accordingly,the Commission conditioned its approval of the ISO on NEPOOL's proffer of contractual provisions for existing Capital Assets, and stated that: 2 Inofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Six copies of this filing letter and its associated exhibits are filed herewith. Contents of this Filing Letter This filing letter is divided into the following sections: • • • an introduction (Section I), addressing the ISO and its mission, and providing a review of the structure ofthe CFT and its rate design; a listing of the documents submitted with this filing (Section II); the additional 2004 capital items reflected in the Revised Sheets, the basis for these capital expenditures, the categorization of those expenditures in CFT Attachment A, and the multi-year capital projects added to Section 8.1 of the CFT (Section Ill); information required by Part 35 (Section IV); communications (Section V); and a conclusion (Section VI). • • • 1. Introduction The context ofthe Revised Sheets is best understood through: (A) a description of the ISO and its mission; and (B) a brief review o f the CFT and its rate design. A. The ISO and Its Mission The ISO is the non-profit independent system operator that, pursuant to the Interim Independent System Operator Agreement (the "ISO Agreement")6 and the authorization of the (...continued) To the extent the ISO requires additional, similar facilities in the future, these facilities should be funded by the ISO, not NEPOOL, through the ISO's transaction fees to be developed as discussed above. /d. Quite simply, the CFT represents compliance with this requirement. 6 See Letter Order, Exte~ion of Interim Independent System Operator Agreement, Docket No. ER03-1181-000. Because the ISO will need to operate under the Interim ISO Agreement pending Commission action on the lSO's October 31, 2003 filing to obtain Regional Transmission Organization ("RTO") status, and because this filing does not reflect capital items relating to future RTO formation, the Commission's approval of this Tariff filing should not wait for Commission resolution of the ISO's filing of RTO status. If granted RTO status, the ISO will review ils capital r e q u ~ t s and, ifnecessary, make a new filing then. A filing will be necessary, in any event, to include this Tariff(and the Admires"trafive Cost Tariff) as Section IV of the onmtbus RTO tariff. 3 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Commission in the June 1997 Order, is responsible for operating the bulk power system in New England, including administration of the NEPOOL Open Access Transmission Tariff(the "NEPOOL Tariff'), and of the region's restructured wholesale electricity marketplace. As a non-profit, non-stock Delaware corporation, the ISO has no equity capital (or ability to raise equity capital) to fund capital expenditures or working capital. Substantially all of the ISO's revenues are derived from charges to its customers, the NEPOOL Participants, and thus, the ISO's ability to fund its capital expenditures through financing is dependent on its collections from those customers under the tariffs approved by the Federal Energy Regulatory Commission (the "Commission"). The ISO's administrative costs are collected under its Tariff for Transmission Dispatch and Power Administration Services (the "ACT"). The ACT's current provisions are the product of a settlement approved by the Commission. 7 The financing expenses for existing capital items and working capital are collected through the ACT revenue requirement. The ISO obtains repayments through depreciation and interest, with the amortization and repayment period corresponding to the appropriate recovery period (typically the depreciation period) for the item being paid for, under generally accepted accounting principles. Formed in response to the Commission's Order No. 888, s the ISO began its operations on July 1, 1997 with the transfer of staff from, and using the equipment of, the NEPOOL control center. On May I, 1999, pursuant to approvals granted in a series of Commission orders, 9 NEPOOL and the ISO initiated the operation of the New England wholesale markets (collectively, the "Markets"). In 2002 and 2003, the ISO dedicated a substantial portion ofits capital resources to the development of a Standard Market Design ("SMD"). The implementation of the initial phase of SMD in New England ("SMD 1.0"), which commenced on March 1, 2003, represents a significant milestone in the evolution of New England's wholesale electricity markets. Nonetheless, improvements and refinements of those markets are required to realize fully the benefits of SMD. This year's filing seeks continued capital funding to implement further enhancements to the wholesale electricity market in New England, and provide other necessary equipment and software to support ongoing operations. 7 See ISO New England Inc., 96 FERC ¶ 61,261 (2001). s Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities: Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036, 61 Fed. Reg. 21,540 (1996), clarified, 76 FERC ¶ 61,009 and 76 FERC ¶ 61,347 (1996) ('Order 888'9, on reh'g, Order No. 888-A, FERC Stats. and Regs. ¶ 31,048, 62 Fed. Reg. 12,274, clarified, 79 FERC ¶ 61,182 (1997), on feb'g, Order No. 888-B, 81 F.E.R.C. 61,248, 62 Fed. Reg. 64,688 (1997), on feb'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998); Open Access Same-Time Information System and Standards of Conduct, Order No. 889, FERC Stats. & Regs. 1 31,035, 61 Fed. Reg. 21,737 (1996) ("Order 889"), on feb'g, Order No. 889-A, FERC Stats. & Regs. ¶ 31,049, 62 Fed. Reg. 12,484 (1997), on feb'g, Order No. 889-B, 81 FERC ¶ 61,253 (1997). 9 See, e.g., New England Power Pool, 85 FERC ¶ 61,379 ( 1998); New England Power Pool, 87 FERC 1 61,045 (1999); New England Power Pool and ISO New England Inc., 87 FERC 1 61,055 (1999). 4 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 In additionto operatingthe Markets, the ISO also providesadministrativesupport for bilateraltransactionsand self-scheduling, provides market power monitoring and mitigation. and The ISO has broad responsibilities under the ISO Agreernent including,in additionto the functionslistedabove: (I) to develop the long-rangeSystem (as thatterm is definedin Section 2.32 ofthe ISO Agreement) assessment and transmissionconstructionplans of the N E P O O L Participants; undertakingindependent assessmentsof the competitivenessand efficiencyof (2) the Markets; (3) ensuring short-termreliability the System; (4) overseeingmaintenance of scheduling for generationand transmissionfacilities; administeringintcrconncctioncontracts (5) with utilities otherentities and outsideof the N E P O O L Control Area; (6) directingand overseeingoperationsof Satellite controlcenters;(7) developing new and revised System rules and procedures;(8) directing, with stakeholderinput,the regionaltransmissionexpansion planning process,and approving associatedupgrades, and (9) providing activeleadershipfor the N E P O O L technicalcommittees and for the regionaltransmissionexpansion planning process.:° The I S O ' s ability to perform its mission successfully is highly dependent on the adequacy o f its facilities, equipment and software. The 2004 Items will fund additional enhancements to SMD, and support other capital priorities, as well. The benefitsof S M D have been recognizedby the Commission in itsordersregarding N e w England's Market Rule I and other filings. In particular, resultingconvergence in 11 the market designs in N e w England, PJM and N e w York will supporta much more liquidenergy market in advance of implementationof the Commission's standardmarket design rule. Additionalsavingswill accrue from more efficient generationlocation,optimal consumcr capital investment,and consumer consumption decisionsthatreflectthe realcost of electricity. :0 See ISO Agreement, §§ 6.3, 6.4, 6.6, 6.8, 6.1 I, 6.17(b), 6.17(b), respectively. The 1SO's responsibilities with respect to regional transmission planning have been increased by the Cormmssion. See ISO New England Inc., 9 I FERC 1 61'3 11 at 62,074-78 (2000), on reh'g, 95 FERC ¶ 61,384 at 62,430-32, 62,436-39 (2001), on reh 'g, 96 FERC ¶ 61,228 at 61,927 (2001). 11 See, See ISO New England Inc. and New England Power Pool, 100 FERC 161,287 at P I (2002), order on reh 'g and accepting compliance filings, 101 FERC 161,344 (2002) (in which the Commission discussed the benefits that SMD and Market Rule I would bring to New England market participants); see also, Regional Transmission Organizations, et al, 104 FERC 1 61,296 at PP 5-7 (2003) (in which the Commission terminated all proceedings aimed at facilitating a single Northeast-wide RTO, in part, because the lSO's efforts to reduce seams through the adoption of SMD had made the formation of such a region-wide RTO mmecessary). Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 B. A Review of the Structure of the CYI" and its Rate Design The structure of the existing CFT is quite straightforward. Section 1 (and Attachment B) set forth the necessary definitions. No changes to the structure of the CFT or its rate design are being made in this filingJ 2 Section 2 and Attachment A set forth the CFT's key substantive provisions. Section 2 specifies the three charges that may be collected under the CFT. Section 2 refers, for calculation of the CFC and EAC, to Attachment A. Existing Attachment A (prior to its replacement by the Revised Sheet) sets forth the capital items for 2000, 2001, 2002 and 2003. The Revised Sheets modify Attachment A to add the 2004 Items. The revised Attachment A carries over the cumulative allocation for 2000-2003 items from the current version of Attachment A, for the purpose of determining EAC allocation percentages. The 2004 Items listed in Attachment A represent the ISO's best estimate of 2004 capital spending. A number of events, initiatives and/or Commission orders, including changes to SMD, or requcsts for additional services from market participants, could affect capital spending levels or purposes. The ISO reserves the option to submit a Section 204 filing for permission to obtain additional financing during 2004, and Section 205 filings to increase capital spending and cover additional debt service in the event that changing circumstances dictate the need for additional funding. Attachment A also allocates the capital costs ofthe 2004 items - as explained more fully in the next subsection - among the services provided by the ISO under the ACT. The remainder of the CFT includes similar terms and conditions to those contained in the ACT. 13 The CFT's rate design is tied closely to the ACT and - in the case of the CFC and EAC to its three-rate-schedule structure. This is consistent with the allocation (discussed in the next subsection) ofcapital items to these three rate schedules (the "Schedules") reflected in Attachment A. The rate design for the CFT has been formulated so the rate design accepted by the Commission for the three schedules of the ACT can be applied at a given point in time to calculate each Participant's charges under the CFT. The amount ofthe CFC and EAC payable by a Participant thus depends on the allocation of the capital-related revenue requirements among the Schedules in Attachment A of the CFT, and the Participant's proportionate monthly payments under each Schedule of the ACT. s2 As explained fu.rth~in the accompanying letterconcerning the ISO 2004 Administrative Cost Tariff Filing,the only modification to the Tariffrates is to expand the "t~ansactionalunit" billingdeterminants utilizedin Schedule 2 to reflectcertainday-ahead market activity. t3 Customers must enter into a Service Agreement of the type specified in Attachment C to the CFT. 6 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Under the ACT, each o f the Schedules recovers the allocated administrative costs o f the ISO of providing a corresponding "Service." The Schedules and corresponding Services t4 are: Schedule 1: Scheduling, System Control and Dispatch Service (''Scheduling Service"); Schedule 2: Energy Administration Service ("EAS"); and Schedule 3: Reliability Administration Service ("RAS"). With this background, the rate design for each charge under the CFT is set forth below. 1. The ¢ F ¢ rate design The CFC recovers the acquisition costs o f capital items listed in Attachment A to the CFT that have not already been funded by Participants as late restructuring expenses ("LRE") under the RNA and only to the extent that the ISO is unable to fund these remaining costs through private financing. In Attachment A, the cost of each of the 2004 Items is allocated among the three Services corresponding to the extent to which that capital item is utilized in providing the Service.15 To assist the Participants in their planning for payments ofthe CFC, the ISO will post on its website the non-binding, estimated monthly cash flow requirements of the ISO (for a Calendar Year or remaining portion thereof) with respect to acquisition ofthe capital items listed in Attachment A, and allocated among the Schedules. To the extent the ISO has not arranged financing, the ISO will bill each Participant monthly, and each Participant will pay, as its CFC: (1) the proportion of the capital costs allocated to Sehedule 1 under Attachment A actually incurred by the ISO during the preceding month equaling the proportion of the Participant's charges under Schedule 1 of the Tariffto the total charges under that rate schedule during the preceding month; (2) the proportion of the eapital costs allocated to Schedule 2 under Attachment A actually incurred by the ISO during the preceding month equaling the proportion of the Participant's charges under Schedule 2 of the Tariffto the total charges under that rate schedule during the preceding month; and (3) the proportion of the capital costs allocated to Schedule 3 under Attachment A actually incurred by the ISO during the preceding month equaling the proportion of the Participant's charges under Schedule 3 of the Tariffto the total charges to all Participants under that rate schedule during the preceding month. t4 The nature of each of the Services is describedgenerallyin the Commission's December30, 1999order with respectto the 2000 Tariff. See ISO New England Inc., 89 FERC¶ 61,339 at 62,017 (1999). 15The testimonyof Mr. CrazyW. Pire (Exhibit3 hereto) explainshow the allocationof the capital expendituresfor the 2004 Itemslisted in AttachmentA to each rate schedule vats determined. Becausethe 2000, 2001, 2002 and 2003 items have alreadybeen acquired throughthird-patty financing,they ate not subject to the CFC mechanism. 7 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 For example, if the Schedule 2 capital costs and the Schedule 3 capital costs incurred in the preceding month are $500,000 each, and the Participant's share oftotal charges to Participants under Schedule 2 for March was 5%, and the Participant's share of total charges under Schedule 3 for March was 3%, the Participant's CFC that month would equal (for Schedule 2) $500,000 x .05 or $25,000, plus (for Schedule 3) $500,000 x .03 or $15,000, for a total CFC o f $40,000. 2. The EAC rate design In the event of early termination or required accelerated repayment of financing that has been entered into by the ISO in support of the items listed in Attachment A (including any additional financing entered into by the ISO during 2004), and if no replacement financing has been obtained by the ISO, an EAC will be billed to, and paid by, each Participant. The ISO shall provide electronic notice (no less than thirty (30) business days in advance o f the date payment is due to the ISO's lenders) to each Participant of the aggregate amount of the unamortized costs of the financed assets (the "EA Amount"), and the portion of the EA Amount assigned by the ISO to each of the Schedules (the "Announced Schedule 1 EA Amount," the "Announced Schedule 2 EA Amount," and the "Announced Schedule 3 EA Amount," respectively). The EA Amount will be assigned to each oftha Schedules in proportion to the total respective value of capital items (funded through the date o f early termination using the financing) allocated to each o f the Schedules under Attachment A. In each such circumstance, the ISO will, immediately after giving the notice described above, bill each Participant and each Participant will pay, as its EAC: (1) the proportion o f the Announced Schedule 1 EA Amount equaling the proportion of the Participant's charges under Schedule 1 o f the Tariffto the total charges to all Participants under that rate schedule during the month previous to the month in which the forgoing notice has been given; (2) the proportion of the Announced Schedule 2 EA Amount equaling the proportion of the Participant's charges under Schedule 2 ofthe Tariffto the total charges to all Participants under that rate schedule during the month previous to the month in which the foregoing notice has been given; and (3) the proportion of the Announced Schedule 3 EA Amount equaling the proportion of the Participant's charges under Schedule 3 of the Tariff to the total charges to all Participants under that rate schedule during the month previous to the month in which the foregoing notice has been given. For example, ifthe Announced Schedule 2 EA Amount and the Announced Schedule 3 EA Amount in April are $500,000 each, and the Participant's share of total charges to Participants under Schedule 2 for March was 5%, and the Participant's share of total charges under Schedule 3 for March was 3%, the Participant's EAC would equal (for Schedule 2) $500,000 x .05 or $25,000, plus (for Schedule 3) $500,000 x .03 or $15,000, for a total EAC of $4O,0O0. 3. The EAWCC rate design In the event of early termination or required accelerated repayment o f financing that has been entered into by the ISO in support of the ISO's working capital requirements, and if no replacement financing has been obtained by the ISO, an EAWCC will be billed to, and paid by, each Participant. The ISO shall provide electronic notice (no less than thirty (30) business days Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 in advance o f the date payment is due to the ISO's lenders) to each Participant of the aggregate amount of the Working Capital Amount (the "EAWW Amount"). In each such circumstance, the ISO shall immediately hill each Participant and each Participant shall pay, as its EAWWC, the proportion of the EAWW Amount equaling the proportion of the Participant's charges under the Tariffto the total charges to all Participants under the Tariffduring the month previous to the month in which notice has been given. For example, if notice is given in April that the EAWW Amount is $1,000,000 and the Participant's share of total charges under all three Schedules for March was 4% of all charges to all Participants, the Participant would be charged a EAWCC of $1,000,000 x .04 or $40,000. 11. Documents Submitted With This Filing The following documents are submitted with this filing: Exhibit 1 Exhibit 2 Exhibit 3 Exhibit 4 Exhibit 5 Exhibit 6 The Revised Sheets Blacklined versions ofthe Revised Sheets, showing changes from the corresponding sheets currently in effect Prepared testimony of Gary W. Pire Lists of Participants, New England Governors, New England electric regulatory agencies, and other New England regional bodies Table showing cross-references for Statements AA-BM data 16 Notice o f Filing (diskette enclosed). 16 The cost support data supplied in this filing (in the exh~it to the testimony of Mr. Gary W. Pire (Exh~its3)) does not sU'iclly take the form of Statements AA through BM (as specified in Section 35.13(h) of the Commission's Rules). The cost support data provided through the testimony and its detailed exhibits are designed to provide a full understanding of the derivation and basis for the costs and rates collected through the CFT and the Revised Sheets, and the same level of data -- pertinent to a utility such as the ISO - as is contained in Statements AA through BM. Statements AA through BM ate, by their nature, intended and des,gned for utilities that own conventional generation and unosmission assets, and that seek a rate of returo on rate base. As such, most o f the statements would not be applicable to the ISO in any event. Also, the cost support data submitted herewith are based on projected, budgeted costs, and therefore do not correlate with the temporal approach of those Statements. For these reasons, the ISO requests waiver (as previously granted via the Commission's initial acceptance of the CFT) &Section 35.13 of the Commission's Rules, to the extent necessary, to permit the acceptance of the cost support data and other information of the type and in the form contained in this fding letter in lieu of the data and forrnat otherwtse required in Sections 35.13(d), (e) and (h). The infommtion required by Sections 35.13(b) and (c) is included at the end of this letter. For the Commission's convenience, and as in prior filings, a cross-reference table is attached as Exhibit 5; this table shows the location in this filing of applicable information addressed in Statements AA through BM. 9 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 IlL The 2004 Capital Budget, and the Allocation Therenf~ Reflected in the Revised Sheets This section of the filing letter discusses the development of the ISO's 2004 capital budget, and describes the 2004 Items, their justification and how they are reflected in CFT Attachment A, as modified by the Revised Sheets. The attached testimony of Gary W. Pire, the ISO's Witness (Exhibit 3 hereto) addresses these topics. This section of the filing letter also describes and justifies the allocation of the 2004 Items in Attachment A, as modified by the Revised Sheets. A. The ISO's 2004 Capital Budget, Its Elements, and Their Justification The ISO's senior management, working with managers throughout the company, prepares a capital budget in advance of each calendar year that responds to the critical needs of the ISO for the upcoming year. The ISO's Senior Executives, including the Chief Financial Officer, and staff, present drafts ofthe capital budget to the NEPOOL Budget and Finance Committee and invite input from NEPOOL Participants. The NEPOOL Participants Committee passed a resolution on September 5, 2003 nearly unanimously approving the ISO's 2004 capital budget, t7 Following receipt of this input, the ISO's Board of Directors reviewed and approved the 2004 capital budget at its September 18, 2003 meeting. Previously, in April 2003, the NEPOOL Participants Committee unanimously approved an extension ofthe Interim ISO Agreement through December 31, 2004, and the Commission approved that extension on September 29, 2003. The ISO's capital budget for 2004 totals approximately $17.6 million, a reduction from last year's capital budget (which was approximately $19.2 million) of approximately eight percent. This reduction reflects decreased spending on capital projects. The 2004 Items (i.e., the elements of the 2004 capital budget) are listed in the following table, and discussed in greater detail below. Capital Purchases Facilities Sullivan Road Improvements including security enhancements Halon Fire Suppression System for Control Room Information Technology Hardware/Software Upgrades Toml Capital Projects $ Cost 528 $ 1,600 $ 2,128 17Onlyone NEPOOLParticipantopposedthe resolution. 10 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Enhancements to SMD 1.0 (Including Locational ICAP Design and modifications to software; Co-Optimized Reserves, etc...) ($8.0 million), and enhancements to other existing hardware and soRware systems (including automation of customer and asset data, upgrade to Oracle software, ISO website redesign, etc...) ($4.9 million) Capitalization of Internal Software Development (for all capital projects) $ $ 12,888 2,534 Total Capital Project Expenditures $ 17,550 The largest single capital expenditure is for enhancements to SMD 1.0 ($8.0 million). The Commission and market participants have encouraged the ISO to move forward on further development of certain key improvements to the New England wholesale electricity market. As part of the development ofthe New England wholesale electricity market, the ISO intends to follow a semi-annual release process to notify Participants o f further market upgrade initiatives. |s A predictable process for releasing market enhancements helps maintain market stability, lower risks for market participants and, thereby, lower overall costs by reducing risk premiums) 9 For calendar year 2004, two SMD 1.0 market enhancements warrant comment: (a) Locational ICAP Design CLICAP'); and (b) Co-Optimized Reserves. • Development o f L o c a t i o n a l I C A P ( ~ L I C A P ' ) Markets In several Orders,2° the Commission has directed the ISO to file proposed market rules for a LICAP market (or a deliverability mechanism) by March 31, 2004 for implementation no later than June 1, 2004. LICAP will help send appropriate price signals for the location of generation capacity and address reliability concerns within the New England Conla'ol Area. lg In addition, persnant to the requirements oftho Commission's Order in ISO New England Inc., 100 FERC ¶ 61,130 (2002) (the "July 31 Order"), the [SO posts on its website (www, i,~-ne,com) more detailed cost breakouts for the SMD 1.0 project, updated on a quarterly basis. 19 To reflect the multi-year nature of the enhancements m SMD 1.0, the Revised Sheets also include an addition to Section 8.1 of the CFT: a description ofthe projects, and the projected capital spending by year. The ISO is not, however,seekingfundingof projectedcapital spendingin these futureyears. The projected capital spending in future yearsis providedfor informational~ only, and to assistParticlpantdecisionmakingon futureand ongoing enhancementsto the wholesalemarketdesign. 2oSee, e.g., New England Power Pool and ISO New England Inc., 100 FERC161,287 at P 101 (2002); Devon Power, LLC, etal., 103 FERC¶ 61,082 at P 37 (2003); New England Power Pool and lSO New England lnc., 103 FERC ¶ 61,304 at P 75 (2003). 11 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 The objective in 2004 is to develop market rules, business processes, and software to implement LICAP, by June 1, 2004, as ordered by the Commission. • Development of Co-Optimized Energy and Reserve Markets A second wholesale market enhancement slated to occur in calendar year 2004 is the implementation of co-optimized energy and reserve markets. The ISO currently does not have market mechanisms for paying generators who supply operating reserves. There is no direct market signal indicating the need for resources that start up quickly and provide energy in a short period. Since New England does not have a surplus of fast-start resources, the absence o f such a market signal is significant. To address this issue, the ISO (and NEPOOL) have recently proposed a forward market for reserves and the ISO is working to develop and implement cooptimized energy and reserve markets. These markets are significant enhancements that will help ensure that generators are properly compensated for providing operating reserves, and that energy and reserve requirements are satisfied at the least possible cost. • Other 2004 Items The remaining 2004 Items include: Enhancements to information software to improve ISO functionality and customer service (including automation o f customer and asset data; upgrade to Oracle software; ISO website redesign) (approx. $4.9 million) • Improvements (including security and fire suppression equipmen0 to the ISO's Sullivan Road site (which includes the ISO's control room) (approx. $528,000); Information technology and software enhancements to existing systems, including Scheduling and Planning software, control room hardware, networks and servers ($1.6 million); and • Capitalization of labor costs associated with internally developed software for the various systems at the ISO (approx $2.5 million) as required by accounting standards. The nature o f the enhancements to SMD 1.0 and their estimated costs has been discussed with NEPOOL Participants. Any reduction in the cost estimates will not be dedicated to new, or other, projects without express authority from the Board of Directors and discussion with NEPOOL Participants. 2j 21 The ISO reserves the fight to make additional Section 204 and 205 filings should increased capital spending be required. Due to the Market Participants' desire that enhancements to the New England wholesale markets proceed with deh~a'ate speed and to ease future review of continued enhancements, the ISO prepared a 2004-2005 12 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 B. H o w the 2004 Items are Reflected in the Revised Sheets Capital expenses incurred by the ISO after January 1, 2000 are considered LRE under Section 19.3 of the RNA (as amended in the 66 m Agreement) and were funded each month, on an as-incurred basis, by the NEPOOL Participants in a proportion to their charges under the ISO Tariff for the previous month. In anticipation of the ISO arranging third-party financing of some or all of the capital budge4 NEPOOL filed with the Commission on November 15, 2000, the Sixty-Eighth Agreement Amending the RNA (the "68 th Agreement"). The 68 th Agreement provides a mechanism for the collection, amortization and repayment o f the LRE. Capital funding is currently structured with the expectation that a third party lender will fund the Capital Budget in the year 2004 with certain repayments to commence in 2005. Revenue reserved for the depreciation in 2004 of capital assets will be used to repay the lender in 2005 and beyond. The ISO obtained outside financing from third party lenders beginning in June 2001. Pursuant to 19.3(d) ofthe RNA, the LRE incurred on or aller January 1, 2001 will be allocated, on an as-incurred basis, to the three ISO Tariff Schedules, employing the same allocation methodology in effect pursuant to the ISO's Capital Funding Tariff. The aggregate LRE in any calendar year are amortized when placed in service on a straight-line basis over their useful life. The ISO obtains cash for the repayment of principal through depreciation and amortization of the capital assets through the tariff schedules. This necessitates that the repayment period corresponds with the appropriate recovery period (the depreciation/amortization period) for the capital asset under generally accepted accounting principles. In the Revised Sheets, the 2004 Items have been added to the existing capital expenditures for 2000, 2001, 2002 and 2003 listed in Attachment A to the CFT. They have also been allocated to the three Services provided by the ISO, as reflected in the three rate schedules of the ACT. The manner in which the 2004 Items have been allocated is described in Section III.B., below. As noted at the outset, the CFT specifies three contingent charges, the CFC, the EAC, and the EAWCC. The addition - through the Revised Sheets - ofthe 2003 Items to CFT Attachment A has an impact only on the level of the contingent CFC and EAC. With respect to the CFC, the 2004 Items reflected in the Revised Sheets would be funded by the ISO's customers directly (through the CFC) only if the ISO is unable to borrow the funds necessary to acquire the additional capital items. Stated another way, if the ISO cannot obtain financing in advance of the time at which it needs to acquire the 2004 Items not otherwise funded under existing approved borrowing, each ISO customer would pay a CFC (calculated in (...con~ucd) Wholesale Market Plan, which has been the subject of stakeholder comment. The Wholesale Market Plan descnbes the rmjor initiatives that are currently planned over the next two years to enhance the New England markets. 13 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 the manner described in Section 2.A. of the CFT), to fund the capital costs actually incurred by the ISO during the preceding month on account of the 2004 Items. However, as noted above, the ISO is attempting to obtain the necessary additional financing for the 2004 Items. The level of the contingent EAC is also affected by the Revised Sheets as follows. The EAC "revenue requirement" is collected only in the event of early termination or required accelerated repayment o f amounts borrowed by the ISO to support its need for capital assets, and would consist of the unamoW|zed costs of the financed capital assets. The EAC revenue requirement will remain zero, even aRer acceptance of the Revised Sheets, if the ISO increases its borrowings to acquire the 2004 Items and no early termination or acceleration (including any required prepayment) o f the corresponding financing actnallyoccurs, lf early termination or acceleration (including any required prepayment) of that financing occurred, the ISO's customers would pay EACs relating to the capital expenses in Attachment A calculated in the manner described in Section 2.B. of the CFT. The EAC revenue requirement (even in the event of early termination or acceleration of all existing financing) is not open-ended: the unamortized costs of the Capital Assets will not exceed the sum of the capita] items reflected in Attachment A. The amount of the ISO's longterm borrowings is also constrained by the requirement for Commission approval ofthese borrowings under Section 204 ofthe Federal Power Act. C. The Allocation of the Elements of the 2004 Capital Budget Reflected in the Revised Sheets As noted, the rate design for the charges collected in the CFT relies on the three-Service structure ofthe ACT. Each ofthe 2004 items has been allocated to the three rate schedules consistent with the allocation of similar cost components in the cost o f service. Exhibit 3, Schedule 1 contains a Test Year 2004 cost o f service for each o f the three rate schedules included in the ACT. The exhibit lays out in detail how ISO costs were assigned to the three schedules in support of the ISO's ACT for 2004. In assessing how costs should be assigned to the various categories of service that the ISO provides to its customers, the objective was to reflect cost causation principles as much as possible. A substantial amount o f time was spent interviewing smffwithin each departmen4 discussing the various tasks and activities and discussing the availability of data that measure the cost drivers for those activities. As part of the interview process, ISO staffprovided substantial insight and direction and in many cases specific data that was used to develop the "Alloc-Fixed" cost allocators. An allocator descriptor that is defined as "Alloc-Fixed" means that a specific percentage was developed by the ISO staffand used to directly allocate costs for that line item. Most Activity costs consist ofdirect labor costs, employee benefits, and other non laborrelated costs (i.e. office supplies, soRware, hardware, depreciation, interest, etc.). For each Activity Code, both the labor-related and non labor-related costs are assigned to the rate schedule using the same allocator. The percentage allocators used to allocate activity costs are summarized in Exhibit 3. 14 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 D. The Allocation of the Late Restructuring Expense The LRE are presented in Exhibit 3, Schedule 6. The costs are basically the debt service component associated with LRE, and they are collected through the ACT, rather than the Capital Funding Tariff. The costs included (and allocated) on page 2 of Schedule 6 of Exhibit 3 are the capital costs for 2000- 2004. Many of theso items were funded by the NEPOOL Participants pursuant to the provisions o f the RNA, as specified in the testimony o f Mr. Gary W. Pire in Exhibit 3, Schedule 6 ofthe accompanying filing letter. The allocations of LRE capital costs that may be collected through the "Capital Funding Charge" under the CFT are based on the 2004 Cost of Service Study which supports the ISO's ACT for 2004. The major LRE cost component is "debt service." In this context, there are two major components o f LRE "debt service." The first major component is depreciation (representing an amortization) expense in the amount of $39.5 million (see Exhibit 3, Schedule 3). The second major component is interest expense in the amount of $4.9 million (See Exhibit 3, Schedule 3). These amounts are being collected under the revisions to the ACT also being filed by the ISO today. The testimony of Mr. Gary W. Pire provides detailed information pertaining to the individual LRE components. These LRE components are the elements of the 2000, 2001, 2002, 2003 and 2004 capital budgets of the ISO. Each component of the LRE has been allocated to the three rate schedules consistent with other similar cost components' allocations in the cost of service. For instance, the LRE item called "Building/property improv. (Renov. workspace, network & voice rewiring)" was allocated 21.55%, 51.75% and 26.70% to Schedules 1, 2 and 3, respectively, according to total company labor factors specific to that item. Another LRE item termed "Various hardware and software upgrades for existing systems" was allocated in proportion to a fixed allocation factor. LRE interest expense was allocated to the three rate schedules in the same proportion as the LRE capital items for 2000-2004. Once the LRE capital costs were allocated to the three rate schedules, the allocated components were summed for each rate schedule and in total. The LRE interest expense was allocated in proportion to the total LRE capital costs for 2000-2004 allocated to each rate schedule. E. Cost Estimates for 2004 Capital Items that are Multi-Year Projects The ISO implements a number of measures to ensure appropriate accountability o f its capital expenditures, including putting into place procedures to ensure frequent monitoring of capital accruals against amounts included in the CFT funding mechanism. In addition, and beginning last year, the ISO also commits to including, for informational purposes, multi-year capital projects, including estimated capital spending for each year of those projects. This provides the Commission and Participants with additional estimations o f the ISO's future plans and longer-term impacts of projects requiring capital expenses. In this year's CFT filing, there are three categories 0f2004 Capital Items that are multi-year projects. Cost estimates o f 2005 capital expenditures o f these projects is provided below. The three categories are: (1) Information Services; (2) Market Enhancements; and (3) Operational Efficiencies. 15 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 2004 Multi-Year Capital Expenditures Information Services (comprised of enhancement to data archive and restoration capability; ISO website redesign) Market Enhancements (comprised o f development of CoOptimized Reserves, Virtual Regional Dispatch and System Improvement Requests)n Operational Efficiencies (comprised of upgrades to Oracle 2005 Cost Estimates $3.4 million $8.5 million $.08 million software) These cost estimates are provided for informational purposes. The ISO is not seeking capital funding o f these estimated costs in this filing. These cost estimates may change before the 2005 CFT filing, and the ISO expects that there will be additional Capital Items in the 2005 CFT filing. IV. Information Required by Part 35 (1) Section 35.13(b)(1): See Section II above for documents submitted with this filing. (2) 1, 2004. (3) Section 35.13(b)(2): The ISO requests that the Revised Sheets be allowed to go into effect on January Section 35.13(b)(3): The ISO is today mailing a copy of this transmittal letter to: (1) each current Transmission Customer under the NEPOOL Tariffthat is not a Participant; and (2) the Governors and electric regulatory agencies of e,ach o f the States (as well as NECPUC and other regional organizations) located within the NEPOOL Control Area (the "Recipients"). Included with these mailings is a notice referring recipients to the ISO's website (where all of the documents included with this filing will be posted) and offering Recipients a hard copy of the filing upon request to the ISO. In addition, the NEPOOL Participants are being provided electronic copies today o f the entire filing, via e-mail, through the Secretary o f the NPC. Because this method of notice is superior in quality to, and more expedited than, the mail-based Vh"tualRegionalD,spatchand SystemImprovementRequestsare hsted as multi-year"projects,because dependingon the developmentof these enhancementsto the New Englandwholesaleelectricitymarket,there is the poss~ility that they will requireminimalcapitalexpendituresat the end of 2004. 22 . . . . ~ • 16 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 "posting" requirement of 18 C.F.R. § 35.2(d), the ISO hereby requests waiver of that requirement. The Recipients (and the NEPOOL Participants) are listed in Exhibit 4 hereto. (4) Section 35.13(b)(4) & (5): See discussion in filing letter for description of rate change and the reason therefor. (5) Section 35.13('o)(6): Not applicable. The ISO Board of Directors has approved the ISO's 2004 capital budget. (6) Section 35.13('o)(7): No expenses or costs to be included in the cost o f service have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative or unnecessary costs that are demonstrably the product of discriminatory employment practices. (7) Section 35.13('o)(8): A form of notice is submitted herewith. (8) Section 35.13(c)(1): Sales, services, and revenues cannot reasonably be projected at this time. (9) Section 35.13(c)(2): The ISO has no other rates for similar services. (10) Section 35.13(c)(3): No specifically assignable facilities axe at issue. (11) Section 35.13(h): Exhibit 5 provides cross-references to data required in Statements AA-BM. 17 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 V. Communications Correspondence and other communications regarding this filing should be directed to: Kathlcen A. Carrigan Sr. Vice President,General Counsel & Corporate Secretary ISO N e w England Inc. One SullivanRoad Holyoke, M A 01040-2841 Phone: 413-535-4000 c-mail: kcarrigan@iso-nc.com and Howard H. Shaffcrman Ballard Spahr Andrews & Ingersoll,LLP 601 13th Street, N.W. Suite 1000 South Washinglon, DC 20005 Phone: 202-(~1-2205 c-mail: hhs(~,ballardspahr.com. 18 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 VI. Conclusion For the reasons discussed herein, the ISO requests the Commission to accept the Revised Sheets for filing, effective January 1, 2004. Please ask your staffto date-stamp the extra copy of this letter and return it to the messenger making this filing. Very ~ltly yours, Robert C. Ludlow Vice President and Chief Financial Officer ISO New England Inc. 19 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Commonwealth o f Massachusetts County of Hamlxlen ) ) ss: ) I am the Vice President and Chief Financial Officer of ISO New England Inc. To the best of my knowledge, information and belief, the cost of service statements and supporting data submitted with this filing are true, accurate, and current representations of the books budgets, or other corporate documents of ISO New England Inc. Robert C. Ludlow Subseribed and sworn to before me, t h i s , ~ ~ day of October, 2003 DC DOCS A # 1 1 2 1 ~ v2 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 1 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 ISO New England Inc. FERC Electric Tariff, Volume No. 2 Capital FundingTariff Second Revised Sheet No. 23 Superseding 1'*Revised Sheet No. 23 determined by the arbitrator but will not be conclusive as to the law or constitute precedent on issues of law in any subsequent regulatory or legal proceedings. An Aggrieved Party m a y initiate a proceeding with a court or with the Commission with respect to the arbitration or arbitrator's decision only: if the arbitration process does not result in a decision within the time period specified and the proceeding is initiated within thirty days a_~er the expiration of such time period; or • on the groundsspecified in Sections 10 and 11 ofTitle 9 of the United States Code for judicial vacation or modification o f a n arbitration award and the proceeding is initiated within thirty days o f the issuance o f the arbitrator's decision. 8.1 Long-Range Capital Planning: The ISO is contemplating the following multiyear capital projects: Issuedby: Issued on: Robert C. Ludlow Vice President and Chief FinancialO/~cer October 3 I, 2003 Effective Date: January 1, 2004 Inofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 ISO New England Inc. FERC Electric Tariff, Volume No. 2 Capital Funding Tariff Original Sheet No. 23A 2005 Cost Estimates of 2004 Multi-Year Capital Projects: Information Services Projects (e.g., Data Archiving and Restoration, ISO Web Site Re-design) Enhancements to Current Market Systems (SMD) Co-Optimized Reserves Virtual Regional Dispatch SIRs Total Enhancements to Current Market Systems (SMD) Operational Efficiency Projects (e.g., Oracle Upgrade) $ 3,400,000 6,~0,0~ 2,~0,000 ~0,0~ 8,500,000 80,000 Total 2005 Cost Estimates of 2004 Multi-Yosr Capital Projects $11,980,000 Issued by: Issued on: Robert C. Ludlow Vice President and Chief Financial Officer October 3 I, 2003 Effective Date: January I, 2004 ISO New England Inc. FERC Elecuic Tariff, Volume No. 2 Capital Funding Tariff ATTACHMENT A LATE RESTRUCTURING CAPITAL COSTS AND THEIR ALLOCATION Une Fourth Revised Sheet No. 24 Superseding Third Revised Sheet No. 24 (3 k.a r~ C3 I No. 1 2 3 4 Code 2004 Itm'n~: I)~¢rlptton (=) I Total (b) /~11. (c) Adj. Total (d) I F,.=or0) (e) Total Dir f0 fo 12651 6529 6529 6529 6529 6529 12651 Bulld0~/pcoperty ~ . (Renov.wod~pace,netwo~& vo~e mwlrf~g) $ 527,700 8,000,000 4,887)800 12,887,800 1,600,000 2,534,500 S 527,700 8,000.000 4,887,800 12,887,800 1,600,000 2,534,500 Labor Nk~c-Fb¢~:~ Allot-Fixed Allot-Fixed Total D~r Labor 0 t~ Q Q Hardware and Soh'w~e upgrades for Exis~ng Market systm~ Mad~t System Enhancements - SlVlD Enhancements to O~ler Ex~t~g Madult Systems Total Herdv~ue and Software upgrades foe E~dsting Madmt systems Hat[P~rare and Software Upgrad~ to FJdstlng Non Market SysWns Internal De~lopment Costs 5 6 7 8 9 Q I Q Q Q 10 11 12 13 14 15 Total 2004 Ite.~ - S .% 2000, 2001. 2002 and 2003 films - $ $ 17.550.000 $ $ 17,550,000 fo fl fo fo 2003 Filing for 2003 Total 2003 Filing for 2003 CMS/MSS (or SldD) 2002 Sul:C~mental Fling For 2002 For ~ (or SMD) 2002 S u l ~ e n t a l Fling For 2002 For CMS/MSS (or SMD) 2002 Supl~e~ental Filing For 2002 For CMS/MSS (or SMD) 2002 Filing For 2002 Fo~ CMS/MSS (o¢ SMD) 2002 Filing For 2002 For CMS/MSS (or SMO) 2002 Filing For 2002 Foe CMS/MSS (or SMO) 2002 Filing For 2002 For Other 2001 Filing for 2001 To~d 2001 Fling for 2000 Total Total 2000. 2001. 2002 and 2003 LRC Cost items -% $ 26,437,000 (7,257,0~0) 24,500.000 (24.500.000) 24.500,000 34.104.300 (34.104.300) 34.104.300 6,709.300 19,038,900 23)284,300 $ S 26,437.000 (7257,000) 24,500.000 (24.500.000) 24.500.000 34.104.300 (34.104.300) 34.104.300 6.709,300 19,038,900 23,284,300 .aJIoc-Flxed /U~o~-Fasd Nloc-Flxed AJloc-Rxed AJIoc-Ftxed AJIoc.4=lxad AJIoc-Flxed AJIoc-FIxl~ AJloc-Flxed Allot-Fixed Nloc-Fixad 0 fl fo M 16 17 18 19 20 21 22 23 24 25 26 27 28 29 3O 0 M Q t~ Q Q S 126,816.800 S $ 126,816.800 Late Rest~ctudng Cal~ta] Costs (2000, 2001. 2002, and 2003 Items) -$ (LRC Capltzd) $ 144.3456.800 $ $ 144,386,800 M O a=. I k.a w Cos= and 2oo3 tLRC I Effective Date: January I, 2004 DC_DOCS_A~ 085211 v2 Issued by: Issued on: Robert C. Ludlow Vice President and Chief Financial Officez October 31, 2003 ISO New England Inc. FERC Eleclxic Tariff, Volume No. 2 Capital Funding Tariff Self-Fundlr~ Tlrlff Fourth Revised Sheet No. 25 Superseding Third Revised Sheet No. 25 (3 t--' r~ Code De~Utl~on (a) 2004 Irene: Bulldln~lxopedy Imwov. (Retry. workspace, ne(wo~ & voice rewlrlo0) Hardware and Software upgrades for F.xJs~ Market sy~ems Market System E n h ~ t s - SMD Enhancements to Other Exts~g Market Systems Total Hardwa~a and So(twain Ul:)gcadesfor Ex~stlpg Mad(et systems Hardware and Software U p ~ to Ex~Ung No~ Madmt Sy~sms Inten~d DevelownentCo~s $ Total (f) Schedule I Schedule 2 3 [ P) (g) 113.719 $ (h) 273.0~5 $ 5,240.000 3~01,509 8,441.509 1,048.000 - - - - O, ,o on 03 I I ~0 12651 6529 6529 6529 6529 6529 12651 527,700 $ 8.000,000 4~887,800 12,887.800 1,600,000 2,534.500 f'r 63, 2,760.000 1,6061291 4.446.291 552,000 676,734 SW O e ~ e W w ~ - F.mmo ~ systm PU SW n v v ~ p m m . F.m~O u a r u . S y m ~ O t~ Q Q 546,135 1.311,632 Q Total 2 0 0 4 Items - $ $ 17.550.000 $ 100.00% 8.~,854 $ 3.76% 11,074,225 $ 63.10% 5,815,~21 33.14% .% 2000, 2001. 2002 a n d 2003 I t ~ r m - $ Q Q Q I 2003 F ~ foe 2003 Tot~ 2003 Firing for 2003 CMS/MSS ((x SMD) 2002 S u p ~ t a l Ring For 2002 For CMS~MSS (or SMD) 2002 Supplemental Filing For 2002 F~" CMS/MSS (or SMD) 2002 Sup~emental Filing For 2002 For ~ (o¢ SMD) 2002 Fi~ng For 2002 Foe CMS~MSS ((x SMD) 2002 Firing Fo~ 2002 For CMS/I~SS (or SMD) 2002 ~ For 2002 For CMS~tSS (or SMD) 2002 F~ng For 2002 For Otto" 2001 ~ for 2001 Total 2001 FEng kx 2000 Total T(Xat 2000, 2001. 2002 and 2003 LRC Cost Itoms -% 26.437.000 $ (7.257.ooo) 24.500.000 {24.500,000) 24.500,000 34.104,300 (34.104,300) 34,104,300 6.709,300 19,038.900 23)284,300 738.743 $ 912,594 (912,594) 818.503 (818.503) 978,489 784,173 1~3g0~853 21.865.149 $ (e.~31.3~0) 18,647.971 (18,647.971) 22.050.000 27.351.649 (27,351,649) 30.6~3.870 3,687,564 14.:330@231 16~036)240 3.833.108 h ~ d On Am~MO'I In C~ck/NO+ E~R03-147~00 (3) (72~.700) BaNdOnAkx:aaor~I~OocklltNO.E1~03-14~00(3) 4,939,435 h~d OnN ~ m (4,939,435) 2.450.000 In Oad~No.ES~.49-C~0(3) fo fl fo fo M 5.934,148 h i n d ~ , t a ~ m ~ In D ( x ~ ( NO. B~)-24g-O~O f3) (5,934.148) Oelild~ )qJiQ(:li~<]~ D(~;kli()e).Elt~0Q-24S*-OOO In {3) 3,410.430 C ~ A I O ~ Pq~t80 ~glln 2,043,247 e~m~l On AIIo~tons In I~dm~ No+ER~Q-249~00 (3) 3,924.496 5,857)207 0 M Q 126,816.800 $ 3,892.258 $ 102,131.754 $ 20.792.788 100.00% 3.07% 80.53% 16.40% t~ Q Q Late Restn~tudng Cap~U Coe~ (2000. 2001. 2002. ~,~ 2003 ~ ) (LRCCap~t~) 4 $ 144.366,800 $ 4,552,112 $ 113,205.979 $ 26,608.709 100.00% 3.15% 0 fl fo c~ co.= (2ooo OOl,2OOZ and 2oo3 . m ) F . c c.l, I 78.42% 18.43% Issued by:. Issued on: Robert C. Ludlow Vice President and Chief Financial Officer October 31, 2003 Effective Date: January 1, 2004 DC_DOCS_A #1085211 v2 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 ISO N e w England Inc. FERC ElectricTariff, Volume No. 2 CapitalFunding Tariff First Revised Sheet No. 27 Supersedin Original Sheet No. 27 8 Cb) a consumer of electricity in the NEPOOL Control Area that generates or purchases electricity primarily for its own consumption or a non-profit group representing such consumers. N E P O O L Participants Committee: The committee established pursuant to Section 7 o f the NEPOOL Agreement. N E P O O L Transmission System: The system of transmission facilities within the NEPOOL Control Area under the ISO's operational jurisdiction. A Participant is an eligible Entity (or group o f Entities which has elected to be treated as a single Participant) which is a signatory to the NEPOOL Agreement and has become a Participant in accordance therewith until such time as such Entity's status as a Participant terminates in accordance therewith. Transmission Customer: Any Eligible Customer that (i) is a Participant which is not required to sign a Transmission Service Agreement with respect to a service to be furnished to it in accordance with Section 48 of the NEPOOL Tariff, or (ii) executes, on its own behalf or through its Designated Agent, a Transmission Service Agreement, or (iii) requests in writing, on its own behalf or through its Designated Agent, that NEPOOL file with the Commission, a proposed unexecuted Transmission Service Agreement in order that the Eligible Customer may receive transmission service under the NEPOOL Tariff. This term is used in Part I o f the NEPOOL Tariff to include customers receiving transmission service under the NEPOOL Tariff. Transmission Provider: The Participants, collectively, which own PTF and are in the business ofproviding transmission service or provide service under a local open access transmission tariff, or in the case o f a state or municipal or cooperatively-owned Participant, would be required to do so if requested pursuant to the reciprocity requirements specified in the NEPOOL Tariff, or an individual such Participant, whichever is appropriate. Participant: Issuedby: Issued on: Robert C. Ludlow Vice Presidentand Chief FinancialOfficer October 3 I, 2003 Effective Date: January 1, 2004 OC_DOCS_A#1064478v9 WORD97 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 2 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 ISO New EnglandInc. FERC Electric Tariff, Volume No. 2 Capital FundingTariff Secon~W*'Revised Sheet No. 23 Supcr~ting I ~ Revised Sheet 30..23 determined by the arbitrator but will not be conclusive as to the law or constitute precedent on issues o f law in any subsequent regulatory or legal proceedings. An Aggrieved Party m a y initiate a proceeding with a court or with the Commission with respect to the arbitration or arbitrator's decision only:. if the arbitration process does not result in a decision within the time period ~ecified and the proceeding is initiated within thirty days after the expiration o f such time period; or • on the grounds specified in Sections I 0 and 11 of Title 9 o f the United States Code for judicial vacation or modification o f an arbitration award and the proceeding is initiated within thirty days o f the issuance of the arbitrator's decision. 8.1 Long-Range Capital Planning: The ISO is contemplating the following multiyear capital projects: Issuedby: Issued on: Robert C. Ludlow Vice President and Chief FinancialOfficer ~vember~Octob~r 31,200,33 EffectiveDate: January I, 200~_ Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 1SO Ncv~ England In(;. FERC Electric Tarifl~ Vqlcm# No. 2 (.'apital Fundin, g . ~ ir.~ Original S h ~ Nq:_223A 2005 Cost Estimates of 2004 Multi-Year Capital Projects: Information Services Projects (e..q., Data Archivinq and Restoration, ISO Web Site Re-desipln) Enhancements to Current Market Systems (SMD) Co-Optimized Reserves Virtual Reqional Dispatch SIRs Total Enhancements to Current Market Systems (SMD) Operational Efficiency Prelects (e..q., Oracle Upgrade) $ 3,400,000 6,000,000 2,000,000 500,000 8,500,000 80,000 Total 2005 Cost Estimates of 2004 Multi-Year Capital Projects ~; 1119801000 lss~_b~,.-_...____~obe~l C. Ludlow Vice Pr~idcpl and Chief Financial Offi~;~r Iss__3t~~,: . . . . . October 31,200,3 Efl~cdve D~.W; J ~ W 1,200~ lSO New England Inc. FERC Electric Tariff, Volume No. 2 Capital Funding Tariff ATTACHMENT A LATE RESTRUCTURING CAPITAL COSTS AND THEIR ALLOCATION P~ Activity DucdDtlon I TJ~IJ Caldtal C o I t i AdL F o . ~ g t ~ Revised Sheet No. 24 Superseding ~dThird Revised Sheet No. 24 o )==, M )o I AdL To~ll I Fm=~1) ill Tot=~ ~bor o (=.r ro /11 1 rl)) rew~na) S ~7.7~ 8.000.000 4.887.800 J Ira ~ll ~2.200 2004 ~ = : 12651 Buildln~/Drooedv {mB'o~. {Renov. wo'k3oao~, netwod~ & ~ Hardware and Software uDonades for F.x~stinoMadmt systems Market System Enhancement~ - SMD Enhancements ~o Other Existirm Market Sv.stems Total Hardware and Software uoorades fo~ ExJsUno Market swdems Hardware and Software Lk3orades to Exlstina Na~ Market S v s ~ n s Z s.ooo.ooo 4.887.800 12.887.800 AJIoc-Fixed ~oc-Flxed lZ~7.S00 1.600.000 t~ o o Z 1.600.000 TomJ ~ r 2.534.500 o I o o o IO 11 12 Total 2004 Items - S "~ 1r 5.m.ooo $ 17.550.000 F0 fl F0 < F0 2000. 2001.2g02 and 2003 I t m n l - S $ 2003 Filino for 2003 CMS/MSS (or SMD) 26.437.000 (7.257.000) ~ S 26.437.000 t7.257,0001 M 17 2002 SuDo~emental Filino For 2002 For CMS/MSS for SMD) ~ ~uDo,~nnental FiJino For 2002 For CMS/MSS (or SMD) 2002 Supplemental Fnlno For 2002 For CMS/MSS for SMDI 2002 Fin<] For 2002 For CMS/MSS ((x SMDI 2002 ~ For 2002 For CIVIS/MSS (or SMD) 2002 Fil~no Fo¢ 2002 Foe CMS/MSS (or SMD) 2002 Filk~o Foe 2002 For 2001 FIIklo for 2001 Total 2( r,0o.0oo ;~4s0o.0oo r~.soo.ooo) 24.500.000 34.104.300 (34.104.3001 34.104.300 8.709.300 19.038.900 23284.300 r~4.soo.(x~o) 24.500.000 34.104.300 f34.104.300) 34.104.300 6.709.300 19.038.900 23.284.300 AJ~oc-~ Aloo.Flxed Allot-Fixed AIk:x:-FLxed p~loc-Fixecl 0 M o t~ o o Z~ 27 2001 Filina for 2000 Total Tolal 2000. 2001. 2002 and 2003 LRC Cost I~l~n~ s ~26.8~6.80o Jk 0 (3 F0 r~ LateRestnJctudnoCa~talCo~st20OO. 2001.2002. a n d 2 0 0 3 1 t e m s ~ 4 t L R C ~ l ) $ 144.366.800 | | $ 144.366.800 i Late Reslz'ucturk~ Capital Costs ~2000. 2001.2002. and 2003 Itmns~ -% tl.RC C, aBltaD Issued by:. Issued on: Robert C. Ludlow Vice President and Chief Financial Officer ~ 200~ Effective Dat~: January 1 , 2 0 0 ~ DC_DOCS_A~ 005211 v2 O ISO New England Inc. FERC Electric Tariff, Volume No. 2 Fourth~-d Revised Sheet No. 24 Su~r~eding 3edThrid Revised Sheet No. 24 0 M I fO fO $.~s,o¢o 4 =~ VarY=me P.::"2":T.:'= ::d :.c..~--.-': =.'=t.+-=,~++ ft. +~-'+*'~--b: :':,-'=:'+:== ...... ~----+V.::-~:.'= Dz;':t=.~r:'.~-: L.~=:+::.= t [ C A P D::'g.-..'P=~=.%'~L-~ 0 t~ Q Q ++.+.+.+.+.+.+.+.+.~ Q I Q Q Q 9 fO 0 fO 44- 4q~iee-K.i,,(ed ~3 fO 4~ 4=74"9 ".%2~,'~', I v y I v */.. M 0 M i --''''~'~ m + I v v l .... l + m $ ,. , i ,,~.',,~',,:o,w, • + 1 ty.,~ ~ , I ~ Ql,~,d, ~ • $ v + v l v v v ~0 + , . , , ' . , . + n n ' , + , . . +. . +~.,+r . . , r ~. - - ~ . . 1~...~_~102003 • ,'~+c'~.,~x • 1~ ~ ' T t ~ Ot~rr~ ¢:3 t~ ¢:3 ¢:3 0 0 fO Issued by:. Issu~l on: Robert C. Ludlow Vice Prgsident and Chief Financial Officer Effective Date: January I, 200-~_ M 0 I 200~ I 0 0 0 ISO New England Inc. FERC Electric Tariff, Volume No. 2 Capital Funding Tariff Activity Code 2004 ~ m : 12651 B u i l d l n ~ o o e f t v imorov, (Renov. w~ksoac~, n e l w ~ k & v~ce rIDvi~Ipo) 6529 Han:Ivmre ar~l Software UD~ade~ for ~ Mad(e¢ svstelm F.__9.E~,-3~Revised Sheet No. 25 Superseding 2.edThird Revised Sheet No. 25 (3 k.,. F.-, Self-Fundlnu Tariff M Descd~lon s~,~,*.~ 527.700 $ 1 1 3 . 7 1 9 8.000.000 4.887.800 s~,~.~ S 273.085 ~ 5.240.000 3.201.509 s~,-~.~ I -'~--,;o~,-~,~171 I C3 I ~.Wi~R-~,n,,i~Sum~ f-¢ r0 ~29 ~29 6529 ~29 Market System Enhancements - SMD Enhancements to ~ Ex~sUno Market Svstlm~ T O ~ Hardware and Software uoo'ades for Existing Martet systems Hardware and Software UDorades to Existin(z No~ Market Svste~l"~ 2.7~.000 1.686.291 ~2.000 676.734 ,~dll~: 1 , 1 . ~ . jf1~~(~~ = r l l ~1~,d~~ L ~ ~ sw ~ E m ~ o ~ae~. s ~ o t~ Q Q Q 12.887.800 8.441.~o0 1.048,000 1.311.632 1.6oo.o00 2.534.500 12651 Internal Develooment Total 2004 Items - S $ 100.00% 3.78% 63.10% 33.14% -% 2000. 2001. 2002 and 2003 Items - S 2003 Filino for 2003 Tote~ 2003 Filina foe 2003 ~ S (or SMD) $ I Q Q Q 26437.000 f7~57.000) 24.500.000 S 7~.743 912,594 S 21,805.149 (6.531.3001 18.647.971 1725.7001 4.~9.435 Breed ( ~ AIl~c~m= In Cmc~X N~ ER93-147-4~0 (~| fo fl fo < fo 2002 Suoolemental Fgirlo For 2002 For CMS/MSS (or SMO) 2002 SuDDlementa~ Ftllrlo For 2002 For CMS/MSS (or SMO) 2002 SuPplemental Fillno For 2Q02 For CMS/MSS (or SMD) 2002 Filino For 2002 For CMS~ISS to~ SMD) 2002 F,lna For 2002 For CMS/MSS (or SMD) 2002 Filino For 2002 For CMS/MSS (or SMD) 2002 Fllino For 2002 F(x Other Bl~d O~ Alio~lons In ~ No ES02-49-000 r~) M ~ ~ 24.5Q0.000 (18.647.9711 ~ (4.939.435) B i l d ~ All~z=ilor~ In D e ~ , z N~ F~i~-49=(XXH3) 34.104.300 (34.104.300) 34.104.300 818.503 (818.503) 27.351.849 (27.351.649) 30.693.870 (5.934.148~ Bu~i Qn Alk~z4lonm D~u~ No ~0~-24~C00 f~) In Em~¢~Q~ AllocmJ~t~ In Doct~ N~ ER002-249~O0 ~ I 0 M Q 6.709.3~0 978.489 3.687.564 2.043~47 10.038.900 23.284.300 784.173 ~ 1.390.853 $ 3.~.258 3.07% $ 16.036.240 102.131.754 80.53% 16.40% 5.857.207 ~ (~ Allaal~l~ In DOC~ N~. ER0l*31e4X)0131 Total 2000. 2001. 2002 and 2003 LRC Cost Rams S 1218.816.800 100.00% t~ Q Q -% Late Restruc~urt~lo Capital Costs (2000. 2001. 2002. and 2003 Itamsl 4 $ 144.386.000 ~ Late Re~dnJctudno Caoital Cost~ (2000. 2001.21X)2. and 2003 Itoff~) -% (LRC CaD/tal) 100.00% 3.15% S 113.205.979 78.42% 18.43% 0 fl fo r~ Issued by:. Issued on: Robert C. Ludlow Vice President and Chief Financial Officer 3 I, 200~. Effective Date: January l, 200~_ DC_DOCS A #1085211 v2 0 ISO New England Inc. FERC Electric Tariff, Volume No. 2 Fourtl,Avd Revised Sheet No. 25 Superseding L~dThird Revised Sheet No. 25 0 M I FO r~ FO . . . . . . . . . . . . . . . . . . . : :. . . . . . 0 t~ 0 0 . ~ £1Pt~ ~ iJ 0 I 0 0 0 FO 0 FO < FO ~C M Sg6rT~T,-;9~ ~ C,==::=~ :.:::~,~:~:: .o:. ;S~ S:.:ff 0 M :?#:96% 4-6:90~ 0 ........... . . . . . . . . . . . . . . . -' . . .v.-.~ o £) ~--I" - :-' . . . . •. . . ~ .......... l / $ (LRC C~"-') .. ~. . . . w--r.--. ,, t~ 0 0 . . . . . . . . '* . . . . . . . . . . . . . . . . . 0 0 FO r~ Issued by: Issued on: Robert C. Ludlow Vice President and Chief Financial Officer "T ..... "^I ~ t o b ~ 3 1 200-2-~. • iv v ,~,i LA~, ~*I* • F.iTc~five Date: January l, 200~_ M 0 I I 0 0 0 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 ISO New England Inc. FERC Electric Tariff, Volume No. 2 Capital Funding T m i f f F ~ O 6 g , i ~ Sheet No. 27 Suoersedine Original Sheet No. 27 Co) a consumer o f electricity in the NEPOOL Control Area that generates or purchases electricity primarily for its own consumption or a non-profit group representing such consumers. N E P O O L Participants Committee: The committee established pursuant to Section 7 of the NEPOOL Agreement. N E P O O L Transmission System: The system o f g g g t r a n s m i s s i o n facilities within the NEPOOL Control Area under the ISO's operational jmisdiction. Participant: A Participant is an eligible Entity (or group o f Entities which has elected to be treated as a single Participant) which is a signatory to the NEPOOL Agreement and has become a Participant in accordance therewith until such time as such Entity's status as a Participant terminates in accordance therewith. Transmission Customer: Any Eligible Customer that (i) is a Participant which is not required to sign a Transmission Service Agreement with respect to a service to be furnished to it in accordance with Section 48 of the NEPOOL Tariff, or (ii) executes, on its own behalf or through its Designated Agent, a Transmission Service Agreement, or (iii) requests in writing, on its own behalf or through its Designated Agent, that NEPOOL file with the Commission, a proposed unexecuted Transmission Service Agreement in order that the Eligible Customer may receive transmission service under the NEPOOL Tariff. This term is used in Part I o f t h e NEPOOL Tariffto include customers receiving transmission service under the NEPOOL Tariff. Transmission Provider: The Participants, collectively, which own PTF and are in the business o f providing transmission service or provide service under a local open access transmission tariff, or in the case of a state or municipal or cooperatively-owned Participant, would be required to do so if requested pursuant to the reciprocity requirements specified in the NEPOOL Tariff, or an individual such Participant, whichever is appropriate. Issued by:. Issued o n : Ed;'.=."~ ,M. McK.%"m.-Robert C. t.ud]ow . Vice President and Chief Financial Officer 2oo)3 Effective Date; January L 2004 0 c o o c s A ~ 0e~78 v0 wo1~307 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 UNITED STATES OF A M E R I C A B E F O R E T HE FEDERAL ENERGY REGULATORY COMMISSION 5 ISO N E W ENGLAND INC. Docket No. ER04- -000 7 8 9 DIRECT TESTIMONY OF GARY W. PIRE 10 11 12 13 14 15 16 17 October 31, 2003 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 ISO New EnglandInc. Exhibit 3 Pagcl UNITED STATES O F AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION 4 ISO N E W ENGLAND INC. ) Docket No. ER04- -000 Direct Testimony of Gary W. Pire 7 8 Q. A. PLEASE STATE Y O U R NAME AND BUSINESS ADDRESS. Gary W. Pire. One Sullivan Road, Holyoke, Massachusetts 01040-2841 9 Io 11 12 Q. A. W H A T IS Y O U R O C C U P A T I O N ? I am the Manager o f Financial Reporting and Budgeting o f ISO New England Inc. (the "ISO"). 1 have served in that role since beginning m y employment with the ISO on March 11, 2002. 13 14 Q. PLEASE DESCRIBE Y O U R EDUCATIONAL B A C K G R O U N D AND PROFESSIONAL EXPERIENCE. 15 16 17 18 19 A. I hold a BA from the University o f Connecticut, an M B A from the Air Force Institute of Technology (University o f North Dakota), a post graduate certificate in Corporate Finance from the University of Michigan as well as post graduate certificates in Accounting and Taxation fi'om Western Connecticut State University. Prior to taking m y current position I was a Principal as well as the DC_DOCS_A#1129OO9v3 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exit%it3 Page 2 I Chief Financial Officer of Utilities International. Prior to assuming the position with Utilities International I was the Director o f Financial Planning and Analysis with Northeast Utilities. 2 3 4 5 6 7 8 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY COMMISSION? A. Yes, I have testified before the Federal Energy Regulatory Commission (Commission) on a variety of matters, including last year's ISO administrative cost and capital funding tariffs; before the Connecticut Department o f Public Utility Control; and before the New Hampshire Public Utility Commission. 9 I0 II PURPOSE OF TESTIMONY 12 13 14 15 16 Qo A. WHAT IS THE PURPOSE OF YOUR TESTIMONY? I am providing this testimony in support o f the filing o f the revised tariff sheets for the Capital Funding Tariff("CFT") (collectively, the "Revised Sheets"). In addition, and as committed to in last year's Capital Funding Teriff filing, I am also providing additional information supporting the 2004 capital projects that have a multi-year duration. In this filing, the ISO is only seeking capital funding for calendar year 2004 for these projects, but provides projected spending during the upcoming year (2005) for such multi-year projects for informational purposes. 17 18 19 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit3 Page 3 In addition I will present the development of the Test Year 2004 cost of service study, as it relates to the allocation of capital costs, including the allocation of Late Restructuring Costs, associated with the ISO providing service under the three rate schedules included in the ISO administrative cost tariff ("ACT"), most recently proposed to be revised in the ISO's October 31, 2003 filing in a parallel docket. My Direct Testimony (Exhibit 3 to the parallel ACT filing) will present the cost of service study and rate design in support of the cost allocations to the ACT rate schedules reflected in Attachment A of the Revised Sheets. My Direct Testimony describes: (i) (ii) (iii) (iv) (v) (vi) the ISO's organizational structure and the services it provides; the Capital Budget development process, the 2003 Capital Budget and its justification; the Activity Accounting System; Term Borrowing; and the allocation of Late Restructuring Costs. 9 10 11 12 13 14 15 16 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 4 I 2 THE ISO'S ORGANIZATIONAL STRUCTURE AND THE SERVICES CURRENTLY PROVIDED BY THE ISO 3 4 5 6 7 8 9 10 11 12 13 14 15 Qo A. WHAT IS THE ORGANIZATIONAL STRUCTURE OF THE ISO? The ISO is governed by an independent board of directors with representatives from the business, regulatory, and research communities. The ISO is overseen by a President and Chief Executive Officer (CEO) who has seven direct reports. A Senior Vice President and Chief Operating Officer (CO0), reporting directly to the CEO, is responsible for Markets Operations, System Operations, System Planning and Customer Services and Training. A Senior Vice President of Market and System Solutions, reporting directly to the CEO, is responsible for Information Technology, Markets Development, and Program Management. A Senior Vice President and General Counsel, reporting to the CEO, is responsible for the Legal and Public Affairs Departments. Other departments reporting directly to the CEO are Human Resources, Finance, Internal Audits, and Market Monitoring and Mitigation. 16 17 18 19 20 21 Q. W H A T SERVICES ARE PROVIDED BY T H E ISO, A N D H O W ARE ITS A D M I N I S T R A T I V E COSTS R E C O V E R E D FROM ITS CUSTOMERS? A. The ISO provides three services to its customers: 1. Scheduling, System Control and Dispatch Service (or "Scheduling Service") 2. Energy Administration Service ("EAS"), and 3. Reliability Administration Services ("RAS') (collectively, the "Services"). Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit3 Page 5 1 2 The ISO, a public utility, collects from its customers (mainly, the New England Power Pool ("NEPOOL") Participants) the administrative costs of providing the Services through a tariff filed with the Commission. The ISO is filing its updated rates for its administrative costs tariff ("ACT") on October 31, 2003, in order to recover its calendar year 2004 operating costs. The ACT includes three rate schedules, recovering the costs ofproviding Scheduling Service, EAS and RAS, respectively. The ACT currently in effect was the product of a settlement agreement accepted by the Commission in its order issued September 12, 2001 (96 FERC ¶ 61,261). There has been no redesign o f the rates, because there are no circumstancesthat would warrant rate redesign. 3 4 5 6 7 g 9 I0 11 12 13 14 Q. ARE THE COSTS OF CAPITAL ITEMS NEEDED TO SUPPORT THE ISO'S MISSION RECOVERED THROUGH THE ACT? IF NOT, H O W WILL THEY BE RECOVERED? No, the acquisition cost ofcapital items is addressed through the CFT rather than the ACT. The CFT includes a "Capital Funding Charge" (or "CFC"), which is the mesns by which the ISO will collect from the NEPOOL Participants its costs o f acquiring capital items (not previously funded by the NEPOOL Participants directly under the Restated NEPOOL Agreement) if it is unable to borrow the necessary funds fi'om a bank. In order to induce the banks to lend for the ISO's capital and working capital needs, the CFT also includes two other charges - the Early Amortization Charge (or "EAC") and the Early Amortization Working Capital Charge (or "EAWWC") that ensure that the ISO can recover the 15 16 17 18 19 20 21 22 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit3 Page6 l unamortized costs of the assets financed privately in the event of early termination or acceleration ofthe loans. When the ISO borrows to support capital and working capital needs, the debt service is collected through the ACT revenue requirement. As explained in the filing letter, the revenue requirement for the contemporaneously filed revised sheets for the ACT revisions for 2004 (the "ACT Revised Sheets") contains funds that will cover debt service for 2000, 2001, 2002, and 2003 capital items during 2004. 2 3 4 5 6 7 8 THE CAPITAL BUDGET DEVELOPMENT PROCESS 9 Q. WHAT BUDGETS DOES THE ISO DEVELOP FOR EACH YEAR? WHAT TYPE OF PROJECTS DOES THE CAPITAL BUDGET SUPPORT? 10 11 12 13 14 A. The ISO develops an operating budget and a capital budget (the "Capital Budget"). The Capital Budget supports very important capital needs for New England. 15 16 Q. A. HOW WERE THE ISO'S BUDGETS DEVELOPED FOR 2 0 0 4 ? The ISO prepares budgets in advance of each upcoming year, including a capital budget. To develop these budgets for 2004, the ISO's Chief Executive Officer ("CEO") held meetings with the Chief Financial Officer and me, the members of the ISO Board, officers and certain key managers to discuss the existing and changing responsibilities of the organization. Based on the results of these meetings, estimates of the resources necessary to carry out the responsibilities 17 18 19 20 21 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhib~3 Page 7 1 were submitted by each of the responsible directors and managers and compiled by myself. All budgets were reviewed to ensure that all costs were included and that no costs were double counted. The ISO presented drafts of its capital budget to the NEPOOL Budget and Finance Committee and invited input from NEPOOL Participants. The ISO presented the capital budget to the NEPOOL Participants Committee ("NPC") on September 5, 2003. This budget was approved by a nearly unanimous vote of the NPC. The ISO's Board of Directors subsequently approved the 2002 Capital Budget at its September 18, 2003 meeting. 2 3 4 5 6 7 8 9 Q. A. PLEASE DESCRIBE THE ELEMENTS OF THE CAPITAL BUDGET. 10 11 12 13 14 15 16 17 The Capital Budget for 2004 is approximately $17.6 mimon. See Exhibit 3, (GWP-5). The capital expenditures include: funds for enhancements to the first phase of the Standard Market Design for New England, implemented March I, 2003 C'SMD 1.0") (including Locational ICAP design and modification of software and Co-optimized Reserves) and enhancements to other existing hardware and software systems (including automation ofcostomer and asset data, upgrade to Oracle software, and ISO website redesign) (approx. $12.9 million); upgrades to facilities (Sullivan Road improvements including security enhancements; and a halon fire suppression system for the control room) (approx. $0.5 million); 18 19 20 Jnofficial FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exlubi!3 Page 8 information technology and software enhancements to existing systems, including Scheduling and Planning software, control room hardware, networks and servers (approx. $1.6 million); and 4 capitalization of labor costs associated with intemally developed software for the various systems at the ISO (approx. $2.5 million) as required by accounting standards. 5 6 8 9 Please note that the expenditures for enhancements to SMD 1.0 and other emerging capital projects represent projects in their conceptual design. As forecasts, the listed expenses are preliminary and will be specifically allocated among the enhancement projects when the project charters are formally approved. Any reduction fi'om the estimates provided in this Filing will not be dedicated to new, or other, projects without express authority from the ISO's Board of Directors and discussion with NEPOOL Participants. 10 11 12 13 14 15 16 CAPITAL BUDGET AND ITS JUSTIFICATION 17 18 19 Q. IS THE ACQUISITION OF CAPITAL BUDGET ITEMS INCLUDED IN THE 2004 ACT REVENUE REQUIREMENT? A. No. Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 9 l 2 3 4 Q. DOES T H E O P E R A T I N G EXPENSE BUDGET INCLUDE D E P R E C I A T I O N ON ITEMS IN T H E C A P I T A L BUDGET T H A T A R E PLACED IN SERVICE IN 2004? A. Yes. 5 6 7 8 Q. PLEASE DETAIL H O W T H E C A P I T A L EXPENDITURES O F T H E C A P I T A L BUDGET AND P R O J E C T S BUDGET A R E FUNDED AND REPAID. A. Capital expenses incurred after January I, 2000 were considered Late Restructuring Expenses (LRE) under Section 19.3 of the RNA and initially were funded each month, on an as-incurred basis, by the NEPOOL Participants in proportion to their charges under the ISO Tariff for the previous month. Pursuant to the NPC resolution authorizing the 2001 ISO budgets, the Participants decided at their November 2000 meeting, to fund the Standard Market Design Project ("SMD', formerly, CMS and MSS) on a cash call basis as those costs are incurred. These expenses were funded pursuant to the NEPOOL Agreement. The aggregate LRE in any calendar year are amortized when placed in service on a straight-line basis over their useful life to be collected under the ISO Tariff Schedule which the assets service beginning in 2001 and repaid as collected. As stated above, NEPOOL incorporated this payment methodology into its Restated NEPOOL Agreement. 9 10 11 12 13 14 15 16 17 18 19 20 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exh~it 3 Page 10 As described in the answer to the preceding question, the ISO had subsequently obtained outside financing from a third party lender in June 2001. Pursuant to 19.3(d) of the RNA, the LRE incurred on or after January 1, 2001 will be allocated, on an as-incurred basis, to the three ISO Tariff Schedules, employing the same allocation methodology in effect pursuant to the ISO's Capital Funding Tariff. The Participants that are repaying the charges under the ISO Tariff Schedules are receiving the benefits o f the services rendered under those schedules. In a parallel manner, the RNA's collection, amortization and repayment methodology requires Participants to bear the cost, for each item ofthe LRE, in proportion to their use o f 7 8 9 10 11 12 13 14 15 services, as measured by the charges under the applicable ISO Tariff Schedule. This is the approach reflected in the Capital Funding Tariffwith respect to the Capital Funding Charge. Furthermore, the amortization and repayment period correspond to the appropriate recovery period (typically the depreciation period) for the item being paid for under generally accepted accounting principles. 16 17 ACTIVITY ACCOUNTING SYSTEM 18 Q. DESCRIBE THE ISO'S ACTIVITY ACCOUNTING SYSTEM AND THE EXTENT TO WHICH IT PROVIDES COST OF SERVICE INFORMATION FOR EACH OF THE THREE ACT TARIFF SCHEDULES. 19 20 21 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exh~oit 3 Page 11 1 2 3 4 5 6 7 8 9 10 11 12 13 A. The activity accounting system was implemented at the ISO's inception in 1997 and refined in 1998. All operating charges recorded in the general ledger system must be cross-referenced to an activity. Each department has identified its major activities. Most activities are department-specific but some activities may be cross-charged ifthey are o f a project nature. Activities within a department are known as either "direct" activities or "indirect" activities. Direct activities are o f an operational nature and are allocated to one or more o f the three tariff schedules based on a fixed percentage. This fixed allocation is provided by the department manager a n n ~ l y in preparation for the next year's budget and tariff filing. Indirect activities are o f an administrative nature and allocated based on current direct labor charges. In addition, the majority o f activities for administrative departments (Finance, Human Resources, etc.) are allocated based on the total labor charges within the Company. The activity accounting system is in large part a manual system meaning that timesbeets and invoices are coded manually. ISO-NE operates with a relatively small staffwho perform a number of duties that provide service to all three services. The ISO found that it would not be prudent to overly expand the system and require each employee to determine what schedule they serviced through the week. Furthermore, the ISO does not pre-code an employee's time because duties may change often with seasonality or new projects. Therefore, the allocation of activities to the three tariff schedules is made at the manager level. 14 15 16 17 18 19 20 21 Jnofficial FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 12 1 The activity system is not designed to track costs to individual markets or transaction units. As explained in the labor and cost of service analysis, employee's time is not driven by the number o f transaction units or markets, but by the number o f tasks and projects. 2 3 4 5 6 If the activity accounting system were expanded to provide for accounting cost in more detail it would be more costly and difficult to manage without substantially increasing its accuracy. 7 8 9 TERM BORROWING 10 11 12 13 14 15 16 17 18 Q. H O W A R E T H E C A P I T A L COSTS O F S U P P O R T I N G T H E ISO'S MISSION C U R R E N T L Y BEING FUNDED UNDER T H E C l r r ? A. Following the Commission's acceptance of the CFT, the ISO obtained outside financing from a third party lender in June 2001. The ISO obtains repayments in accordance with the 68 th Agreement which amends the Restated NEPOOL Agreement's Section 19.3(d) to state that the LRE incurred on or after January 1, 2001 will be allocated, on an as-incurred basis, to the three ISO Tariff Schedules, employing the same allocation methodology in effect pursuant to the ISO's Capital Funding Tariff. 19 20 The Participants that are repaying the charges under the ISO TariffSchedules are receiving benefits of the services rendered under those schedules. In a parallel Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit3 Page 13 1 manner, the revised collection, amortization and repayment methodology for the "Late Restructuring Expense" ("LRE") in the 68 th Agreement r~q~r~ Participants to bear the cost for that item of the LRE in proportion to its use o f those services, as measured by its charges under the applicable ISO TariffSchedule. This is the approach reflected in the Capital Funding Tariffwith respect to the Capital Funding Charge. Furthermore, the amortization and repayment period would correspond to the appropriate recovery period (typically the depreciation period) for the item being paid for under generally accepted accounting principles. 2 3 4 5 6 7 8 9 Q. H O W DOES THE ISO PLAN TO FINANCE THE ISO'S CAPITAL BUDGET FOR 2004? 10 11 12 13 A. The ISO plans to increase its term loan facility, or enter into a new term loan facility, to cover these purchases. The proposed 2004 capital budget is a forecast based on the work needed to be completed in 2004. 14 15 16 17 18 Q, IS THERE AN EXHIBIT THAT SHOWS THE DEVELOPMENT O F THE 2004 COST OF SERVICE ANALYSIS, AND WHY IS THIS RELEVANT TO THE c F r ? A. Yes. My testimony in the parallel ACT filing includes the following cost o f service exhibits under ACT Exhibit 3 (GWP-3) Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 14 1 Schedule 1.0 Total Cost Allocation to Schedules by Department Schedule 2.0 Labor Cost Allocation to Schedules by Department Schedule 3.0 Total Cost Allocation to Schedules by Cost Category Schedule 4.0 Labor Cost Allocation to Schedules by Cost Category Schedule 5.0 Allocation Factors by Cost Category Schedule 6.0 Allocation o f Late Restructuring Expense 2 3 4 5 6 This testimony is pertinent to the CFT because it is used as the basis for allocating the 2004 capital items across the three rate schedules o f t h e ACT, as reflected in revised Attachment A to the CFT. 10 COST AIJ.K}C.ATIQNS TO ~ 1,2AND3 11 12 13 14 15 Qo A. W O U L D YOU PLEASE DESCRIBE A C T EXHIBIT 3 (GWP-3)? Yes. ACT Exhibit 3 (GWP-3) contains the Test Year 2004 cost o f service for each o f the three rate schedules included in the ISO tariff. The exhibit lays out in detail how ISO costs were assigned to the three schedules in support o f the ISO's ACT revisions for 2004. 16 Most Activity costs consist o f direct labor costs, employee benefits, and other non labor-related costs (i.e. office supplies, software, hardware, depreciation, interest, etc.). For each Activity Code, both the labor-related and non labor-related costs are assigned to the rate schedule using the same allocator. An allocator descriptor that is defined as "Alloc-Fixed" means that a specific percentage was developed 17 18 19 20 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 15 1 by the ISO staffand used to directly allocate costs for that line item. The percentage allocators used to allocate activity costs are summarized on Schedule 5.0 o f ACT Exhibit 3 (GWP-3), attached to m y testimony as Exhibit 3 (GWP-6). 2 3 4 5 6 Q. CAN YOU EXPLAIN H O W T H E " A L L O C - F l X E D " A L L O C A T O R S W E R E DETERMINED? A. In assessing how costs should be assigned to the various categories of service that the ISO provides to its customers, the objective was to reflect cost causation principles as much as possible. Over the past three years a substantial amount of time has been spent interviewing staffwithin each department, discussing the various tasks and activities and discussing the availability o f data that measure the cost drivers for those activities. As part o f the interview process, ISO staff provided substantial insight and direction and in many cases specific data that was used to develop the "Alloc-Fixed" cost allocators. 7 8 9 10 11 12 13 14 A L L O C A T I O N O F LATE R E S T R U C T U R I N G COSTS 15 16 17 18 19 20 21 Q. I UNDERSTAND T H A T " L A T E R E S T R U C T U R I N G EXPENSE," AS DEFINED IN T H E R E S T A T E D N E P O O L A G R E E M E N T , IS ADDRESSED IN T H E 2004 COST O F SERVICE STUDY. IS T H A T C O R R E C T ? A. Yes. These are shown as the late resmaeturing expense ("LRE") items in Schedule 6.0 of Exhibit 3 (GWP-3), attached to m y testimony as Exhibit 3 (GWP7). The costs included on page 1 of Schedule 6.0 are basically the debt service components associated with LRE. These are collected through the ACT, rather Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exlu%it 3 Page 16 than the CFT. The costs included (and allocated) on page 2 of Schedule 6.0 are the capital costs for 2000, 2001, 2002, 2003 and 2004. Q. EXPLAIN H O W T H E c F r STUDY. RELATES TO THE COST OF S E R V I C E A. As indicated earlier, the allocations of LRE capital costs that maybe collected through the "Capital Funding Charge" under the CFT are based on the 2004 Cost of Service Study which supports the ISO's ACT for 2004. Exhibit 3 (GWP-6) shows the resulting allocated LRE Capital amounts, and is the basis for revised Attachment A to the CFT 10 II 12 13 14 15 Q. PLEASE S U M M A R I Z E THE RATE D E S I G N OF EACH C H A R G E U N D E R T H E CZI', AND STATE Y O U R OPINION AS TO W H E T H E R THE RATE D E S I G N FOR EACH IS JUST A N D REASONABLE. A. The CFT includes three charges: the Capital Funding Charge ("CFC"), the Early AmortiTation Charge ("EAC"), and the Early Amortization Working Capital Charge ("EAWWC"). 1. The CFC rate design Capital costs to be funded, as necessary (and only to the extent that the ISO is unable to fund these costs), through the CFC have been categorized 16 17 18 19 in Attachment A. The cost of each capital item is allocated among the Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit3 Page 17 three Services corresponding to the extent to which that capital item is utilized in providing the Service. To assist the Participants in their planning for payments of the CFC, the ISO will provide electronic notice to each Participant of the non-binding, estimated monthly cash flow requirements of the ISO (for the upcoming Calendar Year or portion thereof) with respect to acquisition of the capital items listed in Attachment A, and allocated among the Schedules. Each month, the ISO will bill each Participant, and each Participant will pay, as its CFC: (!) the proportion of the capital costs allocated to Schedule 1 under Attachment A actually incurred by the ISO during the preceding month equaling the proportion of the Participant's charges under Schedule 1 of the Tariffto the total charges under that rate schedule during the preceding month; (2) the proportion of the capital costs allocated to Schedule 2 under Attachment A actually incurred by the ISO during the preceding month equaling the proportion of the Participant's charges uncler Schedule 2 of the Tariffto the total charges under that rate schedule during the preceding month; and (3) the proportion of the capital costs allocated to Schedule 3 under Attachmvnt A actually incurred by the ISO during the preceding month equaling the proportion of the Participant's charges under Schedule 3 of the Tariffto the total charges to all Participants under that rate schedule during the preceding month. 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 18 For example, if the Schedule 2 capital costs and the Schedule 3 capital costs incurred in the preceding month are $500,000 each, and the Participant's share of total charges to Participants under Schedule 2 for March was 5%, and the Participant's share of total charges under Schedule 3 for March was 3%, the Participant's CFC that month would equal (for Schedule 2) $500,000 x .05 or $25,000, plus (for Schedule 3) $500,000 x .03 or $15,000, for a total CFC o f $40,000. The CFC rate design is just and reasonable because it is consistent with traditional cost-causation principles. The capital costs are allocatedamong the three Services corresponding to the extent to which that capital item is utilized in providing the Service. Therefore, collection fi'om a Participant of capital costs through the CFC based on the Participant's relative proportion of a prior month's total ACT charges for that Schedule correlates with the Participant's relative use o f the Service, and thus diroctly tracks cost causation. The jnst and reasonable nature o f this rate design is also verified by the fact that it is the same "rate design" developed by the ISO's CFT Customers themselves - for the allocation of LREs as set forth in the 68 ~ Agreement. 8 9 10 11 12 13 14 15 16 17 18 19 2. The E A C ratedesign 20 21 In the event of early termination or required accelerated repayment o f financing that has been entu~.~clinto by the ISO in support o f the items Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exl~'bit 3 Page 19 1 2 3 4 5 6 7 listed in Attachment A, an EAC will be billed to, and paid by, each Participant. The lSO shall provide electronic notice (no less than thirty (30) business days in advance of the date payment is due to the lSO's lenders) to each Participant ofthe aggregate amount of the unamortized costs of the financed assets (the "EA Amount"), and the portion of the EA Amount assigned by the ISO to each of the Schedules (the "Announced Schedule 1 EA Amount," the "Announced Schedule 2 EA Amount," and the "Announced Schedule 3 EA Amount," respectively). The EA Amount will be assigned to each of the Schedules in proportion to the total respective value of capital items (purchased through tbe date of early termination using the financing) allocated to each of the Schedules under Attachment A. In each such circumstance, the ISO will, immediately after giving the notice described above, bill each Participant and each Participant will pay, as its EAC: (1) the proportion of the Announced Schedule 1 EA Amount equaling the proportion of the Participant's charges under Schedule 1 of the Tariffto the total charges to all Participants under that rate schedule during the month previous to the month in which the foregoing notice has been given; (2) the proportion of the Announced Schedule 2 EA Amount equaling the proportion ofthc Participant's charges under Schedule 2 of the Tariffto the total charges to all Participants under that rate schedule during the month previous to the month in which the foregoing notice has been given; and (3) the 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 20 1 proportion o f the Announced Schedule 3 EA Amount equaling the proportion of the Participant's charges under Schedule 3 of the Tariffto the total charges to all Participants under that rate schedule during the month previous to the month in which the foregoing notice has been given. For example, if the Announced Schedule 2 EA Amount and the Announced Schedule 3 EA Amount in April are $500,000 each, and the Participant's share o f total charges to Participants under Schedule 2 for March was 5%, and the Participant's share o f total charges under Schedule 3 for March was 3%, the Participant's EAC would equal (for Schedule 2) $500,000 x .05 or $25,000, plus (for Schedule 3) $500,000 x .03 or $15,000, for a total EAC of $40,000. 2 3 4 5 6 7 8 9 I0 I1 12 13 14 15 16 17 18 The EAC rate design is just and reasonable because it conforms to accepted cost-causation principles. In Attachment A, the capital costs are allocated among the three Services corresponding to the extent to which that capital item is utilized in providing the Service. The calculation o f a Participant's EAC is based on: (1) the cumulative total o f capital items allocated to each Schedule for which the ISO has utilized financing for acquisition; and (2) the Participant's relative proportion of a prior month's total ACT charges for each o f those Schedules (which measures the relative extent to which that Participant is utilized the corresponding Service). Accordingly, the rate design directly tracks cost causation. The 19 20 21 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 21 1 just and reasonable nature of the EAC rate design is also verified by the fact that it is entirely consistent with the "rate design" -- developed by the ISO's CFT Customers themselves - for the allocation of LREs as set forth in the 68th AgreemenL 3. The EAWCC rate design In the event of early termination or required accelerated repayment of financing that has been entered into by the ISO in support of the ISO's working capital requirements, an EAWCC will be billed to, and paid by, each Participant. The ISO shall provide electronic notice (no less than thirty (30) business days in advance of the date payment is due to the ISO's lenders) to each Participant of the aggregate amount of the Working Capital Amount (i.e., the ISO's budgeted administrative costs over the succeeding three months) (the "EAWW Amount"). In each such circumstance, the ISO shall immediately bill each Participant and each Participant shall pay, as its EAWWC, the proportion of the EAWW Amount equaling the proportion of the Participant's charges under the Tariffto the total charges to all Participants under the Tariffduring the month previous to the month in which notice has been given. For example, if notice is given in April that the EAWW Amount is $1,000,000 and the Participant's share of total charges under all three Schedules for March was 4% of all charges to all Participants, the 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 Page 22 Participant would be charged a EAWCC of $1,000,000 x .04 or $40,000. 2 3 4 5 6 7 8 The EAWCC rate design is just and reasonable because it conforms to accepted cost- causation principles. The ISO's working capital borrowings broadly support the performance o f all three Services under the ACT. Calculating a Participant's EAWCC based on its proportion o f the total charges assessed under the ACT in the preceding month directly tracks cost causation,for this calculation tracks the relative reliance ofthat Participant on the ISO's services. The just and reasonable nature o f the EAWCC rate design is also verified by the fact that it is entirely consistent with the "rate design" - developed by the ISO's CFT Customers themselves -- for the allocation o f LREs as set forth in the 68 ~ Agreement, because it ties back to relative use o f the ISO's Services (in this case, all three Services lumped together). 9 10 11 12 13 14 15 16 17 18 MULTI-YEAR CAPITAL PROJECTS Q. PLEASE EXPLAIN THE DERIVATION OF THE COST ESTIMATES FOR THE MULTI-YEAR PROJECTS BEING ADDED TO CFI" SECTION 8.1. 19 A. The revised sheets filed herewith reflect the addition of three categories o f multiyear capital projects to Section 8.1. In last year's CFT filing, the ISO committed 20 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exl~bit3 Page 23 to provide cost estimates for future years of multi-year projects. The three categories of multi-year projects in this Filing are: (1) Information Services (which is comprised of enhancements to data archive and restoration capability and ISO website redesign) (cost estimate: $3.4 million); (2) Market Enhancements (which is comprised of development of CoOptimized Reserves, Virtual Regional Dispatch and System Improvement Requests) (cost estimate: $8.5 million); and 9 (3) Operational Efficiencies (which is comprised of upgrades to Oracle soRware) (cost estimate: $.08 million). The 2005 cost estimates for these multi-year projects were developed in a manner similar to that of the overall 2004 Budget. To develop these project estimates for 2005 the ISO's Project Management Office, Chief Executive Officer CCEO"), Chief Financial Officer, and certain key managers met on numerous occasions to discuss the existing and changing responsibilities of the organization beyond the 2004 Budget. Based on the results of these meetings, estimates of the resources necessary to carry out the responsibilities were complied. These estimates are for informational purposes only, and are only preliminary at this time. No project charters or detailed costs analysis have been performed at this time. It is very likely that once the in-depth analysis on project costs has been completed these COStestimates will change. 10 II 12 13 14 15 16 17 18 19 20 21 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exl~bit3 Page 24 2 CONCLUSION Q. DO YOU WISH TO O F F E R ANY FURTHER TESTIMONY OR EXHIBITS? A. In addition to the exhibits referenced in my testimony above, I would like to incorporate the Cross Reference Table regarding Statements AA-BM (Exhibit 5 in the accompanying filing letter) into my sworn testimony. 9 Qo A. DOES THAT CONCLUDE YOUR PRE-FILED TESTIMONY? Yes. I welcome the opportunity to address questions regarding matters covered by my pre-filed testimony. 10 11 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit3 GWP-I AFFIDAVIT Gary W. Pir% being duly sworn, dcpos~ and says: That he has read the foregoing questions and answers identified as his testimony in this proceeding; and, if askod the questions therein, her answers and r~'ponscs would be as shown; and that the facts contained in said answers are u~e to the best of her knowledge and belief. Subscribed and sworn to before me, this28th day of October, 2003. Notmy Public c ~ ~ " J ~ , M y Commission Expires "7/,2 :R/,~ 0 / O oc oocs A#110eros¢z O Ex~bit 3 GWP-2 fl M I fO CAPITAL B U D G E T F O R 2004 fO 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 12651 6529 6529 6529 6529 6529 12651 2004 items: Building/propertyimprov. (Renov. workspace, network & voice rewiring) Hardware and Software upgrades for Existing Market Systems Market System Enhancements - SMD Enhancements to Other Existing Market Systems Total Hardware and Software upgrades for Existing Market Systems IT Hardware and Software Upgrades to existing Non-Market Systems Internal Development Costs $ 527,487 t~ Q Q Q 8,000,000 4,887,800 12,887,800 1,600,000 2,534,500 I Q Q Q fO fl fO fO Total 2004 Items - $ M 0 M Q t~ Q Q 0 fl fO M 0 I I 0 0 0 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 3 GWP-3 Page 1 of 2 Description of 2004 Capital Budget Build/rig and Property Improvements: Building and Property Improvements are driven by the need to accommodate a growing staff, including both employees and consultants. In the year 2000 the ISO leased space approximately one mile from the control center in Holyoke to house various departments such as planning, settlements, human resources, customer service and accounting. In the year 2001 additional space was leased and spacing plans were reconfigured. In 2004, considerable improvements are needed at the control center location to support operations, IT, and markets development including program management. Hardware and Software Upgrades for Existing M~rkct Systems: The additional hardware and software needed by the ISO is to support a number of different initiatives. These initiatives include but are not limited to enhancements to existing market systems (SMD), OASIS la, lb and 2, host CPU and memory upgrades, storage area network, DTS/Control Room upgrades, phones, scheduling system and NERC Security Information System. IT Hardware and Software Upgrades to Existing Non-Market Systems : Upgrades m existing non-market systems to include the additional desktop hardware (workstations) and software needed by the ISO for new employees Internal Development Co~s: The capitalized labor costs are the costs of the IsO's internally developed soRwaro to support the current market system and the EMS system. These costs will be charged out to the various projects as incurred ~ ) tin,m4) 0 fl M I L,NI , l ~ l Ir~ll A~. ~dL1r~ll l Pl~.rOl I ,.,., " " ~ , , " ~ , ",',',, m fO I i q ~ ' / r l S fO lr'rII I~l F . n h ~ c u m ~ * *o O m ~ I [ m ~ 8 V~mmaI P ~ m ~ & ~ 4N?.m I~N~**JI~ * ~ 4~llr.m IZJ~,JI~ 21,14A~0 10 II 12 I) 14 10 II IT 10 1I it1 24 ~01 PliSk~l Tllld *41IO.FlIal *~mo4qim4 Tirol ~Ir L I I W II~(~0 4m7~0 t2~rr,lgo Jl,,lil4 JlIO * I ~ $ 140.I ~*'~0.000 A , I I ~ * l ~ A d , IIIp~lml $~m*m Ism~*m IW Cmmikem * F.II I ~ IW o ~ * E~ami VI~ :).~Im 1.441JN 1411114 1.311 . l l ~ 1.~Jm 4.4'11,211 I'PI ?14 ~ * i,ide~¢l A41mlrdIkl~,VI 8 4 ~ e l 0 t~ Q Q Tapl ~ amqm * $ -15 | N.4Tr.NO $ I~.s~ ~14.104.11~0 (14.104.110I) I N.ClT.NO ~ ~4,mo.o0~ Anio,(qme )14.1114~ ~u[oo.,Ftl41~l ~4.114.slI) ~ $ lO000~& liJiI~.O(lO | G4.s~ )4.144,.~1~0 (14,~04~I~1 lil~8~ll00 071)q& ?)&h(~l i tat~ ~,,se, q ~ ~ 13 10W* 21.1111.14 ¢+I , I47JrT~) 27.MI .~ ¢1r7.]414aql IO,ll~ 1.1~7.114 | ] ~ J ~;Ir~ $.1~.1Ol 4~,414 J l ~ $.114.1~8 (I.l~l,l~ 1.410+4]0 ~.l~J~ lildOqMoclmlomkOo~llNo Ir44m~ C+l ~ 4 ~ N m ILm~s!4?~C~(I) 0 ~ 1 , Ildl~, Uq~l mill N l ~ l Ilimml * $ Q I ~02 Ik~amm~ F ~ For ~ 0 2 F*r ca~m4~m r ~ I ~ 0 0 2 ~ s k , p ~ m m ~ mr~q8N ~ ~ P*r o ~ m ~ m u (o+ mNo) ~ F I ~ 8 For X ~ Z F = O I I M a ~ W 81~1 N 0 ~ b l l NO E1(0.~4.400 (3) . l(I,l~l.li(~ IIJ,0(~ ~ ,.,;.. "#ll4,lTJi C l m l ~ m N r ~ = I I M P w iII~ llql~ li~ O~ A V u l ~ a l l I~ ~ l m l l NO*~ (lrl I m m l ¢m A I 0 k ~ l In 0 l m m N~ I ! ~ 0 * ~ * l - l m (~1 Ci111¢1~ Al[~mlol P w ~lO ~lm~ ImWOiNIomm~knDo~lNo 1~10~14-~0 m Q Q Q fO fl fO fO M 0 M t~ 0 fl fO M 0 I (1) From E)dV~ $ ( O V A ~ , So~ed~4 1 0 ImIqSqC O ~ m ~Vm+ 0 4 - ~ ~ rzmFrom ~ m 4 m e ~ A *o z901. :Za~, a M ao0~ c 4 ~ e ~ Tarms. I 0 0 0 Sxh~t 3 (OWP-~) 0 fl LA~ R E g ~ AI"rACHMENT A ~T'J~ ~ ~ I"EST ~ ~ AU.~lIONS M I fo Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 27 28 29 3O 2004 I~m~: a=.v~/ (i) $ 65211 85211 6521~ eS2~ 12851 M a ~ S)lmnl E n h l n c l ' n l ~ . SMO E n h a n c l ~ t l to O ~ w F.m~r~ ~ Symml TotaJ Hwdv~m w ~ S o ~ w ~ u~rm~e b F.x~ng I / a ~ m Hwo'~q~ w~d So,lyre Up~md~ ~o E m ~ Non ~ Symm~ ~nlw~ Devek)l:e,e~ C o ~ Total 2004 natal - $ -% ~000. ~01, 20~2 I n d ~003 I m ~ . $ $ 2003 Fllng ~o~2 0 ~ ~ (or SMD) 2002 S u ~ O W n ~ F ~ g Fo~2 0 ~ FC* ( : ~ . ~ S S (o~S~O) 2002 S u i ~ o l e m ~ Fing Fo~2 0 ~ FO~C M S , ~ (o~ SMD) 2002 S4Jpl~m~tll F ' i ~ Fo~2002 FO(CMS,I~S (~ SMD) 2002 F~,ngFO~2002 Fo~CMS,I,~;S(o~8MD) 2002 F ~ F~X2002 F~ CMSn~S ~ SMO) 2002 Fing FO~2002 Fo~CMSn4SS(o~SMO) 2002 Fing FO(2002 F ~ O~her 2001 Fling 101"2001TO~I 2001 F~Ing/or 2000 Totld Tot~ 2000. 2001. 2002 and 2(]03 LRC Co~ Illeml -% Call~4~ C ~ I Alkx:don r~ fo ~) 527.700 $ 8,000.000 4)887,800 12.1187.800 1.e00.000 2.534.500 $ 17.550.000 $ (c) (~ (,) 527.700 TOtl~ O# I.a~x~ 8.000.000 Alloc-Ftx~l 4,887)1100 12.887.800 1.eO0.0~O Alk~.-k"~d 2.534.600 To~ D~ I J i l ~ $ 17,5~0,1000 0 t~ Q Q Q I Q Q Q $ 2e.437.000 $ (7.2sr,ooo) 24.500,000 (24.S00.000) 24,500.000 34,104.300 (~4J 04.~00) 34.104.300 8.70e.300 1g.038.D00 23,284~300 126,816.800 $ $ $ 26,437.000 ALIoo4=~d (7.25?.000) 24.800.000 (24,5OO.OOO)AJk~.-F~x~ 24.600.000 34.104,300 Aloc-Fo~ (34,104,300) 34.104.300 Aloc-Fo~ 6.709.300 AI0c-Fomd I e.0~,Q00 Aloc-Fb~ 23~2a4~300 1;~.81e.~00 144.3e~.800 fo fl fo fo M 0 M LamRe~n~tu~gCUltalC4o~s(2000,2001,2002,~nd200~Imme)-$(LRCCap~ $ ~44.~ee.~oo $ $ Q t~ 0 fl fo r~ M ~0 o I (1) From E x ~ 3 (GWP-3}. Schedule e.0 In FERC 0o¢~1( No. ER04(2) From At~chme~t A to 2001. 2002. and 2003 C~01tll Fun~lg T I l l . o o o I 3 (ow~-~ 0 fl I fO Urm No. (i) 2 3 4 6 7 8 9 10 11 12 13 14 15 le 17 18 19 2O 21 22 23 24 25 2~ 27 28 2G 3O 2004 I r m a : B~L1~1~0~1~ itllpIOV.(Retry WO~lpeCe. tle~lR)~ & IK)k~ t l l t ~ ) Ma~ke(Symm B V l l n c 4 m e ~ - S~D Ent~em~ to O t ~ - E~o~n0 M i t ~ S y m m T(XaJ HInlWlm lind ~ upgn~lu kx F . ~ Madmt m H a r m ~ ~ S o n w ~ Up0mda to E~4~ng Non I/~ket Symms In~m~J 0ev~opme~ C ~ ToeJ 2004 I l l . h i . $ .% 2000, 2001, 2002 told 20e3 t m m l . $ 2003 Finn0 for 2003 To~i 2003 R~n0 fo~ 2003 CMS~SS (o~ SMO) 2002 Supp~nenml Fire0 Fo~2002 For CJ4S4~ISS(o~SMO) 2002 Sup¢lemln~ Fing Fo* 2002 Fo~ CI4S41~ (c~ SMO) 2002 S~o~wnentll F~i~o For 2002 For CMS414SS(or SMO) 2002 F~lg F~r 2g02 For CMS4MSS (m SMD) 2002 Filing For 2002 R x ~ (o~ SMD) 2002 Filing For 2002 Fat CMSA~S (c¢ SMD) 2002 Firing For 2002 Fat O~et 2001 FIkng fo~ 2(X)1Totll 2001 F~,t)gfor 2000 TatJ T0tld 2000.2(X)1. 2002 WI(I 2g03 LRC C~1 Itllml .% s~.~l~ I (f) $ 527.700 $ 8,000.000 4~887,800 12.887.800 1.800.000 2.~34.500 $ 17.~.000 $ 100.00% 26.437.000 $ (7~S?.000) (11) 113.71g $ T,~ p~) 273.~ 5.240.000 3~01,809 8,441,80111 1.048,000 1.$11,632 11,074~25 $ 63.10% 21.888.149 $ (6,531,300) $ (1) 140.89e AdnVFinancl/HR.Ind~lCtAd~Sui~oott 2.7eo.ooo SW ~eveo~nent. Ex~ng M I ~ Symm 1~a~14.21;11 SVt{De~opmen~. Exi~RJngMItI¢~ ~t1~11 4.444~.2~1 852.ooo s w o e ~ o p m ~ . F . ~ 0 M ~ m Symm 876.734 AcVn4:~encl~ R - In~ln~ Aclmlnl~l~V~ Suppo~ 5.81S.921 33.14% 3.m.loe (72S.700) 4.m.43S (4.930.438) 2.4~0.000 5.934.148 (5.934.148) 3.410.4.10 2.043~47 3.924,496 5,857~07 20.792.788 16.40% 26.60~.709 b m ~ On A I o c a ~ In D~V~t No. ER03-147-000 (3) 8~ed On A I o ¢ ~ ~ Ooct~ No. ER03-147.000 (3) b l e ~ On Aloca~r4 In 0 ~ No. ES02-49-000 (3) B a l ~ On Aloca~ns In 0 ~ No. ES0~-4~0OO(3) Co*m~d Agecl~on PI~ k~O S ~ Baled On ~ In Ood~t No. ER1~-249-000 (3) B l e d On ~ In D o d ~ No. ER02-24e-OO0(3) CotYiclld Nlocl~on Pet ISO S~ff BNId On A g g c l ~ n i In Dgdm~ No. ER02-249-0(X)(3) B4medO~Nk)cl~on~lnDoctm~No ER01-318-000(3) Bu41dOnNtoca6x)nslnDoc~e~No ER01-316-000(3) (-t 12~1 ~52g ~2e e52g es2e 12~51 0 hh 0 0 Q I 84~.135 (L~1.854 $ 3.76% 738.743 II - Q Q Q $ fO fl fO < fO D. 24.500.000 (24,S00,0~0) 24.500,00O 912.504 0~12,~e4) 18.847.971 (18,847,971) 22,O5O.00O e4,1o4.~o Cs4.1o~.~oo) e~e,~o~ (a~e,so3) ~,~s~,e4e $ (27,~,e4~) ~4,104.3~ o 30,~,8T0 6.70g.3~0 978,480 3.6417.864 19.038.G(X) 784.173 14.330~31 23~284~300 1~3iK1~853 16~0~14~240 128.818.800 $ 3.892.2~8 S 102.131.754 $ 100.00% 3.07% 80.53% 144.366.8~0 S 4.552.112 $ 113~05.g79 $ M 0 m M Q t~ Q Q 0 fl fO M ~0 0 I (1) FrOthExt~it 3 (GWP-3). ~:fledukl 8.0 in FERC 0ockM No. ER04{2) From Atta~m4nt A to 2001. 2002, and 2003 Cllpbl Funding TJnll. 0 0 0 I Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 4 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Particimmts Commlttee Members and AllCcrnates Charles Sjoberg AES Londonderry c/o AES Odyssey 1001 West Seneca Street Suite I00 Ithaca, NY 14850 Chris Wendent (Alt) AES Londonderry c/o AES Westover 720 Riverside Drive Johnson City, NY 13790 Carl Peterson AIG Energy, Inc. One Greenwich Plaza Greenwich. CT 06830 Hilary Garfein (Air) AIG Energy, Inc. One Greenwich Plaza Greenwich, CT 06830 Ron McNamara American Electric Power Service Corporation One Riverside Plaza 14th Floor Columbus, OH 43215 Thomas Chapman (Air) American Electric Power Service Corporation One Riverside Plaza 14th Floor Columbus, OH 43215 October 16, Paul Krebs Credit Manager Aquila Merchant Services, Inc. c/o Aquila Inc. 20 W. 9th Street, 3rd Floor Annex Kansas City, MO 64105 Peter W. Brown (Alt) ARomey Aqulia Merchant Services, Inc. c/o Brown, Olson & Wilson, P.C. 501 Sooth Street Concord, Nil 03304 Stanley W. HerrioR Manager As~lmrnham Municipal Light Plant 78 Central Street P.O. Box 823 Ashbumham. MA 01430 Roger W. Bacon (Air) Ashburnham Municipal Light Plant c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Robcn Ruddock Executive Vice President Associated Industries of Massachusetts Suite 1300 222 Berkeley Street Boston, MA 02117 Angela M. O'Connor (Alt) Vice President of Energy Programs Associated Industries of Massachusetts 13th Floor 222 Berkeley Street Boston, MA 02117 Jonathan Tucker Bank of Amerka 9 West 57th Street New York, NY 10019 Dorothy J. Cepra Director Regulatory Affairs ANP Marketing Comlnmy 62 Forest Street, Suite 102 Marlborough, MA 01752 William Henson (AIt) Director, Power Marketing ANP Marketing Company 62 Forest Street. Suite 102 Marlborough, MA 01752 -1- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL ParttciNnts ~ t t e e Members and Alternat~ Jeffrey A. Jones Manager-Legal & Regulatory Services Bangor Hydro-Electric Company 33 State Street P.O. Box 932 Bangor. ME 04402-0932 Gregory Hines (Alt) Director of Business Services Bangor Hydro-Electric Company 33 State Street P.O. Box 932 Bangor, ME 04402-0932 Timothy L. McCarthy Manager Belmont Municipal Light Department 450 Concord Avenue Belmont, MA 02478 Roger W. Bacon (Air) Belmont Municipal Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Robert A. Weishaar. Jr. Counsel BOC Energy Services, inc. c/o McNees Wallace & Murick LLC 777 North Capitol Street, N.E. Suite 401 Washington. DC 20002 Larry Stalica (AI0 Vice President BOC Energy Services, Inc. 575 Mountain Avenue Murray Hill, NJ 07974 James Daly Director. Electric and Gas Energy Supply Beston Edison Company c/o NSTAR One NSTAR Way Mail Stop NE 220 Westwood, MA 02090 October 16. 2003 Robert P. Clarke (Alt) Director. Energy Planning and Supply ~ n Edison Company c/o NSTAR 800 Boylston Street (P1704) Boston. MA 02199-8001 H. Bradford White, Jr. Manager Boylston Municipal Light Depariment Paul X. Tivnun Road P.O. Box 753 Boylston, MA 01505-0753 Roger W. Bacon (Air) Boylston Municipal Light Department c/o Mass. Municipal Wholesale Electric Co. M(xxty Street P.O. Box 426 Ludlow. MA 010560246 Robert Scavone BP Energy Company 501 WestLake Park Boulevard Houston. TX 77079 Jason Stever (Alt) BP Energy Company 501 WestLake Park Boulevard Houston. TX 77079 Laurie J. Heffron Electric Operations Manager Brnintree Electric Light Department 150 Potter Road Braintree, MA 02184-3598 John P. Coyle (Air) Braintree Electric Light Department c/o Duncan & Allen 1575 Eye Street, NW Washington. DC 20005-1175 Paul Jutras Bn~can Energy Marketing, Inc. 2 Montreal Road West Masson-Angers,Quebec. CANADA JgM IK6 -2- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Particimmts C..ommlttc¢ Membfrt and Alternat~ Richard St. Jean (Alt) Brasean Energy Marketing, Inc. 2 Montreal Road West Masson-Angers,Quebec, CANADA JSM 1K6 Thomas Kaslow Calplne Energy Services, LP c/o Calpine Eastern Corporation The Pilot House, 2nd Floor Lewis Wharf Boston, MA 02110 Jeff Woodall (AIt) Lead Scheduler Calplne Energy Services, LP 700 Louisiana Ave., Ste. 2700 Houston, TX 77002 Margaret Downey Asst. County Administrator Cape Light Compact, The 3195 Main Street P.O. Box 427 Bamstable, MA 02630 Robert Bigelow (AIt) Cape Light Compact, The P.O. Box 165 Woods Hole, MA 02543 John Trimble Business Development Manager Cargill Power Markets, LLC 12700 Whitewater Drive Minnetonka. MN 55343-9439 Gaston Garrido (Alt) Trading Manager Cargill Power Markets, LLC 12700 Whitewater Drive Minnetonka, MN 55343-9439 Eric N. Stinneford Manager, Power Contracts Administration Central Maine Power Company 41 Anthony Avenue Augusta, ME 04330 October 16. 2003 Hariph M. Smith (AIt) Central Maine Power Company 41 Anthony Avenue Augusta, ME 04330 Jeffrey R. Cady Power Resource Manager Chlcopee Municipal Lighting Plant 725 Front Street P.O. Box 405 Chicopee.M A 01021-0405 Brian Forshaw Chlcopee Municipal Lighting Plant c/o Connccticut Municipal Electric Energy Cooperative 30 Stott Avenue Norwich, CT 06360-1535 Jason Barker The Cincinnati Gas & Electric Company, Ine. 139 East 4th Street EA503 Cincinnati, OH 45202 Walt Yaeger (AI0 The Cincinnati Gas & Electric Company, Inc. 139 East 4th Street EAS03 Cincinnati, OH 45202 Murat Alptekin Director Citadel Energy Products LLC c/o Citadel Investment Group, LLC 225 W. Washington St., 9th Fi. Chicago, IL 60606 Peter Sullivan (AI0 Vice President Citadel Energy Products LLC c/o Citadel Investment Group, LLC 225 W. Washington St., 9th FI. Chicago, IL 60606 Daniel J. Sack Superintendent Concord Munidpni Light Plant 1175 Elm Street P.O. Box 1029 Concord, MA 01742-1029 -3- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL l~rl~ipants Commltt~ Meml?frs an4/51teruaf~ Roger W. Bacon (Alt) Concord Municipal Light Plant c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Marj Garbini Transmission Engineer Conectiv Energy Supply, Inc. P.O. Box 6066 Newark, DE 19714-6066 Bill Fehr (Alt) Power Trading Manager Conectlv Energy Supply, Inc. P.O. Box 6066 Newark, DE 19714-6066 Brian E. Forshaw Director Connecticut Municipal Electric Energy Cooperative 30 Stott Avenue Norwich, CT 06360-1535 Maurice R. Scully (AIt) Executive Director Connecticut Municipal Electric Energy Coopersflve 30 Stou Avenue Norwich. CT 06360-1535 Kenneth Bekman Director, Wholesale Power Consolidated Edison Energy, Inc. 701 Westchaster Avenue Suite 320E White Plains, NY 10604 Michael Forte (Air) General Manager Consolidated Edison Energy, Inc. 4 Irving Place, Room 1349S New York, NY 10003 Carrie Cullen-Hitt (AIt) Constellation Power Source, Inc. 111 Market Place Suite 500 Baltimore, MD 21202 4- October 16. 2003 Daniel W. Allegretti Constellation Power Source, Inc. One Essex Drive Bow, NH 03304 Matthew Flcardi Coral Power, LLC General Manager - Regulatory Affairs 27 Winthrop Rd. Hingham, MA 02043 Robert Reilley (Air) Vice President-Regulatory Affairs Coral Power, LLC 909 Fannin Street Suite 700 Houston. TX 77010 Coleen O'Brien-Pitts Electric Utility Director Donvers Electric Division One Burroughs Street Danvers, MA 01923-2702Francis M. Gaffney (AIt) Power Supply Engineer Danvers Electric Division One Burroughs Street Danvers, MA 01923-2702 Dean L. Wilde. II Managing Member DC Energy, LLC 8065 Leesburg Pike; Suite 500 Vienna, VA 22182 Ware Adams (Air) Vice President DC Energy, LLC 8065 LeesburgPike; Suite 500 Vienna, VA 22182 Thomas E. Atkins President Demand Response Provider Group Member c/o Pinpoint Power LLC 1040 Great Plain Avenue, 2rid Floor Needham, MA 02492 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Por~tclnants Co~mittee Members and Alternates October 16, 2003 Ken Roberts. Jr. (Air) Demand Response Provider Group Member c/o Pinpoint Power LLC 1040 Great Plain Avenue. 2nd Floor Needham, NLA 02492 Gregory Pakela Manager of Operations DTE Energy Trading, Inc. 101 N. Main Street Suite 300 Ann Arbor, MI 48104 Alan Cberkas (Air) Originator DTE Energy Trading, Inc. 414 SouthMain Street Suite 200 Ann Arbor, MI 48104 Stecy L. Dimou Duke Energy North America LLC P.O. Box 426 Millinocket, ME 04462 Steve Vavrik Director Dynegy Power Marketing, Inc. c/o Dynegy Marketing & Trade 1000 Louisiana Suite 5800 Houston, "IX 77002 Miles Allen (Alt) Sr. Vice President Dynegy Power Marketing, Inc. 101 Merrimic Street. 2nd Floor Boston. MA 02114 William Roberts SVP Power Contracting Edison Mission Marketing & Trading, Inc. 160 Federal Slxeet Boston, MA 02110-1776 Jeffry Ellis (Alt) Edison Mission Marketing & Trading, Inc. 160 Federal Street Boston, MA 02110-1776 Gustav Bereel Manager El Cap II, LLC cJo Enva Power, Inc. One Memorial Drive, 17th Floor Cambridge. MA 02142 Tedann Olsen (AIt) Marketing Communications Manager El Cap II, LLC c/o Enva Power. Inc. One Memorial Drive, 17th Floor Cambridge, MA 02142 Marti Fischer El Paso Merchant Energy, LP 1001 Louisiana Street T8 Houston, T X 77002 Robert Stein (Alt) Principal Consultant El Paso Merchant Energy, LP c/o Signal Hill Consulting Group 128 Merchants Row Suite 703 Rutland, VT 05701 Calvin P. Deschene Director Energy Atlantic, LLC 830 Main Street Suite 20 P.O. Box 1148 Prosque Isle, ME 04769-1148 Don Theriault (AIt) Forecast Analyst Energy Atlantic, LLC P.O. Box 1148 Presque Isle, ME 04769-1148 Dennis J. Duffy Energy Management, Inc. One Energy Road North Dartmouth, MA 02747 Chris Sherman (Air) Energy Management, Inc. One Energy Road North Dartmouth. MA 02747 -5- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Participants Committee M be and Re Marc Potkin Entergy Nuclear Generation Company 440 Hamilton Avenue White Plains, NY 10601 William Stone (Alt) Entergy Nuclear Generation Company 600 Rocky Hill Road Plymouth, MA 03260 Steve Gilbert Exelon Generation Company, LLC c/o Exelon Power Team 300 Exelon Way Kennette Square, PA 19348 Jack Crowley (Air) Exeion Generation Company, LLC c/o Exelon New England Holdings, LLC The Schrafft Center 529 Main Street Suite 605 Charlestown, MA 02129 Donald J. Sipe Forster, Inc. c/o Preti, Flaherty, Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, ME 04332-1058 Anthony Buxton (Alt) Forster, Inc. c/o Preti, Flaherty, Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, M E 04332-1058 Femando DaSilva (Alt) Director, Market Affairs FPL Energy LLC 8 Woodlawn Road Assonet, MA 02702 Donald J. Sipe Gardincr Paperbeard c/o Preti. Flaherty, Beliveau, Pachios & Hale), 45 Memorial Circle P.O. Box 1058 Augusta,M E 04332-1058 6- October 161200.~ Anthony Buxton (AIt) Gardlner Paperlmard c/o Preti, Flaherty.Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta.M E 04332-I058 William P. Short Ill Generation Group Member c/o Ridgewood Power Management, LLC 947 Linwood Avenue Ridgewood, NJ 07450 Anthony M. Callendrcllo Chief Operating Officer Great Bay Power Marketing, Inc. 222 International Drive Suite 125 Portsmouth, NH 03801-6819 William Rodgers (Alt) Director of Marketing Great Bay Power Marketing, Inc. 51 Dow Highway. Suite 7 Eliot, ME 03903 Wayne Snow Manager Georgetown Municipal Light Department 94 Searle Street Georgetown, MA 01833 Roger W. Bacon (Air) Georgetown Municipal Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Doffs Chojowski Manager Groton Electric Light Department 23 Station Avenue Groton, MA 01450-4222 Roger W. Bacon (AIt) Groton Electric Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Participants Committee Meml~rS and Alternates Ariane Connor H.Q. Energy Services (U.S.) Joe. 75, houl. Rene-Levesque Ouest 17e etage Montreal, Quebec H2Z IA4 CANADA Robert Stein (AIt) Principal Consultant H.Q. Energy Services (U.S.) Inc. c/o Signal Hill Consulting Group 128 Merchants Row Suite 703 Rutland, VT 05701 Joseph R. Spadea Jr. Manager Hlngham Municipal Lighting Plant 222 Central Stre~ I-lingham,M A 02043-2518 Roger W. Bacon (Alt) Hlngham Municipal Lighting Plant c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Roger W. Bacon (AIt) Holden Municipal Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 James M. Lavelle Manager Holyoke Gas & Electric Department 99 Suffolk Street Holyoke. MA 01040 Brian C. Beanregard (Air) Superintendent Holyoke Gas & Electric Department 99 Suffold Street Holyoke, MA 01040 October 16. 2003 Anthony J. Monteiro General Manager Hudson Light & Power Department 49 Forest Avenue Hudson, MA 01749 Roger W. Bacon (Alt) Hudson Light & Power Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 010564)246 John A. MacLeod Manager Hull Municipal Lighting Plant 15 Edgewater Road Hull, MA 02045-2714 Roger W. Bacon (Air) Hull Municipal Lighting Plant c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Maurice T. Klefeker Asset Manager lndeek Pepperell Power Associates, Inc. 1075 Noel Avenue Wheeling, Iv 60090 Mark V. Magyar (Air) Consultant lndeck Pepperell Power Associates, Inc. c/o Financial Management Co. 325A Southbridge Street Auburn, MA 01501 Donald J. Sipe Industrial Energy Consumer Group c/o Prcti. Fiaherty. Beliveau. Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta. ME 04332-1058 -7- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Porticimmts ¢onul~ttee Members and Alternates Anthony Buxton (Alt) Industrial Energy Consumer Group c/o Preti, Haherty, Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, ME 04332-1058 Sandra Gillis Business Manager Industrial Power Services Corp. Business Manager 60 East Street (rear) Ware, MA 01082 James M. Malandrinos (Air) President Industrial Power Services Corp, Business Manager 60 East Street (rear) Ware, MA 01082 Raymond R. Shnekey Manager Ipswich Municipal Light Department P.O. Box 151 272 High Street Ipswich, MA 01938-0151 Roger W. Bacon (Air) Ipswich Municipal Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Gordon van Welie ISO New England Inc. One Sullivan Road Holyoke, MA 01040-2841 Kevin Kirby (Air) ISO New England Inc. One Sullivan Road Holyoke, MA 01040-2841 Kathy Benini (All) J, Aron & Company 85 Broad Street New York, NY 10004 Oetober 16. 2003 Thomas Hoatson Vice President J. Avon & Company c/o Goldman Sachs & Company 85 Broad Street New York, NY 10004 Robert J. Gray President J.F. Gray & Associates LLC 35 Woodman Road South Hampton, Nil 03827 John F. Gray (Alt) J.F. Gray & Associates LLC 35 Woodman Road South Hampton, NH 03827 LaPorta, Leonard 150 West Newton Street Boston, MA 02118 James Parmelee Director of Power Markets LIPA 31 Brinker Drive South Rensselaar, N Y 12144 William Killgoar (Alt) LIPA c/o Navigant Consulting Inc. 200 Wheeler Road Burlington, MA 01803 Scott Edwards Assistant General Manager Llttleton Electric Light & Water Department 39 Ayer Road P.O. Box 2406 Littleton,M A 01460-3406 Roger W. Bacon (Air) Littleton Electric Light & Water Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, M A 01056-0246 -8- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Particimmt~ Committ~ Members and A l t e r n g ~ Stephen M. Crauthier Program Manager Maine Health & Higher Educational Facilities Authority 3 University Drive P.O. Box 2268 Augusta, ME 04338-2268 Robert O. Lenna (Air) Executive Director Maine Health & Higher Educational Facilities Authority 3 University Drive P.O. Box 2268 Augusta, ME 04338-2268 Donald J. Sipe Maine Skiing, Inc. c/o Prcti, Flaberty, Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, ME 04332-1058 Anthony Buxton (Air) Maine Skiing, Inc. c/o Preti, Flabeny, Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, ME 04332-1058 John J. Beliveau Director Mansfield Electrk Light Department 125 High StreeL Suite 4 Mansfield, MA 02048-2404 Roger W. Bacon (AIt) Mansfield Electric Light Deparlment c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 010564)246 Robert V. Jolly Jr. Manager Marblehead Municipal Light Department 80 Commercial Street P.O. Box 369 Marblehead, MA 01945-0369 October 16, 2003 Roger W. Bacon (Alt) Marblehead Municipal Light I~partnwnt edo Mass. Municipal Wholesale Electaic Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 James Johnson Marquette Energy, LLC 801 W. Adams #500 Chicago, IL 60607 Ginny Urquhart (AI0 Marquett¢ Energy, LLC 801 W. Adams #500 Chicago, IL 60607 John J. McSweeney, Jr. Director of Operations Support Massachusetts Bay Transportation Authority 45 High Street Boston, MA 02110 Maybew Seavey (AIO Principal Massachusetts Bay Transportation Authority c/o PLM, Inc. 35 Main Street Hopkinton, MA 01748 Roger W. Bacon Director. Power Services Division Mass. Munlelpai Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Timothy Peet (Alt) Mass. Munldpai Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Frank Gorke Massachusetts Public Interest Research Group 29 Temple Place 5th Floor Boston. MA 02111 -9- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Partlelmmts C,.ommlttt¢ Mfmbers an0 A l t e r n a ~ Robert Sargent (Air) Massachasetls Public Interest Research Group 29 Temple Place 5th Floor Boston, MA 02111 Donald J. Sipe Mead Oxford Corporation c/o Preti, Flaherty, Beliveau, Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, ME 04332-1058 Anthony Buxton (Air) Mead Oxford Corporation c/o Preti. Plaheny. Beliveau. Pachios & Haley 45 Memorial Circle P.O. Box 1058 Augusta, ME 04332-1058 James L. Collins Energy Analyst Middleboraugh Gas & Electric 2 Vine Street Middleborough, MA 02346 Roger W. Bacon (Air) Middleborough Gas & Electric c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Mark T. Kelly Manager Mlddleton Municipal Light Department 197 North Main Street Middleton, MA 01949-1068 Roger W. Bacon (Air) Mlddleton Municipal Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 01056-0246 Jeffrey Perry (Alt) Mlrant New England, LLC Canal Station - 9 Freezer Road P.O. Box 840 Sandwich, MA 02563 -10- October 16. 2003 Peter D. Fuller Mlrant New England, LLC 1099 Hingham Street Rockland, MA 02370 Levon Kazerian Vice President Morgan Stanley Capital Group, Inc. 1585 Broadway 4th floor New York, NY 10036 Doron Ezickson (ALL) Morgan Stanley Capital Group, Inc. c/o McDermott, Will & Emery 28 State Street Boston, MA 02109 Michael Hager New England Power Company 25 Research Drive Wastborough, MA 01582 Mary Ellen Paravalos (AR) New England Power Company 25 Research Drive Westhorough. MA 01582 Fred C. Anderson General Manager New Hamln~Ire Electrk Cooperative, inc. 579 Tenney Mountain Highway Plymouth. Nil 03264-3147 Stephen Kaminski (AIt) Director, Energy Access & Services New H m p s h i r e Electric Cooperative, Inc. 579 Tenney Mountain Highway Plymouth, NH 03264-3147 Michael C. White Global Sourcing Manager New H m p s h i r e Industries Inc. 68 Etoa Road Lebanon, NH 03766 J. Todd Miller (AI0 President New Hampshire Industries Inc. 68 FAnaRoad Lebanon. Nil 037645 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL l~rtleimmts Commlllee Members and Alternate# Michael W. Holmes Consumer Advocate New Hampshire Office of Consumer Advocate October 16, 2003 Elizabeth Wisniewski Director of New England Regulatory Affairs NRG Power Marketing Inc. 6 Barton Street Newburyport, MA 01950 Hinwing Lee President Outback Power Marketing, Inc. 16360Park Ten Pl~e, Suite 327 Houston, TX 77084 Theodore O. Garill General Manager Poseong UtilRy 55 Soeth Main Street P.O. Box 107 Pascoag, RI 02859-0107 Roger W. Bacon (AIt) Paseeag Utility District c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Diane Dillman Manager Paxton Municipal Light Department 578 Pleasant Street Paxton, MA 01612-1365 Roger W. Bacon (Air) Poxton Munldpal Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Ronald Tabroff Supervisor, Electrical Engineer Peabody Municipal Light Plant 201 Warren Street, Ext. Peabody, MA 01960-4208 Roger W. Bacon (Alt) 117 Manchester Street Concord. Nil 03301 Paul Peterson (Alt) New H a m ~ Office of C o m m e r Advocate c/o Synapse Energy Economics, Inc. 22 Pearl Street Cambridge, MA 02139 Mark V. Magyar North Attleborongh Electric c/o Financial Management Group 325A Southbridge Street Auburn, MA 01501 Roger W. Bacon (Alt) North Attleboroegh Electric c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Frank P. Sabation Senior Vice President - Power Marketing Northeast Utilities System Companies c/o Select Energy, Inc. 107 Selden Street Berlin, CT 06037 James R. Shuckerow (Air) Director-Wholesale Power Contracts Northeast Utilities System Companies P.O. Box 270 Hartford, CT 06141-0270 Malcolm N. McDonald Superintendent Norwood Municipal Light Department 206 Central Street Norwood. MA 02062-3567 Joseph DeVito Regulatory Specialist NRG Power Marketing Inc. c/o NRG Energy 10 Southpond Circle Cheshire, CT 06410 Peabody Municipal Light Plant c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 -11- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NI~I~OL Parflclnants ~.omml~,~.e M~mbers and Alternates David Facey Solicitor and Counsel Powerex Corp. 66 Burrard Street Suite 1400 Vancouver. BC V6C 2X8 CANADA Michelle Hiley (Alt) Portfolio Manager, Eastern Operations Powerex Corp. 66 Burrard Street Suite 1400 Vancouver, BC V6C 2X8 CANADA Benson Caswell President PowerOptions, Inc. 99 Sununer Street Boston, MA 02110-1240 Douglas Stevenson (Alt) PowerOptions, Inc. Rte. I, P.O. Box 398 Wayne, ME 04284 John F. Brodbeck Energy Consultant PPL EnergyPlus, LLC 2 North Ninth Street Allentown, PA 18101-1179 Garrith W. Kirkner (Alt) PPL EnergyPlus, LLC 2 North Ninth Stree~ Allentown, PA 18101-1179 Robert A. Weishaar, Jr. Counsel Praxalr, Inc. c/o McNoes Wallace & Murick LLC 777 North Capitol Street, N.E. Suite 40 1 Washington, DC 20002 Jennifer Hunsperger (Air) Account Manager, Eastern Region Praxair, Inc. 126 Windham Drive Langhorne, PA 10947 -12- October 1612009 Debra M. Bateman Providence Energy Services, Inc. Mail Stop GENWT21 East Office 56 Exchange Terrace Providence, RI 02903 James M. Stephens (Air) Providence Energy Services, Inc. 56 Exchange Terrace Providence, RI 02903 Joel Gordon Director, Market Policy PSEG Emerg3, Reseeroes & Trade LLC 7 Steeple Lane Ambersl, NH 03031 Daniel P. Ciullo (Air) Marketing Manager- New England PSEG Energy Resources & Trade LLC 80 Park Plaza - TI9 Newark, NJ 07102-4194 Jeffrey D. Jonson Rainbow Energy Marketing Corp. 919 7th St., Ste. 405 Bismark, ND 58504 Joe Wolfe (Alt) Rainbow Energy Marketing Corp. 919 7th St., Ste. 405 Bisrnark, ND 58504 Brian Bacher RAM Energy Products, LLC c/o Ritchie Capital Management 2100 Enterprise Avenue Geneva, IL 60134 Donald Kane (AI0 RAM Energy Prodncls, LLC c/o Ritchie Capital Management 2100 Enterprise Avenue Geneva. IL 60134 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEpOOL Partieloants Committee Membfrs Aqtl Alternates Leonard D. Rucker General Manager Reading Municipal Light Department 230 Ash Street P.O. Box 150 Reading, MA 01867-0250 Vincent F. Cameron Jr. Assistant General Manager - Energy and Operations Reading Municipal Light Department 230 Ash Street Reading, MA 01867-0250 William Seldon (Air) Reading Municipal Light Department 230 Ash Street P.O. Box 150 Reading, MA 01867-0250 Scott Cline Director, Asset Management and Regulatory Affairs Reliant Energy Services, Inc. 1111 Louisiana, 9th flour Houston, TX 77002 Guinette Haas (Alt) Eastern Region. Asset Management Reliant Energy Services, Inc. I 111 Louisiana. 9th floor Houston, TX 77002 G. Robert Merry Manager Rowley Municipal Light Plant 47 Summer Street Rowley, MA 01969 October 16, 2003 Thomas Haileran Sempra Energy TradingGroup 58 Commerce Road Stamford, c r 06902 Mark Magyar (Air) Sempra Energy Trading Group c/o Financial Management Group 325A Southbridge Street Auburn. MA 01501 Michael Schubiger CEO SESCO Enterprises, LLC 120 Wood Avenue South Suite 511 helin. NJ 08830 Patrick Suseri Executive Vice President SESCO Enterprises, LLC 120 Wood Avenue South Suite 511 Iselin, NJ 08830 Thomas R. Josie General Manager Shrewsbury Electric Light Plant 100 Maple Avenue Shrewsbury, MA 01545-5398 Roger W. Bacon (AIt) Shrewsbury Electric Light Plant c/o Mass. Municipal Wholesale Eleclric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Silknmn, Richard 76 Main Street Yarmouth, ME 04096 Roger W. Bacon (Alt) Rowley Municipal Light Plant c,/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Wayne D. Doerpholz Manager South Hadley Electric Light Department 85 Main Street South Hadley. MA 01075-2706 Schaefer, Marc c/o SESCO. Inc. 2 Elmwood Drive Rutland, VT 05701 -13- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Participants Committee Members and Alternates Roger W. Bacon (Air) South Hadley Electric IAght Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. M A 01056-0246 Peter J. Garratt Split Rock Energy Vice President, Power Trading 301 4th Ave South Suite 860N Minneapolis. MN 55415 October 16t 200~; John Kilgo Jr. Manager Sterling Municipal Light Department 50 Main Street Sterling. MA 01564-2129 Roger W. Bacon (AIt) Sterling Muaieipai Light Deparlment c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Matthew Motais Strategic Energy lAd. Two Gateway Center 9th Floor Pittsburgh. PA 15222 Michael Swider (Alt) Strategic Energy Ltd. 33 Sleeper St., Apt. #303 Boston, MA 02210 R. Scott Whittemore Manager Energy Services and Planning Taunton Municipal Lighting Plant 55 Weir Street P.O. Box 870 Taunton. MA 02780-0870 Brian Forshaw Taunton Municipal Lighting Plant c/o Connecticut Municipal Electric Energy Cooperative 30 Stott Avenue Norwich. CT 06360-1535 Roger L. Buck Executive Director TEC-RI 7 Madeline Drive Newport, 17,I 02840-1714 Michael Hoffer (All) Vice Chairman Exec. Board TEC-RI 7 Madeline Drive Newport, RI 02840-1714 Laureen Ross McCalib (Air) Split Rock Energy Vice President, Power Marketing 301 4th Ave South Suite 860N Minneapolis, M N 55415 Jamie Cote (AIt) Sprngne Energy Corp. T w o InternationalDrive Portsmouth, N H 03801-6809 Mary J. Healey State of Connect/cuL Office of Consumer Counsel Ten Franklin Square New Britain, CT 06051 Nancy A. Harnick (AIt) State of Connecticut, Offke of Consumer Counsel Ten Franklin Square New Britain, CT 06051 Julie Hasham Policy Development Specialist State of Maine, Offk'e of the Governor 38 State House Station Augusta, ME 04333-0038 Stephen G. Ward (AIt) Public Advocate State of Maine, Office of the Governor 112 State House Station Augusta, ME 04333 -14- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Parl]cipante Committee Meml~r~ and A~rn~Ws Gerald P. Skelton Manager Templeton Municipal Light Plant School Street Baldwinville, MA 01436 Roger W. Bacon (Air) Templeton Municipal Light Plant c/o Mass. Municipal Wholesale ElectricCo. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 Jeffrey Bergman Utilities Manager Texas Instruments MS 10-04 34 Forest Street Attlebom, MA 02703 Mark Sestak (Alt) Facilities Engineer Texas Instruments MS 10-O4 34 ForestStreet Attleboro,M A 02703 Jeffrey Bergman The Energy Consortium MS 10-04 34 Forest Street Attleboro, MA 02703 Roger Borghesani(Alt) Chairman The Energy Consortium 24 HastingsRoad Lexington,M A 02421-6807 Mark T. Ladrow Marketing Manager Tractebel Energy Marketing, Inc. 15 New England Executive Park Suite 205 Burlington, MA 01803 October 16, 2003 Chris Bergamini Power Trader TransAita Energy Marketing (U.S.) Inc. 151 West Street Suite 300 Annapolis, MD 21401 Dan LoBue Power Trader TransAlta Energy Marketing (U.S.) Inc. 151 West Street Suite 300 Annapolis, MD 21401 William C. Taylor Vice President TransC.anada Power Marketing Ltd. 110 Turnpike Road Suite 203 Westborough, MA 01581 Michael ~ Hachey (All) Director, Power Marketing TransC.anada Power Marketing Ltd. 110 Turnpike Road Suite 203 Westborough, MA 01581 Michael S. Grim Director, Markets & Regulatory TXU Portfolio Management Co. liP 1717 Main Sunet, Suite 17000 Dallas, TX 75201 Brian Agree (AI0 TXU Portfolio Management Co. LP 1717 Main Street Suite 2000 Dallas, TX 75201 Kevin M. Foley General Manager UAE Lowell Power LLC 2 Tanner Street Lowell, MA 01852 Teri M. Pageno (AIt) UAE Lowell Power LLC c/o United American Energy Corp. 50 Tice Boulevard WoodcliffLake, NJ 07677 -15- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NEPOOL Participants Committ~ Members and Alternates James Steffes Qftober 16. 2003 Thomas N. Wies Vice President & General Counsel Vermont Electric Power Company, Inc. 366 Pinnacle Ridge Road Rutland, VT 05701 Gerald Spring (Air) Vermont Electric Power Company, Inc. 366 Pinnacle Ridge Road Rutland, VT 05701 William J. Gallaghar General Manager Vermont Public Power Supply Authority P.O. Box 298 Waterbury Center, VT 05677 Brian Evans-Mongeon (AIt) Manager of Power Supply & Marketing Service Vermont Public Power Supply Authority P.O. Box 298 Waterbury Center, VT 05677 Ron Armstrong Virginia Electric and Power Company 5000 Dominion Blvd. 3N Glen Allen, VA 23060 Michael Bekker (AI0 Virginia Electric and Power Company 440 Windy Hill Road Orange, CT 064770 William J. Wallace Manager Wakefield Municipal Gas and Light Department 9 Albion Street P.O. Box 190 Wakefield, MA 01880-0390 Roger W. Bacon (Air) Wakefield Municipal Gas and Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 01056-0246 UBS AG c/o UBS Warburg Energy LLC 1500 Louisiana Street Houston, "IX 77002 Deborah Donovan Union of Concerned Scientists c/o Synapse Energy Economics, Inc. 22 Pearl Street Cambridge, MA 02139 Paul R. Peterson Union of Concerned Scientists c/o Synapse Energy Economics, Inc. 22 Pearl Street Cambridge, MA 02139 Robert T. Gagliardi Director, Strategic Policy The United Illuminating Company 157 Church Street - 1-15D P.O. Box 1564 New Haven, CT 06506-0901 Dennis I-Irabchak (Alt) Vice President Regulatory Policy The United llluminaling Company 157 Church Strcet-15th Floor P.O. Box 1564 New Haven, CT 06506-0901 David K. Foote Vice President Unitil Corporation Participant Companies 6 Liberty Lane West Hampton, NH 03842-1720 Philip C. Smith USGen New England, Inc. d o PG&E Energy Trading One Bowdoin Square Boston, MA 02114-2910 Chris Bursaw (AIt) USGen New England, Inc.. c/o PG&E Energy Trading 50 Congress Street, Suite 310 Boston, MA 02109 -16- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 NI~PQOL Partteimmts Committe~ Memlpers and ~Iternallfs Mark Noyes WebGen Systems inc. 41 William Linsky Way Cambridge, MA 02142 Paul Taglianetd (Alt) WebGen Systems Inc. 41 William Linsky Way Cambridge, MA 02142 Joyce M. D. Wood (Alt) Wellesley Municipal Lighting Plant c/o Onway Lake Consulting 11 Forest Road Raymond, NH 03077 John Scirpoli Manager West Boylston Municipal Lighting Plant 4 Crescent Street West Boylston, MA 01583-1310 Ocq#~r 16. 2003 Dennis Keener (Ah) Williams Energy Marketing & Trading Company One Williams Center Mail Drop 35-7 P.O. Box 3448 Tul~l, OK 74101-9567 Tim Charette Power MarketingExecutive WPS Energy Services Inc. 1242 Lower Lyudon Street Caribou, ME 04736 Ed Howard (Alt) Power Marketing Executive WPS Energy Services Inc.. 1242 Lower LyndoflStreet Caribou, ME 04736 Roger W. Bacon (Ah) West Boylston Municipal Lighting Plant c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow. MA 010560246 Daniel Golubek (Alt) Manager Westileld Gas and Electric Light Department 100 Elm Street Westfield, MA 01085-2907 Roger W. Bacon (Air) Westfleld Gas and Ekctric Light Department c/o Mass. Municipal Wholesale Electric Co. Moody Street P.O. Box 426 Ludlow, MA 010564)246 David K. Singer Williams Energy Marketing & Trading Company One Williams Center Tulsa. OK 74172 -17- Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Non-Participant Transmission C u s t o m e r s July 31, 2003 Miller Hydro Group P.O. Box 97 Lisbon Falls, ME 04252-0097 Massachusetts Government Land Bank Devens Commerce Center 43 Buena Vista Ft. Doyens, MA 01433 Groveland Municipal Light Department 23 School Street Groveland, MA 01834 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 New England Governors and Utility Regulatory and Related Agencies Connecticut The Honorable John G. Rowland State Capitol 210 Capitol Ave. Hartford, CT 06106 Maine The Honorable John Baldueci One State House Station Rm. 236 Augusta, ME 04333-0001 Massachusetts The Honorable Mitt Romney Office of the Governor Rm. 360 State House Boston, MA 02133 New Hampshire The Honorable Craig Benson State House Rm. 208 Concord, NH 03301 Rhode lsl0nd The Honorable Donald Careieri State House Rm. 143 Providence, RI 02903 Vermont The Honorable James Douglas 109 State Street Montpelier, VT 05609 September 8, 2003 Connecticut Department of Public Utility Control 10 Franklin Square New Britain, CT 06051-2605 Maine Public Utilities Commission State House, Station 18 242 State Street Augusta, ME 04333-0018 Massachusetts Department of Telecommunications and Energy One South Station Boston, MA 02110 New Hampshire Public Utilities Commission 8 Old Suncook Road - Building #1 Concord, NH 03301 Rhode Island Public Utilities Commission 89 Jefferson Boulevard Warwick, RI 02888 Vermont Public Service Board 112 State Street, Drawer 20 Montpelier, VT 05620-2701 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 New England Governors and Utility Regulatory and Related Agencies ~eptember 8~ 2003 Elia Germani, President New England Conference of Public Utilities Commissioners, Inc. c/o Rhode Island public Utilities Commission 89 Jefferson Boulevard Warwick, RI 02888 Amy Ignatius, Esq. Executive Director New England Conference of Public Utilities Commissioners, Inc. One Eagle Square Suite 514 Concord, Nil 03301 Harvey L. Reiter, Esq. Counsel for New England Conference of Public Utilities Commissioners, Inc. c/o MORRISON HECKER ll50 18th Street, N.W., Suite 800 Washington, DC 20036-3816 Power Planning Committee New England Governors Conference, Inc. 76 Summer Street, 2nd Floor Boston, MA 02110 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 5 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 5 CROSS-REFERENCE TABLE (showing location of applicable items from Statements AA - BM in Section 35.13(h)) Statement AA Statement AB Statement AC Statement AD Balance sheets: See 2002 ISO Form 1. Income statements: See 2002 ISO Form 1. Retained earnings statement: not applicable Cost of plant: The ISO's "plant" consists of office furniture and equipment (Account 391). The ISO does not own generation, transmission or distribution equipment. See 2002 ISO Form 1 balance sheet at page 110, lines 2 and 4. The three "functions" of the ISO am the three Services provided by the ISO under its administrative costs tariff ("ACT"), as described in the filing letter. Accumulated depreciation and amortization: See 2002 ISO Form 1 balance sheet at page 110, line 5. Specified deferred credits: not applicable Specified plant accounts (other than plant in service): not applicable, because the ISO is not seeking a return on rate base. Operation and maintenance expenses: not applicable Wages and salaries: not applicable, due to the nature of the revenue requirement Depreciation and amortization (lease and sublease) expenses: these are functionalized among the Services as described in the filing letter. Taxes other than income taxes: not applicable Working capital: the Commission has authorized a revolving line of credit of $15 million for the ISO's working capital needs. See 94 FERC 9[ 62,271 (2001). Due to the nature of the limited plant owned by the ISO, the concepts of supplies, fuel supplies, plant materials and operating supplies arc not applicable to the ISO. Prepaid expenses for the ISO consist mainly of insurance costs. Construction work in process: not applicable Statement AE Statement AF Statement AG Statement AH Statement AI Statement AJ Statement AK Statement AL Statement AM OC_DOCS_A #11(~782 v2 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : ER04-114-000 Exhibit $ Statement AN Notes payable: see description of notes authorized in 94 FERC | 62,271, 94 FERC Cl62,272, 97 FERC tl 61,304 (2001), 100 FERC ~I61,140 (2002) and 101 FERC c[ 61,188(2002). The ISO is also filing a new request for Section 204 approval from the Commission to borrow additional funds necessary to support the activities and capital expenses described in the filing letter. Rate for allowance for funds used during construction: not applicable Federal income tax deductions - interest: The ISO is exempt from federal income taxation. Federal income tax deductions - other than interest: The ISO is exempt from federal income taxation. Federal tax adjustments: The ISO is exempt from federal income taxation. Additional state income tax deductions: The ISO pays no state income taxes. State tax adjustments: The ISO pays no state income taxes. Revenue credits: not applicable Rate of return: not applicable because the lSO seeks no rate of return, Statement AO Statement AP Statement AQ Statement AR Statement AS Statement AT Statement AU Statement AV Statement AW Statement AX Statement AY Cost of short-term debt: no short-term debt. Other recent and pending rate changes: not applicable. Income and revenue tax rate data: not applicable because the ISO pays no federal or state income tax, and no revenue taxes. Wholesale customer rate groups: Statement BA The NEPOOL Participants (see sections 2.A., 2.B. and 2.C. of the CPT for description of charges and cost of service). Statement BB Allocation demand and capability data: not applicable because the ISO's capital revenue requirement is not based on generation or transmission expenses. DC_DOCSJ~ #1106782 v2 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : ER04-114-000 Exhibit 5 Statement BC Reliability data: not applicable because the ISO's capital revenue requirement is not based on generation or transmission expenses. Allocation energy and supporting data: not applicable because the ISO's capital revenue requirement is not based on generation expenses. Specific assignment data: not applicable Exclusive-use commitments of major power supply facilities: not applicable. Revenue data to reflect changed rates: The entire projected capital revenue requirement for a Service (discussed in Exhibit 4 and in the filing letter) is paid for by the corresponding customer group described in the Statement BA discussion, above. The ISO has no fuel clause. Revenue data to reflect present rate: not applicable Fuel cost adjustment factors: not applicable Summary cost tables: See CFT Attachment A (the Revised Sheets). Electric utility department cost of service: the revenue requirement for the CFT is described in Section HI of the filing letter and CFT Attachment A. Rate design information: See Exhibit 3 and Section I of the filing letter. Construction program statement: not applicable. Statement BD Statement BE Statement BF Statement BG Statement BH Statement BI Statement BJ Statement BK Statement BL Statement BM D C _ D O C S J L,#1106782 v2 Jnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 Exhibit 6 lnofflclal FERC-Generated PDF of 20031103-0009 Received by FERC OSEC 10/31/2003 in D o c k e t # : E R 0 4 - 1 1 4 - 0 0 0 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION ISO New England Inc. NOTICE OF FILING ( , 2003) Docket No. ER04- Take notice that on October 31, 2003, ISO New England Inc. (the "ISO") tendered for filing under Section 205 of the Federal Power Act changes to its Capital Funding tariff. The ISO requests that the changes to the Capital Funding Tadffbe allowed to go into effect on January 1, 2004. Copies o f the transmittal letter were served upon each non-Participant entity that is a customer under the NEPOOL Open Access Tranm'nission Tariff, as well as on the governors and utility regulatory agencies o f the six New England States, and the New England Conference o f Public Utility Commissioners. NEPOOL Participants were also served with the entire filing electronically. The entire filing is posted on the ISO's website (www.iso-ne.cem). Any person desiring to intervene or to protest this filing should file with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with Rules 211 and 214 o f the Commission's Rules o f Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be comidered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. All such motions or protests should be filed on or before the comment date, and, to the extent applicable, must be served on the applicant and on any other person designated on the official service list. This filing is available for review at the Commission or may be viewed on the Commission's web site at http://www.fere.gov, using the "eLibrary" link. Enter the docket number excluding the last three digits in the docket number field to access the document. For assistance, contact FERC Online Support at FERCOnlineSupport@fere.gov or toll-flee at (866)208-3676, or for TTY, contact (202)502-8659. Protests and interventions may be filed electronically via the Intemet in lieu o f paper;, see 18 CFR 385.2001(aX1)(iii) and the instructions on the Commission's web site under the "e-Filing" link. The Commission strongly encourages electronic filings. Comment Date: Magalie Roman Salas Seeretary DC_DOCS_A ~ 128673 vl