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STATE OF NEW YORK PUBLIC SERVICE COMMISSION
Case No. 01-M-0075
Niagara Mohawk Power Corporation d/b/a National Grid
PETITION FOR AUTHORIZATION TO DEFER ELECTRIC TRANSMISSION AND DISTRIBUTION INVESTMENT COSTS
December 21, 2007
Volume One (Petition)
NIAGARA MOHAWK POWER CORPORATION
CASE NO. 01-M-0075
PETITION FOR AUTHORIZATION TO DEFER ELECTRIC TRANSMISSION AND DISTRIBUTION INVESTMENT COSTS
Volume One (Petition)
Table of Contents
Filing Letter Service List Petition Figures Referenced in Petition
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Filing Letter
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300 Erie Boulevard West, Law A-3, Syracuse, NY 13202 T: 315.428.5320 F: 315.428.5740 [email protected] www.nationalgrid.com
December 21, 2007 VIA HAND DELIVERY Hon. Jaclyn A. Brilling, Secretary New York State Public Service Commission 3 Empire State Plaza Albany, New York 12223 RE: Case 01-M-0075 -- Joint Proposal of Niagara Mohawk Holdings, Inc. Niagara
Mohawk Power Corporation, National Grid plc and National Grid for Approval of Merger and Stock Acquisition
Dear Secretary Brilling:
Pursuant to Section 1.2.4.16 of the Merger Joint Proposal approved by the Commission in Case 01-M-0075,1 Niagara Mohawk Power Corporation, d/b/a National Grid (“National Grid” or “Company”), encloses for filing a petition for authorization to defer electric transmission and distribution investment costs (the “Petition”) and supporting documents. Specifically, National Grid requests authorization to defer a portion of the revenue requirement impact during 2008 of (1) specified electric transmission and distribution (“T&D”) capital programs and (2) operating expenses that are directly associated with those programs (“capital-related O&M”). In accordance with the Commission’s orders in Case 06-M-0878,2 National Grid’s request is limited to 50 percent of the revenue requirement impact of the capital cost and capital-related O&M for investments that fulfill its commitment in that case to invest $1.47 billion in its T&D system during the five years ending December 31, 2011.
As explained in more detail in the Petition, the immediate impact of granting
National Grid’s request will be modest. The Company’s forecast of eligible deferrals in 2008, including the 50% cap, is $5.3 million. The amount actually deferred would be eligible for recovery from customers as part of the Company’s 4th CTC Reset proceeding, which is expected to produce a rate adjustment in 2010-2011. Nonetheless the Petition is of signal importance because it puts on the agenda, in both a formal and a
1 Case 01-M-0075, Opinion and Order Authorizing Merger and Approving Rate Plan (Dec. 3, 2001) (“2001 Merger Order”). The electric rate plan established in the 2001 Merger Order, which addressed the 10-year period ending December 31, 2011, will be referred to herein as the “Merger Rate Plan.” 2 Case 06-M-0878, Order Authorizing Acquisition Subject to Conditions and Making Some Revenue Requirement Determinations for KeySpan Energy Delivery New York and KeySpan Energy Delivery Long Island (Sept. 17, 2007) (“2007 Merger Order”).
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Hon. Jaclyn A. Brilling, Secretary December 21, 2007 Page 2 colloquial sense, the issue of what requirements National Grid’s T&D system will be expected to meet in the coming decades.
The need for stepped-up investment in National Grid’s T&D system is clear, as
demonstrated by the Company’s commitment to invest at least $1.47 billion during the five years ending December 31, 2011 and as described in detail in National Grid’s October 22, 2007 compliance filing in Case No. 06-M-0878. A key part of that filing, the Capital Investment Plan, identified for possible implementation investment programs with a current estimated cost of $2.4 billion during the five year period ending December 31, 2011.3 Investment at such higher levels, which National Grid believes would be in the interest of customers and which would further the State’s policy objectives, depends on support from the Commission for the Company’s T&D investment program.4 The public policy goals implicated by the scope and shape of future T&D investment include fulfilling customer demands for reliable service, promoting economic growth, supporting competitive markets, facilitating reductions in greenhouse gas emissions, and meeting other future challenges.
The Company began stepping up investment earlier in this decade in response to
evidence of deteriorating service reliability. As explained in the Petition, between 2002 and 2006 shareholders absorbed the revenue requirement on $295.5 million more in capital expenditures, and $127.7 million more in operation and maintenance (“O&M”) costs than was allowed in the Merger Rate Plan. For 2007, National Grid forecasts that its capital expenditures will exceed the Merger Rate Plan allowance by $128.8 million. In addition, National Grid is not seeking deferral treatment for approximately $450.7 million of capital expenditures in its T&D investment program that it may incur during the 2008 through 2011 period. National Grid’s shareholders will also absorb the revenue requirement impact of such expenditures during the remainder of the Merger Rate Plan period. Because National Grid is not seeking deferral treatment for all of its capital expenditures above the allowances reflected in the Merger Rate Plan, the benefits to consumers of capping deferrals associated with expenditures made to fulfill National Grid’s commitment to invest $1.47 billion in the T&D system by the end of 2011 will be even greater than the $90 million the Commission projected when it imposed that limitation. While National Grid will meet that commitment with or without regulatory support, such support at the earliest stage is critical if National Grid is to plan and implement its more ambitious investment program. For investment in 2008, National
3 See National Grid Transmission and Distribution Capital Investment Plan (“Capital Investment Plan”) at p.5. 4 Because all of the expenditures in 2008 for which deferral treatment is sought in this Petition go toward fulfilling the Company’s commitment in Case 06-M-0878 to invest $1.47 billion in its T&D facilities, National Grid is proposing to defer only 50 percent of the revenue requirement impact of those expenditures. If National Grid invests more than $1.47 billion in its T&D facilities during the remaining years of the Merger Rate Plan, National Grid may seek in future petitions to defer 100 percent of the revenue requirement impact of that additional investment.
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Hon. Jaclyn A. Brilling, Secretary December 21, 2007 Page 3 Grid is absorbing a revenue requirement of $7.4 million based upon $71 million in investments above the allowance in the Merger Joint Proposal.
Request for Hearing Procedures
Given the importance to National Grid’s customers and to the economy and
environment of New York State of the rebuilding of the Company’s T&D system, National Grid respectfully requests that this Petition be made subject to hearing procedures. Only by affording all interested parties an opportunity to be heard on the record can the Commission ensure a full airing of the crucial issues to be decided. National Grid stands ready to submit pre-filed testimony supporting this Petition should the Commission grant the Company’s request for the institution of hearing procedures.
Filing Contents; Confidentiality The filing consists of the following documents: • The Petition; • 5 figures supporting the Petition identified as Figure 1A through Figure 4.
Figures are bound together and which immediately follow the Petition in Volume I of the filing;
• 15 exhibits identified as Exhibits P-1 through P-15
The Petition also relies upon and cites to some of the exhibits that were filed with the Commission on October 22, 2007 in support of National Grid’s compliance filing in Case No. 06-M-0878. Those exhibits are identified by their original exhibit number (for example, “Exhibit 10 to the Capital Investment Plan”). Some of the documents contained in this filing are confidential in whole or in part. The complete filing is simultaneously being provided to Steven Blow, the Commission’s Records Access Officer, with a request by National Grid for nondisclosure/confidential treatment of the redacted information. A copy of National Grid’s request to Mr. Blow is enclosed with this filing. Conclusion National Grid welcomes the opportunity presented by this Petition to renew a dialogue with the Commission and with the Company’s customers and other stakeholders regarding the need for investment in its T&D system and the shape that investment should take. While unanimity cannot be expected, collaboration now will provide the best chance of ensuring that the future grid fulfills both current and future requirements, for the benefit of both customers and the public policy goals of New York State.
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Hon. Jaclyn A. Brilling, Secretary December 21, 2007 Page 4
If you have any questions with respect to the filing, please call the undersigned at 315-428-5320.
Respectfully submitted, Robert H. Hoaglund II, Esq. Acting General Counsel, New York Distribution
Niagara Mohawk Power Corporation d/b/a National Grid 300 Erie Boulevard West Syracuse, New York 13202 Phone: 315-428-5320 Fax: 315-428-5740 Email: [email protected]
cc: Active Parties List (U.S. Mail) Steven Blow, Records Access Officer (Hand Delivery) Enclosure: Steven Blow Letter
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Service List Case No. 01-M-0075
10/05/2007
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Presiding:Jeffrey E. Stockholm, Administrative Law Judge
NYS Dept. of Public ServiceThree Empire State PlazaAlbany, NY 12223-1350
Telephone: 518-474-8400Fax: 518-473-3263
Email: [email protected]
Active Parties List As Of: October 05, 2007
Case 01-M-0075Proposed merger Niagara Mohawk & National Grid
FOR: National Fuel Gas Distribution CorporationMichael W. Reville, Esq.National Fuel Gas Distribution Corporation6363 Main StreetWilliamsville, NY 14221Tel: 716-857-7313Fax: 716-857-7254E-mail: [email protected]
FOR: Department of Public Service StaffJane Assaf, Esq.NYS Department of Public Service3 Empire State PlazaAlbany, NY 12223-1350Tel: 518-474-4535Fax: 518-486-5710E-mail: [email protected]
FOR: NYS Consumer Protection BoardDavid Prestemon, Esq.NYS Consumer Protection BoardFive Empire State Plaza, Suite 2101Albany, NY 12223Tel: 518-474-5016Fax: 518-473-7482E-mail: [email protected]
FOR: Saint Regis Mohawk TribeDaniel P. Duthie, Esq.Department of LawPO Box 8Bellvale, NY 10912Tel: 845-987-6453Fax: 845-294-0643E-mail: [email protected]
FOR: The City of New YorkRobert M. Loughney, Esq.Couch White L.L.P.540 Broadway, P.O. Box 22222Albany, NY 12201-2222Tel: 518-320-3404Fax: 518-320-3495E-mail: [email protected]
FOR: Natural Resources Defense CouncilKatherine Kennedy, Esq.Natural Resources Defense Council40 W. 20th StreetNew York, NY 10011Tel: 212-727-4463Fax: 212-727-1773E-mail: [email protected]
FOR: Energy Enterprises, Inc.William R. Green, President and CEOEnergy Enterprises, Inc.3401 Rochester Road, PO Box 687Lakeville, NY 14480Tel: 585-346-2200Fax: 585-346-5214E-mail: [email protected]
FOR: Pro seJoseph F. Cleary, Esq.6311 Sturbridge CourtSarasota, FL 34238Tel: 941-925-2530E-mail: [email protected]
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Case 01-M-0075 October 5, 2007
Paul V. Nolan, Esq.5515 N. 17th StreetArlington, VA 22205Tel: 703-534-5509Fax: 703-538-5257E-mail: [email protected]
FOR: AES SomersetTom JesikiewiczAES Somerset7725 Lake RoadBarker, NY 14012Tel: 716-795-9501Fax: 716-795-3654E-mail: [email protected]
FOR: AES SomersetCharles SjobergAES Somerset7725 Lake RoadBarker, NY 14012Tel: 716-795-9501Fax: 716-795-3654E-mail: [email protected]
FOR: Alliance for Municipal PowerJames F. Fairman, Esq.Alliance for Municipal Power4232 King StreetAlexandria, NJ 22302Tel: 703-894-2200Fax: 703-894-2207E-mail: [email protected]
FOR: Amerada Hess CorporationMartha DugganAmerada Hess Corporation2800 Eisenhower Avenue, 3rd Fl.Alexandria, VA 22314Tel: 703-317-2257Fax: 703-317-2306E-mail: [email protected]
FOR: Board of Public UtilitiesWalter W. HaaseBoard of Public UtilitiesP.O. Box 700Jamestown, NY 14702-0700Tel: 716-661-1670Fax: 716-661-1675E-mail: [email protected]
FOR: Board of Public Utilities of the City of JamestownJeffrey C. Genzer, Esq.Duncan, Weinberg, Genzer & Pembroke, P.C.1615 M Street, NW, Suite 800Washington, DC 20036Tel: 202-467-6370Fax: 202-467-6379E-mail: [email protected]
FOR: City of AlbanyAndrew Gansberg, Esq.Nixon Peabody LLP30 South Pearl StreetAlbany, NY 12207Tel: 518-427-2657Fax: 518-427-2666E-mail: agansberg@ nixonpeabody.com
FOR: Con Edison Company of New York, Inc.Enver Acevedo, Esq.Con Edison Company of New York, Inc.4 Irving Place, Room 1815-SNew York, NY 10003Tel: 212-460-3762Fax: 212-677-5850E-mail: [email protected]
FOR: Energetix, Inc.Robert J. Hobday, Managing Director, Strategic IssuesEnergetix, Inc.755 Brooks AvenueRochester, NY 14619Tel: 585-463-3610Fax: 585-235-3023E-mail: [email protected]
FOR: Entrust Energy Services, LLCNicholas L. Prioletti, Jr.Entrust Energy Services, LLC1005 W. Fayette St., Suite 2DSyracuse, NY 13204Tel: 315-234-9182Fax: 315-234-6578E-mail: [email protected]
FOR: Fluent Energy CorporationDavid W. Koplas, Esq.Fluent Energy Corporation403 Main Street, Suite 630Buffalo, NY 14203Tel: 716-842-1710Fax: 716-842-1705E-mail: [email protected]
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Case 01-M-0075 October 5, 2007
FOR: Harris Beach PLLCPietra G. Letteiri, Esq.Harris Beach PLLCLarkin at Exchange, 726 Exchange St., Suite 1000Buffalo, NY 14210Tel: 716-200-5112Fax: 716-200-5215E-mail: [email protected]
FOR: Internat'l Brotherhood of Elec Workers, Local 97Richard J. Koda, PrincipalKoda Consulting, Inc.409 Main StreetRidgefield, CT 06877-4511Tel: 203-438-9045Fax: 203-438-7854E-mail: [email protected]
FOR: Multiple IntervenorsMichael B. Mager, Esq.Couch White L.L.P.540 Broadway, P.O. Box 22222Albany, NY 12201-2222Tel: 518-426-4600Fax: 518-320-3496E-mail: [email protected]
FOR: Multiple IntervenorsMichael B. Mager, Esq.Couch White L.L.P.540 Broadway P.O. Box 22222Albany, NY 12201-2222Tel: 518-426-4600Fax: 518-320-3495E-mail: [email protected]
FOR: Multiple IntervenorsThais M. Triehy, Esq.Couch White L.L.P.540 Broadway P.O. Box 22222Albany, NY 12201-2222Tel: 518-426-4600Fax: 518-320-3437E-mail: [email protected]
FOR: National Energy Marketers AssociationCraig G. Goodman, PresidentNational Energy Marketers Association3333 K Street, NW, Suite 220Washington, DC 20007Tel: 202-333-3288Fax: 202-333-3266E-mail: [email protected]
FOR: National Energy Marketers AssociationStacey RantalaNational Energy Marketers Association3333 K Street, NW, Suite 110Washington, DC 20007Tel: 202-333-3288Fax: 202-333-3266E-mail: [email protected]
FOR: National GridJames J. BonnerNational Grid300 Erie Boulevard West, A-4Syracuse, NY 13202Tel: 315-428-5285Fax: 315-428-5355E-mail: [email protected]
FOR: National GridRobert H. Hoaglund II, Acting General CounselNational Grid300 Erie Boulevard West, A-3Syracuse, NY 13202-4250Tel: 315-428-5320Fax: 315-428-5740E-mail: [email protected]
FOR: National Grid USAThomas Robinson, Esq.National Grid USA25 Research DriveWestborough, MA 01582Tel: 508 389-2877Fax: 508 389-2463E-mail: [email protected]
FOR: New York Energy Service Providers Assoc. (NESPA)Jeffrey B. Durocher, Esq.Read & Laniado, LLP25 Eagle StreetAlbany, NY 12207Tel: 518 465-9313Fax: 518 465-9315E-mail: [email protected]
FOR: New York Power AuthorityJoseph J. Carline, Esq.New York Power Authority123 Main StreetWhite Plains, NY 10601Tel: 914-390-8009Fax: 914-390-8040E-mail: [email protected]
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Case 01-M-0075 October 5, 2007
FOR: New York Power AuthorityLinda C. PayneNew York Power Authority123 Main StreetWhite Plains, NY 10601Tel: 914-390-8107Fax: 914-390-8154E-mail: [email protected]
FOR: NYS Dept. of Economic DevelopmentGeorge M. Kazanjian, Assistant CounselNYS Dept. of Economic Development 30 North Pearl StreetAlbany, NY 12245Tel: 518-292-5120Fax: 518-292-5807E-mail: [email protected]
FOR: NYS Dept. of Economic DevelopmentMichael J. Santarcangelo, Director of Energy PolicyNYS Dept. of Economic Development 30 North Pearl StreetAlbany, NY 12245Tel: 518-292-5275Fax: 518-292-5804E-mail: [email protected]
FOR: pro seFloyd J. Hitchcock7 Rugby RoadEast Greenbush, NY 12061Tel: 518-477-8115
FOR: Public Utility Law ProjectLouis. Manuta, Esq.Public Utility Law Project194 Washington Ave., Suite 420Albany, NY 12210Tel: 518-449-3375 Ext. 118Fax: 518-449-1769E-mail: [email protected]
FOR: Public Utility Law ProjectGerald A. Norlander, Esq.Public Utility Law Project194 Washington Ave., Suite 420Albany, NY 12210Tel: 518-449-3375 ext. 113Fax: 518-449-1769E-mail: [email protected]
FOR: Rochester Gas & Electric CorporationMark O. MariniRochester Gas & Electric Corporation89 East AvenueRochester, NY 14649Tel: 585-771-4692Fax: 585-724-8818E-mail: [email protected]
FOR: Select Energy New York, Inc.Jon CollinsSelect Energy New York, Inc.507 Plum StreetSyracuse, NY 13204Tel: 315-460-3368Fax: 315-460-3281E-mail: [email protected]
FOR: Small Customer Marketer CoalitionUsher Fogel, Esq.557 Central Avenue, Suite 4ACedarhurst, NY 11516Tel: 516-374-8400 Ext. 108Fax: 516-374-2600E-mail: [email protected]
FOR: Strategic Energy, LLCErin Crehan, Associate CounselStrategic Energy LLCTwo Gateway CenterPittsburgh, PA 15222Tel: 412-258-2036Fax: 412-394-6681E-mail: [email protected]
FOR: Strategic Energy, LLCMarc A. Hanks, Director of Market Development-Eastern RegionStrategic Energy, LLC24 Gary DriveWestfield, MA 01085Tel: 413-642-3575E-mail: [email protected]
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Case 01-M-0075 October 5, 2007
FOR: Town of SomersetSarah L. MillerRegulatory Watch Inc.P.O. Box 815Albany, NY 12201Tel: 518-426-5126Fax: 518-427-8227E-mail: [email protected]
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Petition
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1
STATE OF NEW YORK PUBLIC SERVICE COMMISSION
Joint Proposal of Niagara Mohawk Holdings, Inc. Niagara Mohawk Power Corporation, National Grid plc and National Grid for Approval of Merger and Stock Acquisition
Case No. 01-M-0075
PETITION OF NIAGARA MOHAWK POWER CORPORATION FOR AUTHORIZATION TO DEFER
ELECTRIC TRANSMISSION AND DISTRIBUTION INVESTMENT COSTS
I. Introduction
Pursuant to Section 1.2.4.16 of the Merger Joint Proposal approved by the Commission
in Case 01-M-0075,1 Niagara Mohawk Power Corporation, a National Grid Company (“National
Grid” or “Company”), requests authorization to defer a portion of the revenue requirement
impact during 2008 of (1) specified electric transmission and distribution (“T&D”) capital
programs and (2) operating expenses that are directly associated with those programs (“capital-
related O&M”). In accordance with the Commission’s orders in Case 06-M-0878,2 National
Grid’s request is limited to 50 percent of the revenue requirement impact of the capital cost and
capital-related O&M for investments that fulfill its commitment in that case to invest $1.47
billion in its T&D system during the five years ending December 31, 2011.
The programs for which National Grid seeks rate treatment in this Petition are part, but
not all, of the investment that the Company will make in 2008 in fulfilling that commitment. As
1 Case 01-M-0075, Opinion and Order Authorizing Merger and Approving Rate Plan (Dec. 3, 2001) (“2001 Merger Order”). The electric rate plan established in the 2001 Merger Order, which addressed the 10-year period ending December 31, 2011, will be referred to herein as the “Merger Rate Plan.” 2 Case 06-M-0878, Order Authorizing Acquisition Subject to Conditions and Making Some Revenue Requirement Determinations for KeySpan Energy Delivery New York and KeySpan Energy Delivery Long Island (Sept. 17, 2007) (“2007 Merger Order”).
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National Grid noted in its October 22, 2007 compliance filing in Case No. 06-M-0878, which
included a Capital Investment Plan, the total value of the T&D investment programs that the
Company has identified for possible implementation during that five-year period is
approximately $2.4 billion.3 Investment at such higher levels, which National Grid believes
would be in the interest of customers and which would further the State’s policy objectives,
depends on support from the Commission for the Company’s T&D investment program.4
As a threshold step in approving National Grid’s request for authorization to defer
expenditures incurred in 2008, the Commission must find that such expenditures are eligible for
deferral treatment under Merger Rate Plan Section 1.2.4.16. National Grid accordingly requests
a determination by the Commission that the expenditures described in this Petition are eligible
for deferral under that Section. National Grid intends to petition the Commission in the future
for deferral of qualifying expenditures that will be incurred in years subsequent to 2008. Many
of the major programs described in this Petition will entail expenditures in one or more years
after 2008, while some will have concluded. Future petitions also will seek recovery of
qualifying programs that are not currently expected to commence until 2009 or later. National
Grid’s intent in pursuing this approach is to ensure that the Commission has the opportunity to
consider the most current information available regarding its multi-year investment plans.
The impact of National Grid’s deferral request on the existing electric deferral account if
this petition is granted will be modest. National Grid seeks authority to defer only costs incurred
during 2008 that constitute either part of the cost of plant closed to service during that year or 3 See National Grid Transmission and Distribution Capital Investment Plan (“Capital Investment Plan”) at p. 5. 4 Because all of the expenditures in 2008 for which deferral treatment is sought in this Petition go toward fulfilling the Company’s commitment in Case 06-M-0878 to invest $1.47 billion in its T&D facilities, National Grid is proposing to defer only 50 percent of the revenue requirement impact of those expenditures. If National Grid invests more than $1.47 billion in its T&D facilities during the remaining years of the Merger Rate Plan, National Grid may seek in future petitions to defer 100 percent of the revenue requirement impact of that additional investment.
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O&M directly related to those investments. The Company’s current estimate of such deferred
costs for 2008 only (including the 50 percent deferral limitation described above) is
$5.245million.5 This estimate reflects the implementation of all the programs that were
described in the Company’s October 22, 2007 compliance filing.6 Deferrals authorized to be
recorded under Section 1.2.4.16 of the Merger Rate Plan will not affect electric delivery rates
before 2010, and then only if total deferrals exceed the threshold for adjustment to those rates
when the deferral account balance is reviewed in the biennial Contract Termination Charge
(“CTC”) adjustment filing that the Company is required to submit in 2009. Nevertheless since
spending on most of these programs will continue in subsequent years, the Commission’s
guidance on the treatment of the investments described in this petition will be crucial in helping
the Company direct its investments over the remainder of the Merger Rate Plan period.
The costs for which deferral is sought in this petition qualify for deferral treatment under
the standard established by the Commission in the Merger Rate Plan. In particular, deferral
treatment is requested only for costs associated with investments that are incremental to those
underlying the Merger Rate Plan and that constitute “major programs and expenditures” eligible
for recognition under Section 1.2.4.16. That provision was included in the Merger Rate Plan to
address risks created by uncertainty about the adequacy of the T&D capital spending projections
during the 10-year term of the Merger Rate Plan. The needs of the system could not be forecast
with a high degree of confidence in the latter years of that rate plan. In fact, as explained below
and in the Company’s October 22, 2007 compliance filing, investment in the T&D system during
the latter years of the Merger Rate Plan may be needed at levels well above those reflected in 5 See p. 1 of Exhibit P-14. 6 That filing included an overview (entitled “Compliance Filing”) and two reports required by the 2007 Merger Order: the National Grid Capital Investment Plan (“Capital Investment Plan”), and National Grid Condition of Physical Elements of Transmission and Distribution System (“Condition Report”). It also included nine volumes of exhibits justifying the reasonableness of capital programs described in the Capital Investment Plan and four volumes of exhibits setting forth in detail data underlying the Condition Report.
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underlying projections to maintain reliability and to address growing customer needs. National
Grid is committed to making the necessary investments; it is crucial that the Commission make
clear that it will support the necessary investment in the electric delivery infrastructure by
approving the proposed deferrals.
II. Policy Implications of the Petition
While the level of deferrals presented in this petition is relatively modest, National Grid’s
planned and proposed investments through the end of the Merger Rate Plan period and beyond
are much larger. Ensuring the reliability of service in decades to come will require both these
investments by the Company and the support of the Commission. The expenditures that are the
subject of this Petition represent an initial step in an initiative that will proceed over many years
to rebuild the T&D system to meet customer needs in the future. The objective is to ensure that
National Grid’s T&D system is adequate to fulfill customer demands for reliable service, to
support competitive markets, to facilitate reductions in greenhouse gas emissions, and to meet
other future challenges.
The need for substantially enhanced investment in National Grid’s T&D system to ensure
reliability and to prepare to meet future needs is part of a broader picture in which electric
utilities and regulators nationwide are confronting the need for increased infrastructure
investment, given the age and condition of their delivery systems. Many authorities and experts
have documented this nationwide crisis. For example, the American Society of Civil Engineers
(“ASCE”), which has been doing a periodic assessment of U.S. infrastructure since 1998,
reported in its 2005 assessment update that “the state of the [electric] grid remains a cause for
deep concern among the experts”:
The U.S. power transmission system is in urgent need of modernization. Growth in electricity demand and investment in new power plants has not been matched by
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investment in new transmission facilities. Maintenance expenditures have decreased 1% per year since 1992. Existing transmission facilities were not designed for the current level of demand . . .7
ASCE gave America’s electric infrastructure a “D” grade, down from “D+” in its 2003 report.8
Similarly, Electric Power Research Institute’s (“EPRI”) Clark Gellings and Kurt Yeager
explains:
The power delivery system is largely based on technology developed in the 1950s or earlier and installed as much as 50 years ago. The strain on this aging system is beginning to show, particularly as consumers ask it to do things it was not designed to do. . . . An additional and significant stress on the North American power delivery system results from the discrepancy between the growth in demand for power and the expansion of the delivery system to meet that demand. From 1988 to 1998, US electricity demand rose by nearly 30% while the transmission network's capacity grew by only 15%.9
These problems afflict distribution as well as transmission systems around the country:
[The] steady climb in investment in distribution assets shows no sign of diminishing. The need to replace an aging infrastructure, coupled with increased population growth and demand for power quality and customer service, is continuing to motivate utilities to improve their ultimate delivery system to customers.10
In the words of the California Energy Commission:
California's electric distribution system uses designs, technologies and strategies that are decades old. Due to increasing demand and aging infrastructure, utility, government and technical experts are discussing the need for substantial changes in how this essential delivery system is designed, built and operated.11
The Pennsylvania Public Utility Commission recently recognized and provided funds for its
jurisdictional utility Duquesne Light Company to implement a “plan to address the need for
extensive rehabilitation of aging substations and increase reliability of its entire transmission
7 Infrastructure Report Card 2005, http://www.asce.org/reportcard/2005/page.cfm?id=25. 8 Id. 9 Transforming the Electric Infrastructure, Clark W. Gellings and Kurt E. Yeager, Physics Today (December 2004), at p. 48. 10 Rising Utility Construction Costs: Sources and Impacts, Marc W. Chupka, Gregory Basheda, The Brattle Group, Sept. 2007, p. 7. 11 Notice of a Joint Committee Workshop to Address California Distribution Infrastructure Challenges, at http://www.energy.ca.gov/2007_energypolicy/notices/2007-05-10_joint_workshop.html.
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system”;12 with regard to another of its utilities, the Commission said “[PPL Electric Utilities
Corp.]’s distribution system is part of this nation's aging infrastructure, which includes highways,
bridges, water systems and sewer systems.”13
Other states and regions also are facing similar needs to repair and upgrade electric
distribution infrastructure. Jurisdictions as diverse as Colorado and Ontario, to name just two,
are currently struggling with these distribution infrastructure issues.14 Indeed, analyses
contained in Figure 115 to this Petition indicate that the weakening performance of National
Grid’s transmission and distribution systems mirrors performance nationwide. Nevertheless, we
are committed to improving our performance for the benefit of our customers.
In the United States generally, and New York specifically, bringing transmission and
distribution infrastructure up to an appropriate level will require both very large investments over
a multi-year year period and close cooperation among utilities and various state and federal
governmental entities. National Grid is willing and able to do its part to support these goals.
National Grid has demonstrated its willingness by investing above Merger Rate Plan levels since
2002 and by committing to a higher level of investment through the end of the Merger Rate Plan.
Indeed, National Grid may exceed, perhaps very substantially, the level of spending to which it
committed in the 2007 Merger Order as it strives to achieve these goals and ramp up asset
replacement expenditure on our aged (50 – 100 year old) infrastructure. Delivery of energy is
12 Letter of Notification of Duquesne Light Company etc, Slip, Case A-110150 F0036, Dec. 5, 2006, 2006 WL 3698762 (Pa.PUC). 13 Pennsylvania Public Utility Commission et al. v. PPL Electric Utilities Corporation, 237 P.U.R.4th 419, __, 99 Pa.P.U.C. 389 (2004). 14 See, e.g., Reliability Of Public Service Company Of Colorado’s Electric Distribution System, Final Report To The Colorado Public Utilities Commission, July 9, 2004, available at http://hermes.state.co.us/puc/energy/04I-098E_07-09-04StaffFinalRptPSCoReliabilityElectric.pdf; Waiting for the Storm: Ontario’s Deteriorating Transmission and Distribution Assets and the Privatization Alternative, March 7, 2005, Tom Adams, Energy Probe, p. 8, available at http://www.energyprobe.org/energyprobe/reports/response%20to%20Ministry%20T&D%20paper%20feb%2020051.pdf. 15 Figures are presented at the end of the Petition.
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National Grid’s core business, and it is important to us that we be considered among the best in
that business at delivering value for customers.
In addressing Section 1.2.4.16 of the Merger Rate Plan in the 2007 Merger Order, the
Commission recognized National Grid’s right to seek special ratemaking treatment for its
incremental expenditures while capping recovery at 50% for those incremental expenditures
associated with fulfilling the Company’s commitment to invest $1.47 billion in its T&D assets to
ensure that benefits of the National Grid/KeySpan Merger were captured for customers. As
noted below, the Commission determined that customers would receive a significant benefit if
National Grid were to defer 50% of all T&D investment above the levels assumed in the
development of Merger Rate Plan rates associated with meeting that commitment. This Petition
ensures that customers will receive even greater benefits because it seeks deferral of 50% of only
a subset of the capital costs and capital-related O&M that National Grid will incur above Merger
Rate Plan allowances. Moreover, this Petition seeks no recovery at all of operating expenses
above those allowed in rates that are not directly related to major capital programs.16
The expenditures that are the subject of this Petition constitute only a portion of National
Grid’s capital and operating expenditures aimed at improving the condition and reliability of the
T&D system. National Grid will incur approximately $875 million of capital expenditures
during 2002-2011 above the rate plan levels for which cost recovery is delayed until after 2011.
In addition, National Grid has spent and will continue to incur O&M expense at levels higher
than the rate plan during this period. As shown on Figure 2, for the period 2002 through 2006,
National Grid has incurred $295.5 million more in capital expenditures, and $127.7 million more
in O&M, than was allowed in rates under the Merger Rate Plan. For 2007, National Grid
forecasts that its capital expenditures will exceed the Merger Rate Plan allowance by an 16 See Part IV.E for a discussion of what O&M costs are, and are not, directly related to capital programs.
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additional $128.8 million. Our shareholders are absorbing the revenue requirement impact of the
entire amount of pre-2008 capital and O&M spending in excess of rate allowances.
Based on the $2.4 billion in potential T&D projects that were described by National Grid
in its Capital Investment Plan, the Company projects that it may incur during the period 2008
through 2011 as much as $1,560.4 million more in capital expenditures than was allowed under
the Merger Rate Plan. Of this amount, approximately $450.7 million is associated with capital
expenditures on programs for which National Grid is not seeking deferral treatment under
Merger Rate Plan Section 1.2.4.16. The revenue requirement impact of the non-qualifying
capital expenditures of $71.3 million that National Grid will make in 2008 – estimated at $7.4
million – also will be absorbed by our shareholders through the end of the Merger Rate Plan.
Given the importance to National Grid’s customers and to the economy and environment
of New York State of the rebuilding of the Company’s T&D system, National Grid respectfully
requests that this Petition be made subject to hearing procedures. Only by affording all
interested parties an opportunity to be heard on the record can the Commission ensure a full
airing of the crucial issues to be decided. National Grid stands ready to submit pre-filed
testimony supporting this Petition should the Commission grant the Company’s request for the
institution of hearing procedures.
III. The Proposed Deferrals Meet the Applicable Standard
A. The Deferral Standard
Section 1.2.4.16 of the Merger Rate Plan specifies the standard for deferral of
incremental investment during the last four years of the Merger Rate Plan, or 2008 through
2011. That provision states:
Niagara Mohawk shall have the right to petition the Commission for special ratemaking treatment for major programs and expenditures that may occur in years seven through ten
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of the Rate Plan Period. In the petition, Niagara Mohawk must demonstrate that the proposed investment was incremental to the original 10-year forecasts underlying the rates agreed to in this Joint Proposal and that any expenses or savings go beyond such forecasts. To this end, Niagara Mohawk shall, within six months of the Effective Date and every two years thereafter, file with the Commission a five-year capital and expense budget including therein a schedule of projects consistent with and developed from the capital expenditure forecasts underpinning this Joint Proposal. Any significant additional projects would be accompanied by an engineering and/or technical justification. In the petition, Niagara Mohawk shall have the right to propose a sharing of any efficiency gains as a method to recover the costs for such program or expenditures. To the extent that the petition as approved by the Commission increases or decreases pre-tax net income, Niagara Mohawk shall include the differential in the Deferral Account.
While this provision requires National Grid to file biennially its five-year projected capital and
expense budget regardless of whether deferral authority is ever sought,17 Section 1.2.4.16 sets
forth three substantive criteria that must be met for expenditures to be eligible for deferral. To
qualify, expenditures must:
(1) be for “major programs and expenditures” in 2008-2011;
(2) relate to investments that are “incremental to the original 10-year forecasts underlying the rates” in the Merger Rate Plan; and
(3) be “accompanied by an engineering and/or technical justification.”
As National Grid will demonstrate in part C of this Section and in Section IV, below, the
expenditures for which deferral is sought meet all of these criteria.
The deferral criteria prescribed in Section 1.2.4.16 represent an application, in the
specific context of major programs and investments during the last four years of the Merger Rate
Plan, of the Commission’s generally applicable deferral test. The application of Section 1.2.4 in
light of the elements of the Commission’s general deferral test – that the utility not be over-
earning, that the amount to be deferred be material, and that the amount to be deferred be
17 It was in compliance with this section that National Grid most recently filed its five-year T&D capital and expense budgets on April 2, 2007.
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incremental to the amount currently reflected in rates18 – was clarified in the Stipulation of the
Parties, which resolved National Grid’s Second CTC Reset proceeding in Case No. 01-M-0075
(the “Stipulation”) and which was approved by the Commission earlier in 2007. 19
Under the Stipulation, the “not over-earning” and materiality prongs of the Commission’s
general deferral test were addressed through the earnings sharing provision of the Merger Rate
Plan and through limitations on the recovery of deferrals. For example, pre-June 30, 2005, lost
revenues and expenses excluded from the deferral account established and governed by Merger
Rate Plan Section 1.2.4 nevertheless were to be recognized for purposes of reducing National
Grid’s earnings under its earnings sharing mechanism.20 The materiality prong also is addressed
in Section 1.2.4.16 by the requirement that a program or expenditure be “major” to qualify for
special rate treatment.
Section 3.2 of the Stipulation also addressed the “incremental” prong of the deferral test
as follows (emphasis added):
To the extent a deferral is not addressed by a specific provision of this Section 3 or as otherwise ordered by the Commission, in determining whether a change in Niagara Mohawk’s costs or revenues that falls within a provision of Section 1.2.4 of the Merger Joint Proposal is incremental or decremental, Niagara Mohawk’s actual cost or revenue for the year affected by the change shall be compared to the corresponding annual cost or revenue item reflected in the forecast underlying the Merger Joint Proposal rates. The cost or revenue forecast underlying the Merger Joint Proposal rates shall be as stated in the Merger Joint Proposal or, if not explicitly stated in the Merger Joint Proposal, then as derived from the Financial Forecast and Supporting Workpapers submitted to the Commission together with the Merger Joint Proposal, adjusted as appropriate for a share of the net synergy savings assumed in the Merger Joint Proposal rates.
18 Case 04-W-0075, United Water New Rochelle Inc., Order Allowing Deferral of Extraordinary Expenses (issued March 31, 2005); Case 06-G-059, Corning Natural Gas Corporation, Order Approving the Acquisition of a Natural Gas Local Distribution Company (issued July 24, 2006). 19 See Order Adopting Terms and Conditions of the Parties’ Stipulation, Case No. 01-M-0075 et al. (issued July 19, 2007). 20 Stipulation at Section 2.6. See also Stipulation at Sections 3.10 (same treatment for lost revenues and expenses for the period July 1, 2005 - December 31, 2011) and 8.2 (same treatment for disallowed portion of pension settlement losses). Section 1.2.4.16 also addresses the earnings prong of the test by requiring deferral of the effect of proposed special ratemaking treatment on National Grid’s pre-tax net income.
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Thus the agreement of the parties to the Stipulation, as approved by the Commission, was to
determine whether a cost is incremental by referring to the forecasts underlying the Merger Rate
Plan. The only prong of the Section 1.2.4.16 deferral standard that was not linked by the
Stipulation to corresponding elements of the Commission’s general deferral test – the
requirement that expenditures be accompanied by an engineering and/or technical justification –
is addressed in Part IV, below, and the exhibits referenced therein.
B. The 50% Limitation on Deferral Authorizations
As noted above, the Commission in the 2007 Merger Order prescribed a condition,
accepted by National Grid, that capped at 50% the share of costs associated with the Company’s
commitment to invest $1.47 billion in its T&D system for which deferral would be authorized.
The Commission stated:
In light of National Grid’s commitment to spend the incremental capital moneys on National Grid’s T&D system in return for us approving the KeySpan merger, should the Company file any such petition contemplated by Clause 1.2.4.16, the amount of rate impacts related to the incremental costs recoverable from National Grid ratepayers during the Rate Plan Period will be limited to 50% of the total rate impact as ultimately determined by the Commission. . . . The company’s share of the rate impact is subject to further adjustment based on arguments raised by the parties about the reasonableness of the company’s prior spending.21
At the Commission session at which the National Grid-KeySpan merger was approved, a
Commissioner asked what the ratepayer benefit of this provision would be. The response was
$90 million, or approximately one-half of the estimated total carrying charges associated with
all capital expenditures during 2008 to 2011 in excess of the Merger Rate Plan allowances
(and assuming implementation of the Company’s $1.47 billion investment plan.22) The $90
million benefit could be claimed only if it was assumed that all such expenditures would
otherwise be deferred. This benefit to customers was characterized as “available to offset” 21 2007 Merger Order at 150. 22 Transcript of Commission Session, Aug. 22, 2007, at 12; see also Short Merger Order at 9.
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deferrals resulting from National Grid’s $1.47 billion Capital Investment Plan,23 thus
confirming that such deferrals were contemplated when the Commission imposed the 50%
limitation.
C. The Eligible Expenditures Qualify for Deferral Treatment
The expenditures that National Grid requests authority to defer are eligible for special
ratemaking treatment because they satisfy the criteria prescribed by Merger Rate Plan Section
1.2.4.16: they (1) are for major programs in 2008-2011; (2) relate to investments incremental to
the original 10-year rate forecast; and (3) are supported by engineering and/or technical
justifications. Furthermore, National Grid clearly is not over-earning, as the earnings sharing
provision established by the Merger Rate Plan has not been triggered since the Merger Rate Plan
began in February 2002.24 The latest report to the Commission calculated an ROE of 8.83% for
calendar year 2006.25 Should the Company be determined to have over-earned in some future
period, a share of excess earnings will be credited to customers by operation of Section 1.2.5 of
the Merger Rate Plan. In addition to meeting the applicable standard for deferral, the
expenditures at issue warrant deferral because such rate treatment is in the public interest.
First, the subject expenditures are for “major programs” (and therefore also constitute
“material” expenditures under the Commission’s generally applicable standard for deferrals).
Whether a program is “major” may be defined on an engineering or on a financial basis. From
an engineering perspective, some of the programs for which deferral is sought qualify as “major”
because they address an important system need to enhance reliability or otherwise benefit
customers. From a financial perspective, many of the programs involve investment of tens of
23 See Transcript of Commission Session, Aug. 22, 2007, at 12. 24 See also n. 19, above. 25 Report of Earnings of Electric Operations submitted to the Commission on June 28, 2007, as required by Sections 1.2.3.6 and 1.2.5 of the Merger Joint Proposal.
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millions of dollars over a multi-year spending cycle that overlaps at least in part with the 2008-
2011 deferral period. Exhibit P-14 (workpapers 10 to 12) shows the projected total expected cost
of each transmission, sub-transmission, and distribution program for which deferral authority for
2008 expenditures is sought in this Petition by calendar year. In short, the subject expenditures
are central to National Grid’s Capital Improvement Program and to the Company’s ability to
strengthen the reliability of its T&D system. The Commission should recognize that the
programs for which deferral is sought constitute only a fraction of the Company’s projected
spending on its T&D system during 2008 and the remainder of the Merger Rate Plan. As
illustrated in Figure 3, National Grid will spend at least $1,560.3 million above the Merger Rate
Plan allowances during 2008-2011.
Section 1.2.4.16 of the Merger Rate Plan does not limit eligibility to programs or
expenditures that fulfilled only a particular type of need. T&D system planning is dynamic
inasmuch as the needs of the system change over time and are affected by numerous variables,
including many that are outside of National Grid’s control. The Merger Rate Plan correctly
recognized that those needs could not be perfectly predicted over the full 10-year rate plan
horizon. While it is possible that different participants in the settlement process may have had
differing views of what types of programs Section 1.2.4.16 was addressing, the plain meaning of
this section is not constraining. Rather, it manifestly allows that provision to be reasonably
interpreted in light of the current system need for critical infrastructure investment.
Second, the subject expenditures are “incremental” within the meaning of the Merger
Rate Plan. None of the programs were contemplated at the time of the Merger Rate Plan, as
shown by an examination of National Grid’s first 5-year capital and expense budget, which was
submitted to the Commission on July 31, 2002. On the other hand, each of those programs
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addresses a specific need that has been identified in National Grid’s T&D planning since the
Merger Rate Plan’s execution and approval. Spending on the subject programs is over and above
spending on other projects, which more than consume the Merger Rate Plan allowances for the
subject years.
The capital-related O&M for which National Grid seeks deferral authority is, by
definition, directly linked to its associated capital project; indeed, capital-related O&M consists
of O&M that is charged to a capital work order. Accordingly any capital-related O&M is
incremental if the underlying capital project is incremental.
Third, the programs are supported by engineering and/or technical justifications. Those
justifications are set forth in Section IV below and in the exhibits referenced in that Section.26
In applying the standard of Section 1.2.4.16, the Commission should recognize that it
already has imposed a financial penalty based on its determination that National Grid’s
“investment over the last several years [was] inadequate for [the Company] to meet certain
reliability measures . . . .”27 That penalty, the 50% cap on deferrals allowable under Section
1.2.4.16, was accepted by National Grid as a condition of Commission approval of its merger
with KeySpan. The amount National Grid agreed to forego, which, as noted above, was
calculated at $90 million, was intended to compensate customers for what the Commission found
was the Company’s failure to make sufficient investments. In these circumstances, denying or
further limiting deferrals based on considerations relating to the adequacy of investments in past
years would amount to an inappropriate and unjustified double penalty.
IV. Description of the Eligible Expenditures
This section identifies and describes the expenditures that National Grid seeks
26 As will be explained further below, some of those exhibits were filed on October 22, 2007 in support of the Capital Investment Plan; others are being filed with this Petition and are identified with the prefix “P”. 27 Short Merger Order at 22.
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authority to defer. The expenditures presented in this Petition are current estimates; based on
recent volatility in the cost of raw materials used in the manufacture of various components of
electricity infrastructure, such as oil, steel, and copper, it is highly likely that actual costs will
vary from those estimates. Deferrals will be based on actual expenditures.
By way of background, we first explain (in subsection A, below) the new approach to
T&D asset management that National Grid has implemented to address evidence of
deteriorating reliability in the performance of its T&D system. We next present the major
programs and expenditures for which National Grid seeks deferral, grouped by function
(transmission (subsection B), sub-transmission (subsection C), and distribution (subsection
D)). As noted above, National Grid is limiting its request for deferral to capital programs and
expenditures and to capital-related O&M. Supporting exhibits, including cross-references to
exhibits that were filed as part of National Grid’s October 22, 2007 Compliance Filing, are
described in connection with each program. We also describe for each program the impact of
proposed investment on future O&M expense (excluding capital-related O&M).
In the concluding parts of this Section, we define and provide several examples of
capital-related O&M (subsection E). We also explain why National Grid believes there is no
basis for reducing deferrals to account for estimates of O&M savings that could result from its
investment programs (subsection F).
A. The Deterioration of Reliability and National Grid’s Decision to Change Its Approach to Asset Management
The data show that National Grid’s reliability performance has been deteriorating. While
year-to-year variances in reliability performance may be explained at least in part by weather and
other circumstances, a comparison of the five-year periods ending in 2001 and in 2006 shows a
modest but noticeable decline in reliability, as illustrated by the System Average Interruption
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Frequency Index (“SAIFI”) data shown in Figure 1A.
To address this unforeseen deterioration of reliability, the Company decided to introduce
a new approach to T&D asset management. This approach, referred to as “Asset Management,”
is designed to address the effect on reliability of deteriorating equipment, and focuses on formal
documented strategies regarding investment and maintenance practices. Asset Management
substantially differs from the traditional utility approach of replacing equipment either following
failure or based on the results of facility-specific diagnostic tests, which often consisted of visual
inspection. The Company began implementing this approach in 2003-04 for its assets on the
transmission system. In 2006-2007, the Company introduced Asset Management for the
distribution system when it developed the feeder hardening program using the strategies
provided in Exhibit 31 of the Company’s Capital Investment Plan. In 2007 and 2008, the
Company is using the approach to develop other advanced strategies for the distribution and
transmission system.
Asset Management seeks to meet customer, electricity market participant, and
shareholder expectations today and far into the future. The concept is to manage the lifetime
costs of assets while achieving targeted levels of safety and system performance. The
performance of the network is a function of decisions regarding T&D assets over their lives,
from network design when installed to maintenance strategy over the ensuing decades. The aim
of Asset Management is to balance performance, risk and cost in order to deliver the highest
reasonable reliability at the lowest reasonable cost. This requires forecasting when reliability
will decline due to the age-related deterioration of assets and to other causes, as well as
identifying and responding to early indicators of performance deterioration so as to optimize the
timing of asset replacement. The aim is to neither incur costs prematurely by replacing assets
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too early, nor suffer significant reliability degradation by replacing them too late. Reasonable
engineering and business judgment on the part of decision makers utilizing continually
improving analytical techniques is essential. This approach seeks neither reliability at any cost
nor the lowest possible cost with poor reliability; it involves striking the balance that meets both
objectives. The process needs to be applied over the typical lifetime of assets to maximize their
life and achieve long term customer benefits.
Asset Management needs to be systematically applied based on an annual budget cycle
that includes both capital and O&M expenditures. We seek to continually monitor the
performance of the system and to update our understanding of the condition of each asset in a
coordinated manner. Decisions are made on a risk and criticality basis to maximize the long-
term benefit to our customers over the whole lifetime. This means we not only optimize asset
risk, but we also consider the criticality of the asset to the customer both now and in the future,
and optimize our approach to provide the least-cost solution to customers over the lifetime of an
asset. This approach forms the basis for the Transmission, Sub-Transmission and Distribution
programs outlined in the following sections.
B. Transmission Programs and Expenditures
National Grid has developed and approved through internal review processes
approximately 11 transmission programs and expenditures that are incremental to those reflected
in rates, and that are important to enhancing reliability or to serving new load. These programs
and expenditures may also be classified based on three primary rationales: asset condition;
statutory/regulatory; and system capacity and performance. The primary supporting
justifications for transmission projects are defined as follows:
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• Statutory/Regulatory – Capital expenditures required to ensure that the T&D facilities meet the minimum legal, regulatory and contractual obligations of the Company (e.g., compliance with rules of the North American Electric Reliability Corporation (“NERC”), the Northeast Power Coordinating Council (“NPCC”), the New York State Reliability Council (“NYSRC”), and the Occupational Safety and Health Administration (“OSHA”)).
• Asset Condition – Capital expenditures required to reduce the risk and consequences of failures of T&D assets.
• System Capacity & Performance – Capital expenditures undertaken to upgrade the capability of the T&D delivery system beyond minimum requirements in order to provide improved thermal loading, voltage, stability, reliability or availability performance.28
We briefly describe below major asset programs and projects that National Grid will pursue to
improve the condition of its transmission facilities, enhance their reliability, and ensure that they
remain safe and adequate to meet the needs of our customers. Engineering and technical
analyses supporting each program are provided in the exhibits referenced below.29
ATB Strategy
The ATB Breaker replacement program is a significant program that involves the
expenditure of $18.5 million in capital and $0.6 million in capital-related O&M to replace all
twenty-six remaining General Electric ATB-7 Air Circuit Breakers on the 345 kV system in New
York. This program was not anticipated at the time of the Merger Rate Plan or included in the
Company’s initial capital and expense budget. The engineering, technical, and economic
justification for the program is described in Exhibit 5 to the Capital Investment Plan and in
Exhibit P-1 to this Petition.30 That justification is summarized below.
The Company is in the midst of a program to replace all twenty-six remaining ATB-7
28 In the Capital Improvement Plan, National Grid identified two additional categories of primary supporting justifications for transmission projects: Damage/Failure, and Other. Since neither of these categories includes any major and incremental programs, they are not discussed in this Petition. 29 It should be noted that for some programs there is a discrepancy, usually immaterial, between the costs estimates contained in supporting exhibits and cost estimated for the same program provided in the Petition. The Petition contains the most up-to-date estimates. 30 Exhibit 5 of the Capital Investment Plan includes a sanction paper and several scoping documents, and Exhibit P-1 includes a justification document, a root cause analysis, AIMMS trouble data and an estimate of O&M savings.
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breakers in New York in order to remediate these potential hazards at a total estimated capital
cost of $18.5 million. Approximate expenditures for this program through the end of 2007 are
projected to be $13.9 million. Spending for 2008 through 2011 is estimated to be approximately
$4.6 million. National Grid will absorb until its next rate case 100% of the revenue requirement
impact of the costs that are expected to be incurred through 2007; it is only expenditures in 2008
and later for which deferral recognition is sought here.
National Grid has undertaken this program to replace the ATB-7 breakers for several
reasons. First, these breakers were introduced in the early 1960s and it is now difficult to obtain
parts for them. Second, as they have aged, the ATB-7 breakers have become increasingly
problematic, and the operating mechanism of the ATB-7 breaker is complicated, expensive and
difficult to maintain. Third, leaks of SF631 from ATB-7 breakers are common and unfixable in
the field, so replacement of these breakers is environmentally beneficial. Fourth, the ATB-7
breakers are significant elements of the transmission system. An ATB failure could result in the
loss of several lines in the system or even render a transmission line terminal out of service.
Such a loss would reduce the capacity of the transmission grid until a replacement is installed.
Fifth, replacement of these breakers will have safety benefits. In 2000, an ATB-7 breaker
experienced a violent, potentially life-threatening failure with no prior warning of failure being
imminent. The interrupter, a part spanning 5 feet and weighing 3000 lbs, was blown fifty feet
away from the breaker, and the porcelain bushing fragmented into hundreds of pieces. While
this may be a low-probability event and no one was injured in this incident, this type of violent
failure presents obvious reliability issues and concerns for the safety of anyone in the vicinity of
the remaining breakers.
31 SF6 is a greenhouse gas that has a global warming potential that is 23,900 times an equal mass of carbon dioxide and has an atmospheric lifetime of 3,200 years.
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Replacement of the ATB-7 breakers is estimated to produce O&M expense savings of
$70,000 in 2008 due to a reduction of unplanned trouble maintenance and decreased planned
preventive maintenance. Decreased planned maintenance results from replacement breakers that
are smaller and less complicated requiring less time and labor, and longer maintenance cycles.
See Exhibit P-1.32
Shield Wire Strategy Program
The Shield Wire Strategy program involves the replacement of a significant amount of
shield wire on the overhead transmission system at a capital cost of $27 million and a capital-
related O&M cost of $0.8 million. This program was not anticipated at the time of the Merger
Rate Plan or included in the Company’s initial capital and expense budget. The engineering,
technical, and economic justification for the program is set forth in Exhibit P-2 and in Exhibit 6
to the Capital Investment Plan.33
The facilities at issue are the shield wire on 408 miles of 115 kV transmission lines, or
approximately 7% of the total 115 kV mileage in National Grid’s New York system. Since 2003
there has been a spike in shield wire related outages, mostly in the 115 kV transmission class.
We assume the range of anticipated lives for shield wire is 30-80 years with a mean life of 50
years,34 yet approximately 40% of the shield wire in this class is over 70 years old. While
customers have benefited financially from such extended asset lives, it would be inadvisable to
continue to rely on shield wire that is significantly older than its expected service life.
The shield wire, or static wire, is critical to the physical stability of a transmission circuit.
Shield wire serves both a mechanical and electrical function. A shield wire provides grounding
32 The net O&M savings projected for each program do not include capital-related O&M. 33 Exhibit P-2 includes a justification document and an estimate of O&M savings, and Exhibit 6 of the Capital Investment Plan includes two strategy papers, a sanction paper and two engineering scope documents. 34 Ageing of the System Impact on Planning, Working Group 37.27, CIGRE, December, 2000.
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protection from lightning strikes as well as critical support against the imbalance of forces in the
longitudinal direction (in the direction from one tower to the next) such as heavy wind or ice
loading. In addition, if a dropped shield wire goes unnoticed it could fail without tripping a
circuit or cause only a momentary fault, creating a significant safety hazard to the public and
degrading reliability of the system.
To remediate these potential hazards, the Company is proposing to replace 408 miles of
shield wire on certain 115 kV transmission lines, detailed in Exhibit P-2, with stronger high
strength steel. The Company will also review and upgrade, as necessary, the grounding system
on each structure visited.
The capital cost of this program, estimated at $27 million, will be incurred as follows:
$1.9 million in 2008; $9.1 million in 2009; $10.1 million in 2010; and $5.8 million in 2011. The
overall benefit to the customers is the enhanced reliability of the transmission grid. Based on
historical outage events, the Shield Wire Strategy Program is expected to result in a reduction of
over 8,000 minutes/year of total sustained outage durations. In addition, the safety performance
of each circuit will also be improved through reduced likelihood that a shield wire would drop
without tripping the circuit. In contrast, delaying replacement would increase the risk of failures,
resulting in greater potential for a safety event as well as degradation in reliability of the system.
Implementation of the Shield Wire Strategy program is expected to result in no net O&M
expense savings in 2008, as explained in Exhibit P-2.
Frontier Region Program35
The Frontier Region Program involves the expenditure of $45.7 million in capital and
$1.4 million in capital-related O&M to construct a major set of upgrades and replacements to the
35 This program includes projects not associated with reinforcements required in the Frontier region that are included in the Reliability Criteria Compliance program described below.
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115 kV system near the existing Huntley Station in western New York. This program was not
anticipated at the time of the Merger Rate Plan or included in the Company’s initial capital and
expense budget. The engineering, technical, and economic justification for the program is set
forth in Exhibit P-3 and Exhibit 13 to the Capital Investment Plan.36
Although Huntley Station once had four coal fired operating units connected to the 115
kV system, the recent retirement of these units announced by NRG Energy, Inc. (”NRG”), which
resulted from a 2005 agreement between NRG and the NY Department of Environmental
Conservation, has resulted in thermal and voltage concerns for the system during summer
loading periods. Load pocket studies completed from 1995 through 2007 indicated that the
Huntley area could be subjected to thermal and voltage problems if generation both at Huntley
and the several facilities near Huntley was removed from service. Upon the announcement of
the retirement of the units at Huntley, further analysis of the area confirmed that thermal and
voltage problems would be present and those problems would be more severe than had been
indicated in prior load pocket studies.37
To remediate the potential problems with the June 2007 retirement of the last 115 kV
unit, the region required immediate capacitive support to maintain a minimum level of service.
Accordingly, National Grid installed two 52.5 MVAR portable capacitor banks on the 115 kV
bus at Huntley Station before the generation closed in June 2007. The Company is not seeking
to defer carrying charges associated with its investment in these capacitor banks, which cost $2.4
million, as the reinforcements were in-service before year seven of the rate plan.
This short-term temporary solution following the generation closure needs further
transmission support before 2009/2010 to provide thermal and voltage security to the region. In
36 Exhibit P-3 includes a justification document, several load pocket assessments, and an estimate of O&M savings. Exhibit 13 includes a strategy paper and a sanction paper. 37 See Exhibit 13 of the Capital Investment Plan.
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total the Company plans to construct or install the following equipment to provide a long-term
solution to the Frontier Region reliability concerns:
• Construction of a 115 kV breaker and a half station (25 breakers) to be known as Paradise Station, operational in April 2010;
• Installation of two 115 kV capacitor banks at the new station, operational in 2010;
• Replacement of twelve 115 kV breakers at Packard Station to allow the 115 kV
bus tie at Packard to be operated closed, operational in April 2009;
• Retirement of the Huntley 115 kV switchyard and the removal of the relays and controls from NRG’s property, to be completed in 2012;
• Construction of a control house on National Grid property at Huntley for 230 kV
protection, control and communications systems, operational in 2011; and
• Removal of approximately 20 miles of double circuit transmission towers between Paradise Station and Huntley Station, to be completed in 2012.38
The $45.7 million capital cost for the project will be incurred as follows: $13.9 million in 2008,
$16.8 million in 2009, $12.3 million in 2010, and $2.7 million in FY 2011.
The engineering design will prevent thermal and voltage problems in the area load pocket
formerly supported by the Huntley generation, as well as benefit the existing customer base
through overall reliability improvement. In addition, the approach will reduce the environmental
risk of a release of oil from the aged oil-filled equipment at Huntley, which is surrounded by
bodies of water. This program is being implemented in order to ensure that appropriate thermal
support and further voltage support is in place by the summer of 2010. This approach reflects
the Company’s dedication to addressing future reliability problems and represents a cost-
effective way of mitigating future problems with current solutions.
38 In June 2007, the Company installed two temporary 52.5 MVAR portable capacitor banks on the 115 kV bus at Huntley Station. Those facilities, for which no cost deferral is sought in the Petition, will be available for use elsewhere on the system once the future improvements described above are made.
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The Frontier Region program is expected to produce no net O&M expense savings in
2008. As explained in Exhibit P-3, this program is not being undertaken because of high or
increasing O&M costs, but to address the specific needs created by the retirement of the
generating units at Huntley Station.
Reliability Criteria Compliance
This project involves the expenditure of $122 million in capital and $3.7 million in
capital-related O&M to construct major reinforcements of the 115 and 230 kV transmission
systems in western NY, including the Frontier, Southwest and Genesee regions that extend from
the NY/Canada border east to Mortimer Station and south to the Pennsylvania border. This
program was not anticipated at the time of the Merger Rate Plan or included in the Company’s
initial capital and expense budget. The engineering, technical, and economic justification for the
program is found in Exhibit P-4 and Exhibit 15 to the Capital Investment Plan.39
National Grid decided to undertake this program following recent studies of the 115 kV
and 230 kV transmission systems of these regions. The studies were performed for years 2006
through 2017 and included both N-1 and N-1-1 design criteria. These studies identified the need
for system improvements to remedy several reliability criteria violations for the regions based on
NERC TPL Standards, NPCC A-2, NYSRC Reliability Rules and National Grid Transmission
Planning Guide 28. These include thermal overloads on 115 kV circuits in the Frontier region
(N-1 and N-1-1), 230 kV and 115 kV voltage problems at Gardenville (N-0, N-1 and N-1-1),
thermal overloads on transformers at Gardenville (N-1-1), voltage problems around Homer Hill
(N-0, N-1, N-1-1) and voltage problems around Golah (N-1 and N-1-1). Most of these problems
39 The supporting documentation in Exhibit P-4 includes a justification document, three planning studies, one screening analysis and two detailed studies on the area, a summary presentation on the Western area studies, and an estimate of O&M savings. Exhibit 15 of the Capital Investment Plan includes two strategy papers.
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were identified in analysis completed late in 2006 based on 2006 load levels, and the problems
only worsen based on load levels forecasted for later years.
The Company’s program to remediate these potential reliability problems comprises the
following components:
• Rebuilding 27 miles of double circuit 115 kV transmission line between Packard, Paradise and Gardenville correcting overloads;
• Constructing a new 345:115 kV station near Homer Hill station tying into Homer
City – Stolle 345 kV line #37 and Gardenville – Homer Hill 115 kV lines #151 and #152 to support area voltage;
• Installing three 75 MVAR capacitor banks on the 115 kV buses at Gardenville to
support the 115 kV and 230 kV bus voltage;
• Reconductoring 6 miles of Falconer – Warren 115 kV #171 to prevent the circuit from being opened by First Energy due to loading concerns;
• Installing a second bus tie breaker between the National Grid and NYSEG
substations at Gardenville to correct overloads;
• Installing a 15 MVAR capacitor bank at Andover to boost area voltage; and
• Converting a 10.5 mile 69 kV circuit between Mortimer and Golah stations to 115 kV to prevent low voltage conditions.
The portions of the system described above do not meet mandatory reliability standards and
therefore must be upgraded. Many of the newly identified problems are expected to worsen as
area loads grow. As a result, voltage support and correction of thermal overloads is needed as
soon as possible.
The estimated capital cost for this project of $122 million is projected to be incurred as
follows: $3.3 million in 2008; $7.8 million in 2009; $32.6 million in 2010; $43.9 million in
2011; and the remainder in 2012-2013. This program is driven by voltage and thermal current
carrying capability and therefore no maintenance expense savings are expected in 2008 and
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beyond.
Clay 345 kV Substation Rebuild
This project involves the expenditure of $35.1 million in capital and $1.1 million in
capital-related O&M to rebuild the Clay 345kV substation in situ to address issues identified in a
2003 review of the facilities. This program was not anticipated at the time of the Merger Rate
Plan or included in the Company’s initial capital and expense budget. The engineering,
technical, and economic justification for the program is found in Exhibit P-5 and in Exhibit 17 to
the Capital Investment Plan.
As explained in more detail in the exhibits,40 Clay Station is a 345/115kV bulk power
substation located northwest of Syracuse and south of Oswego. Clay Station was constructed
between 1960 and 1967. Thus, the majority of its equipment exceeds 45 years of age. When
reconfiguration began in 2006, the station had ten 345kV line terminals arranged in a “switch
and a half” dual bus arrangement. Clay Station is one of the critical bulk power stations in
central New York. It is a hub for approximately 3300 MW of generation from the north and
2400 MW of generation from the west.
National Grid decided to undertake the reconfiguration of Clay Station to address several
important reliability concerns. First, there are several concerns regarding the age of the Clay
345kV Station equipment. The oil circuit breakers are beyond their useful life and are
underrated; the protection systems, control systems, and communications packages are beyond
their useful life; the station bus insulators do not have sufficient strength to meet structural
requirements; and the disconnects are beyond their useful life and underrated. These conditions
40 The supporting documentation in Exhibit P-5 includes a justification document, a 2003 conceptual upgrade study, and an estimate of O&M savings. Exhibit 17 of the Capital Investment Plan includes a strategy paper, a sanction paper authorizing the anticipated expenditures, and an engineering scope document.
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present a higher than acceptable risk of failure, threaten reliability and also present a safety risk.
Second, Clay 345kV Substation does not conform to the current NPCC A-5 criteria.
Specifically, the protection and control systems do not conform to the separation criteria required
for protection systems in bulk power stations; the Oil Circuit Breakers have single trip coil
systems rather than two redundant control systems; and, before this program, the control building
could not accommodate any changes or expansion to bring the station up to NPCC A-5
standards.
A variety of facility attributes currently contribute to the potential for equipment failure.
Some of these concerns are stated below; please see Exhibit P-5 for a detailed justification of
each proposed modification/replacement.
• Because of the age of the relays and the difficulty in finding spare parts, the relays often drift beyond tolerable settings. This drift may cause the relays to automatically operate when not needed, or to fail to operate when required.
• Clay Station’s control cables have PVC and/or rubber jackets that are
deteriorating due to age, causing 300-400 man-hours to be spent each year locating and correcting battery grounds.
• The 345kV disconnects are manually operated and are a safety concern when
operating.
• Existing post bus insulators do not have sufficient strength capabilities required today to meet the structural requirements associated with the design for higher short circuit capabilities.
In addition, the amount of construction required to upgrade the Clay 345kV Station relays
has also triggered the need for the entire facility to be brought up to compliance with NPCC A-5
standards, which is a significant driver of the final scope of this project. This will require the
Company to install redundant relay and control systems, physically separated such that the loss
of one would not impact the other.
To remediate these potential concerns, the Company is undertaking a major multi-phase
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project to rebuild the existing 345kV substation in situ on a bay by bay basis. This complex
project is being undertaken over four years, since the scheduling of the work involves taking
outages on the critical circuits. The work commenced in 2006 and is scheduled to be completed
in 2008, with project closeout in 2009.
As of the date of this Petition, the Company has installed a new Control building, station
service and backup generator. We have also completed the re-building of bays 6, 7 and 8. This
leaves the completion of bay 5, which is partially rebuilt, the rebuilding of bay 3, the relocation
of the Pannel line 2, Edic line 2-15, Dewitt line 13 and Nine Mile Point line 8, the associated
remote terminal work at Dewitt and Nine Mile Point and the removal of the bay 2 equipment, all
to be completed in 2008.
The total capital cost for this project is estimated to be $35.1 million. It is projected that
approximate expenditures for this project through the end of 2007 will be $29.3 million.
National Grid is not seeking authority under the Merger Rate Plan to defer costs incurred before
2008. Spending for the remainder of this project in 2008 and 2009 is estimated to be $5.8
million. National Grid proposes to defer only costs incurred during the latter period; carrying
charges associated with costs incurred earlier on this program will be absorbed by shareholders
until the time of the next rate case.
National Grid estimates that the Clay Station Rebuild program will result in net O&M
savings of $222,000 in 2008 due to a reduction in both unplanned and planned maintenance
resulting principally from spending on this program in earlier years. The basis for the estimate is
included in Exhibit P-5.
Conductor Clearance Correction Program
The Conductor Clearance Correction program involves the expenditure of $44.6 million
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in capital and $1.3 million in capital-related O&M to increase the clearance of certain overhead
conductors. This program was not anticipated at the time of the Merger Rate Plan or included in
the Company’s initial capital and expense budget. The engineering, technical, and economic
justification for the program is found in Exhibit P-6 and Exhibit 18 to the Capital Investment
Plan.
The need for greater clearances was identified as a result of a 2005 review of parts of the
transmission system using an innovative technology called Arial Laser Survey (“ALS”), in
which aerial surveys measure clearances with an accuracy previously unavailable except by
ground inspection. The facilities at issue are the Company’s overhead transmission lines that
currently do not meet the clearance standards prescribed by the National Electric Safety Code
(“NESC”). Preliminary results of an ALS to date have indicated that approximately one-fifth to
one-quarter of the spans (based on 782 spans) are not currently in compliance with the applicable
code.41
National Grid discovered the need to update substandard clearances through its
application of current computational power, survey techniques, installation methods, and
engineering practices, which all allow for higher levels of accuracy than available at the time the
lines were constructed. The modern laser survey technology made it cost-effective to undertake
the project in 2005. In the past, survey crews needed to visit each location at a high cost in terms
of time and effort. Today, in contrast, the ALS technology has allowed the Company to
determine quickly and cost-effectively which spans require clearance correction.
The NESC is designed to ensure public safety. Although the risk of a safety event
occurring as a result of substandard clearance conductors is low, the results of such a safety
event could be extremely serious. Thus, addressing the non-compliant spans will enhance the 41 See Exhibit P-6.
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safety of National Grid’s facilities and reduce risks to the Company’s employees and the public.
To mitigate the potential hazards, the Company will implement line clearance
rectification projects where the NESC governing code requirements have not been met. As
described in greater detail in the supporting Exhibits,42 the code requirements vary depending on
what date the transmission line went into service. Clearance of the lines will be prioritized based
on the enhancement of public safety, but at the same time the work will be bundled by
geographic areas to ensure efficient delivery. In order to enhance public safety, the Company
will bring clearances over railroads, roads, streets, driveways, parking lots, water bodies, and
clearly developed right-of-way access roads crossing under a span up to current standards even
in cases where such clearances are grandfathered.
The anticipated $44.6 million capital cost for this program is projected to be incurred as
follows: $1.2 million in 2008; $6.0 million in 2009; $10.4 million in 2010; $15.9 million in
2011; and the remainder in 2012. Actual expenditures may vary depending on the number of
spans that are discovered through ALS to be in noncompliance with NESC standards.
The Conductor Clearance Correction program is expected to produce net O&M savings
of $36,000 in 2008 due to decreased planned preventive maintenance. This decrease results
because replacement structures do not require maintenance such as painting and footer
inspections for steel structures, and ground line treatments for wood poles, as explained in
Exhibit P-6.
Overhead Line Replacement and Refurbishment Program
The Overhead Line Replacement and Refurbishment Program (“OHL Program”)
42 The supporting documentation in Exhibit P-6 includes a justification document and an estimate of O&M savings. Exhibit 18 of the Capital Investment Plan includes an approved strategy paper, a sanction paper authorizing certain of the anticipated expenditures, and a 2005 conductor clearance study.
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involves investment of an estimated $48.2 million and $1.4 million in capital-related O&M over
the period 2008-2011 to refurbish, reconductor or replace towers and wood poles. This program
was not anticipated at the time of the Merger Rate Plan or included in the Company’s initial
capital and expense budget. The engineering, technical, and economic justification for the
program is found in Exhibit P-7 and Exhibit 10 of the Capital Investment Plan. 43
Many of the New York overhead line assets are approaching, and some are beyond, the
end of their anticipated lives. As assets age beyond these earliest onsets of unreliability, the
reliability of each component can be expected to decrease. Over the course of the next 25 years,
the Company proposes to implement a program to replace or refurbish steel towers, replace
wood poles, and reconductor the transmission lines with static line replacement.
The anticipated $48.2 million capital cost for this program during the deferral period is
projected to be incurred as follows: $0.7 million in 2008; $2.5 million in 2009; $10.5 million in
2010; and $34.5 million in 2011. Much of the initial work, which will begin in 2008, is
preliminary engineering. To an even greater extent than other programs, the costs of this
program remain contingent upon timely environmental and siting regulatory reviews and
approvals.
For each of the discussed facilities, the Company has carefully determined the anticipated
life of the asset and the cost-effective method for ensuring that the Company’s transmission
facilities remain effective and reliable. Although asset age will provide the initial screening tool
for determining aging assets, four attributes will control their replacement: (i) five-year
reliability performance averaging, (ii) condition as determined by field testing, (iii) average age
of the assets in the region and (iv) risk. Replacing, refurbishing and reconductoring these assets
43 Exhibit P-7 includes a justification document and several supporting documents, as well as an estimate of O&M savings. Exhibit 10 includes a strategy paper, a sanction paper and engineering scope documents.
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will ensure that the Company will avoid decreasing reliability results.
Implementation of the Overhead Line program will not result in any net O&M savings
during 2008 as explained in Exhibit P-7, as the program is in the preliminary engineering phase.
Digital Fault Recorder Strategy Program
This program involves the expenditure of $7.1 million in capital and $0.2 million in
capital-related O&M to replace Digital Fault Recorder units (“DFRs”) to ensure the availability
of sufficient information during system events at critical substations. This program was not
anticipated at the time of the Merger Rate Plan or included in the Company’s initial capital and
expense budget. The engineering, technical, and economic justification for the program is found
in Exhibit P-8 and Exhibit 19 to the Capital Investment Plan.44
Replacing or upgrading the DFRs will ensure that the Company meets the revised NPCC
requirements outlined in the NPCC Bulk Power System Protection Document A-5 on Fault
Recorders. It will also address Recommendation 12 of the August 14, 2003 Blackout NERC
Actions to Prevent and Mitigate the Impact of Future Cascading Blackouts, published on
February 10, 2004. In total the program addresses 22 DFRs located at critical locations across
National Grid’s transmission system.
The total estimated capital cost of $7.2 million is expected to be incurred as follows:
$1.3 million through 2007; $1.7 million in 2008; $2.3 million in 2009; $1.5 million in 2010; and
the remainder in 2011. Replacement of the DFRs will improve reliability and will promote
efficient management of the transmission grid. In the event of a system failure, quicker and
more reliable data will help with system restoration by pinpointing which element has been
44 The supporting documentation in Exhibit P-8 includes a justification document, applicable NERC standard and NPCC criteria documents, and an estimate of O&M savings. Exhibit 19 of the Capital Investment Plan includes a strategy paper, a sanction paper authorizing certain of the anticipated expenditures, and engineering scope documents for individual projects engineered to date.
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affected as well as by providing information used to analyze the system to prevent future
disturbances.
As explained in Exhibit P-8, the DFR Strategy program will increase the number of
devices on the system requiring planned preventive maintenance, and therefore no maintenance
expense savings are expected in 2008 and beyond.
Remote Terminal Unit Strategy Program
The Remote Terminal Unit (“RTU”) Strategy program involves the expenditure of $17.2
million in capital and $0.5 million in capital-related O&M to replace obsolete monitoring and
control equipment with current and fully functional equipment. This program was not
anticipated at the time of the Merger Rate Plan or included in the Company’s initial capital and
expense budget. The engineering, technical, and economic justification for the program is found
in Exhibit P-9 and Exhibit 20 to the Capital Investment Plan.
RTUs are an integral part of the supervisory control and data acquisition (“SCADA”)
system, in that the RTUs take inputs from a remote location, such as breaker open/close status,
transformer/line loading and alarming and transmit it to a computer at a system control center.
RTUs also take control commands from the control center and transmit them to a remote
location. In the 1980s, the Company installed RTUs at locations throughout the system. These
locations included all substations having a bus voltage of 13.2kV or above, generating stations,
and stations owned by neighboring utilities that connected to our system. In the intervening
years, additional RTU models have been installed in various locations. There are currently
approximately 550 operating RTUs under National Grid’s control in New York, of which 12345
would be replaced under this program.
45 The RTU strategy covers replacement of 165 RTUs for both transmission and distribution. This program only refers to transmission RTU replacement and expenditures
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As a result of the August 14, 2003 blackout and subsequent NERC recommendations, the
Company reexamined it RTU assets. Many of the RTUs have become obsolete and are not
supported by the manufacturer, and replacement parts and test equipment are either difficult to
obtain or completely unavailable. Much of the current test equipment is no longer serviceable
and operates on older computer hardware and software that is no longer supported by the
manufacturer. In addition, most of the now obsolete RTUs will not work with modern energy
management systems, which the Company expects to implement by 2011.
NERC Recommendation 28, released in response to the 2003 blackout, requires the use
of, among other things, more modern, time synchronized data recorders. Many in-service RTUs
do not satisfy this requirement. NPPC’s recent release of Document A-15 may further increase
the number of RTUs that need to be replaced.
As described in more detail in the supporting Exhibits,46 the Company will remediate
potential concerns by replacing 123 Company-owned transmission RTUs located both at
Company-owned stations as well as at interconnections with neighboring utilities and generating
stations. The Company is also proposing to acquire test equipment that will adequately maintain
the new RTUs. Replacement of specific units will be scheduled so as to maximize reliability and
minimize costs, with priority determined by bulk power status, stations where the current RTU
has operational or maintenance issues, and stations with ongoing or upcoming construction.
Replacement of the RTUs will improve reliability and will promote efficient management
of the transmission grid. In the event of a system failure the new RTUs will provide more
accurate data quickly to control centers, which will aid system restoration. The use of existing
46 The supporting documentation in Exhibit P-9 includes a justification document. Exhibit 20 of the Capital Investment Plan includes a strategy paper, a sanction paper authorizing certain of the anticipated expenditures, and engineering scope documents for individual projects engineered to date.
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RTUs will result in decreased system reliability because of increased risk of equipment failures
and because the obsolete RTUs will not communicate properly with the energy management
system upgrade planned to be installed on the Company’s transmission grid by 2011.
The total estimated capital cost of $17.2 million is projected to be incurred as follows:
through the end of 2007, $3.5 million; $2.8 million in 2008; $1.9 million in 2009; $2.0 million in
2010; $0.5 million in 2011; and the remainder in 2012 and later years. National Grid is not
seeking authority to defer the revenue requirement impact of costs incurred before 2008. As
described in Exhibit P-9, the RTU Strategy program is expected to produce no net O&M savings
in 2008.
3A/3B Towers Program
The 3A/3B Towers program involves the expenditure of $30.4 million in capital and
$500,000 in capital-related O&M to replace certain transmission towers whose design and
location make them unacceptably vulnerable to failure. This program was not anticipated at the
time of the Merger Rate Plan or included in the Company’s initial capital and expense budget.
The engineering, technical, and economic justification for the program is found in Exhibit P-10
and Exhibit 21 to the Capital Investment Plan.47
The 3A/3B Towers program was established following a 2003 tower failure. As
described in greater detail in the supporting Exhibits, the facilities at issue in Phase I of the
program are 139 transmission towers that are in service at road crossings and that support the
Edic-New Scotland 14 345 kV line. Phase II of the program will examine towers meeting
equivalent criteria on the Athens-Pleasant Valley 91, Leeds-Pleasant Valley 92, and New
47 Exhibit P-10 includes a justification document, engineering analysis on type 3A and 3B towers, incident analyses and supporting information from previous tower failures, and an estimate of O&M savings. Included in the Capital Investment Report as Exhibit 21 is an engineering design report on the Edic-New Scotland 14 line, a strategy paper, a sanction paper authorizing certain of the anticipated expenditures, a wind speed and climatology study, and engineering scope documents for individual projects engineered to date.
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Scotland-Leeds 93 and 94 345 kV lines. The Edic-New Scotland 14 line is the third most
important bulk transmission line in New York, as its interface heavily supports the power supply
to downstate New York and New England, and would pose a considerable threat of congestion if
disabled. Although there are six tower types on the line, only the 3A and 3B tower types have
presented safety and reliability concerns.
The Edic-New Scotland 14 line runs largely east-west, and with the prevailing wind
direction being west-to-east, the prevailing wind blows in the precise direction in which risk of
failure is greatest. Other lines that contain the 3A and 3B tower types run primarily north-south,
and so present less of a risk of failure due to high wind speed above the design capabilities of the
present structures.
The 3A and 3B tower types have experienced failure three times since the line was first
energized in 1962, most recently, as noted above, in 2003. In each case the failure resulted from
extreme longitudinal wind loading generated by storms. Although the failure of a tower causes a
transmission line outage, the primary justification for Company’s decision to replace the 104
towers is the safety hazard potential to pedestrians, railroad passengers, boaters, drivers and
passengers of motor vehicles that use the transportation crossings at which these towers are
located.
Based on extensive analyses of the towers at issue, the Company is proposing to replace
104 of the 3A and 3B towers by 2009 that pose the greatest public safety concerns. The
replacement towers will not only meet higher wind speed standards but will also have new
insulators and fittings that should bring an additional reliability improvement.
An estimated $30.4 million will be incurred in 2008 to 2011. The current forecast of
capital expenditures for the 3A/3B Towers program is the following: $6.9 million in 2007; $10.1
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million in 2008; $4.8 million in 2009; $7.8 million in 2010; and $7.6 million in 2011. National
Grid is not seeking, and will not seek, deferral of expenditures incurred before 2008. As
discussed further in Exhibit P-10 (at page 3q of the Overview), these costs reflect the difficulty
of working with live transmission wires, the increased cost of steel and other supplies, and the
increased need for hardware.
The 3A/3B Towers program is expected to produce net O&M savings of $37,000 in 2008
due to decreased planned preventive maintenance. This decrease results because replacement
structures do not require maintenance such as painting and footer inspections.
Steel Towers
The Steel Towers program involves investment of $132 million and $4.0 million in
capital-related O&M to repair and replace deteriorated steel transmission towers on National
Grid’s transmission system. This program was not anticipated at the time of the Merger Rate
Plan or included in the Company’s initial capital and expense budget. The engineering,
technical, and economic justification for the program is found in Exhibit P-11 and Exhibit 7 to
the Capital Investment Plan.
The Steel Towers program was established following a review of our steel towers after
several tower failures in 2003 and 2004. As described in greater detail in the supporting
Exhibits,48 the facilities at issue are approximately 20,000 steel transmission towers that are in
service across National Grid’s service territory. Due to the deteriorated condition of certain of
these facilities, a serious safety and reliability concern exists. Although all voltage levels were
initially examined, the major concern focuses on towers on 115 kV transmission lines.
48 The supporting documentation in Exhibit P-11 includes a justification document, engineering analysis on the condition of National Grid’s steel towers, and an estimate of O&M savings. Exhibit 7 of the Capital Investment Plan includes a strategy paper, sanction papers authorizing certain of the anticipated expenditures, and engineering scope documents for individual projects engineered to date.
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Based on extensive analyses of the towers at issue, the Company is proposing a program
to inspect and categorize all steel towers and based on the grade each receives to either maintain
the towers through an accelerated painting program49 or to replace the towers. It is estimated
that there are currently 2,400 steel towers in need of replacement and that an additional 2,100
will need replacement before the end of the program. The replacements will be prioritized based
on those that pose the greatest public safety concerns.
The estimated capital cost for this project of $132 million is expected to be incurred as
follows: $7.6 million in 2008; $13.9 million in 2008; $24.7 million in 2009; $39.3 million in
2010; $20.0 million in 2011; and the remainder in later years. O&M expense will not be subject
to deferral unless it qualifies as capital-related O&M.
The Steel Towers program is expected to produce net O&M savings of $51,000 in 2008
due to decreased planned preventive maintenance. As explained in Exhibit P-11, this decrease
results because replacement structures do not require maintenance such as painting and footer
inspections.
Future Incremental Programs
As described in the Capital Investment Plan, National Grid is developing and/or
implementing a number of other programs. While National Grid believes these programs would
also qualify for special ratemaking treatment under Section 1.2.4.16, National Grid is not
including spending associated with these programs in this petition because, in some cases, the
timing of the program is uncertain, and in others, the programs are at an early stage of
development, so that the necessary technical and engineering support is not available. They may
be the subject of future petitions.
The following programs are currently under development but are not included in this 49 The costs for the painting program are O&M and not included in this deferral request.
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request for deferral treatment:
• Luther Forest: This major program consists of reinforcements of the transmission
system in the Saratoga and Glens Falls area of Eastern NY necessary to respond
to reliability needs caused by area load growth and the impact of the proposed
Luther Forest Technology Campus. The timing and content of this program
depends upon a decision by Advanced Micro Devices (“AMD”) to move forward
with its plans to build a new micro-chip fabrication facility. This program is
expected to cost approximately $80-90 million.
• Line crossing strategy: This program would implement modifications to the
transmission system to lessen the reliability impacts of failures of facilities where
the mechanical failure of one circuit could cause the failure of an additional
circuit. This problem exists where one transmission circuit crosses another circuit
at locations vulnerable to failure such as terminating structures with multiple
circuits. This program is expected to cost $5-10 million.
• Flying ground strategy: Flying ground switches have been used as a method of
interrupting faults on the transmission system by deliberately placing a fault on
the system that allows remote circuit breakers to operate when they otherwise
would not operate for the original fault. This program is expected to cost $5-10
million.
• 115 kV Substation Bulk Power System Upgrades: This program results from a
recent change in the NPCC definition of Bulk Power Facilities (“BPS”). This
change can result in a reclassification of facilities from non-BPS to BPS. A
reclassification to BPS requires the facilities to be compliant with all standards
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related to BPS. While the studies associated with this change are not yet
complete, we have identified three substations that might need significant
investment to meet the new standards. This program is expected to cost
approximately $40-50 million.
• Substation Rebuilds: This major program of work is being developed in response
to the reliability challenges faced by the company from aging infrastructure and to
prevent unacceptable risk of loss of supply events due to asset failures. There are
several substations that are currently being assessed for their overall condition.
Once these assessments are complete, a specific program will be developed. This
program is expected to cost approximately $40-50 million.
• Leeds SVC: A Static VAR Compensator (“SVC”) is a major piece of equipment
on the transmission system used to automatically regulate transmission reactive
power (“VARs”). This program is being developed to upgrade the SVC currently
located at the Leeds substation in Eastern New York. This device, which allows a
material increase in the Central East Interface connecting generation in upstate
New York to downstate load, is no longer supported by the manufacturer and
therefore future component failures might render the device un-repairable. This
program is expected to cost $7-10 million.
• Security Strategy: This program, which is under development, would enhance
reliability and security of the electric system through physical and cyber security
measures at stations currently without adequate protection from deliberate acts of
vandalism or from tampering with power system elements. The program would
include installation of equipment such as video surveillance, key card readers, and
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improved fencing to limit physical access to substation, as well as improved
firewall protection of the control systems within the station. This program is
anticipated to cost approximately $10-20 million.
• Other Major Programs: As we continue to analyze the transmission system and
assess the condition of each of its elements, we will develop new programs to
improve the reliability and safety of the network. A number of programs have
been identified that could provide benefits to customers. One example is breaker
replacement. This program consists of the replacement of obsolete and/or
problematic circuit breakers throughout the system. There are currently almost
400 circuit breakers that our modeling shows should be replaced over the next 10
years. Under this program we would review the condition and criticality of the
circuit breaker population and propose replacement based on criteria to be
established. Similarly, we are assessing other equipment classes as well as other
potential problems, such as areas prone to flooding, that we believe need attention
over the next decade. The breaker replacement program alone is preliminarily
estimated to cost $250 million.
C. Subtransmission Programs and Expenditures
As described in Section IV(A), above, shortly after the Merger Rate Plan was adopted,
National Grid took a fundamentally new approach to the management of its transmission assets.
National Grid has begun to apply that approach to its subtransmission system, which comprises
equipment primarily in the 23 kV to 69 kV voltage range. The process of managing the
subtransmission assets using a proactive, integrated approach is ongoing, and is expected to
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result in the development and initiation of a number of new major programs to address the
deteriorating condition of those assets and thereby to enhance the reliability of service to
customers.
To date, the Company has developed a subtransmission asset management program
involving the rebuilding of portions of 50 overhead subtransmission circuits, portions of 30
substations, and the automation of several circuits. The major automation implementation effort
for 2008 is full automation of the Boonville - Lowville 23 kV circuit and associated substations.
These programs were not anticipated at the time of the Merger Rate Plan or included in the
Company’s initial capital and expense budget. Additional detail with respect to the technical and
engineering justification for these programs may be found in Exhibits 11, 22, 24, 33, 34, 37, 39,
46, 51, and 58 included with the Company’s Capital Investment Plan compliance filing, which
are cross-referenced in the discussion below.
These programs are designed to address two aspects of the condition of the Company’s
subtransmission system that have been identified as a cause of an increasing number of customer
interruptions, as shown in Figure 4. First, equipment degradation on the subtransmission system
(substations, breakers, switches, poles, crossarms, insulators, conductor, and lightning arrestors)
has been identified as a leading cause of these customer interruptions. Second, the inability to
quickly isolate the damaged portion of subtransmission circuits has led to an increase in the
duration of outages caused by equipment problems on the subtransmission system.
To address these conditions, the Company plans to rebuild portions of 50 overhead
subtransmission circuits and 30 subtransmission stations to remediate equipment degradation that
threatens reliability, add automated switches to 3 circuits in the Eastern Division, and automate
the Boonville - Lowville 23 kV circuit to improve restoration capability. At this time, the
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request for deferral rate treatment for subtransmission systems is limited to programs in progress
to rebuild overhead lines and substations as well as to expand automation, totaling approximately
$14 million in 2008. The three components of the subtransmission asset management program
for which special ratemaking treatment is requested in this petition are described briefly below.
Overhead Lines The Overhead Line portion of the subtransmission asset management program involves
the rebuilding of portions of 50 overhead circuits and replacement of poles on several other
circuits. The program, which was developed in 2007, targets those subtransmission circuits that
have experienced poor reliability performance due to degraded equipment. The aim of the
program is to replace or rebuild equipment that is nearing the end of its useful life. As explained
in Exhibits 23 and 24 of the Capital Investment Plan, the subtransmission system includes nearly
70,000 poles with an average age of approximately 45 years, approximately 27% of which are
more than 60 years old. In 2008, portions of lines will be rebuilt, but as the program continues in
subsequent years, the Company plans to rebuild significantly longer portions of other lines.
The specific remediation projects that will be undertaken as part of this program are listed
in Exhibit P-14, workpaper 11, and include the replacement or poles, crossarms, insulators,
conductors, lightning arresters, and other pole top components. Projected total spending on this
program during 2008 through 2011 is approximately $19.6 million, with an expectation of an
additional $8.3 million in 2008.
National Grid projects that net O&M savings from implementation of this portion of the
subtransmission asset management program in 2008 will be between $1,500 and $3,000. This
estimate is based on the potential reduction in off-hour interruptions thereby saving a crew from
having to respond. The estimate details are provided in Exhibit P-12.
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Automation
This portion of the subtransmission asset management program involves the installation
of automatic sectionalizing equipment such as switches, reclosers, and modular control systems
linked by the Energy Management System to the Dispatch Center to allow a portion of the circuit
to be quickly reenergized after an electrical fault occurs. This project, which was developed in
2007, allows a reduction in the length of time customers are without power and provides
information on fault locations. The automation program focuses on subtransmission circuits
with breaker-to-breaker exposure of greater than 10 miles and is prioritized based on expected
reliability improvement. Technical and engineering support for this element of the program is
provided in Exhibit 22 to the Capital Investment Plan.
During 2008, the Company plans to install this automatic equipment on the Boonville –
Lowville 23 kV circuit. This circuit is one of the worst performing circuits and has multiple
distribution substations tapped off of it. This project is the first of its kind at National Grid and,
as such, the Company intends to learn from the experience prior to selecting additional lines for
automation. Automation of the Boonville – Lowville 23 kV circuit and addition of automated
switches to the three Eastern Division circuits is projected to cost $1.65 million in 2008.
Additional subtransmission circuits will be automated during 2008 through 2011 at a projected
cost of $8.1 million.
National Grid projects that net O&M savings from implementation of the Automation
program in 2008 will be approximately $1,000 or less based on the details provided in Exhibit P-
12. The Company estimated this savings based on reducing the time required to locate faulted
sections of overhead lines.
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Substations The substation portion of the subtransmission asset management program involves the
rebuilding/replacing portions of more than 30 substations. The program, which was developed
in 2007, targets those substations that have experienced poor reliability performance due to
degraded equipment. The aim of the program is to replace or rebuild equipment that is nearing
the end of its useful life. The asset strategies that address substation replacement/rebuild were
provided in Exhibits 11, 33, 34, 39, 46, 37, 51 and 58 to the Capital Investment Plan. These
strategies set out the age and performance of substation components and describe the reasons
these components have been selected. The Company plans to replace/rebuild significant portions
of other stations in the future.
The specific projects that will be undertaken as part of this program are listed in Exhibit
P-14, workpaper 11, and include items such as breakers, insulators, arresters and switches.
Projected total spending on this program during 2008 through 2011 is approximately $67
million, with an expectation to incur $4.2 million in 2008.
National Grid projects that there will not be any net O&M savings from implementation
of this portion of the subtransmission asset management program because the majority of work
to repair failures on substation equipment such as breakers, switches, insulators and arresters is
capitalized.
Future Subtransmission Programs
The Company is also developing additional programs to address conditions on the
subtransmission system, including new programs to reconfigure the system and to replace
underground subtransmission cables. National Grid anticipates delaying portions of the CY 08
work of these programs from the schedule presented in Exhibit 14, workpaper 11, to include
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spending approximately $.5 million in preparatory work in 2008 and $178 million in 2009 to
2011. Because these programs are still under development, National Grid does not seek to defer
carrying charges associated with investments in these programs in this filing. They may,
however, be the subject of future petitions. The programs under development are briefly
summarized below:
Area Reconfiguration 34.5 & 46 kV
The Area Reconfiguration program was developed in 2007 to study critical areas of the
subtransmission system and develop system reconfiguration plans to improve reliability. The
key elements of this program are (1) the conversion of radial subtransmission lines to looped
configurations, (2) the addition of substations, and (3) the circuit automation described above.
Since the infrastructure has become aged, it is time to take a critical review of the existing
design. This system was largely designed in the 1920s-1950s and, as such, has the potential to
be significantly improved using a new approach to serving the load. This program will evaluate
the options and then implement solutions.
Underground Cable
In 2007, National Grid began development of a program to replace a significant portion
of the subtransmission underground system. The program will target cables that are more than
60 years old and replace them over the next 15 years. The aim of the program will be to replace
underground subtransmission cable that is nearing the end of its useful life. This should improve
reliability, especially in the metropolitan regions of Buffalo, Niagara Falls and Albany, where
there are concentrations of underground subtransmission cables. National Grid expects to seek
authorization to defer costs associated with its underground cable program once it is sufficiently
developed.
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D. Distribution Programs and Expenditures
National Grid’s new approach to the management of its T&D assets is reflected, with
respect to the distribution system, in the Company’s Reliability Enhancement Plan (“REP”). As
noted in Section IV(A) above, National Grid experienced an unforeseen deterioration of
reliability early in this decade, beginning in 2002, as illustrated in Figure 1. In response, the
Company began the development of a program with both capital and O&M elements – the REP –
in 2005 to target those portions of the distribution system that were experiencing degraded
performance. The REP is a critical component of National Grid’s intensive effort to address the
condition of its delivery infrastructure to improve service reliability.
Reliability Enhancement Plan
The REP is a five-year program focused on strengthening the reliability performance of
the distribution system that comprises both capital and O&M spending initiatives. The capital
portion of the REP involves the replacement or rebuilding of equipment that is nearing the end of
its useful life, as well as the installation of equipment to aid in system restoration. This intensive
program to replace aged infrastructure with new distribution facilities will provide long-term
performance benefits to customers. This program was not anticipated at the time of the Merger
Rate Plan or included in the Company’s initial capital and expense budget submitted in July
2002.
The REP was described in detail in Reliability Panel’s rebuttal testimony submitted by
National Grid in Case No. 06-M-0878; a copy of that testimony is attached to this Petition in
Exhibit P-13. As explained in that testimony, total expenditures on the REP during the five years
ending in 2011 are expected to reach $360 million. National Grid does not seek special
ratemaking treatment for all of these expenditures. First, expenditures on the maintenance
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components of the REP, which are expected to be approximately $125 million, are excluded.
Second, when the REP was developed, the Company included within its framework certain T&D
capital initiatives that were already under way at the time of the Merger Rate Plan. National
Grid does not consider those elements of the REP to be incremental and so has excluded
estimated expenditures on them from its proposed deferrals. Third, National Grid is excluding
the revenue requirement impacts of the amounts it will have invested in REP programs prior to
2008.
National Grid plans to expand this program further, as explained in the Company’s
October 22 compliance filing. The expansion of the REP will result in a total incremental capital
investment of $60 million in 2008 and total incremental capital investment of $449 million
between 2008 and 2011.50 It is the 2008 portion of this capital program that is the subject of this
deferral filing.
The capital elements of the REP include asset replacement of substation, overhead and
underground facilities; the addition of substation and distribution equipment to isolate damage
and provide contingency support; and the expansion of the EMS to improve the restoration
capability of the system. The elements of the REP were defined to address the specific causes of
this degradation and to aid in quicker restoration. Accordingly, capital components of the REP
include the following:
• Feeder Hardening;
• Substation Asset Replacement;
• Underground Deteriorated Equipment;
• Targeted Pole Replacements;
50 See Exhibit P-14, workpaper 12.
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• Mainline Reconductoring;
• Recloser Installations & Fusing & Engineering Reliability Reviews;
• Cable Replacement;
• Distribution Transformer Upgrades; and
• EMS Expansion.
The following exhibits that were filed with the Capital Investment Program and Asset
Condition Report provide engineering and technical support for these REP capital components.
The descriptions of the REP components in the exhibits reflect the fact that programs to upgrade
distribution assets are structured differently than those directed to transmission assets, as
discussed above. Unlike the transmission system, which consists of a relatively small number of
large and costly facilities, the distribution system comprises many thousands of much smaller
and less costly facilities. Engineering and technical support for programs to rehabilitate the
distribution system necessarily will involve a higher degree of generalization, and will not be as
facility-specific, as those prepared for programs to rehabilitate the transmission system. They
are, however, no less important in terms of their significance in delivering reliable service to
customers. The exhibits supporting the components of the REP are as follows:
Report Exhibit Number Exhibit Description CIP 31 Feeder Hardening Strategy 33 Substation Insulators 34 Substation Metalclad Switchgear 36 Reactors 39 Substation Surge Arrestors 41 Distribution Line Transformer Strategy 46 Battery and Related Equipment 47 Substation Capacitor Banks 51 Substation Infrastructure 52 Instrument Transformers
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58 Substation Transformers 40 Ducts and Conduit Strategy 42 Manholes Strategy 23 Subtransmission and Distribution Tower Strategy 57 Poles Strategy 37 Distribution Line Recloser Application 38 Line Reclosers 62 Distribution Engineering Reliability Reviews 44 Primary Underground Cable Strategy 45 Underground Getaway Cable Strategy 59 Underground Residential Distribution Cable
Strategy 22 Subtransmission Automation 24 Subtransmission Circuit Hardening 25 Subtransmission Cable Condition Report
12 Asset Information Maintenance Management System
11 Substation Equipment Assessment 17 Distribution Problem Identification Worksheet 3 Equipment Inspection Protocols 4 Equipment Inspection Cycles 5 List of Operating Procedures 6 New Prioritization of Work from Computapole
National Grid projects that net O&M savings from implementation of this portion of the
distribution program in 2008 will be approximately $180,000. This estimate is based on the
potential reduction in off-hour interruptions thereby saving a crew from having to respond,
reducing the time it take to find the fault, or both. The estimate details are provided in Exhibit P-
12 for distribution automation, cable, feeder hardening and reclosers.
E. Capital-Related O&M
Capital-related O&M consists of costs that are incurred directly as a result of capital
investment, but that, due to accounting rules and conventions, are classified as operating expense
rather than as capital. Specifically, the accounting regulations of the Federal Energy Regulatory
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Commission (“FERC”)51 provide that O&M shall include labor, materials, overheads and other
expenses, regardless of whether a capital project is involved, if the activity involves the
following:
• Direct field supervision of maintenance. • Inspecting, testing and reporting on conditions of plant specifically to determine the
need for repairs, replacements, rearrangements, and changes; and inspecting and testing the adequacy of repairs which have been made.
• Work performed specifically for the purpose of preventing failure, restoring serviceability of maintaining the life of plant.
• Rearranging and changing the location of plant not retired. • Repairing for reuse materials recovered from plant. • Testing for, locating and clearing trouble. • Net cost of installing, maintaining, and removing temporary facilities to prevent
interruptions in customer service. • Replacing or adding minor items of plant which do not constitute a plant unit.52
Virtually all capital projects constructed involve some relationship or interface with existing
facilities. Many of these projects involve a combination of complicated reconfigurations of
existing facilities and construction of many interface points between new and old facilities.
When there are existing facilities of any kind involved, there will be O&M costs.
Using a tower replacement as an example and following the established guidelines, the
following O&M costs would be incurred:
• Accessing the location:
o Repairing roadways, bridges etc.; o Trimming trees and brush to maintain previous roadway clearance; o Snow removal; o Maintenance work on publicly owned road and trails when complete; and o Chemical treatment of right-of-way areas.
• Performing the work: o Transferring customer load for an outage, switching and reconnecting
circuits; 51 Code of Federal Regulations (18 CFR Part 101). 52 A minor unit of plant is any item that is less than a whole defined unit of plant, for example, a wood pole is defined as a unit of plant; hardware associated with the pole (bolts, nuts, washers, brackets) would be minor items of plant.
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o Detaching conductor and shield wire from the old tower, transferring and reattaching it to the new tower;
o Cleaning insulators; o Repairing grounds; and o Resagging, retying or rearranging position or spacing of conductors.
• Certain indirect costs (such as costs of engineering, direct field supervision, railroad flagmen, police protection, switching, grounding, wildlife protection, and the installation of swamp mats and hay bales/silt fences) support all aspects of a capital project.
Each of the foregoing activities is required to complete and integrate replacement of the
transmission tower – a capital project – even though such activities are classified as O&M in
compliance with FERC regulations.
F. There is no basis for imputing efficiency gains as a reduction to National Grid’s deferrals under Section 1.2.4.16.
While the Company has identified the expected impact of each program on net O&M
costs following completion of the program, National Grid believes it would be inappropriate to
impute O&M costs savings as an offset to its deferrals, for the following reasons. As a threshold
matter, there is no textual basis for doing so. Section 1.2.4.16 of the Merger Rate Plan
specifically addresses efficiency gains by giving National Grid “the right to propose a sharing of
any efficiency gains as a method to recover the costs for such program or expenditures.” Had the
parties to the Merger Rate Plan, or the Commission in approving that Proposal, wished to
mandate a sharing of efficiency gains, they surely would have done so. To require sharing now,
particularly under the circumstances of this proceeding, would entail an unwarranted re-writing
of the terms that the parties and the Commission adopted in 2001.
Moreover, the Company has no expectation of reducing the total number of personnel
devoted to maintenance and repair of the T&D system. To produce O&M savings as a result of
capital programs, it would be necessary to reduce the staffing levels of personnel performing
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maintenance and repairs on the T&D system. The Company does not intend to do that. Instead,
National Grid will redeploy people to work on other T&D facilities.
National Grid is, and will be, increasing its O&M expenditures over the five-year period
in question rather than reducing expenditures. National Grid is not requesting any deferral
treatment for these higher O&M expenditures under Section 1.2.4.16 except for capital-related
O&M, as discussed above. So any such savings would be but a fraction of the increased O&M
spending for which deferral treatment is not proposed.
V. The Proposed Ratemaking Treatment and Methodology
National Grid seeks deferral of 50% of the revenue requirement impact of the subject
programs. Costs would be deferred only if they arise from a facility that is closed to plant in
service during the deferral period addressed by this request, i.e., 2008. In addition, only costs
incurred during the deferral period would give rise to a deferral. For example, where a facility
valued at $20 million was closed to plant in service in 2008 but only $8 million was expended in
that year, with the rest having been expended prior to the deferral period, only the amount spent
in 2008 would be subject to deferral. These principles apply to both capital expenditures and to
capital-related O&M. The estimates provided in this petition will be updated for actual capital
and related O&M expenditures in 2008. All deferrals would be subject to full audit by the
Commission. Accounts would be maintained in accordance with regulatory requirements, and a
tracking mechanism would be established to facilitate Staff review. The methodology used by
National Grid to determine the revenue requirement impact of the T&D investment programs for
which deferral authorization is requested is described below.
Revenue Requirement Calculation
The Company’s revenue requirement includes a return on the rate base associated with
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the major incremental capital expenditures. The rate base includes gross plant, accumulated
depreciation reserve including cost of removal, and deferred taxes. In addition, the revenue
requirement includes associated depreciation expense, property taxes and incremental operating
expenses. These expenditures should be included in the revenue requirement since they are all
directly associated with the major incremental capital programs.
Exhibit P-14 consists of a summary sheet and six supporting sheets. Work papers follow
the summary sheet and six supporting sheets. Exhibit P-14 concludes with a summary and
details of program spending in support of the revenue requirement calculation, as well as
projected spending in 2009 through 2011. The exhibit’s summary sheet and six supporting
sheets are explained as follows:
Page 1 shows the estimated incremental revenue requirement summary for 2008. The
return on average incremental cumulative rate base was determined by applying the Weighted
Cost of Capital allowed in the Merger Rate Plan. In accordance with the Commission’s orders in
Case No. 06-M-0878, the Company is requesting to recover 50% of the 2008 calendar year
revenue requirement.
Page 2 shows the estimated incremental average capital investment for 2008. The
Company’s major incremental 2008 transmission and distribution capital expenditures were
obtained from the Company’s Transmission and Distribution Asset Strategy departments. For
purposes of the revenue requirement, the annual expenditures were cash flowed evenly over
twelve months. The cash flows were allocated into closing rule groups consistent with how the
Merger Rate Plan cash flows were grouped. Based on the closing rule groupings, the cash
flowed capital expenditures were closed to plant in service. Based on forecasted plant in service,
an incremental average gross plant impact was determined. Retirements were not forecasted to
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reduce either incremental gross plant or the incremental depreciation reserve since the net
ratebase impact is zero.
Page 3 shows estimated annual incremental book depreciation for 2008. Annual
incremental depreciation expense was developed by applying annual depreciation composite
rates to incremental annual plant closings using a half year convention for the first year of
closings. The annual depreciation composite rate for transmission and distribution was based on
December 2006 FERC Form 1 data. The calculation of depreciation considered estimated plant
retirements percentages. The retirement percentages were based on a 2002-2006 five year
historic average of retirements as a percentage of plant closings. An incremental average
depreciation reserve was determined based on the forecasted incremental annual depreciation
expense. Retirements were not forecasted to reduce either incremental gross plant or the
incremental depreciation reserve since the net ratebase impact is zero.
Page 4 shows the estimated incremental average cost of removal for 2008. An
incremental cumulative average net cost of removal impact was determined by applying a net
cost of removal factor to the incremental capital expenditures. The net cost of removal factor
was developed based on an average of the 2005 and 2006 calendar years’ historic cost of
removal compared to actual capital expenditures for the same time period.
Page 5 shows the estimated incremental average deferred tax balance for 2008. An
incremental average deferred tax balance was determined by applying a 40% combined Federal
and NY State tax rate to incremental tax depreciation associated with the incremental annual
plant closings (net of estimated retirements). The 40% combined rate was developed by
assuming a 35% gross Federal rate and a 7.1% NY State rate, while considering the state tax
deduction allowed for Federal purposes. The calculation for tax depreciation utilized 20 year
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Modified Accelerated Cost Recovery System (“MACRS”) for Distribution plant and 15 year
MACRS for Transmission Plant.
Page 6 shows the estimated incremental annual property tax expense for 2008.
Incremental property tax expense was determined by applying a 3.81% annual rate to
incremental plant closings with a one year lag of plant closings. The annual rate was based on a
2002-2006 five year historic average of electric property taxes as a percentage of electric plant.
The calculation of property taxes considered estimated plant retirements consistent with the
retirement percentage utilized for calculating incremental depreciation.
Page 7 shows the estimated incremental annual operating expense associated with
incremental capital investment for 2008. The incremental operating expense was determined by
applying capital related historic percentages to incremental capital expenditures. The
percentages were developed based on operating expenses associated with capital expenditures
for the twelve month period ended October 2007. Individual percentages were developed for
transmission, distribution feeder hardening and overall distribution.
Monthly Deferral Calculation
Exhibit P-15 consists of a summary sheet and six supporting sheets, which present the
proposed template for calculating the actual monthly 2008 deferral.
Page 1 shows the actual incremental revenue requirement summary for purposes of
calculating the actual monthly deferral. Consistent with the estimate of the revenue requirement,
first the actual incremental cumulative average rate base on the incremental capital expenditures
will be determined. Second, a return on average incremental cumulative rate base will be
determined by applying the Weighted Cost of Capital allowed in the Merger Rate Plan. Third,
estimated incremental depreciation expense will be determined. Fourth, estimated incremental
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property tax expense will be determined. Fifth, actual incremental operating expense associated
with incremental capital expenditures will be determined. Sixth, all components will be totaled
to arrive at an actual incremental revenue requirement. In accordance with the Commission’s
orders in Case No. 06-M-0878, 50% of the 2008 monthly revenue requirement is determined for
purposes of calculating the deferral.
Page 2 shows the actual incremental cumulative capital investment calculation. The
Company will report actual T&D dollars in-service for all T&D major incremental capital
spending beginning January 2008. The report will be based on the major incremental capital
spending programs identified by the Company’s Transmission Asset Strategy and Distribution
Asset Strategy departments. The report will be developed by month, by calendar year, starting
January 2008. The in-service dollars will represent the incremental capital investment impact.
Actual retirements will not be included to reduce either incremental gross plant or the
incremental depreciation reserve since the net ratebase impact is zero.
Page 3 shows estimated incremental depreciation expense and the estimated incremental
cumulative depreciation reserve calculation. Based on the actual monthly incremental capital
investment determined and reported on Page 2, the Company proposes to calculate incremental
monthly depreciation expense by utilizing the composite depreciation rates presented in Exhibit
P-15, workpaper 3. The actual retirements associated with the major incremental capital
expenditures programs will be tracked and applied against the incremental capital investment for
purposes of calculating depreciation expense. Based on the calculated depreciation expense, an
incremental depreciation reserve will be determined. Actual retirements will not be included to
reduce either incremental gross plant or the incremental depreciation reserve since the net
ratebase impact is zero.
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Page 4 shows the actual incremental cumulative cost of removal calculation. The
Company will report actual monthly cost of removal associated with the major incremental
capital expenditure programs beginning January 2008. The report will be developed by month,
by calendar year, starting January 2008.
Page 5 shows the estimated incremental cumulative deferred tax balance calculation.
Based on the actual monthly incremental capital investment impact determined and reported on
Page 2, incremental tax depreciation will be calculated. Based on the calculated tax depreciation
expense, an incremental deferred tax balance will be determined. The actual retirements
associated with the major incremental capital expenditures programs will be tracked and applied
against the incremental capital investment for purposes of calculating tax depreciation expense.
Page 6 shows the estimated incremental property tax expense calculation. Based on the
actual monthly incremental capital investment determined and reported on Page 2, the Company
proposes to calculate incremental property taxes by applying a 3.81% annual rate with a one year
lag of plant closings. The actual retirements associated with the major incremental capital
expenditures programs will be tracked and applied against the incremental capital investment for
purposes of calculating property tax expense.
Page 7 shows the actual incremental operating expense associated with incremental
capital investment calculation. The Company will report actual monthly incremental operating
expenses associated with the major incremental capital expenditure programs beginning January
2008. The report will be developed by month, by calendar year, starting January 2008.
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Booking of Deferrals
The Company proposes to begin booking the deferral effective to January 2008 and to
begin recovering the deferral in January 2010 as part of the Company’s Fourth CTC Reset filing.
VI. Impact on Deferral Account and Rates
National Grid currently projects that the gross revenue requirement impacts of eligible
expenditures for 2008, based on projected spending for the programs that are the subject of this
petition, will be $10.5 million. The level of deferrals for 2008 is estimated to be $5.3 million. If
ultimately approved for recovery as part of National Grid’s Fourth CTC Reset, the 2008
estimated deferrals would result in an increase of 0.01% in the total electric bill of the average
National Grid residential customer in 2010.53
VII. Conclusion
While the programs and expenditures for which National Grid seeks deferral
authorization in 2008 are relatively modest, they represent an important first step in the
rebuilding of the Company’s T&D system in order to meet the needs of future New York
electricity customers and the objectives of State policymakers. The process of defining those
needs and objectives depends vitally on the active engagement of National Grid, our regulators,
and our stakeholders. The contribution that National Grid’s T&D system will make toward
addressing the major issues confronting the State, such as economic development, greater energy
efficiency, and reducing greenhouse gas emissions, depends on the actions and investments that
are determined to best serve the long-range interests of our customers. This petition affords an
opportunity to launch a dialogue as to how together National Grid, the Commission, and our
stakeholders can determine the shape of the grid of the future.
53 This assumes that deferral recoveries are reset as part of the Fourth CTC reset process.
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Uncertainty about the common goals of stakeholders in rebuilding the T&D system and
uncertainty about regulatory support for implementation of those goals will make them difficult
if not impossible to reach. The litigation of the Company’s Second CTC Reset and deferral
filing under Sections 1.2.3.3 and 1.2.4 of the Merger Joint Proposal and the Stipulation of the
Parties resolving that litigation illustrate, respectively, the risks of uncertainty and the benefits of
resolving uncertainty. Going forward, it is crucial for National Grid to develop plans for
rebuilding and enhancing the T&D system that are supported by the Commission and by the
Company’s stakeholders, including plans the costs of which exceed the $1.47 billion
commitment to which the 50% limitation in the 2007 Merger Order applies.
The cornerstone of National Grid’s multi-year investment program is outlined in this
Petition. For the reasons explained above, National Grid believes the capital programs and
expenditures and capital-related O&M described herein meet the criteria prescribed by Merger
Rate Plan Section 1.2.4.16 and thus warrant deferral.
National Grid also believes that the issues raised by this Petition warrant full review and
an opportunity to be heard by all interested Parties. National Grid accordingly requests that the
Commission institute hearing procedures in this proceeding.
Respectfully submitted,
Robert H. Hoaglund II, Esq. Acting General Counsel, New York Distribution Niagara Mohawk Power Corporation d/b/a National Grid 300 Erie Boulevard West Syracuse, New York 13202 Phone: 315-428-5320 Fax: 315-428-5740 Email: [email protected]
73
Figures Referenced in Petition
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2002
2003
2004
2005
2006
$000
MJP
Est
imat
eAc
tual
Niagara Mohawk Power Corporation d/b/a National Grid Case 01-M-0075 Petition to Defer Electric T&D Investment Costs Figure No. 2
77
Fore
cast
ed In
vest
men
t Pla
n 20
08-2
011
$137
$139
$141
$142
$132
$193
$341
$443
$71
$116
$111
$152
0
100
200
300
400
500
600
700
2008
2009
2010
2011
$ million
Rat
e P
lan
Allo
wan
ceA
dd'l
Inve
stm
ent
Pet
ition
Inve
stm
ent
Niagara Mohawk Power Corporation d/b/a National Grid Case 01-M-0075 Petition to Defer Electric T&D Investment Costs Figure No. 3
78
NY
SubT
- D
eter
iora
ted
Equi
pmen
t Int
erru
ptio
ns
-102030405060708090
2002
2003
2004
2005
2006
2007
Year
Interruptions
*MS
Excl
uded
Niagara Mohawk Power Corporation d/b/a National Grid Case 01-M-0075 Petition to Defer Electric T&D Investment Costs Figure No. 4
79
