January 2012 Capital Investment - National Grid

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Exhibit ___ (EIOP-19)Page 25 of 684two year period for all NERC registered entities to bring those elements of thetransmission system, now brought into the BES per the new “definition,” into compliancewith all the mandatory, NERC standards.There are four main areas where that the Company has identified potential impacts to itsinvestment plans due to the bright line definition.• One aspect of meeting the proposed criteria would be to undergo a programsimilar to Conductor Clearance Strategy (SG163) on the circuits not formerlyincluded in the A-10 bulk circuit list but are on the new BES list (estimated to beover 200 additional circuits at this time). The current 5 year and 15 year Plansassume implementation of such a program over a 5-10 year period, instead of a2-3 year period, due to logistic implementation constraints. The conductorclearance program is in the capital investment plan at $75 million over 8 years.Adoption of the NERC rule would require implementation of the 8 year programin 2 years to 115kV spans with inadequate clearances to this new regulation(unless the Company can obtain an agreement from NPCC and NERC for alonger implementation timeline)• The new NERC definition in combination with the new NERC stricter planningcriteria would impose such criteria on a larger set of facilities. This is expected toincrease capital costs in the range of $50 million over 10 years; however, morespecific cost estimates are difficult at this point until both the new BES definitionand new NERC Transmission Planning standards are approved by FERC.• The new NERC definition in combination with the NPCC/NERC RegionalStandard, PRC-002-NPCC-01— Disturbance Monitoring, would requiredisturbance monitoring equipment to be installed to cover all of the newly definedBES elements. Any regionally approved standards that are submitted to NERCand FERC for approval are subject to the NERC definition of Bulk ElectricSystem and not the Region’s definition. This change has an impact ofapproximately $10 Million over the next 4 years; again, more specific costestimates are difficult at this point until the new BES definition is approved byFERC. In addition the Company will be working with NPCC to identify if there areany opportunities for modifying the Regionally-approved standard to bespecifically applicable to NPCC’s defined Bulk equipment. However, this changewould need to be submitted to NERC and FERC for their subsequent approval inorder for that change to be effective.• New Cyber Security standards version 4 (and Version 5) in combination with theBES definition will impact facilities that are expected to be in conformance withthe CIP standards. The new CIP standards now require facilities that are criticalin deriving Interconnection Reliability Operating Limits (IROLs), that have SpecialProtection Schemes that could impact an IROL, and that have a high number oflines connected to the substation(version 5 only) to be included. These changesin conjunction with the new BES definition is expected to add 23 additionalfacilities to the list of those that must meet CIP. The impact of this change isestimated in the range of $4 to 6Million over the next two years; however, morespecific cost estimates are difficult at this point until both the new Cyberstandard(s) and new BES definition are approved by FERC.II-826
Exhibit ___ (EIOP-19)Page 26 of 684Drivers:The primary driver for the redefinition of the BES proposed by NERC was FERC OrderNo. 743 issued in November of 2010. This order expressed a desire to improve clarity,reduce ambiguity, and establish consistency in the definition of the BES and in itsapplication across regions of the country. The use of a 100kV threshold in the newdefinition is intended make the line of demarcation between the BES and non-BESsystem “brighter” and easier to manage, and is expected to improve the reliability of theBES.Customer Benefits:The redefinition of BES using the lower voltage of 100kV will enlarge the portion of thetotal system to which BES planning criteria are applied. This broader application of suchcriteria is expected to improve the reliability and security of that portion of the system towhich it is extended. Because extension of the BES will bring its demarcation closer tocustomers, the reliability of customer service will improve to the degree that suchreliability is affected by the reliability of the BES portion of the system. Because theextension of the BES will require some additional investments, rate base and customerelectricity bills will also be impacted accordingly.Remote Terminal Unit Replacement StrategyThe ongoing Remote Terminal Unit (“RTU”) Strategy (C03772) involves replacingobsolete monitoring and control equipment with current and fully functional equipment. 5There are currently approximately 550 operating RTUs under the Company’s control, ofwhich 158 transmission and distribution units are being replaced under this program. 6NERC Recommendation 28, released in response to the August 2003 blackout, requiresthe use of, among other things, more modern, time-synchronized data recorders. Manyin-service RTUs do not satisfy this requirement; and obsolete RTUs will not work withthe modern Energy Management Systems (“EMS”) the Company expects to implement.To date, 104 of the 158 RTU replacements have been completed. Another 38 havecompleted engineering and are awaiting installation; and 25 still need to be scoped.Drivers:The RTUs are being replaced under this program for the following reasons:• The target RTUs do not meet the criteria outlined in NERC Recommendation 28, 7which places the Company at risk for being unable to provide synchronizedsystem data during a system emergency.5 The Remote Terminal Unit Strategy (SG 002) was included as Exhibit 20 in Volume 5 of 9 of theSeptember 17, 2007 Transmission and Distribution Capital Investment Plan, Case 06-M-0878.6 Some of the proposed RTU replacements are in generator owned facilities, not just NationalGrid substations.7 North American Electric Reliability Council (NERC) “Final Report on the August 14, 2003Blackout in the United States and Canada: Causes and Recommendations,” April 5, 2004 Page-162II-927
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January 2012 Capital Investment - National Grid

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