SECTION 2-TRANSMISSION PLAN SUMMARY Nevada Power Is The

SECTION 2-TRANSMISSION PLAN

SUMMARY Nevada Power is the electric utility for most of Southern Nevada. Its service area is approximately 4,500 square miles. Service is primarily to Las Vegas, Henderson, and several smaller towns in Clark County. Nevada Power is a wholly-owned subsidiary of Sierra Pacific Resources. Nevada Power operates 1,665 miles of Federal Energy Regulatory Commission ("FERC") jurisdictional transmission lines ranging from 500 kV to 69 kV. Transmission services are offered under the Sierra Pacific Resources Operating Companies' Open Access Transmission Tariff (OATT).

Nevada Power's existing Rd-, transmission system is composed of am,-=- three sections as shown in Figure TP-1. The first part is the uncongested grid, where the vast majority of Nevada Powcr's customers reside. Geographically, the uncongested grid is located within thc Las Vegas Valley. Generally, the ability to deliver resources is not limited by the transmission facilities within this area. The second and third parts of the transmission system deal with congested portions of the transmission grid. These are shown on Figure TP-1 as heavy dashed lines.

The second part is the Southern cut-plane, which allows s:"b, Nevada Power to bring in power % from market hubs - namely Mead, McCullough, and Eldorado Substations - located south of Las A Vegas in the Eldorado Valley. The Neda Power-

Southern cut-plane consists of . fourteen 230 kV bulk transmission lines electrically situated in parallel with each other. These lines are connected to Mead, McCullough, Eldorado, and Hoover. They connect to several trading hubs south of Nevada Power's transmission system and proportionally bring in import or deliver out any export that is scheduled across this cut-plane. Annual studies are done to verify the capability of this cut-plane and to identify the southern cut plane transmission limitation. The third part is the Northern cut-plane, comprised of the Red Butte-Harry Allen 345 kV interconnection with PacifiCorp in Utah and the Crystal interconnection with the Navajo - McCullough 500 kV line. The lines south of Harry Allen 230 kV currently limit Nevada Power's ability to bring in generation resources and purchased power from north of Las Vegas, including resources from Reid Gardner, Crystal, and the Nevada- Utah border, as well as generation interconnected to Harry Allen 230 kV. With the addition of the Harry Allen - Mead ("HAM") 500 kV line in 2007, this constraint will be reduced so as not to be the limiting factor of the northern cut-plane. Annual studies are conducted to verify the capability of this cut-plane and to provide the northern cut-plane transmission limitation.

SPECIFIC REQUESTS FOR COMMISSION APPROVAL

In this 2006 Resource Plan, Nevada Power seeks Commission approval of the following (unless otherwise noted, all estimated costs are in year spent dollars).

1. To immediately begin securing and purchasing easements, rights of way (ROW), as well. as authorize necessary permitting and construction for the following Ely Energy Center ("EEC5)-related projects:

- Ely Energy Center 500 kV Switching Station - Ely Energy Center-Robinson Summit 500 kV No. 1 Transmission Line - Robinson Summit 5001345 kV Switching Station - Falcon-Gonder 345 kV line fold into Robinson Summit 5001345 kV Substation - Harry Allen-Robinson Summit 500 kV No. 1 Transmission Line (EN-ti) - Harry Allen 500 kV Switching Station improvements for EEC (EN-ti) - Funding to initiate studies, permitting, and land acquisition for Nevada Power's Robinson Summit to Hany Allen 500 kV No. 2 Transmission Line.

Total Estimated Cost: $570.6 million (Allocation - 80 percent to Nevada Power and 20 percent to Sierra). The timing of the expenditures may change due to Robinson Summit Substation being put into service in 2008 rather than 2010.

2. To immediately begin securing and purchasing easements, ROW, as well as authorize necessary permitting and construction for the following White Pine Energy Associates ("WPEA") and Great Basin Transmission Company ("GBT"), related projects:

- Robinson Summit and Hany Allen Substation work necessary for GBT (LS Power) Transmission Interconnection of its Robinson Summit - Harry Allen 500 kV line - Harry Allen-Mead 500 kV line No. 2 and associated Substation work for the WPEA (LS Power) Point to Point Transmission Service Request - if executed or filed unexecuted 3. To immediately begin sccuring and purchasing easements, ROW, as well as authorize necessary permitting and construction for the following:

Sunrise fold of Harry Allen to Mead 500 kV line and associated 230 kV, 138 kV and 69 kV modifications between Sunrise and Winterwood Substations Sunrise to Clark 230 kV transmission line Sunrise to Equestrian 230 kV transmission lines (two lines) Equestrian North 5001230 kV North Suhstation Equestrian North to Equcstrian 230 kV transmission lines (two lines) Equestrian to Faulkner 230 kV line Equestrian North fold of Harry Allen to Mead 500 kV line Northwest 500/230 kV substation transformer bank No. 2 Thunderbird 2301138112 kV substation Thunderbird to Iron Mountain 230 kV line Thunderbird to Northwest Substation 230 kV line Five new 230112 kV substations along the Harry Allen to Northwest 230 kV line corridor Mobile 230 x 138/12 kV 25 MVA transformer for new 230/12 kV Substations Brooks 2301138 kV substation Southeast 1, Southeast 2, and West Henderson 230112 kV Substations Sinatra Project Iron Mountain Substation 2301138 kV transformer bank No. 2 Northwest Substation 2301138 kV transformer hank No. 2 Arden 230i138 kV transfomler bank No. 2 Valley Electric Interconnection at Northwest 230 kV substation Clark 2301138 kV bank No. 6 Transformer Change out Solargenix 230 kV Interconnection

Total Estimated Cost: $848.9 million

4. To immediately begin securing and purchasing easements, ROW, as well as authorize necessary permitting and construction for the Clark Peaker Units project:

Total Estimated Cost: $384.3 million

5. Westconnect membership costs for Nevada Power Company. The estimated WcstConnect membership cost is $52,000 in 2006, $54,000 in 2007, $55,000 in 2008, and $57,000 in 2009.

6. Spending up to $350,000 over a 12 month period for Nevada Powcr's participation in regional transmission expansion feasibility analysis.

7. Funding to initiate studies, permitting, and land acquisition for Sunrise to Highland, Highland to Sinatra, and Highland to Brooks 230 kV transmission lines (20071, Total Estimated Cost: $1,000,000 in 2007.

TRANSMISSION PATH RATINGS

Nevada Power owns three transmission paths, each consisting of one or more transmission lines, that are rated by the Western Electricity Coordinating Council ("WECC") and is a partial owner of one additional WECC-rated transmission path. Nevada Power and Sierra are in the process of rating the proposed Eastern Nevada Transmission Intertie ("EN-ti"). Descriptions of all the Nevada Power rated transmission paths are as Follows:

Crvstal500 1 230 kV Path (WECC Path # 77) This path allows energy to be moved from the Navajo - McCullough 500 kV transmission line into the northeast comer of the Nevada Power system at Crystal. This path is rated for 950 MW of inbound flow measured at Crystal.

Harry Allen - Red Butte 345 kV Path (WECC Path # 35) This path allows energy to be moved to and from Utah (PacifiCorp - East) to the northeast comer of the Nevada Power system at Hany Allen. This path is rated for 300 MW of bi-directional flow; however, actual schedules from Utah are significantly limited due to load growth in Southern Utah not by the Path rating.

East of River (WECC Path #49) Nevada Power is a 25 percent owner in the Navajo - McCullough 500 kV transmission system. This line is one of several that comprise the WECC East of the River ("EOR) path #49. Nevada Power's contractual rights on the Navajo- McCullough 500 kV line are 371 MW in either direction along the entire length of this path. These rights can be used to deliver power to Nevada Power via Crystal or McCullough substations. A planned upgrade of the EOR path is expected to increase the Nevada Power rating - via a pro-rata share method of allocation of the total increase among the various EOR path owners. If Nevada Power participates in the funding of this upgrade project, it would be allocated approximately 75 MW of additional transmission capacity across this path. Nevada Power's rights would then be increased to 446 MW on the Navajo - McCullough 500 kV system.

Centennial Proiect (WECC Path # 111-2) The Centennial Project has been granted a Phase I11 rating for delivery of 3,000 MW injected at the Hany Allen 500 kV substation. This rating has been evaluated for both the delivery of the full 3,000 MW rating to Mead substation, which is owned by the Westem Area Power Administration ("Western"), and for partial delivery of the rated power into the Nevada Power system with the balance going to Mead substation. Upon completion of the Centennial Project this Phase 111 rating will become a WECC Accepted Rating. Eastem Nevada Transmission Intertie ("EN-ti") The EN-ti is thc proposed Robinson Summit to Hany Allen 500 kV transmission line. Nevada Power has initiated the WECC Regional Review Process, the first stage of the WECC three-phase path rating process. The initial estimate for this rating is 2,000 MW north to south and 1,000 MW south to north.

Great Basin Transmission, LLC (GBT) has also initiated the WECC path rating process for a second 500 kV transmission line that parallels the EN-ti 500 kV transmission line, between Robinson Summit and Hany Allen 500 kV substations.

Both projects are being proposed to interconnect new coal generation projects in Northcrn Nevada, allow expanded access to renewable resources, and allow the combined utilization of Nevada Power and Sierra Pacific Power resources.

Itizport Capability

Import capability is the energy that can bc transferred into a control area. Thc control area boundaly is specifically dcfined for each control area by the WECC. Import capability is determined in accordancc with WECC / North Amcrican Reliability Council ("NERC") reliability critcria. Accordingly, the system must be capable of mccting all performance critcria for steady state and single continge~~cyoutage conditions at the stated import level. Nevada Power's import capability is dependent on generation dispatch patterns and the maximum import is not currently attainable without generation at Clark Gcnerating Station.

The first table below shows the existing and post HAM system import limit using a generation pattern that is non-economic but allows maximum system import capability. The second table below shows the existing and post HAM maximum import capacity using Ncvada Power's economic dispatch gcncration pattern. Thc import capability is higher when a non-economic dispatch pattern is employcd. By running Clark Generation (not the most economic units), the import limiting Mead to Basic 230 kV line flows are rcduced allowing higher import levels.

Maximum System Import Capability

I Existing 1 Plus I System-(2006) I HAM (2007) 3,713 MW 1 3,988 MW

Maximum Import with Economic Dispatch Pattern

I Existing I Plus 1 System-(2006) I HAM (2007) 1,550 MW 1 1,800 MW Export Capability

Maximum Export with optimal generation configuration

PREVIOUSLY-APPROVED TRANSMISSION PROJECTS

Centennial Project Status Report

Work remains to be completed on two elements of the Centennial Project; the Harry Allen - Mead 500 kV transmission line, and Regional Fault Duty Mitigation at Mead 230 kV substation.

HARRY ALLEN - MEAD 500 kV

The Harry Allen - Mead 500 kV transmission line construction contract was awarded to Infra-Source Transmission Services on July 25, 2005. As of June 6, 2006, 627 out of 847 total (74%) below ground structure foundations were completed, 94 out of 221 total (43%) structures were assembled on the ground, 88 out of 221 total (40%) structures were erected, and 0 out of 51 total circuit miles of conductor have been installed. The transmission line construction is estimated to be completed in January of 2007.

Western has awarded a construction contract to Addison Construction Company for the Mead Substation 500 kV facility additions, including the installation of the new 5001230 kV transformer. Western will be modifying and connecting to existing sections of 500 kV substation bus which will require 500 kV bus outages. The number of outages will be limited by the Mead-Phoenix owners to a total of three and can only occur during winter months (October - March). The installation of the Mead 5001230 kV transformer is estimated to be completed on March of 2007.

PECOS-SHADOW 138 kV

The Pecos-Shadow 138 kV transmission line re-conductor began in October 2005 and was completed and put into service in March 2006. Nevada Power has unresolved compensation issues regarding the acquisition of easements on 257 parcels and is in the process of resolving these issues through negotiation or litigation, where necessary, and expects closure by early 2008. REGIONAL FAULT DUTY

As of April 26, 2006, 18 out of 42 230 kV circuit breakers at Mead substation have been replaced by Western's contractor. The remaining breakers will he replaced by June of 2007 to coincide with the encrgization of the Harry Allen to Mead 500 kV line and the Mead 5001230 kV transformer. Figure TP-2 is an overview of original and current or completed cost estimates for the different portions of the Centennial Project. Nevada Power is not requesting any action on the Centennial Project. This information is being provided as an update only.

Figure TP-2 Centennial Project Status

The Cea~tennialP

Original Current PROJECT PROJECT INCREASE DESCRIPTION TOTAL TOTAL (DECREASE) LV COGEN $334,548 $461,357 $126,809 HARRY ALLEN 1 CRYSTAL $61,657,920 $64,724,624 $3,066.904 HARRY ALLEN I NW $60,001,100 $60,540,778 $539,618 HARRY ALLEN I MEAD $124,872,092 $1 18,364,548 ($6,507,544) ARDEN 1 BIGHORN $34,034,790 $34,007,712 ($27,078) BELTWAY $6,673,604 $6,027,642 ($645,962) PECOS I ARTESIAN $6,650,584 $5,360,593 ($1,269,991) LVCOGEN EXT: PECOSISHADOW $1,822,970 $9,716.296 $7,893,326 LVCOGEN EXT: PECOSILEAVITT $3,394,382 $2,775,887 ($618,495) ARDEN TO DECATUR $2,450,301 $0 ($2,450,301) NORTHWEST TERTIARY REACTOR $689.854 $502,663 ($187,191) REGIONAL FAULT DUTY $1,524,501 $6,676,489 $5,151,986 TOTAL (1) $304,106,646 $309,176,729 $5,072.083

(1) Contingency included in total $956,014 $4,999.741 $4,043,727 1

NORTH LAS VEGAS VALLEYAREA ROUTING AND SITING (VARS) PROJECT

The Third Amendment to the Nevada Power 2003 Integrated Rcsource Plan (IRP) stated Nevada Power's desire to build a new Northeast substation (renamed Thunderbird substation) as wcll as a 16 mile 230 kV line on quad circuit structures (2x230 kV and 2x138 kV) between Thunderbird and Iron Mountain substations. The Amendment also stated the Company's desire to convert a portion of the existing Hany Allen to Northwest 230 kV line to a 138 kV line in order to serve three distribution substations at 138 kV (Grand Tetou 138112 kV, ElkhornlCommerce 138112 kV and ElkhornlPecos 138112 kV). Nevada Power informed the Commission, in the Tenth Amendment to the Nevada Power 2003 IRP of its intent to change the plan of scwicc for the VARS projects as follows: - Construct a new Thunderbird 2301138/12 kV Substation (formerly known as Northeast Substation) - Install one new 2301138 kV, 336 MVA transformer at Thunderbird Substation - Install one new quad circuit 2x230 kV and 2x138 kV transmission line from Thunderbird Substation to Northwest Substation. The 138 kV circuits will fold into Iron Mountain substation at a future date - Install one new quad circuit 2x230 kV from Iron Mountain to Thunderbird Substation, with two spare 138 kV line positions reserved for future use - Construct five new 230112 kV distribution substations along the existing Hany Allen to Northwest 230 kV line route - Construct a new Brooks 2301138112 kV substation and one new quad structure (2x230 kV and 2x138 kV) transmission line from Pecos Substation to Brooks Substation - Purchase a 2301138112.5 kV, 25 MVA mobile substation - Install one new 2301138 kV, 336 MVA transformer at Iron Mountain Substation - Install one new 2301138 kV, 336 MVA transformer at Northwest substation

Nevada Power seeks approval to proceed with the construction of these facilities as part of this 2006 Resource Plan. The specific project scope and details are included in the "Bulk Transmission Projects for Native Load Service."

EVAMP AND VARS LANDS, ROW, AND PERMITTING

In the Tenth Amendment to Nevada Power's 2003 Resource Plan (Docket No. 06- 01027, Order issued May 4, 2006), Nevada Power requested permission to purchase certain strategic land parcels and rights of way to minimize future custon~ercost due to accelerating land prices. The Commission approved Nevada Power's request to proceed with the expenditures needed to secure these easements and rights of way - prior to Commission approval of the facilities. Specific approvals for the related facilities are sought in this 2006 Resource Plan. The approved acquisition of easements and rights of way is underway at this time.

There are several issues driving the need to secure these easements. First and foremost is the explosive growth in Las Vegas. Nevada Power's load forecast indicates that approximately 2,000 MW of new load growth will occur in Las Vegas within the next ten years. This growth puts pressure on the long-term planning and siting feasibility of new transmission lines and substations.

The same loads that drive the need (housing and new business) also populate the areas in and around the easements needed to serve them. Additionally, load growth has until recently been "horizontal" meaning growing away from downtown areas and spreading outward - filling the Las Vegas Valley. However, a new trend in Las Vegas property development is towards redevelopment of existing areas with high-rise, high density, and multi-use facilities, such as condominiums, casinos, and retail, which require extensive new transmission infrastsucture to be added into established populatio~~with a lack of large transmission eascments available.

Land prices have also increascd substantially in the past few years and developers are rapidly acquiring and developing properties. Not only do land prices continue to increase, but the space needed to develop hture electrical transmission and distribution facilities is becoming more difficult to access.

A budget of up to $37,003,000 was approved for the acquisition of land and land rights nccessaty for the future construction of local transmission facilities, with the Commission's Ordcr in the Tenth Amendment to the Action Plan of the 2003 Resource Plan. Land and land rights acquisition was approved for the following projccts:

o Northwest 5001230 kV transformer bank No. 2 ($477,000) o Harry Allell to Mead fold into Sunrise 500 kV ($8,879,000) o Two Sunrise to Clark 230 kV lines ($1,640,000) o Two Sunrise to Equestrian 230 kV lines ($2,257,000) o Thundcrbird Substation and lines ($23,750,000)

PROPOSED NEW TRANSMISSION AND GENERATION INTERCONNECTION FACILITIES

General Description of Eastern Nevada Transmission Zntertie ("EN-ti" Project

The EN-ti Project has been created to provide transmission scrvice to Nevada Power, Sierra, and non-affiliated transmission customers. Nevada Power's request is the result of the submittal of new Network Resources designations for 1,550 MW of capacity from Robinson Summit to Nevada Power's Las Vcgas loads - this capacity may include them~al,geothermal or wind resources. EN-ti has been designcd to provide the requested Network Resource capacity as well as inter-utility economic transfers, generation reserve sharing, and additional access for renewable resources. The EN-ti Project is designed with the ability to be scaled upwards or downwards in scope, depending on the transmission and interconnection services ultimately contracted and facilities approved by the Commission. Nevada Power is planning to fold Sierra's existing Falcon - Gonder 345 kV line into a new Robinson Summit 5001345 kV Substation. Two phase-shifting transformers will be used to control power flow between the 345 kV and 500 kV lines. The EEC facility will ultin~atelyconnect into the Robinson Summit 500 kV bus via two 500 kV transmission lines. A single 500 kV, series compensated, transmission circuit between Robinson Summit Substation and Harry Allen 500 kV Substation is bcing designed by Nevada Power. A new 500 kV termination for this line is being planned for thc existing Hany Allen 500 kV substation.

Design of the Robinson Summit 500 kV substation also accommodates the interconnection of the proposed LS Power's White Pine Energy Associates' (WPEA) generators. The Robinson Summit and Hany Allen 500 kV substations are being designed to interconnect the proposed GBT series compensated 500 kV transmission line. GBT has also proposed a 500 kV transmission line, parallel to EN-ti. Both lines are being regionally evaluated through the WECC's Path Rating Process.

System performance for a single 500 kV line between Robinson Summit and Harry Allen is also being evaluated in case either one of these transmission facilities is not completed.

The proposed Robinson Summit 5001345 kV switching station will be designed for future expansion and will initially be built to meet only the contracted and Commission approved scope.

Summary of Transmission Facilities for the Ely Energy Center

Nevada Power requests the Commission approve the following transmission facilities associated with the EEC: - EEC 500 kV Switching Station - EEC-Robinson Summit 500 kV Transmission Lines No. 1 & 2 - Robinson Summit 5001345 kV Switching Station - Harry Allen-Robinson Summit 500 kV Transmission Line No. 1 (EN-ti) - Harry Allen 500 kV Switching Station - Falcon-Gonder 345 kV line fold into Robinson Summit 500/345 kV Switching Station - Funding to initiate studies, permitting, and land acquisition for Nevada Power's Robinson Summit to Hany Allen 500 kV line No. 2.

Ely Energy Center Interconnection

Nevada Power has submitted requests in accordance with the Sierra Pacific Resources' Operating Companies OATT requirements - for the creation of all necessary transmission facilities to interconnect Phase I of the proposed EEC into both the Sierra and Nevada Power transmission systems and deliver up to 1,550 MW of new resources to Nevada Power loads. The Transmission Planning department has performed analyses to determine the requirements for this interconnection in conjunction with its designation of this facility as a Network Resource. The associated switchyard one-line shown in Figure TP-3 is for the preliminary interconnection of one of the two generators. Figure TP-4 is the associated one line diagram for interconnection of the second generator as well as the second line to the Robinson Summit 500 kV substation. The switchyard and line cost estimates are shown in Figures TP-5 and TP-6, respectively.

The EEC and associated Robinson Summit switching facility designs accommodate the phasing of construction of EEC. Phase 1A will commence in 2010 and include one 750 MW pulverized coal (PC) generating unit at EEC with one line termination to the Robinson Summit 500 kV yard. Phase 1B includes the completion of PC generating unit No. 2 at EEC (750 MW) with an associatcd second 500 kV transmission line betwcen EEC and Robinson. Phase 2 anticipatcs Nevada Power installing two additional 500 MW generating units at EEC, possibly utilizing coal gasification technology.

Figure TP-3 Ely Energy Center Switchyard Phase 1A

"sve-oscc..-q,asss I I 8 I n 8 n 8 --.a lto* 0 8

1 I e*, I B Bo* 4 Generation Unlt 8 0 No 1 (750-MW) m-* 0 n be-8 I n n ~~-a~~-~--~=*-s-

Robinson 500-kV L~neNo 1 Phase lA ;"" -0 Future ------Figure TP-4 Ely Energy Center Switchyard Phase 1B

Robinson 500-kV Phase lA - Line No. 1 Generation Unit Phase 1B -=--- No. 2 (750-MW)

Figure TP-5 EEC Phase 1A & 1B 500 kV Switchyard estimated Costs

In- ELY ENERGY CENTER PHASE 1A & 1B SWITCHYARD service Date ($ Millions) 2010 New 500 kV Substation ring bus configuration $30.9 2010 Lands $0.6 2010 Comnlunications $0.5 Total ELY ENERGY CENTER PHASE 1A & 1B Switchyard $32.0

Figure TP-6 EEC Phase 1A & 1B Robinson Summit Transmission line estimated costs

'Ianned In- ELY ENERGY CENTER PHASE 1A & 18 TRANSMISSION LINE service Date $ Millions) 2010 EEC-Robinson Sum~iiitLine I $42.4 2013 EEC-Robinson Summit Line 2 $45.9 2010 Lands %I .2 2010 Comniunications $3.0 2010 Comniunications-Microwave $1.2 Total ELY ENERGY CENTER PHASE 1A & 1B Transmission Line $93.7

Robinson Summit 500/345 k V Substation

Nevada Power has designed the Robinson Summit 5001345 kV switching station (Figure TP-7) to interconnect the proposed EEC, the proposed WPEA Plant, renewable energy resources, two 500 kV lines, and future generation or transmission interconnections.

Sierra's existing Falcon-Gonder 345 kV transmission line will be folded into the new Robinson-Summit 345 kV Switching Station. Each end of the Falcon-Gonder 345 kV transmission line fold-in will have a series connected 345 kV phase shifting transformer to facilitate the control of the power flow into and out of the Robinson Summit 345 kV Switching Station. Additionally, each end of the Falcon-Robinson 345 kV line will have series compensation capacitors. The costs of these facilities are detailed in Figures TP-8 and TP-9.

Figure TP-7 Robinson Summit 5001345 kV Switching Station Phase 1A

Robinson Summit 345 kV Controlled Bus ROblnBon summi, - Falcon 345 k"Will be compensated upfo 35

I Phsre Shiner

Robinson Surnmn 500 kV Transformer #I

Robinson Summit 500 kV

Robinson Summit-Harry Aiieo circuits 500 kV Ih~ntreaCtomWm neutral reactors 455 at each end Future studies la #denlibulllmale sizd Iwnchlng

Robnson summit - H~~~ AII~"500 kv W,~I Existing - be compensated up to 35 % senes a, each end %111 Proposed-- :,-"* Future ------

to Harry Allen 500 kV Figure TP-8 Robinson Summit 500/345 kV Switching Station Cost Estimates

'IannedIn- Robinson Summit 5001345 kV Switching Station ($ Millions) service Date 2010 Transmission Substation 500/345 kV $103.8 2010 Lands $0.6 2010 Communications $0.5 Total $104.9

Figure TP-9 Falcon - Gonder 345 kV Line Fold Into Robinson Summit - Estimated Costs

Planning ln- -service Date Falcon-Gonder 345 kV line fold into Robinson Summit Switchins Station (5 Millions) 2010 Falcon-Gonder line fold-in at Falcon end of line $0.0 2010 Falcon-Gonder line fold-in at Gonder end of line 50.0 201 0 Transmission fold-in at Robinson Summit $2.2 2010 Falcon-Robinson Summit Series Compensation $15.0 2010 Communications $1.1 Total $18.3

Eastern Nevada Transmission Intertie ("EN-ti")(Robinson Summit - Harry AIlen 500 kV In order to meet Nevada Power's interconnection and Network Resource transmission service requests, the Nevada Power Transmission Planning Department has designed a new 500 kV intertie that connects Sierra's existing Falcon - Gonder 345 kV line to the proposed Robinson Summit 500/345 kV Switching Station with a 500 kV transmission line interfacing with Nevada Power's existing Hany Allen 500 kV substation as shown in Figure TP-10. This intertie is designed to be a triple-bundled 1590 ACSR (Aluminum Conductor, Steel Reinforced (cable)), series compensated transmission line. It has a 345 kV phase shifted interconnection to the Sierra system in order to regulate pre and post outage flow into and out of the Sierra and PacifiCorp power systems. Nevada Power will endeavor to design this 500 kV line to accommodate single- pole switching, thus minimizing outages requiring power plant generating unit tripping. The cost estimate of this line is shown in Figure TP-I 1.

Additionally, to accommodate delivery of potential IGCC plants at EEC in the future, Nevada Power is requesting authority to permit Nevada Power's Robinson Summit to Harry Allen 500 kV No. 2 line. The No. 2 line's estimated permitting costs are included in the total EEC cost estimate. Figure TP-I0 Robinson Summit to Harry Allen 500 kV Transmission Line Interconnection

Robinson Summit 5001345 kVTransformer No. 1

Robinson Summit 500 kV (Expandable-Additional long

Robinson Summit -Harry Alien 500 kV Line will be compensaled up to 35 % series at each end.

Existing - Allen circuils 500 kV shun1 reactors with Proposed---- Future ------Fulure studies to identity ullimale size1

Figure TP-11 Robinson Summit to Harry Allen 500 kV Transmission Line Estimated Costs

Planncd In- Robinson Summit to Harry Allen 500 kV Transmission Line #I (5 Millions) service Date Robinson Summit to Harry Allen 500 kV Transmission Line #1 with 35% 2010 $257.7 series conipensation at each end of the line 2010 Land and Environmental $18.4 2010 Communications - Fiber Optic $10.1 2010 Comn~unications-Microwave $8.3 Total $294.5 New Harry Allen 500 kV Line Terminal

In order to accommodate the interconnection of the proposed Robinson - Hany Allen 500 kV line, Nevada Power has designed the expansion of the existing Hany Allen 500 kV switching station shown in Figure TP-12. The cost estimate of this project is shown in Figure TP- 13.

Figure TP-12 Harry Allen 500 kV Switching Station Interconnection

Allen 500 kV will be compensated up to 35 % Serles at each end.

Existing - Robinson Summit-Harry a Proposed ---. 6:: Future ------idenlib ultimate size1

Figure TP-13 Harry Allen 500 kV Switching Station Costs

Planned In- New Harry Allen 500 kV Line Terminal ($ Millions) service Date Robinson Sununit to Harry Allen 500 kV Transmissio~lLine #I tenninal 2010 $26.0 with 35% series compensation at each of the line 2010 Lands $1.0 2010 Communications-Microwave $0.2 Total $27.2

WHITE PINE ENERGY ASSOCIATES TRANSMISSION INTERCONNECTION AND TRANSMISSION SERVICE REQUESTS

WPEA, LLC and its affiliate GBT, LLC have made four transmission-related requests from Nevada Power, listed as follows.

The first request is to interconnect a transmission line owned by GBT to Sierra's system at Robinson Summit substation and to Nevada Power's system at Hany Allen 500 kV substation. GBT's transmission line interconnection request is not a request under thc OATT as there is not a FERC tariff process for transmission line interconnections. It is a Section 21 01212 Federal Power Act request and is not posted on the OASIS.

The second request is for Nevada Power to provide 1,200 MW of Firm Point-to- Point transmission service from the Harry Allen 500 kV substation to Western's Mead 230 kV substation. The Point-to-Point transmission service request would require the construction of additional transmission facilities to increase the transfer capability from Hany Allen to Mead 500 kV. Given the recent issues related to the transformer addition at Mcad for the Centennial Project, therc will likely be significant fault duty increases rcquiring further study. Currently, a Short Circuit Work Group is conducting studies to address this issue, which Nevada Powcr is a participant.

The third and fourth requcsts are for generation interconnection under Sierra's OATT made by White Pine Energy Associates, LLC ("WPEA"), a subsidiary of LS Power. These generation interconnection requests require the construction of all transmission facilities nccessary to interconnect the proposed White Pine Energy Center with Sierra's transmission system at the proposed Robinson Summit substation. WPEA's interconnection applications state its intent to deliver output into Nevada Powcr's system. The Transmission Planning dcpartment has performcd analyses to determine the requircmcnts for this interconnection in conjunction with GBT's request for interconnection of a Robinson Summit - Harry Allen 500 kV transn~issionline. This type of request is a network resource designation type service for merchant generation.

A one-line diagram of the proposed White Pine Energy Center interconnection with the Robinson summit switchyard is shown in Figure TP-14. A cost estimate of this interconncction work is shown in Figure TP-15. Thc estimates in Figure TP-15 for GBT work are in addition to all of the aforcmentioned cost estimates. The White Pinc Energy Center is scheduled to be built prior to completion of the EEC and EN-ti, and therefore the Robinson Summit 5001345 kV substation will be required to be in-scrvice by 2008. Current FERC interconnection rulings require Sierra to refund the cost of the Robinson Summit interface built for the White Pine Energy Center generation interconnection if the costs are advanced by White Pine Energy Ccnter. The FERC considcrs these facilities to be Nctwork Upgrades to Sierra's transmission system.

Cost estimates and cash flows provided in this documcnt are based on Nevada Power's schedule of completing Robinson Summit Substation const~uctionwork in 2010 - nccessary for the construction of the EEC. If an Interconnection Agreement is signed with WPEA, thc estimates and cash flows provided in this 2006 Rcsource Plan will change due to the earlier in-service date for Robinson Summit Substation. The WPEA construction requirement would move Robinson Summit in-service date from 2010 to 2008. Figure TP-14 White Pine Energy Center 1 Great Basin Transmission Interconnections

Great Basin Transmission, LLC Robinson Summit - Harry Allen 500 kV Line

Robinson Summit 500 kV :. - EECMOYLme?-l- 9 . . ..'. .

I ~arwAllen 500 LU

Existing - a Proposed by GET - ,I--, , Installed Ey ...... Proposed by WPEA :-1 NPC for EEC Figure TP-15 White Pine Energy Center I Great Basin Transmission Estimated Interconnection Costs

'Ianned In- Great Basin Transmission. LLC I$ Millions) service Date 2010 Robinson Stillunit Substation Additions $113.0 Robinson Sununit - Harry Allen 500 kV transmission line (LS power will 2010 $298.2 build this) 2010 IIarry Allen Substation Additions $27.0 Total $438.2

Figure TP-16 White Pine Energy Associates Transmission Service ~e~udst

New HA 500 kV terminal

Mead 5001230-kV

Transformer No. 3

Second Harry Allen - Mead 500 kV Transmission Line. Designed similarly to HAM No. 2

Existing - Proposed-- iU,'-* Future ------Figure TP-17 White Pine Energy Associates Transmission Service Request Estimated Cost

'lanned In- Harry Allen to Mead 500 kV Transmission Line #Z ($Millions) service Date 2010 Hany Allen Substation Additions (Harry Allen Temiinal) $4.7 2010 Harry AllenIMead 500 kV line No. 2 $47.8 2010 Mead Substation Additions with 3td 5001230 kV Bank $36.9 Total S89.4

Figure TP-18 EN-ti Transmission and Interconnection Facilities Cash Flows

I I I I I I I I I ZOH 1~otalEly Energy Center hansmlarion $6.11 $2.61 $2.51 146.81 $67.91 $432.01 $7.91 $34.81 $570.6 Cash Flows may changefar the Robinson Summit 345/500 kV substation 1fLS signs an interconnection agreement requesting service in 2008.

EEC I EN-TI STUDY RESULTS

The integration of the WPEA generation facility, consisting of three 533 MW units, requires the installation of GBT's Robinson Summit-Harry Allen 500 kV line in addition to the required generation terminations at the Robinson Summit 500 kV substation for WPEA. The results of the load flow studies for the steady state, transient and post transient analysis have identified no adverse impact to the interconnected system. The installation of the second 500 kV circuit between Robinson Summit and Harry Allen will eliminate the need for the generation tripping scheme required if there is only one Robinson Summit - Harry Allen 500 kV line. The dual 500 kV circuits will allow both EEC and WPEA to share transmission capacity, on an emergency basis, when one of the two 500 kV circuits is removed from service due to a system disturbance. System analysis achieved a performance that either met or exceeded the WECCNERC reliability standards under the conditions studied. The studies for the different project included evaluating thc transmission options from Robinson Summit to Harry Allen for several generation configurations. Each generation project (EEC and WPEA) was evaluated separately as a stand-alone project to determine viable transmission options.

Several different system configurations were rcviewed to provide the required connections to both Sicrra and Nevada Power. The only existing Sierra transmission near the generation projects that has the capacity required is the 345 kV system. The existing Sierra 345 kV line from Falcon to Gonder was selected for the Sierra transmission interface. Robinson Summit was selccted as the evaluation sitc because the existing 345 kV line is on the site, space at Robinson Summit is available for a large 5001345 kV substation, and cxpected space restrictions at and near Gonder Substation. Different transformer and phase shifter sizes and configurations were reviewed at Robinson Summit and the recommended design of one 5001345 kV transformer and two phase shifters was selected to control the power flow from the generation projects to the requested load areas.

The EEC and WPEA can operate separately (up to 2,000 MW total) with a single 500 kV line from Robinson Summit to Harry Allen, but both projects required tripping of some or all of their ncw generation for an outagc of the single line configuration. The EEC project requircd two 500 kV lincs from the plant site to Robinson Summit to avoid a 1,500 MW contingency with the second generator on line. Power flow and fault duty studies did not show any problems. Transient stability studies showed the EEC project required lower system impedance between Falcon and Robinson Summit to maintain system stability for an outage of the Robinson Summit to Harry Allen 500 kV line. Lower impedance transformers and phase shifters were evaluated, but series compcnsation on the Falcon to Robinson Summit 345 kV line was selected as the best solution.

The EEC and WPEA generation projects werc evaluated together, generation tripping was not required because each'project includes a 500 kV line from Robinson Summit to Harry Allen. The two 500 kV line configuration provides a performance that can serve the first phase of EEC (1,500 MW) and WPEA. Additional studies and transmission facilities are expected to be required for the second phase of EEC (1,000 MW additional).

Figure TP-19 shows a single line diagram of the EEC and WPEA facilities. Figure TP-20A models only the EEC generation facility producing 1,500 MW of power delivered to the Harry Allen 500 kV substation. Figure TP-20B shows the intcgration of both EEC and WPEA generation and illustrates the delivery of approximately 3,100 MW (1,500 MW EEC and 1,600 MW WPEA) of power to thc Harry Allen 500 kV substation. Figure TP-19 EEC Interconnection to Robinson Summit 500 kV Substation Figure TP-20A EEC Interconnection to Robinson Summit 500 kV Substation

i - 0 0 "\>". . 0, d .B"jd;tSdL2duoosv 0 u 8" $0 i 9zLt .??;! .::aw~-o C,?IE*;z2$ !!- YGd.,AY. 5 ~IIOUDOL."> ; 6?Vnigd~~ = : e. -n % - - - - - s f ?

m * E Figure TP-20B EEC and WPEA Interconnection to Robinson Summit 500 kV Substation BULK TRANSMISSION PROJECTS FOR NATIVE LOAD SERVICE

The facilities described below are not related to the development of the EEC. The necessity of the following transmission facilities for native load is driven by the projected load growth in the Las Vegas Valley as well as the assumption that the new generation resources required to serve this load growth will be located at or delivered to the Hany Allen or Crystal 500 kV substations.

EAST VALLEY AREA MASTER PLAN FACILITIES PROPOSED

The East Valley Area Master Plan (EVAMP) was developed and prescnted to the Commission in Nevada Power's Third Amendment to the Action Plan of the 2003 Resource Plan (Docket No. 04-8022, Order issued December 28, 2004). The Third Amendment also asked for Commission approval for Nevada Power to retain the services of a consultant who would conduct a feasibility analysis of various substation and transmission line configurations and associated siting alternatives. Pursuant to the Commission's approval, Nevada Power issued a request for proposal for the study and ultimately selccted Power Engineers, Inc. as the consultant. This study was provided to the Commission in thc confidential technical appcndix of Nevada Power's Tenth Amendmcnt to the Action Plan of the 2003 Resource Plan (Docket No. 06-01027, Ordcr issued May 4, 2006), which requested approval to secure Rights of Way, permits and easements for EVAMP facilities. After Power Engineers provided its report, Nevada Power began conducting power flow studies to establish the order and timing of the master-planned facilities.

The studies presented in the Tenth Amendment included 3,000 MW of transmission reservations associated with the Centennial Project and 1,500 MW to 2,250 MW of additional generation resourccs dclivered to Harry Allen or Crystal 500 kV Substations (the Hany Allen huh), in 2010 and 2014, respectively. The Tenth Amcndmcnt also proposed timing of additions at the existing Northwest 500 kV Suhstation in 2010, at a new 500 kV substation at Sunrise in 2010, and at a new Equestrian North 500 kV substation in 2014.

Since the Tenth Amendment was filcd, Nevada Power's proposed generation plans have been refined. Specifically, EEC will delivcr 600 MW of new generation to the Hany Allen Substation in late 2011 and an additional 600 MW in 2013. The remaining 300 MW of energy will be delivered to thc Sierra system to use in serving its loads. This modification to the staging of new generation resources does not change the requircd transmission additions hut does change the timing of these system improvements.

Surnrnary of EVAMP Facilities

Nevada Power requests the Commission approve the following components of EVAMP: - The Northwest 5001230 kV No. 2 transformer and associated substation equipment to be placed in-service by 2010. - The Sunrise 5001230/138 kV substation, the "Sunrise" option, and associated infrastructure to be placed in-service by 2010. - The Equestrian North 5001230 kV Substation, the "Equestrian" option, and associated infrastructure to be placed in-service by 2014+.

Figure TP-21 EVAMP -Sunrise Option One-Line Diagram

~ ......

I" mine ,"to sunrise

2.230

I0 IqYl.i.i.n .a l . I*YIILII.I1 "0.11 1

PLX ~ Fa">",,., GS" . ".**""~" <"V . ""p.". LIX1 *."3YLSJ -.

..lr,ln. LOO "V -PraPoS-d 100 "V ."lr,lng 2,. "V -e.o~~s*d s30 "" _ex l,,, ng I,. *" - - - -P.ePa=-d 4mh" ..x.,mg @O *V -.- - -P.aPmred 09 "V Figure TP-22 EVAMP - Sunrise Option Estimated Costs

(1): While the cost of these upgrades are included in this 2006 Resource Plan, the sub transmission facilities (138 kV and below) were not studied. With further study, these facilities may likely he modified or delayed. Figure TP-23 EVAMP-Equestrian Option One Line Diagram ,

LEGEND r.,",l.m.V -.....In. ...d-. 1 Y,.,l,,D.V -m...... s.v U,.w,uw . ....- "d1Y.V .LI.'.w Figure TP-24: EVAMP-Equestrian Option Estimated Costs

EVAMP DISCUSSION

Northwest Second 5001230 kV autotransformer (2010): Power-flow studies indicate a need for additional bulk transmission facilities to meet projccted load growth in the Las Vegas Valley and the EEC planned delivcry of 600 MW to the Harry Allen Substation. A sccond 5001230 kV transformer at the existing Northwest 50012301138 kV switching substation is needed in 2010. Without the EEC delivery, this addition can be delayed by one year (Reference "201 l_base.sav" in the Technical Appendix). Bulk tra~~sinissionfacilities arc needed for the following reasons:

1. Transmission service for new load growth in the northwest portion of the Valley. 2. The 230 kV phase shifting transformers at Crystal Substation (a key component in the South of Harry Allen 230 kV cut plane) reach their steady state thermal overload capacity of 950 MW. 3. The Crystal-McCullough 500 kV line is fully subscribed. 4. The existing Northwest 5001230 kV transformer overloads during several single contingency outage conditions.

This study evaluated the timing and performance of three proposcd options for increased bulk load servicc into the Las Vcgas Valley:

1. A second 5001230 kV transformer at the existing Northwest Substation. Reference case "201 1-base" in the Technical Appendix 2. The "Suilrise Option:" A 500 kV fold of the Harry Allen-Mead line into a new Sunrise 5001230 kV substation (and associated 230 and 138 kV infrastructure). 3. The "Equestrian Option:" A 500 kV fold of the Harry Allen-Mead line into a new Equestrian North 5001230 kV substation (and associated 230 and 138 kV infrastructure).

Adding a second 5001230 kV transformcr at the existing Northwest Substation relieves all the reliability and service issues mentioned above and it does not require new 230 kV infrastructure. The Sunrise Option and the Equestrian Option do not relievc the Northwest 5001230 kV transformer overloading for loss of the Harry Allen-Mead 500 kV line. Therefore, a second 5001230 kV transformer at the existing Northwest Substation is required by 201 0.

Other conditions that will advance the timing of Northwest transformer are: I) new generation addition at Harry Allen (over and above the Centennial 3000 MW); 2) loss of transmission capacity or change in operating agreements on the Crystal - McCullough 500 kV line; and 3) desire to reduce reliance on the Crystal-McCullough 500 kV line or the South of Harry Allen 230 kV cut plane.

As an alternative to the Northwest transformer, a new 5001230 kV transformer addition at the existing Iron Mountain substation was considered. It was eliminated from further evaluation because a substantial investment in 230 kV infrastructure (over $13 million) would he required to deliver the power to the load centers at Beltway, Westside, and Decatur substations (these substations are currently served via 230 kV lines from Northwest Substation). Additionally, substantial 500 kV improvements would be required to install a new 500 kV yard at the existing Iron Mountain 2301138 kV substation.

Figure TP-25 Northwest 5001230 kV Transformer Estimated Costs

Planning In- EVAMP - NORTHWEST 5001230 kV BANK ADDITION ($Millions) service Date

6/1/2010 Northwest No. 2 5001230 kV Auto Transformer Addition $28.4 Total Northwest 5001230 kV Bank Addition $28.4

Sunrise 50012301138 kV Substation and Associated Infrastructure (2010)

Once the second transformer at Northwest is installed, the loss of the Lenzie to Northwest 500 kV line becomes the worst contingency outage in the Las Vegas Valley. Between the years 201 1-2014, loss of this line can result in overloads on the Southern 230 kV cut plane. In high import scenarios, the reliance on the Southern 230 kV cut plane will drive a new bulk power transfer addition as early as 2011. In high internal generation scenarios, this addition can be delayed to 2014. In any case, as soon as the second EEC block of energy is delivered to Harry Allen Substation (scheduled for 600 MW in 2013) a second bulk power transfer addition is required.

This study addressed the timing and performance of the remaining two proposed options for increased bulk load service into the Las Vegas Valley--the Sunrise Option and the Equestrian Option (discussed above). Both options resolve the reliability issue of the loss of the Lenzie to Northwest 500 kV line. However, the Sunrise Option delivers 900 MW of load service into the Las Vegas Valley, compared to 600 MW for the Equestrian Option. Additionally, the Sunrise Option is closer to the load center by over eight miles. Anticipated changes in load density in the downtownlstrip area resulting from new mega- casinos and high-rise condoloffice buildings will drive future transmission lines and sub- transmission facilities into and through the downtownistrip area. These transmission lines will likcly comc out of Clark, Wintenvood and/or Faulkncr substations, which are substantially closer to the Sunrise Substation than to Equestrian substation.

Therefore, the Sunrise Option, a 500 kV loop-in from the Harry Allen-Mead line to a new Sunrise 5001230 kV Substation (and associated 230 and 138 kV infrastructure), should be built between 2010 and 2014 but no later than when the second block of the EEC is interconnected. The high import scenario is included in the Technical Appeudix as case "201 I-import.savX and the high generation scenario is included in the Technical Appendix as case "20 14-gen.sav."

As an alternative to the Sunrisc option, a new 5001230 kV substation underneath or near the Harry Allen-Mcad line was examined. This would requirc four to seven (or more) miles of underground 230 kV lines from the new substation to Sunrise, Wintenvood or Clark Substations. A preliminary cost estimate of the 230 kV underground lines is $160 n~illion(not including the substation costs and the associated infrastructure costs). Should the rights of way or permittiug opportunity of the Sunrise 500 kV line be lost, this option may have to be revisited.

Equestrian 500/230 kV S~rbstution(2014)

Power flow studies indicate that additional bulk power transfer facilities will be needed when the second block of energy from EEC is placed into service and delivered to the Harry Allen substation. Studies indicate that under a "high import" scenario and after the Sunrise Option is constructed that the next major necessary transmission upgrade will be the Equestrian Option in 2014. Under a "maximum generation" scenario, the need to construct the Equestrian Option may be delayed a few years longer. Factors that will advance the timing of the Equestrian Option are: 1) new generation at Harry Allen (ovcr and above the Centennial 3,000 MW and EEC 1,200 MW); 2) loss of transmission capacity or change in operating agreements on the Crystal - McCullough 500 kV line; and 3) a desire to reduce reliance on the Crystal-McCullough 500 kV line or the South of Harry Allen 230 kV cut-plane.

If the Department of Energy (DOE) corridor study or internal efforts produce a viable 500 kV option into the Arden arca, the Equestrian Option and the "Arden Option" for increased load service to the Las Vegas Valley should be compared. In any case, efforts should be made to prescrve both options by securing right of way and permitting. In Nevada Power's Tenth Amendrncnt to the Action Plan of the 2003 Rcsourcc Plan (Docket No. 06-01027, Order issued May 4, 2006) the Commission authorized Nevada Power $500,000 to perform studies to develop a McCullough-Jean-Arden transmission corridor for strategic bulk supply.

Nevada Power is requesting Comn~issionapproval to proceed with construction of the Sunrise aud Equestrian Options as well as the Northwest Bauk Addition. A summary of the costs of these options is provided in Figure TP-26. A detailed cost breakdown for each option is provided in Figures TP-22, TP-24 and TP-25 above. Figure TP-26 EVAMP Project - Estimated Cost Summary

Planning In- EVAMP - Proiect Cost Summary (SMillions) service Date

6/1/2010 Total EVAMP - SUNRISE S187.2 61112014 Total EVAMP - Equestrian $181.1 61112010 Total Northwest 5001230 kV Bank Additio~i $28.4 Total EVAMP $396.7

Beyond Year 2014

With both the Sunrise and Equestrian Options constructed, the loss of the Harry Allen-Sunrise line will soon after become the single worst outage. This will place emphasis on the need for further development of 5001230 kV sources into the Las Vegas Valley which are independent of the Harry Allen-Sunrise-Equestrian-Mead 500 kV line. Toward this end, Nevada Power is participating in the Federal Corridor Study and filed comments with the US Department of Energy ("DOE") on November 27, 2005 that are meant to include requests to establish various corridors throughout Nevada of which one will include the Harry Allen to Jean and Jean to Arden Substation corridors. These corridors would benefit many parties and provide a new 500 kV route for new load service into the Las Vegas Valley from the Harry Allen substation in northeast Las Vegas to the Arden Substation located in the southwest Las Vegas Valley.

Nevada Power plans on investigating the feasibility of building a 500 kV loop around Las Vegas to support infrastructure needed to meet hture loads. Nevada Power also plans on investigating new 138 kV and 230 kV substations and lines in downtown Las Vegas. The new lines and substations construction andior conversions are projected to be needed due to the vertical downtown and Strip load growth.

In the Tenth Amendment, the Commission granted approval to proceed with studying a McCullough - Jean - South Arden 500 kV corridor for a future 500 kV transmission line between Hany Allen - Northwest - Jean - and McCullough. This corridor would be one section of the Hany Allen to Jean to Arden corridor discussed in the previous paragraph.

NEW VARS TRANSMISSION PROJECTS BEING PROPOSED

The diagram in Figure TP-27 shows the existing North Las Vegas area bulk transmission and sub-transmission system, existing distribution substations, and the new proposed VARS project plan of service. Figure TP-27: Northwest Las Vegas Area Routing and Siting Master Plan (VARS)

As discussed earlier, in ordcr to determine if the existing plan of converting the existing Hany Allen to Northwest 230 kV line to 138 kV was still feasible, Nevada Power integrated the revised load forecast into the updated power flow studies. From this analysis, Nevada Power determined that due to larger load growth than previously forecasted and 230 kV line construction timing, converting the existing 230 kV line to 138 kV is not a viable reliability option for serving these new substations. Nevada Power also determined that if future distribution substations near the Hany Allen to Northwest 230 kV transmission line were served at 230 kV, the proposed Thunderbird substation could be delayed until 201 1, and thc proposed Thunderbird to Iron Mountain 230 kV line installation could be delayed until 2012.

To meet VARS area load growth, Nevada Power proposes constructing five new distribution substations between 2008 and 2012 in the Northern Las Vegas area to be served at 230 kV instead of at 138 kV, which was proposed in Nevada Power's Third Amendment to the Action Plan of the 2003 Resource Plan (Docket No. 04-8022, Order issued December 28, 2004). These new 230 kV distribution substations include: Grand Teton in 2008; Iron MountaidRainbow in 2009; Log Cabin and ElkhomICommerce in 2010: and ElkhornIPecos in 2012. All five distribution substations are to be served from either the existing Hany Allen to Northwest 230 kV line, the existing Iron Mountain to Pecos 230 kV line, or the existing Iron Mountain to Northwest 230 kV line.

In general, 230112 kV distribution substations cost more than 138112 kV distribution substations because of the need for a larger parcel size, more heavily insulated transformers, and larger circuit breakers as well as larger bushings, insulators, and support structures. The benefits of 230112 kV distribution substations versus 138112 kV distribution substations are less transmission line and transformer core losses, greater transmission line transfer capability between substations, more line loading capability, and lower single contingency outage ("N-1") voltage requirements (0.90 versus 0.93). Since the line can remain energized after 230112 kV distribution substation bus faults, the proposed new 230112 kV distribution substations will have line sectionalizing circuit breakers providing additional flexibility in operating the bulk transmission system, and affording greater reliability during substation bus faults. Maintaining the existing'~any Allen to Northwest line at 230 kV allows for a higher line ratinglcapacity as well.

An operational concern of converting this line from 230 kV to 138 kV is the reduction of the Northwest Las Vegas area transmission capacity by a minimum of 225 MVA during normal operation and 290 MVA during emergencies. An alternative is to serve the distribution substations at 138 kV and convert the existing Hany Allen to Northwest 230 kV line into a 138 kV sub-transmission line and folding it into each of the five proposed distribution substations. To mitigate the conversion of the existing 230 kV line, a new Hany Allen to Northwest 230 kV line needs to be constructed prior to de- energizing the existing 230 kV line. This work will be required by 2007 in order to allow 230 kV to 138 kV transmission line conversion work to be conducted so that Grand Teton distribution substation can be served by its scheduled completion date in 2008. The cost of existing substation modification work at Iron Mountain, Pecos, and Northwest Substations necessary for the 138 kV conversions are included in the cost of the Grand Teton distribution substation, which is to be constructed by 2008, and the Iron MountaidRainbow distribution substation, which is to be constructed by 2009.

It should be noted that the new Hany Allen to Northwest 230 kV line will be needed in 201 1 even if the new distribution substations are to be 138/12 kV substations instead of 230112 kV substations. Nevada Power would merely be delaying the transmission line construction work from 2007 to 201 1. The request to expend the hnds to secure this route was submitted and stipulated to in Nevada Power's Tenth Amendment (cited above).

Nevada Power is requesting authorization to purchase a 230/12 kV x 138x12 kV, 25 MVA mobile transformer in order to support reliability to these 230112 kV substations and to be utilities during their construction. Figure TP-28 VARS 230112 kV Grand Teton Substation (2008)

Figure TP-29 VARS 230112 kV Iron MountainIRainbow Substation (2009)

Planning ln- service Date IRON MOUNTAIN / RAINBOW SUBSTATION (%Millions) I I 6/1/2009 1 Link LM Communications $0.5 0 I 2UO9 I Iron I\.l(!u~~tai~vl>n SI6.U- 6, I ?UO9 I lrun 31(1111itail~I(;ii~ibu~_Tr~~is~iii~sio~i ('o~ii~ii~~n~i;~t~o~is Kcql~~re~iic~il'i $0.4

I Total Iron MountainlRainbow Substation $19.4

Figure TP-30 Vars 230112 kV Log cabin Substation (2010)

Planning ln- service Date LOG CABIN SUBSTATION (%Millions) I I 6/1/2010 Link LM Comniunications $0.4 61112010 Log Cabin 230112 kV Substation $16.5 6/1/2010 Log Cabin 230112 kV Sub Land Purchase $0.6 6/1/2010 Log Cabin 230112 kV Transmission/Communications Lands $0.1 6/1/2010 1 Log Cabin 230112 kV Substation Transmission Line Work $2.6 I Total Log Cabin Substation 520.2 Figure TP-31 VARS 230112 kV ElkhornICommerce Substation (2010)

Planning In- service Date ELKHORN 1 COMMERCE SUBSTATION ($Millions) I I I I 6/1/2010 1 Link LM Communications $0.5 6/1/2010 ElkhondCommerce 230/12 kV Substation $16.4 6/1/2010 Elkhom-Commerce 230 kV Substation LANDS $0.2 6/1/2010 Elkhorn-Commerce 230 kV Transn~issiodTelecommunications $0.1 6/1/2010 Elkhorn/Commerce 230 kV Substation Transmission Line Work $1.1 I Total ElkhornlCommerce Substation I $18.3 I

Figure TP-32 VARS 230112 kV ElkhornlPecos Substation (2012)

Planning ln- service Date ELKHORN I PECOS SUBSTATION ($Millions)

6/1/2012 Link LM Communications $0.5 6/1/2012 ElkhomdPecos 230112 kV Substation $17.4 6/1/2012 ElkhodPecos 230112 kV Substation LANDS $0.4 6/1/2012 Elkhom/Pecos 230/12 kV Transmission/Communications $0.2 6/1/2012 ElkhodPecos 230 kV Substation Transmission Line Work $0.9 Total ElkhornIPecos Substation $19.3

Figure TP-33 VARS 230112 kV Mobile Substation (2008)

Planning In- VARS - MOBILE 230112 kV SUBSTATION ($Millions) service Date I I I 6/1/2008 1 New 230/12kv, 138112 kV Mobile Substation $3.9 I Total VARS - Mobile 230112 kV Substation $3.9

Figure TP-34 VARS 230112 kV Substation Cost Summary

Planninc In-service Date I VARS - 230112 kV SUBSTATION COST SUMMARY I (%Millions)

' 6/1/2008 Total Grand Teton Substation 514.50 6/1/2009 Total Iron Mauntain/Rainbow Substation $19.40 - 6/1/2010 Total Log Cabin Substation S20.20 6/1/2010 Total EIkhorn/Comrnercc Substation $18.30 6/1/2012 Total Elkhornmecos Substation $19.30 6/1/2008 Total VARS - Mobile 230112 kV Substation $3.90 Total - 230/12 kV Substation $95.60 Tlrzrnderbird S~rbstationand VARS Transmission Systertt Additions

To meet the future load growth in the Las Vegas Valley, eight new 138 kV substations to the east and northwest of Iron Mountain substation need to be constructed between 201 1 and 2021 including: New 7 in 201 1; New 6 and CentennialkJellis in 2012; New 1 and New 2 in 2015; New 3 and SNWA in 2018; and New 4 in 2021. These 138112 kV distribution substations arc in addition to the five proposed 230112 kV distribution substations mentioned earlier. Refer to Figure TP-27 for the location of these 138112 kV substations.

Additionally, Nevada Power proposes completing construction of the Thunderbird 2301138 kV substation by 201 1. This substation is needed to serve projected load growth of existing and new distribution substations in the North Las Vegas area. Nevada Power proposes installing a 2301138 kV 336 MVA transforn~crat Thunderbird substation in 201 1, primarily for the New 7 and Centennial INellis distribution substations scheduled to be in-service by 201 1.

Ncvada Power proposes constructing the Thunderbird to Northwest 230 kV line 011 quad-circuit structures (two 230 kV circuits and two 138 kV circuits) by 201 1 and the Thunderbird to Iron Mountain 230 kV line on quad-circuit structures by 2012. Thus, the construction of Thunderbird needs to be complctcd by 201 1. Both 230 kV transmission lines are needed to accommodate bulk transmission service and to improve reliability, as well as provide structures for 138 kV sub-transmission under-built circuits for proposcd distribution substations in the North and Northeast Las Vegas area. Nevada Power also proposes foldii~gthe existing Harry Allen to Northwest 230 kV line into Thunderbird and Pecos substation by 201 1 to provide bulk transmission system reliability and operational flexibility. Also, the 2301138 kV 336 MVA Thunderbird transformer is nceded by 201 1 as part of thc Thunderbird 2301138 kV substation project for support of Distribution Substation New 6. Figure TP-35 is a one line diagram of the proposed substation installation. Figure TP-36 is the cost cstimate for the project.

If the federal corridor is identified through the DOE efforts associated with the Energy Policy Act of 2005 Section 368, Nevada Power will begin studying a 500 kV line (in lieu of 2-230 kV lines) along the Harry Allen - Northwest corridor with two under built 138 kV lines. Figure TP-35 Thunderbird 2301138 kV Substation One-Line Diagram (2011)

Figure TP-36 VARS Thunderbird Estimated Cost Summary

Planning ln- VARS - THUNDERBIRD SUBSTATION ($Millions) service Date I I 6/1/2011 Thunderbird Sub Comlnunications 3L.U 6/1/2011 Thunderbird Sub Transmission (1 quad Third to NW) $38.1 6/1/2011 Iron Mountain work for Thunderbird 230 kV $0.5 6/1/201 1 Northwest work for Thunderbird 230 kV $2.8 6/1/2012 1 Thunderbird 138kV work for New 6 1 ( Total Thunderbird $54.1 Iron Mountain 230/138 kV 336-MVA transforiner

Nevada Power proposes installing a new 2301138 kV 336 MVA transformer bank at Iron Mountain in 2007 to meet future 138 kV distribution station load growth and meet voltage reliability requirements due to load growth. The existing 2301138 kV transformer overloads abovc its emergency rating during an outage on the Pecos to Allen 138 kV line. Alternatives were investigated such as installing a new transformer at Pecos substation: however, due to systcm topography this alternative did not resolve the existing Iron Mountain transformer single contingency reliability overload. Proposed distribution substations in the Northwest area and 138 kV sub-transmission topology changes in the area also contribute to the timing of this addition. Also, due to load growth various 138 kV and 230 kV lincs into and out of Iron Mountain Substation need to be modified, line terminals need to be relocated to new bays and future lines positions and structures for them need to be added or relocated in order to facilitate ease of line egress, to prevent future line outages, and avoid costly future expcnse of adding or relocating lines in the future.

Figure TP-37 Iron Mountain 2301138 kV Transformer #2 One-Line Diagram Figure TP-38 VARS Iron Mountain 2301138 kV Substation Cost Summary

Planned In- VARS - IRON MOUNTAIN 2301138 kV. 336 MVA ($Millions) service TRANSFORMER Date

6/1/2007 Iron Mountain Transformer Addition $10.0 6/1/2007 Iron Mountain Loop in of 138 and 230 kV lines near Iron $5.5 Mountain Sub Total VARS -Iron Mountain 2301128 kV, 336 MVA $15.5 Transformer

Northwest 230/138 kV 336-MVA Transformer

A new 2301138 kV 336-MVA transformer is needed in 2009 to meet future load growth at existing substations as well as for future distribution substations to be fed from the Northwest 50012301138 kV substation. New distribution substations in this area include: Gateway 138112 kV substation (2008): CentennialIHualapai 138112 kV substation (201 1): and New 7 138112 kV substation (201 1). Each distribution substation is projected to have an ultimate build out of 100 MVA. This new transformer is also needed to meet N-1 contingency reliability criteria. The only other alternatives are to not serve the future substations or to build a new 230 kV substation in Northwest Las Vegas, both of which would cost significantly more than the Northwest 2301138 kV transformer. Figure TP-39 Northwest 2301138 kV Transformer #2 One-Line Diagram

Norihiies, i3C-*" Bonk NO. 2

ruture ------,!38-t$

K"rtl,,resl 138-k\'

...... Future :..J

rut"-e ,:a rr i:s-<, Figure TP-40 VARS Northwest 2301138 kV Transformer Cost Summary

Planning In- VARS - NORTHWEST 2301138 kV. 336 MVA TRANSFORMER ($Millions) service Date

61112009 Northwest Substation 2301138 kV Transformer $7.8 kV, $7.8 Total VARS Northwest 230/138 336 MVA Transformer 1

Brooks 230/138/12 kVSubstation and Pecos to Brooks 230 kV Line

Nevada Power conducted studies to analyze the transmission system south of Pecos substation, primarily for the new Gilrnore 138112 kV distribution substation in 2006, the Lincoln 138112 kV distribution substation in 2007, and the proposed Brooks 2301138112 kV transmission/distribution substation in 2010. The Pecos substation is heavily loaded and during various N-1 contingencies, according to the studies, voltages will drop below acceptable reliability standards at Leavitt, Tropical, the future Gilmore, and the future Lincoln substations. This voltage drop is primarily due to the lack of bulk transmission support in the vicinity of these substations. The addition in 2010 of a new 230 kV transmission line between Pecos and the future Brooks substation site along with folding in the 138 kV sub-transmission between Leavitt and Gilmore substations into the Brooks substation will eliminate the N-1 low voltage issues.

Nevada Power is also requesting an option to install a 230 kVl12 kV substation for the new Brooks substation in lieu of a 138112 kV substation and to construct a 230 kV transmission line from Brooks to Highland substation. The Brooks distribution substation is projected to have an ultimate build-out capacity of 100 MVA.

An alternative is to build Brooks as a 138112 kV distribution substation only. This option was not investigated since N-1 contingency violations would still exist in the area. The estimated cost for the VARS project cost is provided below. A one-line diagram showing the substation and the transmission interconnections for this substation is provided in Figure TP-41. The projected cost estimates for this upgrade are provided in Figure TP-42A. The total estimated VARS costs of $230.6 million are summarized in Figure TP-42B. Figure TP-41 Brooks 2301138112 kV Substation One-Line Diagram

I t

r.4 ;

'5 J I I &--..-J I 11 , I I--? : r '4 I '-, J t '-.J : 0 ------I - 8 -*1:" , I-*- r r'i I '-,A : J I I1 I ""*-".*--*--- e--*--- t I I , I I ::.,,>: i:,i3 t .],'..i,.. . .I' 1 :,5 .. . I r------"--- &. ,----- ""- :"=:am% .*"+%*s ; t i I i 1 --q-+>-f-T~-w-~--p I $1' '-2 : -2 i- ; r dl I L L,J L ' ; LJJ o r 8--3 &- .&. ..&. I----- * $1, I I r17 I- '1 '-8 r'? $7, P&A "A- "*. b,J b,J I L.J L,J L,-l %9 2.r ' I r---9 &-A m,..".., L--- & ~ - 1111 i i-1-t r:? i ; 1 : r-17 I LIJ b.2 L 1 L I LIJ ,111 $4-A-*+4 +L- I I I I I t I I , I I I I I t 1,- ' " i i I. I. .. liJ'* . -- - ~ristingW ' r,., -- ; - ---- ~)~.~~~~~d~ '"! ...... -...Future :--: Figure TP-42A VARS Brooks 230/138/12 kV Substation Cost Summary

Figure TP-42B VARS - Total Cost Summary

Planning ln- VARS - PROJECT SUMMARY COST ESTIMATE (%Millions) service Date

Various Total VARS - 230112kV Substation Cost Surnrnaly $95.7 Various Total Thunderbird $54.1 6/1/2007 Total VARS - Iron Mountain 2301128kV. 336MVA Transformer $15.5 6/1/2009 Total VARS Northwest 2301138kV. 336MVA Transformer $7.8 6/1/2010 Total VARS -Brooks 230/138/12 kV Substation $57.5 Total VARS - Project Summary Cost Estimate $230.6

SINATRA SUBSTATION

Sinatra substation is planned to serve projected load along the Las Vegas Strip including Project City Center ("PCC"). PCC is a development by MGM Mirage located between Las Vegas Boulevard South and Interstate 15 and between the Bellagio and Monte Carlo Resort Casinos.

The scope of the Sinatra project involves the installation of the Sinatra 230/138/12 kV substation with four 138112 kV 50 MVA transformers. The existing Arden-Decatur 230-kV line will be folded into Sinatra substation. The Mead-Decatur 230 kV line will be folded into Arden Substation.

It is projected that the total load demand for PCC will be between 102 and 130 MVA. Nevada Power has discussed numerous load service options with its customer, MGM Mirage. In order to provide the requested amount of construction power and back- up requirements, the existing two 25 MVA transformers at the customer-owned Bellagio Substation were upgraded to two 50 MVA transformers. The two 50 MVA transformers will provide the initial capacity for construction power and later provide back up service to PCC once it is in commercial operation.

It is probable for the future Highland-Sinatra 230 kV line route to cross over to the west side of Interstate 15. Therefore, it is recommended that when boring Interstate 15 for the Decatur-Sinatra 230 kV line and the Arden-Sinatra 230 kV line, an additional bore be added for the future Highland-Sinatra 230 kV linc and for the future Procyon- Sinatra 138 kV line described below. This future 230 kV underground circuit should have a capacity greater than or equal to that of 954-bundled overhead ACSS. This line is anticipated to be needed at some time in the future as the load density on the Las Vegas Strip continues to increase and surpasses the transmission capacity of the existing 138 kV and 69 kV circuits which envelope the resort corridor south of Sahara Avenue.

There is also significant 138 kV work required for PCC including construction of the Sinatra 138112 kV substation along with the Suzanne-Sinatra 138 kV linc and Sinatra- Bellagio 138-kV linc folds into the Sinatra 138 kV substation. Various options were created for PCC and are discussed in the Technical Appendix. This linc is anticipated to be needed at some time in the future as the load density on the Las Vegas Strip continucs to increase.

The estimated cost of the preferred optiol~138 kV work is $49.8 million and a cost breakdown is provided in Figure TP-43. The 230 kV work estimated costs for this preferred option is $59.5 million and the cost breakdown is provided in Figure TP-44. Figures TP-45 and TP-46 are onc-line diagrams of the associated facilities for PCC.

Figure TP-43 Sinatra 138 kV Estimated Costs

Planning ln- service Date SINATRA 138 kV ($Millions) I I Figure TP-44 Sinatra 230 kV Estimated Costs

Figure TP-45 Sinatra Transmission System One-Line Diagram

STRIP

EX$S~S$S,~2.&;kb b.:nc%3318 !I, .I \C.'78 - Existinu I3BkV LinelSulI - ExiBillg 6gkVLinmub Figure TP-46 Sinatra Substation One-Line Diagram

Crr&onner Owtted Facilities

"a;;. I.,'....8 B.....@, ,...... Sjj ,z $tj!?%t ;...... P' i f +-i (!... ..I!. 9.6 p&$/A[{ j).~..... iiriil .+ ., 2:2fli?v- L,'-p&--p, 11 ,p;jt; *:.m.! " ;~...."..... m----a-

Ai;Eehii +. /' .... B...... @ ...... s /,gfjg<\.# ~.i : ,:%,k-j Oi ! 1.. ".!,3l.,! *.~Es~<& f :<:l?i;J

...... fxiairtg $z.$lrkVlLi~,n,'i.'(~:EJ f7J - -. - - - F trtirrt? 12.17kV I.irteii'i:i3

~i...... f:iiiii;#st.ij238 kv i.jri:.!i"\.:U

STRATEGIC PLAN FOR LAS VEGAS CORE SERVICE

Nevada Power foresees a need for thc following new 230 kV ties: North Las Vegas to the Strip; South Las Vegas to the Strip; and East Las Vegas to the Strip. The projected need is due to the vertical load growth in the Strip arca and the limited capacity of 691138 kV lines and substations in the Strip area. The projected load growth along the Strip is estimated to be 1,000 MW over the next ten years. To meet the expected load growth Nevada Power is requesting funding in the amount of $1 million over the next three years to perform Las Vegas Strip area Transmission Planning Studies and acquire pcrmits, ROW, and lands for 230 kV corridors and substations betwecn the following substations: Pecos and Brooks; Brooks and Highland; Sunrise and Highland; and Highland and Sinatra.

West Henderson Area Improvements

The population of the West Henderson area is growing rapidly. This rapid growth results in increased demands on the existing distribution substation system thereby taxing the sub-transmission and bulk transmission system in the area. New distribution substations are planned for construction in the West Henderson area to accommodate the development. As a result, transmission system reliability margins are quickly eroding, dictating a need for transmission system additions in the West Henderson area. To mitigate this problem, Nevada Power proposes adding the following facilities in the West Henderson area between 2006 and 20 12.

- Constructing three new 230/12 kV Substations in West Henderson; West Henderson, Southeast 1 and Southeast 2 distribution substations. - Folding the existing Arden-Magnolia 230 kV line, or the Magnolia-Merchant 230 kV line into the West Henderson 230112 kV substation - Folding in the Arden-Tolson 230 kV line into Southeast 2 230112-kV Substation.

Three new distribution substations are planned to meet growth in the West Henderson Area: Southeast 1 230112 kV distribution substation (2008); West Henderson 230/12 kV distribution substation (2010); and Southeast 2 230/12 kV distribution substation (2012). Each substation has an ultimate build-out capacity between 100 MVA and 140 MVA. The existing 138112 kV distribution substations in the area include Keehn, Bicentennial, Wilson, Tolson, Cactus, and Anthem.

An alternative to installing the West Henderson 230112 kV substation is to expand the Magnolia substation and construct new 138 kV lines between Magnolia, West Henderson, Tolson, Arden, and Southeast 1 substations and build the West Henderson substation as a 138112 kV distribution substation. Because the Henderson Airport is in the area, permitting and routing of overhead transmission lines is uncertain and needs to be further investigated. Moreover, the ability to procure additional land to expand the Magnolia substation to accommodate additional 138 kV terminals may also he a challenge. There is also a reliability concern if obtaining additional 138 kV rights of way is not possible, in that all 138 kV circuits in the area would have to occupy the same structures. During a contingency, this could result in loss of load service to all distribution substations in the area.

Installing the 138 kV transmission lines underground is also an option but not cost effective when compared to the Preferred Plan. The four miles of underground 138 kV double circuit transmission lines that are required are estimated to cost $26 million ($6.5 million per mile). A cost summary of the West Henderson Area Project estimated costs is provided below. Figure TP-47 Southeast 1 230/12 kV Substation Estimated Costs

Planning In- WEST HENDERSON - SOUTHEAST1 230112 kV SUBSTATION ($Millions) service Date

6/1/2008 SOUTHEAST 1 230112 kV Conmlunications $0.7 6/1/2008 SOUTHEAST 1 230112 kV SUBSTATION $15.6 6/1/2008 SOUTHEAST 1 230112 KV SUB LAND PURCIlASE $0.1 6/1/2008 SOUTIIEAST 1 Transrnission/Telecorn~~~unicatiot~sLAND RIGHT $0.5 61112008 SOUTIIEAST 1 230112 kV SUBSTATION Transn~issionLine Work $6.6 Total West Henderson - Southeast1 230112 kV Substation $23.4

Figure TP-48 West Henderson 230112 kV Substation Estimated Costs

Planning In- WEST HENDERSON - WEST HENDERSON 230112 kV service Date SUBSTATION ($Millions) I I 6/1/2010 West Henderson 230112 kV SUBSTATION Transmission Line Work $1.2 61112010 WEST HENDERSON 230112 kV SUBSTATION $16.5 6/1/2010 WEST HENDERSON 230112 kV SUBSTATION Co~~~rnl~nications $0.5 6/1/2010 WEST HENDERSON 230112 kV SUBSTATION LANDS $3.7 Total West Henderson - West Henderson 230112kV Substation $21.9

Figure TP-49 Southeast 2 230112 kV Substation Estimated Costs

Planning In- WEST HENDERSON - SOUTHEAST2 230112 kV SUBSTATION (%Millions) service Date

6/1/2012 SOUTHEAST2 230112 kV SUBSTATION Transmissioll Line $9.4 6/1/2012 SOUTHEAST 2 230112 kV SUBSTATION $17.4 6/1/2012 SOUTHEAST 2 230112 kV SUBSTATION Communications $0.8 6/1/20 12 SOUTHEAST 2 230112 kV Transmission Telecommunications $0.5 6/1/2012 SOUTHEAST 2 230112 kV SUBSTATION LANDS $0.2 Total West Henderson - Southeast2 230112kV Substation $28.3

Figure TP-50 Summary of Estimated Costs

Planning In- 1($Millions) service Date

6/1/2010 Total West Henderson - West Henderson 230112 kV Substation $21.9 6/1/2012 Total West lienderson - Southeast2 230112 kV Substation $28.3 6/1/2008 Total West llenderson - Sol~theastl230112 kV Substation $23.4 Total West Henderson - 230112 kV SUBSTATION SUMMARY $73.6 Figure TP-51 West Henderson Area One-Line Diagram

'/ Sicer!enniaI ,. LEGEND _ Exlsllng tJB.*Y *-. -*. -- Ulrting ZJO*" . ~.~ -~ ------~~~~~~~d 118.k~ Magnnlis 2006 Viest Henderscn .-----.P-posed 230.k" .rc,,s. .;<... Additions (Option 3) Hsw13WY )-be bunl(1.d 054ACSl

OTHER NEW PROJECTS BEING PROPOSED

McDonald Substation 230/138 kV transformer

The scope of this load growth driven project is to construct the McDonald 230 kV substation and install a new 336 MVA 2301138 kV transformer at the existing McDonald 138 kV substation. The existing Arden-Decatur 230 kV line will be folded into the new McDonald 230 kV bus. There is presently one 138 kV line between Arden and Avera substations that serve Quail, McDonald, Procyon, Railroad (2008) and Carnero substations. The anticipated coincidental peak on the existing Quail, McDonald, Procyon, Railroad, and Camero substations is expected to exceed the 247 MVA emergency 138 kV line rating by June 2009. Subsequently, a new transformer is needed at McDonald substation prior to June 2009. This transformer will provide more capacity on the 138 kV line which serves these five substations. The total anticipated cost of this project is $8.5 million. Figure TP-52 provides a cost estimate for the McDonald 230 kV substation work while Figure TP-53 illustrates a one-line diagram of this proposed project. Figure TP-52 McDonald 2301138 kV Substation Estimated Costs

Planning ln- McDonald 2301138 kV TRANSFORMER ADDITION ($Millions) service Date

6/1/2009 McDonald 2301138 kV Transmission Line $0.1 6/1/2009 McDonald 2301138 kV Transforn~er $8.6 Total McDonald 2301138 kV Transformer Addition $8.8 Figure TP-53 McDonald 2301138 kV Substation One-Line Diagram

Railroad 138kV

-.-.*~-- E;~j~a:~~:33 k?f

Existing 138 kV Line ~~i~~~,~~~~iq$1 Pri:gtosed 13:! kt:\: lin- Existing 138 kV PCB 954 A

A new 2301138 kV transformer bank will be needed at Arden substation in 2008 to relieve the loading on the Tolson 2301138kV bank for outage of the Arden 2301138kV No. 1 transformer. In order to install the second transformer, the 230 kV and 138 kV busscs at Arden need to be expanded. The estimated cost is provided below.

Figure TP-54 Arden 2301138 kV Transformer No. 2 Installation and One-Line Diagram

Figure TP-55 Arden 2301138 kV Transformer Estimated Costs

Planning ln- ARDEN 2301138 kV BANK ADDITION ($Millions) service Date

6/1/2010 Arden 2301138 kV Autotransforn~erNo. 2 Addition $6.3 Total Arden 2301138 kV Bank Addition 56.3

CIark 230/138 kV bank No. 6 Change-out

The existing 2301138 kV 286 MVA transformer bank No. 6 at Clark ("Clark Bank") needs to be changed out to a 400 MVA bank in order to deliver Nevada Power's resources from Harry Allen into the uncongested grid. The existing Clark Bank is the limiting element to get these resources into the uncongested grid when it is loaded to its normal rating for steady-state normal operating (N-0) conditions. The existing Clark Bank can be installed and utilized at a future 2301138 kV transformer location or eventually paralleled with the new 400 MVA Clark Bank if alternatives become viable.

Figure TP-56 Clark 2301138 kV Transformer Upgrade One-Line Diagram

Figure TP-57 Clark 2301138 kV Transformer Upgrade Estimated Cost

Planning ln- CLARK 2301138 kV BANK #6 CHANGEOUT ($Millions) service Date

6/1/2010 Clark 230/138 kV Bank #6 Change-out $4.1 Total Clark 2301138 kV Bank #6 Change-out $4.1

Valley EIectric Association Intercortnection

Valley Electric Association ("VEA") has submitted an interconnection request to Nevada Power for interconnection of the VEA's Sterling 230 kV substation to Nevada Power's Northwest 230 kV substation. The interconnection will allow VEA to meet NERC voltage reliability requirements during N-1 contingencies. The transmission line is proposed to be 42 miles long, energized at 230 kV and utilize 954-ACSR. Nevada Power would build and pay for six miles of the line (to just North of the Las Vegas Paiute Reservation) and facilities required for interconnection at Northwest substation. VEA would build and pay for the remaining 36 miles of the line and the associated interconnection facilities at their Sterling substation. The project costs are listed below. A one-line diagram of the proposed interconnection is provided below. In this onc-line diagram a new transmission substation is shown. This is a conceptual substation only and may or may not be required in the distant future, depending on load growth and ability of Nevada Power to secure ROW for future transmission lines. This conceptual transmission substation is named New TS for reference only and is not required as part of the VEA Interconnection request.

Figure TP-58 VEA Interconnection One-Line Diagram Figure TP-59 VEA Interconnection One-Line Diagram Figure TP-60 VEA Interconnection One-Line Diagram

lie,, 7s (or Thlndirb'rd) Narih.ei 500-ri Pr"Zr4 rar M:n 230-k

lz10/11B-XI 1230/138-k~~1?30/138-*I 23U/130-XI Harry her Weitside 233-1 rmo-11, ,A I~OO-L~VA1300-llv~ 200-UVA 233-h1

I I I I I I I I I , t I r-----J I I I I p----,J I I I I b------I I

2- -L T, 8, ,+ h lrior11,sest L,J b' 138-kY

I - I I I i I I I I I I I I I I I m I I : I I t \en !or 1101 1 is z~l,re LO"? I l"c~~r~!o##', . d~, kJ I,,:? ie-iv {I t I:~-KL 1 \*", 75 (0, #fop Uodn:ol.l:, El :aa i;kna..i I:%-<,' #i 138-1.. 138-kV '38-kV Figure TP-61 VEA Interconnection Estimated Cost

' Planning In-service Date VEA INTERCONNECTION ($Millions)

6/1/2007 VEA Interconnection Communication $1.5 6/1/2007 VEA Interconnection at Northwest Substation Lands $0.8 6/1/2007 VEA Interconnection at Northwest Substation Transmission Line $8.1 6/1/2007 VEA Interconnection at Northwest Substation Transmission $3.9 Total VEA Interconnection $14.2

The following figure summarizes costs for EVAMP, VARS, Sinatra, West Henderson and other transmission upgrades described in the preceding paragraphs.

Figure TP-62

Clark Generating Station Peakers

Nevada Power retired Clark Units 1, 2 and 3 in September 2005. This resulted in the loss of 175 MW of internal in-valley generation as well as much needed voltage support to the Nevada Power system. In order to provide voltage support during high imports, quick start spinning reserve capacity and peaking capacity, Nevada Power proposes installing approximately 400 MW prior to summer 2008 and approximately 200 MW prior to summer 2009. Nevada Power is examining three different peaking technologies (GE LM6000 PC, GE LMS100, and Pratt & Whitney FT8-3 Swift Pac) with different costs and performance. Upon Commission approval of this 2006 Resource Plan, Nevada Power will select a technology based on project bids from GE and Pratt & Whitney. For economic modeling purposes, thc Pratt & Whitney Units (642 MW) were assumed (see the Supply Side section of this Volume for more dctail on the Clark Peaking Units).

Peaking Units will allow Nevada Power to recover lost voltage support as well as hclp support the system during situations where loss of other generation or other economic resources arc unavailable to meet pcak summer load requirements. The total installed capacity of thc proposed three gencrator sets is approximately 600 MW. The installation of the Clark Peakers will require the segregation of the pcaker units among both the 69 kV and the 138 kV buscs. Figure TP-63 is a one-line diagram of the proposcd peaker installation on the 138 kV bus. If Nevada Power chooses thc Swift Pac packages, it will entail the interconnection of two Swift Pac packages totaling 428 MW. Figure TP-64 shows the installation of the third Swift Pac package onto the 69 kV bus. Studies are continuing to review the project and its impact with the other transmission projects proposed in the general vicinity.

The addition of 642 MW of generation will create fault duty concerns on the Clark 138 and 69 kV buses. The existing breakers may not he able to interrupt the fault current contributiotl of the peakers that will occur for a three-phase fault on the Clark bus. Splitting the Clark 138 kV bus into two bus sections appears to reducc fault current to acceptable levels. It also appears that the Clark 69 kV bus will require breaker replaccments in order to allow for the safe operation of the system. Fault duty studies are currently underway, and the final results will not he known until later. Figure TP-65 provides the projected cash flows for this project. Figure TP-63 Clark Peaker 138 kV Interconnection One-Line Diagram

CLARK GENERATION ADDITIONS AND BUS MODIFICATIONS

OECOMMISSION AN0 OIOCONNECT -

GREEN VALLEI

CLAYLIONTI,

SPENCER NO.

INSTALL NNI CLAIMONT* GNEWON I0MW NICH,"PICAL,I, PUCE3 P&UIULINLR I10

OPEN BUS &NO SPENCERSO. ~~A~~~,","~ ,NS,ALL LO&O BRmK SWITCH SWITCH BREAK LOCKLO OPT" WliRLFL>FE:a

WINTERWOOD

(';>.+:.-> 2 1 -, s Figure TP-64 Clark Peaker 69 kV Interconnection One-Line Diagram

CLARK GENERATION ADDITIONS AND BUS MODIFICATIONS

WHHI- L-- L-- 6%" EAST BUS BRINE -,r, E BASIC.CLARK CONCENTWTE - EQUESTRIAN WlllTNEY I' - WINTERWOOD

SAN FMNCISCOIII a<>

DECOMMISSION AND DlSCONNECT 1

(?,....---- z-- 'TI, 5 - ,_- a*- ! 92-4 > RECONFIGURE \."> ,> BUSSWORK AN0 T&PS AS REPUIREO

W BASIC-CLARK

6910

INSThLL NEW GNEWTIOW IOMW E&CH NPICAL III PLACES

SAW FRAN. 7 60kY WEST BUS WATERSTREET W

FLAMINGO

WATERSTREETXI Figure TP-65 Clark Peaker Project Cash Flows ($ million)

Project 2006 2007 2008 2009 Total Clark Station Peaker Units 25.1 198.2 136.4 24.6 384.3

Solar One Interconnection

Nevada Solar One (NSO) has requested generation interconnection of its proposed 65 MW solar generation facility to the existing Nevada Power transmission system. The NSO site is expected to go into commercial operation in March 2007 and is located approximately 20 miles south of Las Vegas near the existing Merchant 230 kV Substation. The proposed 65 MW project will interconnect to the Nevada Power system by folding in the existing Merchant-Magnolia 230 kV line into the NSO 230 kV substation. The estimated cost to Nevada Power of the project is listed in Figure TP-66. These costs (plus interest) will be refunded by Nevada Power to NSO. A one-line diagram is provided in Figure TP-67.

Figure TP-66 Nevada Solar One Interconnection Estimated Cost

Planned In- service Date Nevada Solar One lnterconnection Estimated Cost ($ Millions) 2006 Solargenix IPP Communications $0.6 2006 Solargenix 230 kV TranITelecom Land Rights $0.3 2006 Solargenix 230 kV Interconnection $1.6 2006 Solargenix 230 kV Siibstation $4.3 Total Solar One Interconnection $6.8 Figure TP-67 Nevada Solar One Interconnection One Line Diagram

Nevrlrlit Solat One Gerrerator &:iPAVfi

......

. / tttslnii: ti.3 R#i!t!r of 1~- .,? 12-954RCSb3 a pole lirbr-: I ', ,..' i lttrill for 7 2:lfil:V C:.irntti(s . - ......

t Future Existing

~~ ~ ~ . prrttxm5.c) (ti 95.PACSI.I. BOW !TC:f) r .I ------Future '& Nf'f: s;l~rr?rirtqI'rtiril

IMPORT CAPABILITY

Import capability is the energy that can be transferred into a control area. The control area boundary is specifically defined for each control area by the WECC. Import capability is determined in accordance with WECCNERC reliability criteria. Accordingly, the system must be capable of meeting all performance criteria for steady state and single contingency outage conditions at thc stated import Icvel. Figure TP-68 shows the optimum maximum import capacity. It is importaut to note that in order to achieve the highest import capacity, the Clark Generating Station Units must be deliveriug powcr to Ncvada Power's control area. Figure TP-69 shows the maximum import capacity of the Nevada Power system employing an economic/optimal internal (within Nevada Power's control area) generation configuration. Figure TP-68 Maximum Import with Optimal Generation Configuration

Existing Plus Plus Plus Sunrise Tap Plus Equestrian System HAM NW Bank #2 Facilities Tap Facilities 5001230 kV 3,713 MW 3,988 MW 5,200 MW* 5,200 MW* 5,700 MW*

Figure TP-69 Maximum Import with Economic Dispatch Configuration

Existing Plus Plus Plus Sunrise Tap Plus Equestrian System HAM NW Bank #2 Facilities Tap Facilities 5001230 kV 1.550 MW 1,800 MW 4,000 MW" 4,400 MW* 4,200 MW*' 'assumes a 400 MVA bank at Clark 6 **assumes two400 MVA banks at Clark 6

EXPORT CAPABILITY

Nevada Power's export capability is dependent on generation dispatch patterns and the maximum export capability can only be achieved with high internal generation and low loads which allows for the schedule of vast amounts of power out of the control area in order to define this export limit. Figure TP-70 shows the export capacity out of the Nevada Power control area with an economic dispatch generation configuration within the Nevada Power control area.

The following table shows the study results for maximum export capability out of Nevada Power's system with the present system, post HAM, with the addition of a new Northwest 5001230 kV transformer bank, with the Sunrise facilities, and with the projected Equestrian facilities.

Figure TP-70 Maximum Export with Optimal Generation Configuration

Existing Plus Plus Plus Plus Equestrian System HAM NW Bank #2 Sunrise Option Option 500f230 kV (2014) (2014) (2006) (2007) (20 10) 1,800 MW 3,800 MW 5,200 MW 5,000 MW 5,000 MW 4,000 MW * 4,800 MW * 5,070 MW * * With EEC

Existing and Proposed Transmission Obligations

Nevada Power has transmission obligations for import capacity and export capacity out of the control area. Figures TP-71 and TP-72 lists these obligations.

146 Figure TP-71 Nevada Power's Long-Term Transmission Obligations for Import into the Control Area (4)

. . HA-Red Butte 345kV Line TOTAL 1 158 1

Figure TP-72 Nevada Power's Long-Term Transmission Obligations for Export Out of the Control Area

(I) SouthemNevada Water Atnthority (SNWA) is taking unbundled retilil lrunsmission under Pati 111 and IV of the OATT. Lns Vegas Valley Water District (LVVWO) started taking unbundled retail trnnsn?ission under Part 111 and IV of the OAlT on llme 1.2006.

TRANSMISSION LOSSES EVALUATION

Nevada Power's efforts to evaluate and mitigate line losses have been minimal within the last few years. Because of the extra workload placed on the Company's Planning staff due to load growth, IPP development, and rcncwable energy evaluations, staff could not be allocated to this effort. Only in cascs of 500 kV construction or high reactive loading, were planning enginccrs assigned to line loss studies.

COMPLIANCE

Nevada Power has endcavored to reduce its cxposure to contingencies. With the purchases of Lenzie No. 1, Lenzie No. 2 and Silverhawk, the most severe single contingency (MSSC) has incrcased from 275 MW (loss of Reid Gardner No. 4) to 551 MW during summer peak (loss of generation at one Lenzie generation block). The loss would occur when a fault on the collector ring bus at the facility occurs. Transmission and Resource Planning have been ordered by the Commission to evaluate the economics of reducing the MSSC. Nevada Power investigated the feasibility of modifying the existing collector ring bus configuration at each of the aforementioned facilities to a breaker and a half substation double bus configuration.

If the Lenzie and Silverhawk collector busses are to be modified to reduce the MSSC, plant power block outages of up to a year may be necessary to reconfigure these buses. Outages could be reduced substantially if new switchyards are built. This would however result in significant duplication of equipment.

BLM permits would take about one year to secure. Due to the magnitude of Nevada Power's construction projects it is estimated that construction personnel and contract crews will be in limited supply between now and 2012. EEC is projected to be on-line in late 201 I, thus changing the worst contingency to 750 MW for an outage of an EEC generating unit. The estimated cost of constructing breaker and a half switchyards for Lenzie and Silverhawk is between $40 and $60 million. Nevada Power recommends that Lenzie and Silverhawk switchyards not be modified at this time due to time and cost of construction in addition to the fact that neither will be the largest contingency once EEC is on line.

It is also important to note that the increase in MSSC from 275 MW to 551 MW has a small impact on Nevada Power's operating reserves requirements. The increased operating reserve requirement that is solely attributable to the increased MSSC (from 275 MW to the new 551 MW level) is only 62 MW. This number is based upon a calculation of Nevada Power's Reserve Responsibility Value (RRV) with the Southwest Reserve Sharing Group (SRSG) as compared to the RRV of the aggregate SRSG pool. It assumes that Nevada Power can receive maximum assistance from the pool during a generation loss event and it assumes that Nevada Power's resource mix between generation and firm imports is constant. In practice, the introduction of the new generation at Silverhawk and Lenzie stations will change the resource mix to supply peak system load, which has an impact on the magnitude of Nevada Power's RRV. Also, the ability of Nevada Power to access the SRSG pool assistance is limited by external transmission constraints. These factors combined with the increase in the MSSC have increased the estimated contingency operating reserve requirement for Nevada Power in the peak hour from 202 MW to 398 MW, or an increase of 196 MW. As such, Nevada Power is proposing to set aside Capacity Benefit Margin for these external reserves in the amount 307 MW - the current maximum that Nevada Power can obtain from the SRSG. Figure TP-73 Lenzie Generating Station Existing Collector Ring Bus

Lenzie 4. 5. 8 6

-1 I Lenzie

500 kV Harry Allen 500 kV #I#2 Figure TP-74 Lenzie Proposed Breaker and a Half Yard

LENZIE VNITTd

I I I I I i 1 I 3 1 I I ---7- * -T-#p.-p-r""p-g'T.-b- B $1 g3 $1 $3 $ It If 1 t; 11 I 1 B 1 a ! 2-a I rI-1 $7 E-'?8 : r 2 ks=J8 LgJ 8 LIJ I Bl-l Lg-' 1 1 &.A I a i 1 I I r17 ?-% I b,J L i s 1 I r-=@ r* L 1 r83 1 P" rPl 0%4 P'L? B L24 3 L9J bid i bsd 1 Lg3 I I 1. 1 $8 8 1$$ Hi 1 #! 9 ]% I 1 -*-d,7-$---l-q-B-q-L---* S i I 1 I 3 i I 0 B f 1 ?NOET:WEST hi-2 HA- 1 SLVERHAWX

7 Figure TP-75 Silverhawk and Mirant Existing Collector Ring Bus

EXISTING HARRY ALLEN SILVERHAWK AND MIRANT STATIONS

MIRANT

HARRY ALLEN

SILVERHAWK

LENZIE

NORTHWEST Figure TP-76 Silverhawk and Mirant Proposed Breaker and a Half Yard

SILVERHAWK AND MIRANT UNITS

500 kV SILVERHAWK - MIRANT BUS

SILVERHAWK Participation in Regional Transmission Planning

Western Electricity Coordinating Council (WECC)

Nevada Power continues to participate in nlultiple WECC committees and groups to ensure efficient and integrated planning of internal and external transmission projects. This participation includes the Planning and Coordinating Committee, Technical Studies Subcommittee, Reliability Subcommittee, System Review Work Group, and other WECC technical subcommittees. Additionally, Nevada Power participates in the review of all projects that it determincs could have a material impact on the Nevada Power system.

WECC Path Rating for EEC 1 WPEA

Nevada Power has initiated the WECC Regional Review and three phase rating process for the proposed EN-ti transn~issionline connecting the Nevada Power and Sierra transmission systems. On January 19, 2006, Nevada Power and Sierra filed with the WECC to initiate this process

Southwest Area Transmission (SWAT)

Nevada Power is continuing to participate and coordinate sub-regional projects through the SWAT group. This group has become the primary planning review forum in this sub-region. The Palo Verde - Devers 500 kV #2 line and the East of River 9000+ up-rating are primarily studied through this group with WECC oversight. This is also going to be the primaty group to review the EN-ti rating - although significant participation in this review process is expected from throughout the entire WECC.

Frontier / Northern Lights / Trat~swestExpress

Nevada Power is participating in feasibility analysis for thcsc projects and others for future impacts andlor benefits to Nevada Power. At this time, these projects are in the developmental stages and are not being considered as options for Nevada Power's near and mid-term transmission plans

Energv Policv Act of 2005 (EP Act 2005)

The Energy Policy Act passed into law in 2005 opened two processes for Nevada Power to participate in corridor siting studies being conducted by the federal government. The first is a planned Programmatic Environmcntal Impact Statement covering numerous utility corridors in thc Western Intcrconnection. Nevada Power and Sierra submitted extensive comments relating to their opinions of how the process should be conducted and supplied insight in routing both internal and external to the state of Nevada. The second process was the National Interest corridor "backstop" authority process. The Companies supplied comments on this process also, but due to the less specific nature of this process input was limited to the basic directions that should be used to begin the process of defining "national interest" corridors. Regional Study Funding Purpose and Need

On April 4, 2005, the Governors of California, Nevada, Utah, and Wyoming entered a Memorandum of Understanding ("MOU"), which purpose is as stated below:

"The purpose of this Memorandum of Understanding is to declare our support for and to create a structure that will allow us to pursue the further development of the Transmission Project. The Transmission Project involves the construction of a transmission line through Wyoming, Utah, Nevada and into California. The Transmission Project will he designed to provide economic benefits to all four states, as well as enhanced reliability for the West's overall high-voltage transmission grid. The Transmission Project may be further defined and redefined as we move forward, and we do not mean to exclude the possibility of inclusion of additional facilities that will provide benefits to other states as well as ours."

The MOU also called for the creation of a Coordinating Committee, which is now known as the Frontier Line Transmission Development Association ("FLTDA"), consisting of a senior-level staff person from each of the four states. The FLTDA has been fulfilling the role of a surrogate developer until the project can be made available for further feasibility analysis.

In order to respond to the Governors' desire to create a structure that will allow them to pursue the Transmission Project, a group of investor owned utilities consisting of Nevada Power, Sierra, Pacific Gas and Electric Company, San Diego Gas and Electric, Southern California Edison, Rocky Mountain Power, and Utah Power have joined together to form the Westem Regional Transmission Expansion Partnership ("Partnership"). In a letter dated April 5, 2006, the Partnership submitted a proposal to the FLTDA to develop a feasibility report and conceptual plan for implementation of the Frontier Transmission Line Project.

The scope of the proposal is as follows:

- The Partnership should be designated by the FLTDA to develop a feasibility report for the Project, conducted in an open stakeholder process, and a conceptual plan for its implementation.

The feasibility report and conceptual plan for implementation should include: - Analysis of future load demand in the region and resource options to satisfy such demands; - Analysis of existing transmission and distribution systems to be affected, including proposed expansions currently in planning; - Analysis of cost effective transmission system designs, routings and interconnection issues, including phased design and incremental expansion options; - Analysis of overall or phased cost of the transmission system as well as projected cost of future generation options in order to determine delivered cost of new generation to various load centers; and - An economic analysis of the benefits created by the new transmission system in the four affected states.

The Partnership's goal is to have the feasibility report and conceptual plan for implementation completed in approximately 12 months from notice to proceed.

If the Project is determined to be feasible and beneficial in comparison to other resource alternatives available to members of the Partnership by the FLTDA, the Partnership, and state regulators, members of the Partnership would have the option of participating in a second phase of the Project development, which would provide for the development of a financial plan, obtaining all necessary regulatory approvals, obtaining all rights-of-way, and the devclopment of a construction schedule and operational methodology.

To assist us this effort, the Partnership also requested the FLTDA's assistance in the following areas:

- Engage the FERC and/or the appropriatc regulatory body in each state, in conjunction with the Partnership, to work to facilitate consideration of proper recovery of prudently incurred costs associated with the preparation of the feasibility report for the Project and conceptual plan for its implenicntation and to ensure that the costs of developing, constructing and maintaining the Project are properly allocated among the broad range of beneficiaries. - Regularly inform and facilitate prompt reactions from individual state regulatory agencies when callcd upon by the Partnership in order to ensure timely regulatory approvals; and - Be available at least monthly in order to review progress and to provide input as necessary into the process.

In order to participate in the feasibility analysis as proposed to the FLTDA and conduct feasibility studies of other regional transmission alternatives, Sierra and Nevada Power are requesting to spend $600,000 over a 12 month period. Specifically, Nevada Power is requesting $350,000 for regional transmission analysis in this filing. Sierra Pacific is planning to request $250,000 for regional transmission analysis.

REGIONAL TRANSMISSION ORGANIZATIONS (RTO) STATUS

The Federal Energy Regulatory Commission ("FERC') approved the merger of Nevada Power and Sierra in Docket Nos. EC99-1-000 and ER99-34-000. The order issued April 15, 1999 was contingent on the following commitment by the Companies "The Applicants also commit to either joining a regional IS0 or forming an independent Transco within threc years of the consummation of the proposed merger." In the western interconnection of the United States, there are three organizations designed to provide regional transmission (see Figure TP-77). The only operating organization is the California Independent System Operator (CAISO). WestConnect plans to meet only some of the FERC RTO requirements but is regional in scope. The Bonneville Power Administration and some other entities recently announced the intention to form Columbia Grid, a regional organization in the Pacific Northwest.

Nevada Power and Sierra were involved in the development of the now dissolved Grid West to evaluate customer benefits and to meet the FERC merger commitment; Nevada Power requested Commission authorizations to join WestConnect instead of Grid West and was allowed to do so in November 2005. Also in PUCN Docket 02-12005, Sierra was granted permission in March 2006 to join WestConnect and leave Grid West. As of May 1,2006, Nevada Power and Sierra are WestConnect members.

Figure TP-77 Regional Transmission Organizations

Grid West Development Costs

Each of the Grid West filing utilities used internal resources to develop the now dissolved Grid West. Additional joint expenses included cost benefit studies, consultant fees, office space and expenses, secretarial and coordination support. These additional Grid West expenses were funded by all the utilities using a cost allocation method of 50 percent based on number of participants and 50 percent on the net transmission plant investment ratio share. The Grid West costs were structured as a loan to Grid West that was to be repaid aficr the entity was operational and providing a billable service. Grid West was dissolved in May 2006.

As of November 14, 2005, the total amount loaned to Grid West by Nevada Power and Sierra was $1,434,890.51. Figure TP-78 shows a cost breakdown between the Companies.

Figure TP-78 Total Loaned to Grid West

% of Total Allocation Allocation Allocation Net Transmission 50% of Net Trans. 50% of Share Total Nevada Power 62% $444,816.05 $358,722.63 $803,538.68 Sierra 38% $272,629.20 $358,722.63 $631,351.83 Total 100% $71 7,445.25 $71 7,445.26 $1,434,890.51

WESTCONNECT

WestConncct is a group of transmission owners in the Southwest who have joined together under an MOU for thc following purposes:

Continue investigation of feasibility of cost-effective wholesale market enhancements. Pursue required regulatory approvals for enhancements. Work cooperatively with other western grid organizations and market participants. Address issues in appropriate forums (c.g. SSG-WI or successor).

WestCoilnect is run by a Steering Committee made up of representatives of each of the elcven members. Other non-members are invited to attend and participate as non- voting participants. Nevada Power was a non-voting participant until November 2005 when it fornlally joined WestConnect. Figure TP-79 list Nevada Power's (and Sierra's) share of WestConnect.

WestConnect is currently working on thc following projects:

Regional Pricing Proposal Regional Planning Market Monitoring Total Transmission Capability Calculation Standardization Virtual Control Area Investigation New Transn~issionProducts Flow Based Market Investigation History

Transmission Owners began discussions of potential benefits of an IS0 in late 1997. In early 1998 the discussions expanded into a stakeholder discussion process, and the talks coalesced around the idea of creating Desert STAR (Desert Southwest Transmission and Reliability operator). Work groups were formed to flesh out proposals. Nevada Power was actively involved at this stage, and chaired the Governance Work Group. The result of the discussions was the formation of Desert STAR, Inc. as an Arizona not-for-profit corporation. A five-member independent Board of Directors was selected in 1999 to oversee the resulting tariff development. By this time, Nevada Power had merged with Sierra Pacific Resources and began to participate in RTO West (predecessor to Grid West) instead of Desert STAR.

In early 2001, the transmission owners became concerned that the non-profit structure did not provide sufficient incentives for cost savings (in view of CAISO and other IS0 spending around the country) and also wanted to create a FERC Order 2000 compliant entity that could own transmission. The result was the conversion of the proposal from Desert STAR into WestConnect, a proposed for-profit limited liability corporation. Four Transmission Owners ("TOs") filed a Request for a Declaratory Order with the FERC in October 2001 seeking confirmation that an RTO created substantially as described in the filing would be acceptable to FERC. With a few modifications, FERC agreed in October 2002.

At the time of the FERC filing, five TOs executed a MOU for the further development of an RTO contingent upon FERC acceptance of the concept. Two public TOs actively participated, but did not fund these efforts.

In July 2003, FERC issued its Standard Market Design (SMD) proposal and western TOs and publics became concerned with the escalating costs (and minimal perceived benefits) of RTOs, as well as being wary of FERC's apparent desire to force eastern style markets on the whole country and encroach on state jurisdiction over retail service. The result was development of a phased approach to RTO formation in which each phase would pass a cost-benefit screen before the participants continued.

Subsequently, it appeared that the FERC became receptive to regional solutions to the creation of wholesale markets. Coupled with some of the States' reluctance to commit their jurisdictional utilities to full RTO formation immediately, the WestConnect transmission owners began discussing a new focus for their efforts in 2004. Ten TOs (eleven with Nevada Power and Sierra) signed a new MOU in December 2004. The ten TOs signed the MOU and agreed to fund further wholesale market enhancement efforts. They describe themselves as:

WestConnect is a group of southwest transmission-providing utilities that has agreed to work collaboratively to assess stakeholder and market needs and to investigate, analyze and recommend to its Steering Committee implementation of cost-effective enhancements to the western wholesale electricity market. WestConnect is committed to coordinating its work with other regional industry efforts to achieve as much consistency as possiblc in the Western Interconnection. Figure TP-79 Cost to Nevada Power

FORECAST NEVADA POWER SHARE OF ANNUAL COSTS $000

TOTAL WESTCONNECT EXPENSE

NEVADA POWER'S SHARE 52 54 55 57 SIERRA'S SHARE 32 33 34 35 TOTAL 84 87 89 92 (I) Sierra's share has not been adjusted for the partial year.

WestConnect members are billcd based on thc followil~gformula: 50 percent allocated pro rata to all members. Nevada Power and Sierra will be considered one member for this allocation. 50 percent allocated based on each member's percentage share of total MWh delivered to the member's load.

RECENT FEDERAL ENERGY REGULATORY COMMISSION ORDERS AFFECTING NEVADA POWER

Summary of the Impacts of Relevant Orders of the Federal Energy Regulatory Commission Issued Since Last Resource Plan Filing

FERC Order No. 2003 was issued July 24,2003. Orders on rehearing were issued in FERC Order No. 2003-A, March 3,2004; FERC Order No. 2003-B, January 4, 2005; and FERC Order No. 2003-C June 16,2005. This rulemaking amended the FERC's regulations requiring public utilities that own, control or operate facilities for transmitting electric energy in interstate commerce to file revised open access transmission tariffs ("OATT") containing standard generator interconnection procedures and a standard agreement for generators having a capacity of more than 20 MW.

FERC Order No. 2004 was issued November 25, 2003. Orders on rehearing were issued in FERC Order No. 2004-A, April 16, 2004; FERC Order No. 2004-B, August 2, 2004; FERC Order No. 2004-C, December 21, 2004; and FERC Order No. 2004-D, March 23, 2005. This Rulemaking added Part 358 to the FERC's regulations which adopted standards of conduct that apply uniformly to interstate gas pipelines and public utilities. The standards govern the relationships between regulated Transmission Providers and all of their Energy Affiliates. The general principles established by the standards of conduct require (1) all Transmission Provider's employees engaged in transmission system operations to function independently from the employees of its Marketing and Energy Affiliates and (2) Transmission Providers to treat all transmission customers, affiliated and non- affiliated, on a non-discriminatory basis and to not operate its transmission system to preferentially benefit its Marketing or Energy Affiliate.

FERC Order No. 2006 was issued May 12, 2005. FERC Order No. 2006-A on rehearing was issued November 22, 2005. This Rulemaking adopted regulations requiring public utilities that own, control or operate facilities for transmitting electric energy in interstate commerce to amend their open access transmission tariffs to include standard generator interconnection procedures and an agreement for generators having a capacity of no more than 20 MW.

FERC Order No. 661 was issued June 2. 2005. FERC Order No. 661-A on rehearing was issued December 12, 2005. This Rulemaking adopts standard procedures and technical requirements for the interconnection of large wind plants. All public utilities that own, control or operate facilities for transmitting electric energy in interstate commerce are required to append to the Large Generator Interconnection Procedures and Large Generator Interconnection Agreements in their OATT's Appendix G which recognizes the technical differences of wind generating technology and benefits customers by removing unnecessary obstacles to further development of wind generating resources while ensuring reliability is protected.

FERC Order No. 670 was issued January 19, 2006. This Rulemaking implements the new Section 222 of the Federal Power Act prohibiting the employment of manipulative or deceptive devices or contrivances.

FERC Order No. 671 was issued February 3, 2006. An Order on Clarification was issued February 10, 2006. This Rulemaking was required by Section 1253 of the Energy Policy Action of 2005 (EPAct) and Section 210 of the Public Utilities Regulatory Policy Act of 1978 ("PURPA"). It ensures that new qualifying cogeneration facilities are using their thermal output in a productive and beneficial manner; that the electrical, thermal, chemical and mechanical output of new qualifying cogeneration facilities is used fundamentally for industrial, commercial, residential or institutional purposes; and that there is continuing progress in the development of efficient electric energy generating technology. The rule amends Form 556 to reflect the criteria for new qualifying cogeneration facilities; eliminates ownership limitation for qualifying cogeneration and small power production facilities and amends the exemptions available to qualifying facilities from the requirements of the Federal Power Act and the Public Utility Holding Company ("PUHCA").

Order No. 672 was issued February 3,2006. An erratum was issued February 13, 2006. This Rulemaking amends the FERC's regulations to incorporate the requirements of a new Section 215 to the Federal Power Act. It establishes the criteria that an cntity must satisfy to be the Electric Reliability Organization (ERO) which the FERC will certify as the organization that will propose and enforce Reliability Standards for the Bulk Power System in the United States subject to FERC approval. The rule also establishes procedures for new Reliability Standards, procedures for enforcement, criteria for delegation to a Regional Entity and procedures for the establishment of Regional Advisory Bodies that may provide advice to the FERC.

On May 19, 2006, the FERC issued a Notice of Proposed Rulemaking rcgarding Preventing Undue Discrimination and Prefercnce in Transmission Service, Docket Nos. RM05-25 000 and RM05-17-000. Thc NOPR proposes thc following reforms:

o Amend the OATT and Open Access Same-time Information System ("OASIS" regulations to increase transparency in how available transfer capability ("ATC") is calculated.

o Rcquires coordinated, open and transparent transmission planning.

o Pricing reforms for energy and generator imbalance charges, capacity reassignment charges and credit for customer-owned facilities.

o Improvements to point-to-point transmission service,

o Reform of rollover rights.

o Require transmission provider's merchant function and network customers to use the OASIS to requcst dcsignation of a new nctwork rcsource and to terminate a network resource.

o Require all network resources be posted on the OASIS

o Require all business rules, practices and standards relating to transmission service be posted on the OASIS.

o Strcngthen enforcement of the pro forma OATT

o Miscellaneous OATT improvements.

Nevada Power, FERC Docket No. ER05-988-000, is a submittal by Nevada Power of a Long-Term Firm Point-to-Point Transmission Service Agreement ("TSA") between Nevada Power and PacifiCorp. The TSA attempted to restrict PacifiCorp's rollover rights based upon the forecasted load growth of Nevada Power's native load customers. The FERC rejected the restriction of rollover rights in a July 18, 2005 Order Conditionally Accepting Transmission Service Agreement as Modified. Nevada Power filed a request for rehearing which was granted on September 16,2005.

Reliant Energy Wholesale Generation, LLC, FERC Docket No. ER05-1418-000 is a reactive power rate filing by Reliant seeking to charge Nevada Power for Reactive Service. An Order Establishing Prehearing Schedule was issued February 7, 2006. Hearing is scheduled for September 6, 2006. Nevada Power and Reliant Energy engaged in settlement negotiations and filed a settlement with the FERC on May 3 1,2006.

OTHER TRANSMISSION SYSTEM REQUIREMENTS - TRANSMISSION CAPACITY

The Transmission Plan must cover the 20 years covered by the forecast in the supply plan. It must identify the transmission capacity required to serve bundled retail transmission customers, unbundled transmission customers and those customers for whom the utility has an obligation to provide transmission services, for annual and peaking periods throughout the period covered by the resource plan.

Annual Transmission Capacity

Figure TP-80 and Figure TP-81 provide the following annual transmission capacity information in a tabular and chart form:

System Import Transmission Capacity represents the maximum energy that could be transferred into the control area under peak conditions not taking into account econon~icdispatch and is therefore dependent on actual generation patterns. This number also does not take into account generation maintenance or other factors that reduce the system import capacity. The information in this table includes completion of the Centennial Project, the Sunrise Tap in 2010 and the Equestrian Tap in 2014.

Native Load represents import capacity required for external generation, planned generation requiring import rights, new contracts external to the system, planned short-term purchases and the short position requiring import rights. These resources are planned to serve native load.

Colorado River Commission ("CRC"), Southern Nevada Water Authority ("SNWA") and Las Vegas Valley Water District ("LVVWD) peak loads.

PacifiCorp's Firm Point to Point Agreement.

Available Transfer Capability (ATC) represents the difference between the System Import Transmission Capacity and the sum of Native Load, Capacity Benefit Margin (CBM), Transmission Reliability Margin (TRM), CRCISNWA and LVVWD (Unbundled Retail), and PacifiCorp's Firm Point To Point. This table represents all the transmission capacity Nevada Power has secured for its bundled retail transn~issioncustomers on its system. Currently no long-term capacity has been secured on other systems. Therefore this table complies with NAC 704.9385(3)(e) which requires identification of the capacity on "both its transmission system and the transmission systems of othcr companies."

Figures TP-82 and Figure TP-83 provide charts showing "for each year of the 20- year planning period, the excess or required capacity both with and without the additional planned resources" in accordance with NAC 704.945(3).

Annual and Peaking Periods

NAC 704.9385(3)(~)requires transmission capacity information to be provided for annual and peaking periods. Figure TP-84, TP-85, TP-86 and TP-87 provide the transmission capacity information on a monthly basis for thc 36 month Action Plan in a table and in charts.

The System Import Transmission Capacity has been held constant at the maximum peak amount used in thc annual charts. Nevada Power cannot accurately forecast the import capability on a monthly basis. Because the annual peak amount is used in the charts, the resulting ATC amounts cannot be used to dctermine actual available capacity on a monthly basis.

Figure TP-80 Annual Transmission Capacity Information with Additions

NEVADA POWER COMPANY 20 YEAR TRANSMISSION PM

201 2008 2009 2080 2011 2012 2043 1011 10'5 2016 2077 2048 lOlP 2020 21121 2022 2021 2021 2021 201 Figure TP-81: Transmission Capacity with Additions by Year

TRANSMISSION PUNWITH ADDlTlONS (1)

Figure TP-82 Annual Transmission Capacity with Additions

EXCESS OR REQUIRED TRANSMISSION CAPACITY WlTH ADDITIONS (1)

%$+*@*#&@#######&#&#&@#

(1) brsd on Total lmpan capsc8ly On Peak NO, under Economic Dispatch Conditions J~~~~,~~~~~Tranpm,sslonCapaaly i Figure TP-83 Annual Transmission Capacity without Additions

EXCESS OR REQUIRED TRANSMISSION CAPACITY WITHOUT ADDITIONS (1)

Figure TP-84 Monthly Transmission Capacity for Thirty Six (36) Months with Additions

NEVADA POWER COMPANY

7 Decal

Nabye Load 0 1,340 1.030 1.035 TRM BCBhl 347 347 347 7 347 347 347 CRCISWMMN*D S821 I 48 44 37 36 Pac8fiCarp 50 50 50 50 ~va~able~ranrm~rr~oncaparw system lmponTranrm8ssion CapaclQ(l1

08 Mar08 AprO8 8 Oct08 Nov0B Osc08

Nabve Load 36 1028 1057 1073 TRhj & CBM 347 347 347 347 347 347 -347 CRCISNWMW 5821 1 83 67 65 Pac8hCorp 50 50 iiva ~able~ranrm,sr~oncaparlv system lmportTianrm8srlon CapatlQ (1)

Jana8 FebOS Mar49 AprO9 May08 JunO9 Ju109 Aug09 Sep09 Ost08 Nova9 Osc09

Nabue Load 843 835 8E4 880 1581 2049 2672 2269 1850 1390 843 842 TRMBCBM 347 347 347 347 347 547 347 347 547 347 347 347 CRCISWNLWVW 5821 1 60 60 58 81 89 106 114 114 94 86 70 68 PaclflCam 50 50 50 50 50 50 50 50 50 50 50 50 AvalableTranrmrr#onCapar~ 2,688 2696 26" 2631 1921 1437 805 1208 1546 2 116 2678 2681 System Import Tranim8ssion 3988 3988 3988 3988 3988 3988 3988 3988 3988 3988 3988 3988 Capacq (11

(1)Eased onTolal Import Capanty On PeakNofUnder Economc DispafchCondUons Figure TP-85 Monthly Transmission Capacity for 2007 with Additions

NEVADA POWER COMPANY 2007 MONTHLY TRANSMISSION ACTION PLAN (1)

/o~~c~~~aad~TRM~CISNWAILWWD- SBZI~ o~acmcarp m~vaiteb~a Tranrmlrran capaciiyl (1) ~assdon ~otallmport Capscity On Psak NO, uno'er Economic Dispatch Cmdit1on.l Figure TP-86 Monthly Transmission Capacity for 2008 with Additions

2008 MONTHLY TRANSMISSION ACTION PLAN (1)

,89* *8 @* &* *** * ,* +9* ,** &9* ,d" 8 ,." ,."*o*

10~sliveLoad .TRM & CBM OCRUSNWlVLWO -S8211 OPaa6Com .AvsilablsTranrmlulon CswclV /

(I)Based on Total ImportCapacity On Peak NotUndsrEconomis Dispatch Conditionr Figure TP-87 Monthly Transmission Capacity for 2009 with Additions

2009 MONTHLY TRANSMISSIONACTION PLAN (I1

EL!^ .TRM =o~~~~~~~~wo.SB~~~~~L~II~I~ransmi~nun~a

(I)Basod onTotal Impon Capacity On Peak Not Under Economic Oicpatch Condillons