Nevada Power & Sierra Pacific Power d/b/a NV Energy Stakeholders Planning

Input Meeting July 2012 1

1. Welcome – Introductions 2. IRP filing and results Update on Loads and Resources

Renewable Transmission Initiative 3. WestConnect SWAT/SPPG Study Results FERC Order 1000 4. Customer and Stakeholder Input 5. Customer and Stakeholder Planned Projects

(TBD) (Proposed projects) 6. Additional Items 7. Closing Comments

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1. Nevada Power Filed its 2012 Integrated Resource Plan (IRP) covering the period 2013 – 2032 on June 29, 2012

2. The 2012 IRP was designated as Docket 12-06053

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1. ON Line Transmission Project

2. Renewable Transmission Initiative

3. Harry Allen 500/230 kV Transformer

4. WestConnect

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Project was approved by the PUCN in the Nevada Power 2009 IRP Filing and the Sierra 8th Amendment to the 2007 IRP. NVE / LS ON Line Financial closing occurred on 2/11/11

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SCOPE

◦ 235-mile 500 kV transmission line Robinson-Harry Allen

◦ Robinson Summit 500/345 kV substation

◦ Falcon-Gonder Fold

◦ Series compensation on the existing Falcon – Gonder 345 kV line

◦ Harry Allen Terminal

SPPC and NPC Balancing areas will be consolidated post ON- Line

Original ON-Line project scheduled in service December 2012

Wind Induced Vibration Issues –

In early December 2011 high sustained winds damaged several tubular guyed – V towers

Several potential tower modifications are currently undergoing testing

In-service date of the project has been delayed to December 2013

The Harry Allen 500/230 kV transformer is the preferred alternative to provide additional capacity from the 500 kV system to the 230 kV system

Project is preferred over the Sunrise Tap project, Thunderbird 500/230 kV substation, or Northwest 2nd transformer and Northwest – HA Line.

Project would include the following elements:

1. 1,500 MVA 525/230 kV Autotransformer at Harry Allen

2. 300 MVA 230/138 kV Autotransformer at Clark Substation

3. 300 MVA 230/138 kV Autotransformer at Faulkner Substation

NPC is not recommending the installation of the Harry Allen 500/230 kV transformer at this time

Project can be delayed with changes in operating procedures including Crystal PST operation, re-dispatch of Clark generation and Lenzie generation RAS

Need for the project will be driven by:

1. Increases in load growth

2. Replacement of generation inside load pocket with external resources

3. New Transmission Service Agreements

4. Additional external renewable resources delivered

5. into the Las Vegas load pocket.

WestConnect Action Plan Funding 1. The WestConnect Steering Committee is a group of 17

transmission owners in the Southwest who have joined together for the following purposes:

Continue investigation of cost effective transmission enhancements to serve wholesale markets.

Pursue required regulatory approvals for transmission enhancements.

Work cooperatively with other western grid organizations and market participants.

2. NPC has requested PUCN approval of funding for the continued participation in WestConnect.

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1. 500 kV Sunrise Tap Project

2. North Las Vegas VARS Project

3. Brooks 230/138/12 kV Substation

4. McDonald 230/138 kV Transformer

5. Darling 230/12 kV Substation

6. Southeast No. 2, 230/12 kV Substation

7. Northwest Second 500/230 kV transformer

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1. Sierra Pacific filed its 2010 Integrated Resource Plan (IRP) covering the period 2011 – 2030 on July 1, 2010

2. The 2010 IRP was designated as Docket 10-07003

3. The Public Utilities Commission Of Nevada (PUCN) issued its order on the IRP on 12/10/10

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1. Fallon 230 kV Reinforcement

2. Bordertown to Cal Sub 120 kV Line

3. WestConnect Action Plan Funding

4. Blackhawk Project – Request Cancelation

5. Blackhawk – Mira Loma Line – Request Cancelation

6. Blackhawk 345 kV Capacitor – Request Cancelation

7. Plumas – Sierra Interconnection – Request Cancelation

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Fallon 230 kV Reinforcement 1. The Fallon 230 kV reinforcement project original project

scope included a 230 kV transmission line from the existing Salt Wells tap location on the Ft. Churchill – Austin 230 kV line to the new Greenwave substation in Fallon.

2. Project would have interconnected two new geothermal projects and provide additional capacity to Fallon area loads.

3. Scope of the project has been reevaluated due to the cancellation of one geothermal project LGIA and a reduction in the Fallon area load growth.

4. Revised project scope includes construction of Pony Express switching station and acquisition of 230 kV transmission line from Austin-Frontier 230 kV line tap to Pony Express.

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Bordertown to Cal Sub 120 kV Line 1. The project was approved by the PUCN in 2007 and includes

the construction of a 345/120 kV transformer at Bordertown Substation and a new 120 kV line from Bordertown substation to California Substation.

2. Project would provide additional transmission support to the West Reno transmission system for outages of a North Valley Road transformer and N-1-1 outages of the 120 kV transmission system.

3. To date Sierra has not obtained the required permits for this line and permitting work is continuing. The in-service date for this project has been moved from 2012 to 2016.

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Request to Cancel Previously Approved Projects 1. Due to the decrease in the forecast load growth

Sierra requested and received PUCN approval to cancel the following previously approved transmission projects:

Blackhawk Project

Blackhawk – Mira Loma Line

Blackhawk 345 kV Capacitor

Plumas – Sierra Interconnection

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HOT

WEATHER

ENERGY PERCENT PEAK PERCENT PEAK PERCENT

Year (GWH) GROWTH (MW) GROWTH (MW) GROWTH

2011 21,659 5,530

2012 21,816 0.7% 5,557 0.5% 5,792

2013 21,754 -0.3% 5,505 -0.9% 5,738 -0.9%

2014 21,866 0.5% 5,483 -0.4% 5,715 -0.4%

2015 22,147 1.3% 5,529 0.8% 5,763 0.8%

2016 22,577 1.9% 5,603 1.3% 5,840 1.3%

2017 22,850 1.2% 5,679 1.4% 5,919 1.4%

2018 23,171 1.4% 5,757 1.4% 6,001 1.4%

2019 23,486 1.4% 5,833 1.3% 6,080 1.3%

2020 23,900 1.8% 5,918 1.5% 6,169 1.5%

2021 24,215 1.3% 5,999 1.4% 6,253 1.4%

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HOT

WEATHER

ENERGY PERCENT PEAK PERCENT PEAK PERCENT

Year (GWH) GROWTH (MW) GROWTH (MW) GROWTH

2011 8,728 1,513

2012 8,814 1.0% 1,569 3.7% 1,630

2013 8,975 1.8% 1,585 1.0% 1,647 1.0%

2014 9,580 6.7% 1,661 4.8% 1,726 4.8%

2015 9,994 4.3% 1,708 2.8% 1,774 2.8%

2016 9,653 -3.4% 1,680 -1.6% 1,745 -1.6%

2017 9,817 1.7% 1,711 1.8% 1,777 1.8%

2018 9,891 0.8% 1,732 1.2% 1,799 1.2%

2019 10,010 1.2% 1,754 1.3% 1,822 1.3%

2020 10,107 1.0% 1,759 0.3% 1,827 0.3%

2021 10,159 0.5% 1,772 0.7% 1,841 0.7%

2022 10,244 0.8% 1,798 1.5% 1,868 1.5%

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(MW) Date Hour Max Min (MW) Max Min MW % Diff

South 5,761 7/11/2012 5:00 PM 114 91 5,557 112 87 204 3.7%

North 1,618 7/11/2012 5:00 PM 101 65 1,569 101 64 49 3.1%

Note: The air conditioner load management program was not operated in the South on 7/11/2012.

The forecast assumes operation of the system. If operated that day, the peak would have been about

5,680 MW.

Recorded

Daily Temperatures 20-yr average Temps

Forecast

Difference w/ Fcst

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PEAK PERCENT

YEAR (MW) GROWTH

2011 711 2.7%

2012 731 2.7%

2013 749 2.4%

2014 768 2.4%

2015 786 2.3%

2016 804 2.3%

2017 826 2.6%

2018 848 2.6%

2019 865 2.0%

2020 906 4.4%

Combined Loads in Control Area of NPC, Boulder City, CRC-

BMI, City of LV SB211, LVVWD, Lincoln, Overton, East Side /

Newport, SB 211, Valley Electric, City of Henderson

Required by Assembly Bill 387 Process developed under PUCN

Docket 09-07010 Identifies transmission plans and

costs to access RETAAC/PUCN approved renewable energy zones

NV Energy is required to file an RECTP in each triennial Integrated Resource Plan

CREZTP was filed June 29, 2012 in the NPC IRP

This RECTP integrates ON Line, RETAAC/PUCN, Western SOI, SWAT and SSPG work into comprehensive design.

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◦ The CREZTP is a conceptual plan to provide the transmission required to interconnect each of the renewable energy zones forecast by RETAAC. Elements of the plan include:

◦ Construct the ON Line Project

◦ Permit Harry Allen – Northwest and Northwest – Amargosa 500 kV lines.

◦ Permit Harry Allen – Eldorado 500 kV line.

◦ Future elements could include construction of the West Side Tieline and required collector lines.

◦ Estimated cost of the RECTP is $4.3 billion.

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Transmission proposed from four Points of Receipt (1-4) to three Points of Delivery (A-C)

~ 600 miles of potential EHV lines.

Significant response on Sept. 16th, 2011

Study agreements sent Nov. 1st, 2011

Agreements due by Dec. 15th, 2011

Studies completed and given to participants April 27, 2012

Permitting and construction costs estimated have been completed

RTI process has been concluded. Customer commitments were insufficient to fund Phase 2

2011 TEPPC / TAS Study Request

2011 TEPPC / TAS/SWG status

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2012 Study Request

2012-2021 Projects

Three studies are being requested in response to requests from the Nevada Energy Assistance Corporation - a SSPG stakeholder. The studies requested are as follows:

1. A new 345/230 kV 1000 MW tie line from Northern Nevada to Northern

California. This study is similar to last year’s SSPG request but the resource mix and topology for this study differs from the 2011 request.

2. A new 500 kV tie line for 750 – 1000 MW delivered from Northern Nevada into Southern California via a new line paralleling the existing Pacific DC line.

3. A new 345 kV tie line for 600 MW delivered from Northern Nevada into Southern California via a new line to the IPP DC line in Utah.

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High capacity factor of N. NV Geothermal energy No need for “following” resources Short distance from California Potential expedited in-service date The SSPG expects these projects will be highly

competitive with other projects included in the TEPPC 2010 Study Report and 2011-12 study programs.

Expected Completion by TEPPC Q4 2013

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Eastern terminus

of LMUD

Interconnection

from 2011 SSPG

Study Project constructed at 345 kV

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Project constructed at 500 kV

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Project constructed at 345 or 500 kV

Arizona Public Service

El Paso Electric

Imperial Irrigation District

NV Energy

Public Service Company of New Mexico

Salt River Project

Southwest Transmission Cooperative

Tucson Electric Power Company

Tri-State Generation & Transmission

Western Area Power Administration – Desert Southwest

Ten year plans are under development

Project names, dates, and routes are still subject to change from information presented today

Only high-level summary information is presented.

Please contact utilities directly for more information

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SWAT Transmission Projects Updated 9/14/11

TransmissionMW Proposed Proposed Type of SWAT

Project Name NOTES # ckts Voltage Capacity Length in-service Status ConstructionSubcommitteeSponsor

ON Line (One Nevada Transmission Line)-Stage I 1 500kV 600-2000 235 2012 in construction NC SSPG/EVSG NV Energy/Great Basin Transmission

SWIP/ON Line-Stage II (Southwest Intertie Project) 1 500kV 2000 60 2014 in development NC EVSG NV Energy/Great Basin Transmission

West Side Tie 1 500kV 2000 476 2018 in permitting NC SSPG/EVSG NV Energy

NV Energy Self Build Robinson - Harry Allen 500 kV Line 1 500kV 2000 236 2015 permitted NC EVSG NV Energy

RTI Westside Tie 345 kV (Armagosa-Esmeralda-Tracy) 1 345kV 800 141 2015 In permitting NC SSPG NV Energy

TCP Amargosa-Black Hawk REMOVE - DUPLICATION OF "WEST SIDE TIE" 1 500kV 2000 268 2015 In permitting NC SSPG NV Energy

RTI Zone 4 to Harry Allen 1 500kV 2000 40 2014 In permitting NC EVSG NV Energy

Bighorn-Eldorado 1 500kV 2000 24 2015 In permitting NC EVSG NV Energy

TCP (Transmission Corridor Project, Northwest - Amargosa Collector Sub) 1 500kV 2000 75 2015 In permitting NC EVSG NV Energy

TCP (Transmission Corridor Project, Northwest - Harry Allen) 1 500kV 2000 31 2015 In permitting NC EVSG NV Energy

TCP (Transmission Corridor Project, Harry Allen - Eldorado) 1 500kV 3000 55 2015 In permitting NC EVSG NV Energy

NVE Request to WECC Planning Coordination Committee and Technical Studies Subcommittee

1) Cancel and remove from the three Phase Rating Process the ON Line rating (currently in Phase II) submitted by NV Energy

2) Initiate a new expedited review process and create a PCRG for the purpose of modifying the existing Path # 81 (“Centennial”) rating to comprise the existing southern Nevada interface between NVES and the Eldorado Valley.

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Figure 1: ON Line versus major WECC Paths

Cry-HA

(#77)

TOT 2B

(#78/79)

PGE-SPP

(#24)

ALTURAS

(#76)

CENT/S.

CUTPLANE

ON Line

RB-HA

(#35)

IN/PAV-

GON (#32)

ID-SPP

(#16)

MDW-

LBNS

(#15)

COI

(#66)

ID-NW

(#14)

NW

(BPA)

UTAH

(PAC)

NPC

ID

(IPC)

CA/AZ

(SCE/LA/WAPA/APS)

CA

(PG&E) SPPC

“C”

(#20)

Requires transmission planning at the regional level to consider and evaluate possible transmission alternatives and produce a regional plan

Requires the cost of transmission solutions chosen to meet regional transmission needs to be allocated fairly to beneficiaries.

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Public utility transmission providers are required to participate in a regional transmission planning process that satisfies Order No. 890 principles and produces a regional transmission plan.

Local and regional transmission planning processes must consider transmission needs driven by public policy requirements established by state or federal laws or regulations.

Public utility transmission providers in each pair of neighboring transmission planning regions must coordinate to determine if more efficient or cost effective solutions are available.

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Each transmission planning region must produce a regional transmission plan reflecting solutions that meet the region’s needs more efficiently or cost effectively.

Stakeholders must have an opportunity to participate in identifying and evaluating potential solutions to regional needs.

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Regional transmission planning process must have a regional cost allocation method for a new transmission facility selected in the regional transmission plan for purposes of cost allocation. Cost allocation method must satisfy six cost allocation principles.

Neighboring transmission planning regions must have a common interregional cost allocation method for a new interregional transmission facility that the regions select. Cost allocation method must satisfy six similar interregional cost allocation principles.

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Participant funding of new transmission facilities is permitted, but is not allowed as the regional or interregional cost allocation method.

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◦ Cost allocation method must meet six principles (PP

585-705) :

Costs allocated “roughly commensurate” with benefits

No involuntary cost allocation to non-beneficiaries

If benefit-cost ratio is used, must not be so high to exclude

facilities with significant net benefits (can’t exceed 1.25-1 unless

FERC approves higher ratio)

Costs allocated solely within region or regions unless those

outside voluntarily assume costs

Method and data requirements must be transparent

Different method may be chosen for different types of facilities (

e.g., reliability, congestion relief, public policy)

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◦ Bottoms up-top down process. The bottoms-up incorporates a roll-up of local TO plan (local projects) and a WestConnect reliability assessment of TO plans. The bottoms-up would be in combination with a top-down approach which utilizes the WECC TEPPC scenario analysis and incorporating a WestConnect verification and project-by-project analysis based on the WECC Board approved TEPPC results to identify regional

efficient and cost effective solutions.

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Calculation of reliability benefits will be based on required compliance with NERC TPL transmission planning standards.

If a system is compliant with NERC TPL standards during the 10 year planning horizon they will not be allocated costs for reliability improvements.

Individual TOs have the ultimate responsibility to ensure the reliability of their systems. Local plans submitted by each TO should be compliant with NERC TPL standards. Therefore, the local TO will have the ability to approve or deny changes to local reliability projects.

If a TO agrees to replace a local project with a regional project that is more efficient and cost effective calculation of benefits and allocation of costs will be based on the cost of alternatives to comply with the standards.

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Calculation of Economic Benefits will be based on regional production cost savings.

Hurdle rate should be calculated to ensure that, on a bilateral basis, the transactions modeled are likely to occur (including transmission rates, losses, and an adequate margin).

Production cost analysis will need to calculate benefits for each company.

WestConnect will establish a B/C ratio of 1.25 for a project to be considered economically-justified and receive cost allocation.

Cost of economic projects will be allocated based on the benefits that each Company receives.

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Public Policy Requirements will be included in the evaluation of reliability and economic projects, if applicable.

Legislated Public Policy Requirements shall be included in the system models used for the transmission system studies. The impact of potential future public policy requirements may be evaluated through scenario analysis.

The costs of projects required to satisfy the public policy requirements shall be allocated to the entities that will access the resources enabled by the project in order to meet their public policy requirements

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In developing the most efficient plan for the region, it is possible for the plan to jointly consider different types of benefits when approving projects for inclusion in the regional plan.

A transmission system addition may result in multiply categories of benefits; Reliability & Economic Benefits, Reliability & Public Policy Benefits, Economic & Public Policy Benefits or Reliability, Economic & Public Policy Benefits.

Under the WestConnect cost allocation procedure all categories of benefits shall be considered.

The total project benefit shall be the sum of the benefits from each benefit category.

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Customer and Stakeholder Input on Transmission Study Plan

Customer and Stakeholder Proposals for Transmission Study Plan

Customer and Stakeholder Planned Projects

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