Benefits of Nevada West Connect Preferred Renewables Option · 2017. 6. 27. · Executive Summary...

Benefits of Nevada West Connect – Preferred Renewables Option

June 2017

Prepared for

GridLiance GP, LLC

Prepared by:

ICF

Nevada West Connect Benefits Study

ICF study compared generation cost, transmission cost, and production cost benefits of NWC to TWE and SunZia

The study shows that NWC is the lowest cost option to deliver out of state renewable generation to California

NWC has the advantage of being the only project that is wholly in CAISO, and also the only one that enables a balanced portfolio

6/27/2017 2

Nevada West Connect (NWC) is shown to be a lower cost option to firmly deliver out of state renewables to

Southern California than projects such as Transwest Express (TWE) and SunZia transmission projects

INTRODUCTION

SunZiaTransWest ExpressNevada West Connect

Executive Summary – Shorter Distance Saves Money

Gridliance commissioned ICF to conduct a research study comparing three transmission projects: NWC, TWE and SunZia.

All three projects are assumed to obtain transmission capability to deliver directly into California (SP15) as RPS Category 1 resources

6/27/2017 3

NWC is the low cost way to deliver out of state renewables to Southern California, and costs much less than TWE

and SunZia because it is closer to California

INTRODUCTION

Note: Additional transmission capacity required for deliverability into California are assumed to be

(1) the 500 kV line from Inyo to Antelope Valley for NWC; (2) a new 500 kV line from Eldorado to

Lugo for TWE; and (3) incremental transmission capacity from Pinal Central to Devers for SunZia.

Project

Name

Total Capital

Costs

($ million)

Renewable

Capacity

Enabled

(MW)

Renewable

Generation

(million MWh)

Capital Cost

($/MWh)1

NWC 1,327 1,000 3.0 36

TWE 5,000 1,500 2 5.9 68

SunZia 3,656 2,000 6.8 43

• Shorter distances lead to lower capital costs for NWC

compared to TWE and SunZia

Shorter Distances = Lower Capital Costs

NWC – 500 miles (350 miles in western Nevada; 150 miles from Inyo to SP15)

TWE – 880 miles – (730 miles HVDC from Wyoming to Eldorado, NV; 150 miles

AC from Eldorado to SP15)

SunZia – 875 miles – (515 miles from New Mexico to Phoenix, AZ; 360 miles

from Phoenix to SP15)

Lower Capital Costs – 59% Lower per MWh of Renewables

1 ICF used an 8% annualization rate (CCR) and 40 year amortization schedule2 TWE is expected to deliver an initial capacity of 1,500 MW of wind generation in an initial

phase, increasing to 3,000 MW. For this study, ICF modeled 1,500 MW and normalized costs

and benefits

Executive Summary – Lower Transmission Costs and Attractive Mix of Renewables Gives NWC the Edge

NWC’s 75% solar and 25% wind generation mix is modestly more costly than TWE and SunZia wind generation, but NWC’s total costs are still much

lower due to much lower transmission costs.

6/27/2017 4

NWC renewables are attractive, represent a diversified mix and have only modestly higher all-in costs.

GENERATION AND TRANMISSION COSTS LOWEST FOR NWC

• Cost of NWC’s generation mix is at a modest premium,

but overall NWC has a large cost advantage due to much

lower transmission cost.

NWC Enables Diversified Mix of Resources

Scenario Generation

($/MWh)

Transmission

($/MWh)

Total ($/MWh)

(relative to NWC)

NWC 43.8 35.5 79.4

TWE 36.7 67.9 104.6 (+25)

SunZia 46.6 43.0 89.6(+10)

Project Solar

Capacity

(MW)

Wind

Capacity

(MW)

Total

Renewable

Generation

Capacity

(MW)

Average

Capacity

Factor

(%)

Annual

Renewable

Energy

(TWh)

NWC 750 250 1,000 34 3.0

TWE 0 1,500 1,500 45 5.9

SunZia 0 2,000 2,000 39 6.8

Note: Average capacity factor for NWC is 34%. This is the weighted average capacity factor for 750 MW

of solar at 33% capacity factor and 250 MW of wind at 38%.

• NWC enhances fuel mix as the only option that enables a

balanced portfolio – solar, wind and geothermal resources

NWC Total Cost is Approximately 1/3 Lower

Executive Summary – Renewables Lower Use of Fossil Fueled Plants –Accounting for these Savings Confirms NWC’s Edge as Least Cost Line

NWC 75% solar and 25% wind is modestly more costly from generation, lower total costs due to lower transmission.

6/27/2017 5

ICF modelled WECC grid operations, to calculate the decrease utilization of other generation and associated cost savings from

decreased operation of fossil fuelled power plants.ALL IN NET COSTS LOWEST FOR NWC

• All renewables decrease usage of other power plants, with a

modest advantage to TWE and SunZia, but not enough to

offset higher costs.

Detailed Grid Modelling of transmission and Generation in the western

US Power Grid

Project Project Costs –

Transmission and

Generation

($/MWh)

Production Cost

Savings

($/MWh)

Net Costs –

Project Costs

less Production

Cost Savings

($/MWh)

NWC +79.4 -38.4 41.0

TWE +104.6 -44.6 60.0 (+19.0)

Sunzia +89.6 -42.1 47.5 (+6.5)

NWC has the Lowest Net Costs by Nearly Half

• Modeling accounts for different daily and

seasonal patterns of renewables.

• Modeling accounts for each generator and

transmission line

Qualitative Considerations Reinforce Economics – NWC is Preferred

6/27/2017 6

NWC will be relatively easy to implement and less risky.

NWC Qualitative Advantages

Transmission lead times can be very long, and lead time could be

especially important if the federal incentives for renewables expire

before the projects come on line

Possible Less

Lead Time and

Federal Incentive

Risk

All CAISO Project

Entirely within the CAISO system footprint; simplifies planning, siting

(fewer states), permitting, allocation of costs, recognition of benefits

Fewer States

NWC is entirely within two states while the other projects involve

more states simplifies planning, siting (fewer states), permitting

More Diverse Mix

Solar and wind compared to only wind for other projects, and can

also enable geothermal

NWC may be easier to implement because it is shorter than the

other two with potentially significantly easier siting permitting and

cost allocation

Shorter

Distance/Easier

Implementation

Incentives of Resource Required to Participate in the EM

Also, in general, renewable projects grandfathering status - i.e. the

ability to be under construction over 4 years, and still qualify for the PTC

or ITC level available as of the start of construction - hinges on Internal

Revenue Service (IRS) rulings, not explicit statutory language; avoids

the albeit small risk of loss of grandfathering status

Potentially Less

Grandfathering

Risk

First Non

California CAISO

Member

NWC represents the first major renewables project with VEA, the only

non-California entity to join CAISO (VEA joined CAISO in 2013).

Therefore, it positively reinforces integration and the goal of California

that its ISO have economies of scale

Added Looping-

Potential

Geothermal

NWC also strengthens the California grid on the eastern side of the

Sierra Nevada, and has the optionality of facilitating access to

geothermal and other resources in this area. In contrast, the other two

projects originate in non-CAISO and entirely in non-ISO/RTO regions

NWC delivers mostly solar power, and hence, there is a longer “runway”

for the ITC than the PTCSolar ITC

Schedule More

Robust

Quantitative and Qualitative Assessment of Nevada West Connect (NWC) Transmission Project

June 27, 2017

Submitted to:

GridLiance GP, LLC

Chicago, IL

Submitted by:

ICF Resources, LLC

Fairfax, VA

ICF proprietary and confidential. Do not copy, distribute, or disclose.

GridLiance GP, LLC – Assessment of NWC

Use or disclosure of data contained on this sheet is subject to the restrictions on the title page of this report. 2

Table of Contents

List of Exhibits ........................................................................................................................................................ 3

List of Acronyms ....................................................................................................................................................... 4

1. Introduction and Executive Summary ................................................................................................................. 5

1.1 Introduction ............................................................................................................................................. 5

1.2 Summary of Conclusions – Quantitative Assessment of the Projects ..................................................... 6

1.3 Summary of Conclusions – Qualitative Assessment of the Projects ........................................................ 8

2. Introduction and Project Background ................................................................................................................. 9

2.1 Project Background .................................................................................................................................. 9

2.2 Nevada West Connect (NWC) Project – Background ............................................................................... 9

2.3 Other Comparative Transmission Projects Assessed ............................................................................. 10

2.4 CAISO - Background ............................................................................................................................... 11

2.5 Valley Electric Association (VEA) - Background ..................................................................................... 12

3. Recent CAISO Power Market Developments .................................................................................................... 13

. Key Modeling Assumptions ............................................................................................................................... 21

4.1 Peak Demand and Energy Growth for California ................................................................................... 21

4.2 Gross Peak Demand and Energy Growth for California Zones .............................................................. 22

4.3 Gas Prices ............................................................................................................................................... 23

4.4 Firm Generator Builds ............................................................................................................................ 24

4.5 Recent and firm retirements ................................................................................................................. 25

4.6 Environmental Assumptions .................................................................................................................. 25

4.7 Project Assumptions for the three alternatives ..................................................................................... 26

4.8 Capital Charge Rate Assumptions .......................................................................................................... 28

4.9 Additional Project Description and Characteristics ............................................................................... 29

5. Modeling Approach and Results ....................................................................................................................... 32

5.1 Modeling Approach ............................................................................................................................... 32

5.2 Production Cost Savings......................................................................................................................... 32

5.3 Wholesale Consumer Cost Savings ........................................................................................................ 34

5.4 Key Production Cost Savings Metric ...................................................................................................... 35

5.5 Transmission Costs – Capital Costs and Project Capacity ...................................................................... 35

5.6 Generation Costs of Renewables ........................................................................................................... 36

5.7 Generation costs of Renewables under Sensitivity cases ...................................................................... 38

5.8 Total Gross Costs ................................................................................................................................... 39

5.9 Production Cost Savings......................................................................................................................... 40

5.10 Net Costs of the Three Alternatives .................................................................................................. 40

6. Qualitative Considerations for comparative assessment ................................................................................. 42

7. Conclusions ....................................................................................................................................................... 43

7.1 Summary ................................................................................................................................................ 43

7.2 Quantitative Considerations .................................................................................................................. 43

7.3 Qualitative Considerations .................................................................................................................... 45



List of Exhibits

Exhibit 1 Map of transmission projects assessed (NWC, TWE and SunZia) ................................................................... 6

Exhibit 2 Net Costs Summary for the Three Scenarios .................................................................................................. 7

Exhibit 3 Valley Electric Association’s 230kV Transmission System .............................................................................. 9

Exhibit 4 Map of proposed Nevada West Connect (NWC) Transmission Line ............................................................ 10

Exhibit 5 Map of utilities in California (Left) and zones within CAISO (Right) ............................................................. 12

Exhibit 6 TAFAs and Intertie Potential Resource Additions ......................................................................................... 13

Exhibit 7 California’s Resource Adequacy Mechanism ................................................................................................ 17

Exhibit 8 IRP Framework for California ........................................................................................................................ 19

Exhibit 9 Gross and Peak Demand projections for California ...................................................................................... 21

Exhibit 10 Net Peak (MW) and Energy Demand (GWh) for California Sub-Regions (CAISO Zones) ............................ 22

Exhibit 11 Net Peak (MW) and Energy Demand (GWh) for California Sub-Regions (Non-CAISO Regions) ................. 23

Exhibit 12 Delivered Natural Gas Price Assumptions .................................................................................................. 24

Exhibit 13 Firm Builds by Technology Type in California ............................................................................................. 25

Exhibit 14 Recent and Firm Retirements in California ................................................................................................. 25

Exhibit 15 California AB32/SB32 Allowance Price for CO2 and Import Charges Schedule .......................................... 26

Exhibit 16 Assumptions for Supply Resources in the Three Scenarios ........................................................................ 27

Exhibit 17 Assumptions for Transmission Projects in the Three Scenarios ................................................................. 28

Exhibit 18 Capital Charge Rate Assumptions for Transmission and Generator Assets ................................................ 28

Exhibit 19 Selected Project Characteristics ................................................................................................................. 29

Exhibit 20 Current Federal PTC and ITC Schedules ...................................................................................................... 30

Exhibit 21 Approximate Route Distances for the Three Projects ................................................................................ 30

Exhibit 22 Consumer Cost Savings for the Projects ..................................................................................................... 34

Exhibit 23 Adjusted Production Cost Savings .............................................................................................................. 35

Exhibit 24 Transmission Capital Costs Comparison for the Three Scenarios ............................................................... 36

Exhibit 25 Generation Capacity Factors and Renewable Generation per 1000 MW ................................................... 37

Exhibit 26 Generation Costs for Wind at Full PTC and Solar at Full ITC ....................................................................... 37

Exhibit 27 Generation Costs for Wind at 80% PTC and Solar at 100% ITC ................................................................... 38

Exhibit 28 Generation Costs for Wind at 80% PTC and Solar at 100% ITC ................................................................... 38

Exhibit 29 Sensitivity Case - Wind Generation Costs at Full PTC and 50% Capacity Factor ........................................ 39

Exhibit 30 Total Gross Costs – Base Case ..................................................................................................................... 39

Exhibit 31 Total Costs – Sensitivity Case with Wyoming Wind at 50% Capacity Factor .............................................. 39

Exhibit 32 Normalized Annual APC Savings ................................................................................................................ 40

Exhibit 33 Net Cost Comparison for the Three Scenarios ............................................................................................ 41

Exhibit 34 ICF Analyzed Three Projects ........................................................................................................................ 43

Exhibit 35 Capital Costs Comparison of the Three Projects......................................................................................... 43

Exhibit 36 Renewable Mix Enabled for the Three Projects ......................................................................................... 44

Exhibit 37 Total Costs Comparison for the Three Projects .......................................................................................... 44

Exhibit 38 Net Costs Comparison for the Three Projects ............................................................................................ 44

Exhibit 39 Qualitative Advantages of NWC Project ..................................................................................................... 45



List of Acronyms

APC Adjusted Production Costs

CAISO California Independent System Operator

CCR Capital Charge Rate

CEC California Energy Commission

CPUC California Public Utilities Commission

CSL Cost-to-Serve Load

EIM Energy Imbalance Market

GW Gigawatt

HVDC High Voltage Direct Current

ITC Investment Tax Credit

LADWP Los Angeles Department of Water & Power

LNG Liquefied Natural Gas

LTPP Long-Term Procurement Plan

MW Megawatt

MWh Megawatt Hour

NWC Nevada West Connect

NEAC Nevada Energy Assistance Corporation

NREL National Renewable Energy Laboratory

PTC Production Tax Credit

RA Resource Adequacy

RPS Renewable Portfolio Standards

TAFA Transmission Assessment Areas

TPC Total Production Cost

TWE TransWest Express

TWh Terawatt Hour

VEA Valley Electric Association



1. Introduction and Executive Summary

1.1 Introduction

GridLiance GP, LLC (GridLiance) engaged ICF Resources, LLC (ICF) to analyze three electricity transmission

projects proposed to deliver generation from out of state renewable resources into southern California.

The projects have been proposed to help meet California’s need for renewable resources. It is estimated

that meeting California’s 50% Renewable Portfolio Standard (RPS) requirement by 2030 would entail

nearly $5 billion or more in transmission upgrades. Also, a recent California Energy Commission report

determined that California would require an additional 25 to 108 TWh of renewables annually to meet its

50% RPS mandate.1 This would translate into 7 to 31 GW of new capacity, assuming a 40% average

capacity factor or 9 GW to 41 GW assuming a 30% capacity factor. Options to meet California’s renewable

needs using resources from as far away as Wyoming, combined with transmission projects such as the

TWE Express transmission project (TWE), and from New Mexico combined with the SunZia transmission

project (SunZia) have received some examination. In contrast, the potential for resources in close

proximity, such as those in neighboring Nevada enabled by the Nevada West Connect (NWC) project have

not be examined as closely.

ICF assessed the cost effectiveness of renewable generation enabled by NWC relative to that of TWE and

SunZia. The study determines the production cost savings to customers in California, based on a nodal

production cost analysis of the WECC region conducted using the PROMOD model. ICF compared

production cost benefits to the cost to develop the renewable resources as well as the transmission

infrastructure to ensure firm deliverability into California. Other factors were assessed qualitatively.

The three projects, as specified in the study, were (See Exhibit 1 for map of three projects):

Nevada West Connect (NWC) – NWC delivers 1,000 MW of renewables, primarily solar (750 MW)

and secondarily wind (250 MW), from the Valley Electric Association system (VEA) in

southwestern Nevada to southern California (SP15 region). VEA’s territory is contiguous with

California and since 2013 is the only part of the California ISO (“CAISO”) system outside the state

of California2. NWC would connect to SP15 through the proposed 500kV Inyo to Antelope Valley

transmission project, a portion of the proposed Nevada Energy Assistance Corporation (NEAC)

South project. NEAC South connects the east side of the Sierra Nevada Range into SP15.

TransWest Express (TWE) – TWE delivers 1,500 MW3 of wind power from plants in Southern

Wyoming to the Eldorado substation near Las Vegas, Nevada. The transmission line is a long High-

Voltage Direct Current (HVDC) line terminating at Eldorado substation, Nevada. Additional

transmission upgrades would be required to allow the power to be delivered into California.

Sunzia - The project gathers 2,000 MW of wind power in New Mexico and transmits it to Pinal

Central near Phoenix, Arizona. Additional transmission would be needed to deliver firmly to

1 See http://docketpublic.energy.ca.gov/PublicDocuments/15-RETI 02/TN214168_20161025T091645_Transmission_Capability_and_Requirements_Report.pdf 2 Other parts of the WECC participate in CAISO’s EIM, but are not full members of CAISO – e.g. separate planning, cost

allocation, day ahead unit commitment, governance, etc. 3 TWE is a 3000 MW HVDC connecting Southern Wyoming to Eldorado, NV. The project is expected to be implemented in two phases, with 1500 MW coming online in the first phase (by 2021) and the other 1500 MW in the second phase. For the purposes of the study ICF modeled a 1,500 MW injection in line with the first phase, and normalized the results.

http://docketpublic.energy.ca.gov/PublicDocuments/15-RETI



California. For example, two routes were considered: Phoenix to SP-15 (e.g. Lugo substation) via

Eldorado and then to SP-15 and Phoenix via Palo Verde and then further west to SP15. This project

has the most uncertainty regarding the costs of firm delivery into California.

Exhibit 1 Map of transmission projects assessed (NWC, TWE and SunZia)

Source: Generated by ICF using SNL. Additional transmission upgrades to California SP-15 are shown as dashed

lines.

1.2 Summary of Conclusions – Quantitative Assessment of the Projects

ICF adopted a net cost approach to compare the three scenarios. The benefits of the projects are

measured in terms of production cost savings relative to a Base Case without the transmission projects.

The project costs are calculated based on information furnished by GridLiance, ICF internal market

assumptions, and information from other publicly available sources. In order to compare the project on a

normalized basis, the costs and benefits are computed on a megawatt-hour (MWh) delivered basis. The

difference between the project costs and savings/benefits on an MWh basis is the net costs per MWh.

Based on the results of ICF’s quantitative assessment of the three scenarios, NWC is the most cost

effective project per MWh at $41.0/MWh without factoring in any benefits from applicable state

renewable energy credits (RECs). The $41.0/MWh cost is the total cost of generation plants and

transmission to deliver into California, net of production cost savings. TWE costs $19.0/MWh or 47% more

than NWC, and Sunzia is $6.5/MWh or 15% more.4

4 The economic test is least net present value of discounted cash flow (DCF). However, in this case, the levelized cost per MWh

matches very closely the full DCF because the time pattern of costs and benefits are very similar across the projects. We present the $/MWh to facilitate exposition.



Exhibit 2 Net Costs Summary for the Three Scenarios

Project Transmission and Generation Costs

($/MWh)

Average Production Cost Savings

($/MWh)1

Net Costs ($/MWh)2

Increase over NWC

($/MWh)

NWC 79.4 38.4 41.0 N/A

TWE 104.6 44.6 60.1 19.0 (+47%)

Sunzia (assumed to sink in California)3

89.6 42.1 47.5 6.5 (+15%)

1 Production cost savings is a benefit to consumers. It is the reduction in the cost of producing electricity due to the resources

enabled by the transmission projects.

2 Net cost is calculated as the difference between the project transmission and generation cost and the production cost savings.

It does not include REC revenue. See discussion. 3 SunZia terminates at the Pinal Central substation in Arizona. For the purposes of the analysis it is assumed to obtain incremental capacity to provide deliverability into California

NWC costs much less than TWE and Sunzia because the transmission costs are much lower, and greatly

offsets the moderately lower generation costs and higher production cost savings of TWE and Sunzia.

Transmission – NWC costs approximately $1.3 billion for the transmission. In contrast, TWE and

SunZia cost $3.7 billion to $5.0 billion.5 Put another way, the transmission capital costs of TWE

and SunZia are approximately 2.8 to 3.8 times higher than NWC’s. The levelized 6 cost of

transmission is $35.5/MWh for NWC, $67.9/MWh for TWE and $43.0/MWh for SunZia. This

implies that TWE and SunZia have approximately 1.2 to 1.9 times the levelized cost of NWC. TWE

and Sunzia deliver more power than NWC. Therefore, the cost premiums of these projects on a

per MWh basis are smaller than the capital cost premium due to economies of scale in power

delivery, but the costs are still much higher. There is significant additional uncertainty in

transmission costs because ICF did not find explicit estimates from TWE and SunZia on the cost of

transmission that would ensure deliverability into California. In order to breakeven with NWC,

Sunzia transmission costs would have to decrease by $480 million or 13%, and TWE costs would

have to decrease by $1.7 billion (or 28%).

Renewable Power Generation – The average generation cost of NWC is $43.9/MWh net of full

federal Production and Investment Tax Credits (PTC for wind projects will be at maximum level if

construction starts in 2016 and ITC for solar if construction starts by end of 2019)7. NWC’s

generation cost is almost $12/MWh higher than TWE. This is primarily because the wind

resources in Wyoming have a much higher capacity factor than renewable resources in Nevada.

However, the generation cost advantage of TWE is small compared to NWC’s $32/MWh

transmission cost advantage. Although the capacity factor of New Mexico wind resources is also

higher than that of Nevada renewable generation, NWC has a lower cost than SunZia because

5 While capital costs are by far the largest component of transmission costs, there are others including annual O&M and losses. In this case, these correlate with capital costs and do not greatly affect the relative costs. They are accounted for in the detailed DCF analysis. 6 Levelized means annuitized to have the same present value. 7 The cost analysis accounts for the large economies of scale in central station renewable generation, but no storage is considered at the project sites.



Nevada solar capital costs are lower than that of New Mexico wind. As a result, NWC generation

is $3/MWh lower than that of SunZia. In addition, NWC transmission has a $7/MWh advantage

over SunZia.

Production Cost Savings – TWE and Sunzia have production cost savings advantages of

approximately $6/MWh and $4/MWh, respectively. While solar generation coincides with

traditional on-peak wholesale power conditions, seasonally and diurnally, and incremental

generation costs are traditionally higher on-peak than off peak, in the period examined, large solar

output from other sources partially mitigates this advantage. However, the production cost

savings advantage is also small compared to the transmission cost advantage.

1.3 Summary of Conclusions – Qualitative Assessment of the Projects

There are also qualitative considerations favoring NWC project. They are summarized below:

NWC may be easier to implement because of the much shorter distance, lower capital costs, and

fewer states involved compared to the other two projects.

NWC also has the advantage that it is entirely within the CAISO system, and hence, similar to other

transmission projects pursued by CAISO as opposed to inter-regional projects, which are more

complicated in terms of planning and execution.

NWC (without the interconnecting NEAC South segment) is located on the less populated border

regions between Nevada and California. Hence regulatory approvals, acquisition of project right-

of-ways and construction of transmission line should be easier and cost-effective.

To the extent the project is easier to implement and faces less risks of delay, this might be

important in terms of accessing available federal renewables (like PTCs and ITCs) incentives before

they expire. NWC delivers mostly solar power, and hence, there is a longer “runway” for its

federal renewable incentives, the ITC, than for that of TWE and SunZia, the PTC. The availability

of the full PTC expires by the end of 2019. The ITC is almost at full value for projects qualifying for

2020 vintage ITC, and never goes to zero under current legislation. In contrast, the PTC value is

zero for projects qualifying with the vintage year of 2020 or later. This issue is complicated, as

discussed below, because of grandfathering of projects based on start of construction, and other

factors. As noted above, this is not reflected in our quantitative analysis, which assumes all

renewables receive full value of the federal incentives.

NWC has a mix of renewables and is less susceptible to factors that might affect the economics of

one or the other.



2. Introduction and Project Background

2.1 Project Background

In September 2016, GridLiance HoldCo entered into an agreement with Valley Electric Association (VEA)

to purchase and own Valley Electric’s transmission assets.8 The assets purchased included 160 miles of

230kV transmission lines belonging to Valley Electric. The transmission system of Valley Electric were

placed under the operational control of California ISO (CAISO) in 2013. The CAISO approved the asset

purchase in December 2016, and the sale is expected to close in the first quarter of 2017.9 The transaction

is currently under review by FERC and yet to be approved. 10 The proposed NWC project when

implemented is expected to bring renewable power from Nevada into CAISO system.

GridLiance intends to extend Valley Electric Association’s (VEA) transmission network to areas in Nevada

and California with renewable resources that are currently difficult to access due to limited transmission

capability, but which would be cost-effective in meeting the state’s renewable goals. Specifically,

GridLiance would develop the 230 kV Nevada West Connect (NWC) line, which would connect Valley

Electric’s existing network to the Inyo substation in California (see Exhibit 3 ).

Exhibit 3 Valley Electric Association’s 230kV Transmission System11

Source: GridLiance

2.2 Nevada West Connect (NWC) Project – Background

The NWC project will connect VEA’s southern system to its northern system and interconnect to the

California market. At the northern end, NWC is assumed to be interconnected to Los Angeles area through

a 500kV Inyo – Antelope Valley transmission line (part of NEAC South Project)12. On the southern end,

8 See http://www.gridliance.com/newsroom/valley-electric-association-to-sell-its-transmission-system-to-gridliance/ 9 See http://www.vea.coop/content/230kv-sale-clears-significant-milestone-caiso-approval 10 See http://www.vea.coop/content/230kv-sale-delayed 11 See http://www.vea.coop/content/230kv 12 See NEAC Transmission Initiative Routing Study (2012) for more details. See http://energy.nv.gov/uploadedFiles/energynvgov/content/NEAC_FinalRpt-CoverTableOfContents.pdf

http://www.gridliance.com/newsroom/valley-electric-association-to-sell-its-transmission-system-to-gridliance/

http://www.vea.coop/content/230kv-sale-delayed

http://www.vea.coop/content/230kv

http://energy.nv.gov/uploadedFiles/energynvgov/content/NEAC_FinalRpt-CoverTableOfContents.pdf



NWC is assumed to be interconnected through Crazy Eyes – Bob – Mead (WAPA) and Bob – El Dorado

(SCE).

Exhibit 4 Map of proposed Nevada West Connect (NWC) Transmission Line

Source: GridLiance

2.3 Other Comparative Transmission Projects Assessed

ICF compared the NWC project to other options to meet California’s renewable goals, and determined the

viability of NWC relative to two of the major options currently being examined in other planning processes

in the West. ICF compared NWC to resources from Wyoming and New Mexico. Specifically, ICF examined:

Development of Wyoming wind resources and the long-distance TransWest Express Line

Development of renewable resources in New Mexico combined with the Sunzia Transmission

project to deliver the power to Pinal Central in Arizona.



For each project ICF included additional transmission capacity required to ensure that the power would

be delivered into California.

NWC accesses a desert region roughly northwest of Las Vegas and east of Death Valley, and hence, is an

excellent location for solar energy. In contrast, the other two are exclusively wind projects accessing

attractive wind resources in Wyoming and New Mexico. ICF implemented a production cost assessment

to determine economic benefits, and a capital cost assessment. The detailed assumptions about the three

options are explained in the subsequent sections.

2.4 CAISO - Background

The California Independent System Operator (CAISO) was created in 1998, following California’s adoption

of the Energy Policy Act of 1992. CAISO is comprised of the transmission assets of the three major

California investor-owned utilities (IOUs): PG&E (Pacific Gas and Electric Company), SCE (Southern

California Edison), and SDG&E (San Diego Gas and Electric Company). Notable exclusions to CAISO control

are municipal utilities such as Sacramento Municipal Utilities District (SMUD), Los Angeles Department of

Water & Power (LDWP), Modesto Irrigation District, Turlock Irrigation District, Imperial Irrigation District

(IID) and Valley Electric Association (VEA). The CAISO system footprint includes approximately 80 percent

of California’s power grid.

The bulk power transmission system in California and portions of Nevada is primarily operated and

managed by CAISO.13 CAISO centrally dispatches generation and coordinates the movement of wholesale

electricity in California and parts of Nevada. CAISO operates a competitive wholesale electricity market

for energy (day-ahead and real-time), ancillary services and congestion revenue rights. CAISO also

manages the transmission planning and ensures system reliability in its territory. CAISO has also initiated

the Western Energy Imbalance Market (EIM) in 2014 to allow participating utilities/balancing authorities

to transact energy on a real-time basis.14 Currently, Pacific Corp, Arizona Public Service, NV Energy and

Puget Sound Energy and Portland General Electric are active members of EIM initiative. Idaho Power, Salt

River Project and Seattle City Light are expected to join the EIM initiative in the near future. Valley Electric

Association (VEA) in Nevada joined CAISO in 2013. The list of utilities in California is shown in Exhibit 3.

The list of zones within CAISO for hub price aggregation and flow interfaces is also shown in Exhibit 3.

13 See https://www.ferc.gov/market-oversight/mkt-electric/california.asp ; http://www.caiso.com/Pages/default.aspx 14 See https://www.caiso.com/informed/Pages/EIMOverview/Default.aspx

https://www.ferc.gov/market-oversight/mkt-electric/california.asp

http://www.caiso.com/Pages/default.aspx

https://www.caiso.com/informed/Pages/EIMOverview/Default.aspx



Exhibit 5 Map of utilities in California (Left) and zones within CAISO (Right)

Source: CAISO

2.5 Valley Electric Association (VEA) - Background

VEA is a member-owned electric cooperative operating from Pahrump, Nevada.15 VEA provides service to

more than 45,000 people within a 6,800-square mile service area located primarily along the California-

Nevada border. VEA’s service area starts in Sandy Valley in southwest of Las Vegas and extends north for

more than 250 miles to Fish Lake Valley. VEA has a bulk energy demand of around 10 GWh a year and a

peak demand of around 124 MW.

VEA joined CAISO in 2013. Its high voltage transmission system is operated and dispatched as part of the

CAISO system. The tariffs on the VEA’s transmission system are also set by CAISO. VEA ‘s 164 miles of 230

kV transmission system runs north and south of Pahrump, connecting the VEA system to the regional

transmission grid (see Exhibit 2). In May 2016, VEA issued a request for proposals to sell the high voltage

transmission system and all related substation assets. Multiple companies submitted bids and GridLiance

was finally selected as the successful bidder. In September 2016, the VEA Board of Directors approved the

sale of transmission assets to GridLiance. As part of the sale process, approvals from CAISO and FERC are

required. While CAISO approved the sale process in December 2016, the approval from FERC is still

pending as of date.

15 Background material on VEA are sourced from the following, unless stated otherwise. http://www.vea.coop/content/about-valley-electric-association-inc

http://www.vea.coop/content/about-valley-electric-association-inc



3. Recent CAISO Power Market Developments

An overview of the key market issues in CAISO is provided here for reference.

Transmission limits for out-of-state resources in California - It is estimated that meeting California’s 50%

RPS requirement by 2030 would entail nearly $5 billion or more in transmission upgrades. Also, a recent

California Energy Commission report determined that California would require an additional 25 to 108

TWh of renewables annually to meet its 50% RPS mandate.16 This would translate into 7 to 31 GW of new

capacity, assuming a 40% average capacity factor or 9 GW to 41 GW assuming a 30% capacity factor. While

options to meet California’s renewable needs have included the potential use of resources from as far

away as Wyoming combined with transmission projects such as TWE Express and Zephyr, and New Mexico

combined with the SunZia transmission project, the potential for resources in close proximity, such as

those enabled by the GridLiance project have not be examined closely. This study will help demonstrate

the benefits of these projects.

There is currently limited ability to deliver renewable energy to California consumers from out-of-state

resources. The import capacity limited by constraints on the interties that deliver power to several

transmission assessment areas (TAFAs) in California. The proposed NWC project could use the Central

Sierra or Eldorado/Mead/Marketplace intertie points to deliver up to 3,500 MW of power. Likewise the

Palo Verde/ Delaney hub is capable of transferring nearly 3,000 MW of power. The TAFAs and intertie

potential resource additions are shown in Exhibit 2. As the owner of Valley Electric’s transmission assets,

GridLiance has the opportunity to complete development and construction and own this important asset.

Exhibit 6 TAFAs and Intertie Potential Resource Additions 16

16 See http://docketpublic.energy.ca.gov/PublicDocuments/15-RETI 02/TN214168_20161025T091645_Transmission_Capability_and_Requirements_Report.pdf

http://docketpublic.energy.ca.gov/PublicDocuments/15-RETI



Natural Gas Pricing – The recent collapse in oil prices has prompted oil and gas producers to cut capital

expenditure budgets; while these cuts are likely to cause gas production from oil-directed drilling to

decline, production from dry gas plays (including the majority of the Marcellus play) should continue to

increase. Assuming normal weather, prices are likely to remain weak in the near term as growth in shale

gas production continues to outpace demand growth. However, starting around 2017/2018, ICF

anticipates that gas demand growth will accelerate (from new LNG and Mexican exports, and increases in

industrial and power sector demand) placing steady upward pressure on prices. Post-2020, ICF’s Henry

Hub (HH) natural gas prices are projected to reach and exceed $4 per MMBtu (in real 2015$), increasing

to $4.50 (2015$) by 2030. Despite the projected increase over recent (2010-2015) levels, North American

prices are expected to remain below pre-recession levels, largely due to the abundance and low cost of

shale gas supplies.

Another factor that has had a specific influence on California’s gas market in the last four years is the Ruby

pipeline. The start-up of Ruby pipeline in 2011 provided northern California with access to Rocky

Mountain gas supplies. Future California gas prices and basis will be very sensitive to both the rate of gas

demand growth and changes in gas production in the western U.S. and Canada. The key factors that could

impact projected prices and basis, include: California gas demand growth (and particularly how

renewables will impact demand growth in the power sector), potential development of in-state gas

resources (e.g., the Monterey Shale), growth in Rockies gas production, the disposition of proposed U.S.

west coast LNG terminals (e.g., Jordan Cove and Oregon LNG), and the dynamics of the Canadian gas

market (e.g., growth in western Canadian shales, potential LNG exports from British Columbia, and a

changing tariff structure on the TransCanada pipeline system).17

Aliso Canyon Incident – The Aliso Canyon gas storage facility, the largest storage facility on the Southern

California Gas Company (SoCal Gas) system, experienced a severe gas leak in October 2015 that lasted a

number of months into February 2016, when the leak was successfully mitigated. As a result, the CPUC

ordered SoCal Gas to stop all new gas injections into the facility and limited withdrawal capability exists

to maintain energy reliability. As part of a risk assessment conducted by California Public Utilities

Commission (CPUC), California Energy Commission (CEC), LADWP, SoCal Gas and CAISO, seventeen gas-

fired power plants totaling 9,500 MW located in Southern California were identified as capacity most

affected by Aliso Canyon’s reduced output. Additionally, the report established a significant risk of natural

gas curtailments this summer assuming gas withdrawals are not permitted, suggesting potential summer

generation outages and low SP-15 reserve margins.18

California AB32 CO2 Regulations – California’s AB 32 legislation attempts to capture emissions associated

with generation in California as well as those associated with imported power. Given the inherent

difficulties with tracking power flows, some bulk power flows into the state are ascribed an unspecified

rate reflecting a carbon intensity assumption based on overall system characteristics. The potential

remains for some higher CO2 intensity resources to sell into California, but be charged a lower hurdle rate

due to their categorization as unspecified sources, thus placing native fossil generation at a disadvantage

in the supply stack. While the issues related to resource shuffling linger, relatively low demand growth (as

17 See : http://www.energy.ca.gov/almanac/naturalgas_data/ 18 See: http://www.cpuc.ca.gov/aliso/

http://www.energy.ca.gov/almanac/naturalgas_data/

http://www.cpuc.ca.gov/aliso/



projected in the latest CEC forecast) and high renewable penetration (particularly record levels of solar

growth) have tamped down on allowance prices, even in the wake of a series of below average

hydroelectric generation years. The May 2017 join auction was the eleventh joint auction, reflecting the

official linkage between the Quebec and California Cap-and-Trade Programs (the linkage began in January

2014). The auction settlement price was $13.80.19

On April 29, 2015, Governor Brown signed an executive order to reduce California’s greenhouse gas

emissions by 40% from 1990 levels by 2030. This order reflects the next step beyond the AB32 goals, which

targeted emissions of 1990 levels by 2020, and is intended to take the state toward the eventual 2050

goal of 80% below 1990 levels. The executive order (B-30-15) creates an obligation for all state agencies

to take action in their jurisdictions to achieve this new target.

California Renewables Expansion and Integration – Based on its scope and timing, California has the most

ambitious RPS in the United States, and in 2014 all of California’s major Investor Owned Utilities exceeded

20% renewable generation. California’s current RPS standards, signed by Governor Jerry Brown in 2015,

dictate that 50% of California’s energy come from renewables by 2030, with interim targets of 25% by

2016 and 33% by 2020. All of these targets are reflected in ICF’s Base Case. These targets are in

conjunction with other targets for distributed energy resources and in particular, distributed solar.

Increasing amounts of renewable generation, which will likely be dominated by variable resources like

wind and solar PV, will challenge the operation of California’s power system. CAISO estimates that by

2020, 8,000 MW of supply could be lost in as little as one hour due to the variable nature of wind and

solar generation. As a result, CAISO will need to adjust its resource adequacy requirements to ensure

adequate fast start capacity, since proliferation of renewables increases the potential for a hard landing

– i.e. a surprise need for capacity. There is currently an artificial incentive for renewables in CAISO due to

an overstatement of their capacity contributions, which could be sustained until problems develop. In

the meantime, thermal gas generation may be needed to cover for renewables.

California Power Plant Retirements/Retrofits/Repowering – There is significant potential for retirement

of supply due to stringent environmental regulations related to once-through-cooling (OTC) and local air

quality district air emission limits. For example, the state’s Long Term Procurement Planning (LTPP)

assumes almost all OTC generation capacity will retire, except for Diablo Canyon. In addition, the LTPP

scenario planning assumes approximately 2 GW of additional thermal retirements. Overall, it is our view

that the current pricing level does not support investing in existing generation, and significant OTC-related

retirements are plausible. We note, however, that the baseline LTPP planning assumes approximately 12

GW of additional OTC-related retirements, contradicting owner-proposed schedules for compliance which

includes nearly 5 GW of recent retirements and an additional 1 GW with plans to retire.

In addition, California explicitly relies on large amounts of imports for energy and capacity. However, the

visibility of California into these imports is very limited and there is no process for addressing any potential

shortfall beyond the reactive mechanisms of contracting when and if a problem develops. This is a

potentially serious problem because there is the potential for extremely large capacity retirements

19 See: https://www.arb.ca.gov/cc/capandtrade/auction/results_summary.pdf

https://www.arb.ca.gov/cc/capandtrade/auction/results_summary.pdf



outside of the state which could manifest itself, as it did in 2000, as a sudden need for capacity. In such a

situation, siting restrictions in California will place premiums on existing sites and repowering.

Hydro Conditions - After four consecutive years of below-normal rainfall from 2011-15, California faced

its most severe drought emergency in decades. However, conditions have improved and the drought

designation is no longer as severe. Hydroelectric capability is projected to be near normal for the 2016

spring and summer seasons. A key driver of pricing going forward is the expectation around hydro

conditions. ICF will review the current outlook but is likely to assume a return to weather normal

conditions in the near-term.20

Low Demand Growth – Adverse economic conditions and energy efficiency policies of the state have

slowed demand growth, with official forecasts continuing to anticipate low demand growth going

forward. California demand projections include aggressive energy efficiency (EE) and demand side

management (DSM) targets embedded into its forecast, resulting in a conservative demand growth

outlook. The cumulative average growth rate for peak demand between 2015 and 2025 for the CEC 2015-

2025 Forecast, Mid Case is around 1.1%. On the other hand, should ambitious energy efficiency and

rooftop solar goals fail to achieve projected growth, the demand could grow more than anticipated in the

next decade. This could dovetail with other problems and increase the value of capacity. Demand growth,

coupled with retirements, influences the pace of supply tightening in the market and the trajectory of

increased RA pricing.

Resource Adequacy Payments for Existing Generation Capacity – California considers three categories of

resource adequacy (RA): system wide, local, and flexible. System wide RA involves traditional reserve

margin planning (15%, and assigned to each IOU individually), local RA requirements are calculated

through transmission outage security analysis (NERC contingency categories B and C in local transmission-

limited zones and subzones, and flexible RA is a system wide consideration of resources capable of

ramping generation up or down to accommodate increasingly variable statewide load profiles. Further,

there are three key mechanisms affecting resource adequacy and procurement in California: (i) the Long

Term Procurement Plan (LTPP), (ii) local and system Resource Adequacy Requirements (RAR), and (iii) the

backstop reliability mechanism. Under all of these compensation mechanisms, existing and new

generation receive different payments, and each mechanism takes place on a different time scale:

20 See: http://www.energy.ca.gov/hydroelectric/

http://www.energy.ca.gov/hydroelectric/



Exhibit 7 California’s Resource Adequacy Mechanism

Source: CPUC

Resource adequacy payments for existing generation are currently in the range of approximately $2 to

$4/kW-mo. The 2016 weighted average is $2.7/kW-mo, with the 85th percentile at $3/kW-mo. Some

generation can secure resource adequacy payments for only part of the year (e.g. summer months). The

general consensus is that resource adequacy payments at current levels are not sustainable and may

result in significant retirements in the mid-term. Much of the existing dispatchable capacity is being paid

too little for sustained reliable performance. Recent developments in New England (and to some extent

MISO) may be a harbinger of the future for California – i.e. nearly a decade of low capacity pricing followed

by retirements resulting in a sudden spike in capacity prices, which in the case of New England remain

strong for the second auction in a row. We note that despite efforts to mitigate volatility, in many markets

the nature of capacity payments remains binary. For example, retirement of one or two large generators

can shift the region from excess to deficiency, thereby spiking the capacity payments from low levels to

near net cost of new entry (CONE) level.

Flexible Resource Adequacy Criteria – California’s 50% renewable by 2030 target requires significant

reliance on flexible supply resources that can ramp up and down as response to intermittency of

renewables. The infamous “duck chart” demonstrates the magnitude of the problem with increased

penetration of renewables. While alternative resources such as storage and demand response are

expected to meet a certain part of the demand for flexible resources, it is commonly expected that gas

turbines will be the primary supplier of flexible capacity. On October 16, 2014 FERC conditionally approved

CAISO’s Flexible Resource Adequacy Proposal that includes month-ahead and year-ahead flexible capacity

obligations for load serving entities and establishes CAISO as the backstop procurement authority.

In addition, CAISO has introduced the Flexible Ramping Product. The CAISO proposes to use the Flexible

Ramping Product to address the emerging operational challenges relating to maintaining power balance

LTPP: 10 Year Forward

RAR: 1 Year Forward

CPM: Prompt – 2 Year Forward



in real-time dispatch. In doing so, the CAISO emphasized that while its existing regulation service product

could be called upon to address forecast uncertainties, procuring more regulation service is problematic

from an economic and market efficiency perspective both because the generating capacity of some

resources must be reserved to provide regulation service and because more real-time dispatch prices will

be compensated at administratively-set penalty rates. 21 Furthermore, the method of compensation

implemented by CAISO pays resources for both upward and downward forecasted movements of load

thereby provides system transparency and ensures long term market participation from the resources by

allowing them to recover their costs.

California’s Integrated Resource Plan (IRP) Framework – IRPs are long-term system planning reports for

electric utilities. Typically, IRPs are intended to ensure that publicly owned utilities (POUs) lay out the

“…resource needs, policy goals, physical and operational constraints, and general priorities or proposed

resource choices of an electric utility, including customer-side preferred resources”.22 IRPs also play a

critical role in aligning utilities’ plan to achieve the desired energy and environmental policy goals

including greenhouse reduction goals. The IRP planning framework was introduced through the SB 350.

The Bill requires the Energy Commission to produce guidelines for and to review the IRPs from public

utilities in California. POUs with an average load greater than 700 GWh (in the 2013-16 period) are

required to adopt IRPs January 1, 2019, submit them to the Energy Commission, and update them at least

once every five years thereafter. Based on historical data, 16 POUs are expected to be required to file an

IRP. The Energy Commission may review and advise on the plans, and may adopt guidelines to “govern

the submission of information” for this review. The overall framework for the IRP process in California is

shown in Exhibit 8.

The LTTP process has characterized resource planning in California to date. Under this framework, new

capacity is authorized if is demonstrable that load cannot be met through existing and firm capacity, no

optimization modeling is required, and GHG limits are not treated as a binding constraint. The IRP process

on the other hand, requires detailed optimization modeling that demonstrates that any capacity additions

are consistent with the least cost best fit system wide portfolio as determined by the regulatory authority,

which must also ensure that California’s ambitious GHG targets of 40% below 1990 levels by 2030 are

met. Hence each LSE proposes a portfolio under its IRP filing, and the CPUC accepts these plans by

comparing in aggregate against its preferred system portfolio. While some guidance has been offered

around IRP filing and reporting details, there remains some uncertainty around the final requirements

under this program.

21 See: http://www.caiso.com/informed/Pages/StakeholderProcesses/FlexibleRampingProduct.aspx 22 See: http://www.energy.ca.gov/sb350/IRPs/

http://www.caiso.com/informed/Pages/StakeholderProcesses/FlexibleRampingProduct.aspx



Exhibit 8 IRP Framework for California

Source: CPUC - http://www.cpuc.ca.gov/general.aspx?id=12400

Distributed Generation – California’s retail rates are among the highest in the U.S., along with New

England. These rates, coupled with strong policy measures (e.g. net energy metering, the California Solar

Initiative, the Self-Generation Incentive Program, etc.), strong consumer demand and a high quality solar

resource base, have produced favorable conditions for the deployment of distributed PV in the state. This

has produced high levels of growth for distributed PV in California and growing penetration rates which

could displace some conventional supply, but also can impose new challenges for system planners and

operators. Distributed generation, another of the ambitious unprecedented experiences stressing the

grid and having disruptive effects on reliability, could add to the sudden unexpected need for capacity.

A number of stakeholders, including electric and water utilities, the federal government and governing

bodies at the city and council level have enacted a number of policies, incentives and programs to capture

the full value of distributed generation.23 As of March 31, 2017, California had an installed capacity of

5,337 MW of distributed generation, with 673,031 solar projects.24

23 See: http://programs.dsireusa.org/system/program?fromSir=0&state=CA 24 See: http://californiadgstats.ca.gov/

http://programs.dsireusa.org/system/program?fromSir=0&state=CA

http://californiadgstats.ca.gov/



Energy Imbalance Market - The EIM extends the California ISO

real-Time market to other balancing authorities in the West. This

regional market will help dispatch resources for use as short-

term balancing resources. In October 2014, the first stage of EIM

was launched with a partnership between CAISO and PacifiCorp,

which has customers in six western states. Currently, Pacific

Corp, Arizona Public Service, NV Energy and Puget Sound Energy

and Portland General Electric are active members of EIM

initiative. Idaho Power, Salt River Project, Powerex (energy

marketing subsidiary of BC Hydro), Los Angeles Department of

Water and Power (LADWP) and Seattle City Light are expected

to join the EIM initiative in the near future. This joint effort has

wide-ranging implications for both generation and transmission

operations within the covered states and entities. As

participants in the EIM, generation assets could have access to

higher-priced markets due to the larger size of the balancing

authority in the Real-Time market. Transmission assets will likely

be utilized more effectively to serve load across a broader

footprint. In order to fully estimate the potential benefits of the

EIM setup, careful emphasis has to be placed on production cost

modeling and cost allocation issues.



4. Key Modeling Assumptions

The key modeling assumptions used in the modeling runs are explained in this section. 25

4.1 Peak Demand and Energy Growth for California

The overall peak and energy demand trends for California is shown in Exhibit 9. The gross demand and

the net demand for the state are also shown in the table below. The net demand takes into account the

additional savings from energy efficiency (AEE), demand response (DR) and distributed energy resources

(DERs) in the state. In 2016, the gross energy demand for the state was 64,342 GWh and a gross peak

demand of 306,134 GWh. When factoring in the different demand-side measures, the net energy demand

for the state reduces to 281,796 GWh and the net peak demand reduces to 58,062 MW. The gross peak

and energy demand are expected to grow at 0.8 % and 1.0% a year for the period 2017-2035. The net

peak and energy demand are expected to grow at -0.2% (negative growth) and 0.2%. The net energy and

peak demand estimates are used in the modeling runs.

Exhibit 9 Gross and Peak Demand Projections for California

Year

Gross Demand (GWh) Demand Net of [AEE+DR+DER] (GWh)

Peak (net of Committed EE)

Energy (net of Committed EE)

Peak Energy

2016 64,342 306,134 58,062 281,796

2017 65,200 306,937 58,257 278,590

2018 65,781 308,725 57,886 276,267

2019 66,199 311,752 57,536 275,966

2020 66,740 314,551 57,322 275,657

2021 67,320 317,586 57,140 275,505

2022 68,135 321,975 57,166 276,562

2023 68,890 326,046 57,083 277,117

2024 69,574 329,744 56,900 277,219

2025 70,212 333,652 56,633 277,406

2026 70,879 337,358 56,355 277,236

2027 71,577 340,197 56,106 278,752

2028 72,324 343,405 55,908 280,571

2029 72,594 346,696 55,733 282,405

2030 72,866 350,075 55,592 284,254

2031 73,140 353,546 55,495 286,119

2032 73,416 357,112 55,454 287,998

2033 73,693 360,778 55,476 289,893

2034 73,972 364,550 55,569 291,803

2035 74,253 368,432 55,739 293,729

Average (2017-2035)

70,055 334,963 56,570 281,242

Average Rate (2017-2035)

0.8% 1.0% -0.2% 0.2%

Source: California Energy Demand Forecast Update; January 201726 ; AAEE savings and self-generation forecasts are from California Energy Demand 2015 Revised Forecast; Mid Demand Case, January 2016 27

25 Only key assumption are discussed in the report. For a more comprehensive listing of the assumptions, refer to “ICF Base Case Nevada West Connect California Market Assumptions 4-16-17”. 26 See http://www.energy.ca.gov/2016_energypolicy/documents/2016-12-08_workshop/LSE-BA_Forecasts.php 27 See http://www.energy.ca.gov/2015_energypolicy/documents/index.html#adoptedforecast

http://www.energy.ca.gov/2016_energypolicy/documents/2016-12-08_workshop/LSE-BA_Forecasts.php

http://www.energy.ca.gov/2015_energypolicy/documents/index.html%23adoptedforecast



4.2 Gross Peak Demand and Energy Growth for California Zones

The net peak and energy demand for California sub-regions are shown in Exhibit 10 and Exhibit 11. With

CAISO, the growth rates for Bay Area is the highest at 0.83%/year for energy demand and 0.42%/year for

peak demand. The overall projected growth rates for CA SP-15 is expected to 0.3%/year for energy and

0.1%/year for peak demand. The overall projected growth rates for CA NP-15 is expected to be 0.6%/year

for energy and 0.73%/year for peak demand. The net peak demand for non-CAISO regions are shown in

Exhibit 11. Among the non-CAISO regions, LADWP has a major share of energy and peak demand. The

overall projected growth rates for LADWP is expected to be 0.84 %/year for energy and 0.50 %/year for

peak demand. The VEA has an annual energy demand of 10 GWh and a peak demand of 124 MW. By 2030,

the annual energy demand is expected to increase to 12 GWh and the peak demand is expected to

increase to 147 MW. The overall projected growth rates for VEA is expected to be 1.4 %/year for energy

and 1.23 %/year for peak demand.

Exhibit 10 Net Peak (MW) and Energy Demand (GWh) for California Sub-Regions (CAISO Zones)

Year Bay Area CA-ZP26 CA-NP-15

CA-SP-15

SCE SDGE

Energy Peak Energy Peak Energy Peak Energy Peak Energy Peak

2016 42,699 8,655 10,816 2,179 49,925 10,306 108,246 22,225 20,602 4,448

2017 42,760 8,684 10,791 2,184 49,863 10,371 107,778 22,237 20,618 4,446

2018 43,027 8,736 10,806 2,192 50,082 10,459 107,703 22,275 20,636 4,453

2019 43,424 8,765 10,848 2,192 50,441 10,513 108,112 22,262 20,785 4,454

2020 43,767 8,798 10,884 2,200 50,763 10,601 108,445 22,296 20,889 4,455

2021 44,167 8,846 10,921 2,208 51,104 10,692 108,739 22,314 21,035 4,467

2022 44,664 8,907 10,969 2,220 51,665 10,815 109,614 22,435 21,297 4,502

2023 45,200 8,976 11,022 2,234 52,127 10,929 110,187 22,497 21,461 4,511

2024 45,595 9,020 11,045 2,242 52,429 11,011 110,576 22,520 21,615 4,518

2025 45,931 9,023 11,054 2,241 52,736 11,054 111,100 22,563 21,761 4,523

2026 46,279 9,052 11,061 2,247 52,996 11,123 111,336 22,553 21,890 4,525

2027 46,638 9,086 11,069 2,252 53,265 11,196 111,583 22,555 22,024 4,530

2028 47,044 9,122 11,090 2,259 53,591 11,273 111,981 22,579 22,172 4,535

2029 47,452 9,159 11,110 2,266 53,919 11,352 112,381 22,603 22,322 4,541

2030 47,865 9,195 11,130 2,272 54,249 11,431 112,782 22,627 22,472 4,547

2031 48,281 9,232 11,150 2,279 54,582 11,510 113,184 22,652 22,623 4,552

2032 48,700 9,268 11,171 2,285 54,916 11,590 113,588 22,676 22,776 4,558

2033 49,123 9,305 11,191 2,292 55,252 11,670 113,993 22,700 22,929 4,563

2034 49,550 9,342 11,212 2,299 55,590 11,751 114,400 22,724 23,084 4,569

2035 49,981 9,380 11,232 2,305 55,930 11,833 114,808 22,748 23,239 4,574

Average (2017-2035) 46,287 9,047 11,040 2,246 52,921 11,114 111,173 22,517 21,875 4,517

Average (2017-2035)

0.83% 0.42% 0.20% 0.30% 0.60% 0.73% 0.31% 0.12% 0.64% 0.15%

Source: California Energy Demand Forecast Update; January 2017



Exhibit 11 Net Peak (MW) and Energy Demand (GWh) for California Sub-Regions (Non-CAISO Regions)

Year

Other Regions

SMUD LADWP Turlock Irrigation

District Imperial

Irrigation District Valley Electric

Association

Energy Peak Energy Peak Energy Peak Energy Peak Energy Peak

2016 16,168 4,365 29,548 6,580 2,726 625 3,798 1,035 10 124

2017 16,329 4,413 29,056 6,594 2,737 631 3,841 1,176 10 126

2018 16,479 4,474 29,120 6,576 2,762 641 3,891 1,193 10 128

2019 16,700 4,524 29,400 6,598 2,792 648 3,967 1,208 10 130

2020 16,892 4,577 29,693 6,641 2,822 656 4,047 1,223 11 131

2021 17,068 4,623 29,963 6,681 2,852 663 4,128 1,240 11 133

2022 17,272 4,676 30,312 6,729 2,888 672 4,226 1,259 11 134

2023 17,469 4,730 30,624 6,766 2,923 679 4,319 1,277 11 136

2024 17,657 4,780 30,942 6,805 2,954 687 4,409 1,294 11 138

2025 17,828 4,825 31,258 6,843 2,984 694 4,502 1,310 11 139

2026 17,993 4,872 31,574 6,879 3,015 701 4,587 1,324 11 141

2027 18,160 4,918 31,903 6,917 3,046 708 4,685 1,337 11 142

2028 18,343 4,968 32,231 6,955 3,079 715 4,783 1,353 11 144

2029 18,528 5,018 32,563 6,994 3,112 723 4,882 1,370 11 145

2030 18,715 5,069 32,897 7,032 3,145 731 4,984 1,386 12 147

2031 18,903 5,121 33,236 7,071 3,179 738 5,088 1,403 12 149

2032 19,094 5,173 33,578 7,110 3,213 746 5,194 1,420 12 151

2033 19,286 5,225 33,923 7,150 3,247 754 5,302 1,437 12 153

2034 19,480 5,278 34,272 7,189 3,282 762 5,413 1,454 13 154

2035 19,677 5,332 34,624 7,229 3,317 770 5,525 1,472 13 156

Average (2017-2035) 17,993 4,873 31,640 6,882 3,018 701 4,620 1,323 11 141

Average (2017-2035)

1.04% 1.06% 0.84% 0.50% 1.04% 1.10% 1.99% 1.91% 1.40% 1.23%

Source: California Energy Demand Forecast Update; January 2017

4.3 Gas Prices

ICF relied on its proprietary Gas Market Model (GMM) for natural gas price projections. ICF computes the

delivered gas prices with the addition a local distribution charge (LDC) (as a distribution adder). Also, ICF

also assumes a differential price schedule for power plants located on the “backbone” and “non-

backbone”. Backbone plants see a lower transportation adder as they are located on the main gas

transmission system running through California. Non-backbone plants see an additional non-backbone

charge on top of the backbone charge. On average, the projected Henry Hub prices for 2017-35 from ICF

GMM are $5.36 $/MMBtu. The average basis for the corresponding period are 0.16 $/MMBtu for NP-15

and ZP-15; and 0.05 $/MMBtu for SP-15. For the modeling period from 2020-30, the average delivered

gas price for “backbone” plants in NP-15 and ZP-15 is $5.07 $/MMbtu and for plants in SP-15 is $4.85

$/MMBtu. For the same period, the average delivered gas price for “non-backbone” plants in NP-15 and

ZP-15 is $5.73 $/MMBtu and for plant in SP-15 is $5.02 $/MMBtu. ICF assumed a 2.1% inflation factor

from 2016 to project the nominal dollar prices.



Exhibit 12 Delivered Natural Gas Price Assumptions

Delivered Natural Gas Price: Including LDC (Nom$/MMBtu)

Year Henry Hub

CAISO-NP15 CAISO-SP15 ZP-26

Backbone Non-

Backbone Backbone

Non-Backbone

Backbone Non-

Backbone

2016 2.48 2.74 3.71 2.50 2.65 2.74 3.71

2017 4.03 4.53 5.56 4.08 4.24 4.53 5.56

2018 4.18 4.56 5.37 4.24 4.40 4.56 5.37

2019 4.18 4.43 5.02 4.15 4.31 4.43 5.02

2020 4.23 4.35 4.95 4.13 4.30 4.35 4.95

2021 4.18 4.34 4.95 4.12 4.29 4.34 4.95

2022 4.43 4.60 5.22 4.38 4.55 4.60 5.22

2023 4.40 4.55 5.19 4.35 4.53 4.55 5.19

2024 4.64 4.82 5.47 4.63 4.82 4.82 5.47

2025 4.76 4.98 5.65 4.72 4.90 4.98 5.65

2026 5.10 5.33 6.01 5.07 5.26 5.33 6.01

2027 5.16 5.36 6.05 5.11 5.30 5.36 6.05

2028 5.38 5.52 6.23 5.29 5.48 5.52 6.23

2029 5.53 5.58 6.30 5.35 5.55 5.58 6.30

2030 6.28 6.29 7.03 6.08 6.28 6.29 7.03

2031 6.96 6.90 7.65 6.70 6.91 6.90 7.65

2032 7.60 7.55 8.31 7.35 7.56 7.55 8.31

2033 7.74 7.70 8.49 7.50 7.72 7.70 8.49

2034 7.90 7.81 8.62 7.64 7.86 7.81 8.62

2035 8.05 7.95 8.76 7.79 8.02 7.95 8.76

Average (2016-2035)

5.36 5.49 6.23 5.26 5.45 5.49 6.23

Source: Henry Hub prices and basis differential are computed based on ICF Gas Market Model (GMM) Forecast

(2017 Q1). ICF assumes an inflation factor of 2.1% from 2016 onwards.

4.4 Firm Generator Builds

ICF relied on multiple sources for firm generator builds to be included in the modeling runs. ICF used

California Energy Commission database, California Public Utilities Commission (CPUC) database and SNL

for determining the status of power plant projects.28 ICF typically classifies firm generator projects as

those that are under-construction or secured financing or PP agreements and a rated nameplate capacity

of 20 MW or greater. Based on the updated information, these projects are included in the modeling base

case. Overall, California is expected to add close to 13.76 GW of generator projects from 2016-2027.In

order to comply with the state aggressive RPS target of 50% by 2030, solar is expected to constitute a

substantial chunk of the proposed additions. Overall, close to 8.7 GW of solar resources are expected to

be added in the next ten years (including recent additions).

28 California Energy Commission - Energy Facility Status as of March 2017 (http://www.energy.ca.gov/sitingcases/all_projects.html) California Public Utilities Commission (CPUC) database of planned projects as of February 2016 SNL Power Plant Projects as of April 2017

http://www.energy.ca.gov/sitingcases/all_projects.html



Exhibit 13 Firm Builds by Technology Type in California

Technology Type 2016 2017 2018 2019-2020 2021-2027 Total

Total Biomass - 14 - - - 14

Natural Gas 946 - - 1,562 1,040 3,548

Landfill 20 - - - - 20

Solar 2,171 1,612 801 2,335 1,778 8,698

Wind - 395 132 491 - 1,018

Energy Storage - 97 - 70 261 350

Total Firm Builds 3,137 2,118 933 4,458 3,079 13,647

Source: CEC – Energy Facility Status (March 2017); SNL (April 2017); CPUC

4.5 Recent and firm retirements

ICF relied on a number of sources to project the expected retirements. The primary sources include SNL,

California Energy Commission (CEC) and other press article on individual plant retirements. Overall, nearly

12.2 GW is expected to retire in the period from 2014- 2025. Natural gas plants constitute a considerable

share of the proposed retirements at 7.8 GW, followed by nuclear at 2.2 GW and coal at 1.8 GW. We

assume the Diablo Canyon nuclear unit to retire in this period as well. The retirements also account for

the California’s regulation of once-through-cooling (OTC) regulations.29

Exhibit 14 Recent and Firm Retirements in California

Technology Type 2016 2017 2018-2019 2020-2025 Total

2016-2025

Natural Gas 525 1,583 2,776 2,993 7,876

Coal - - - 1,800 1,800

Wind 80 - 19 - 99

Hydro 80 5 19 - 104

Other 128 - - - 128

Geothermal - - - - -

Nuclear - - - 2,240 2,240

Total 813 1,588 2,814 7,033 12,247

Source: SNL (as Dec 2016); CEC – Tracking Progress Reports

4.6 Environmental Assumptions

We also assume the applicable environmental regulations for California wholesale power market. We also

model allowance price for CO2 to comply with California’s AB 32 regulation. 30 California’s SB 32

requirement specifies that the state achieve economy-wide statewide greenhouse gas emissions to 40

percent below 1990 levels by 2030. ICF assumes allowance prices paid by generators in CA between 2016

and 2020 that are close to the administratively mandated AB 32 floor price, reflective of recent market

trends. After 2020, allowance prices increase to reflect the path to compliance with the 2030 requirement.

The prices to 2030 are based on ICF internal analysis. Imports into California are charged the same

allowance prices, assuming the CA ARB unspecified rate of 0.428 metric tons CO2/MWh.

29 California’s State Water Board adopted its Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling on May 4, 2010. The Policy became effective on October 1, 2010 when the California Environmental Quality Act Notice of Decision was submitted to the Secretary of Resources. The policy calls for the phased-in reduction of OTC impacts by 2020. 30 For an overview of CA AB32 regulations and targets, see: https://www.arb.ca.gov/cc/ab32/ab32.htm

https://www.arb.ca.gov/cc/ab32/ab32.htm



Exhibit 15 California AB32/SB32 Allowance Price for CO2 and Import Charges Schedule

California AB32/SB32 CO2 Allowance Price California AB32/SB32 Import Charges

Year AB32 CO2

Allowance Price (Nom$/ton)

Year AB32 Import

Charges (Nom$/MWh)

2016 11.2 2016 5.3

2017 11.1 2017 5.3

2018 12.5 2018 5.9

2019 13.6 2019 6.4

2020 14.7 2020 7.0

2021 15.8 2021 7.4

2022 16.8 2022 7.9

2023 18.0 2023 8.5

2024 19.3 2024 9.1

2025 20.6 2025 9.7

2026 22.0 2026 10.4

2027 23.5 2027 11.1

2028 25.8 2028 12.2

2029 27.5 2029 13.0

2030 30.1 2030 14.2

2031 32.2 2031 15.2

2032 34.6 2032 16.3

2033 37.3 2033 17.6

2034 40.3 2034 19.0

2035 43.7 2035 20.6

Average (2016-2035)

23.5 Average

(2016-2035) 11.1

4.7 Project Assumptions for the Three Alternatives

The assumptions for supply resources for each of the three scenarios are shown in Exhibit 16 . We assume

NWC will enable 750 MW of solar and 250 MW of wind generation in Nevada. We assumed that 50% of

the load interconnects at Big Dunes substation, while the other 50% of the load interconnects at Crazy

Eyes substation. Based on ICF internal modeling assumptions, capital costs of solar in Nevada is estimated

to be $1,403 $/kW and the fixed O&M is estimated to be $15 $/kW. Likewise, the capital cost of wind in

Nevada is estimated to be $1,510 $/kW and $50 $/kW for fixed O&M. For the SunZia case, we assumed a

total of 2000 MW of wind resources at the terminal end of the line in New Mexico. Again based on ICF

internal modeling assumptions, ICF projects a capital costs for wind projects in New Mexico at $1,433

$/kW and a fixed O&M cost of $50 $/kW. For the TWE case, ICF assumes an injection of 1,500 MW of

power at El Dorado substation, NV (from a HVDC line from Southern Wyoming). Based on ICF Internal

modeling assumptions, ICF projects a capital costs of wind projects in Wyoming at $1,380 $/kW and a

fixed O&M cost of $50 $/kW. All projects are assumed to be online before 2021 for modeling purposes,

which ensures that all projects will qualify for full PTC and ITC allocations.31 We also tested sensitivity

cases to assess the impact of delays that could result in lower PTC allocations. The wind generation profile

31 The latest a wind project can come on line and receive the full PTC is end-2020. For projects wishing to avail the PTCs, IRS established the maximum time between start of construction and coming on-line date at 4 years. The cutoff online period can be extended by legislation, IRS rule change or injection locally until the transmission construction completes.



is based on NREL profiles for appropriate regions.32 For NWC’s solar profile, we relied on the Appaloosa

profile furnished by GridLiance.33

Exhibit 16 Assumptions for Supply Resources in the Three Scenarios

Assumptions for Supply Resources

Scenario Type

(Solar/Wind) Capital Cost

($/kW) Fixed O$M

($/kW) Capacity

(MW) Interconnection Nodes PTC/ITC

Level

Online Date

(Before)

NWC Solar 1,403 15 750

50% @ Big Dune; 50%

@ Crazy Eyes 10%-30%

(ITC) 2021

NWC Wind 1,510 50 250 50% @ Big Dune; 50%

@ Crazy Eyes 80% (PTC) 2021

Sunzia Wind (Pattern

Energy) 1,433 50 1,500

100% @ Sun Zia East (NM)

100% 2021

Sunzia Wind (Other) 1,433 50 500 100% @ Sun Zia East

(NM) 80% (PTC) 2021

TWE Wind 1,380 50 1,500 Eldorado 80% (PTC) 2021

Source: ICF and GridLiance. All $ values are expressed in nominal dollars.

The assumptions for transmission projects for the three scenarios is shown in Exhibit 17. For the NWC

line, we assume two transmission line segments – 230 kV Inyo – Big Dune – Crazy Eyes segment and a new

substations at Bob and Crazy Eyes on existing 230kV Pahrump – Mead line. The transfer capability of the

new NWC line is expected to be 1200 MVA. From Inyo, the project is expected to deliver power to

Antelope Valley, California through the proposed 500kV Inyo – Antelope Valley transmission line (part of

NEAC South Project).34 The SunZia project is expected to supply 3000 MVA from SunZia East (NM) to Pinal

Central (AZ). This is would then be connected to Palo Verde hub through third party transmission service.

The TWE HVDC line is expected to supply 3000 MW of power from Southern Wyoming to El Dorado

substation in Nevada. The project is implemented in two phases. For the current model runs, we

implemented an injection of 1500 MW at El Dorado (to reflect Phase I transfer capability for the TWE

project). The estimated capital cost of NWC is expected to be $1.044 billion (including NEAC South line to

Antelope Valley, CA). The SunZia project is expected to cost $2 billion and the TWE project is expected to

cost $3 billion (based on information from respective project website).

32 ICF relies on wind profiles from National Renewable Energy Laboratory (NREL)’s WIND ToolKit. The ToolKit data can also be accessed through NREL’s System Advisory Model (SAM) – See https://sam.nrel.gov/ 33 GridLiance furnished a solar profile for Nevada “ Appaloosa, UT- NASA 1983”. ICF request citation from GridLiance for the solar profile. 34 See NEAC Transmission Routing Report (2012) for more details.

mailto:100%25@Sun%20Zia%20East%20(NM)

mailto:100%25@Sun%20Zia%20East%20(NM)



Exhibit 17 Assumptions for Transmission Projects in the Three Scenarios

Assumptions for Transmission Projects

Project Type Capital Cost ($ million)

Rating (MVA/MW)

Interconnection Nodes/Sections

Voltage (kV)

Online Date

(Before)

NWC Line HVAC

402

1,200 Inyo-Big Dune-Crazy Eyes 230 kV 2021

NWC Line HVAC 1000 Crazy Eyes-Bob-Mead 230 kV 2021

NWC Line HVAC 870 Bob-Eldorado 230 kV 2021

NEAC South HVAC 924 3,512 Inyo-Antelope Valley 500 kV 2021

Sunzia HVAC 2,000 3,000 SunZia East (NM) to Pinal Central (AZ)

500 kV (Double Circuit)

2021

TWE HVDC 3,000 3,000 Modeled as injection at Eldorado

N/A 2021

Source: ICF and GridLiance. All $ values are expressed in nominal dollars.

4.8 Capital Charge Rate Assumptions

Capital charge rate (CCR) is typically the cost of the capital or the typical rate or return expected on

invested capital. The capital charge (in $ value) is the cost of capital (or CCR) times the amount of invested

capital. ICF relies on the following assumptions to derive the CCR for generator and transmission assets.

The assumption is used to compute the annual charges of transmission and generator projects which turn

leads to the levelized costs of renewables.

Exhibit 18 Capital Charge Rate Assumptions for Transmission and Generator Assets

Transmission Assets

Parameter Value

Book Life 40 years

ROE – Nominal 10%

Debt Rate – Nominal 5%

Equity Share 50%

Federal Income Tax Rate 34%

Levelized (annuitized) Capital Charge Rate 8%

Source: ICF

Generation Assets

Parameter Value

Book Life 30 years

ROE – Nominal 12%

Debt Rate – Nominal 5%

Equity Share 25%

Federal Income Tax Rate 34%

Levelized (or annuitized) capital Charge Rate 10%

Source: ICF



4.9 Additional Project Description and Characteristics

The three projects are assumed to come on line at the same time (assumed to be end 2020).35 However,

the three projects differ significantly in distance from California markets, originating region, size and mix

of renewable resources (see Exhibit 19).

Exhibit 19 Selected Project Characteristics

Project

Renewable Resource Location

Solar Capacity

(MW)

Wind Capacity

(MW)

Total Renewable Generation

Capacity (MW)

Average Capacity

Factor (%)

Annual Renewable

Energy (TWh)

NWC Nevada 750 250 1,000 34 3.0

TWE Wyoming 0 1,500 1,500 45 5.9

SunZia New Mexico 0 2,000 2,000 39 6.8

Source: ICF and GridLiance

The differences in the three projects are discussed below:

Renewable Mix – The three projects have different mixes of renewable generation. Therefore,

the economics of the projects will be impacted by the resource characteristics such as capacity

factor of wind resources from different locations, capacity factor of wind relative to solar, hourly

and seasonal profile of wind compared to solar, and incentives such as the ITC for solar compared

to the PTC for wind. The types and mix of resources considered were:

o NWC accesses a desert region roughly northwest of Las Vegas and east of Death Valley

National Park, CA and hence, is an excellent location for solar energy. NWC delivers a mix

of renewables that is mostly solar power (75%) and the remainder wind (25%), all located

in Nevada. Therefore, the production cost impacts will reflect primarily the impacts of

additional injection of solar power.

o In contrast, TWE and SunZia access attractive wind resources in Wyoming and New

Mexico, respectively, and deliver wind generation exclusively.

o As of 2016, the Federal PTC for qualified wind resources is approximately $0.023/kWh for

projects or $23/MWh.36 The PTC is available for the first ten years of a project. Average

wind costs are $36.7/MWh to $50.6/MWh after the PTC, and hence, the PTC is a critical

factor in the economics of renewables. Depending on the year of start of construction,

the value of the credit steps down from 2016 levels between 2017 and 2019. The PTC

credit is completely eliminated after this period. Depending on scenario assumptions, the

wind projects for the three scenarios are assigned appropriate wind PTC levels. The

Federal ITC for renewable projects is expected to remain at 30% of the total project costs

in the near future.37 Starting from 2020, the ITC is expected to be scaled down to 10% in

35 The latest a wind project can come on line and receive the full PTC is end 2020. That is because the IRS established the maximum time between start of construction and coming on line is 4 years. The latest time period for coming on line can be extended by legislation, IRS rule change or injection locally until the transmission construction completes. 36 See DOE Renewable Electricity PTC - https://energy.gov/savings/renewable-electricity-production-tax-credit-ptc 37 See DOE Business Energy ITC - https://energy.gov/savings/business-energy-investment-tax-credit-itc

https://energy.gov/savings/renewable-electricity-production-tax-credit-ptc

https://energy.gov/savings/business-energy-investment-tax-credit-itc



two years period. This would correspond to one-third of the ITC level in 2016. Solar

projects in the current modeling runs are assumed to obtain the ITC credits at full value.

Exhibit 20 Current Federal PTC and ITC Schedules

Start of Construction

(Year)

Percent of 2016 PTC Value

Level

ITC Value – Percent of

Project Cost

ITC Value – Percent of 2016

ITC Value Level

2016 100 30 100

2017 80 30 100

2018 60 30 100

2019 40 30 100

2020 0 26 87

2021 0 22 73

2022+ 0 10 33

Note: The latest a wind project can come on line and receive the full PTC is end 2020. That is because the IRS established the maximum time between start of construction, and coming on line is 4 years. The latest time period for coming on line can be extended by statue change, rule change or injection locally as the construction completes. Source: DOE Renewable PTC and Business Energy ITC 36,37

Proximity to California – NWC follows a much shorter route than the other two projects, and

hence, enables the development of renewable resources much closer to California than the other

two projects. Approximate route distance of the NWC project is 530 miles. In contrast, the TWE

project is 880 miles or 65% longer, and the Sunzia project is also approximately 875 miles or 64%

longer. 38 Therefore, transmission capital costs are lower when compared to the other two

alternatives.

Exhibit 21 Approximate Route Distances for the three projects

Project Segment Approximate Length of Line (miles)1

Measurement

NWC Western Nevada 268 From Crazy Eyes to Control

Nevada to California 264 From Inyo to Antelope Valley

TWE Wyoming to Nevada 730 From Wyoming to Eldorado

Nevada to California 150 Eldorado to Lugo

Sunzia New Mexico to Arizona 515 From New SunZia East substation to Pinal

Central

Sunzia Arizona to California 360 Pinal Central to Devers via Palo Verde2

1 For transmission lines, typically circuit-miles are used. We show for exposition a simpler, more approximate measure of the

distance of the route in terms of miles. . 2 ICF estimate with allowance for routing.

Source: ICF, GridLiance, SunZia (www.sunzia.net), TransWest Express (www.transwestexpress.net/)

38 Assumes 360 miles from Pinal Central to Devers in SP-15, for a total of 875 miles. See later discussion.



Delivery Capability – NWC is the smallest of the three projects with an approximate capacity of

1,000 MVA and delivers approximately 3.0 TWh 39 of renewable energy. The other two projects,

TWE and Sunzia, are larger and deliver approximately 5.9 TWh and 6.8 TWh, respectively. To

correct for size difference, we compare projects using average levelized costs per MWh delivered.

Therefore, to the extent the larger projects have economies of scale, with respect to MW transfer

capability and the capacity factor of the renewables, this would be reflected in the lower costs

per MWh.

39 1 TWh = 1 million MWh.



5. Modeling Approach and Results

5.1 Modeling Approach

ICF simulated the wholesale power market in California using its PROMOD modeling platform. ICF is a

licensed user of ABB PROMOD IV40, a highly detailed, fundamental electric market simulation model that

chronologically computes hour-by-hour production costs while recognizing the constraints on the

dispatch of generating units imposed by the transmission system. PROMOD IV performs an 8760-hour

commitment and dispatch recognizing both generation and transmission impacts at the nodal level.

PROMOD IV uses a detailed electrical model of the entire transmission network, along with generation

shift factors determined from a solved alternating current (AC) load flow, to calculate the real power flows

for each generation dispatch. PROMOD is capable of delivering hourly dispatch and prices at a nodal and

zonal level. This enables PROMOD IV to capture the economic penalties of re-dispatching generation

resources to satisfy transmission line flow limits and security constraints.

The output of PROMOD IV includes hourly Locational Based Marginal Prices (LBMP) for all generator and

load buses, hourly forecast of congestion across transmission lines and interfaces along with associated

congestion costs, system-wide congestion costs, and hourly dispatch of generating units. The model also

captures the effect of marginal losses on power prices. This approach is similar to the market design of

most Independent System Operators (ISOs). ICF modeled four scenarios – a Base Case representing

market conditions without any of the proposed transmission projects and a Change Case using similar

market conditions but with one of the proposed transmission projects included. So in effect there is a

separate Change Case scenario for NWC, TWE and SunZia projects (along with upgrades required to

deliver to California).

ICF simulated the operation of the California market for the period 2020 through 2030. We modeled four

explicit run years –2020, 2022, 2025 and 2030. A linear interpolation methodology was used to develop

the forecast for the intervening years. Prior to modeling the two cases, the PROMOD model database and

results were analyzed and benchmarked to historical zonal prices. ICF calibrated the model simulation

results to within ± 10% of the average annual zonal historical prices in CAISO. The results of the modeling

runs are explained in the following sections.

5.2 Production Cost Savings

ICF simulated the operation of the Western Electricity Coordinating Council (WECC) region using the

PROMOD production cost model to compare the economic benefits for the three scenarios. ICF analyzed

the proposed alternatives using the PROMOD platform for a security constrained, unit commitment

(SCUC) simulation of California wholesale markets in the WECC. The principal focus of the analysis is

adjusted production costs (APC) for California (also referred to in the report as production costs). We

calculate the production cost impacts of the three projects in individual scenarios to compare the projects.

The methodology used to analyze the production costs of the projects has the following components:

Transmission Costs – We calculated the transmission costs of the projects assuming that the

projects are able to firmly deliver renewables into California, corresponding to a California

40 See ABB PROMOD - http://new.abb.com/enterprise-software/energy-portfolio-management/market-analysis/promod

http://new.abb.com/enterprise-software/energy-portfolio-management/market-analysis/promod

http://new.abb.com/enterprise-software/energy-portfolio-management/market-analysis/promod



Renewable Portfolio Standards (RPS) Category 1 procurement portfolio (i.e. “Bucket 1”).41 We

assume the recovery of and on capital invested in transmission occurs via traditional cost of

service rate making assuming 40 year book life for the transmission assets.

Generation Costs of Renewable Power plants – As noted, we calculated the generation costs of

the renewables assuming full availability of federal tax incentives, 100% of the PTC level for 2016

vintage wind projects, and the 30% ITC for solar projects. We assume that the renewable energy

is provided via long term PPAs.

Total Gross Costs – The total gross cost of the projects is the sum of the generation and

transmission costs as described above.

Total Adjusted Production Cost Savings in California – As noted, we use a production cost model,

PROMOD, to calculate adjusted production costs savings from injecting the renewable energy and

adding the transmission. In this modeling, the dispatch of power plants, and transmission power

flows are calculated and change in response to new power supply from each transmission project.

The model also calculates the variable costs of plant operation – i.e. the production costs.

We use the term Adjusted Production Costs (APC) rather than production costs because

California’s production costs are adjusted. Specifically, imports from outside California have costs

set by the market price of power at the import location, and exports have revenues set at the

market price of exports. The imports of the three projects – NWC, TWE and SunZia - are modeled

as if they are part of California.

Capacity Cost Savings: We did not calculate capacity cost savings in our quantitative assessment.

Therefore, the analysis may have understated the advantage of NWC. This is because solar

facilities receive greater capacity credits (i.e. a higher percentage of nameplate capacity counts

towards meeting the CAISO planning reserve margin requirements) than wind facilities. This in

turn occurs because solar generation coincides with grid peak demand period diurnally and

seasonally, and hence, the contribution of solar to reserve margin requirements tends to be

higher than wind whose output is distributed more evenly diurnally and more during winter

periods than summer periods. ICF assumes a generic reserve margin (RM) contribution of 35% for

solar and 20% for wind units in WECC region. If solar facilities save 15% more capacity than wind,

and new fast start thermal peaking units are needed, the solar facilities of NWC decrease capacity

costs by $3.5/MWh.42 ICF did not calculate this benefit because California is not projecting a new

capacity need for the near future. At recent capacity prices for existing facilities, the savings are

more likely to be approximately $1/MWh. Furthermore, these generic RM contributions rates

41 California’s RPS program defines all renewable procurement acquired from contracts executed after June 1, 2010 into three portfolio content categories, commonly referred to as “buckets.” Category 1 refers to energy and RECs delivered to a California balancing authority without substituting electricity from another source. For the 2017 -2020 compliance period, Category 1 RECS must be at least 75% of the procurement. (Source: http://www.cpuc.ca.gov/RPS_Procurement_Rules_33/)

42 If solar RM contribution is 35% and wind’s RM contribution is 20%, and 75% of the 1000 MW is solar, then there is an

incremental capacity benefit of approximately:

(1000$/kw x 0.1/year x 1000 MW x 0.15 x 0.75)/3 million MWh = $3.75/MWh

If capacity costs are $35/kw year, then the savings fall to $1.3/MWh

http://www.cpuc.ca.gov/RPS_Procurement_Rules_33/



might not apply to wind in Wyoming, and New Mexico, and are increasingly more complex due to

changes in net demand.43

Net Costs – The difference between the gross costs and APC is computed as the net costs. The

net costs is computed for the three individual scenarios for comparison (see Exhibit 2).

Renewable Energy Credits - The net costs do not include revenues from the sale of Renewable

Energy Credits (RECs). This is not required for a relative ranking of the cost-effectiveness of the

three transmission projects because per MWh all three projects are assumed to generate the

same REC revenues. Put another way, we focused in on determining the most cost effective

method of delivering renewables among the three projects. This can be thought of determining

a supply curve with the least average cost step representing the first step, the next highest cost

project representing the second step, etc.

Hence, the net costs are positive in the prior discussions i.e. the cost of the projects exceed the

production cost savings as calculated (see Exhibit 2 ). However, this does not mean the projects

are not net beneficial. Rather, there is a larger, much more complex study that is beyond the

scope of this study that would assess this issue, and this study is assumed to be conducted by

California. This study might conclude the projects are net beneficial because they achieve the

renewable energy goals of the state in the most cost effective manner. For example, this net cost

or cost premium could be offset by revenues from RECs or other programs, and at $41.0/MWh

REC credit, the NWC project is break-even.

5.3 Wholesale Consumer Cost Savings

Another metric considered is the wholesale consumer cost savings due to the project’s decreasing

wholesale prices. For example, if nodal electrical energy prices decrease on a demand weighted average

by 10 percent, this would mean the consumer cost savings would be ten percent. The consumer cost

savings for NWC project ranges from $ 127 million in 2020 to $139 million in 2030. The consumer cost

savings for TWE project are higher ranging from $165 million in 2020 to $204 million in 2030.

Exhibit 22 Consumer Cost Savings for the Projects

Year CSL Savings ($ million)

NWC

2020 (127)

2022 (113)

2025 (119)

2030 (139)

TWE

2020 (165)

2022 (156)

2025 (181)

2030 (204)

SunZia

2020 (191)

2022 (180)

2025 (209)

2030 (236)

43 Net demand is demand net of renewable supply and other non-dispatchable sources. This complexity is related to system

changes often referred to as the “duck” problem, namely low need for additional power during periods of higher solar output

mid-day and high need during demand peak in hours ending 5 and 6 pm.



Source: ICF

5.4 Key Production Cost Savings Metric

The results of the production cost modeling run is shown in Exhibit 23. The table reports adjusted

production cost (APC), total production costs (TPC) (i.e. without adjusting for California imports/exports),

imports costs savings and cost-to-serve load (CSL) savings between a Change and Base cases. The APC

savings for NWC project is expected to range between $100 million in 2020 to $149 million in 2030. While,

the APC for TWE case is expected to range between $223 million in 2020 to $331 million in 2030. For

SunZia caser, the APC savings is expected to range between $39 million in 2020 to $48 million in 2030.

Exhibit 23 Adjusted Production Cost Savings

Year APC Savings ($ million)

NWC

2020 (100)

2022 (96)

2025 (116)

2030 (149)

TWE

2020 (223)

2022 (231)

2025 (269)

2030 (331)

SunZia

2020 (244)

2022 (253)

2025 (280)

2030 (385)

Source: ICF

5.5 Transmission Costs – Capital Costs and Project Capacity

The most important difference between the three projects is the lower capital costs of the NWC compared

to the other projects, even after accounting for differences in the MWh delivered. The three projects differ

significantly in terms of capital costs and size.

NWC - The NWC project has the lowest total capital costs of approximately $1.3 billion.

TWE - In contrast, the TWE project capital costs for Wyoming to Eldorado, Nevada to be $3 billion.

ICF estimates another $2 billion for new lines from Eldorado near Las Vegas into SP 15 for a total

of $5 billion.

Sunzia - The Sunzia project estimates capital costs for the lines from New Mexico to Pinal Central,

Arizona to be $2 billion. Sunzia does not provide estimates or even a route from Pinal Central to

SP15 in California.44 ICF provides a scoping level estimate of $1.7 billion for Pinal Central, Arizona

to Devers in California. The distance from Pinal Central to Devers is approximately 360 miles. ICF

assumed a unit cost of $4.6 million/mile for the line segment from Pinal Central to Devers resulting

in a cost of approximately $1.7 billion. This brings the total transmission cost of the SunZia

scenario to $3.7 billion.

44 Sunzia states it expects that California utilities would use existing transmission rights to complete the route. However, even if this capacity exists, we feel that the opportunity costs could be as high as the transmission costs.



In order to compare the capital costs, we compare the $/MWh levelized (i.e. annuitized) capital costs of

the transmission projects correcting for the renewable energy delivered. Exhibit 24 shows the capital

costs and the annualized capital costs per MWh. The capital costs are higher for the TWE and Sunzia

projects by a factor of 2.8 to 3.8 or $2.3 billion to $3.7 billion. On a per MWh basis SunZia is 1.2 times the

cost of NWC or $7.5/MWh higher. TWE is 1.9 times the cost and $32.4/MWh higher. The per MWh

premium of TWE and Sunzia is smaller than the capital cost premium (1.2 to 1.9 compared to 2.8 to 3.8

times) due to economies of scale, but even with the economies of scale the costs are still much higher

than NWC. Thus, in order for TWE and SunZia to be more economic than NWC, generation and production

costs savings per MWh need to make up for this large deficit.

Exhibit 24 Transmission Capital Costs Comparison for the Three Scenarios

Project Name

Cost of Main Segment

($ million)

Cost of Additional Segments for Delivery

into California ($ million)1

Total Costs ($ million)

Renewable Capacity Enabled

(MW)

Renewable Generation

(million MWh)

Capital Cost ($/MWh)2

NWC 402 924 1,327 1,000 3.0 35.5

TWE 3,000 2,000 5,000 1,5003 5.9 67.9

Sunzia 2,000 1,656 3,656 2,000 6.8 43.0

Note: 1 Additional transmission capacity required for deliverability into California are assumed to be (1) the 500 kV line from Inyo to Antelope Valley for NWC; (2) a new 500 kV line from Eldorado to Lugo for TWE; and (3) incremental transmission capacity from Pinal Central to Lugo for SunZia. 2 ICF assumes an 8% annualization rate (CCR) and 40 year amortization schedule (also see Model Assumptions section) 3 TWE is expected to deliver an initial capacity of 1,500 MW of generation, increasing to 3,000 MW. For the purposes of the study, ICF assumed it will deliver up to 1,500 MW.

The cost of incremental transmission capacity to ensure deliverability of the generation resources into

California are substantial for TWE and especially SunZia. The cost for transmission capacity to deliver TWE

generation from the terminus at Eldorado to Lugo in California is approximately $27/MWh. For SunZia the

cost of incremental transmission capacity from Palo Verde to Devers is estimated at approximately

$19.5/MWh. For these projects to be competitive in term of transmission costs relative to NWC, the

incremental cost would have to be almost zero for TWE, and $0.8 Billion or 83% lower.

5.6 Generation Costs of Renewables

Exhibit 25 shows the capacity, capacity factor, and resulting annual energy generation for each of the

three projects. ICF assumed capacity factors of 33% and 38% for Nevada solar and wind resources,

respectively. For a combination of 750 MW solar and 250 MW wind, this results in a weighted average

capacity factor of 34%. The capacity factor of wind in Wyoming and New Mexico were both assumed to

be 45%. The corresponding annual energy produced is 3 TWh for NWC and 5.85 and 7.8 TWh for TWE and

SunZia, respectively or approximately 30% more per MW of capacity.



Exhibit 25 Generation Capacity Factors and Renewable Generation per 1000 MW

Project

Solar Capacity (MW)

Wind Capacity (MW)

Total Renewable Generation

Capacity (MW)

Average Capacity

Factor (%)

Annual Renewable

Energy (TWh)

NWC 750 250 1,000 34 3.0

TWE 0 1,500 1,500 45 5.9

SunZia 0 2,000 2,000 39 6.8

Note: For NWC scenario, weighted average capacity factor for 750 MW of solar at 33% and 250 MW of wind at 38% is 34%

NWC’s average generation costs are higher, because the capacity factors are lower than the other two

projects. At full level of ITC and PTC, the cost of TWE wind is lower at $36.7/MWh compared to

$41.3/MWh for the NWC solar – or $4.6/MWh lower. The capacity factor of the NWC wind is 38%, with

a cost of $50.6/MWh, $13.9/MWh higher than the TWE wind. Therefore, NWC has an average cost of

$43.9/MWh, or $7.2/MWh higher than TWE wind at full levels of PTC and ITC. Sunzia wind cost is

$46.6/MWh, which is lower than NWC wind, but higher than the weighted average NWC wind and solar

cost of $43.9/MWh. NWC is lower on average due to the lower solar capital and O&M costs.

Exhibit 26 Generation Costs for Wind at Full PTC and Solar at Full ITC

Parameter Wind (WY) Wind (NM) Wind (NV) Solar (NV)

Capacity Factor (%) 45 39 38 33

Capital Cost ($/KW) 1,380 1,433 1,510 1,403

ITC NA NA NA 30%

Capital charge/Annualization Rate (%) 10.51 10.68 10.66 10.66

Annual Capital Cost 145 153 161 105

Fixed Annual O&M 50 50 50 15

Total Annual Charges ($/kw yr) 195 203 211 120

Levelized Average Cost ($/MWh) 49.4 59.3 63.3 41.3

PTC Rate ($/MWh)45 23 23 23 NA

PTC Level (%) 100 100 100 NA

Levelized Cost ($/MWh) 36.7 46.6 50.6 41.3

The advantage of the wind at TWE and SunZia might be lower because the transmission projects are

forecasted to be on line by the end of 2020, and there might be delays, and these longer projects might

be more susceptible to delays. This is because under current rules, for projects coming on-line in 2021,

the PTC maximum is 80% of the full PTC rate because the latest on-line date with full PTC is end of 2020.

This increases the TWE and SunZia rates to $39.3/MWh and $49.2/MWh, respectively, without affecting

the primarily solar NWC project. This is because solar projects starting in construction as late as end 2020

45 Wind projects can avail PTC for ten years after commissioning. See https://energy.gov/savings/renewable-electricity-production-tax-credit-ptc





and coming on line at the end of 2024 could have full ITC assuming four years maximum construction

period applies to solar ITC as well. Thus the $7.2/MWh advantage of TWE decreases to an advantage of

$5.3/MWh. Another year of delay would bring the costs even closer, $39.3/MWh versus $41.9/MWh.

We did not include this consideration in the quantitative analysis because delays might not affect any of

the projects, there is potential for rule changes and injection locally while waiting for transmission. The

capacity factor is a key driver of the generation costs. The average costs also reflect the similar capital

costs, but higher fixed O&M for wind than solar (see below).

5.7 Generation costs of Renewables under Sensitivity cases

The levelized costs for different resources for different sensitivity assumptions are shown in Exhibit 27-

29. These sensitivity cases are not used in the final quantitative assessment. The best wind sites in the

country are closer to 50% capacity factor. It is possible that Wyoming wind might be able to support a

higher capacity factor. Combined with 100% PTC, costs are $31.8/MWh. This would be $12.1/MWh

lower, but still not enough to offset the large transmission cost disadvantage. The results of the sensitivity

case is shown in Exhibit 29.

Exhibit 27 Generation Costs for Wind at 80% PTC and Solar at 100% ITC (Not used in quantitative analysis)

Project Solar (MW) Wind (MW) Solar Costs ($/MWh)

Wind Costs ($/MWh)

Weighted Average($/MWh)

NWC 750 250 41.3 53.1 44.6

TWE 0 1,500 NA 39.3 39.3

SunZia 0 2,000 NA 49.2 49.2

Exhibit 28 Generation Costs for Wind at 80% PTC and Solar at 100% ITC (Not used in quantitative analysis)

Parameter Wind (WY) Wind (NM) Wind (NV) Solar (NV)

Capacity Factor 45 39 38 33

Capital Cost ($/KW) 1,380 1,433 1,510 1,403

ITC NA NA NA 30%

Capital charge/Annualization Rate (%) 10.51 10.68 10.66 10.66

Annual Capital Cost 145 153 161 105

Fixed Annual O&M 50 50 50 15

Total Annual Charges ($/kw yr) 195 203 211 120

Levelized Average Cost ($/MWh) 49.4 59.3 63.3 41.3

PTC Rate ($/MWh) 45 23 23 23 NA

PTC Level (%) 80 80 80 NA

Levelized Cost ($/MWh) 39.3 49.2 53.1 41.3

Source: ICF



Exhibit 29 Sensitivity Case - Wind Generation Costs at Full PTC and 50% Capacity Factor (Not used in Base Case)

Parameter Wind

Capacity Factor 50

Capital Cost ($/KW) 1,380

ITC NA

Capital charge/Annualization Rate (%) 10.51

Annual Capital Cost 145

Fixed Annual O&M 50

Total Annual Charges ($/kw yr) 195

Levelized Average Cost ($/MWh) 49.4

PTC Rate ($/MWh) 45 23

PTC Level (%) 100

Levelized Cost ($/MWh) 31.8

Source: ICF

5.8 Total Gross Costs

Exhibit 30 summarizes the levelized cost of generation and transmission resources for each of the three

projects. Overall, NWC has a significant cost advantage due to the much lower transmission capital cost.

The total levelized cost of the NWC project is $75.6/MWh. TWE is 38% higher at $104.6/MWh, and SunZia

is 13% higher at $89.6/MWh.

Exhibit 30 Total Gross Costs – Base Case

Scenario Generation ($/MWh) Transmission ($/MWh) Total ($/MWh) (relative to NWC)

NWC 43.8 35.5 79.3

TWE 36.7 67.9 104.6 (+25.3)

SunZia 46.6 43.0 89.6 (+10.3)

Exhibit 31 shows the change in costs if Wyoming wind operated at a higher capacity factor than assumed

in the study. At a 50% capacity factor the levelized cost for Wyoming wind is reduced by approximately

$5/MWh to $31.8/MWh. Even under these more favorable conditions, NWC is still much lower cost than

the other projects.

Exhibit 31 Total Costs – Sensitivity Case with Wyoming Wind at 50% Capacity Factor

Scenario Generation ($/MWh) Transmission ($/MWh) Total ($/MWh) (relative to NWC)

NWC 43.8 35.5 79.3

TWE 31.8 67.9 99.7 (+20.3)



Sunzia 46.6 43.0 89.6 (+10.2)

5.9 Production Cost Savings

ICF used PROMOD to estimate the change in adjusted production costs for each project. APC refers to the

costs in CAISO plus imports at import prices and minus exports at export prices. This modeling captures

differences in the diurnal and seasonal output and accounts for economics of scale. The details of the

production cost modeling are explained in the methodology section. As shown, TWE has a $4 to 6 $/MWh

cost savings advantage when compared to NWC (see

Exhibit 32). SunZia also has a $2 to $6/MWh cost savings advantage.

Exhibit 32 Normalized Annual APC Savings 46

Scenario Year APC Savings ($ million)

APC Savings ($/MWh)

Average Savings ($/MWh)

NWC 2020 (100) (33.58)

38.4 2022 (96) (32.24)

2025 (116) (38.95)

2030 (149) (50.03)

TWE 2020 (223) (37.71)

44.6 2022 (231) (39.07)

2025 (269) (45.49)

2030 (331) (55.98)

SunZia 2020 (244) (35.34)

42.1 2022 (253) (36.74)

2025 (280) (40.61)

2030 (385) (55.78)

5.10 Net Costs of the Three Alternatives

The main quantitative conclusion of the analysis is that NWC is the most cost effective project per MWh

at $41.0/MWh before REC revenue. TWE costs approximately $19/MWh or 47% more, and Sunzia

approximately $6.5/MWh or 15% more. The transmission cost advantage of NWC offsets the cost

advantages of TWE and Sunzia in generation costs and production cost savings. Put another way, in spite

of the differences in the mix and type of renewables, and the adjusted production cost savings, in spite of

lower renewable costs and economies of scale in transmission, NWC is by far the least cost option of the

three.

46 The total annual renewable output of NWC is 2.978 million MWh. TWE output is 3.942 million MWh. We multiply the output of NWC divided by the output of TWE times the savings to obtain the normalized savings. Alternatively, we can simply calculate the per MWh savings of each project which is also shown.



Transmission - The transmission capital costs of NWC were much less than that of TWE and

SunZia. The capital costs are higher for the TWE and Sunzia projects by a factor of 2.8 to 3.8 or

$2.3 billion to $3.7 billion. On a per MWh basis, TWE is 1.9 times the cost of NWC, or $32.4/MWh

higher. SunZia is 1.2 times the cost or $7.5/MWh higher. The per MWh premium is smaller than

the capital cost premium due to economies of scale, but even so the cost is still much higher.

There is significant uncertainty in transmission costs especially for Sunzia. The costs used are

scoping level because TWE and SunZia do not estimate the full costs of transmission to deliver

into California. In order to breakeven with NWC, Sunzia transmission costs have to decrease by

$480 million (13%), and TWE costs would have to decrease by $1.4 billion (28%).

Generation - NWC has an average cost of $43.9/MWh, or approximately $7/MWh higher at full

PTC and ITC than TWE. This is small compared to the approximately $36/MWh transmission cost

premium of TWE. NWC has a $3/MWh premium over SunZia, in addition to a $48/MWh

transmission cost premium.

Production Cost Savings – TWE has a $6/MWh cost savings advantage. Again, this is small

compared to the $36/MWh generation and transmission cost premium. SunZia’s $4/MWh

production cost savings advantage is also insufficient to offset the approximately $10/MWh

generation and transmission cost premium.

Exhibit 33 Net Cost Comparison for the Three Scenarios

Project Transmission and Generation Costs

($/MWh)

Average Production Cost Savings

($/MWh)

Net Costs ($/MWh)

Increase over NWC

($/MWh)

NWC 79.4 38.4 41.0 N/A

TWE 104.6 44.6 60.0 19.0 (+47%)

Sunzia (assumed to sink in California)2

89.6 42.1 47.5 6.5 (+15%)



6. Qualitative Considerations for comparative assessment

There are also qualitative considerations favoring NWC project:

Shorter Distance - NWC may be easier to implement because it is shorter than the other two.

Total distance is much less, not only facilitating lower capital costs but also potentially significantly

easier siting permitting and cost allocation.

Possible Less Lead Time and Federal Incentives - Transmission lead times can be very long, and

lead time could be especially important if the federal incentives for renewables expire before the

projects come on line. NWC is less complex and smaller and might have lower lead time risk.

All CAISO Project - NWC also has the advantage that it is entirely within the CAISO system and

hence similar to other transmission projects pursued by CAISO as opposed to inter-regional

projects which are a newer phenomenon. The well-trod path of all CAISO projects simplifies

planning, siting (fewer states), permitting, and allocation of costs compared to the other two

projects which involve more states, regions outside CAISO, subject to newer less tested inter-

regional cost allocation rules. They are not part of an ISO, and rely more on relatively untested

regional planning entities to recognize the system wide benefits of competition, reliability and

integration.

Fewer States – NWC is entirely within just two states, Nevada and California, while the other

projects involve generation and transmission projects traversing more states.

Solar ITC Schedule More Robust - NWC delivers mostly solar power, and hence, there is a longer

“runway” for the ITC than the PTC. The ITC is still at full value for projects qualifying for 2020

vintage ITC, and never goes to zero under current legislation. In contrast, the PTC value is zero

for projects qualifying with the vintage year of 2020 or later. This issue is complicated, as discussed

below, because of grandfathering of projects based on start of construction, and other factors.

This is not reflected in the quantitative analysis which assume s all renewables receive full federal

support.

Potentially Less Grandfathering Risk - Also, in general, renewable projects grandfathering status

- i.e. the ability to be under construction over 4 years, and still qualify for the PTC or ITC level

available as of the start of construction - hinges on Internal Revenue Service (IRS) rulings, not

explicit statutory language, and hence, alacrity in compliance avoids the albeit small risk of loss of

grandfathering status.

First Non-California CAISO Member - NWC represents the first major renewables project with

VEA, the only non-California entity to join CAISO (VEA joined CAISO in 2013). Therefore, it

positively reinforces integration and the goal of California that its ISO have economies of scale. It

is already wholly contained within the CAISO footprint, compared to the other projects which

cross numerous states and not within the CAISO footprint.

Added Looping - NWC also strengthens the California grid on the eastern side of the Sierra

Nevada, and has the optionality of facilitating access to geothermal and other resources in this

area. In contrast, the other two projects originate in non-CAISO and entirely in non-ISO/RTO

regions.



7. Conclusions

7.1 Summary

ICF study compared generation cost, transmission cost, and production cost benefits of NWC to TWE and

SunZia. All three projects are assumed to provide their own dedicated firm transmission capability to

deliver directly into California (SP-15) as RPS Category 1 resource. The quantitative analysis and

qualitative considerations support the conclusion that NWC is the best option among the three projects.

Lower transmission costs and attractive mix of renewables gives NWC the edge among the three

projects.

Exhibit 34 ICF Analyzed Three Projects

7.2 Quantitative Considerations

The study shows that Nevada West Connect (NWC) to be a lowest cost option among the three to firmly

deliver out of state renewables to Southern California; NWC costs less than TWE and SunZia transmission

projects. NWC project’s transmission costs are much less than its competitors primarily because the

distance is less. NWC involves 500 miles of additional transmission line construction (350 miles in western

Nevada and an additional 150 miles to deliver into California). The TWE projects is around 800 miles (with

730 miles of HVDC from southern Wyoming to Nevada (El Dorado) and 150 miles AC line from Nevada (El

Dorado) to California). The SunZia is around 875 miles (515 miles from New Mexico to Phoenix, Arizona

and 360 miles Arizona to California).

Exhibit 35 Capital Costs Comparison of the Three Projects

Project

Name

Total Capital Costs

($ million)

Renewable Capacity

Enabled (MW)

Renewable Generation

(million MWh)

Capital Cost

($/MWh)1

NWC 1,327 1,000 3.0 35.5

TWE 5,000 1,500 2 5.9 67.9

Sunzia 3,656 2,000 6.8 43.0

1 ICF used an 8% annualization rate (CCR) and a 40 year amortization schedule 2 TWE is expected to deliver an initial capacity of 1,500 MW of wind generation in an initial phase, increasing to 3,000

MW. For this study, ICF modeled 1,500 MW and normalized costs and benefits



The very large transmission cost advantage of NWC is only modestly offset by NWC’s higher renewable

costs (see Exhibit 36). NWC’s 75% solar and 25% wind generation mix is modestly more costly than TWE

and SunZia wind generation, but NWC’s total costs are still much lower due to much lower transmission

costs. Also, NWC enhances the fuel mix as the only option that enables a balanced portfolio – solar, wind

and potentially nearby geothermal resources.

Exhibit 36 Renewable Mix Enabled for the Three Projects

Project

Solar Capacity

(MW)

Wind

Capacity

(MW)

Total Renewable

Generation Capacity

(MW)

Average Capacity

Factor

(%)

Annual

Renewable

Energy

(TWh)

NWC 750 250 1,000 34 3.0

TWE 0 1,500 1,500 45 5.9

SunZia 0 2,000 2,000 39 7.8

Note: Average capacity factor for NWC is 34%. This is the weighted average capacity factor for 750 MW of solar at

33% capacity factor and 250 MW of wind at 38%.

ICF modelled WECC grid operations, to calculate the decrease utilization of other generation and

associated cost savings from decreased operation of fossil fuelled power plants. Renewables lower the

use of fossil fuels for power generation. ICF’s modeling accounts for different daily and seasonal patterns

of renewables. Modeling also accounts for each generator and transmission line. The production cost

savings confirms NWC’s edge as a least cost option of the three projects. Also, the very large transmission

cost advantage of NWC is only modestly offset by NWC’s lesser production cost savings (see Exhibit 37

and Exhibit 38).

Exhibit 37 Total Costs Comparison for the Three Projects

Scenario Generation ($/MWh) Transmission ($/MWh) Total ($/MWh)

(relative to NWC)

NWC 43.8 35.5 79.3

TWE 36.7 67.9 104.6 (+25)

SunZia 46.6 43.0 89.6 (+10)

Exhibit 38 Net Costs Comparison for the Three Projects

Project Project Costs –

Transmission and

Generation ($/MWh)

Production Cost Savings

($/MWh)

Net Costs – Project Costs less

Production Cost Savings

($/MWh)

NWC +79.3 -38.4 41.0

TWE +14.6 -44.6 60.0 (+19)

Sunzia +89.6 -42.1 47.5 (+7)

Thus, in spite of factors favoring the other projects such as greater size and potential economies of scale

and higher renewable capacity factors favoring the other two transmission projects, NWC costs are less.



7.3 Qualitative Considerations

Qualitative considerations reinforce project economics favoring NWC. NWC has the advantage of being

the only project that is wholly in CAISO, and also the only one that enables a balanced portfolio (see Exhibit

39). Qualitative factors also include shorter routing and easier implementation also favors the NWC

project. The key factors favoring the NWC project are summarized below:

Exhibit 39 Qualitative Advantages of NWC Project



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