Transmission Costs v.2
CPUC GHG Modeling
10/31/07
CPUC Greenhouse Gas Modeling
Transmission Cost Assumptions
Transmission Costs in the GHG Model
Transmission upgrades can be a significant contributor to the cost of new generation,
especially for resources that are in remote or transmission-constrained locations. The
GHG model includes two different components of transmission upgrade cost:
(1) The costs of generation interconnection or “collector systems” – transmission that is
radial to the main transmission grid and that collects energy produced by generators and
transmits it to a higher voltage, backbone facility
(2) The costs of main grid upgrades or “trunk lines” – the higher voltage facilities
necessary for transmitting large amounts of power over long distances.
The GHG model assumes that generation interconnection facilities are financed by the
generation owner, while main grid upgrades are network upgrades that use investorowned utility financing.
New studies of potential transmission upgrades to facilitate the development of lowcarbon generation resources are outside the scope of the GHG modeling project, so
transmission costs for both trunk lines and collector systems were developed on the basis
of previous studies and accepted engineering-economic rules of thumb. However, the
methodology for estimating the cost of transmission upgrades is currently under review to
ensure that consistency with other costing methodologies used in the GHG model, and
particularly to ensure that transmission costs reflect the recent, dramatic inflation in the
cost of steel and other raw materials.
For transmission within California, assumptions about costs and potential routes and
capacities are discussed in the next section. For interstate transmission WECC regions,
including California, the assumptions are discussed in the subsequent section.
Transmission within California for Renewable Resources
In the GHG model reference cases, it is assumed that renewable resources will be
obtained within California (and closely bordering areas such as northern Baja California
(CFE) and the Reno, Nevada area) only, and that trunk lines to obtain renewable
resources from distant regions are not built. The main assumptions regarding the
transmission routes, line capacities, and costs necessary to provide access to the resources
in different renewable resource zones within the state are shown in Table 1 below. (The
development of zonal resource supply curves for new generation within these zones is
discussed in the section on “Resource Ranking and Selection.”)
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Transmission Costs v.2
CPUC GHG Modeling
10/31/07
The basis for cost estimation is shown in the “Cost Notes” column of Table 1. In many
cases, costs are based on existing transmission studies, adjusted for inflation. In a few
cases, costs are based on measured distances between resource zones and load centers, to
which rule of thumb estimates were applied. These rules of thumb are shown in Table 2
and Table 3.
Table 1. California Transmission in the Reference Case
Interconnection
Point
Geothermal and
Wind Sites in
Shasta, Lassen,
Modoc, and
Siskiyou Counties
Cluster Name
Northeast CA
Counties
Siskiyou,
Shasta,
Modoc,
Lassen
Geysers/Lake
Lake,
Colusa,
Sonoma
Geothermal and
Wind sites in Lake
& Colusa Counties
(and on Sonoma
Border with Lake
County)
Vaca-Dixon
Substation
$58
Bay Delta
Solano,
Alameda,
Contra
Costa,
Marin
Kern
Solano and
Alameda Wind
Sites
Vaca-Dixon
Substation &
Altamont
Substation
$218
Source: CRS, p.66 (adjusted to
2008$).
Tehachapi Wind
Sites
Pardee/Vincent
$2,282
Source CRS, p.65 (adjusted to
2008$).
San
Bernardino
San
Bernardin
o
Mountain Pass & 2
new substations
along the way
Lugo
$1,718
Mono/Inyo
Mono,
Inyo
Lundy/Mono/Lee
Vining
Lugo
$432
Assumed two 500 kV AC
transmission lines with a length
of 200 miles. Cost = (200 miles
X $2.15 million per mile X 2
circuits) + (4 line terminations,
series capacitor banks and svc
x (26M+10M+30M) Plus 3
collection subs x 4 spokes per
sub of 230 kV line,
CPUC 2003 Transmission
Study for picking up 580 MW of
Solar Thermal, Wind,
Geothermal from Mono/San
Bernardino total (removed costs
for lines & substation going
west to El Dorado)
San Diego
San
Diego
East San Diego
wind sites
San Diego (SWPL
Substation)
$191
Tehachapi
Delivery Point
Round Mountain &
Cottonwood
Substations in
Shasta County
Total
Cost
($MM
2008)
$263
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Cost Notes
Source: CRS, p.66, for 295 MW
geothermal for geothermal
(adjusted to 2008$). Added (3 x
$1.1M/mile for 230 kV x 50
miles) + (3 x 2 x 10M each for
line terminations) for
interconnection of wind ~700
MW.
Assumed Upgrade of Geysers
to Vaca-Dixon, per North
Geysers transmission upgrade
environmental study. Distance:
30 mi. Cost = ($1,600/MW-mi X
400 MW X 30 mi). Added
($1,600/MW-mi X 300 MW X 50
mi) for wind interconnection.
Source: CPUC Transmission
Study 2003, p.90 (Adjusted to
2008$). Value has been
doubled to account for doubling
the capacity.
Transmission Costs v.2
CPUC GHG Modeling
10/31/07
Imperial
Imperial
Imperial
San Diego
$1,269
Source CRS, p.65 (adjusted to
2008). Plus $44.2MM for Path
42 upgarde -- Source: SDG&E
10/30/2006 IV Bank 82 Addition
Presentation, recommended
option.
CA Distributed
Entire
State
Biomass/Biogas
sites
Local regions
throughout CA
$61
Assumed interconnection for 36
x 25 MW biomass units in urban
area with 10 miles average gen
tie. Cost = ($1,600/MW-mi X 25
MW X 3 miles X 36 units) +
($1.5 million substation upgrade
X 36 units).
CFE
Northern
Baja
Rumorosa/Mexicali
Around Miguel
Substation
$1,269
Assumed same cost as Sunrise
line
Reno
Area/Dixie
Valley
All NV
Geo sites
Various Reno &
Dixie Corridor Sites
(a) Bordertown, NV
up to Malin Sub
then down to Tracy
Sub [1200 MW]
plus (b) Donner
Pass to Truckee
[500 MW]& (b)
PDCI tap near
Gerlach, NV
[400MW]
$1,169
Source: CRS, p.66 (adjusted to
2008$). Assume the existing
DC line can accommodate with
a new DC Substation and some
upgrades; Assumes both new
AC and PDCI tap in. Added
costs from Geothermex report
for collector to each of the sites.
Notes:
CRS = Center for Resource Solutions, Achieving a 33% Renewable Energy Target, prepared for
CPUC, November 2005
CPUC Transmission Study 2003 = CPUC Energy Division, Electric Transmission Plan for
Renewable Resources in California, December 2003
Table 2. Rules of Thumb for Transmission Capacity Estimates –
California-Only Case
Approximate Power Carrying Capability of Uncompensated
AC Transmission Lines (MW)
Nominal Voltage (kV) 
138
161
230
345
500
765
Line Length (Miles) 
145
195
390
1260
3040
6820
50
100
130
265
860
2080
4660
100
60
85
170
545
1320
2950
200
50
65
130
420
1010
2270
300
NA
NA
105
335
810
1820
400
NA
NA
NA
280
680
1520
500
NA
NA
NA
250
600
1340
600
Source: Russell and Craft, The Wheeling and Transmission Manual, 3rd Edition, Spectrum
Books, 1999.
Table 3. Rules of Thumb for Transmission Cost Estimates –
California-Only Case
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Transmission Costs v.2
CPUC GHG Modeling
10/31/07
Source: CEC, Scenario Analysis for 2007 IEPR, Table 4-3.
Trunk Line Transmission Costs between WECC Regions
The methodology for estimating trunk line transmission costs from other WECC regions
to California is still under development.
Generation Interconnection Costs
The GHG model contains six types of conventional resources and five types of renewable
resources. Costs for generation interconnection – transmission facilities that connect the
generator radially to the high-voltage, “backbone” grid – are estimated separately for
each type of resource. Each resource is assigned a distance from the backbone grid, and
is assessed the cost of building transmission over that distance. Interconnection costs are
assumed to be linear with the size of the generation resource, and a simple rule of
$1600/MW-mile is applied. Interconnection costs are also subject to the regional capital
cost multiplier.
Assumptions about distance to the backbone grid vary by resource type. For renewable
resources outside of California, the methodology for assigning transmission distances is
integral to the methodology for assessing resource availability, about which more details
can be found in the separate “Resource and Cost Assumptions” report for each
technology.
Conventional
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Transmission Costs v.2
CPUC GHG Modeling
10/31/07
The model assumes the following distances to the backbone transmission system for
conventional resources:


Nuclear and coal resources: 25 miles
CCGT and SCGT resources: 10 miles
Levelized interconnection costs for conventional resources range from $0.22 to
$0.77/MWh.
Wind
For wind resources, the GHG model uses the NREL transmission assignment method to
estimate collection costs for wind generation. This method estimates the total MW
capacity of all existing 69kV to 345 kV lines in each WECC zone based on the line’s
length and voltage, and assumes that 10% of the total capacity of each line is available
for transmission of new wind resources.1 Starting with the lowest cost wind resources,
the NREL optimization assigns wind resources of each wind class from individual grid
squares to the nearest transmission line until no available transmission capacity remains,
then moves to next nearest line. In the GHG model, the distances from the resource grid
squares to transmission were backed out from the NREL data, and used to estimate the
interconnection cost. In a few situations in which wind resources of Class 5 or higher
were not assigned to a transmission line through the NREL methodology, E3 manually
assigned the resource the highest transmission distance for any wind of the same region
and class that did connect to available existing transmission.
Concentrating Solar Power
The GHG model uses NREL zonal data for solar thermal resources to estimate
transmission interconnection costs for CSP. E3 used a web-based map from Idaho
National Laboratory to measure the distance from the center of the greatest resource
concentration within each NREL zone to the nearest transmission line with a voltage of
230 kV or higher.
Geothermal
In the GHG model, geothermal resources are identified on a site-specific basis. E3 used
the INL map to locate transmission lines and measure the distance from the site location
to the nearest transmission line with a voltage of 115 kV or higher.
Per NREL WinDS model description (http://www.nrel.gov/analysis/winds/transmission_cost.html), “The
transmission line capacity as a function of kV rating and length is drawn from Weiss, Larry and S.
Spiewak, 1998, The Wheeling and Transmission Manual, The Fairmont Press Inc., Lilburn GA.”
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Transmission Costs v.2
CPUC GHG Modeling
10/31/07
Small Hydro
In the GHG model, small hydro resources are identified on a site-specific basis. E3 used
the INL database and map to estimate the distance from potential hydro sites to
transmission, then used this to determine the average distance from the site location to the
nearest transmission line for all potential sites within each zone. Sites without specified
distances were assigned the maximum value of 25 miles when calculating the zonal
averages.
Biomass
Biomass was treated as distributed resource, with average interconnection distance of 25
miles.
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