CT v.3
CPUC GHG Modeling
10/25/07
New Natural Gas Combustion Turbine Generation
Resource, Cost, and Performance Assumptions
Current Status of Technology
Natural gas-fired generation currently provides 35-45% of the electricity used to serve
California loads, depending on hydro conditions and the method used to assign
generation to imports.1 Within the WECC as a whole, natural gas-fired generation
constitutes about one-quarter of the total electricity supply.2 Natural gas is used in base
load, intermediate cycle, and peaking units. In California, less than one-quarter of natural
gas generation comes from combustion turbines (CT) operated primarily as peaking units.
Natural gas combustion is the second most important source of GHG emissions in the
electricity sector after coal, with a typical value of 117 pounds of CO2 emitted per million
Btus of natural gas burned. Lifecycle GHG emissions from upstream and downstream
processes such as plant construction and natural gas extraction are not included in the
California emissions inventory, while methane (CH4) emissions from the transport of
natural gas are included but not in the electricity sector inventory. Within the WECC,
natural gas-fired generation is currently responsible for about 25% of total sector
emissions. Determining the natural gas emissions for which California loads are
responsible is a difficult question that depends on the method used to assign generation to
imports, but natural gas under known California ownership and long-term contracts
produces about 35% of electricity sector emissions in the latest draft California Emissions
Inventory, and could be more than 50%.3
The state of California is currently addressing the question of the plant retirement
schedule for older and relatively inefficient natural gas plants, many of which are
essential to power system reliability due to their location within load pockets (see Plant
Retirements and Repowering Report). New environmental requirements associated with
cooling water will not affect CTs, which have low water use.
The two basic classes of gas turbines are aeroderivative machines and industrial machines
(also called “frame” or “heavy duty” turbines). Aeroderivative turbines, as the name
suggests, are derived from the gas turbine engines used for aircraft. They are
characterized by light weight, relatively high efficiency, quick startup, rapid ramp rates
1
The CEC 2006 Net System Power Report shows 106.968 GWh of specified natural gas generation, and
15,258 GWh of natural gas in unspecified imports, out of a total gross system power of 294,865 GWh in
2006. Under the reporting methodology of Griffin and Murtishaw, the presumed share of natural gas
generation in unspecified inputs is substantially larger, and coal and hydro proportionally less.
2
CEC 2007 IEPR Scenarios, 2009 Scorecard.
3
For 2004, the most recent year included in draft inventory, natural contributed 35.1 million metric tons
out of a total of 100.1 million metric tons of GHGs generated to serve California loads (CARB 2007,
calculation by author.) If the Net System Power generation figures are used, they imply emissions from
natural gas of 51.4 million metric tons (for an assumed average heat rate of 8,000 Btu/kWh).
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CPUC GHG Modeling
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and ease of maintenance. Aeroderivative turbines tend to be more costly than industrial
machines because of more severe operating conditions and more expensive materials.
Industrial gas turbines are designed for extended high-output duty. They are
characterized by heavier components, somewhat lower efficiency, slower startup time,
slower ramp rates and more complex maintenance procedures.
Reference Case Resource, Cost, and Performance Assumptions
Table A gives the reference case resource, cost, and performance assumptions for new
natural gas combustion turbine generation used in the GHG calculator. The reference
technology to which these assumptions apply is a new 160 MW CT.4 These costs do not
apply to as yet uncommercialized advanced CTs.
The values in Table A are largely derived from the EIA’s Annual Energy Outlook 2007,
which is considered a relatively unbiased source for new technology cost and
performance estimates. However, AEO 2007 costs are generally too low, as they do not
reflect recent capital cost increases resulting from higher materials costs and unfavorable
exchange rates. The Table A reference case values are adjusted to reflect these
increases.
The natural gas fuel resource is assumed to be unlimited. The base capital cost for new
CTs is $673/kW, prior to applying zonal cost multipliers (see Table B) and adjustments
for financing costs during construction (see “Financing and Incentives” report). This
value is based on the AEO 2007 total overnight cost assumption, adjusted for inflation
and recent increases in the cost of materials. Reference case non-fuel variable O&M
costs are $3.62/MWh and fixed O&M costs are $12.28/kW-year.
The reference case performance values are a heat rate of 10,807 Btu/kWh (which follow
the AEO 2007 assumptions) and a capacity factor of 5% (which is based on the CEC
2007 Cost of Generation Draft report). 5
Table A. Natural Gas CT Cost, Resources, & Performance
2008 value
2020
reference
case value
(in 2008$)
2020 tech
growth case
4
Range of
2008 values
in model
Sources
EIA AEO Assumptions 2007, Table 39.
The nominal capacity factor of 5% is only used for ranking of potential new resource additions based on
levelized costs (see “Resource Ranking and Selection” report). In the GHG model, production costs depend
on the dispatch of each generating unit in the production simulation, which may be very different from the
nominal capacity factor.
5
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CT v.3
CPUC GHG Modeling
10/25/07
Base
overnight
capital cost
($/kW)
$6731
$673
$673
$619 - $8072
AFUDC
Multiplier (%)
Non-Fuel
Base Variable
O&M
($/MWh)
Base Fixed
O&M
($/kW-yr)
Gross resource
in WECC
(MW)
Filtered
resource in
CA (MW)
Filtered
resource in
WECC (MW)
Nominal Heat
Rate
(BTU/kWh)
Capacity
factor
(%)
114.9%
114.9%
114.9%
114.9%
$3.623
$3.62
$3.62
$3.62
$12.283
$12.28
$12.28
$11.29 14.732
[EIA, 2007]
No limit
applicable.
No limit
applicable.
No limit
applicable.
No limit
applicable.
[n/a]
No limit
applicable.
No limit
applicable.
No limit
applicable.
No limit
applicable.
[n/a]
No limit
applicable.
No limit
applicable.
No limit
applicable.
No limit
applicable.
[n/a]
10,807
10,807
10,807
10,807
[EIA, 2007]
5%
5%
5%
5%
[CEC 2007
Beta Model]
Reference
case:
[EIA, 2007]
Tech growth
case:
[Assumed no
net change]
[CEC 2007
Beta Model]
[EIA, 2007]
Notes:
1
Base value originally reported in 2005$ in EIA AEO 2007. Cost has been adjusted (a) from 2005$ to
2007$ at rate of 25% per year to account for recent price escalation, and (b) from 2007$ to 2008$
at general inflation rate of 2.5%.
2
Capital costs and fixed O&M costs in model vary by region, based on state-specific factors from US Army
Corps of Engineers, Civil Works Construction Cost Index System (CWCCIS), March 2007. Lowest
multiplier for region in WECC is WY (0.92); highest multiplier is CA (1.20)
3
Fixed and Variable O&M cost originally reported by EIA in 2005$. Costs have been adjusted from 2005$
to 2008$ at general inflation rate of 2.5%.
Zonal Levelized Costs
Table B shows reference case levelized costs for new CT generation in each of the 11
WECC zones used in the GHG calculator. They are derived by applying zonal cost
multipliers from the U.S. Army Corps of Engineers to the base generation and O&M
costs in Table A, along with financing costs during construction, and are calculated based
on merchant financing assumptions. Table B also shows reference case fuel cost
assumption ranging from $7.14 to $8.50 per million Btu across zones (see Fuel Cost
Assumptions Report). The reference case range of busbar levelized cost of energy
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(LCOE) for CTs in the WECC is $77-91/MWh. Other costs associated with new CT
generation in addition to busbar costs, for example the costs of transmission
interconnection, are covered in separate reports.
Table B. Natural Gas CT Levelized Cost by Zone
Zonal Cost
Multiplier
1.00
1.00
Capital Cost
($/kW)
$673
$673
Fixed O&M
($/kW-yr)
$12
$12
Fuel Cost
($/MMBTU)
$7.15
Capacity
Factor
Range
5%
5%
AZ-S. NV
1.00
$673
$12
$8.29
5%
$421
n/a
BC
1.00
$673
$12
$7.35
5%
$411
n/a
CA
1.20
$807
$15
$8.46
5%
$489
n/a
CFE
1.00
$673
$12
$8.45
5%
$423
n/a
CO
0.97
$652
$12
$7.18
5%
$399
n/a
MT
1.02
$686
$13
$7.14
5%
$415
n/a
NM
0.96
$646
$12
$7.97
5%
$405
n/a
N. NV
1.09
$733
$13
$8.50
5%
$453
n/a
NW
1.11
$747
$14
$7.25
5%
$446
n/a
UT-S. ID
1.00
$673
$12
$7.31
5%
$410
n/a
WY
0.92
$619
$11
$7.14
5%
$382
n/a
Resource
Zone
Base Value
AB
Busbar LCOE
Range
Net Resource
($/MWH)
Potential (MW)
n/a
$409
n/a
Notes:
1
All values shown in 2008$.
2
Capital Cost and Fixed O&M Cost by zone are calculated by multiplying base value for cost by the zonal
cost multiplier.
3
Fuel costs are for 2020, and shown in 2008$. Data from 2005 SSG-WI database, and have been inflated
(a) from 2005$ to 2008$ at general inflation rate of 2.5%, and (b) from 2005 to 2020 at an annual fuel price
escalation rate of 3% real. For resource zones containing multiple SSG-WI regions, fuel costs are have
been averaged.
4
Levelized Cost of Energy (LCOE) is calculated using cost and performance data from this table, as well
as: (a) financing during construction cost multiplier and non-fuel variable O&M costs (which is assumed
not to vary by region) from preceding table, (b) insurance of 0.5% of capital cost, (c) property tax of 1% of
capital cost, and (d) income tax liability.
Benchmarking of CT Costs
Levelized Costs
As noted in Table B, the GHG calculator uses a busbar LCOE of $489 for a CCGT in
California (2008$). Table C below compares the GHG Calculators busbar levelized cost
for California to the latest levelized costs estimates (with merchant financing) from the
CEC’s Cost of Generation model, as reported by CEC staff (and adjusted here to 2008$).
The fixed cost portion of the levelized cost estimate from CEC is lower than the CEC
cost estimate.
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CPUC GHG Modeling
10/25/07
Table C: LCOE Benchmarking Comparison (2008 $/MWh) – Merchant Financing
Source
Plant
Capital
Fixed O&M
Taxes & Insurance
Total Fixed
Fuel
Variable O&M
Total Variable
Total
GHG Calc
(Busbar)
160 MW
Conventional
(in CA)
$272.94
40.48
80.00
$393.42
91.47
3.62
$95.09
$488.51
CEC COG
100 MW
Conventional
$512.99
$114.74
$627.73
Notes:
1
All values shown in 2008$. CEC values have been adjusted from 2007$ to 2008$ using general inflation
rate of 2.5%.
2
CEC is currently updating its Cost of Generation model, and values shown here were provided by CEC
staff as most recent estimates.
3
The GHG Calculator values have been adjusted upward using the zonal multiplier for California (1.2), and
represents a busbar cost estimate that does not include expenses for interconnection or emission
allowances. See table D below
Capital Costs
Table D explores these differences in capital cost between the models. The CEC model’s
total includes interconnection costs and environmental permits that are not included in the
GHG Calculator’s busbar cost estimate. The GHG Calculator’s installed cost estimate of
$927 is in a near range to the base value from the CEC model of $966 when those other
items are excluded.
Table D: Capital Cost Comparison (2008 $/kW) 1
GHG Calc
GHG Calc CEC COG
Component
(overnight)
(installed)
(installed)
2
Base
$807
$927
$966
Interconnection
35
Env. Permits
25
TOTAL
$1025
Notes:
1
All values shown in 2008$. CEC values have been adjusted from 2007$ to 2008$ using general inflation
rate of 2.5%.
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CT v.3
CPUC GHG Modeling
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2
The GHG Calculator overnight cost is taken from Table B, and represents the EIA 2007 AEO value,
adjusted for recent cost escalation and for the California regional cost multiplier of 1.2. The GHG
Calculator installed cost represents the overnight cost multiplied by the financing during construction
multiplier of 114.9% Both GHG Calculator costs represent cost at the busbar, and therefore do not
include interconnection or permitting costs.
Capital Costs and Performance Characteristics
Table E below compares the GHG Calculator’s reference plant costs and performance
characteristics to those provided from other models. The plant used in the GHG
Calculator is assumed to have the same capacity factor of the plant in the CEC model
(5%). This value is in the same range as the estimate for peaking plants from the
Northwest Power and Conservation Council’s (NWPPC) 5th Power Plan (10%). Cost and
other data are included below for the GHG Calculator, the EIA AEO 2007 data (for
Conventional and Advanced CTs), the 2004 MPR, the CEC COG model, and the
NWPPC’s estimates. All data have been converted to 2008$ for ease of comparison.
Table E: CT Assumptions Comparison –EIA, MPR, CEC, NWPCC (2008$)
EIA – Conv.
160 MW
Conventional
CT
EIA –
Adv.
230 MW
Advanced
CT
2004
MPR
n/a
$807
(CAspecific
plant)
$927
(CAspecific
plant)
$452
$422
$599
Capacity
Factor
5%
30%
30%
$966
(base)
$1025
(incl.
interconn. and
env. permits)
5%
Fixed O&M
($/kW-yr)
$15
(CAspecific)
$3.62
(All
zones)
10,807
$12.28
$10.67
$7.31
10%
(for peaking
service)
$9.75
$3.62
$3.21
$26.40
$9.75
10,807
(2006 order
date)
9,166
(2006
order date)
9,266
New:
 9,900
Lifetime
Average:
 9,960
Industrial
Lifetime
Average:
 10,500
Source
Plant
Description
Overnight
Capital Cost
$/kW
Installed
Capital Cost
$/kW
Variable
O&M
($/MWh)
Heat Rate
(Btu/kWh)
GHG
Calc
160 MW
CT
6
9,662
(new
plant)
CEC COG
100 MW
Conventional
CT
2004 NWPPC
(2 x 47 MW)
Twin
Aeroderivative
Gas Turbines
such as GE
LM6000
$731
CT v.3
CPUC GHG Modeling
10/25/07
2003n/a
n/a
-0.5%/year
2010:
(5% learning
-0.54%
rate)
20032025:
-0.22%
2003-2010:
2003n/a
n/a
-0.5%/year
Technology
-1.02%
2010:
Vintage Cost
2003-2025:
-0.49%
Change
0%
20032025:
0%
1
All values shown in 2008$. CEC values have been adjusted from 2007$ to 2008$ using general inflation
rate of 2.5%. 2004 MPR values and EIA are adjusted from 2005$ to 2008$ at 2.5% per year. NWPCC
values are adjusted from 2000$ to 2008$ at 2.5% per year.
Heat Rate
Improvement
2003-2010:
-0.23%
2003-2025: -0.20%
Sources
California Air Resources Board, Draft California Greenhouse Emissions Inventory,
August 2007.
California Energy Commission, “2006 Net System Power Report,” CEC-300-2007-007,
CEC Staff Report, April 2007.
California Energy Commission, Beta Model for “Comparative Costs of California
Central Station Electricity Generation Technologies,” June 2007.
California Energy Commission, “Comparative Costs of California Central Station
Electricity Generation Technologies,” CEC-200-2007-011-SD, CEC Staff Report, June
2007.
http://www.energy.ca.gov/2007publications/CEC-200-2007-011/CEC-200-2007-011SD.PDF.
U.S. Energy Information Administration, “2007 Annual Energy Outlook, Electricity
Market Module Assumptions,” DOE/EIA-0554, April 2007.
http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf.
Northwest Power Conservation Council, “The Fifth Northwest Electric Power and
Conservation Plan,” July 2005.
http://www.nwcouncil.org/energy/powerplan/plan/Default.htm.
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