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Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Gas Turbine/Solar Parabolic 

Trough Hybrid Designs

Preprint

Craig S. Turchi and Zhiwen Ma

National Renewable Energy Laboratory

Michael Erbes

Enginomix, LLC

To be presented at the ASME Turbo Expo 2011

Vancouver, Canada

June 6-10, 2011

Conference Paper

NREL/CP-5500-50586

March 2011
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1

GAS TURBINE/SOLAR PARABOLIC TROUGH HYBRID DESIGNS

Craig S. Turchi and Zhiwen Ma

National Renewable Energy Laboratory

Golden, CO, USA

Email: craig.turchi@nrel.gov, zhiwen.ma@nrel.gov

Michael Erbes

Enginomix, LLC

Menlo Park, CA, USA

ABSTRACT

A strength of parabolic trough concentrating solar power 

(CSP) plants is the ability to provide reliable power by 

incorporating either thermal energy storage or backup heat 

from fossil fuels. Yet these benefits have not been fully 

realized because thermal energy storage remains expensive at 

trough operating temperatures and gas usage in CSP plants is 

less efficient than in dedicated combined cycle plants. For 

example, while a modern combined cycle plant can achieve an 

overall efficiency in excess of 55%; auxiliary heaters in a 

parabolic trough plant convert gas to electricity at below 40%. 

Thus, one can argue the more effective use of natural gas is in 

a combined cycle plant, not as backup to a CSP plant. 

Integrated solar combined cycle (ISCC) systems avoid this 

pitfall by injecting solar steam into the fossil power cycle; 

however, these designs are limited to about 10% total solar 

enhancement. Without reliable, cost-effective energy storage 

or backup power, renewable sources will struggle to achieve a 

high penetration in the electric grid. This paper describes a 

novel gas turbine / parabolic trough hybrid design that 

combines solar contribution of 57% and higher with gas heat 

rates that rival that for combined cycle natural gas plants. The 

design integrates proven solar and fossil technologies, thereby 

offering high reliability and low financial risk while 

promoting deployment of solar thermal power.

INTRODUCTION

CSP plants use sunlight to heat a fluid that is used to drive a 

thermodynamic heat cycle, often a Rankine steam cycle. CSP 

technologies include parabolic trough, power tower and 

dish/engine systems. Parabolic troughs, represented by the 

SEGS plants in southern California, Nevada Solar One outside 

Las Vegas, and multiple plants in Spain, are the most mature 

CSP technology. The mirrored collectors track the sun from 

east to west during the day, to ensure that the sunlight is 

continuously focused on a linear receiver. A heat transfer fluid 

(HTF) is circulated through the receiver and returns to a series 

of heat exchangers in the power block where the fluid is used 

to generate high-pressure, superheated steam. The superheated 

steam flows to a conventional Rankine-cycle steam turbine to 

generate electricity, see Figure 1. Linear Fresnel systems are 

conceptually similar to parabolic trough plants but use a 

sequence of flat or near-flat mirrors instead of a parabolic 

collector.

Figure 1. Representation of a parabolic trough plant with thermal energy storage and auxiliary fossil backup. 

(Courtesy of Mike Wagner, NREL)

A solar power tower, also known as a central receiver, 

generates electric power from sunlight by focusing 

concentrated solar radiation on a tower-mounted heat 

exchanger that serves as the “receiver.” The system uses 

hundreds to thousands of sun-tracking mirrors called heliostats 

to reflect the incident sunlight onto the receiver. The HTF in a 

power tower is usually water/steam or molten nitrate salt. 

Power towers differ from troughs in their ability to achieve 

higher steam temperatures. Designs planned for the United 

States report steam conditions as high as 565oC and 140 bar, 

which is comparable to fossil-fired Rankine plants. While 

direct steam generation towers are simpler, towers using 
2

molten salt HTF can easily integrate thermal storage at 

minimal cost as shown in Figure 2. This efficient integration 

of energy storage is unique among renewable energy 

technologies.

Figure 2. Molten salt Power Tower [1].

The fourth major CSP technology uses a 2-axis tracking 

parabolic dish to continuously focus sunlight onto the receiver 

of a Stirling engine. Dish/engine systems range up to 25kW 

and large plants consist of thousands of units. The lack of a 

circulating HTF makes hybridization or integration of thermal 

energy storage difficult and these systems are not considered 

in the discussion here.

As noted above, parabolic trough, linear Fresnel, and power 

tower systems can integrate thermal energy storage by storing 

hot HTF directly or indirectly heating a storage media. These 

technologies can also utilize natural gas to aid system startup 

and provide backup power. Both features serve to convert the 

intermittent solar energy into a reliable, dispatchable resource. 

Thermal storage and fossil backup are valuable attributes of 

these CSP technologies. As shown in Table 1, thermal energy 

storage and fossil backup provide the same benefits with 

differing cost drivers.

Although TES and fossil backup provide similar benefits there 

are important distinctions between the two approaches. TES 

systems maintain a full solar fuel source, but require the 

installation of substantial hardware, especially for parabolic 

troughs and linear Fresnel systems. (Molten salt power towers 

use storage more efficiently because of their higher 

temperatures and can store salt by simply increasing their tank 

size and salt inventory.) The cost of tanks and storage media is 

not trivial, but the greatest increase to capital cost is the 

increase in solar field size required to provide the energy used 

to charge storage. In short, adding TES will substantially 

increase the installed cost of the solar plant. In addition, 

although conceptually simple, the TES technology is relatively 

new and entails an added risk for the project.

Table 1. Thermal energy storage and fossil backup both 

serve to increase reliability and dispatchability from the 

CSP power plant.

Attribute TES Fossil Backup 

(hybridization)

Generation during 

clouds

Yes Yes

Generation after sunset Yes Yes

Renewable energy 

source

Yes Solar fraction 

only

Technical risk Moderate Low

Capital cost High Low

Operating cost Low Function of gas 

price

In contrast, backup via fossil burners has a relatively low 

investment cost and is mature, low risk technology. While it

does not provide renewable power, the solar fraction of the 

total plant can still be quite high. The greatest downside to the 

use of natural gas in this fashion is the argument that it would 

be better burned in a dedicated combined-cycle power plant. A 

modern natural gas combined cycle (NGCC) plant can achieve 

thermal cycle efficiencies greater than 55% (heat rate less than 

6200 BTU/kWh); whereas a parabolic trough plant has a 

thermal cycle efficiency of less than 40%. The use of small 

amounts of gas backup may be justified by the investment in 

the solar plant infrastructure, but the economics of burning 

natural gas in auxiliary boilers falls rapidly as gas 

consumption increases.

Overview of Integrated Solar/Fossil Designs

Various types of integrated solar/fossil plants designs have 

been described and some ISCC systems have been built, for 

example the Martin Next Generation Solar Energy Center in 

Florida. In the 1990s Luz, the builders of the SEGS trough 

plants in California, proposed hybrid plant designs where solar 

steam would be used to supplement a combined cycle power 

plant. Under contract to NREL, Kelly and coworkers [2,3] 

examined the potential of such designs through a detailed 

analysis of power cycle performance using GateCycle. The 

studies focused on sizing equipment for extracting water from 

feedwater heaters to produce solar steam that was fed to the 

superheater along with the fossil-produced steam. Overall 

conclusions held that such a hybrid plant offered three 

advantages:

• Solar energy was converted to electric energy with an 

efficiency of about 39 percent; in contrast, the 

efficiency of the Rankine cycle plants was estimated 

at about 37 percent;

• The incremental unit cost for the larger steam turbine 

in the integrated plant was less than the overall unit 

cost in a solar-only plant; and 

• A hybrid plant did not suffer the thermal 

inefficiencies associated with the daily startup and 

shutdown of the steam turbine.
3

Nonetheless, the integrated concept did suffer from two 

distinct disadvantages. First, in the absence of the solar 

contribution the steam turbine operated at partial loads during 

cloudy weather and at night. Operation at partial loads caused

an increase in the fossil fuel heat rate, which effectively 

subtracted from the annual thermal contribution of the 

collector field to the heat recovery steam generator. Second, 

the annual solar contribution for plants was in the range of 

only 2 to 8 percent because higher contributions led to lower 

overall efficiency.

Recent work by the Electric Power Research Institute (EPRI) 

examined the optimum means for augmenting coal and NGCC 

plants with solar thermal energy [4]. While the EPRI study 

also examined feedwater extraction for solar steam 

production, the study highlighted the advantages of integrating 

solar steam into NGCC plants that are designed with gas-fired 

duct heaters between the gas turbine and boiler. Plants with 

duct firing are designed with slightly oversized steam turbines 

and the use of natural gas for duct firing is inherently less 

efficient than gas used in the gas turbine. In addition, most 

duct-firing occurs during hot afternoons that correspond to 

peak demand in the U.S. and lower gas turbine performance.

Thus, replacing gas-fired duct heating with solar thermal 

energy is a natural match.

EPRI’s analysis examined a host of different extraction and 

injection strategies for solar augmentation. The best cases led 

to improved solar use efficiency (versus a solar-only plant) 

and improvements in gas heat rate. In general, solar use 

efficiency drops and heat rate improves as the amount of 

injected solar thermal energy increases and the optimum 

combination for maximum solar contribution and efficiency 

occurred in the range of about 10% solar contribution. This is 

consistent with the design proposed for most ISCC projects in 

the United States.

Bohn and Williams [5,6] evaluated a molten salt power tower 

hybrid design that provides preheated combustion air to a 

conventional NGCC power plant. Three plants of capacities 

(30, 100 and 300 MWe) were examined and compared with a 

solar-only 100 MWe plant and with a NGCC plant of similar 

capacity. The work studied hybrid plant solar fraction, 

capacity factor, material cost, and fuel cost effects on 

economic competitiveness. The study concluded that the 

hybrid design was more cost effective than any of the solaronly configurations. Because of the higher temperatures 

required, this concept applies to power tower only.

The Solar Hybrid Gas Turbine Electric Power System 

(SOLGATE) uses a high temperature power tower for direct 

air heating to drive a gas turbine [7]. The design focused on 

concentrating collectors to generate air temperatures in excess 

of 1000oC through 3-stage heaters. SOLGATE uses solar 

energy to raise air temperature close to gas combustion 

temperature in a gas turbine combustor and then uses a booster 

burner to bring the gas temperature to a desired level for 

maximum efficiency. SOLGATE achieved 47.5% efficiency 

on a combined cycle configuration, or 37.3% in simple cycle 

with turbine exhaust heat recuperation. The solar contributions 

on both cases are high too, with 56.8% in combined cycle and 

35.04% for simple cycle. The concept is only applicable to 

power tower systems and has significant material challenges 

to handle the high solar fluxes; however, the combination of 

efficiency and solar contribution is promising. In general, the 

higher temperatures possible with power tower configurations 

grant them a greater potential for efficient hybridization.

Integrating Aeroderivative Turbines with CSP

Aeroderivative turbines offer a unique set of features for fossil 

backup of parabolic trough plants. (The concept described 

here is equally applicable the linear Fresnel systems, but 

further discussion will focus on the trough design.) As 

illustrated by Wacek and Ferguson [2], aeroderivative turbines 

excel at quick and frequent cycling. A 10 minute profile from 

cold-start to full load for a GE LM6000 is shown in Figure 3. 

The aeroderivative turbine heats up very quickly (less than six 

minutes) due to the low mass compared to a frame gas turbine. 

Ramping to full load takes about four minutes at a ramping 

rate of ~12MW/min. These attributes indicate that such 

turbines can transition from cold to full load in about 10

minutes, and cycle from standby to full load in just few 

minutes. Load following in time domains of seconds is also 

possible.

Figure 3. General Electric LM6000 Startup Profile [2].

Wacek & Ferguson highlight these characteristics in their 

discussion of the use of aeroderivative turbines as backup 

systems for wind farms. While such complementary operation 

is valuable, the turbines are not integrated with the wind 

generators and exist as totally separate generation systems

with no shared infrastructure. Representative GE 

aeroderivative turbine properties are given in Table 1; other 

turbine suppliers include Rolls Royce and Pratt & Whitney.

Table 1. Selected GE Aeroderivative Gas Turbine 

Specifications [9,10].

Model

Rated 

Power 

(MW)

Heat Rate 

(BTU/kWh)

LHV

Exhaust

Temp 

(C) Efficiency

LMS100DLE 100 7600 415 44.5%

LM6000PC 42.6 8323 451 41.1%

LM2500PK 30.7 8815 515 38.7%

Modern parabolic trough plants produce superheated steam at 

just under 390°C, while power towers can operate at steam 

temperatures near 560°C. As shown in Table 1, the exhaust 

heat from aeroderivative turbines would be a suitable source 

of backup heat for parabolic trough plants. This temperature 
4

match, combined with the rapid startup and load following 

capabilities of aeroderivative turbines makes them an excellent 

match for integration with a parabolic trough plant. In such a 

role the turbine provides backup heat and additional power, 

realizing the greater operational efficiency inherent in a 

combined heat & power system. This design largely 

overcomes the traditional complaint that gas use for CSP 

backup is inefficient.

The flexibility of the aeroderivative turbine allows for 

multiple hybrid configurations with parabolic troughs. One 

simple conceptual design for aeroderivative turbine backup of 

a parabolic trough plant is shown in Figure 5. The 

aeroderivative turbine is started when backup heat is 

anticipated. Within 10 minutes the system is at full power, 

providing power from its generator and enough thermal 

energy to the solar HTF to support operation of the steam 

cycle power block. The size and number of turbines can be 

varied as desired, but we will examine cases using relatively 

small turbines in order to maintain a high solar contribution. 

Based on this constraint, the aeroderivative turbine(s) are 

normally providing only a fraction of the full design thermal 

energy to the steam cycle. Depending on the design, this may 

or may not be sufficient to run the steam cycle without solar 

input.

A key design parameter for CSP plants is the solar multiple –

the ratio of solar field thermal energy to power block thermal 

demand at design point conditions. A trough plant without 

thermal energy storage is normally designed with a solar 

multiple between 1.2 and 1.5, assuming the reference solar 

conditions correspond to a clear summer afternoon for the site 

in question. A design using a solar multiple of 1.0 would be 

capable of design-point operation for relatively few hours per 

year (Figure 4, top), forcing part load steam turbine operation 

for the remainder of the year. Accordingly, trough plants are 

designed with a solar multiple greater than one. The greater 

solar multiple allows the plant to run at design point for a 

large fraction of the year, but necessitates dumping excess 

solar energy for much of the summer (Figure 4, bottom).

Figure 4 shows that a plant with a solar multiple equal to one 

will use all solar energy, but operate within 10% of design 

(>90 MW) for only 24% of its operating hours. In contrast, the 

design with a solar multiple = 1.4 runs near design point for 

approximately 60% of its operating hours, but must dump 

86,000 MWh of thermal energy over the course of the year. 

Using NREL’s Solar Advisor Model (SAM, version 2010-10-

08), one can show that despite costing approximately $100M 

to pay for the larger solar field (at default costs in SAM), the 

latter case provides the lower levelized cost of electricity. 

However, clearly neither is optimal. One path to avoid this 

difficulty is to install thermal energy storage, thereby avoiding 

the dumping of excess energy. This adds cost and complexity 

to the plant, and at current TES prices, slightly raises the 

LCOE for parabolic trough plants. The alternative described 

here is to use one or more aeroderivative turbines to fill-in the 

energy shortfall of the low solar multiple plant.

Figure 4. Net electricity production and dumped thermal 

energy for every hour of the year for 100 MW trough plant 

with a solar multiple = 1.0 (top) or solar multiple = 1.4 

(bottom).

Perhaps the simplest integration into a trough plant is to allow 

the turbine exhaust gases to heat the circulating HTF. This 

configuration is suited to “topping off” the thermal energy 

during cloud transients or less than ideal solar resource. This 

configuration would be a relatively simple retrofit for existing 

trough plants. Providing heat to the HTF facilitates the use of 

molten salt HTF in troughs or linear Fresnel systems because 

the exhaust heat from gas turbine provides sufficient energy to 

maintain the circulating salt at a temperature well above its 

freezing point. This design could run a small gas turbine 

overnight or during extended shutdowns to keep the molten 

salt at the desired temperature. Furthermore, molten salt HTF 

allows for easy integration of direct storage of the HTF for 

thermal energy storage, thereby opening new options for 

alternative operating modes and design optimization.

Waste heat from the turbines could provide thermal energy to 

keep the steam turbine and/or cooling system in a standby 

mode, thereby avoiding the need to break and reset steam seals 

overnight or during shutdowns. Conceptually this uses the gas 

turbine more like a combined heat and power system rather 

than a combined cycle system.

Improvements in cycle efficiency can be realized through a 

variety of alternative configurations. For example, gas turbine 

exhaust exiting the HTF heat exchanger may be used within 

one or more feedwater preheaters as shown in Figure 5. Gas 

turbine exhaust could be used to provide steam superheat or 

reheat. A reheat mode is attractive because it could extract a 

substantial fraction of energy from the turbine exhaust. Both 

superheat and reheat configurations would likely require the 
5

turbine(s) to run whenever the solar field is in operation. With 

multiple different configurations possible, a process 

performance model will be an essential tool in selecting and 

optimizing designs.

Lastly, while these designs are described for parabolic trough 

and linear Fresnel systems, it is possible that similar options 

could be applied to power tower CSP systems, especially if 

higher exhaust temperatures can be achieved from the gas 

turbines. The concepts could also be used with CSP plants 

using water steam HTF, that is, direct steam generation

systems.

Hybrid Plant Design

The thermal energy balance for the integration of 

aeroderivative turbines into a trough plant was undertaken 

using IPSEPro. The IPSEPro software package has 

components for solar troughs, Rankine steam cycles, and 

aeroderivative turbines. The IPSEPro simulation indicated a

single LM6000 turbine running at design could supply 

sufficient thermal energy for the equivalent of approximately 

10 MWe from the steam cycle when integrated via an HTF 

heater and feedwater heat exchanger (see Figure 5). For 

comparison, twin LM6000s can drive a 55-MW steam cycle 

when configured specifically for that purpose in GE’s 2-on-1 

combined cycle plant. The larger steam cycle contribution in 

the 2-on-1 plant design likely reflects the higher steam 

conditions and dedicated hardware yielding better heat 

recovery.

As the gas turbines become large relative to the steam cycle, 

their output dominates the total plant output. Their ability to 

respond to changes in solar energy is limited by the variation 

in total plant output caused by the gas turbine electric output. 

That is, starting 80 MW of gas turbines to respond to a 20 

MW drop in solar power may not be desirable. Because one 

goal of the hybridization is to minimize plant variability, a 

design was selected where the turbines are relatively small 

compared to the steam cycle. While the AGT waste heat 

maybe insufficient to run the steam cycle in the absence of 

solar energy, it is sufficient to preheat the steam turbine and 

provide freeze protection heating to the HTF.

The configuration used for the following analysis assumes a 

single GE LM6000 turbine combined with a 100 MW 

parabolic trough plant as depicted in Figure 5. A simpler 

configuration without use of an air-to-feedwater heater was 

also examined but ultimately discarded due to its lower 

thermal-use efficiency. The design included the following 

assumptions:

• a gas/HTF heat exchanger sized to produce 395°C oil 

matching the solar field exit design,

• a dedicated gas/water feedwater heater used downstream 

of the gas/HTF heat exchanger and sized to heat boiler 

feedwater to same temperature as the regular feedwater 

heater train,

• a feedwater heater based on steam turbine extraction 

flows (not shown in Figure 5) shuts off when the gas 

turbine is operating,

• a vacuum deaerator is used instead of an open feedwater 

heater using steam turbine extraction flow,

• back pressure on the turbine is increased by 4 inch water 

(10 mbar) to account for the downstream heat exchangers, 

and

• gas turbine output was derated based on ambient 

temperature for the site using the same weather file that 

supplied the hourly solar input and IPSEPro’s input for 

turbine performance as a function of temperature.

This design approach led to an operating strategy where the 

AGT is started prior to sunrise every morning, run at full load 

throughout the day, and shut down shortly after sunset (see 

Figure 6). A low solar multiple allows the contribution from 

the AGT waste heat to be incorporated into the steam cycle 

throughout most of the year, while rarely having to dump any 

solar energy.

RESULTS

Four different plant configurations were compared for the 

initial analysis. These included two solar-only plants without

storage and two solar trough / AGT hybrids. The designs are 

summarized in Table 2. Trough plant steam cycle performance

was modeled in SAM using Daggett, CA as the test site. The 

SAM fossil backup option was used to simulate the presence 

of waste heat from the AGT. Hourly net electricity, fossil 

energy consumption, and ambient temperature were exported 

from SAM to Excel where the hourly contribution from the 

AGT was added to arrive at total generation.

The total installed cost for the solar hardware was based on 

default values provided in SAM version 2010-10-08. These 

costs include combined solar field, site preparation and HTF 

System at $410/m2 and wet-cooled power block at $940/kWe. 

A 10% contingency and 24.7% indirect cost multiplier are 

applied to the direct costs. Gas turbine direct costs were 

assumed to be $900/kWe and the same contingency and 

indirect cost multipliers were used to arrive at an installed 

cost.

The first two plants in Table 2 are solar-only designs differing 

in the solar multiple. Case S1.4 costs $74M more than S1.1 

due to the larger solar field, but S1.4 produces 17% more 

energy over the course of the year and is able to run near 

design point for about 55% of its operating hours versus 36% 

for the smaller S1.1 plant. However, S1.4 has lower solar-use 

efficiency because it must dump sunlight during the summer. 

The LCOE for S1.4 is slightly lower, suggesting it is the 

favored solar-only design.

For the hybrid plants H1.1 and H1.2, operation of the gas 

turbine was nominally begun an hour before sunrise and ended 

an hour after sunset every day. Starting the AGT before 

sunrise allowed the waste heat to be used for steam turbine 

startup. The gas turbine was run at full load when used and the 

waste heat was incorporated into the steam cycle whenever 

there was sufficient capacity. Shutting off the AGT during 

high-insolation periods may improve its annual efficiency, but 

these periods often coincide with high demand and for this 

analysis the turbine was assumed to run throughout the day. 

Backpressure from the downstream heat exchangers lowered 

the AGT capacity from a nominal 40 MW to 37.8 MW.
6 

Table 2. Solar Only and Hybrid Configurations. 

Case

S1.1 S1.4 H1.1 H1.2

Solar 

Only

Solar 

Only

Solar + 

AGT

Solar +

AGT

Solar Multiple 1.1 1.4 1.1 1.2

Steam Turbine 

Capacity (MW) 100 100 100 100

AGT Capacity 

(MW) - - 37.8 37.8

Steam Turbine 

Annual Gen. 

(MWh) 210,300 245,900 231,000 244,100 

AGT Annual 

Gen. (MWh) - - 143,800 143,800 

Total Annual 

Gen. (MWh) 210,300 245,900 374,800 387,900

Solar Fraction 1.00 1.00 0.57 0.59

Annual solar 

efficiency 

(MWhe/MWh) 15.9% 14.5% 16.1% 15.7%

Total Installed 

Cost ($M) 410 484 459 485 

Effective heat 

rate (BTU/kWh) - - 7360 7460 

Gas 

Consumption 

(MMBTU/yr) - - 1,193,000 1,193,000

Total LCOE * 

($/MWh) 243 240 175 176 

Gas LCOE *

($/MWh) - - 105 105 

Solar LCOE * 

($/MWh) 243 240 228 226

* levelized cost of electricity, no incentives included

Comparison of heat rates indicates the benefit of integrating 

the gas turbines with the steam cycle. The heat rate for the 

LM6000 is about 8300 BTU/kWh, based on values reported 

by GE [1]. When the additional power production from the 

thermal contribution to the steam turbine is included, the 

effective heat rate drops to 7360 to 7460 BTU/kWh depending 

on design assumptions. The heat rate is slightly lower for the 

H1.1 case because the smaller solar field leaves capacity for 

the AGT heat in the steam cycle for more of the year. The low 

effective heat rate indicates that the goal of utilizing gas at 

efficiencies comparable to NGCC plants is possible.

A simple LCOE analysis is included in Table 2 based on an

8% real discount rate and 20-year analysis period giving a 

uniform capital cost recovery factor (UCRF) of 0.1018. Total 

20-year life cycle costs were multiplied by the UCRF and 

divided by annual energy production to yield LCOE [11]. 

Solar hardware O&M cost was calculated using SAM’s 

default value of $70/kW-yr. Natural gas price was set at 

$6/MMBTU and, like other O&M costs, was escalated with 

inflation. (Note: gas price is quoted based on higher heating 

value HHV, whereas values in Table 2 use lower heating 

value, LHV. Operating cost is adjusted to account for this 

difference of ~10%) The Solar LCOE for the hybrid plant is 

calculated by solving:

(LCOE)total = xgas * (LCOE)gas + xsolar * (LCOE)solar

where xgas and xsolar are the fractional contributions to total 

generation. No investment tax credits are applied in the LCOE 

calculations, but accelerated depreciation is used for the solar 

hardware. The LCOE and annual solar efficiency indicate that 

the hybrid plant is slightly more efficient in its use of solar 

energy. These costs are based on energy value alone and no 

credit has been given for the greater reliability/dispatchability 

of the hybrid plant.

A comparison of the hybrid H1.1 design and the solar-only 

S1.4 design reveals the following advantages of the hybrid 

system: 

 lower installed cost

 lower solar LCOE

 greater annual generation

 higher solar efficiency

 lower heat rate (vs. combustion turbine only)

While each of these benefits is relatively modest, combined 

they indicate a clear advantage for the hybrid design. In 

addition to these quantitative advantages, the hybrid system 

utilizes commercially proven technologies and provides 

greater dispatch reliability.

CONCLUSIONS

Solar/fossil hybrid designs reduce the impact of solar 

intermittency by providing either fossil backup to the solar 

plant or integrating solar output into a much larger fossil 

power installation. Hybrid designs utilize shared infrastructure 

that reduces the capital cost compared to separate stand-alone 

plants. However, traditional solar/fossil hybrid designs have 

been hampered by poor gas utilization efficiency and/or 

limited solar contribution. Incorporation of aeroderivative gas 

turbines overcomes these limitations and expands the hybrid 

design options available to developers.

In the preliminary analysis provided here, it is shown that a 

single 40-MW aeroderivative gas turbine mated with a 100- 

MW parabolic trough plant can be more efficient than two 

separate power plants. The estimated solar fraction for the 

concepts examined was 57% to 59%. The design utilizes 

proven parabolic trough and aeroderivative turbine hardware. 

While various integration schemes are proposed, this initial 

analysis looked at only one configuration. Further examination 

is expected to yield alternatives that provide greater operating 

or efficiency benefits than that described here.

Ongoing work is exploring alternative integration options by 

modeling in IPSEPro process simulation software. Results 

from IPSEPro are combined with SAM simulations to predict 

hourly system performance for a full year. Further research 

will investigate how to incorporate thermal energy storage and 

ways to optimize use of the gas turbines to maximize power 

production during peak demand periods and minimize overall 

ramp rates from the combined steam turbine / gas turbine 

output.

ACKNOWLEDGMENT 

This work was supported by the U.S. Department of Energy 

under Contract No. DE-AC36-08-GO28308 with the National 

Renewable Energy Laboratory (Agreement 15085).
7

REFERENCES

[1] Pacheco, J.E. “Final Test and Evaluation Results from 

the Solar Two Project,” SAND2002-0120, January 

2002.

[2] Kelly, B.D., Herrmann, U., and Kearney, D. W., 

“Evaluation and performance modeling for integrated 

solar combined cycles systems and thermal storage 

system, “Final report on contract RAR-9-29442-05, 

National Renewable Energy Laboratory, September, 

2000.

[3] Kelly, B., U. Herrmann, M.J. Hale, “Optimization 

Studies for Integrated Solar Combined Cycle Systems,” 

Proceedings of Solar Forum 2001 Solar Energy: The 

Power to Choose, April 21-25, 2001 Washington, DC.

[4] Libby, C., “Solar Augment Steam Cycles for Natural 

Gas Plants: Conceptual Design Study,” Electric Power 

Research Institute, Report 1018645, July 2009.

[5] Bohn, M. S., T. A. Williams, and H. Price, “Combined 

Cycle Power Tower,” in proceedings of 

ASME/JSME/JSES International Solar Energy 

Conference, Maui HI. NREL/TP-471-7019, 1995.

[6] Williams, T.A., M. Bohn and H. Price, “Solar Thermal 

Electric Hybridization Issues,” in proceedings of 

ASME/JSME/JSES International Solar Energy 

Conference, Maui HI. NREL/TP-471-7019, 1995.

[7] European Commission Directorate-General for 

Research, “SOLGATE Final Published Report, EUR 

21615” 2005.

[8] Wacek, E., and W. Ferguson, “Application of the Latest 

Aeroderivative Gas Turbine Technology,” General 

Electric, 09-IAGT 203.

[9] Badeer, G.H., “GE Aeroderivative Gas Turbines –

Design and Operating Features,” GER-3695E, GE 

Power Systems, Evendale, OH, 2000.

[10]Reale, M., New High Efficiency Simple Cycle Gas 

Turbine – GE’s LMS100,” GER-4222A, GE Energy, 

June 2004.

[11]Short, W., D. Packey, and T. Holt, “A Manual for the 

Economic Evaluation of Energy Efficiency and 

Renewable Energy Technologies,” NREL/TP-462-

5173, March 1995.

Figure 5. Simplified schematic of aeroderivative turbine backup for a parabolic trough plant. Additional 

feedwater heaters using steam extraction are not shown.
8

Figure 6. Operating strategy for the aeroderivative turbine integrated with a solar trough plant (1= running; 

0=off).

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March 2011

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Conference Paper

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4. TITLE AND SUBTITLE

Gas Turbine/Solar Parabolic Trough Hybrid Designs: Preprint

5a. CONTRACT NUMBER

DE-AC36-08GO28308

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6. AUTHOR(S)

C.S. Turchi, Z. Ma, and M. Erbes

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NREL/CP-5500-50586

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CP09.8401

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National Renewable Energy Laboratory

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13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

A strength of parabolic trough concentrating solar power (CSP) plants is the ability to provide reliable power by 

incorporating either thermal energy storage or backup heat from fossil fuels. Yet these benefits have not been fully 

realized because thermal energy storage remains expensive at trough operating temperatures and gas usage in CSP 

plants is less efficient than in dedicated combined cycle plants. For example, while a modern combined cycle plant 

can achieve an overall efficiency in excess of 55%; auxiliary heaters in a parabolic trough plant convert gas to 

electricity at below 40%. Thus, one can argue the more effective use of natural gas is in a combined cycle plant, not 

as backup to a CSP plant. Integrated solar combined cycle (ISCC) systems avoid this pitfall by injecting solar steam 

into the fossil power cycle; however, these designs are limited to about 10% total solar enhancement. Without 

reliable, cost-effective energy storage or backup power, renewable sources will struggle to achieve a high penetration 

in the electric grid. This paper describes a novel gas turbine / parabolic trough hybrid design that combines solar 

contribution of 57% and higher with gas heat rates that rival that for combined cycle natural gas plants. The design 

integrates proven solar and fossil technologies, thereby offering high reliability and low financial risk while promoting 

deployment of solar thermal power.

15. SUBJECT TERMS

parabolic trough; aeroderivative turbine; solar; hybrid

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