2012 GENERATION TECHNOLOGY ASSESSMENT - · PDF fileThe 2012 Generation Technology Assessment begins by surveying available central state electricity generation technologies, generally

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2012 GENERATION TECHNOLOGY ASSESSMENTGeneration Technology Cost & PerformanceTechnical Supplement to 2012 ENO IRP

JANUARY 2012 UPDATE

SPO PLANNING ANALYSIS

An understanding of generat ion technology cost and performance is a necessary input to p lanning and dec is ion support act iv i t ies . SPO P lanning Analys is monitors and assesses generat ion a l ternat ives on an on -going bas is. Th is s tudy updates technology assumptions and is intended as an input into the 2012 Integrated Resource P lan (“ IRP”) process as wel l a s other dec is ion support act iv i t ies involv ing resource p lanning and/or t ransact ion evaluat ions.

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TABLE OF CONTENTS

Introduction …………………………………………………………………………………………….. 3

I. The Technology Landscape ………………………………………………….……………………. 5

II. Cost & Performance Assumptions ………………………………………………..……………... 31

III. Detailed Modeling ………………………………………………………………………………… 41

IV. Conclusions ………………………………………………………………………………………... 57

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INTRODUCTION

In support of long-range planning and procurement activities System Planning & Operations (”SPO”), Planning Analysis monitors electric generation technology cost and performance. This report “2012 Generation Technology Assessment” describes current assumptions and conclusions.

The 2012 Generation Technology Assessment has been prepared in preparation of the 2012 IRP process. Results of this generation technology assessment will support IRP activities in 2012 and will provide the basis for portfolio modeling

TECHNOLOGY ASSESSMENT

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I.

• Review the state of generation technology and identify candidate technologies that may be available to meet long-term needs.

The Technology Landscape


II.

• Develop cost and performance assumptions for candidate technologies.

Cost & Performance Assumptions

III.

• Model cost of candidate technologies across relevant range of operations and assess overall attractiveness including risks.

Detail Modeling

IV.

• Summarize conclusions and identify technologies to be modeled in IRP portfolio design.

Conclusions

STUDY METHODOLOGY

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I. The Generation Technology Landscape

I.



II.



III.


Detail Modeling

IV.

• Summarize conclusions and identify reference technologies to be modeled in IRP portfolio design.

Conclusions

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THE RANGE OF TECHNOLOGIES


The 2012 Generation Technology Assessment begins by surveying available central state electricity generation technologies, generally those that are two megawatts or greater.. The objective is to identify as wide a range of generation technologies as reasonable to consider. The initial list is subject to a screening analysis to identify generation technologies that are technologically mature and could reasonably be expected to be operational in or around the Entergy regulated service territory..

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TECHNOLOGIES SCREENED


Nuclear– Advanced Boiling Water Reactor– Generation IV– Modular Reactors

Entergy Storage– Pumped Hydro– Underground Pumped Hydro– Battery– Flywheel– Compressed Air Energy Storage

Renewable Technologies– Biomass– Solar Photovoltaic– Solar Thermal– Wind Power– Municipal Solid Waste– Landfill Gas– Geothermal– Ocean & Tidal

Pulverized Coal – Subcritical Pulverized Coal– Supercritical Pulverized Coal– Ultra Supercritical Pulverized Coal

Fluidized Bed– Atmospheric Fluidized Bed– Pressurized Fluidized Bed

Integrated Gasification (“IGCC”)– Oxygen-Blown IGCC– Air-Blown IGCC– Integrated Gasification Fuel Cell Combined Cycle

Combustion Turbine / Combined Cycle / Other Natural Gas– Combustion Turbine– Combined Cycle– Small Scale Aeroderivative– Steam Boiler

Fuel Cells– Molten Carbonate– Solid Oxide– Phosphoric Acid– Proton Exchange Membrane– Fuel Cell Combined Cycle

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PREFERENCE FOR PROVEN TECHNOLOGY

The Entergy Operating Companies prefer technologies that are proven on a commercial scale. Some technologies identified in this document lack the commercial track record to demonstrate their technical and operational feasibility. A cautious approach to technology development and deployment is therefore prudent in order to maintain System reliability and to protect Operating Company customers from undue risks. The Entergy Operating Companies generally do not plan to be the “first movers” for emerging technologies.


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Technology Deployment Over Time

TECHNOLOGY LIFE CYCLE

ConceptualResearch &

Development Early Movers MatureEstablished


Fuel Cell CCGT Aeroderivative Combustion Turbine

Combined Cycle Gas Turbine

Heavy Duty Combustion Turbine

Gas Fired Steam Boiler

Integrated Gasification Fuel Cell CCGT

Oxygen Blown IGCC

Ultra Supercritical PC

Supercritical PC Subcritical PCAir Blown IGCC

Generation IV Nuclear

Modular Nuclear

Generation III Nuclear

Biomass –Stoker Boiler

Wind – Off-Shore

Biomass -CFBGeothermal

MSW – Plasma Torch

Ocean and Tidal Power

Wind – On-ShoreLandfill Gas MSW

Solar –Thermal

Solar –PV

FlywheelUnderground

Pumped Hydro BatteryCompressed Air Energy Storage

Pumped Storage Hydro

Proton Fuel Cell

Small CT Internal Combustion Engine

Conventional Gas Fired

Solid Fuel

Nuclear

Renewable

Energy Storage

Distributed Generation

Generation II Nuclear

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SCREENING PROCESS


The following pages provide an overview of each major technology.

• Description of the technology

• The current state of maturity and extent of deployment

• Factors which may constrain additional deployment or advancement

• Potential for improvements in cost or performance

The objective is to identify technologies that merit further consideration, more detailed modeling in the following sections, and to eliminate those that do not.

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PULVERIZED COAL


Background:

Pulverized Coal (“PC”) is a mature technology representing nearly 40% of installed utility capacity in the U.S.

The generation technology incorporates a boiler that burns pulverized coal producing steam that feeds into a steam turbine to produce electricity.

PC technology is categorized based on boiler pressure and temperature into three categories:

• Subcritical (2,400 psig and 1000 °F)• Supercritical (3,200 psig and 1000 °F) • Ultra Supercritical (3,400 psig and 1100 °F)

The reduction or capture of environmental emissions, particularly carbon dioxide (CO2), is the current focus for improvements in this technology.

Challenges:

Coal’s environmental footprint, especially it’s emissions profile, creates a significant challenge to future deployment and may threaten the long-term viability of existing facilities. In particular, coal fired facilities are high carbon emitters. Consequently, the imposition of a cost on CO2 emissions would negatively affect the economics of PC. Lack of a commercial scale method for economic carbon capture and storage and the risk of significant carbon compliance cost has already limited coal deployments. Finally, coal’s relatively high capital cost put it at a disadvantage to other technologies that have lower up front cost.

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PULVERIZED COAL


DispositionTechnology Description

Eliminate from analysis in favor of newer more efficient technology such as supercritical boilers.

Subcritical Pulverized Coal

Subcritical cycle boilers for steam coal plants have been in use for more than 20 years. Efficiency of subcritical boilers is in the 32-36% range (9,480-10,665 btu/kWh). The technology is mature and use is expected to decline as the need for increased efficiencies to reduce emissions favor the use of more efficient technology.

Retained for detailed analysis.Supercritical Pulverized Coal

Supercritical cycle boilers have long been utilized in international markets. Higher boiler pressures and temperatures improves efficiency to between 36-40% (9,480-8,530 btu/kWh) and reduces emissions. Environmental regulations may dictate the need for higher efficiency to reduce emissions making this the PC technology of choice.

Eliminated from analysis until the technology has been commercially proven in order to understand cost and risk profile.

Ultra Supercritical Pulverized Coal

Ultra supercritical cycle boilers offer the potential of higher efficiencies and lower emissions, but these advantages come at increased operations risk and construction cost. Efficiency ranges between 40-45% (8,530-7,585 btu/kWh). The higher pressures and temperatures require higher alloy steels in the boiler resulting in higher capital cost.

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FLUIDIZED BED


Background:

Fluidized bed combustion, both bubbling bed and circulating bed, are mature, having been commercially available since the 1970’s. Due to the limitations of the bubbling bed design the circulating bed (“CFB”) is the preferred technology design.

CFB boilers burn crushed coal or other carbon-based solid fuel in a mixture with blown air and limestone. More than 95 percent of the sulfur pollutants are captured inside the CFB boiler and falls out as ash.

Historically CFB boilers operated at atmospheric conditions limiting size to around 300 MW. Development is underway on pressurized circulating bed designs capable of electrical output up to 600 MW.

Challenges:

Environmental concerns associated with CO2 emissions and relatively high capital cost affect CFB technology in much the same manner as PC technology.

Other Considerations:

A CFB plant has the ability to burn a variety of solid fuels including coal, petroleum coke (“pet coke”), and other “waste” fuels resulting in lower fuel cost.

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FLUIDIZED BED



Retained for detailed analysis.Atmospheric Circulating Fluidized Bed (“ACFB”)

ACFB technology is mature. The ACFB boiler is suited to burn a variety of carbon-based solid fuel feedstocks, including bituminous and sub-bituminous coals, petroleum coke and waste coal. Technological limitations prevent boiler sizes much above a 300 MW limit.

Eliminated from analysis because the technology lacks sufficient commercial development at this time.

Pressurized Circulating Fluidized Bed (“PCFB”)

PCFB boilers offer the advantage of larger size and reduced environmental emissions. However, the technology is at an early stage of commercialization and not proven for wide spread deployment.

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INTEGRATED GASIFICATION


Background:

Integrated Gasification Combined Cycle (“IGCC”) is an emerging technology.

An IGCC facility combines two processes or stages. First, a gasification unit converts coal or other solid fuel into a synthesis gas (“syngas”). Second, the syngas is burned in a combined cycle gas and steam power plant. Each of these processes have been widely deployed in separate applications. The uniqueness of the IGCC technology is the combining of the technologies for the purpose of electricity generation.

IGCC has attracted attention because the gasification process may facilitate the removal of carbon. Consequently, carbon capture and storage may be more feasible compared with other carbon based solid fuel technologies.

IGCC demonstration units currently in operation have only demonstrated efficiencies of between 37-41 percent (heat rates between 8,300 and 9,200 Btu/kWh) which is similar to current supercritical PC technology. However, IGCC has the potential to be more efficient than conventional PC with efficiency of 43-48 percent (heat rate between 7,100 and 7,900 Btu/kWh).

Challenges:

At this time IGCC has not been widely deployed and capital cost are higher than PC and CFB coal plants. Further, the lack of operating experience raises concerns about operating cost and performance.

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INTEGRATED GASIFICATION



Eliminated from analysis because of high capital cost and lack of sufficient commercial operating history..

Oxygen-Blown IGCC IGCC technology is the least mature of all solid fuel technologies. The gasifier and air separation components results in high capital cost compared to other generation technologies. If carbon capture technology is required to control emissions the cost will increase and output decrease, negatively impacting economics.

Eliminated from analysis because technology lacks sufficient commercial development to fully evaluate its cost and risk.

Air-Blown IGCC Like other IGCC technologies air-blown IGCC is immature and not proven in commercial practice. Air-blown IGCC has potential of being a lower cost alternative for IGCC by eliminating the air separation unit.

Eliminated from analysis because the technology is currently in the developmental stage and not available for deployment in commercial applications.

Integrated Gasification Fuel Cell Combined Cycle

This technology is still in the development/ bench scale phase. It is a hybrid IGCC technology combining fuel cells with gas combustion turbines to increase efficiency and reduce emissions. The technology is based on solid oxide fuel cell (SOFC) design. The current timeline estimates the commercialization of a 100 MW unit some time around 2020.

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COMBUSTION TURBINE


Background:

Combustion Turbine (“CT”) generation is a mature technology first introduction into the power generation market in 1979. Aeroderivative CTs, based on aircraft engine design, are more recent having been introduced into the generation market in 1995.

Heavy Duty -Heavy Duty frame CTs with a size range of between 85-300 MW and heat rates between 9,000-11,500 Btu/kWh are broadly utilized in the power generation market with more than 3,000 units in operation accumulating nearly 100 million operating hours.

Aeroderivative -Aeroderivative CTs, as the name implies, are based on flight engines and are smaller, lighter, and more efficient than heavy duty CTs. Size ranges between 40-100 MW with heat rates in the 8,400-9,500 Btu/kWh range. New aeroderivative CTs in the 100 MW range are new to the market.

Aeroderivative turbines have higher capital and maintenance cost than heavy duty CTs resulting from the use of lighter weight exotic materials and more stringent machine tolerances.

Opportunities :

CT technology offers quick start capability, flexible siting and short construction time, low emissions footprint, and relatively low capital cost making it suited for peaking duty applications.

Challenges:

Higher heat rates make CTs less economic than CCGTs for load following and base load operations. However, CTs may be designed and constructed to provide peaking duty services in the near term yet allow for the conversion to combined cycle operations if load or other circumstances require additional load following capability.

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Retained for detailed analysis.Combustion Turbine –Heavy Duty

Combustion turbine (“CT”) technology, based on the heavy duty frame, is mature with thousands of units in operation around the world. Still in development are newer generation turbines with larger electrical output, better heat rates and reduced emissions.

Retained for detailed analysis.Combustion Turbine -Aeroderivatives

Aeroderivative combustion turbines are an “Established” technology. Their smaller size (50-100 MW) and higher capital and maintenance cost could potentially limit deployment to situations such as local area problems and areas with limited space.

COMBUSTION TURBINE

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Background:

Combined Cycle Gas Turbine (“CCGT”) technology is mature representing over 50% of new generation capacity installed in the U.S. since 2000.

CCGT arrangements typically are combinations of one or more combustion turbines each with a dedicated heat recovery steam generator (“HRSG”) and a common steam turbine.

Development efforts currently underway focus on designs that incorporates closed-loop steam cooling and advanced coating materials allowing for higher firing temperatures and increased efficiency making CCGT more economic for baseload applications.

Opportunities

Taking into consideration moderate capital cost, low expected natural gas price forecast and flexible operating modes CCGTs are expected to be the choice technology to meet most load following roles and baseload applications over the first ten years of the planning horizon and possibly beyond.

Challenges:

CCGT cost competitiveness is driven by low to moderate natural gas prices. A sustained period of high gas prices would reduce the attractiveness of CCGTs particularly if a price is placed on carbon.

COMBINED CYCLE GAS TURBINE

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Retained for detailed analysis.Combined Cycle As with combustion turbines, combined cycle technology is mature with a significant number of units in operation. The development of the new CCGT designs incorporating closed loop cooling with higher pressure and firing temperature will serve to keep this technology competitive with other generation technologies for use in the power generation business during the planning horizon.

COMBINED CYCLE GAS TURBINE

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NUCLEAR


Background:

No new nuclear power plant has been constructed in the U.S. in over 30 years. However, a nuclear generation alternative offers the potential benefits of no greenhouse or other air emissions, fuels diversity, and energy security.

Nuclear technology, while considered mature, continues to push new technological advances. Generation II reactors, first installed in the 1970’s, were light water reactors and represent most all of the reactors operating in the U.S. today. Since 1996, Generation III and III+ designs have been considered by developers as the design choice. Generation III includes Economically Simplified Boiling Water Reactor (“ESBWR”), Advanced Passive Nuclear Reactor (“AP-1000”), Advanced Boiling Water Reactor (“ABWR”), and Evolutionary Pressurized Water Reactor (”EPR”) designs. While most recent applications to construct and operate a new plant include one of these designs no applications have been approved by regulators at this time.

Nuclear equipment manufactures are currently designing and developing Generation IV technology. Generation IV designs include closed fuel loop cycles for more efficient fuel burn with reduced waste and cost. Generation IV is expected to include a line of smaller modular units well below the 300+ MW size currently considered. Expectations for commercial delivery of Generation IV nuclear reactors is in the 2020-2030 timeframe.

Challenges:

Among the issues facing the nuclear generation are:• The large investment required and the impact on an owner’s financial structure•Limited government support at both state and federal levels•Additional safety systems in reaction to the Fukashema Nuclear accident in Japan could raise cost.•Potentially significant increases in cost estimates being planned•Delays in NRC review and approval process•Disposition of nuclear waste•Opposition by citizen and environmental groups

Opportunities:Nuclear could become attractive if the U.S. passes a stringent greenhouse gas policy and resolves concerns around nuclear waste and safety.

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NUCLEAR



Advanced Boiling Water (Generation III & III+)

The design of the Generation III & III+ reactors has been around for more than 10 years but the technology must still be considered in the “Early Mover” phase since no new construction and operating permit has yet been approved by the NRC.

Eliminated from analysis due to the expectation of commercial deployment beyond the current planning horizon.

Generation IV Generation IV designs are still in the early stages of R&D with no potential deployment before the 2020-2030 time period. Generation IV technology has the potential to reduce nuclear waste and fuel cost.

Eliminated from analysis due to the expectation of commercial deployment beyond the current planning horizon.

Modular Designed A sub-set of the Generation IV these smaller modular reactors offer the potential to reduce total investment cost for a new installation, but is not expected to be available for deployment until 2020 at the earliest.

Retained for detailed analysis. Considering the long-lead time for development and construction the earliest COD for this technology is assumed to be after 2020.

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ENERGY STORAGE


Background:

Energy storage technologies provide load shifting peak shaving capability for utilities. These technologies are “charged” using lower cost off-peak energy and “discharged” during periods when energy cost or demand are higher. Examples of Energy Storage technologies include pumped storage hydro, battery, flywheel and compressed air energy storage.

Pumped Storage Hydro-

Pumped storage hydro is mature and is one of the two bulk energy storage technologies commercially available.

The potential to use underground reservoirs such as old salt mines offer some opportunities for a limited number of projects in the region, but development cost are high.

Compressed Air Energy Storage-

Compressed air energy storage (“CAES”) is mature and is the second bulk energy storage technology commercially available. CAES can use old underground salt mines as storage mediums for holding compressed air. When needed the compressed air is withdrawn and mixed with a fuel such as natural gas for firing in a combustion turbine. This process reduces fuel requirements by nearly two-thirds compared to conventional combustion turbines.

Flywheel-

Flywheels stores kinetic energy in the form of a spinning mass, a rotor, which can be discharged for peak shaving or backup purposes. Currently flywheels are immature with test units ranging in size from 2-6 kW. Future plans call for scaling up to 25 kW. The discharge rate is a drawback with discharge times of up to one hour.

Battery Storage-

Large scale energy storage using batteries is still a “Developing” technology. Developers need to reduce cost, improve life cycle and reduce the use of hazardous material. Currently battery energy storage cost is high, estimates are around $3,000/kW and most battery types utilize hazardous material that can become combustible when exposed to water requiring additional protection for the battery cells. Battery energy storage may find a niche application assisting wind projects with grid integration issues.

Challenges:

Energy Storage technologies are more capital intensive than traditional technologies and are net energy users. These technologies may find specialized applications such as assisting with grid integration of intermittent renewable resources like wind.

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ENERGY STORAGE



Eliminated from analysis due to a lack of sufficient available sites for commercial development.

Pumped Hydro and Underground Pumped Hydro

Pumped hydro is mature with 21.5 GW in operation. The large amount of land resources required along with the proper site elevations make this a highly site specific niche deployment option. Underground pumped storage can offer limited opportunity considering the numerous underground salt caverns in the service area.

Eliminate from analysis because the technology lacks sufficient benefits or sites for widespread deployment.

Compressed Energy Storage

CAES is one of the only bulk energy storage technologies commercially available. High capital cost and acceptable sites limit deployment opportunities.

Eliminate from analysis because the technology lacks sufficient benefits for widespread deployment.

Battery Battery energy storage is a developing technology at the utility scale. Future development is needed to improve cycle life, size, and reduce cost. Useful for grid support and possibly wind integration issues.

Eliminate from analysis because the technology lacks sufficient scale for consideration.

Flywheel Flywheel’s limited capacity size and short discharge duration is not currently attractive for utility grid applications.

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RENEWABLE GENERATION


Background:

Renewable generation technologies offer the potential to supplement utilities’ traditional generation portfolio. Renewable generation can provide utilities with no or neutral emission generation to assist in reducing greenhouse gas emissions.

Government Policy-

Renewable generation, especially wind power has seen rapid growth over the past decade, due in large part to government subsidies (federal and state) and state mandates often referred to as renewable portfolio standards (“PRSs”). Mandatory RPSs currently exist in about 30 states. The only state RPS in the Entergy utility service area is Texas. RPS usually require a load serving entity to obtain a certain percent of its electricity from renewable sources often utilizing a market mechanism known as renewable energy credits (“RECs”). This technology assessment does not consider government subsidies or requirements.

Wind-

Wind generation is the most mature and prevalent renewable technology. For the U.S. the best wind generation sites are in the Great Plains region of the country.

Manufactures of wind turbines and associated equipment continue working to improve wind plant availability and capacity factors through the use of variable speed turbines, larger turbines, maximized plant layout, and improved control systems.

Biomass-

Biomass is a carbon neutral renewable generation resource utilizing forest and agricultural waste as fuel sources. The dispersed nature of feedstock and large quantities required to fuel a utility scale plant generally limit the capacity of biomass plants to around 50 MW.

Solar-

Solar Photovoltaic (“PV”) employs semiconducting material to convert direct sunlight into electricity. The current generation of solar PV cells have an operating efficiency of 10-20%. Future generations of PV cells need to improve efficiency to better compete with other renewable and traditional generation technologies. Ultimately, the efficiency of solar PV installations are highly dependent on the amount of direct solar radiation making the best site location the western part of the US.

Solar thermal technology concentrates solar radiation using mirrors to heat a medium, such as molten salt, to produce steam and ultimately electricity. Land requirements are large, requiring 4-6 acres per MW of peak capacity or more for lower quality locations. As with solar PV output is highly dependent on the amount of solar radiation with the best site located in the western part of the US.

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Geothermal-

Prime geothermal sites with high-grade steam reservoirs have been largely developed, mostly in the pacific coast region. Future projects will depend on water-steam, hot water, or dry rock technologies that are less efficient. Within the region natural deposits of hot brine found in conjunction with oil and gas deposits offer options for geothermal production, albeit, expensive to develop.

Ocean and Tidal Power-

Ocean and Tidal power, both in-stream hydro and ocean wave energy are mostly still in the bench-scale phase of development with few actual operating turbines in service. Time, cost and complexity of the U.S. FERC regulatory process poses a barrier for tidal project developers.

Municipal Solid Waste and Landfill Gas-

Municipal solid waste (“MSW”) projects offer opportunities where sufficient fuel supply can be procured. Based on current estimates a 50 MW MSW facility requires approximately 2,000 tons of solid waste per day for full output. Solid waste projects require large fuels handling systems and substantial processing of solid waste to remove unwanted containments from the fuel prior to burning.

Landfill gas systems collect the naturally occurring methane gas emitted by landfill decay and processes it for burning in small combustion turbines or internal combustion engines. Issues for landfill gas are mainly associated with gas processing which includes the removal of moisture and impurities, compression, and blending the gas to achieve consistent heating values.

Challenges:

The need to meet Renewable Portfolio Standard mandates and fill the potential void left by coal retirements will pose a significant challenge for utilities in the coming years. High capital cost, low efficiencies, and intermittent nature of most renewable technologies will need to be accounted for in the planning and operations of utilities as renewables are deployed as part of generation portfolios.

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Retained for detailed analysis.Biomass Biomass is a mature technology with a carbon neutral footprint. Dispersed nature of feedstock and large fuel requirements limit capacity to around 50 MW per site.

Retain for detailed analysis as an option for the second ten years of the plan horizon.

Solar Photovoltaics Solar PV technology is still maturing. The biggest improvement opportunities are 1) increase efficiency and 2) lower capital cost.

Eliminated from analysis due to lack sufficient potential at this time.

Municipal Solid Waste For MSW technology is mature. However, fuels handling and processing needs to be improved and site capacity is limited.

Eliminated from analysis due to lack of sufficient commercial sites within the region.

Solar Thermal Solar thermal technology is mature. However, most high quality site are not located near the Entergy area and capital cost remains high.

Retained for detailed analysis.Wind Power Wind technology is mature, over 35 GW of capacity installed world-wide. Best site are in the upper Great Plains states so transmission is an issue.

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Eliminated from analysis due to lack sufficient potential at this time. Niche opportunities may exist in the future.

Landfill Gas The basic firing system for Landfill Gas is a mature technology. The issue for landfill gas is fuel supply is low quality with numerous contaminants that must be removed before use.Most development opportunities are under 10 MW which reduces cost competitiveness.

Eliminated from analysis due to lack sufficient commercial potential at this time within and in close proximity to the Entergy Operating Companies. The Southeast U.S. geological conditions are not well suited for this technology

Geothermal The greatest potential Geothermal generation in the Entergy region rests with the hot brine found in conjunction with oil and gas deposits. These are lower quality resources compared to the pure steam resources found in the West and will cost more to tap and operate.

Eliminated from analysis because the technology lacks sufficient commercial development at this time.

Ocean & Tidal Ocean & Tidal power has seen limited actual operating projects. Both in-stream hydro and ocean wave projects are costly and require FERC regulatory approvals.

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RESULTS OF SCREEN


SPO Planning Analysis through this Technology Screen has selected certain traditional and renewable generation technology alternatives which may reasonably be expected to meet the Systems primary objectives of cost, risk mitigation, and reliability. For each selected technology Planning Analysis will develop the necessary cost and performance parameter inputs into the detailed modeling used to develop the reference technologies comprising the IRP Portfolio.

SPO Planning Analysis will monitor the technologies eliminated as a result of the initial screen and incorporate changes into future technology assessments and IRPs.

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CANDIDATE TECHNOLOGIES


The following technologies are being carried forward for development of detailed planning assumptions . . .

Nuclear– Advanced Boiling Water Reactor

Renewable Technologies– Biomass– Wind Power– Solar PV

Pulverized Coal – Supercritical Pulverized Coal

Fluidized Bed– Atmospheric Fluidized Bed

Natural Gas Fired– Combustion Turbine– Combined Cycle– Small Scale Aeroderivative

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II. Cost & Performance Assumptions






Detail Modeling


Conclusions

I. II. III. IV.

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COMBUSTION TURBINES TECHNOLOGY ASSUMPTIONS


Characteristic Units GE 7 FA (.03)

GE 7FA (.03)

GE LM 6000

GE LM 6000

GE LMS 100

GE LMS 100

GE 7FA (.05)

GE 7FA (.05)

First Year Available from Vendor*

(Yr) 1999 1999 2009 2009 2010 2010 2012 2012

Net MW at ISO (59°F) (MW) 172 344 48 290 101 304 219 438

Number of Units (#) 1 2 1 6 1 3 1 2

Typical Development Time

(Yrs.) 1.5 1.5 1 1.5 1 1.5 1.5 1.5

Typical Construction Time

(Yrs.) 1 1 1 1 1 1 1 1

Overnight Cost ($/kW) $850 $800 $1,600 $1,100 $1,400 $1,150 $800 $760

Installed Cost ($/kW) $940 $900 $1,800 $1,200 $1,550 $1,250 $900 $840

Heat Rate (ISO) (Btu/kWh) 9,850 9,850 9,150 9,150 8,400 8,400 9,250 9,250

Typical Capacity Factor (%) 0-30 0-30 0-30 0-30 0-30 0-30 0-30 0-30

Fixed O&M ($/kW-yr) $8.50 $6.00 $16.00 $8.00 $12.00 $8.00 $7.50 $5.50

Variable O&M ($/MWh) $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00

NOx (lbs/MMBtu) 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

SO2 (lbs/MMBtu) 0 0 0 0 0 0 0 0

CO2 (lbs/MMBtu) 118.9 118.9 118.9 118.9 118.9 118.9 118.9 118.9

Hg (lbs/MMBtu) 0 0 0 0 0 0 0 0

Useful Life (Yrs.) 30 30 30 30 30 30 30 30

2012 – 2021 (First Ten Years of Planning Horizon) 2011$

*First year of commercial operation equals First Year Available from Vendor plus construction time.

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COMBUSTION TURBINES TECHNOLOGY ASSUMPTIONS


Characteristic Units GE LM 6000

GE LM 6000 GE LMS 100 GE LMS 100 GE 7FA.05 GE 7FA.05

First Year Available From Vendor* (Yr) 2009 2009 2011 2011 2012 2012

Net MW at ISO (59°F) (MW) 48 290 101 304 219 438

Number of Units (#) 1 6 1 3 1 2

Typical Development Time (Yrs.) 1 1.5 1 1.5 1.5 1.5

Typical Construction Time (Yrs.) 1 1 1 1 1 1

Overnight Cost ($/kW) $2,122 $1,459 $1,856 $1,525 $1,061 $1,008

Installed Cost ($/kW) $2,388 $1,592 $2,056 $1,658 $1,194 $1,114

Heat Rate (ISO) (Btu/kWh) 9,050 9,050 8,300 8,300 9,250 9,250

Typical Capacity Factor (%) 0-30 0-30 0-30 0-30 0-30 0-30

Fixed O&M ($/kW-yr) $19.50 $9.93 $14.50 $9.75 $9.15 $7.45

Variable O&M ($/MWh) $2.48 $2.48 $2.48 $2.48 $2.48 $2.48

NOx (lbs/MMBtu) 0.03 0.03 0.03 0.03 0.03 0.03

SO2 (lbs/MMBtu) 0 0 0 0 0 0

CO2 (lbs/MMBtu) 118.9 118.9 118.9 118.9 118.9 118.9

Hg (lbs/MMBtu) 0 0 0 0 0 0

Useful Life (Yrs.) 30 30 30 30 30 30

2022 – 2031 (Second Ten Years of Planning Horizon) 2022$


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COMBINED CYCLE TECHNOLOGY ASSUMPTIONS


Characteristic Units GE 7FA.03 (2x1)

GE 7FA.05 (2x1)

GE 7FA.03 (1x1)

GE 7FA.05 (1x1) GE 7H

First Year Available from Vendor* (Yr) 1999 2012 1999 2012 2008

Net MW at ISO (59°F) (MW) 502 640 237 290 404

Number of Units (#) 2 2 1 1 1

Typical Development Time (Yrs.) 2 2 2 2 2

Typical Construction Time (Yrs.) 3 3 3 3 3

Overnight Cost ($/kW) $1,200 $1,100 $1,500 $1,350 $1,550

Installed Cost ($/kW) $1,350 $1,350 $1,650 $1,650 $1,700

Heat Rate (ISO) (Btu/kWh) 6,650 6,550 6,800 6,700 6,400

Typical Capacity Factor (%) 65 65 65 65 85

Fixed O&M ($/kW-yr) $15.00 $15.00 $20.00 $20.00 $15.00

Variable O&M ($/MWh) $2.50 $2.50 $2.50 $2.50 $3.50

NOx (lbs/MMBtu) 0.015 0.015 0.015 0.015 0.015

SO2 (lbs/MMBtu) 0 0 0 0 0

CO2 (lbs/MMBtu) 118.9 118.9 118.9 118.9 118.9

Hg (lbs/MMBtu) 0 0 0 0 0

Useful Life (Yrs.) 30 30 30 30 30



35

COMBINED CYCLE TECHNOLOGY ASSUMPTIONS


Characteristic Units GE 7FA.05 (2x1) GE 7FA.05 (1x1) GE 7H

First Year Available from Vendor* (Yr) 2012 2012 2008

Net MW at ISO (59°F) (MW) 640 290 404

Number of Units (#) 2 1 1

Typical Development Time (Yrs.) 2 2 2

Typical Construction Time (Yrs.) 3 3 3

Overnight Cost ($/kW) $1,478 $1814 $2,082

Installed Cost ($/kW) $1,814 $2,217 $2,284

Heat Rate (ISO) (Btu/kWh) 6,550 6,600 6,400

Typical Capacity Factor (%) 65 65 80

Fixed O&M ($/kW-yr) $18.61 $24.82 $18.61

Variable O&M ($/MWh) $3.01 $3.10 $4.34

NOx (lbs/MMBtu) 0.015 0.015 0.015

SO2 (lbs/MMBtu) 0 0 0

CO2 (lbs/MMBtu) 118.9 118.9 118.9

Hg (lbs/MMBtu) 0 0 0

Useful Life (Yrs.) 30 30 30



36

COAL & NUCLEAR TECHNOLOGIES ASSUMPTIONS


Characteristic Units PC CFB Generation III -Nuclear


Size (MW) 800 750 1,310




Overnight Cost ($/kW) $2,150 $2,500 $5,000


Heat Rate (Btu/kWh) 9,250 10,600 10,200


Fixed O&M ($/kW-yr) $40.00 $45.00 $81.54

Variable O&M ($/MWh) $3.50 $10.00 $4.08

NOx (lbs/MMBtu) 0.04 0.039 0

SO2 (lbs/MMBtu) 0.05 0 0

CO2 (lbs/MMBtu) 214 212.6 0



Although there are a few nuclear projects in development around the U.S., given the long lead time to develop and construct a new nuclear plant Entergy does not believe such a facility could be online prior to 2021 at the earliest.



37

COAL & NUCLEAR TECHNOLOGIES ASSUMPTIONS


Characteristic Units PC w/90% CO2 Removal CFB Generation III -

Nuclear


Size (MW) 800 750 1,310




Overnight Cost ($/kW) $4,922 $3,326 $6,625


Heat Rate (Btu/kWh) 13,100 10,600 10,200


Fixed O&M ($/kW-yr) $86.87 $55.84 $101.19

Variable O&M ($/MWh) $9.93 $12.41 $5.06

NOx (lbs/MMBtu) 0.04 0.039 0

SO2 (lbs/MMBtu) 0.02 0 0

CO2 (lbs/MMBtu) 21.4 212.6 0



Generation IV New Nuclear Commercial Operation dates in the U.S. are not expected before 2030 or later, and therefore are not considered. However, this technology will be monitored and could be incorporated into future Technology Assessments and IRPs especially if it offers significant cost or time to develop and construct savings.



38

RENEWABLE TECHNOLOGIES ASSUMPTIONS


Characteristic Units Biomass - Stoker Biomass – CFB Wind – On Shore

Wind – Off Shore Solar - PV

First Year Available from Vendor* (Yr) 2000 2006 2010 2011 2011

Size (MW) 50 50 75 120 50

Number of Units (#) 1 1 50 40 1

Typical Development Time (Yrs.) 2 2 1 2 2

Typical Construction Time (Yrs.) 2 3 1 2 1.5

Overnight Cost ($/kW) $3,000 $4,000 $1,850 $2,900 $4,500

Installed Cost ($/kW) $3,400 $4,700 $2,000 $3,500 $5,000

Heat Rate (Btu/kWh) 13,000 11,000 NA NA NA

Typical Capacity Factor (%) 65 85 39 41 20

Fixed O&M ($/kW-yr) $55.00 $70.00 $40.00 $90.00 $20.00

Variable O&M ($/MWh) $7.50 $3.00 $1.00 $1.00 $0.00

NOx (lbs/MMBtu) 0 0 0 0 0

SO2 (lbs/MMBtu) 0 0 0 0 0

CO2 (lbs/MMBtu) 0 0 0 0 0

Hg (lbs/MMBtu) 0 0 0 0 0

Useful Life (Yrs.) 20 30 20 20 20

Does not include any possible cost subsidization. Does not include capacity match cost or flexible capability cost to make intermittent resources consistent with dispatchable resources. Entergy Region refers to the area served by or in close proximity to the Entergy Operating Companies.


* Lead times preclude deployment in 2012 or First Year Available from Vendor if later than 2012.

39

RENEWABLE TECHNOLOGIES ASSUMPTIONS


Characteristic Units Biomass – CFB Wind – On Shore Wind – Off Shore Solar - PV

First Year Available from Vendor* (Yr) 2006 2021 2021 2021

Size (MW) 50 75 120 50

Number of Units (#) 1 50 40 1

Typical Development Time (Yrs.) 2 1 2 2

Typical Construction Time (Yrs.) 3 1 2 1.5

Overnight Cost ($/kW) $5,288 $2,356 $3,263 $4,791

Installed Cost ($/kW) $6,214 $2,547 $3,868 $5,428

Heat Rate (Btu/kWh) 11,000 NA NA NA

Typical Capacity Factor (%) 85 45 60 24

Fixed O&M ($/kW-yr) $86.87 $49.64 $111.69 $24.82

Variable O&M ($/MWh) $3.72 $1.24 $1.24 $0.00

NOx (lbs/MMBtu) 0 0 0 0

SO2 (lbs/MMBtu) 0 0 0 0

CO2 (lbs/MMBtu) 0 0 0 0

Hg (lbs/MMBtu) 0 0 0 0

Useful Life (Yrs.) 30 20 20 25

Does not include any possible cost subsidization. Does not include capacity match cost or flexible capability cost to make intermittent resources consistent with dispatchable resources. Entergy Region refers to the area served by or in close proximity to the Entergy Operating Companies.


*First year of commercial operation equals first year available plus construction time.

40

CANDIDATE TECHNOLOGY INSTALLED CAPITAL COST PROJECTIONS (2011-2030)


Installed Capital Cost ($/kW)Installed Capital Cost ($/kW)

Dollars are stated in Nominal values including both Real cost changes and inflation. Does not include any cost subsidization or REC value.

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 … 2025… 2030

Combustion Turbines:

CT – 7F $900 $929 $974 $1,004 $1,075 $1,071 $1,076 $1,092 $1,108 $1,142 $1,170 $1,194 $1,267 $1,427

CT – LM6000 $1,200 $1,239 $1,299 $1,338 $1,434 $1,427 $1,435 $1,456 $1,478 $1,522 $1,561 $1,592 $1,689 $1,828

CT – LMS 100 $1,250 $1,291 $1,353 $1,394 $1,493 $1,487 $1,494 $1,517 $1,539 $1,586 $1,626 $1,658 $1,760 $1,943

Combined Cycle:

CCGT – 7F (2x1) $1,350 $1,395 $1,471 $1,524 $1,619 $1,635 $1,643 $1,667 $1,692 $1,734 $1,778 $1,814 $1,925 $2,125

CCGT – 7F (1x1) $1,650 $1,705 $1,798 $1,863 $1,979 $1,998 $2,008 $2,037 $2,068 $2,120 $2,173 $2,217 $2,352 $2,597

CCGT – 7H $1,700 $1,757 $1,853 $1,920 $2,039 $2,059 $2,069 $2,099 $2,130 $2,184 $2,239 $2,284 $2,424 $2,676

Solid Fuel:

PC $2,700 $2,806 $2,959 $3,066 $3,256 $3,338 $3,304 $3,353 $3,402 $3,452 $3,521 $3,592 $3,812 $4,209

PC w/Carbon Capture - - - - - - - - - - $5,902 $6,020 $6,388 $7,053

CFB $3,300 $3,429 $3,616 $3,747 $3,980 $4,079 $4,038 $4,098 $4,158 $4,220 $4,304 $4,390 $4,659 $5,144

Nuclear $7,500 $7,826 $8,043 $8,234 $8,461 $8,599 $8,738 $8,880 $9,057 $9,238 $9,423 $9,612 $10,200 $11,262

Biomass $4,700 $4,856 $5,067 $5,249 $5,658 $5,659 $5,571 $5,682 $5,826 $5,942 $6,092 $6,214 $6,594 $7,281

Wind (On-Shore) $2,000 $2,033 $2,086 $2,072 $2,355 $2,501 $2,399 $2,375 $2,420 $2,478 $2,512 $2,547 $2,656 $2,847

Wind (Off-Shore) $3,500 $3,558 $3,594 $3,511 $3,936 $4,116 $3,883 $3,782 $3,793 $3,822 $3,815 $3,868 $4,033 $4,323

Solar PV $5,000 $5,166 $5,287 $5,371 $5,682 $5,569 $5,371 $5,371 $5,400 $5,400 $5,428 $5,428 $5,428, $5,428

41


III. Detailed Modeling






Detail Modeling


Conclusions

I. II. III. IV.

42

FUEL AND EMISSIONS ALLOWANCE CREDITS PRICES


Forecasts:

SPO has developed long-term forecasts for relevant fuel prices and emission allowance prices. Because these prices can have a large impact on the viability of competing technologies, where appropriate multiple forecasts have been made in order to see how robust a given technology is relative to its underlying fuel; and emissions allowance price forecasts.

Delivered Natural gas prices:

The technology assessment is based on the SPO Henry Hub natural gas price forecast dated January 19, 2012. Actual delivered gas prices to a specific plant could be a little higher or lower than the Henry Hub price. The Henry Hub, located at Erath Louisiana connects to nine interstate and four intrastate gas pipelines. There are three gas price forecasts cases used in this assessment:

Levelized Nominal Prices for the years 2012-2041Low $4.22/MMBtuReference $6.29/MMBtuHigh $8.46/MMBtu

Levelized Nominal Prices for the years 2022-2051Low $5.57/MMBtuReference $9.08/MMBtuHigh $13.40/MMBtu

Delivered Coal Prices

The technology assessment is based on the SPO Delivered Coal Reference Price forecast January 25, 2012. Actual delivered coal prices to a specific plant could be a little higher or lower than this forecast which is a volume weighted average of delivered coal prices at White Bluff, Independence, Nelson 6 and Entergy’s minority interest at Big Cajun 2, Unit 3. In order to provide for uncertainty in long-term coal prices Low and High Coal Price Forecast were also considered. These alternative forecast were $1.00 (nominal) per MMBtu higher or lower than the Reference Case.

Levelized Nominal Prices for years the 2012-2051 (PRB)Low $2.35 $/MMBtuReference $3.35 $/MMBtuHigh $4.35 $/MMBtu

Levelized Nominal Prices for the years 2022-2061 (PRB)Low $3.16 $/MMBtuReference $4.16 $/MMBtuHigh $5.16 $/MMBtu

43



Delivered Biomass Prices Delivered Nuclear Fuel Cost

The technology assessment is based on the SPO Delivered Biomass Reference Price forecast June 4, 2010. Actual delivered biomass prices to a specific plant could be higher or lower than this forecast . SPO monitors market prices for biomass and does not believe the outlook for prices has materially changed since the 2010 forecast. The forecast is based on a market survey of Pine Pulpwood Stumpage plus forecast escalations for timber and lumber and general freight trucking through 2020. Prices beyond 2020 are held constant in real terms.

Levelized Nominal Price for the 30 years 2012-2041Reference $3.93/MMBtu


The technology assessment for long-term nuclear fuel cost is based on the SPO Generic Nuclear Fuel forecast dated December 21, 2011. This forecast is derived from a more detailed unit level long-term forecast prepared by Entergy Nuclear’s Fuel Group on August 19, 2011. Due to the relative stability of nuclear fuel cost and the small share of total cost at nuclear plants, High and Low Sensitivity cases are not necessary.



44



CO2 Price Forecasts

The Technology Assessment ranks technologies under two different states of the world. One state is that resources are not subject to carbon constraints. The second is that resources become subject to meaningful carbon constraints in the future.

The CO2 price forecast used in the Technology Assessment assumes a cap and trade program beginning in 2023 at about $24 per ton nominal and escalating about 7 to 8 percent nominally per year through 2050. The POV assumes that price must rise faster than inflation until global goals of CO2 reduction are reached.

Levelized CO2 Nominal Prices for the years as specified below ($/Short Ton)

2012-2041 (30 Years For Use with CCGT, CT) $13.432022-2051 (30 Years For Use with CCGT, CT) $46.55

2012-2051 (40 Years for use with Coal Plants) $18.402022-2061 (40 Years for use with Coal Plants) $55.32

NOx, SO2 Price Forecasts

The Technology Assessment assumes that the Cross State Air Pollution Rule “CSAPR” as finalized by the Environmental Protection Agency “EPA” in July 2011 with October 2011 EPA proposed modifications survives court challenges. Under CSAPR AR/LA/MS are only subject to seasonal NOx restrictions. While TX is also subject to annual NOx and annual SO2 restrictions, the Technology POV will use the AR/LA/MS rules for its bus bar comparisons. Because the Technology POV focuses on new technologies which are generally lower emitting that older resources, the assumptions around CSAPR rules and allowances prices for covered emissions have only a minor impact around total bus bar cost of various resources. The Technology Assessment does not consider the impacts of EPA’s Acid Rain Program because allowance cost for this program are expected to be zero. Other currently proposed EPA rules that affect the power sector such as the proposed Mercury MACT Rule are not expected to utilize a cap and trade or emissions tax compliance mechanism.

Levelized NOX Nominal Prices for the years as specified below ($/Short Ton)

2012-2041 (30 Years For Use with CCGT, CT) $73.302022-2051 (30 Years For Use with CCGT, CT) $106.97

2012-2051 (40 Years for use with Coal Plants) $77.562022-2061 (40 Years for use with Coal Plants) $110.76

45

CCGT TECHNOLOGY


State of Technology:

CCGT technology is mature. However, equipment manufactures continue to push incremental technological advances. Among the expected improvements are reductions in heat rate, start up time, and emissions.

Capability:

Factoring in capital cost, heat rate, fuel cost, and operating performance CCGT technology is economically and operationally suited for dispatchable load following duty in the capacity factor range of 25 percent and higher.

Once CCGT technologies such as GE’s “H” class turbines are commercially available CCGTs are expected to be more competitive in a baseload duty applications.

Risk:

CCGT technology is economic across a wide range of operating roles and capacity factors. Favorable economics are based on reasonably low capital cost compared to solid fuel technologies and expected stable natural gas prices.

CCGTs utilizing natural gas as a fuel source emit less greenhouse gases than carbon based solid fuel technologies.

While CCGTs are well suited for dispatchable load following role operational stress may increase maintenance cost from repeated cycling.

46

$75

$85

$95

$105

$115

$125

$135

$145

$155

$165

$175

25% 35% 45% 55% 65% 75% 85%

$/M

Wh

Capacity Factor (%)

CCGT - 2x1 7F CCGT - 1x1 7F CCGT - 1x1 7H

CCGT COST ANALYSISLEVELIZED NOMINAL $ @ 9.25%, 2012-2041


$0 $50 $100 $150

2x1 7F

1x1 7F

1x1 7H

$/MWh @ 65% Capacity Factor

Fixed Cost Fuel VOM CO2 NOx

Cost Elements (2012 COD)Cost Elements (2012 COD)Screening Curves (2012 COD)Screening Curves (2012 COD)

Commodity Cost Input Assumptions30 Year Levelized Nominal Prices Covering Years 2012-2041Natural Gas - $6.29/MMBtu NOx - $73.30/short tonCO2 - $13.43/short ton SO2 - $0/short ton

47

CT TECHNOLOGY



CT technology is mature. As with CCGTs, equipment manufactures are expected to continue to push incremental advances such as improvements in heat rate and lower emissions.

Capability:

High heat rate, compared to CCGT, and higher cost natural gas, compared to solid fuels, combine to make CTs primarily suited for peaking duty roles with a capacity factor range up to 25 percent.

Risk:

CTs are economic for peaking roles based on reasonably low capital cost, short construction lead times, flexible siting options, and low emissions rates.

While suited for a peaking role CT’s heat rates and fuel cost make the technology less economic for dispatchable load following roles.

48

$100

$150

$200

$250

$300

$350

$400

$450

$500

5% 15% 25% 35% 45%

$/M

Wh

Capacity Factor (%)

CT - 7FA CT- LM6000 CT - LMS 100

CT COST ANALYSISLEVELIZED NOMINAL $ @ 9.25% , 2012-2041


$0 $50 $100 $150 $200 $250

CT - 7F

CT -LM6000

CT - LMS100





49

SOLID FUEL (PC) TECHNOLOGY



Both PC and CFB technologies are mature technologies. Future development will focus on increased boiler efficiency and carbon capture and storage.

Increasing boiler pressure and temperature improves efficiency and reduces emissions. However, these benefits come at an increased cost. The increase in pressure and temperature requires the use of exotic alloys resulting in higher cost to building and operate supercritical and ultra supercritical units.

Capability:

Low fuel cost and high capital cost make these technologies suitable for consideration in baseload applications.

Risk:

Coal’s environmental footprint creates a significant challenge to future deployment of solid fuel burning technologies. In particular, coal fired facilities are high carbon emitters. Absent the development of an economic carbon capture and storage technology future coal deployments will be limited.

The ultimate cost of carbon capture technology is unknown but preliminary estimates including the cost of parasitic load loss are included in this technology assessment. Based on these projections and given the CO2 cost under cap and trade in this analysis (starting at about $24 per short ton in 2023 (nominal dollars) and escalating at about 7% each year until 2050 (with inflation, post 2050) , it would be more economic to purchase allowances than to invest in carbon capture technology.

50

$100$110$120$130$140$150$160$170$180$190$200$210$220

50% 55% 60% 65% 70% 75% 80% 85%

$/M

Wh

Capacity Factor (%)

PC PC w/CCS CFB

SOLID FUEL COST ANALYSIS(LEVELIZED NOMINAL $ @ 9.25% ,2012-2051)


$0 $50 $100 $150 $200

PC

PC w/CCS

CFB




Commodity Cost Input Assumptions40 Year Levelized Nominal Prices Covering Years 2012-2051PRB Coal- $3.35/MMBtu NOx - $77.56/short tonCO2 - $18.40/short ton SO2 - $0/short ton

51

RENEWABLES (INTERMITTENT) TECHNOLOGY



Wind turbine technology is the most mature of the Renewable technologies. Future incremental technology improvements will focus on larger turbine size and improved control systems with a goal of achieving capacity factors of nearing 50% in the most attractive wind speed sites. The highest on shore capacity factors achievable in and around the Entergy Operating Companies is expected to be 36% over the 2012-2021 planning horizon and 43% over the 2022-2031 planning horizon. Off shore wind capacity factors are expected to be about 30% and 50% respectively.

Solar PV is an established technology with improvements focused on increasing conversion efficiency and reducing capital cost. Over the next two decades conversion efficiency is expected to improve In the most attractive solar .regions (the Desert Southwest capacity factors currently average 20%. Capacity factor in and around the Entergy Operating Companies are expected to be 13% over the 2012-2021 planning horizon and 16% over the 2022-2031 planning horizon due to lower solar radiation intensity.

Capability:

Intermittent renewable technologies are highly dependent on wind and solar radiation as “fuel” sources and as such are considered “as available” resources providing limited energy and little peak capacity.

Risk:

The intermittent nature of wind and solar PV resources impact planning and operational activities due to the utility’s need to provide back-up and flexible capable resources to support wind and solar PV generation.

Additionally, most suitable sites for wind and solar PV are remote to the region and are expected to require additional transmission resources to deliver the energy. This Technology Assessment does not consider incremental transmission investment spending in its cost estimates.

When comparing intermittent resources to dispatchable resources capacity match up cost and flexible capability cost are included to make economic comparisons meaningful.

52

$100

$300

$500

$700

$900

$1,100

$1,300

$1,500

$1,700

$1,900

5% 10% 15% 20% 25% 30% 35% 39% 45%

$/M

Wh

Capacity Factor (%)

Wind Solar PV

RENEWABLES (INTERMITTENT) COST ANALYSISLEVELIZED NOMINAL $ @ 9.25% , WIND 2012-2031, SOLAR 2012-2036


$0 $100 $200 $300 $400 $500

Wind

Solar PV


Fixed Cost Fuel VOM Matchup Flex. Cap.


Does not include any cost subsidization or REC price value Include capacity match cost and flexible capability cost to make intermittent resources consistent with dispatchable resources.

53

RENEWABLES (BASELOAD) TECHNOLOGY



Biomass technology is mature. Environmental concerns are expected to cause stoker boiler technology to decline in use in favor of CFB technology.

Capability:

With a stable fuel supply biomass units can operate as a baseload resource with capacity factors approaching 80% or more.

Risk:

High capital cost for biomass plants will mean developers will need government incentives to compete with other generation technologies.

Stable fuel supply and/or co-firing with carbon based fuels will improve unit availability.

54

$100

$150

$200

$250

$300

$350

25% 35% 45% 55% 65% 75%

$/M

Wh

Capacity Factor (%)

Biomass (CFB)

RENEWABLES (BASELOAD) COST ANALYSISLEVELIZED NOMINAL @ 9.25% ,2012-2041)


$0 $50 $100 $150

Biomass


Fixed Cost Fuel VOM Matchup Flex. Cap.


Does not include any cost subsidization or REC price value

Biomass Fuel Cost Assumptions: (30 Year Levelized Nominal 2012-2041)$3.93/MMBtu

55

NUCLEAR TECHNOLOGY



Nuclear technology is mature, accounting for nearly 20% of U.S. electricity generation. Nuclear generation produces no greenhouse gas emissions and does not rely on fossil fuels there by providing energy security.

Capability:

Nuclear generation’s high capital cost and low operating cost makes it best suited for baseload operations so as to minimize cost on a dollar-per-megawatt-hour basis.

Risk:

Large investment, the potential for significant cost overruns, and long lead times for permitting and construction limit utility interest in nuclear generation.

Delays in NRC review and approval of new construction and operating permits are likely prevent any new nuclear units from completing construction during the first ten years of the planning horizon.

56

$130

$140

$150

$160

$170

$180

$190

$200

$210

65% 70% 75% 80% 85% 90%

$/M

Wh

Capacity Factor (%)

Nuclear

NUCLEAR COST ANALYSISLEVELIZED NOMINAL $ @ 9.25%, 2012-2051


$0 $25 $50 $75 $100 $125 $150

Nuclear




Fuel Cost Assumptions: (40 Year Levelized Nominal 2012-2051) $1.24/MMBtu

Does not include any cost subsidization.

57


IV. Conclusions






Detail Modeling


Conclusions

I. II. III. IV.

58

PEAKING GENERATION


Resources operating as Peaking resources should be able start quickly, operate for relatively short periods of time and then shut down on a daily, or intra-day basis. Expectations are that resources serving this role will experience utilization factors of 15% or less.

To be economic, Peaking resources will have relatively low capital cost and higher variable cost. In this case the lower capital cost is spread across fewer megawatt hours (“MWh”). Among the technologies considered CT and CCGT technologies offer the best fit for the peaking role.

Considering the low capital cost, short deployment period, and quick start capability Combustion Turbines, CT, are the preferred technology for new capacity serving in the Peaking role for both the ten year planning period starting in 2012 and the second ten year planning period starting in 2022. Under most peaking roles a CT with General Electric 7F technology (or similar technology from a different vendor ) is preferred due to lower capital cost, on a dollar per kW basis, than aero-derivative CTs.

59

PEAKING GENERATIONLevelized Nominal $ @ 9.25%, 2012-2041


$100

$150

$200

$250

$300

$350

$400

$450

$500

$550

5% 10% 15% 20% 25% 30%

$/M

Wh

Capacity Factor (%)CCGT - 2x1 7F CT - LMS 100 CT - LM6000 CT - 7F

Screening Curves (2012 COD)Screening Curves (2012 COD)

$0

$50

$100

$150

$200

$250

CT - 7FA CT - LM6000 CT - LMS 100 CCGT - 2 7FA$/

MW

h @

15%

Cap

acity

Fac

tor


Cost Elements (2012 COD)Cost Elements (2012 COD)


60

PEAKING GENERATION (SENSITIVITY)LEVELIZED NOMINAL $ @ 9.25%, 2012-2041


$100

$150

$200

$250

$300

$350

$400

$450

$500

$550

5% 10% 15% 20% 25% 30%

$/M

Wh


High Gas Price Sensitivity (2012 COD)High Gas Price Sensitivity (2012 COD)

$100

$150

$200

$250

$300

$350

$400

$450

$500

$550

5% 10% 15% 20% 25% 30%$/

MW

h


Low Gas Price Sensitivity (2012 COD)Low Gas Price Sensitivity (2012 COD)

Commodity Cost Input Assumptions30 Year Levelized Nominal Prices Covering Years 2012-2041Natural Gas Low- $4.22/MMBtu NOx - $73.30/short tonNatural Gas High- $8.46/MMBtu SO2 - $0/short ton CO2 - $13.43/short ton

61

PEAKING GENERATIONLEVELIZED NOMINAL $ @ 9.25%, 2022-2051


$150

$200

$250

$300

$350

$400

$450

$500

$550

$600

$650

$700

5% 10% 15% 20% 25% 30%

$/M

Wh



$0

$50

$100

$150

$200

$250

$300

CT - 7FA CT - LM6000 CT - LMS 100 CCGT - 2 7FA$/

MW

h @

15%

Cap

acity

Fac

tor




62

DISPATCHABLE LOAD FOLLOWING GENERATION


Resources operating in the Dispatchable Load Following Role should be to react to the dynamics of ever changing and unpredictable load as well as the physical and mechanical capabilities of other units used to serve load. Expectations are that resources in the Dispatchable Load Following Role will see utilization factors that could range from as low as 20% to as high as 80% with 50% to 65% seen as a typical load factor range.

To be economic, Dispatchable Load Following resources need to have both moderate capital cost and variable cost. Among the technologies considered, CT, CCGT, PC, and CFB technologies offer the best fit for load following.

Factoring in low capital cost, short deployment period, and suitability for the load following, CCGT is the preferred technology for the dispatchable load following role. Additional analysis indicates that CCGT is still the economic under a high gas price scenario. Under most load following roles a CCGT in a 2X1 configuration with General Electric 7FA technology combustion turbines (or similar technology from a different vendor) is preferred due to lower cost and performance than other CCGT Technologies.

63

DISPATCHABLE LOAD FOLLOWING GENERATIONNOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (CT/CCGT 30 YEARS , PC/CFB 40 YEARS)


$50

$100

$150

$200

$250

$300

30% 40% 50% 60% 70% 80%

$/M

Wh

Capacity Factor (%)CT - 7F CCGT -2x1 PC CFB


$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

CT - 7FA CCGT - 2x1 PC CFB$/

MW

h @

65%

Cap

acity

Fac

tor

Fixed Cost Fuel VOM CO2 NOx SO2


Commodity Price Assumptions:30 year Levelized Nominal (2012-2041)-Natural Gas - $6.29/MMBtuCO2 - $13.43/tonNOX - $73.30/tonSO2 - $0/ton

40 year Levelized Nominal (2012-2051)–Coal - $3.35/MMBtuCO2 - $18.40/tonNOX - $77.56/tonSO2 - $0/ton

64

DISPATCHABLE LOAD FOLLOWING GENERATIONNOMINAL LEVELIZED $ @9.25% OVER EXPECTED LIFE OF RESOURCE (CT/CCGT 30 YEARS , PC/CFB 40 YEARS)


$50

$100

$150

$200

$250

$300

30% 40% 50% 60% 70% 80%

$/M

Wh


Levelized Nominal $ Over Expected Life of Resource


Commodity Price Assumptions:30 year Levelized Nominal (2012-2041) -Natural Gas – (Ref) $6.29/MMBtu

(High) $8.46/MMBtuCO2 - $13.43/tonNOX - $73.30/tonSO2 - $0/ton

40 year Levelized Nominal (2012-2051)–Coal – (Ref) $3.35/MMBtu

(Low) $2.35/MMBtuCO2 - $18.40/tonNOX - $77.56/tonSO2 - $0/ton

No Carbon Cost Sensitivity (2012)No Carbon Cost Sensitivity (2012)

Low Coal Price Sensitivity (2012 COD)Low Coal Price Sensitivity (2012 COD)

$50

$100

$150

$200

$250

$300

30% 40% 50% 60% 70% 80%

$/M

Wh



$50

$100

$150

$200

$250

$300

30% 40% 50% 60% 70% 80%

$/M

Wh



65

DISPATCHABLE LOAD FOLLOWING GENERATIONNOMINAL LEVELIZED $ @ 9.25 OVER EXPECTED LIFE OF RESOURCE (CT/CCGT 30 YEARS , PC/CFB 40 YEARS)


$100

$150

$200

$250

$300

$350

$400

30% 40% 50% 60% 70% 80%

$/M

Wh



$0

$50

$100

$150

$200

$250

CT - 7FA CCGT - 2x1 PC w/CarbonCap.

CFB$/

MW

h @

65%

Cap

acity

Fac

tor




40 year Levelized Nominal (2022-2061) –Coal - $4.16/MMBtuCO2 - $55.32/tonNOX - $110.76/tonSO2 - $0/ton

66

BASE LOAD GENERATION


Resources operating in the Base Load Role should be available to serve load most hours of the year. Expectations are that resources in the Base Load will see utilization factors exceeding 85%.

Base Load resources can be expected to cost more to construct but operate at fairly low cost. The combination of capital and operating cost is economic since operating at a high utilization factor allows capital cost to be spread over more MWh. Technologies offering the best fit for the Base Load role are: CCGT, PC, CFB, and nuclear. . In regards to CCGTs a 2x1 configuration with General Electric 7FA technology combustion turbines (or similar technology from a different vendor) is preferred during the first ten year planning period (2012-2021) due to lower cost and performance than other CCGT technologies. However, by the second ten years of the planning period 2022-2031 the GE H Class CCGT in a 2x1 configuration is expected to offer the lowest cost and performance in a base load operating role. In regards to coal PC is generally believed to be lower cost than CFB, however, proximity to alternative fuel sources like petroleum coke more advantages in some settings.

The ideal choice of baseload technology is currently CCGT. Declines in the long-term outlook for natural gas prices has been the biggest single driver.

This technology assessment has stressed that assumption under eighteen different combinations of future natural gas, coal and CO2 prices. In a large majority of cases, including the Reference Case scenarios for these inputs the CCGT is preferred. In the few cases the CCGT was not preferred the cost difference between it and the preferred choice was small.

This technology assessment has stressed that assumption under eighteen different combinations of future natural gas, coal and CO2 prices. In a large majority of cases, including the Reference Case scenarios for these inputs the CCGT is preferred. In the few cases the CCGT was not preferred the cost difference between it and the preferred choice was small.

In addition to lower forecasted total supply cost per MWh CCGTs also offer the following advantages over coal and nuclear resources:

-Lower upfront capital cost-Shorter development and construction time meaning lower financing cost-Easier siting and smaller environmental footprint-Likely to have less environmental group opposition-Shorter payback period in case operating conditions or fuel and emissions allowance cost change.-Able to operate under a wide range of operating roles and contributes to flexible capability

67

BASE LOAD GENERATIONNOMINAL LEVELIZED $ @9.25 OVER EXPECTED LIFE OF RESOURCE (CT/CCGT 30 YEARS , PC/CFB/NUCLEAR 40 YEARS)


$75

$100

$125

$150

$175

$200

70% 75% 80% 85% 90% 95%

$/M

Wh

Capacity Factor (%)

CCGT -2x1 CCGT - 7H PC CFB Nuclear


$0

$20

$40

$60

$80

$100

$120

$140

$160

CCGT - 2x1 CCGT - 7H PC CFB Nuclear$/

MW

h @

90%

Cap

acity

Fac

tor



Commodity Price Assumptions:30 year Levelized Nominal (2012-2041)Natural Gas - $6.29/MMBtu CO2 - $13.43/tonNOX - $73.30/tonSO2 - $0/ton

40 year Levelized Nominal (2012-2051) –Coal - $3.35/MMBtuNuclear - $1.24/MMBtuCO2 - $18.40/tonNOX - $77.56/tonSO2 - $0/ton

68

BASE LOAD GENERATION (SENSITIVITIES)NOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (CT/CCGT 30 YEARS , PC/CFB/NUCLEAR 40 YEARS)


$80

$130

$180

70% 80% 90%

$/M

Wh

Capacity Factor (%)CCGT -2x1 CCGT -7H PCCFB Nuclear


Commodity Price Assumptions:30 year Levelized Nominal (2012-2041) -Natural Gas – (Ref) $6.29/MMBtu

(High) $8.46/MMBtuCO2 - $13.43/tonNOX - $73.30/tonSO2 - $0/ton

40 year Levelized Nominal (2012-2051) –Coal – (Ref) $3.35/MMBtu

(Low) $2.35/MMBtuNuclear - $1.24/MMBtuCO2 - $18.40/tonNOX - $77.56/tonSO2 - $0/ton

No Carbon Cost Sensitivity (2012 COD)No Carbon Cost Sensitivity (2012 COD)

Low Coal Price Sensitivity (2012 COD)Low Coal Price Sensitivity (2012 COD)

$50

$100

$150

$200

70% 80% 90%

$/M

Wh


$50

$100

$150

$200

70% 80% 90%

$/M

Wh


Levelized Nominal $ Over Expected Life of Resource Levelized Nominal $ Over Expected

Life of Resource


69

BASE LOAD GENERATIONNOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (CT/CCGT 30 YEARS , PC/CFB/NUCLEAR 40 YEARS)


$100

$125

$150

$175

$200

$225

$250

$275

$300

70% 75% 80% 85% 90% 95%

$/M

Wh

Capacity Factor (%)

CCGT - 7H PC CFB Nuclear


$0

$50

$100

$150

$200

$250

CCGT PC CFB Nuclear$/

MW

h @

90%

Cap

acity

Fac

tor




40 year Levelized Nominal (2022-2061)–Coal - $4.16/MMBtuNuclear - $1.53/MMBtuCO2 - $55.32/tonNOX - $110.76/tonSO2 - $0/ton

70

RENEWABLES VERSUS CONVENTIONAL GENERATION


In and around the area served by the Entergy Operating Companies absent government subsidies or mandates the cost of power from renewable generation alternatives continues to be above that of a CCGT given Reference Case assumptions. This is currently forecasted to hold true for new resource installations over the next twenty years. This conclusion is made in light of recent and expected future improvements to both CCGT and renewable technologies.

Of the renewable technologies wind power is likely to be the most cost competitive with natural gas fired generation. However, the continued decline in the long-term outlook for natural gas prices has put pressure on wind’s economics relative to natural gas fired resources. The realization that started in late 2008 that shale and other non conventional gas resources would have profound affects on supply and demand fundamentals has had led the power industry to gravitate to CCGT and CTs as the resource of choice.

Furthermore, the current federal political climate has shifted away from supporting renewable technologies. Current federal tax incentives for renewables could expire as soon as year-end 2012.

Finally the outlook for near-term CO2 regulation has also dimmed improving the relative economics of CCGT and CTs versus renewable generation.

71

RENEWABLES VS. CONVENTIONAL (PEAKING)NOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (30 YEARS CT, 25 YEARS SOLAR, 20 YEARS WIND)



$0

$100

$200

$300

$400

$500

$600

$700

CT - 7F Wind Solar PV$/

MW

h @

15%

Cap

acity

Fac

tor

Fixed Cost Fuel VOM CO2 NOx Matchup Flex Cap


Does not include any cost subsidization or REC price value. Includes capacity match cost and flexible capability cost to make intermittent resources comparable with dispatchable resources.

$100

$350

$600

$850

$1,100

$1,350

$1,600

5% 10% 15% 20% 25% 30% 35% 40%

$/M

Wh

Capacity Factor (%)CT - 7F Wind Solar PV


72

RENEWABLES VS. CONVENTIONAL (PEAKING)NOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (30 YEARS CT, 25 YEARS SOLAR, 20 YEARS WIND)


Screening Curves (2022 COD)Screening Curves (2022 COD) Cost Elements (2022 COD)Cost Elements (2022 COD)


$0

$100

$200

$300

$400

$500

$600

$700

CT - 7F Wind Solar PV$/

MW

h @

15%

Cap

acity

Fac

tor


$100

$350

$600

$850

$1,100

$1,350

$1,600

$1,850

5% 10% 15% 20% 25% 30% 35% 40% 45%

$/M

Wh

Capacity Factor (%)CT - 7F Wind Solar PV


73

RENEWABLES VS. CONVENTIONAL GENERATIONNOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (30 YEARS CCGT, 25 YEARS SOLAR, 20 YEARS WIND)


$50

$150

$250

$350

$450

$550

15% 25% 35% 45% 55% 65%

$/M

Wh

Capacity Factor (%)CCGT -2x1 Wind Solar PV



$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

CCGT (65% CF) Wind (39% CF) Solar PV (20% CF)$/

MW

h @

Indi

cate

d Ca

paci

ty F

acto

r


Capacity Factors for Wind and Solar PV are their expected maximum

capacity factors

Assumptions: 30 Year Levelized Nominal (2012-2041)Natural Gas – $6.29/MMBtu

CO2 - $13.43/tonNOX - $73.30/ton

SO2 - $0/ton

74

RENEWABLES VS. CONVENTIONAL GENERATIONNOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (30 YEARS CCGT, 25 YEARS SOLAR, 20 YEARS WIND)




$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

CCGT (65% CF) Wind (45% CF) Solar PV (24% CF)$/

MW

h @

Indi

cate

d Ca

paci

ty F

acto

r


Capacity Factors for Wind and Solar PV are their expected maximum

capacity factors

$50

$150

$250

$350

$450

$550

$650

15% 25% 35% 45% 55% 65%

$/M

Wh

Capacity Factor (%)CCGT -2x1 Wind Solar PV

Assumptions: 30 Year Levelized Nominal (2022-2051)Natural Gas - $9.08/MMBtu

CO2 - $46.55/tonNOX - $106.97/ton

SO2 - $0/ton

75

RENEWABLES VS. CONVENTIONAL GENERATIONNOMINAL LEVELIZED $ @ 9.25% OVER EXPECTED LIFE OF RESOURCE (30 YEARS CCGT & BIOMASS CFB)


$50

$75

$100

$125

$150

$175

$200

60% 65% 70% 75% 80% 85%

$/M

Wh

Capacity Factor (%)CCGT -2x1 Biomass


$0

$20

$40

$60

$80

$100

$120

$140

$160

CCGT - 2x1 Biomass$/

MW

h @

75%

Cap

acity

Fac

tor



Does not include any cost subsidization or REC price value. Biomass assumed to be fully dispatchable.


Biomass - $3.93/MMBtuCO2 - $13.43/ton

NOX - $73.30/tonSO2 - $0/ton

76

RENEWABLES VS. CONVENTIONAL GENERATIONNOMINAL LEVELIZED @ 9.25% OVER EXPECTED LIFE OF RESOURCE (30 YEARS CCGT & BIOMASS CFB)



$100

$125

$150

$175

$200

$225

$250

60% 65% 70% 75% 80% 85%

$/M

Wh

Capacity Factor (%)CCGT -7H Biomass

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

CCGT - 7H Biomass$/

MW

h @

75%

Cap

acity

Fac

tor


Does not include any cost subsidization or REC price value. Biomass assumed to be fully dispatchable.


Biomass - $4.80/MMBtuCO2 - $46.55/ton

NOX - $106.97/tonSO2 - $0/ton

7777

LEVELIZED COST OF ELECTRICITY FOR VARIOUS TECHNOLOGIES

0

50

100

150

200

250

300

CT-7FA

LM6000

CT-LM

S 100

CC

GT-2 7FA

CT - 7FA

CC

GT - 2x1

CC

GT - 2x1

CC

GT - 7H

PC CFB

Nuclear (G

en III)

Wind (39%

CF)

Solar PV (20% C

F)

Biomass (75%

CF)

Peaking (15% CF) LoadFollowing(65% CF)

Base Load (90% CF) Renewables

Fixed Cost Fuel VOM NOx CO2 Integration

$438

Notes:• Costs not adjusted to

include subsidies (ITC/PTC)• Jan. 2012 Technology

Assessment for 2012 IRP.• Reference case

assumption for newtechnologies ifdeployed in 2012.

• 30-year levelized(2012-2041) cost assumption Nominal $:

– Natural gas $6.29/MMBtu

– Biomass :$3.93/MMBtu– CO2: $13.43/ton– NOx :$73.30/ton– SO2: $0/ton

• 40-year levelized(2012-2051) cost assumption Nominal $:

– Coal: $3.35/MMBtu– Nuclear: $1.24/MMBtu– CO2: $18.40/ton

NOx :$77.56/ton– SO2 :$0/ton

• Useful life:– CCGT, CT & Biomass 30

years– Coal & Nuclear 40 years– Wind 20 years– Solar PV 25 years

$/MWh


78

CONVENTIONAL ALTERNATIVES


182

107

98

55

19

Nuclear

Coal

CCGT w/o CO2

CO2

50

100

150

200

250

300

10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60%

And in 2022For base load CCGT is low cost alternative now . . .

CT is preferred over CCGT below about 30% Capacity FactorGas Fired CT / CCGT offers Lowest Capital Cost

900 1,350 2,700

7,500

CT CCGT Coal Nuclear

148

85

72

18

6

Nuclear

Coal

CCGT

w/o CO2

CO2

Installed Cost (2011$/kW) $/MWh (2012 Installation)*

Bus Bar Cost $/MWh (90% Capacity Factor)*Bus Bar Cost/MWh (90% Capacity Factor)*

*Bus bar cost levelized in nominal $/MWh over expected life of resource (30 years CCGT & CT, 40 years coal and nuclear). CO2compliance cost begins in 2023 and escalates over time.

CCGT

CT

79

(5)

(6)

(10)

(16)

5

8

10

16

SENSITIVITIES



(12)

(13)

0

(6)

12

16

0

6

(3)

(5)

(4)

(22)

3

6

4

22

± 10$/Ton CO2

± 10% Installed Cost

± 50% Fuel Cost

± 10% Capacity Factor

NuclearGas-Fired CCGT Coal

Gas-fired CCGT economics remain favorable across range of assumptions*

65% 90%80%

80

RENEWABLE ALTERNATIVES



2022 In Service Date

$308

$123

$141

Solar

Wind

Biomass

$404

$151

$173

Solar

Wind

Biomass

$327

$112

$113

Solar

Wind

Biomass

$438

$137

$138

Solar

Wind

Biomass

$/MWh Without Incentives* $/MWh With Incentives*

$/MWh Without Incentives* $/MWh With Incentives*

CCGT w/o CO2 CCGT with CO2CCGT w/o CO2 CCGT with CO2

CCGT w/o CO2 CCGT with CO2 CCGT w/o CO2 CCGT with CO2

Documents

2012 GENERATION TECHNOLOGY ASSESSMENT - · PDF fileThe 2012 Generation Technology Assessment begins by surveying available central state electricity generation technologies, generally