Levelized Cost of New Electricity Generating Technologies
May 12, 2009· 14 Comments
The Energy Information Administration (EIA) produces forecasts of energy supply and demand for the next 20 years using the National Energy Modeling System (NEMS)[1]. These forecasts are updated annually and published in the Annual Energy Outlook (AEO). EIA published a preliminary version of the AEO 2009 in December 2008, and updated the forecasts in April, 2009, to incorporate the energy provisions in the stimulus.[2] All sectors of the energy system are represented in NEMS, including the electric power generation, transmission, and distribution system.
To meet electricity demand, the EIA represents the existing generating plants, retires those that have come to the end of their economic life, and builds additional plants to meet projected demand from the residential, commercial, industrial, and transportation sectors. As a result, EIA must represent a slate of technologies, their capital and operating costs, their availability and capacity factors, the financial structure and subsidies, the time to construct the plant, the utilization of the plant, and expected future cost changes, including fuel input for fossil and nuclear plants.
To determine the most economic technology for the type of demand (base, intermediate, or peaking load) for which new capacity is needed, NEMS competes the technologies based on the economics of their levelized costs. Levelized costs represent the present value of the total cost of building and operating a generating plant over its financial life, converted to equal annual payments and amortized over expected annual generation from an assumed duty cycle.
The table below provides the average national levelized costs for the generating technologies represented in the updated AEO2009 reference case.[3] The values shown in the table do not include financial incentives such as state or federal tax credits, which impact the cost and the competitiveness of the technology. These incentives, however, are incorporated in the evaluation of the technologies in NEMS based on current laws and regulations in effect at the time of the modeling exercise, as well as regional differences in the cost and performance of the technology, such as labor rates and availability of wind or sun resources.
In the AEO2009 reference case, a 3-percentage point increase in the cost of capital is added when evaluating investments in greenhouse gas intensive technologies such as coal-fired power plants without carbon capture and sequestration (CCS) technology and coal-to-liquids plants. The 3-percentage point adjustment is similar to a $15 per ton carbon dioxide emissions fee when investing in a new coal plant without CCS technology. This adjustment represents the implicit hurdle being added to greenhouse gas intensive projects to account for the possibility that they may need to purchase allowances or invest in other greenhouse gas emission-reducing projects that offset their emissions in the future. Thus, the levelized capital costs of coal-fired plants without CCS are likely higher than most current coal project costs.
The levelized cost for each technology is evaluated based on the capacity factor indicated, which generally corresponds to the maximum availability of each technology. However, some technologies, such as a conventional combined cycle turbine, that may look relatively expensive at its maximum capacity factor may be the most economic option when evaluated at a lower capacity factor associated with an intermediate load rather than base load facility.[4]
Simple combustion turbines (conventional or advanced technology) are typically used for peak load, and are thus evaluated at a 30 percent capacity factor. Intermittent renewable resources, e.g. wind and solar, are not operator controlled, but dependent on the weather or the sun shining. Since the availability of wind or solar is dependent of forces outside of the operator’s control, their levelized costs are not directly comparable to those for other technologies although the average annual capacity factor may be similar. Because intermittent technologies do not provide the same contribution to system reliability as technologies that are operator controlled and dispatched, they may require additional system investment as back-up power that are not included in the levelized costs shown below.
Levelized Cost of New Generating Technologies, 2016
Revised AEO 2009 Reference Case
| Plant Type | Capacity Factor (%) | Levelized Capital Cost | Fixed O&M | Variable O&M (including fuel) |
Transmission Investment |
Total System Levelized Cost |
| Conventional Coal | 85 | 64.5 | 3.7 | 23.0 | 3.5 | 94.6 |
| Advanced Coal | 85 | 75.6 | 5.2 | 19.3 | 3.5 | 103.5 |
| Advanced Coal with CCS | 85 | 87.4 | 6.2 | 25.2 | 3.8 | 122.6 |
| Natural Gas-fired | ||||||
| - Conventional Combined Cycle | 87 | 23.0 | 1.6 | 55.7 | 3.7 | 83.9 |
| - Advanced Combined Cycle | 87 | 22.4 | 1.5 | 52.3 | 3.7 | 79.9 |
| - Advanced CC with CCS | 87 | 43.6 | 2.6 | 65.8 | 3.7 | 115.7 |
| - Conventional Combustion Turbine | 30 | 41.3 | 4.6 | 83.6 | 10.7 | 140.2 |
| - Advanced Combustion Turbine | 30 | 38.5 | 4.0 | 71.2 | 10.7 | 124.3 |
| Advanced Nuclear | 90 | 84.2 | 11.4 | 8.7 | 3.0 | 107.3 |
| Wind | 35.1 | 122.7 | 10.3 | 0.0 | 8.5 | 141.5 |
| Wind-Offshore | 33.4 | 193.6 | 27.5 | 0.0 | 8.6 | 229.6 |
| Solar PV | 21.7 | 376.6 | 6.2 | 0.0 | 12.9 | 395.7 |
| Solar Thermal | 31.2 | 232.1 | 21.3 | 0.0 | 10.3 | 263.7 |
| Geothermal | 90 | 86.0 | 20.7 | 0.0 | 4.8 | 111.5 |
| Biomass | 83 | 71.7 | 8.9 | 23.0 | 3.9 | 107.4 |
| Hydro | 52 | 97.2 | 3.3 | 6.1 | 5.6 | 114.1 |
Source: Energy Information Administration, Annual Energy Outlook 2009 (revised), April 2009, SR-OIAF/2009-03, http://www.eia.doe.gov/oiaf/servicerpt/stimulus/index.html
[1] Energy Information Administration, NEMS documentation, http://tonto.eia.doe.gov/reports/reports_kindD.asp?type=model%20documentation
[2] Energy Information Administration, Annual Energy Outlook 2009, http://www.eia.doe.gov/oiaf/aeo/index.html
[3] Energy Information Administation, Assumptions to the Annual Energy Outlook, http://www.eia.doe.gov/oiaf/aeo/assumption/index.html
[4] Base load plants are facilities that operate almost continuously, generally at annual utilization rates of 70 percent or higher. Intermediate load plants are facilities that operate less frequently than base load plants, generally at annual utilization rates between 25 and 70 percent. Peaking plants are facilities that only run when the demand for electricity is very high, generally at annual utilization rates less than 25 percent.
May 20th, 2009 at 10:58 am
Very relevant data; our thanks and appreciation!
Two questions:
1) what was the number of years (lifetime) used for the various generating systems in the cost analysis?
2) what is the “energy pay back ratio” for the various systems (i.e. years after the total potential energy generated – since day one – is equal to the total energy used to manufacture, install and operate up to that year)
May 22nd, 2009 at 9:07 am
The financial life of the units are assumed to be 20 years, i.e. planning decisions to build a new unit are based on a life cycle cost analysis over a 20-year period. The actual life of a generating unit, however, far exceeds the 20-year financial life. The analysis retires units based on planned retirements by utility companies and past operating experience.
May 26th, 2009 at 2:08 am
Dear Administrator,
Is that possible to find the LEC cost for the systems which dont generate electricty,but produce only steam.If so,which are the factors considered?
Thanking you in advance
K.Muniasamy
May 27th, 2009 at 8:10 am
Those costs are embedded in the National Energy Modeling System that the Energy Information Administration (EIA) uses. You can see some of the cost components that go into calculating them at: http://www.eia.doe.gov/oiaf/aeo/assumption/index.html.
Select the residential, commercial, transportation, and/or industrial model components, depending on what technologies you are interested in. For combined heat and power systems, for example, see Table 6.7 in the industrial sector.
June 25th, 2009 at 1:55 am
Someone needs to compute the cost of CO2 replacing anexisting coal unit (~1 tonCO2/MWH) with generation at the above prices. For those technologies that emit zero CO2 then the above cost is the cost of removing a ton of CO2:
Nuclear $107 per ton CO2
Wind $141-229 per ton CO2
Solar $263-396 per ton CO2
Hydro $114 per ton of CO2
For technologies that emit CO2 a half ton of CO2/MWH you need to double the above costs:
Gas turbine combined cycle $160/ton CO2
These are much higher than the $15/ton on which many of the cost numbers are based. The power pools are calculating $50-100 per ton to fuel switch however the pool needs to have both sufficient coal and GTCC capacity to make it happen( and most don’t in a large scale). Consistent with this the EU had a price of about $50/ton (before overallocation of CO2 credits was discovered) which was based on utility fuel switching.
All of these are cost numbers and do not reflect market dynamics which could multiply them several fold as we’ve seen in other energy commodity markets in time of shortage or “speculation”.
THe Waxman studies base $15/ton CO2 on buying international offsets for 50-80% of the reduction. The idea that someone would sell to us at $15 when our marginal cost is $50-400 violates basic common sense. We’ll be at the mercy of a “CO2 OPEC”.
August 6th, 2009 at 8:35 am
Dear IER:
Thanks for your “Levelized Costs of New Generating Technologies” analysis. Some questions:
1. I estimate that you did the analysis from data at EIA, rather than pulling the numbers directly from EIA. Correct?
2. What accounts for the differences in your table and the EIA Figure 57 in the AEO Outlook 2009: “Least Expensive Technology Options Are Likely Choices for New Capacity”? For example, your numbers for wind power are 142 and 230 per Mw-hour and the AEO Outlook puts this number at about 100.
Thanks much,
Steve Goreham
August 10th, 2009 at 11:21 am
Steve,
The numbers come directly from EIA. They are available upon request from the Coal and Electric Power Division. The difference between the numbers in the table on the IER website, which are for 2016, and Figure 57 of the Annual Energy Outlook (AEO) 2009 is that the numbers in the table are from the revised AEO 2009 that includes the stimulus, i.e. the American Recovery and Reinvestment Act (ARRA) of February 2009. (See http://www.eia.doe.gov/oiaf/servicerpt/stimulus/index.html for EIA’s service report.) In the case of the revised AEO 2009, more wind capacity is built earlier in the forecast than in the AEO 2009 without the stimulus (10 gigawatts more by 2010 and 33 gigawatts more by 2020). As more wind units are constructed, the better wind sites are used up earlier, and wind becomes more expensive due to access and resource availability issues.
- Mary Hutzler
August 24th, 2009 at 1:46 pm
Dear IER,
Is the hydro 114.1 number, conventional hydro, hydrokinetic, or combined? I ask because non-conventional hydro might be higher capacity factor.
thx
ed
August 26th, 2009 at 3:42 pm
Ed,
The number is conventional hydro.
Thanks,
Mary Hutzler
September 16th, 2009 at 11:50 pm
Dear IER:
Thank you for your Cost analysis.
I have some questions:
1) What discount rate did you use?
2) If there is summery of assumptions, please let me know.
Best regards
September 17th, 2009 at 11:24 am
Koji,
The assumptions are contained in the report: Assumptions to the Annual Energy Outlook 2009 in the Electricity chapter. The link is: http://www.eia.doe.gov/oiaf/aeo/assumption/electricity.html.
Thanks,
Mary Hutzler
September 22nd, 2009 at 9:09 am
What are the prices of natural gas and coal (fuel factors) modeled in the analysis? I went to the link with the assumptions but it only explained the methodology, not the actual prices used. Thanks.
September 24th, 2009 at 6:55 am
Andy,
The fuel prices are determined by the model at equilibruim. They can be found in Table A1 of the following link: http://www.eia.doe.gov/oiaf/servicerpt/stimulus/pdf/sroiaf(2009)03.pdf.
Thanks,
Mary Hutzler
September 25th, 2009 at 1:22 pm
Just to be clear re natural gas prices. Are the prices used based on the Henry Hub prices in Table A1?
Thanks.