DOE/NETL-2010/???? 2014/1653
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Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The 

views and opinions of authors expressed therein do not necessarily state or reflect those of the 

United States Government or any agency thereof.
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Carbon Dioxide Transport and Storage Costs

in NETL Studies

DOE/NETL-2013/1614

Final Report 

September 30, 2013

NETL Contact:

Tim Grant

Physical Scientist

Office of Program Planning and Benefits, Benefits Division

National Energy Technology Laboratory

www.netl.doe.gov
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Prepared by:

Tim Grant

National Energy Technology Laboratory

David Morgan

National Energy Technology Laboratory

Kristin Gerdes

National Energy Technology Laboratory

DOE Contract Number DE-FE0004001
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Acknowledgments

This report was prepared by the United States Department of Energy (DOE), National Energy 

Technology Laboratory (NETL). 

The authors wish to acknowledge the excellent contributions and cooperation by members of the 

Energy Sector Planning and Analysis staff, particularly:

Jason Valenstein, Booz Allen Hamilton

Andrea Poe, Booz Allen Hamilton

Richard Lawrence, Advanced Resources International
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Table of Contents

Executive Summary.........................................................................................................................9

1 Objective ................................................................................................................................10

2 Approach................................................................................................................................11

2.1 Transport Costs.......................................................................................................................11

2.2 Storage and Monitoring Costs................................................................................................17

3 Results....................................................................................................................................21

3.1 Transport Costs.......................................................................................................................21

3.2 Storage and Monitoring Costs ...............................................................................................22

3.3 Combining Transport and Storage Costs...............................................................................28

4 Revision Control ....................................................................................................................29

5 References..............................................................................................................................30

List of Exhibits

Exhibit ES-1 Total transport and storage (T&S) costs for use in NETL system studies................ 9

Exhibit 2-1 Timelines for construction and operations of plant, transport, and storage............... 11

Exhibit 2-2 Natural gas pipeline capital costs using different equations...................................... 14

Exhibit 2-3 Kinder-Morgan pipeline cost metrics........................................................................ 15

Exhibit 2-4 Location of four basins selected for this study .......................................................... 18

Exhibit 2-5 Modeling parameters for low-cost, base, and high-cost cases distance..................... 20

Exhibit 3-1 Sensitivity of transport costs to plant and distance assumptions............................... 22

Exhibit 3-2 CO2 cumulative storage potential cost supply curves................................................ 23

Exhibit 3-3 Storage resource potential for four basins ................................................................. 24

Exhibit 3-4 Potential storage cost supply curves for low-cost, base, and high-cost case scenarios 

in the Illinois Basin ............................................................................................................... 26

Exhibit 3-5 Breakout of project stage cost as a percent of total storage costs.............................. 27

Exhibit 3-6 Cost items for reservoirs providing storage potential resource at 25 Gt ................... 28

Exhibit 3-7 Total transport and base case storage (T&S) costs for use in NETL system studies 28

Exhibit 4-1 Revision table ............................................................................................................ 29
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Acronyms and Abbreviations

AoR Area of Review

CO2 Carbon dioxide

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

FE Fossil energy

GW gigawatt

Gt Gigatonne (billion metric tons, 

1012 kilograms)

IRROE Internal rate of return on equity

INGAA Interstate Natural Gas Association of 

America

mi2square mile

Mt Million tonne, 109kilograms

MVA Monitoring, Verification, and 

Accounting

NETL National Energy Technology 

Laboratory

O&GJ Oil and Gas Journal

O&M Operation and maintenance

psia Pounds per square inch absolute

ROW Right-of-way

T&S Transport and storage

tonne metric ton, 1000 kilograms
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Executive Summary

The values to be used in systems studies sponsored by the National Energy Technology 

Laboratory (NETL) for estimating the cost of CO2 pipeline transport and storage (T&S) (rounded 

to the nearest whole dollar) are shown in Exhibit ES-1. The basis for these values is discussed 

below.

Exhibit ES-1 Total transport and storage (T&S) costs for use in NETL system studies

Plant Location Basin T&S Value for System Studies 

(2011$/tonne)

Midwest Illinois 11

Texas East Texas 11

North Dakota Williston 16

Montana Powder River 24

Source: NETL

T&S cost information is used by NETL in their studies on the capture of CO2 from electric 

power plants. Four geographic locations were selected (Exhibit 2-4) to model transportation and 

storage of captured CO2: Midwest (Illinois Basin), Texas (East Texas Basin), North Dakota 

(Williston Basin), and Montana (Powder River Basin). In the base case, 3.2 million metric tons

of CO2 are captured and transported from a source in each of the basins modeled for storage

costs. Cost of transportation is defined by a dedicated 100 km (62 mi) pipeline connecting the 

source of the captured CO2 with a storage site. The modeled cost of transportation is $2.24 per 

tonne of CO2. 

Variability in overall T&S costs are found in the unique geology of the different reservoirs 

present in each of the four basins. Potential uncertainty associated with the cost of CO2 storage 

in the reservoirs modeled in each basin is addressed with low-cost, base, and high-cost scenarios

(Exhibit 2-5). Cost parameters for each cost scenario are modified to reflect a savings in cost or 

an additional cost burden due to potentially unique operational situations; for example, a 

reduction in 3-D seismic cost due to applied technology or an increase due to logistical 

challenges of seismic data acquisition. 

Storage potential in a subsurface reservoir of captured CO2 represents a resource that has yet to 

be proved. The cost of storage, which is the modeled cost to utilize this resource once proved, is 

the break-even cost to store a metric ton of CO2. Storage costs posted in this guideline represent 

low-cost, base, and high-cost case scenarios at a cumulative storage potential of 25 billion metric 

tons (25 gigatonnes [Gt]), 50 Gt and 75 Gt (Exhibit 3-3). For the base case scenario and a 

cumulative storage potential of 25 Gt, the modeled cost to store one tonne of CO2 in the Illinois 

Basin is $8.69. In the East Texas Basin this cost is $8.83 per tonne, in the Williston Basin it is 

$13.95 per tonne, and in the Powder River Basin it is $21.81 per tonne. Combined T&S basecase scenario cost at 25 Gt of potential storage is $10.93 per tonne in the Illinois Basin, $11.07 

per tonne in the East Texas Basin, $16.19 per tonne in the Williston Basin, and $24.05 per tonne 
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in the Powder River Basin. For system analysis studies at NETL, these cost values are rounded 

to $11 for the Illinois and East Texas Basins, $16 for the Williston Basin, and $24 for the Powder 

River Basin.

1 Objective

The purpose of this guideline is to estimate the cost of CO2 pipeline transport and storage (T&S) 

in a deep saline aquifer for the plant locations used in the energy system studies sponsored by the 

National Energy Technology Laboratory (NETL). NETL is in the Office of Fossil Energy (FE) 

in the United States (U.S.) Department of Energy (DOE). 

Transport costs are calculated using the FE/NETL CO2 Transport Cost Model, [1] assuming a 

100 km (62 mi) dedicated pipeline is used in each region to connect the CO2 source (e.g., a 

power plant) to the CO2 storage site. The FE/NETL CO2 Transport Cost Model determines the 

pipeline diameter needed to transport a specified CO2 mass flow rate (in this case an annual 

average of 3.2 million tonnes of CO2) with or without boost pumps along the pipeline. The 

model then determines which combination of pumps and pipeline diameter gives the lowest 

overall cost in dollars per tonne of CO2 transported.

Due to the variances in the geologic formations that make up saline aquifers across the U.S., the 

cost to store CO2 can vary greatly depending on location. To account for these variances, regionspecific results from the FE/NETL CO2 Saline Storage Cost Model [2] are utilized to represent 

costs for the following plant locations and associated sedimentary basins used in NETL studies:

 Midwest – Illinois Basin

 Texas – East Texas Basin

 North Dakota – Williston Basin

 Montana – Powder River Basin

Variance also occurs within the geologic formations present in each of these basins. Three cost 

scenarios – low-cost, base, and high-cost – were developed to reflect variance within the 

geologic formations in each of the basins modeled. 

The costs calculated by the FE/NETL CO2 Saline Storage Cost Model cover all costs including 

capital costs, operating costs, financing costs, and taxes and are expressed in dollars per tonne of 

CO2 stored. Costs were developed for all potential storage formations in each region, and the 

total mass of CO2 that can potentially be stored in each formation was also calculated. Since the 

cheapest formations are likely to be the first to be used for storage (all other things being equal), 

the costs for all formations in a region were ranked from lowest to highest, and the cumulative 

mass of CO2 that could be stored at that cost (or lower) was calculated. T&S costs were then 

determined for three levels of cumulative CO2 storage in each region: 25, 50, and 75 billion 

tonnes. As a point of reference, the U.S. emits around 2 billion tonnes of CO2 each year from the 

electric power sector and around 1 billion tonnes of CO2 each year from industrial sector 

excluding emissions associated with electricity used by industrial operations. [3] 
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2 Approach

T&S costs are reported as first-year costs in $/tonne of CO2, increasing at a nominal rate of 3

percent per year, which is consistent with the general inflation rate assumed in NETL’s baseline 

energy system studies. From the perspective of the CO2 source (e.g., a power plant or other 

energy conversion facility), these costs are treated as a disposal cost for each tonne of CO2

captured during the assumed 30-year operational period. From the pipeline and storage site’s 

perspective, the costs of T&S represent the minimum price that these operators must charge so 

that they receive the revenue needed across the 30-year operational period to cover all their costs 

and provide their required internal rate of return on equity (IRROE). All costs are reported in 

2011 dollars.

Exhibit 2-1 Timelines for construction and operations of plant, transport, and storage

Source: NETL

T&S costs are based on the CO2 flow rate of one example plant: a daily maximum 11,000

tonne/day (12,000 ton/day), which translates into an annual average of 3.2 million tonnes per 

year assuming an 80 percent capacity factor. The sensitivity of transport costs based on flow 

rate, capacity factor, and pipeline length can be assessed using the FE/NETL CO2 Transport Cost 

Model. A limited sensitivity analysis is presented in Section 3.1. The sensitivity of storage costs 

based on flow rate and capacity factor can be determined using the FE/NETL CO2 Saline Storage 

Cost Model, but the sensitivity of the model to these parameters was not investigated in this 

guideline. 

2.1 Transport Costs

The FE/NETL CO2 Transport Cost Model is a mathematical model that estimates the cost of 

transporting liquid CO2 using a pipeline. The FE/NETL CO2 Transport Cost Model is an 

updated version of the CO2 pipeline cost model at NETL. [4] Costs are estimated for a single 

point-to-point pipeline, which may have pumps along the pipeline to boost the pressure. The 

model includes the capital costs for purchasing and installing the pipeline, a surge tank, a 

pipeline control system and, if economical, the boost pumps. The FE/NETL CO2 Transport Cost 

30-Year

Operational Period

30-Year

Operational Period

30-Year Operational 

Period (Monitoring Well 

Drilling)

50-Year Post-Injection

Site Care and Closure
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Model accounts for the operation and maintenance (O&M) costs for the pipeline and pumps and 

the cost of the electricity used to power the pumps. The FE/NETL CO2 Transport Cost Model 

also has a financial model with debt, equity, depreciation, and taxes. The model can determine 

the price of CO2 (in dollars per tonne of CO2 transported) that provides investors with their 

desired minimum IRROE. This price is referred to as the break-even price of CO2 in this 

guideline. The break-even price is also the minimum cost of transporting CO2 from the 

perspective of the CO2 source.

For the analysis in this guideline, it is assumed that CO2 is provided by the CO2 source at a 

pressure of (2,200 psig), and the cost and energy requirements of compression are assumed by 

the CO2 source. CO2 is in a dense phase liquid state at this pressure, which is desirable for 

transportation. 

CO2 exits the pipeline terminus at the CO2 storage site at a pressure of 1,200 psig. This exit 

pressure specification ensures that CO2 remains in a dense phase liquid state throughout the 

length of the pipeline regardless of potential pressure drops due to pipeline elevation changes. 

Costs for additional compression that may be required for injection in a particular formation is

included as part of storage costs. 

For this analysis, a pipeline length of 100 km (62 mi) is assumed. The FE/NETL CO2 Transport

Cost Model can estimate the minimum pipeline diameter needed to transport the CO2 this

distance without any pumps to boost the pressure. The model can also determine if a smaller 

diameter pipe can be used if one or more pumps are used at equal intervals along the pipeline to 

boost the pressure from 1200 psig at the pump inlet to 2200 psig at the pump outlet. 

The FE/NETL CO2 Transport Cost Model uses an iterative procedure to determine the diameter 

necessary to sustain a 1,000 psia pressure drop over the specified pipeline length, or pipeline 

segment length, if pumps are installed along the pipeline. The model rounds up the diameter to 

the nearest standard pipe diameter. The pipeline diameter was determined based on the CO2

output produced by the CO2 source when it is operating at full capacity (100 percent utilization 

factor) rather than at average capacity. 

CO2 transport costs are broken down into capital and operating expenses. The capital expenses 

include the costs for the pipeline, a surge tank, a pipeline control system, and the boost pumps (if 

used). The operating expenses include O&M costs for these pieces of equipment and the cost of 

the electricity used by the boost pumps. 

The FE/NETL CO2 Transport Cost Model provides three equations for calculating the capital 

costs for the pipeline. The three equations all used pipeline capital costs reported in the Oil and 

Gas Journal’s (O&GJ) annual Pipeline Economics Report for existing natural gas, oil, and 

petroleum pipeline projects. [5] The O&GJ reported capital costs in four categories: 1) 

materials, 2) labor, 3) right of way (ROW) and damages, and 4) miscellaneous. The materials 

category included the cost for pipe, pipe coating, and cathodic protection. The miscellaneous 

category included costs for surveying, engineering, supervision, contingencies, 

telecommunications equipment, freight, taxes, allowances for funds used during construction 

(AFUDC), administration and overheads, and regulatory filing fees. One set of equations for 

pipeline capital costs was developed by Parker [6] using cost data from 1991 to 2003; these 

equations give costs in 2000 dollars. A second set of equations for pipeline capital costs was 
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developed by McCoy and Rubin [7] using cost data from 1995 to 2005; these equations give 

costs in 2004 dollars. The third set of equations for pipeline capital costs was developed by Rui 

et al. [8] using cost data from 1992 to 2008; these equations give costs in 2008 dollars. While 

the three sets of equations have different functional forms, they all calculate capital costs as a 

function of pipeline length and diameter. The capital costs for all three sets of equations were 

adjusted to 2011 dollars using a variety of price indices. [1] The resulting capital costs are for 

natural gas pipelines. CO2 pipelines operate at higher pressures than natural gas pipelines, so 

they require a thicker pipe wall, which affects the cost. The capital costs for materials and labor 

were adjusted, depending on the pipe diameter, using factors developed by ICF International. [9]

The costs for a surge tank and pipeline control system were taken from an earlier NETL study.

[4] These costs were in 2000 dollars and were adjusted to 2011 dollars using appropriate price 

indices. [1] The capital costs for a boost pump were determined using an equation provided by 

McCollum and Ogden. [10] This equation needs the power requirements for the boost pumps 

and McCollum and Ogden [10] also provide an equation for estimating the power requirement 

based on the CO2 mass flow rate and pressure increase through the pump. The pump capital 

costs were in 2005 dollars and were adjusted to 2011 dollars using appropriate price indices. [1] 

The O&M costs for the pipeline were based on a value provided in Heddle et al. [11] These 

were in 1999 dollars and were adjusted to 2011 dollars using appropriate price indices. [1] The 

O&M costs for the remaining pieces of equipment were assumed to be 4 percent of the capital 

costs on an annual basis. The price of electricity used to estimate the cost of the electricity used 

by the pumps was assumed to be the national average electricity price for electricity provided to 

commercial operations in 2011. [12] 

As discussed above, the FE/NETL CO2 Transport Cost Model has a financial model with debt, 

equity, depreciation, and taxes. The model can determine the price of CO2 (in dollars per tonne 

of CO2 transported) that provides investors with their desired minimum IRROE. To use the 

financial model, a number of parameters must be specified. For this evaluation, it was assumed 

that it takes 3 years to complete the construction of the pipeline and that the pipeline operates for 

30 years. The following financial parameters were used, which match the low-risk business 

scenario for an investor-owned utility [13]:

 Escalation of all costs at a rate of 3% per year

 Debt to equity ratio of 50%/50%

 Interest rate on debt of 4.5%/year

 Minimum IRROE of 12%

 30-year operational period

The FE/NETL CO2 Transport Cost Model includes a project contingency calculated for all 

capital costs. NETL guidelines for cost estimating [14] recommend using a project contingency 

between 15 percent and 30 percent for the budgetary-level type cost estimate that is provided by 

the FE/NETL CO2 Transport Cost Model. The lower value of 15 percent was used for the

analysis in this guideline, because the pipeline costs provided by the O&GJ may include 

contingency and some taxes.

The FE/NETL CO2 Transport Cost Model determines the returns to the owner using a weighted 

average cost of capital methodology. [1] 
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The three sets of equations for natural gas pipeline capital costs give different results as 

illustrated in Exhibit 2-2, which presents the cost per mile for different pipeline lengths and 

diameters. In general, the equations from Parker [6] give the highest cost followed by the 

equations from McCoy and Rubin [7] and then Rui et al. [8] The equations from Parker [6] give 

significantly higher costs than the other two equations.

Exhibit 2-2 Natural gas pipeline capital costs using different equations

Source: NETL
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To determine which of these three sets of equations to use in the analysis for this guideline, a 

comparison was made to pipeline capital cost data from a variety of sources. The capital costs 

for a CO2 pipeline per inch (diameter) and mile (length) including contingency range are as 

follows for the different sets of equations:

• Parker: $85,000/in-mi (12 in pipe) to $120,000/in-mi (42 in pipe)

• McCoy: $65,000/in-mi (50 mile long pipe) to $46,000/in-mi (500 mile long pipe)

• Rui: $50,000/in-mi (50 mile long pipe) to $35,000/in-mi (500 mile long pipe)

The capital costs per inch-mile using the equations from Parker [6] increase with increasing 

diameter but are relatively insensitive to the length of the pipeline. The capital costs per inchmile using the equations from McCoy and Rubin [7] increase somewhat with increasing diameter 

but decrease with increasing pipeline length. The capital costs per inch-mile using the equations 

from Rui et al. [8] show the same type of behavior as the equations from McCoy and Rubin. [7] 

These costs were compared to contemporary pipeline costs quoted by industry experts, such as 

Kinder-Morgan and Denbury Resources. Exhibit 2-3 details typical rule-of-thumb costs for 

various terrains and scenarios as quoted by a representative of Kinder-Morgan at the Spring Coal 

Fleet Meeting in 2009. [15] It is not known if these rule-of thumb estimates include 

contingencies. As shown, the costs using the equations from Parker [6] are on the high end of 

this range, while the costs using the equations from McCoy and Rubin [7] fall on the low end of 

this range, and the costs using the equations from Rui et al. [8] tend to fall below this range. 

Exhibit 2-3 Kinder-Morgan pipeline cost metrics

Terrain

Capital Cost

($/inch-Diameter/mile)

Flat, Dry $50,000

Mountainous $85,000

Marsh, Wetland $100,000

River $300,000

High Population $100,000

Offshore (150’-200’ depth) $700,000
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A further comparison was made to cost data for two Denbury CO2 pipelines. The first is the 

Green pipeline with the following characteristics.

• Location: Southeast United States

• Pipeline length: 314 miles

• Pipeline diameter: 24 inches

• CO2 flow capacity: 42,320 tonne/day

• Capital cost: About 660 million dollars according to trade journals

About 884 million dollars excluding capitalized interest according 

to the annual report

• Status: Completed around 2010

Assuming the capacity factor is 80 percent for this pipeline, the FE/NETL CO2 Transport Cost 

Model determines that a 24-inch pipeline of this length would need 2 pumps. The capital cost 

for this project is estimated by the model to be as follows:

• Using Parker eq.: 740 million dollars

• Using McCoy eq.: 435 million dollars

• Using Rui eq.: 370 million dollars

The result using the Parker equations [6] exceeds the value in trade journals but is less than the 

value in the annual report. The results from the McCoy and Rubin [7] and Rui et al. [8] 

equations are significantly less than both published capital costs.

The second CO2 pipeline is the Greencore pipeline with the following characteristics:

• Location: Wyoming

• Pipeline length: 232 miles

• Pipeline diameter: 20 inches

• CO2 flow capacity: 38,280 tonne/day

• Capital cost: About 285 million dollars according to trade journals

About 135 million dollars for second half of project according to 

annual report

• Status: Completed in 2012 or 2013

Assuming the capacity factor is 80 percent for this pipeline, the FE/NETL CO2 Transport Cost 

Model determines that a 20-inch pipeline of this length would need 4 pumps. The capital cost 

for this project is estimated by the model to be as follows:

• Using Parker eq.: 430 million dollars

• Using McCoy eq.: 170 million dollars

• Using Rui eq.: 135 million dollars
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The result using the Parker equations [6] exceeds the value in trade journals. The results from 

the McCoy and Rubin [7] and Rui et al. [8] equations are less than the published capital costs.

These results indicate that the equations from Parker [6] and McCoy and Rubin [7] give costs 

that are closest to published CO2 pipeline costs. The equations from Parker [6] tend to give costs 

on the high side, while the equations from McCoy and Rubin [7] tend to give costs on the low 

side. To be conservative (i.e., to err on the side of over-estimating CO2 transport costs), the 

equations from Parker [6] were used in the analysis for this guideline.

2.2 Storage and Monitoring Costs

Storage and monitoring costs were estimated using the FE/NETL CO2 Saline Storage Cost 

Model. This model is a spreadsheet-based tool that estimates the break-even price for storing 

CO2 in a deep saline aquifer from the perspective of the owner of a CO2 storage site. This breakeven price is also the minimum cost for storing captured CO2. The FE/NETL CO2 Saline 

Storage Cost Model includes the cost of complying with key regulations. In order to inject CO2

into the subsurface for the purpose of storing CO2 in a saline aquifer, the site owner must comply 

with the U.S. Environmental Protection Agency (EPA) regulations for Class VI injection wells 

under EPA’s Underground Injection Control Program, which is authorized under the Safe 

Drinking Water Act. The site owner must also comply with monitoring and reporting 

requirements under Subpart RR of the Greenhouse Gas Reporting Rule, which is authorized 

under the Clean Air Act. 

The majority of well, technology, and labor cost data are from EPA’s economic analysis of the 

Class VI and Subpart RR regulations and are in 2008 dollars. Except for groundwater wells or 

vadose zone wells, the cost of all wells in the model is based on the 2006 API-Joint Association 

Survey. Some cost data are based on conversations with industry personnel while at 

conferences. Costs posted in the model are updated as new information becomes available.

Results from the FE/NETL CO2 Saline Storage Cost Model for storage and monitoring costs 

were aligned with the NETL system studies by taking the four generic plant locations and 

overlaying them with possible storage basins from the cost model. This couples generic system 

study plant locations of Midwest, Texas, North Dakota, and Montana with the Illinois, East 

Texas, Williston, and Powder River Basins, respectively, as shown in Exhibit 2-4.
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Exhibit 2-4 Location of four basins selected for this study

Source: NETL

Inputs to the FE/NETL CO2 Saline Storage Cost Model that have a significant influence on cost 

include financial parameters, timelines for the various stages of storage, drilling or monitoring 

activities in stages, and selection of financial responsibility instruments.

The financial parameters match the high-risk business scenario for an Investor Owned Utility

and include:

 Debt to equity ratio of 45%/55%

 Interest rate on debt of 5.5%/year

 IRROE of 12%

 Escalation rate of 3%

 Modified trust fund that grows at an annual rate over the period of injection operations

 Project contingency factor of 15%

 Process contingency factor of 20%

Illinois Basin

Storage for Midwest Plants

East Texas

Storage for Texas Plants

Williston Basin

Storage for ND plants

Powder River Basin

Storage for MT plants
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In the FE/NETL CO2 Saline Storage Cost Model, a storage project is divided into six stages. 

The timelines and important activities impacting costs for these stages are:

 Regional evaluation and initial site selection: 1 year

 Site characterization: 3 years

o Four sites simultaneously undergo characterization, each having a 2-D seismic 

survey covering the estimated Area of Review (AoR) and one strat-well drilled to 

collect relevant reservoir data.

o The successful site has an additional strat-well drilled plus a 3-D seismic survey 

covering the AoR; pore-space rights and property access are also leased.

 Permitting: 2 years

o Includes submittal of required plans (AoR & Corrective Action, Testing & 

Monitoring, Injection Well Plugging, Post-Injection Site Care & Site Closure, 

Emergency & Remedial Response) for Class VI injection well permit, permission 

to drill injection wells, drilling and completion of injection wells, incorporation of 

new data from injection wells into reports, resubmission of reports, and final 

permission to inject captured CO2. 

o Demonstrate financial responsibility.

 Operations: 30 years

o Injection of 3.2 Mt of CO2 per year for 30 years.

o Installation of buildings, surface equipment, monitoring wells, and other 

monitoring equipment per submitted testing and monitoring plan.

o AoR review occurs every five years with 3-D seismic.

o Plugging injection wells at conclusion of injection operations.

o Payment into modified trust fund to cover financial responsibility requirements 

for corrective action, injection well plugging and post-injection site care, and site 

closure. Emergency and Remedial Response covered by separate insurance.

 Post-injection site care and site closure: 50 years

o Monitoring continues per submitted testing and monitoring plan.

o Monitoring wells are plugged and other monitoring equipment removed at the 

conclusion of post-injection site care.

o Costs during this period are covered by the storage site operator’s trust fund.

 Long-term stewardship: This stage is not explicitly included in the model. The possible 

financial implication of long-term stewardship is included in the model as a statesponsored trust fund that the storage operator pays into during operations. 

Cost variability is also present within a basin due to the changing geologic character of a 

particular formation in which a CO2 storage operation will be developed. Three cost scenarios 

were established to model this variability: low-cost, base, and high-cost. Changes in modeling 

parameters between low-cost, base, and high-cost case scenarios are illustrated in Exhibit 2-5. 
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Exhibit 2-5 Modeling parameters for low-cost, base, and high-cost cases distance 

Source: NETL

Costs increase from the low-cost scenario to the high-cost scenario due to changes in the 

following parameters listed in Exhibit 2-5:

 Rate of return on the trust fund decreases, increasing the cost to the operator to maintain a 

suitable balance in the modified trust fund to meet regulatory requirements.

 Storage coefficient decreases, reducing the storage volume per unit area and increasing 

the plume size and associated monitoring costs.

 Post-injection site care and site closure period of 25 years in the low case increases to the 

default time period of 50 years for the base and high-cost cases, increasing monitoring 

and financial responsibility costs.

 The number of years to complete site characterization and permitting are increased in the 

high-cost case, delaying operations and positive cash flow from injection revenue.

 3-D seismic costs increase from $100,000 per square mile to $220,000 per square mile.

 The number of monitoring wells drilled increase because well spacing for monitoring 

wells in the plume area decrease from low to base case, both of which utilize the 

opportunity to dual complete these wells in the reservoir and above the seal where 

possible. The high-cost case has the well spacing of the base case but does not dual 

complete any monitoring wells in the plume area, increasing the number of above seal 

wells drilled. All three scenarios have four dual completed monitoring wells for the 

pressure front area.

Low Cost Case Base Case High Cost Case

Financial Responsibility Modified Trust Fund

Trust Fund Growth Rate 5 % 7 % 5 % 3 %

Storage Coefficient P50 P90 P50 P10

Debt/Equity Ratio

45/55 - based on High Risk 

scenario for an Investor 

Owned Utility (IOU)

Financials

Cost of Debt = 5.5%

Cost of Equity = 12%

Escalation = 3%

Post-Injection Site Care & 

Site Closure

50 years, default period in 

Class VI regulations

25 years 50 years, default period in 

Class VI regulations

50 years, default period in 

Class VI regulations

Site Characterization 3 years - 4 sites 3 years - 2 sites 3 years - 4 sites 6 years - 4 sites

Permitting 2 years 2 years 2 years 4 years

3-D Seismic $160,000/mi 2 $100,000/mi 2 $160,000/mi 2 $220,000/mi 2

Monitoring Wells

In Reservoir: 1 well/4 mi 2

Above Seal: 1 well/2 mi 2

In reservoir wells dual 

completed above seal.

In Reservoir: 1 well/8 mi 2

Above Seal: 1 well/4 mi 2

In reservoir wells dual 

completed above seal.

Four dual completed 

monitoring wells pressure 

front. 

In Reservoir: 1 well/4 mi 2

Above Seal: 1 well/2mi 2

In reservoir wells dual 

completed above seal.

Four dual completed 

monitoring wells in 

pressure front. 

In Reservoir: 1 well/4 mi 2 - 

no dual completions.

Above Seal: 1 well/2 mi 2

Four dual completed 

monitoring wells in 

pressure front.

Corrective Action 1 well/4 mi 2

 requiring 

corrective action.

1 well/8 mi 2 requiring 

corrective action.

1 well/4 mi2 requiring 

corrective action.

2 wells/mi2 requiring 

corrective action.

Water 

Withdrawal/Disposal None None None $2.00 per tonne CO2

 stored

Parameter Modeled FY 12 Model Run Model Parameters for Baseline CO2

 Storage Costs - FY13 Update

Modified Trust Fund

45/55 - based on High Risk scenario for an Investor Owned Utility (IOU)

Cost of Debt = 5.5%; Cost of Equity = 12%; Escalation = 3%
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Carbon Dioxide Transport and Storage Costs in NETL Studies

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 Increasing number of wells requiring corrective action increases the value of financial 

responsibility and cost to perform this activity.

 Water withdrawal from the storage reservoir and subsequent treatment and disposal in the 

high-cost case scenario adds another level of costs to operations. [16] A methodology to 

model costs associated with water withdrawals from the storage reservoir, surface 

treatment, and subsequent disposal is under development and testing. This cost is 

included in the high-cost case scenario to reflect the possibility that an operator may 

adopt water withdrawals to maintain suitable reservoir pressures and/or control the areal 

extent of the plume. [17]

3 Results

3.1 Transport Costs

The FE/NETL CO2 Transport Cost Model was used to estimate the first-year break-even price 

(also the minimum cost) for transporting a maximum daily flow of 11,000 tonne/day of CO2

with a capacity factor of 80 percent a distance of 100 km (62 mi) with 1,000 psi pressure drop. 

The model estimates that the lowest cost configuration will have a 12-inch pipe diameter and one 

boost pump. For this configuration, the estimated capital cost is $67 million in 2011 dollars, and 

the estimated annual operating and maintenance cost (O&M) is $1.5 million per year in 2011 

dollars. The resulting first-year break-even price (or minimum cost) for CO2 transport is 

$2.24/tonne of CO2 in 2011 dollars. 

This value will be used in NETL Energy System Studies as a reasonable approximation for CO2

transport costs for all plants regardless of the capacity factor and CO2 capture rates. Exhibit 3-1

shows the sensitivity of the minimum transport cost to capacity factor and CO2 transport rate. 

Costs are shown for pipelines of 100 km (62 mi) and 200 km (124 mi). The plot indicates that 

the higher the flow rate, the lower the unit cost, although there are some small discontinuities 

when the pipeline configuration changes (such as at 11,000 tonne/day for the 100 km long 

pipeline when the number of pumps increases from zero to one). The plot indicates that 

increasing the capacity factor decreases the cost, but this effect is relatively small. The plot also 

indicates that the longer the pipeline the higher the cost, with the cost being roughly proportional 

to the length. 
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

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Exhibit 3-1 Sensitivity of transport costs to plant and distance assumptions

Source: NETL

3.2 Storage and Monitoring Costs

Cost supply curves are plotted in Exhibit 3-2 for the East Texas, Illinois, Powder River, and 

Williston basins. This figure presents the mass of CO2 that can be stored theoretically in each 

basin at a given price of CO2. The price is the break-even price of CO2 for a storage project in 

each basin (i.e., the price of CO2 where the net present value for the project is zero). Each basin 

includes two or more storage formations. The curves in Exhibit 3-2 represent the storage 

resource potential for the Paluxy and Woodbine formations in the East Texas Basin; the Mt. 

Simon, St. Peter, and Knox formations in the Illinois Basin; the Red River, Mission Canyon, and 

Cambrian Sandstone formations in the Williston Basin; and the Minnelusa, Muddy, and Madison 

formations in the Powder River Basin. Also plotted in Exhibit 3-2 is a projection, based on EIA 

data, [3] of the cumulative mass of CO2 emissions from the electric power and industrial sectors 

that can be captured over the next century (305 Gt), assuming 90 percent of all CO2 emissions 

are captured.

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

0 5,000 10,000 15,000 20,000 25,000

$/tonne

Maximum CO2 Flow in Pipe (tonne/day)

100 km, 80% CF

100 km, 85% CF

200 km, 80% CF

200 km, 85% CF
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Carbon Dioxide Transport and Storage Costs in NETL Studies

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Exhibit 3-2 CO2 cumulative storage potential cost supply curves

Source: NETL

The storage potential for each formation depends upon the inherent porosity of each formation 

and upon a storage coefficient. The cost variability in the modeling is in part due to a change in

the storage coefficient, which is the percentage of the formation’s brine-filled pore volume that 

may be occupied by CO2. The storage coefficient depends on the depositional environment and 

the structural setting. [18] The storage resource potential for each formation in the basins shown 

previously in Exhibit 2-4 is partitioned into three structural settings: dome, anticline, and

regional dip. Depositional environments for the clastic formations are eolian (Minnelusa),

shallow clastic shelf (Muddy), peritidal (St. Peter), strand plain (Mt. Simon), fluvial (Woodbine),

and delta (Paluxy). Depositional environments for the carbonate formations are shallow shelf 

(Knox, Madison, and Mission Canyon). 

The storage resource potential for any particular formation reflects the areal extent of the 

formation as well as its thickness, porosity, and storage coefficient. In the FE/NETL CO2 Saline 

Storage Cost Model, over the total area of any formation, only 2.5 percent of the area is assigned 

to structural closure or 1.25 percent each for dome and anticline structures. [19] The remaining 

area is regional dip (97.5 percent). Dome and anticline structures have higher storage 

coefficients, but the regional dip structural portion of a formation has considerably higher storage 

potential due to its larger areal extent. CO2 storage potential modeled here is a resource that has 

yet to be proven. This process begins with site characterization for a specific storage project.

2000

2020

2040

2060

2080

2100

2120

 $1

 $10

 $100

 $1,000

 $10,000

0 50 100 150 200 250 300 350 400 450 500 Year (CO2 Capture) First Year Break-Even Cost - $/tonne (2011)

Cumulative Storage Potential - Billion Tonnes (Gt)

Four Basin Study: Base Case

East Texas, Illinois, Powder River & Williston Basins

East Texas Illinois Powder River Williston Elec+Ind Cum Captured CO2
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Carbon Dioxide Transport and Storage Costs in NETL Studies

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Each formation in each basin has a maximum theoretical capacity to store CO2, and this capacity 

significantly exceeds the mass of CO2 being stored by a single storage project. It is assumed that 

institutional issues (such as obtaining property rights to store CO2, restrictions on storage in 

urban areas) and pressure interferences from multiple storage sites will reduce the effective area 

of a formation to provide storage capacity. The model takes into account total storage potential 

and the total mass of CO2 to be injected by a single project over the time of operations and 

adjusts the total mass of CO2 stored, limiting utilization of a formation to less than 60 percent.

For each basin plotted in Exhibit 3-2, the cost to store at least 25 Gt is shown in Exhibit 3-3. A 

storage potential of 25 Gt presents a significant resource relative to the generating capacity of the 

electric power sector reflected by the gigawatt (GW) storage potential in Exhibit 3-3. Choosing 

this point on the supply-cost curves provides a conservative estimate of the storage cost since 

many decades, if not more than a century, will pass before 25 Gt of CO2 is stored in any of the 

four individual basins. For example, 25 Gt of storage would be sufficient for 125 GW of coal 

power with 90 percent CO2 capture operating over 30 years.

Exhibit 3-3 Storage resource potential for four basins

Source: NETL

For the East Texas Basin, 25 Gt of cumulative storage resource potential is provided by a 

combination of sedimentary depositional and structural settings in the Woodbine and Paluxy

formations, each represented by a point on the cost supply curve. For the base-cost case scenario 

in the East Texas Basin, the low-cost point is $6.20 per tonne of CO2 stored for a dome structure 

in the Woodbine. A reservoir with regional dip structural setting in the Woodbine provides the 

storage resource potential at the 25 Gt mark at a cost of $8.83 per tonne of CO2. At this price, 

within the Woodbine formation, the resource storage potential represents 40 Gt of captured CO2. 

This storage resource potential represents 11 percent of the volume of CO2 emissions that can be 

$/tonne 

(2011)

Storage 

Potential 

(Gt) at 

this $/t

% of next 

100 yrs of 

captured 

CO2

GW 

Storage 

Potential

$/tonne 

(2011)

Storage 

Potential 

(Gt) at 

this $/t

% of next 

100 yrs of 

captured 

CO2

$/tonne 

(2011)

Storage 

Potential 

(Gt) at 

this $/t

% of next 

100 yrs of 

captured 

CO2

Low 5.49 109 3 0 545 5.49 109 3 0 5.49 109 3 1

Base 8.69 96 27 482 8.69 96 27 8.69 96 27

High 19.65 9 4 2 6 469 19.65 9 4 2 6 19.65 9 4 2 6

Low 5.69 4 5 1 3 227 7.82 6 8 1 9 8.08 8 6 2 4

Base 8.83 40 11 201 13.67 63 17 13.69 79 22

High 19.57 3 7 1 0 187 33.22 5 3 1 5 83.36 7 4 2 1

Low 8.79 106 3 0 534 8.79 106 3 0 8.79 106 3 0

Base 13.95 104 29 522 13.95 104 29 13.95 104 29

High 31.60 9 0 2 5 453 31.60 9 0 2 5 31.60 9 0 2 5

Low 14.11 106 3 0 534 14.11 106 3 0 14.11 106 3 0

Base 21.81 89 25 447 21.81 89 25 21.81 89 25

High 46.69 6 8 1 9 340 46.69 6 8 1 9 54.94 8 2 2 3

Low 366 102 1,839 390 109 407 113

Base 329 92 1,652 352 98 368 102

High 289 8 1 1,450 305 8 5 339 9 5

Storage Potential to 50 Gt Storage Potential to 75 Gt

Illinois

Basin

Modeled 

Cost 

Scenario

Powder 

River

Totals

East 

Texas

Williston

Storage Potential to 25 Gt
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy System Studies May 2014

captured from the electric power and industrial sectors over the next century. Similar 

information for the Illinois, Powder River, and Williston Basins are also posted in Exhibit 3-3.

For these four basins, the base-cost case scenario storage resource potential at the CO2 price 

associated with cumulative storage of 25 Gt totals 329 Gt. This represents 92 percent of the 

volume of CO2 emissions that can be captured from the electric power and industrial sectors over 

the next century. Assuming 6.64 million tonnes of CO2 captured from a 1 GW power plant (30 

years of operation, 30 percent plant efficiency, 80 percent capacity factor, and 90 percent capture 

efficiency), this storage resource potential is equivalent to 1,652 GW of power generation.

Storage resource potential with respect to electric power generation ranges from 201 GW in the 

East Texas Basin to 522 GW in the Williston Basin. Total storage resource potential for these 

four basins, through the CO2 price associated with cumulative storage of 75 Gt, represents 102 

percent of the volume of CO2 emissions that can be captured from the electric power and 

industrial sectors over the next century. The Illinois Basin, with the Mt. Simon Formation, is the 

low-cost provider. The Williston Basin, as illustrated in Exhibit 3-3, has the largest storage 

resource potential. 

The range of storage costs for the low-cost, base, and high-cost case scenarios for the Illinois 

Basin is plotted in Exhibit 3-4. The regional dip portion of the Mt. Simon formation in central 

Illinois provides 90.2 Gt of storage potential resource. Increasing costs shifts the curves up 

while a reduction in storage coefficient shifts the curves to the left. The cost to store a tonne of 

captured CO2 predominately lies between the low-cost and high-cost curves but this does not 

preclude the possibility that the storage costs of any particular project may lie above high-cost or 

below low-cost curves.
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

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Exhibit 3-4 Potential storage cost supply curves for low-cost, base, and high-cost case scenarios

in the Illinois Basin

Source: NETL
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Carbon Dioxide Transport and Storage Costs in NETL Studies

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Exhibit 3-5 Breakout of project stage cost as a percent of total storage costs

Source: NETL

A breakout, by project stage, of storage costs for the Mt. Simon, along with the Woodbine, Red 

River, and Madison formations, is presented in Exhibit 3-5. This cost breakout is for the 

regional dip structural setting for each formation. It is this reservoir formation combination that 

provides the storage potential resource at 25 Gt and more (see Exhibit 3-2 and Exhibit 3-4). For 

each reservoir modeled (formation and structural setting), applied costs are identical (see 

modeling parameters Exhibit 2-5). Variables impacting costs are in the reservoir. Storage 

capacity and the combination of formation height, porosity, storage coefficient, and CO2 density 

determine the areal extent of the plume. The areal extent of the plume determines the number of 

monitoring wells drilled and the extent of 3-D seismic and monitoring, verification, and 

accounting (MVA) coverage needed to monitor the plume. Plume size impacts costs for site 

characterization, operations, and post-injection site care. These costs are comparable in the 

Woodbine and Mt. Simon but increase for the Red River and more so for the Madison; this is 

due to an increasing plume size and the number of monitoring wells drilled (Exhibit 3-6). The 

significant change in project stage costs between reservoirs in this instance is in permitting when 

the injection wells are drilled and completed. Formation height and permeability impact 

injection of CO2, and depth drilled impacts drilling costs. During permitting, four injection wells 

are drilled for the Mt. Simon, Woodbine, and Red River, but the Red River is 3,000 feet deeper 

accounting for the increased costs in Williston Basin storage. In the Powder River Basin, the 
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

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Madison is 2,000 feet deeper than the Red River, and 10 injection wells are drilled. This 

increasing depth also impacts drilling and completion costs for monitoring wells.

Exhibit 3-6 Cost items for reservoirs providing storage potential resource at 25 Gt

Source: NETL

3.3 Combining Transport and Storage Costs

Exhibit 3-7 reports the base case storage cost results from the FE/NETL CO2 Saline Storage Cost 

Model base-cost case for the 25 Gt of cumulative storage resource potential and transport cost 

for the example plant parameters. The cost from the FE/NETL CO2 Transport Cost Model of 

transporting CO2 100 km is also provided in Exhibit 3-7. The resulting CO2 T&S values 

(rounded to the nearest whole dollar) to be used in NETL systems studies are shown in the far 

right column.

Exhibit 3-7 Total transport and base case storage (T&S) costs for use in NETL system studies

Plant 

Location Basin Transport (2011$/tonne)

Base Case 

Storage 

(2011$/tonne)

Total T&S

(2011$/tonne)

T&S Value for 

System 

Studies 

(2011$/tonne)

Midwest Illinois

2.24

8.69 10.93 11

Texas East Texas 8.83 11.07 11

North Dakota Williston 13.95 16.19 16

Montana Powder River 21.81 24.05 24
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

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4 Revision Control

Exhibit 4-1 Revision table

Revision 

Number Revision Date Description of Change Comments

1 September 30, 2013 Updated cost estimates

2 February 12, 2014 Document edited and formatted
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

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5 References

1 National Energy Technology Laboratory (NETL). (2013). FE/NETL CO2 Transport Cost 

Model: Description and User Guide. In preparation.

2 National Energy Technology Laboratory (NETL). (2013). FE/NETL CO2 Saline Storage 

Cost Model User Guide. In preparation.

3 Energy Information Administration. (2013). Table 18 AEO2013 Energy Related Carbon 

Dioxide Emissions by Sector and Source United States Reference Case. Retrieved on 

January 24, 2014, from 

http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2013&subject=0-

AEO2013&table=17-AEO2013®ion=1-0&cases=ref2013-d102312a.

4 National Energy Technology Laboratory (NETL). (2010). Quality Guidelines for Energy 

System Studies: Estimating Carbon Dioxide Transport and Storage Costs. DOE/NETL2010/1447, Pittsburgh, PA.

5 Oil & Gas Journal. Annual Pipeline Economics Reports for the years 1991-2003. 

Houston, Texas : PennWell Corporation, 2004

6 Parker, N. (2004). Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen 

Pipeline Costs. UCD-ITS-RR-04-35, Institute of Transportation Studies, University of 

California at Davis.

7 McCoy, S., & Rubin, E. (2008). An Engineering-economic Model of Pipeline Transport 

of CO2 with Application to Carbon Capture and Storage. International Journal of 

Greenhouse Gas Control, 2, 219-229.

8 Rui, Z., Metz, P., Reynolds, D., Chen, G., & Zhou, X. (2011). Regression Models 

Estimate Pipeline Construction Costs. Oil and Gas Journal, 109 (27).

9 ICF International. (2009). Developing a Pipeline Infrastructure for CO2 Capture and 

Storage: Issues and Challenges. Prepared for the INGAA Foundation, Inc., report 

number F-2009-01, February. Retrieved on January 24, 2014, from 

http://www.ingaa.org/Foundation/Foundation-Reports/Studies/7626/8230.aspx.

10 McCollum, D. & Ogden, J. (2006). Techno-Economic Models for Carbon Dioxide 

Compression, Transport, and Storage & Correlations for Estimating Carbon Dioxide 

Density and Viscosity. UCD-ITS-RR-06-14, Institute of Transportation Studies, 

University of California at Davis.

11 Heddle, G., Herzog, H., & Klett, M. (2003). The Economics of CO2 Storage. LFEE 2003-

003 RP, Laboratory for Energy and the Environment, Massachusetts Institute of 

Technology.

12 Energy Information Administration (EIA). (2013). Table 5.3. Average Retail Price of 

Electricity to Ultimate Customers: Total by End-Use Sector, 2003 - June 2013 (Cents per 

Kilowatthour). Retrieved January 24, 2014, from 

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_5_3.
National Energy Technology Laboratory Office of Program Performance and Benefits

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Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy System Studies May 2014

13 National Energy Technology Laboratory (NETL). (2011). Recommended Project Finance 

Structures for the Economic Analysis of Fossil-Based Energy Projects. DOE/NETL2011/1489, Pittsburgh, PA.

14 National Energy Technology Laboratory (NETL). (2011). Quality Guidelines for Energy 

System Studies: Cost Estimation Methodology for NETL Assessments of Power Plant 

Performance. DOE/NETL-2011/1455, Pittsburgh, PA.

15 Jeffrey Lane. (2009). Operating Experience with CO2 Pipelines. Proceedings of the EPRI 

Coal Fleet for Tomorrow: General Technical Meting, Houston, Tx, April 21-23, 2009.

16 Harto, C. (2013). Life Cycle Water Consumption for Carbon Capture and Storage. 

Carbon Storage R&D Project Review Meeting, Pittsburgh, Pa. August 20-22, 23013.

17 Buscheck, T.A., Y. Sun, M. Chen, Y. Hao, T.J. Wolery, S.J. Friedmann, R.D. Aimes. 

(2012). Active CO2 Reservoir management for CO2 Capture, Utilization, and Storage: An 

Approach to Improve CO2 Storage Capacity and to Reduce Risk. Carbon Management 

Technology Conference, Orlando, FL. February 7-9, 2012. CTMC 151746.

18 International Energy Agency (IEA). (2009) Development of Storage Coefficients for CO2

Storage in Deep Saline Formation. IEA Greenhouse Gas R&D Programme (IEA GHG). 

2009/13, October 2009.

19 Brennan, S.T., R.C. Furruss, M.D., Merrill, P.A. Freeman, and L.F. Ruppert. (2010). A 

Probabilistic Assessment Methodology for the Evaluation of Geologic Carbon Dioxide 

Storage. OFR 2010-1127. Retrieved on April 1, 2013, from 

http://pubs.usgs.gov/of/2010/1127/