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To: Docket EPA-HQ-OAR-2013-0495

Date: July 31, 2015

Subject: Geographic Availability 

1 Introduction 

Geologic sequestration (GS) is technically feasible in different types of geologic 

formations including deep saline formations (formations with high salinity formation fluids) or 

in oil and gas formations, such as where injected carbon dioxide (CO2) increases oil production 

efficiency through a process referred to as enhanced oil recovery (EOR). CO2 may also be used 

for other types of enhanced recovery, such as for natural gas production. Both deep saline and 

oil and gas formation types are widely available in the United States, although there are some 

specific geographic exceptions. Additionally, formations such as unmineable coal seams also 

offer the potential for geologic storage.1

Figure 1 depicts the geographic extent of potential CO2 sequestration in deep saline 

formations, oil and gas reservoirs, and unmineable coal seams, as identified by the Department 

of Energy, National Energy Technology Laboratory (NETL), Carbon Utilization and Storage Atlas, 

Fourth Edition (2012). An explanation of the Atlas and NETL methodology is provided in Section 

2. Figure 1 also shows the locations of counties where active CO2 EOR operations are occurring, 

based on data reported to the EPA Greenhouse Gas Reporting Program (subpart UU -Injection 

of Carbon Dioxide). Also shown is the area within 100 kilometers from potential GS formations.

2

Existing CO2 pipelines are shown on the map, along with the locations of planned pipelines, or 

pipeline projects that are currently being considered. As shown in Figure 1, there are 39 states 

for which potential onshore and offshore deep saline formation storage resources have been 

identified. EOR operations are currently being conducted in 12 states. An additional 17 states 

have geology that may be amenable to EOR operations. There are 18 states within 100 

kilometers of an active EOR location and 13 states have operating CO2 pipelines. 

A few states do not have geologic conditions suitable for GS, or may not be located in 

proximity to these areas. However, in some cases, demand in those states can be served by 

 

1 Other types of opportunities include organic shales and basalt.

2

As part of the regulatory impact analysis for the NSPS, the EPA assumed costs associated with a 100 

kilometer pipeline between an EGU and GS site. This is based assumptions used in DOE NETL studies 

(Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases, DOE/NETL-341/082312; Cost 

and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, DOE/NETL-2011/1498; 

Cost and Performance Baseline for Fossil Energy Plants (DOE/NETL-2010/1397); Economic Evaluation of 

CO2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 

2002; Carbon Dioxide and Transport and Storage Costs in NETL Studies. DOE/NETL-2014/1653, May 

2014; Cost and Performance Baseline for Fossil Energy Power Plants, Volume 1a: Bituminous Coal (PC) 

and Natural Gas to Electricity, DOE-NETL-2015/1723, July 2015).
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coal-fired power plants located in areas suitable for GS, and in other cases, coal-fired power 

plants are unlikely to be built in those areas for other reasons, such as the lack of available coal 

or state law restrictions against coal-fired power plants. If an area does not have a suitable GS 

site, EGUs can either transport CO2 to GS sites via CO2 pipelines or they may choose to locate 

their units closer to GS sites and provide electric power to customers through transmission 

lines. Figure 2 shows the location of high voltage electrical transmission lines (greater than 230 

volts) within the continental United States, and illustrates the extensive network of power 

transmission lines available to electric generating facilities.
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Figure 1 – Geologic Sequestration in the Continental United States
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Figure 2 – Electrical Transmission Lines Across the Continental United States3

2 Geologic Sequestration

The DOE and the United States Geological Survey (USGS) have independently conducted 

preliminary analyses of the availability and potential GS capacity in the United States.

National Carbon Sequestration Database and Geographic Information System (NATCARB) and

National Energy Technology Laboratory (NETL) Atlas Storage Resource Estimates

DOE estimates are compiled by the DOE’s National Carbon Sequestration Database and 

Geographic Information System (NATCARB) using volumetric models and published in a Carbon 

Utilization and Storage Atlas. The resource estimates in the Atlas were developed to provide an 

assessment of CO2 geologic storage potential across the United States. The latest version of the 

Atlas, published in November 2012, includes the most current and best available estimates of 

potential GS capacity determined by a methodology applied consistently across all seven of the 

DOE Regional Carbon Sequestration Partnerships (RCSPs).4The methodology defines a CO2 

storage resource estimate as the fraction of pore volume of porous and permeable sedimentary 

rocks available for CO2 storage and accessible to injected CO2 via wellbores. 

The RCSPs have evaluated CO2 storage resources in most states. Some states with 

potential are still being studied and NETL has not developed estimates for the storage resource 

in these states. For example, the deep saline storage potential (including offshore areas) for 

Alaska, Connecticut, Hawaii, Maine, Massachusetts, Minnesota, Nevada, New Hampshire, 

Rhode Island, and Vermont has not been assessed. Similarly, the storage potential of oil and gas 

reservoirs in Alaska, Connecticut, Delaware, Hawaii, Idaho, Iowa, Maine, Massachusetts, 

Minnesota, Missouri, Nevada, New Hampshire, North Carolina, Oregon, Rhode Island, South 

Carolina, Vermont, and Washington has not been assessed; and unmineable coal seam storage 

potentials in California, Connecticut, Delaware, Hawaii, Idaho, Maine, Massachusetts, 

Minnesota, Nevada, New Hampshire, New York, North Carolina, Oregon, Rhode Island, South 

Carolina, South Dakota, and Vermont have not been assessed. Several of these states have a 

potential storage resource, but the amount is not currently reflected in the NETL estimates. 

New Jersey and Wisconsin were assessed and had little to no storage capacity. 

The NETL methodology for estimating storage resources uses a volumetric approach. 

The method requires information on the area of each potential saline formation or horizon 

within a geologic basin along with the formation’s thickness and porosity (pore space). 

Additionally, other specific parameters unique to oil and gas fields and coal seams are needed 

to compute the estimated CO2 storage resource. A storage coefficient (referred to as the 

 

3

Ventyx Velocity Suite Online. April 2015.

4

http://www.netl.doe.gov/research/coal/carbon-storage/carbon-storage-infrastructure/rcsp 
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efficiency factor) is applied to the theoretical maximum volume in an effort to determine what 

fraction of the pore space can effectively store CO2. Each potential storage resource must meet 

basic criteria including (1) adequate pressure and temperature conditions in the formation to 

keep the CO2 liquid or supercritical; (2) presence of a suitable seal system, such as a caprock, to 

limit vertical flow of the CO2 to the surface; and (3) a combination of hydrogeologic conditions 

to isolate the CO2 within the saline formation. Other factors including isolation (depth) from 

shallow potable groundwater, the maximum allowed injection pressure imposed by regulatory 

agencies to avoid fracturing the formation at the injection well (reservoir pressure), and 

caprock or seal capillary entry pressure are also considered. Carbon dioxide storage resource 

estimates consider only physical trapping of CO2 (structural trapping, hydrodynamic trapping, 

and residual trapping). Chemical trapping mechanisms (dissolution and mineralization were not 

considered in the methodology. A minimum and maximum storage volume was estimated for 

each saline resource by applying a low formation efficiency factor (only 0.51 percent of the 

pore space is available for CO2 storage) and a high efficiency factor (5.5 percent of the available 

pore space is available for CO2 storage). A full description of the NETL methodology is presented 

in “Summary of the Methodology for Development of Geologic Storage Estimates for Carbon 

Dioxide,” and is available at: http://www.netl.doe.gov/File%20Library/Research/Coal/carbonstorage/natcarb/geologic-storage-estimates-for-carbon-dioxide.pdf.

NATCARB provides access to publically available data presented in Atlas.5 Maps and data 

files depicting the location and extent of potential saline storage areas, oil and gas producing 

areas, and unmineable coal seams can be downloaded and used for advanced geographic 

analysis of the data. 

The Atlas shows storage potential of approximately 2,296 billion metric tons to more 

than 20,092 billion metric tons of CO2 in the United States from deep saline formations, oil and 

gas reservoirs, and unmineable coal seams. This estimate includes estimates for onshore 

storage and offshore storage in federal waters. Deep saline formations offer the largest GS 

potential; DOE estimates that areas of the United States with appropriate geology have a 

sequestration potential of at least 2,035 billion metric tons of CO2 in deep saline formations.

Table 2.1 shows total CO2 storage resource by state based on analysis by NETL.

 

5

http://www.netl.doe.gov/research/coal/carbon-storage/natcarb-atlas
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Table 1 – Total CO2 Storage Resource (DOE-NETL)6

Million Metric Tons*

State Low Estimate High Estimate

ALABAMA 122,490 694,380

ALASKA 8,640 19,750

ARIZONA 130 1,170

ARKANSAS 6,180 63,670

CALIFORNIA 33,890 420,630

COLORADO 37,610 357,190

CONNECTICUT not assessed by DOE-NETL not assessed by DOE-NETL

DELAWARE 40 40

DISTRICT OF COLUMBIA not assessed by DOE-NETL not assessed by DOE-NETL

FLORIDA 102,740 555,010

GEORGIA 145,340 159,050

HAWAII not assessed by DOE-NETL not assessed by DOE-NETL

IDAHO 40 390

ILLINOIS 10,020 116,820

INDIANA 32,020 68,210

IOWA 10 50

KANSAS 10,880 86,340

KENTUCKY 2,920 7,650

LOUISIANA 169,500 2,103,980

MAINE not assessed by DOE-NETL not assessed by DOE-NETL

MARYLAND 1,860 1,930

MASSACHUSETTS not assessed by DOE-NETL not assessed by DOE-NETL

 

6

The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, 

Office of Fossil Energy, National Energy Technology Laboratory (NETL).
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Table 1 – Total CO2 Storage Resource (DOE-NETL), cont.

Million Metric Tons*

State Low Estimate High Estimate

MICHIGAN 19,050 47,210

MINNESOTA not assessed by DOE-NETL not assessed by DOE-NETL

MISSISSIPPI 145,010 1,185,030

MISSOURI 10 170

MONTANA 84,580 912,720

NEBRASKA 23,770 113,240

NEVADA not assessed by DOE-NETL not assessed by DOE-NETL

NEW HAMPSHIRE not assessed by DOE-NETL not assessed by DOE-NETL

NEW JERSEY 0 0

NEW MEXICO 42,760 359,090

NEW YORK 4,640 4,640

NORTH CAROLINA 1,340 18,390

NORTH DAKOTA 67,090 147,480

Offshore Federal Only 489,840 6,440,090

OHIO 13,460 13,460

OKLAHOMA 56,950 244,550

OREGON 6,810 93,700

PENNSYLVANIA 22,100 22,100

RHODE ISLAND not assessed by DOE-NETL not assessed by DOE-NETL

SOUTH CAROLINA 30,100 34,180

SOUTH DAKOTA 8,760 24,030

TENNESSEE 430 3,860

TEXAS 443,800 4,329,930

UTAH 25,470 240,910

VERMONT not assessed by DOE-NETL not assessed by DOE-NETL

VIRGINIA 440 2,910

WASHINGTON 36,620 496,730

WEST VIRGINIA 16,650 16,650

WISCONSIN 0 0

WYOMING 72,690 684,850

U.S. Total 2,296,680 20,092,180

* States with a “zero” value represent estimates of minimal CO2 storage resource. States that have not 

yet been assessed by DOE-NETL have been identified.
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USGS Storage Resource Estimates

In 2013, the USGS completed its evaluation of the technically accessible GS resources for 

CO2 in U.S. onshore areas and state waters using probabilistic assessment. The USGS 

methodology defines technically accessible storage as the mass of CO2 that can be stored in the 

pore volume of the storage formation taking into account present-day geologic knowledge and 

engineering practice and experience. The assessment used a geology-based examination of all 

sedimentary basins in the onshore and State waters area of the United States that contain 

potential storage formations that meet specific criteria including depth (3,000 feet to 13,000 

feet deep), thick regional seals, and saline formation water (total dissolved solids greater than 

10,000 milligrams per liter). The storage estimates were divided into buoyant trapping, where 

CO2 can be trapped in structural or stratigraphic closures, and residual trapping, where CO2 can 

be held in place by capillary pore pressures in areas outside of buoyant traps. Probability 

percentiles were calculated representing the 5-, 50-, and 95-percent probabilities, respectively, 

that the true storage resource is less than the value presented. A mean value of storage for 

each storage type was also calculated. Storage in oil and gas formations was considered in the 

assessment, however, only the amount of CO2 at that could replace the volume of known 

hydrocarbon production was assessed and quantified. This represents a conservative estimate 

because it does not include assessment of GS associated with enhanced oil recovery (EOR). 

Like the NETL methodology, the USGS storage estimates did not include chemical 

trapping (mineralization or dissolution) or potential storage in shales or basalt. Several basins, 

including areas of California, Washington, Oregon and Idaho were not assessed. The 

methodology differs from the NETL methodology in that it does not include an estimate of the 

CO2 storage potential in “unmineable coal seams”, or offshore federal waters, and does not 

consider EOR. Storage estimates were reduced to account for potential USDWs that may be 

present. A summary of the methodology and results of the USGS assessment can be found at 

http://pubs.usgs.gov/circ/1386/. 

USGS estimates a mean of 3,000 billion metric tons of subsurface CO2 sequestration 

potential from buoyant and residual trapping and 11 billion metric tons from known oil and gas 

recovery replacement. Storage resources are dominated by medium permeability residual 

trapping resources which accounts for 89 percent of the total resources. The Coastal Plains 

Region of the United States contains the largest storage resource of any region. Within the 

Coastal Plains Region, the resources from the U.S. Gulf Coast area represent 59 percent of the 

national CO2 storage capacity. 

Summary of Findings
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The DOE and USGS analyses of the availability and potential CO2 sequestration capacity 

in the United States show that the potential for geologic sequestration of CO2 in the United 

States is large and the resource is widely available throughout the country.

Geologic storage in deep saline formations has been identified in onshore and offshore 

areas of the US in both the NETL and USGS storage assessments. 

Oil and gas reservoirs are potential CO2 storage resources because they have held 

hydrocarbons for thousands to millions of years and hence have properties potentially suitable 

for CO2 storage. The reservoir characteristics of older fields are well known as a result of 

exploration and many years of hydrocarbon production and in many areas infrastructure 

already exists for CO2 transportation and storage. The NETL and USGS CO2 storage resource 

studies include estimates of CO2 storage in depleted oil and gas fields, and storage as part of 

ongoing EOR activities. 

In 2011, DOE sponsored a study7to analyze the geographic availability of applying EOR 

in 11 major oil producing regions of the United States, including several areas that are not 

currently applying EOR. The study developed a national EOR resource assessment from 

reservoir simulations of CO2 floods of 1,800 onshore reservoirs and over 4,000 off shore sands 

and found that there is an opportunity to significantly increase the application of EOR to areas 

outside of current operations. The study found that one of the limitations to expanding CO2 use 

in EOR is the lack of availability of CO2 in areas where oil and gas reservoirs are most amenable 

to CO2 flooding. The EPA analyzed the state-by-state results of the study and identified 17 

additional states where oil and gas fields are amenable to EOR. 

Many states have coal resources that are uneconomical to mine or cannot be extracted 

due to technological barriers. Coal preferentially adsorbs CO2 over methane, which is naturally 

found in coal seams and can become trapped, forming the basis for CO2 storage in coal seams. 

Enhanced coalbed methane recovery is similar to EOR because it provides an economic benefit 

from the recovery and sale of the methane gas, which helps to offset the cost of CO2 storage. 

DOE’s RCSPs have documented the location of approximately 56 to 114 billion metric tons of 

potential CO2 storage resource in unmineable coal seams in 21 states.

8

3 CO2 Pipelines

 

7

“Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-

Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at: 

http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-

04a505a19185.

8

The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S. Department of 

Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL).
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CO2 pipelines are the most economical and efficient method of transporting large 

quantities of CO2.

9

CO2 has been transported via pipelines in the United States for nearly 40 

years. Over this time, the design, construction, operation, and safety requirements for CO2

pipelines have been proven, and the U.S. CO2 pipeline network has been safely used and 

expanded. Many miles of pipelines are currently under construction or planned, further 

expanding the network in the United States. 

Existing Pipelines

The Pipeline and Hazardous Materials Safety Administration (PHMSA) reported that in 

2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a 7

percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2

pipeline miles since 2004. Twenty-eight companies currently operate CO2 pipelines in 13 states, 

to support transportation of natural and anthropogenic CO2 from source areas to CO2 EOR 

locations. The Cortez pipeline is the longest CO2 pipeline and begins at the McElmo Dome CO2

field in southwest Colorado and traverses 502 miles through New Mexico ending at the Denver 

City Texas CO2 Hub, where it connect with several other CO2 pipelines. The Cortez pipeline was 

constructed in 1982. Other large pipelines connect natural CO2 sources in south central 

Colorado, northeast New Mexico, and Mississippi to oil fields in Texas, Oklahoma, New Mexico, 

Utah and Louisiana. 

Anthropogenic CO2 from natural gas processing plants, fertilizer plants and ethanol 

facilities is also transported to oil and gas fields through a series of pipelines that are generally 

shorter than pipelines from natural CO2 source areas. Large pipelines in Wyoming, Texas and 

Louisiana carry anthropogenic gas from gas plants and refineries to the EOR projects. Many 

smaller pipelines carry gas from anthropogenic sources to central distribution facilities or to 

EOR projects, including the examples below: 

 Four gas processing plants in the southern part of the Permian Basin in Texas, referred 

to as the “Val Verde Plants” supply CO2 for EOR projects in the Permian Basin through 

an 82 mile pipeline. 

 A fertilizer plant in Coffeyville Kansas supplies CO2 via a 68 mile dedicated pipeline to 

the North Burbank Unit in northeast Oklahoma. 

 Two separate CO2 facilities, a fertilizer plant in Borger, TX and an ethanol plant in 

Liberal, KS supply CO2 to several EOR projects in Oklahoma and Texas via 173 miles of 

dedicated pipelines. 

 A fertilizer plant in Velma Oklahoma supplies CO2 for EOR projects in southern 

Oklahoma via a 145 mile pipeline. 

Planned Pipelines

 

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Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), page 36.
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The increased demand for CO2 to support EOR projects, and availability of new 

anthropogenic sources of CO2 has provided new opportunities for CO2 transport companies to 

expand the CO2 infrastructure. Several companies have recently proposed several hundred 

miles of dedicated CO2 pipeline in Colorado, Louisiana, Montana, New Mexico, Texas, and 

Wyoming. Some projects are already under construction, some are in the permitting and 

planning stage and some are still in the evaluation and study phase. Examples are identified 

below.

Kinder Morgan has reported several proposed pipeline projects including the proposed 

expansion of the existing Cortez CO2 pipeline, crossing Colorado, New Mexico, and Texas, to 

increase the CO2 transport capacity from 1.35 billion cubic feet per day (Bcf/d) to 1.7 Bcf/d, to 

support the expansion of CO2 production capacity at the McElmo Dome production facility in 

Colorado. The Cortez pipeline expansion is expected to be placed into service in 2015.10

Denbury reported that the company utilized approximately 70 million cubic feet per day 

(Mcf/d) of anthropogenic CO2 in 2013 and that an additional approximately 115 Mcf/d of 

anthropogenic CO2 may be utilized in the future from currently planned or future construction 

of facilities and associated pipelines in the Gulf Coast region.11 Denbury also initiated transport 

of CO2 from a Wyoming natural gas processing plant in 2013 and reported transporting 

approximately 22 Mcf/d of CO2 in 2013 from that plant alone.12

Denbury completed the final section of the 325-mile Green Pipeline for transporting CO2

from Donaldsonville, Louisiana, to EOR oil fields in Texas.13 Denbury completed construction 

and commenced operation of the 232-mile Greencore Pipeline in 2013; the Greencore pipeline 

transports CO2 to EOR fields in Wyoming and Montana.14 A project being constructed by NRG

and JX Nippon Oil & Gas Exploration (Petra Nova) would capture CO2 from a power plant in Fort 

 

10 “Form 10-K: Annual Report Pursuant to Section 13 or 15(d) of the Security and Exchange Act of 1934, 

For the Fiscal Year Ended December 31, 2014”, Kinder Morgan, February 2015. Available at: 

http://ir.kindermorgan.com/sites/kindermorgan.investorhq.businesswire.com/files/report/additional/K

MI-2014-10K_Final.pdf. 

11 “2013 Annual Report”, Denbury, April 2014. Available at 

http://www.denbury.com/files/doc_financials/2013/Denbury_Final_040814.pdf.

12 “CO2 Sources”, Denbury, 2014. Available at: http://www.denbury.com/operations/rocky-mountainregion/co2-sources-and-pipelines/default.aspx. 

13 http://www.denbury.com/operations/gulf-coast-region/Pipelines/default.aspx.

14 “CO2 Pipelines”, Denbury, 2014. Available at: http://www.denbury.com/operations/rocky-mountainregion/COsub2-sub-Pipelines/default.aspx.
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Bend County, Texas for transport to EOR sites in Jackson County, Texas through an 82-mile CO2

pipeline.15 The project is anticipated to commence operation in 2016.16

4 Coal-by-Wire

As discussed in the proposal, electricity demand in states that may not have geologic 

sequestration sites may be served by coal-fired electricity generation built in nearby areas with 

geologic sequestration, and this electricity can be delivered through transmission lines. This 

method, known as “coal-by-wire,” has long been used in the electricity sector because siting a 

coal-fired power plant near the coal mine and transmitting the generation long distances to the 

load area is generally less expensive than siting the plant near the load area and shipping the 

coal long distances. 

For example, we noted in the proposal: “There are many examples where coal-fired 

power generated in one state is used to supply electricity in other states. For instance, 

historically, nearly 40 percent of the power for the City of Los Angeles was provided from two 

coal-fired power plants located in Arizona and Utah. In another example, Idaho Power, which 

serves customers in Idaho and Eastern Oregon, meets its demand in part from coal-fired power 

plants located in Wyoming and Nevada.” 79 FR at 1478.

In this section, we explore in greater detail the issue of coal-by-wire and the ability of 

demand in areas without geologic sequestration to be served by coal generation located in 

areas that have access to geologic sequestration. Figure 1 of this TSD depicts areas of the 

country with: (1) existing CO2 pipeline; (2) probable, planned, or under study CO2 pipeline; (3) 

counties with active CO2-EOR operations; (4) oil and natural gas reservoirs; (5) deep saline 

formations; (6) unmineable coal seams; and (7) areas 100 kilometers from geologic 

sequestration. As demonstrated by Figure 1, the vast majority of the country has existing or 

planned CO2 pipeline, active CO2-EOR operations, the necessary geology for CO2 storage, or is 

within 100 kilometers of areas with geologic sequestration. A review of Figure 1 indicates 

limited areas that do not fall into these categories. 

As an initial matter, we note that the data included in Figure 1 is a conservative outlook 

of potential areas available for the development of CO2 storage in that we include only areas 

that have been assessed to date. Portions of the United States – such as oil and gas storage 

potential in Alaska - have not yet been assessed and thus are depicted as not having geological 

 

15 “The West Ranch CO2-EOR Project, NRG Fact Sheet”, NRG, 2014. Available at:

http://www.nrg.com/documents/business/pla-2014-west-ranch-fact-sheet.pdf. 

16 “WA Parish Carbon Capture Project”, NRG, 2015. Available at: 

http://www.nrg.com/sustainability/strategy/enhance-generation/carbon-capture/wa-parish-ccsproject/.
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formations suitable for CO2 storage, even though assessment could in fact reveal additional 

formations.17

As one considers the areas in Figure 1 that fall outside of the above enumerated 

categories, in many instances, we find areas with low population density, areas that are already 

served by transmission lines that could deliver coal-by-wire, and/or areas that have made policy 

or other decisions not to pursue a resource mix that includes coal. In many of these areas, 

utilities, electric cooperatives, municipalities, and other load-serving entities have a history of 

joint ownership of coal-fired generation outside the region or contracting with coal and other 

generation in other areas to meet their demand. Some of the relevant areas are in RTOs18

which engage in planning across the RTO, balancing supply and demand in real time throughout 

the RTO. Accordingly, generating resources in one part of the RTO such as a coal generator can 

serve load in other parts of the RTO, as well as load outside of the RTO. As we consider each of 

these geographic areas here, we make key points as to why this final rule does not negatively 

impact the ability of these regions to access new coal generation to the extent that coal is 

needed to supply demand and/or those regions seek to include new coal-fired generation in 

their resource mix.

Upper Northwest

This region includes a large portion of Idaho, with smaller areas in Washington, Oregon, 

and Montana. The specific areas identified in this region tend to have a lower population 

density, which would indicate a lower demand for electricity and therefore a likely low demand 

for new coal generation. To the extent that it is needed to supply electricity demand, new coal 

generation can be constructed in areas with geologic sequestration available and delivered to 

this region via the highly interconnected western grid. Washington’s only coal-fired generator –

 

17 The data in Figure 1 is based on estimates compiled by the DOE’s National Carbon 

Sequestration Database and Geographic Information System (NATCARB) and published in the 

United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition. As discussed in the 

TSD, deep saline formation potential was not assessed for Alaska, Connecticut, Hawaii, Maine, 

Massachusetts, Minnesota, Nevada, New Hampshire, Rhode Island, and Vermont. Oil and gas 

storage potential was not assessed for Alaska, Connecticut, Delaware, Hawaii, Idaho, Iowa, 

Maine, Massachusetts, Minnesota, Missouri, Nevada, New Hampshire, North Carolina, Oregon, 

Rhode Island, South Carolina, Vermont, and Washington. Unmineable coal seams were not 

assessed for California, Connecticut, Delaware, Hawaii, Idaho, Maine, Massachusetts, 

Minnesota, Nevada, New Hampshire, New York, North Carolina, Oregon, Rhode Island, South 

Carolina, South Dakota, and Vermont. We are assuming for purposes of our analysis here that 

they do not have storage potential in those formations.

18 In this discussion, we use the term RTO to indicate both ISOs and RTOs.
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Centralia - is located in western Washington and both of its generating units are scheduled to 

shut down in the next 10 years.19

We note that a large portion of this area is served by the Idaho Power, Avista, and Rocky 

Mountain Power, as well and multiple cooperatives and municipalities. Idaho Power and Avista 

provide good examples of both joint-ownership of coal generation as well as coal-by-wire. 

Idaho Power is served by three coal plants located in Wyoming, Oregon, and Nevada.20 Avista’s 

service territory includes parts of eastern Washington and northern Idaho. According to Avista, 

nine percent of its generation is supplied by coal.21 Avista owns 15 percent of two of the 

Colstrip Steam Electric Station units in Colstrip, Montana.22

Small Areas in Nevada and Utah

This region includes small areas in Nevada and Utah, which have low population density 

and therefore less electricity demand than other more populous areas in the country. Rocky 

Mountain Power, which is a subsidiary of Berkshire Hathaway Energy, serves much of Utah. 

Berkshire Hathaway Energy and its subsidiaries and affiliates own coal-fired power plants that 

generate electricity to serve load. Nevada is served by multiple entities including electric 

cooperatives and municipalities as well as NV Energy. This region is part of the highly 

interconnected western grid with transmission lines crossing it, making coal-by-wire readily 

available. For example, Intermountain Power Agency owns the Intermountain Power Project in 

western Utah which largely serves Utah and Southern California.23 Another example is Deseret 

Power, a regional generation and transmission cooperative, which supplies electricity to its 

members and other bulk energy customers in Arizona, Colorado, Nevada, Utah, and Wyoming. 

 

19 Bills in Washington State Seek to End Use of Coal, N.Y. Times, Feb. 14, 2015, available at

http://www.nytimes.com/2015/02/15/us/politics/bills-in-washington-state-seek-to-end-use-ofcoal.html?_r=0.

20 Idaho Power, Coal-Fired Plants, available at

https://www.idahopower.com/AboutUs/EnergySources/Coal/coal.cfm (last visited July 22, 

2015). Idaho Power owns shares of the Jim Bridger coal plant in Wyoming, the Boardman coal 

plant in Oregon, and the North Valmy coal plant in Nevada. Id.

21 Avista, Avista’s Diverse Energy Mix, available at

https://www.avistautilities.com/inside/resources/energymix/Pages/default.aspx (last viewed 

July 22, 2015).

22 Avista, Reliable, Lower-Cost Coal, available at

https://www.avistautilities.com/inside/resources/energymix/Documents/Reliable,%20LowerCost%20Coal.FS%2011.6.14.pdf (last viewed July 22, 2015).

23 Multiple entities in Utah, including cooperatives, Utah Power & Light Company (PacifiCorp), 

and numerous municipalities purchase coal-fired generation from this facility. Intermountain 

Power Agency, Generation Entitlement Shares, available at

http://www.ipautah.com/participants/.
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Deseret owns interests in coal generation, as well as its own facility, that it uses to supply this 

electricity.24 

Southwest

The southwestern region of Figure 1 includes a section of Arizona as well as a small part 

of New Mexico. As can be seen in Figure 2, this area has extensive transmission infrastructure, 

enabling the area to be served by outside coal plants. Most of the load in Arizona - including 

Phoenix, the most populous part of this area - is served by the Arizona Public Service (APS) or 

the Salt River Project, each of which owns shares of coal plants in other areas with geologic 

sequestration available. Specifically, Arizona Public Service owns shares of coal plants in Arizona 

and New Mexico,25 and Salt River Project owns shares of coal plants in Arizona, New Mexico, 

and Colorado.26 Other entities such as Tucson Electric Power, Trico Electric Cooperative, UNS 

Electric, Sulphur Springs Valley Electric Co-op also have service territories in this area.27 Mexico 

has instate coal generation with the majority of the state having geologic sequestration 

available.

Upper Midwest

This region includes Minnesota, most of Wisconsin, the Upper Peninsula of Michigan, 

and parts of North Dakota, South Dakota, Nebraska, and Iowa. Most of the areas of this region 

shown in Figure 1 are located in an RTO28 or are in the process of joining an RTO,29 which 

 

24 Deseret Power Electric Cooperative, Power to Succeed, Now and in the Future, available at

http://www.deseretgt.com/profile/profile.php.

25 APS jointly owns the Four Corners Power Plant on the Navajo Indian Reservation west of 

Farmington, New Mexico. APS also owns part of the Cholla Power plant in northeastern Arizona 

and the Navajo Power Plant in northern Arizona. APS, Coal-Fueled Power Plants, available at

https://www.aps.com/en/ourcompany/generationtransmission/generation/Pages/home.aspx

(last visited July 22, 2015).

26 Salt River Project, Facts about SRP, available at http://www.srpnet.com/about/Facts.aspx.

27 Arizona Corporation Commission, State of Arizona-Electric Map, available at

http://www.azcc.gov/divisions/utilities/electric/map-elect.pdf (last visited July 22, 2015).

28 In this discussion, we use the term RTO to indicate both ISOs and RTOs.

29 FERC, MISO Electric Market: Overview and Focal Points, available at 

http://www.ferc.gov/market-oversight/mkt-electric/midwest/elec-mw-reg-des.pdf; FERC, 

Southwest Power Pool Electric Market: Overview and Focal Points, available at

http://www.ferc.gov/market-oversight/mkt-electric/spp/elec-spp-reg-des.pdf; SPP, FERC 

Approves Integrated System Joining SPP (Nov. 12, 2014), available at

http://www.spp.org/publications/FERC%20approves%20IS%20membership.pdf (noting FERC’s 

approval of the Integrated System, made up of the Western Area Power Administration-Upper 

Great Plains, Basin Electric Power Cooperative, and Heartland Consumers Power, joining SPP).
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provides open access to transmission service and a large set of resources within the RTO to 

serve load. The two RTOs in this area are MISO and SPP, both of which engage in planning 

across the RTO, balancing supply and demand in real time throughout the RTO. Accordingly, 

generating resources in one part of the RTO such as a coal plant often serve load in other parts 

of the RTO, as well as load outside of the RTO. Both MISO and SPP have a number of coal-fired 

power plants in areas with access to geologic sequestration. If a new coal unit is built in an area 

with geologic sequestration, this supply can serve load both inside and outside areas with 

available sequestration. Just as current coal facilities in SPP and MISO can inject electricity onto 

the grid and that electricity can serve load in areas without coal facilities, new coal plants built 

in RTO areas with geologic sequestration available can serve load in areas without 

sequestration available.30 For example, Wisconsin is in MISO with the southern part of the state 

as well as many surrounding areas having geologic sequestration available. Further, this area 

has extensive transmission infrastructure that includes coal-fired power plants outside of this 

area (e.g., lignite plants in North Dakota).31

 

30 See e.g., North Dakota v. Heydinger, Case No. 11-cv-3232, at 6 (SRN/SER) (MN D.Ct)(2014) 

(emphasis added), which discusses MISO, including how generation assets throughout MISO 

serve load throughout MISO:

MISO also ensures the reliability of the transmission system by requiring buyers 

to demonstrate that they have the legal rights to an amount of capacity (i.e., the 

capability of producing electricity) sufficient to meet their customers’ expected 

demand. (Id. ¶¶ 13, 26, 48.) MISO participants usually obtain this capacity 

through ownership of generation assets or through bilateral purchase 

agreements. (See id. ¶ 49; Porter Report ¶ 38; Blumsack Report ¶ 29.) Due to the 

nature of the grid, however, whether the electricity that a buyer ultimately 

receives is from the generation resources that it bid into the market or that it 

contracted for is unknown. (Porter Report ¶¶ 38, 40; Hempling Report ¶¶ 19, 

22.) As described by Defendants’ expert witness, “[o]nce the generating facility 

injects its output into the interconnected transmission network, the electrons 

move according to physical laws, unresponsive to any state law or contract 

provisions.” (Hempling Report ¶ 22.) He analogizes the grid to a “reservoir”: “If I 

want to buy 10 buckets of water, my chosen seller would dump in 10 buckets 

at [its] location, and I would take out 10 buckets at my location. The molecules 

I take out are not the ones my seller dumped in.” (Id. ¶ 19.) In other words, as 

noted by Plaintiffs’ expert witness, “MISO does not match buyers to sellers.” 

(Porter Report ¶ 33.) Moreover, once electricity is generated and injected into 

the power grid, there are no qualitative differences based on generation source, 

so the buyer is unaware of the type of resource that generated the electricity it 

receives. (See Porter Report ¶ 33.)

31 For example, Basin Electric owns the Antelope Valley Station, a 900 MW lignite-based electric 

generating facility near Beulah, ND. Lignite Energy Council, Antelope Valley Station, available at

https://www.lignite.com/mines-plants/power-plants/antelope-valley-station/.
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Central 

This area includes small parts of Missouri, Arkansas, and Tennessee. Parts of this area 

are in MISO, providing the opportunity to serve load through a diverse set of resources 

including coal-fired electricity, as discussed above. The eastern part of this central area is 

served at wholesale by the Tennessee Valley Authority, which is a large federal entity that 

functions like an RTO with numerous generation assets and whose transmission network 

includes areas with geologic sequestration available. Moreover, this area is crossed by 

transmission lines and ringed by coal fired power plants at or near its border. 

Southeast

Figure 1 also indicates areas in the southeast that do not have geologic sequestration, 

including parts of Alabama, Georgia (including Atlanta), South Carolina, and North Carolina. As 

Figure 2 indicates, this area is served by an extensive network of transmission infrastructure 

that can deliver electricity from a diverse resource mix. Additionally, most of this area is served 

by Alabama Power, Georgia Power, Duke Energy Progress, and South Carolina Electric and Gas, 

each of which are large companies with numerous generating assets, including coal-fired assets 

and allowing diverse resources throughout the balancing authority to serve load.

Mid-Atlantic

Figure 1 indicates that parts of Virginia, Maryland, Pennsylvania, and New Jersey are 

lacking geologic sequestration. Again, as noted previously, Figure 2 indicates that there is 

extensive transmission infrastructure in this area that delivers electricity throughout the region. 

This area is served by PJM, a large RTO. Currently, existing coal-fired units in West Virginia, 

Kentucky, Pennsylvania, and Ohio provide electricity onto the electric grid to serve electricity 

load in PJM. Additionally, generators in the western parts of PJM, which has geological 

sequestration available, historically have provided a large amount of generation in the RTO. 

Similarly, new coal generation could be sited in areas with geologic sequestration while 

allowing this new generation to serve other areas without geologic sequestration through the 

extensive transmission infrastructure.

New York

Figure 1 indicates that the eastern part of New York does not have available geologic 

sequestration. This area is part of NYISO, which, similar to other RTOs, has a diverse resource 

mix to meet system demand. New York’s resources include a very small amount of coal-fired 
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generation.32 Additionally, this area, like many others on the grid, imports electricity from 

surrounding areas.33 Portions of New York, as well as surrounding areas such as Pennsylvania, 

have access to potential geologic sequestration. Therefore new coal generation could be built in 

those areas and serve load in the eastern part of New York.

Moreover, New York is a member of the Regional Greenhouse Gas Initiative (RGGI), 

which is a market-based regulatory program to reduce greenhouse gas emissions, which 

indicates that the state is moving away from generation facilities that have high CO2 emissions. 

Further, New York has adopted CO2 limits on new coal-fired power plants, which essentially can 

be met only through the installation of CCS.34

New England

This area includes Connecticut, Rhode Island, Massachusetts, Vermont, New Hampshire, 

and Maine. All of these states are members of RGGI, which is the first market-based regulatory 

program in the U.S. to reduce greenhouse gas emissions, giving a clear indication that New 

England is moving away from electric generation that has high CO2 emissions. 

Coal-fired power plants may have more unfavorable economics in this area than in some 

other areas of the country. For example, this area does not have coal supplies, so that coal must 

be transported into this area from Appalachia or elsewhere. Additionally, some existing coalfired power plants with recently added pollution controls such as SO2 scrubbers are still 

choosing to close for economic reasons: Brayton Point Power Station (Somerset, 

Massachusetts) is scheduled to close in May, 2017 and Mt. Tom (western Massachusetts) 

recently closed. According to ISO New England’s 2015 Regional Electricity Outlook, “Rising costs 

associated with oil and coal and the advanced age of many of the power plants that use these 

fuels make it difficult for these resources to compete against newer, more efficient generators -

primarily natural gas units. For this reason, coal and oil units are now run mainly to meet peak 

demand, when natural gas plants are unavailable, or when natural gas price spikes surpass oil 

prices. The region’s coal- and oil-fired generators represent about 28% of capacity in the region, 

but only produced about 6% of its electricity in 2014 - and very few coal units are left.”35

Moreover, ISO New England stated, “The natural gas price spikes in recent winters have led to 

oil- and coal-fired units being more economical and thus selected in the energy market to run 

 

32 EIA, New York: State Profile and Energy Estimates – Profile Analysis (July 16, 2015), available 

at http://www.eia.gov/state/analysis.cfm?sid=NY.

33 EIA notes that more half of New York’s energy is supplied by other states and Canada. Id.

34 Scott DiSavino and Jim Marshall, NY adopts CO2 rules that limit new coal power plants, 

Reuters, June 28, 2012, available at http://www.reuters.com/article/2012/06/28/us-utilitiesnewyork-carbon-coal-idUSBRE85R1GF20120628.

35 ISO New England, 2015 Regional Electricity Outlook, at 19 (Jan. 2015), available at

http://www.iso-ne.com/static-assets/documents/2015/02/2015_reo.pdf.
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more frequently in winter. (See page 29.) This revenue stream could delay retirements for some 

resources; however, it’s unclear how long the trend will continue or whether it will be enough 

to counter other economic and regulatory pressures. For example, once oil resources run more 

than 9% of the time, expensive capital investments may be required in order to meet air quality 

regulations. In some cases, state regulations restrict the number of hours that dual-fuel units 

can burn oil. And over time, the Regional Greenhouse Gas Initiative’s cap and trade program for 

carbon dioxide emissions could make oil and coal less economic fuels.”36

EIA has also noted the trend towards natural gas and Canadian hydroelectric generation 

in New England over the last decade.37 This region is seeing older, less efficient, traditional 

resources such as coal retire. New England states have several reasons to further limit their use 

of electricity generated from fossil fuels. “Constraints on some of the pipelines delivering 

natural gas into New England have contributed to higher natural gas prices and made electricity 

relatively more expensive. Also, all New England states have renewable portfolio standards (or 

in Vermont, a nonbinding goal) requiring that a certain percentage of their electricity comes 

from renewable sources.”38 To partly make up for retiring coal and nuclear, northeastern 

utilities and Hydro-Quebec have proposed constructing several transmission lines, including the 

1,200-MW Northern Pass, to increase the transmission of electricity from Canada.39 To the 

extent that ISO-NE wanted to utilize coal-fired generation, we note that it is interconnected to 

PJM which has both currently-existing coal generation available, as well as geologic 

sequestration.

 

36 Id. at 20.

37 Energy Information Administration, New England relying more on natural gas along with 

hydroelectric imports from Canada (Aug. 22, 2014), available at

http://www.eia.gov/todayinenergy/detail.cfm?id=17671.

38 Id.

39 Id.