Clean Air Task Force 

Office of Management and Budget Meeting 8-22-13. 

Update on the Availability of Geologic Carbon Storage 

L. Bruce Hill, Ph.D., Senior Geologist. Email: bruce@catf.us 

I. Storage Capacity 

How Much: In its 2013 National Assessment of Geologic Carbon Dioxide Storage Resources, the 

U.S. Geological Survey assessed the technically accessible geologic carbon storage resources in 

36 sedimentary basins in the onshore and beneath state waters of the United States. 1 The 

assessment only inventoried geologic formations below 3,000 feet with adequate porosity and 

permeability to accept commercial volumes of COz. The assessment estimates that there are 

approximately 3,000 Gt of subsurface storage capacity. This represents more than 500 times 

the 2011 annual 5.5 Gt of energy-related COz emissions in the U.S. today. In addition, DOE 

estimates that 500 to 7,500 Gt of COz could be sequestered in all U.S. offshore formations on the 

outer continental shelf.2 

Where: The analysis suggests storage potential in nearly all regions of the U.S.3 Capacity and 

transportation and injection infrastructure currently available in EOR fields in the parts of the 

Rocky Mountains, Midwest, Southeast and parts of California provide a model for expansion. 

Where formations that have capacity for COz don't exist, research suggests that the expansion 

and build-out oftoday's 4,000-mile COz pipeline network is feasible and would reach much of 

the rest ofthe U.S. Offshore areas are under investigation. 

8 A!a£ka Padfic ~Jorthwnst 

{270 Gti ---, 04 Gil Ca!ifomia 

@% (9t1Btl 

3% We~1~m 

Mid·ComiMnt 1150Gtl 

5~; 

Rn'tBas1ns 

!0.44 Gt! 

Grl!al Plains 

(270 Gt! 

~ 9% 

Mid·Cominent 

1m Gt! / 

\ 

8% Co;;stal Plains 

12.000 Gil 

65% 

Gulf Coast: A Hub for U.S. COz? Recent work done by the Gulf Coast Carbon Center (GCCS) at the 

University of Texas, Austin has mapped and in the process of estimating the magnitude of the 

large storage volumes in 30 Mt sites within 10 miles of shore in the Gulf of Mexico (see map 

below). The "Megatransect Project" has documented capacity for billions, if not trillions of tons 

of COz in geologic formations below the Gulf of Mexico. 4 5 6 Combined with existing pipelines 

and future potential for pipelines from the Midwest, the Gulf Coast could potentially be a hub 

for COz. 

Clean Air Task Force 22-Aug-13 1 
main shoreline 

II. C02 Capacity in Depleted Oil Fields 

In early 2012 there were 127 U.S. COz EOR projects with approximately 7,100 C02 injection 

wells and 10,500 producing wells. According to the National Petroleum Council, approximately 

3 billion cubic feet per day ofCOz (57 Mtjyr) of newly purchased COz are presently injected for 

tertiary EOR producing 286,000 barrels of oil per day (105 million barrels per year). 

C02 source 

co, 

surface 

leakage, if 

any 

Storage 

The graphic above {EPA] illustrates how C02 that is received at a project site is a recycled and 

subsequently accounted for in EPA's greenhouse gas accounting scheme {Subpart RR). During the 

progressive injection and reinjection ofCOz nearly all ofthe COz is stored in geologic formations. 

Very little is lost to the atmosphere. Recently released filed life carbon balance data from the 

Kinder Morgan SACROC project suggest that 93% ofthe purchased C02 that was injected for EOR 

was stored {taking into account stationary and mobile emissions associated with the project. 7 

Residu;1l Oil Zones (ROZ): Residual oil zones (ROZs) are naturallywaterflooded formations 

below the oil water contact in oilfields (see illustration below). They are formed when meteoric 

water flushes out the primary oil deposit over geologic time leaving only residual (stubborn) oil 

behind. That residual oil can be substantial-- in some cases as large as the primary deposit (e.g. 

Clean Air Task Force 22-Aug-13 2 
Hess Seminole Field, TX) --but it can only be produced using tertiary EOR methods since water 

flooding will not be effective. Because oil is soluble in COz at pressure, residual oil zones 

represent another frontier for COz-EOR oil production while at the same time promising 

capacities for large volumes of COz to be stored. Significant ROZs have been discovered in Texas 

(and produced) and Wyoming and are being investigated elsewhere. 

(ARI) 

C02 Demand: Advanced Resources Inc. (ARI) has estimated that next generation EOR combined 

with currently limited estimates of ROZ production could produce a demand for approximately 

33 Gt of COz .s 9 10 11 This suggests EOR/ROZ could accept/store approximately one dozen years 

of US EGU system C02 (at 2.2 Gt/y). Currently there is an estimated 2 to 3 Gt of naturally 

occurring COz available to meet this demand. The remaining future demand must be made up 

by captured sources. 

III. Stacked Storage: A Bridge to Commercial Storage. 

What is Stacked Storage? Thick sedimentary sequences commonly are characterized by 

repeating layers of interbedded sand and mud. Stacked storage takes advantage of these 

repeating sequences in the geologic section to build storage capacity vertically (See illustrations 

below). Utilizing multiple layers for storage is advantageous because instead of creating a large 

plume, COz volumes can be managed --along with formation pressures-- by spreading out the 

COz vertically in the geologic section. 

Adyantages of Stacked Storage: stacked storage, when used in combination with EOR, would 

allow for commercial volumes of COz to be stored by the same existing facilities that are being 

used to produce tertiary oil by EOR. EOR combined with stacked storage therefore takes 

advantage of existing pipeline transportation and injection infrastructure and could allow EOR 

operators to transition from oil production once the field is depleted, to storage with incidental 

EOR. As a result, is a potential for large commercial volumes to be stored not only in oilfields 

but in the formations associated with oilfields at a lesser capital cost. 

Clean Air Task Force 22-Aug-13 3 
Illustrations above-- Left: Illustration ofstacked saline storage lj Pashin). Right: Illustration of 

layered oil, gas and saline formations (and intervening caprock in white] at the SECARB Frio 

project, TX that could be accessed in stacked storage. 

IV. Updates on North American Commercial C02 Storage Projects 

1. DOE Regional Carbon Sequestration Partnership Updates 

SECARB /Southern Co. Plant Barry-Cintmnelle. COz is captured at Plant Barry with Mitsubishi 

Heavy Industries amine technology and transported 12 miles by pipeline to Den bury 

Resources' Cintronelle oilfield. The plant began capturing COz in the 4th quarter of 2011 at a 

rate of up to 650 of naturally occurring COz per day, amounting to a target of approximately 

50,000 tons per year. 12 Alabama Power has constructed a pipeline from Plant Barry to 

Denbury's nearby Cintronelle oilfield where injection of the captured COz into a saline unit in 

the Paluxy Formation began in 2012. During this project, a consortium led by LBNL and EPRI 

have developed an innovative new method that will allow the continuous monitoring of 

subsurface parameters such as pressure, temperature and microseismicity. 

SECARB CranJjg)d, MS Project: The Cranfield Mississippi oilfield geologic carbon storage project 

began injection operations in 2008 and had purchased, transported and injected 4 Mt COz into 

the Tuscaloosa Formation as of summer 2013. In March 2012 it was reported that 1.5 Mt had 

been produced and recycled, summing to about 6 Mt injected. The project has been the site of 

numerous monitoring efforts and experiments that have substantially improved scientists' 

understanding ofwhat is needed to ensure secure geologic storage of COz. 

Big Sky Partnership. Kevin Dome, MT.13 14 Injection of 1 Mt of COz into a northern Montana 

saline aquifer is planned to begin in 2015 and continue through 2018 to demonstrate the 

viability of Kevin Dome as a secure target for regional COz emissions. Kevin Dome is a geologic 

structure with naturally occurring COz that has been trapped for SO Ma, that promises the 

ability to hold commercial volumes of captured COz. In the test, COz will be produced from the 

dome, then transported 6 miles to the injection site into the Duperow Formation Formation at 

the edge ofthe dome. The injections will be accompanied by monitoring demonstration and 

research projects. 

Clean Air Task Force 22-Aug-13 4 
MGSC Partnership Illinois Basin Decatur Project: A successful 7,000 foot deep saline injection 

test is underway in Decatur IL, including a comprehensive monitoring program.lt is a 

cooperative project of the Archer Daniels Midland (ADM), The Midwest Geological 

Sequestration Consortium (MGSC) and Schlumberger with $4.4 million of DOE support.15 

During the 3-year injection program, 1.1 million tons of C02 will be captured at ADM's ethanol 

plant using Alstom's amine capture process and will be injected into the Cambrian Mt. Simon 

Formation. A second well is planned which will bring the total to approximately 1 million tons 

per year. Monitoring tools utilized at the site include four shallow groundwater wells and soil 

gas measurements, 3-D seismic profiling, a dedicated monitoring well with embedded 

geophones for walk-away vertical seismic profiling (VSP) and a dedicated in-zone monitoring 

well. The success of this project underscores the availability of commercial scale saline geologic 

sequestration in the Mt. Simon Formation under the Midwest United States, a locus of coalbased electric power generation. The project has injected 0.5 Mt of captured C02 as ofJune 

2013.16 

PCOR Regional Partnership. Bell Creek. WY: Beginning Spring 2013, 1 million tons of C02. 

sourced from the Lost Cabin natural gas separation plant, is being injected for EORY Costeffective monitoring protocols will be the focus of this study. 

MRCSP Partnership Northern Lower Michigan PIQj_ect: 1 Mt of C02 captured at a Antrim Shale 

natural gas separation facility is being injected over a 4 year period into several small oil fields 

in Niagran Pinnacle Reef carbonate formations for the purposes of EOR and storage and 

accompanying monitoring development.1s 19 

2. Other North American Projects 

Pakota Gasification/Weyburn. Saskatchewan, Canada: Weyburn-Midale oil field is an EORstorage project located in Saskatchewan Canada and is the receptor site for captured C02 from 

the Beulah Dakota gasification site in the U.S. 20 Over the life of the field, approximately 44 Mt 

will be injected at Weyburn, with approximately 17 million tons to date). The !EAGHG, in 

conjunction with Canada's non-profit Petroleum Technology Research Centre (PTRC), has 

implemented a monitoring demonstration and research program to investigate the most 

effective methods for ensuring C02 injected for EOR is securely stored. In 2011 it was alleged 

that COz from the project was leaking at the surface at Kerr Farm. Subsequent independent, 

peer-reviewed analysis by the University of Texas suggests, however, that the methane in the 

soils at the farm are of biologic and not geologic origin. 21 

Aquistore/Boundary Dam. Saskatchewan Canada: This SaskPower project will add postcombustion capture to a 110 MW EGU (Unit 3 at Boundary Dam Power Station) and will capture 

90% of the COz, approximately 1 million tons per year.22 23 SaskPower received approval from 

the Saskatchewan Government to build the project in April 2011 and construction is underway. 

Operation of the plant will begin in 2014. COz capture from Boundary Dam will be injected at 

the Sasketchewan Aquistore facility and at the Weyburn EOR project. The IEAGHG's Aquistore 

Program, a collaborative industry and government program, is being operated by Canada's nonprofit Petroleum Technology Research Centre (PTRC).24 Aquistore is a 3-kilometer deep 100 

meter thick Cambro-Ordovician age saline sandstone reservoir located in the Williston Basin in 

Saskatchewan, Canada.25 Aquistore is setto be drilled in 2013 and will also accept COzfrom a 

nearby refinery at the end of 2013. Captured COz from the SaskPower Boundary Dam project 

Clean Air Task Force 22-Aug-13 5 
two kilometers away where it will most likely become the largest commercial and fully 

integrated carbon dioxide capture and storage facility in the world. 

Fort Nelson BC: A PCOR partnership planned saline test and MVA strategy development effort 

will injectl-2.2 Mt/yr COz from the Fort Nelson natural gas processing plant in British 

Columbia. When completed this could be the largest deep saline test in North America.26 

Shell Quest. Alberta: Quest will capture 35 o/o of the COz emissions, 1 Mt/y, from the Scotford 

upgrader (Alberta oil sands) near Fort Saskatchewan, Alberta, will be injected into a saline 

aquifer into the Basal Cambrian Sands starting in 2015. 27 

References. 

1 See USGS at: http:jjpuivsJtsgs.gov jdsj774( 

2 DOE, The National Carbon Storage Atlas (2012) (Available at 

!l__lJp:/j \YYVW,IJQ_tl.do_q_,g_ov jt_~_(_hnolf)_gics /r<J_rboJL~eqfrg_f_~ hc__)tjN_i-\CS_A__~O 12_,p__ci_f). Attached as Exh.III-71. 

3 New England could, access storage in the Midwest by pipeline. or in the offshore outer continental shelf (OCS) 

along Georges Bank as was suggested by an abandoned CCS project that would have stored its C02 in the 

Mississauga Formation 70 miles off ofthe coast of New jersey. 4 Meckel. et aL. Offshore CCS in the Northern Gulf ofMexico and South Atlantic, Poster, Regional Carbon 

Sequestration Partnership Meeting Pittsburgh (September 2011). attached as Exh. Ill·89. 

5http:Jjwww.netLdoe.gov/publications/proceedings/11Jcarbon_storage/tuesdayj11_1115_M eckel_D 0 E_Review _ 

mtg_offshore_compress.pdf 

6 http:jjwww.aapg.org/explorer/2010J09sep/co2storage0910.cfm 

7 See: htt_p_:_/ j VV-':YYY, co2_QJn fe_r_q1 ce.JW__tjVv' lX~:_c_o n tqrg_/ u p_lq~l__ds/_2_(1) _3 / Q_5_/_Fox-~__Kl\'J Prq0_t:_1_1 ta t_i__Q__n-SA_(_B 0 C. pc_l_f 

8 Vella Kuuskraa, Advanced Resources International. Inc. (2012). Using the Economic value of C02·EOR to 

accelerate the deployment of C02 capture, utilization and storage. (CCUS, EPRI Cost Workshop, Palo Alto, CA, April 

25-26, 2012. 9 Meckel, et aL, Offshore CCS in the Northern Gulf ofMexico and South Atlantic, Poster, Regional Carbon 

Sequestration Partnership Meeting Pittsburgh (September 2011), attached as Exh. Ill-89. 

1Dhttp:Jjwww.netl.doe.gov/publicationsJproceedingsJ11Jcarbon_storage/tuesday/11_1115_Meckel_DO E_Review 

_mtg_offshore_compress.pdf 

11 http:/jwww.aapg.orgjexplorerj2010/09sepjco2storage0910.cfm 1' Koperna, et aL, The SECARB anthropogenic test: the first U.S. integrated C02 capture, transportation and storage 

test (2011) (Available at: ht1!Ufww"f.aclYcies.comfP<lJ.LPitLCoal Conference_Pilj)_ei_Flt!A!;.p_clf). Attached as Exh. 

Ill-42. 

13 See: IJ~_t_p: j j_,c;__e_q u(~5_t_rati_Qn_n 1itg;i_u /t(~_p_l_ sJp_rgj cct::;/J£_ev i11__~]__o m_Q_j_1__t_m1 

14 See: '"'.l"I.L.' 

15 See h_t._tp: j j~r,:qucs_t_ratiqq_.mit._t~f._l_u/toJ~l__sj p,t:Qjs;cts/_(l_E;Catu__r_,_htntl. Attached as Exh. III-102. 

16 See: _http:(jseq_ugstrc\ti__Qn.org 

17 See PCOR project site: htt_p_: /_/vY_\y_vv. LH1_cl_ecrc_,_Q_l_-gjp.(_q_rj co__2?<::quq_~__t;_ratiq_n_projQ_(_ts/ dq_fct_u lta_~_p_]( 

18 See: \Ittp:fl2l6.]Q9.2JQJ u"·'''''"'''h'"dlaSJtl_l.lcv·elrlp!nl:r1 

19 See: _[1 ttp_:_//21_Q__.J 0 9 .?J_Q. 10_2_/y s c _nl~l_t.a /_F_r_qscrl_t<_~_ti on~ j__lYI Re__:~l~_%J2 Q_}?_Qstc r_(;_H GT_11_QV ex~ 2_Q_? 0 1 2_,p~lf 

20 See: ht_tp:jjvv·__vvvv.ic_c1ghg.()_!J.~/do_c_s_/genq_r~li._p_ttl)_1lcat:ip_ns/w_t:~ybun),_p_{lf. Attached as Exh. 111-45. 

' 1 Romanak, Analysis ofGas Chemistry at the Kerr Site, !PAC Publication (2012). Attached as Exh. Ill-46. 2' Global CCS Institute, The Global Status ofCCS: 2011, pp. 25, 102 (2011). Attached as Exh. Ill-66. 

23 ht~:p_:/ /w_vvw,sa,skptn,ve r·.con1jsu:.;tainablc__gnJ\.Yth/_<1Ssets/cl_ean_co~l t i nf()pnatiq_n_shect. pdf Attached as Exh. III65. 

24 For more information on Aquistore, see: 

Fvv'yvw._i [p_q ne_rgi_es n_o_qye! lc_~_:;_,_I_.'O m__cy(1__2. Fcn__J_}_tent1:!\1_?. F d q_w_n l o <1 (_FXJ 2F_(i_7_9 8 3')h_2F14:7J_8 37__%} Ffi_h~% 2F2.__§_W b__i_t_t;~ ker_:_._p_{,l_f 

&eicx2ixT7l\oBKig6QHC.rnaGICQ&usgoAFQj(NH··h:)UN02_dyK9_8·yDUxK1zc1UwkQAttached as Exh. 111-48. 

2s See: }_Jtt.p_:_j_/_\NVVW_,ptrc._c_~l/aq~_!_i_stort~__ qvcry_igw.p_l_m. Attached as Exh. 111-49. 

26 See: l_1_t_tp_: I I w_~yvv:, p_f~Ld Qt\,gQ v/_t_c_c_h no_l_ qg_( e:;/_c_<ll-_b_(_) JL~:c_q/_f r_1__fr2l_S_tg1 {: tllTt?lrc5}2/_p_co_ r_J_1 tml 

27 See: ht_tp:I j~yvv_w,::;__b_el l,_c~<j enj g_lJ()ll_ t~hs,;IJ /_q L! r_-: bt1_ 5iJ_1_e ss~ t_v_lsgj tt_p;)Jrcatp/ <J i1~ s_~lDd 5_/_q_y_es__t_._h_t_p_1I 

Clean Air Task Force 22-Aug-13 6 
' 


A 


TASK FORCE 

Saline and EOR "Stacked" Storage 

• Existing Transportation and Injection Infrastructure 

• Revenue early when needed to support capture 

• Vertically stacked capacity, pressure management vs one large plume 

• Existing surveillance tools and reservoir knowledge 

• Multiple caprock seals 

.•­.... •.• Stacked oil, gas & 


saline aquifers 


SECARB Frio 


project, TX 


8500­

.A 

'4 o; '""" ~= 

Example of Stacked 

Storage potential in 

fVlodifled frorr; exh1b1t 2 Citronelle Field, MS TRRC Docket 113"23116 

(Esposito/Southern Co) QU6o/. 
Q 


TASK FORCE 

Depleted Oil Fields and Residual Oil Zones (ROZ) 

Storage targets: 

I ~ • Main Pay Zone I Tertiary EOR 

'£ 

! 

x -...-- Residual Oil Zone t3' 


1 

.£ 

~ 1---- Saline Water 


" 

,! 

:t· 

EOR & ROZ C02 demand: 33 Gt--30 Gt must be supplied by captured sources. 

TASK .~ FORCE Offshore Storage Progress: 


Gulf Coast "Mega Transect" 


Approx. location of 

present-day shelf edge 

(Meckel, Trevino/TX BEG et al) 

TX BEG screening 30 Mt-size reservoirs: suggests billions to trillions of tons of capacity 

8 

·~· ll~'W 

·~· 

-

~· 

D 150 fiOO 75G 1,000KUlMEfEAS 

0 250 500MilES 

B"ia ""'l' imrn JaM8 

al!d olhe~SI2008) 

CGVIR-Consortium 

1m Spariallnfo!mation 

SRTM 9ful Databa•a 

@ 

TASK FORCE 

USGS (2013): Estimated Storage =3,000 Gt 


... .w

Alaska Pacific Northwest 


l\4 Gt) 


I270Gtl·~· California ·.. 9% . ·. I ISO Gtl Western
 3% 
 Mid-Continent 

(150 Gt) 

5% 

Eastern Mesozoic 

Rift Basins 

IOMGtl 

<1% 

Rocky Mountains 

and Northern 

Great Plains 

1110 Gtl 

\ 9% 

/ Eastem 

Mid-Continent 

(23!J Gt) 

8% 

Coastal Plains 

{2,000Gtl 

65% 

Map ofthe conterminous United States and Alaska showiflg 8 regions {separatEtd by bold dashed lines), evaluated areas (bluish gray) that 

were not asst7ssed, and 36 areas (pattern) that were assessed by the U.S. Geological Smvey for carbon dio)(ide (C0 ) storage. Resource~ in federally 1

owned offshore areas were not assessed, and Hawaii was considered unlikely to have significant storag~;~Jesources. Regions and study areas are 

plotted over a shaded·reliel image showing higher elevations in brown end ten and lower elevations in green. 

USGS-screened storage resources met technical criteria -adequate data, depth, 

volume & injectivity in 36 basins. 
How Much Does CCS Really Cost? 

An Analysis of Phased Investment in Partial C02 Capture and 


Storage for New Coal Power Plants in the United States 


December 20, 2012 

Mike Fowler, Clean Air Task Force 

John Thompson, Clean Air Task Force 

Bruce Phillips, The NorthBridge Group 

Douglas Cortez, Hensley Energy Consulting 

The Clean Air Task Force 

The Clean Air Task Force (CATF) is a nonprofit organization dedicated to reducing 


atmospheric pollution through research, advocacy, and private sector collaboration. CATF 


acknowledges the contributions of Douglas Cortez in developing the coal power plant capital 


cost and performance data utilized in this analysis, including the cases where the construction 


of CCS facilities is deferred, and acknowledges the contributions of Bruce Phillips for his 


advice on the financial models used to estimate cost of electricity. 


18 Tremont Street, Suite 530, Boston, MA 02108 


www.catf.us 

Introduction 

There is no shortage of cost estimates for carbon capture and storage (CCS). 1 

Frequently, however, when these estimates are applied to some particular policy 

purpose differences in their cost bases and methodology obscure the underlying trends 

of most general interest. As a result, in this short paper, we have attempted to provide 

some clarity around a basic policy-relevant CCS question: wh;1t is the increase in cost of 

electricity for a new coal power plant in the Midwestern United States as a result of CCS 

used to comply with proposed US Environmental Protection Agency C02 emission 

standards? 

Our methodology and analysis are described in detail below. In summary, we find that 

while the increase in cost of electricity (COE) 2 for new coal power due to CCS may be 

35% or more in some cases, the opportunity to delay the installation of CCS and to use 

partial removal of COz, as contemplated in EPA's proposed rule, and the opportunity to 

sell the captured COz for enhanced oil recovery (EOR), would reduce this electricity cost 

premium due to CCS to just under 13%. Without revenue for sales of C02 for EOR the 

premium would rise to just over 19%. Optimization of plant design and operations 

during the early years of a phased-in CCS approach, development of more robust C02 

sales markets, and realizing technology cost and performance innovations over time 

could further reduce the estimated cost premium. 

The Clean Air Task Force has previously published a lengthy description of CCS that 

included a limited analysis of CCS economics, including partial capture.3 This paper 

updates and extends the previous economic analysis and provides additional detail on 

our methodology and data sources. 

Our COz Emission Target·· US EPA's Proposed C02. Limits for Power Plants 

The COz emissions limits proposed by EPA for new power plants include significant 

implementation flexibility. 4 One compliance option includes producing power by 

burning natural gas in a modern combined cycle power plant. This is the direction most 

new power plants in the United States are already headed, because today's low natural 

gas fuel prices have made this technology the lowest ali-in cost source of new 

generation under most circumstances. For developers who choose to build coal-fired 

2 

power plants, however, EPA's rule offers two options: either the project proponent 

must a) install CCS so that the power plant emits no more than an annual average of 

1000 pounds of C02 for each one million watt-hours of gross electricity generated 

("MWh") from the start of operations (which we call a "Day 1" option), or b) ensure that 

the power plant will emit no more than an annual average of 1800 pounds of C02 for 

each MWh of electricity generated during its first 10 years of operation followed by no 

more than 600 pounds of C02 for each MWh of electricity generated after that. Under 

the latter option, which effectively delays the time at which CCS must be operating on 

the plant, the average C02 emissions of the power plant over 30 years also must not 

exceed 1000 pounds per MWh (we call this a "Phased" option). 

The Basis for Our CCS Cost Estimates 

A number of organizations, including the US DOE, MIT, EPRI, and others, have developed 

estimates of the cost of building new coal power plants with CCS. Of all of these the US 

DOE estimates -- which are produced under contract to the National Energy Technology 

Laboratory (NETL) by engineering firms using 'bottom-up' estimates of the procurement 

and installation cost and performance of individual plant components -- include the 

broadest range of plant configurations, contain the most detail, and are most widely 

used in industry, academia, and policy circles. The costs associated with capturing C02 

are generally significantly higher than the costs associated with sequestering that 

captured C02 geologically, and so we pay particular attention to these capture costs in 

our analysis. 

Of particular advantage for our current purposes, the NETL studies include detailed 

estimates of performance and cost for new coal power plant configurations that use socalled partial capture of C02 • This level of detail is helpful because the costs of 

producing power from a coal power plant will generally increase as the amount of C02 

captured increases (due to larger capture equipment, larger C02 compressors, greater 

auxiliary loads, etc.) and the NETL estimates include these effects.5 Furthermore, intercomparison efforts suggest that where comparable configurations and cost metrics are 

used, the NETL results are similar to or more conservative (i.e. higher cost and greater 

loss of efficiency for CCS) than other studies.6 

3 

Several coal power plant configurations studied by NETL would meet EPA's proposed 

C02 standards. The NETL case for a new supercritical coal power plant with 50% C01 

capture would emit 939 pounds of C02 per MWh, for example (hereinafter our "Case 

1"), while a new supercritical coal power plant with 70% C01 capture would emit 592 

pounds of C01 per MWh (hereinafter our "Case 2"). For comparison, NETL estimates 

that a new supercritical coal power plant without CCS would emit 1675 pounds of C02 

per MWh (hereinafter our "Case 0"). 7 This latter case is the typical type of coal power 

plant built around the world today. In addition to performance estimates, the NETL 

studies include extensive estimates of operation and maintenance and construction 

costs (the latter category including process equipment, supporting equipment, direct 

and indirect construction labor, engineering-procurement-construction services such as 

detailed design and construction management, and various process and project 

contingencies). 

Our Methodology for Deriving Incremental Costs Due to CCS Requirements 

To derive the incremental COE for a coal power plant with CCS over and above the COE 

for an otherwise similar coal power plant without CCS, we start with the raw overnight 

installed equipment costs, project development costs, operation and maintenance 

costs, and performance estimates produced by NETL for Cases 0, 1, and 2 above, which 

reflect year 2007 price levels expressed in year 2007 dollars. We then assume that the 

power plant cases we are evaluating will come into service in 2017, and we escalate the 

raw NETL costs accordingly, finally expressing our results in year 2017 dollars and 

projected year 2017 cost levels." For comparison purposes in our analysis we also 

include a case for combined cycle natural gas without CCS, which we call Case 4. 

We calculate COE for each case using an economic methodology broadly used in the 

power project development industry. In this analysis, all of the cash flows for the 

project, including initial construction costs, 9 operating and maintenance costs, fuel, 

taxes, and revenue from the sale of power are projected for each year of the project 

lifetime (here 30 years) on an 'unlevered' basis, and the resulting free cash flow that 

would be returned to project owners each year is discounted back to the initial day of 

operation to produce a single net present value estimate for the project. 10 Obviously 

the NPV depends strongly on the assumed discount rate, and by standard convention 

4 

the 'internal rate of return' of the project is that discount rate for which the NPV on day 

one is zero. 

In our analysis, we specify a nominal, unlevered, after tax internal rate of return of 10%, 

and derive the initial sales price for electricity from the project that is required for the 

investment to earn that rate of return. This 2017 electricity sales price is the COE 

measured in dollars per net MWh, assumed in our analysis to escalates at 2.5% per year 

over the project lifetime (as a proxy for the long-term US inflation rate). Other 

economic inputs to the calculation are also assumed to increase at 2.5% per year, 

including O&M, fuel, and, where it has been assumed, revenue from sales of C02 

captured by the project and used for enhanced oil recovery. 

Our Assumptions About Coal Power Project Design Meeting EPA's Standard 

In addition to updating NETL's 2007-era raw overnight installed equipment costs and 

applying our own project economics analysis framework, we make several key 

assumptions about CCS project development that significantly impact our cost 

assessment. In particular: 

• 	 Unlike NETL's analysis where a cost of $8.48 per tonne of C02 captured is 

assessed to the coal power plant for sequestration site development, injection, 

and monitoring associated with CCS, we assume that captured C02 will be sold 

by the power plant to a different entity for $16.56 per tonne, and used for EOR 

(both in 2017 terms). $16.56 per tonne is the difference between prevailing C02 

sales prices in Texas (reported to be in excess of $37.83 per tonne in late 2011) 

and US EPA estimates of the cost to transport C02 from the Midwest US to Texas 

($18.59 per short ton in 2007 terms) after both are adjusted for inflation." The 

net difference to the coal power plant between paying for sequestration and 

selling C02 by pipeline for EOR in Texas is $25.04 for each tonne captured. 

Although we have assumed sales of C02 by pipeline to Texas for this analysis, 

other sales opportunities may be present which could be more or less favorable 

than our assumption (e.g., sales of C02 for EOR along the Gulf Coast or closer to 

the Midwest). Ultimately, given the uncertainties in the price for which C02 

might be sold we also include a sensitivity case in which we assume that no 

revenue from sales of CO, for EOR will be available. 

s 
• 	 We develop a new analytical case (which we call Case 3) representing a 

supercritical coal power plant that is initially put into service without CCS, but 

with a certain level of investment in CCS readiness (e.g., an oversized boiler), and 

for which 70% CCS is added at year 11 of operation. Such a configuration would 

perform better than EPA's proposed Phased option, emitting 1692 pounds of 

C02 per MWh for the first 10 years, and 592 pounds per MWh thereafter, and 

averaging 995 pounds per MWh over 30 years. This case, which we call Case 3, is 

the same power plant as in our Case 2, except that the amine-based C02 removal 

system and C02 compression system (which together represent close to 20% of 

the overnight construction cost of the power plant) are constructed during years 

8 - 10 of operation of the base power plant and come into service in the 11'h 

year. 

• 	 Because amine-based C02 removal systems require significant quantities of 

steam for operation, and because the C02 removal system in Case 3 is not in 

service until the 11'h year of power plant operation, there is a significant surplus 

of low pressure steam from the plant's boiler during the prior years. In order to 

utilize this energy, we specify that an additional low-pressure steam turbine 

generator, condenser, condensate pumping system and associated cooling water 

systems would be operated during this initial 10-year period. We estimate the 

performance of this system using the same steam conditions and equipment 

used by NETL in the Case 2 design. Based on those steam conditions we 

estimate that this additional turbine in our Case 3 would produce an additional 

net 100.2 MWe, and would increase initial construction costs by $38 million 

{2007 basis) above NETL's estimate. 12 Our cost estimates for this additional 

steam bottoming cycle are based on scaling data provided in the NETL reports. 

We assume that this additional turbine/generator is retired after the 10'h year of 

plant operation.13 

• 	 Because the C02 removal system in Case 3 does not operate until year 11, the 

auxiliary electrical loads associated with that equipment (14.8 MWe for the 

amine system, 31.7 MWe for the C02 compressors, and several MWe for other 

system loads) are similarly absent during that period. Due to those adjustments 

and the presence of the additional low-pressure steam turbine generator 

6 

system, we estimate a plant heat rate of our Case 3 during years 1 - 10 of 

operation of 8.752 MMBtu of fuel input per MWh of net electricity produced. 

Owing to the design changes in Case 3 made in preparation for CCS this heat rate 

is slightly higher than the heat rate of a new coal plant without CCS (8.687 

MMBtu/MWh for Case O) but significantly lower than the heat rate of Case 3 

after CCS is installed and operational (11.151 MMBtu/MWh), all measured in 

terms of the higher heating value of the fuel needed to produce a net MWh of 

electricity. 

• 	 All of our cases include significant expenditures for project development 

activities and other 'owners costs' in advance of commercial operation. We 

follow NETL's treatment of these expenditures directly, adding between $208 

million for our case without CCS and $312 million for our case with 70% CCS 

(both in 2007 terms, which we later inflate). For our Case 3 we apportion the 

owners cost between the initial construction period and later addition of CCS in 

accordance with other construction expenditures. 

Table 1 of our Appendix lists all of the key cost and performance assumptions for our 

cases 0, 1, 2, 3, and 4, in the original (2007-era) NETL terms. Fuel costs in our analysis 

are derived from current projections of coal market prices and transportation charges 

for a generic Midwestern US location. We estimate the 2017 price of this delivered coal 

at $2.98/MMBtu.14 In our NGCC case, we assume a 2017 price for delivered gas of 

$4.73/MMBtu. 15 

Our Results 

Our results for key project economic metrics are summarized in Table 2 of our Appendix. 

We find that the 2017 COE for a new natural gas combined cycle plant would be 

$56/MWh (Case 4), while that for a new supercritical coal power plant without CCS 

would be $100 per MWh (Case 0), and that for a new supercritical coal power plant with 

enough CCS to meet EPA's Day 1 standard would be $124 per MWh (Case 1, including 

revenue from sales of C02 for EOR). $124 per MWh represents roughly a 24% premium 

on the price of power the facility owner must charge in order to comply with the 

proposed Day 1 standard by using CCS. If, however, the investment in CCS is delayed by 

10 years consistent with EPA's proposed standard, and the appropriate anticipatory 

7 

v 

work done, a new supercritical coal power plant might be constructed which meets 

EPA's Phased standard for only $113 per MWh, representing only a 13% power price 

premium over the uncontrolled coal case (again after accounting for C02 sales revenue). 

For Case 1 (50% CCS from Day 1) without EOR revenue the .COE premium is 36% (versus 

24% with EOR revenue). For Case 3 (70% CCS, Phased approach) without EOR revenue 

the COE premium rises is 19% (versus 13% with EOR revenue). These cases are labeled 

Case lb and Case 3b, respectively in Table 2. Relative power costs for our primary cases 

are indicated in Figure 1 below. 

Figure 1 

Impact of CCS on Cost of Electrldty for Coal (Greenfield) 

$150 or-------------------·------------'-----­

~ 

.: 

~ 

l$10<> -!-·-···-·················· 

$1$ +-------

Conclusions and Further Analysis 

Our analysis indicates that with phased implementation of partial CCS, the COE 

premium for a new coal power plant in the Midwest US could be under 20%, and under 

13% if revenue from sales of C02 for EOR purposes is considered. In this analysis we 

have been somewhat conservative, however, and it is likely that additional reductions in 

the 13% cost premium for the phased construction case with EOR C02 sales would be 

possible both through a refined study and in actual practice. For example, better 

8 

optimized low-pressure steam system design in the early years of the Phased case could 

increase power output and sales, while the construction cost contingencies for CCS 

equipment included in our estimate likely will decrease over time. Additionally, there is 

uncertainty in future C02 revenues for EOR, and as markets develop actual prices may 

exceed the values we have assumed here. Exploration of these issues is beyond the 

scope of our current analysis. 

9 

Notes 

1 See for example Cost and Performance of Carbon Dioxide Capture for Power Generation, International 

Energy Agency, 2011 (hereinafter lEA 2011) 2 The key economic metric in our analysis is the 1

cost of electricity' (COE) for each power plant case, which 

we derive following NETL as "the revenue received by the generator per net megawatt-hour during the 

power plant's first year of operation, assuming that the COE escalates thereafter at a nominal annual rate 

equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period 

of the power plant". Cost and Performance Baseline for Fossil ,Energy Plants, Volume I, Revision 2, NETL, 

(November, 2010) at 58- 59 (hereinafter "NETL A"). This current-dollar metric (also sometimes called a 

'real levelized price' because the price is constant in real terms) reflects the ail-in construction cost, 

operation and maintenance cost, fuel costs, and return on investment for the power plant owner, and is 

one of a number of different approaches for calculating annualized lifecycle economics used in the 

industry. 

3 See Technical Options for Lowering Carbon Emissions from Power, available at 

http://www.coaltransition.org/filebin/pdf/Technicai_Options_for_Lowering_Carbon_Emissions_from_Po 


wer.pdf 


4 See Federal Register Vol. 77, No. 72, Friday, April13, 2012, at 22436-22421. 
 5 NETL A and Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, NETL 

(May, 2011) (hereinafter "NETL B"). These studies include identical cost and performance baselines, with 

some overlap in plant configurations studied. 6 See lEA 2011 at Table 4. 7 See NETL A at 9 and NETL Bat 35-39. 8 Specifically, we update NETL's costs to a 2017 period using our estimates of inflation in power plant 

overnight construction costs between 2007 and today (39.4%) and our projection of further inflation in 

power plant overnight construction costs between today and 2017 (assuming 2.5% per year). This yields 

an estimate of the construction costs for each case. To derive operation and maintenance costs, we begin 

with NETL's estimates, which again are for a 2007 period, and apply our estimate of inflation in those 

costs from 2007 through 2017 (2.5% per year). Our estimate of inflation during the period 2007 to 2012 

is considerably larger (more conservative for our overall calculation) than a recent cost update by NETL 

(see Updated Costs (June 2011) Basis for Selected Bituminous Baseline Cases, August, NETL, August, 

2012). 

9 We assume a 5-year construction period for each coal case and apportion the overnight construction 

costs, including owners costs, escalated to constant year 2017 dollars, to June 1 of each year of the 

construction period (10%/30%/25%/20%/15%). For each year's construction expenditure we then add 

interest compounded annually at a real rate of 7.32% up to the commercial operation date of January 1, 

2017. We treat the natural gas case (Case 4) in the same way except that the construction period is three 

years (10%/60%/30%). These costs, with interest up through the first day of operation of each plant, form 

the initial lump-sum investment against which the operational cash flows of the project in later years are 

balanced in the NPV calculation. The delayed CCS addition in Case 3 is treated slightly differently. For 

that case we apportion the construction expenditures and associated owner's costs evenly over 

operational years 8 - 10 of the project (33%/34%/33%). We fund these expenditures from cash flow 

generated by the operating project, so we do not charge interest for them in our analysis. We use 

overnight costs escalated to year 2027 for this purpose, providing some measure of conservatism to the 

calculation. 

10 By 'unlevered' we mean the capital to construct the project is assumed to be financed entirely from 

equity, with no debt. Actual power projects typically Include some level of debt, with the amount of debt 

depending on the level of financial risk associated with the project. Using an 'unlevered' cash flow 

analysis is common In the industry, however, when comparing generally similar projects for which the 

precise capital structure is not yet determined. 10% is a typical nominal discount rate used for these 

purposes, reflecting a balance between long-term debt and equity return expectations, although other 

10 

values are also used (e.g., weighted average cost of capital in some utility ratemaking cases). We use 10% 

for all projects here, with no adjustmEnt for project type or risk, because it is not clear that the financial 

risks associated with the projects considered in this paper are materially different from one another. In 

addition, we do include, following NETL, a contingency on CCS capital costs reflecting the newness of the 

technology. 

11 We derive an estimated cost of $6.62/tonne for C02 sequestration from NETL B at p. 475, in 2007 

terms. This is $8.47 in 2017 terms. Reported C02 prices at Denver City, Texas were above $2 per 

thousand standard cubic feet ($37.83/tonne) and rising at the end of 2011. See "North American co, 

Supply and Developments11 , Glen Murrell, Wyoming Enhanced Oil Recovery Institute, University of 

Wyoming 10th Annual Carbon Management Workshop, December 6, 2012, Midland Texas. For 

transportation costs see Technical Support Document (TSD) for the Transport Rule Docket ID No. EPA-HQOAR-2009-0491, US EPA, July 2010, at 6-2.21. 12 Steam at 73.5 psia and 556.3 F supplies both the amine system and the low-pressure turbine in NETL's 

design (1.26 million pounds per hour, and 1.80 million pounds per hour, respectively), returning to the 

plant systems as very low-energy steam from the turbine (1.0 psia and 101.1 F).and hot water from the 

amine system. See NETL B at p. 100. Based on these steam conditions and the performance of the 

existing steam system in NETL's design we estimate that an additional low pressure steam system used in 

lieu of the amine system (including an additional low pressure turbine with steam extraction, condenser, 

feedwater heaters, and condensate pump to return steam to the existing deaerator) could produce 100.2 

MWe additional power for the plant and would cost $38 million dollars (in 2007 terms, including both 

turbine system and associated buildings and electrical plant). In part due to economies of scale in the 

NETL estimates for the boiler, main steam turbine generator, and other systems in their 70% CCS case, the 

specific capital cost of our Case 3 (in $/kW-net) prior to CCS installation is less than that of NETL's case for 

a supercritical coal plant without CCS. 

13 We assume that this equipment is salvaged after fully depreciated, at no net cost to the facility owner. 

In fact this would probably occur in year 11 when the equipment would be sold at a value which offsets 

the amount of undepreciated basis. 14 We estimate $47.75 per short ton at 11800 Btu per pound for Illinois coal, per 

http://www.eia.gov/coal/news_markets/ for August 2012, escalated at 2.5%, plus 30% for transportation. 15 The current price for natural gas futures contracts for June, 2017 delivery at the Henry Hub in Louisiana 

is $4.433/MMBtu according to The CME Group (http://www.cmegroup.com/trading/energy/naturalgas/natural-gas.html). We assume an additional $0.30/MMBtu for gas transportation between Henry Hub 

and our generic Midwestern US location. 

11 

APPENDIX