### Clean Air TaskForce Office ofManagementand BudgetMeeting 8-22-13. Update ontheAvailabilityofGeologic Carbon Storage L. 

### Bruce Hill, Ph.D., Senior Geologist. Email: bruce@catf.us I. Storage Capacity 

### How Much: In its 2013 National Assessment ofGeologic Carbon Dioxide Storage Resources, the U.S. Geological Survey assessed the technically accessible geologic carbon storage resources in 36 sedimentarybasins in the onshore and beneath state waters ofthe United States. 1 

### The assessment onlyinventoried geologic formations below 3,000 feet with adequate porosity and permeability to acceptcommercial volumes ofCOz. The assessment estimates thatthere are approximately 3,000 Gt ofsubsurface storage capacity. This represents more than 500 times the 2011 annual 5.5 Gt ofenergy-related COz emissions in the U.S. today. In addition, DOE estimates that 500 to 7,500 Gt ofCOz could be sequesteredin all U.S. offshore formations on the outer continental shelf. 2 

### Where: The analysis suggests storage potential in nearly all regions ofthe U.S. 3 

### Capacity and transportation and injection infrastructure currently available in EOR fields in the parts ofthe Rocky Mountains, Midwest, Southeast and parts ofCalifornia provide a model for expansion. Where formations thathave capacityfor COz don't exist, research suggests thatthe expansion and build-out oftoday's 4,000-mile COz pipeline networkis feasible andwould 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

1mGt! 

# / \

8% Co;;stal Plains

12.000 Gil

65% 

### GulfCoast: AHub for U.S. COz? Recent work done bythe GulfCoast Carbon Center (GCCS) atthe University ofTexas, Austin has mapped and in the process ofestimatingthe magnitude ofthe large storage volumes in 30 Mt sites within 10 miles ofshore in the GulfofMexico (see map below). The "Megatransect Project" has documented capacityfor billions, ifnottrillions oftons ofCOz in geologic formations belowthe GulfofMexico. 4 5 6 

### Combined with existing pipelines and future potential for pipelines from the Midwest, the GulfCoast could potentiallybe a hub for COz. CleanAir Task Force 22-Aug-13 1main shoreline



### II. C02 Capacityin Depleted Oil Fields In early 2012 therewere 127 U.S. COz EOR projects with approximately 7,100 C02 

### injection wells and 10,500 producingwells. According to the National Petroleum Council, approximately 3 billion cubic feet per day ofCOz (57 Mtjyr) ofnewly purchased COz are presentlyinjected for tertiaryEOR producing 286,000 barrels ofoil per day (105 million barrels per year).

C02 source 

### co, surface leakage, if

any Storage



### Thegraphic above {EPA] illustrates how C02 

### thatis 

### received ataprojectsiteis 

### a recycled and subsequentlyaccounted for in EPA'sgreenhousegasaccounting scheme {SubpartRR). During the progressive injection and reinjection of COz nearlyall of the COz is 

### stored in geologic formations. Very little is 

### lostto the atmosphere. Recently released filed life carbon balance datafrom the Kinder Morgan SAC ROCprojectsuggestthat 93% of thepurchased C02 

### thatwas injected for EOR wasstored {taking into accountstationaryandmobile emissions associated with theproject.7 

### Residu;1l Oil Zones (ROZ): Residual oil zones (ROZs) are naturallywaterflooded formations belowthe oil water contactin oilfields (see illustration below). They are formed when meteoric water flushes outthe primaryoil deposit overgeologic time leaving onlyresidual (stubborn) oil behind. Thatresidual oil can be substantial-- in some cases as large as the primarydeposit (e.g. CleanAir Task Force 22-Aug-13 2

### Hess Seminole Field, TX) --butit can onlybe produced using tertiaryEOR methods sincewater flooding will notbe effective. Because oil is soluble in COz atpressure, residual oil zones represent anotherfrontier for COz-EOR oil productionwhile atthe same time promising capacities for largevolumes ofCOz to be stored. Significant ROZs have been discovered in Texas (and produced) andWyoming and arebeing investigated elsewhere.

(ARI)

C02 Demand: Advanced Resources Inc. (ARI) has estimated thatnextgeneration EOR combined with currentlylimited estimates ofROZ production could produce a demand for approximately 33 Gt ofCOz .s 9 10 11 

### This suggests EOR/ROZ could accept/store approximately one dozenyears ofUS EGU system C02 (at 2.2 Gt/y). Currentlythere is an estimated 2 to 3 Gt ofnaturally occurring COz available to meetthis demand. The remainingfuture demand mustbe made up by captured sources. III. Stacked Storage: ABridge to Commercial Storage. 

### What is Stacked Storage? Thick sedimentary sequences commonly are characterizedby repeating layers ofinterbedded sand and mud. Stacked storage takes advantage ofthese repeating sequences in the geologic section to build storage capacityvertically (See illustrations below). Utilizing multiple layers for storage is advantageous because instead ofcreating a large plume, COz volumes can be managed --along with formation pressures-- by spreading outthe COzverticallyin the geologic section. Adyantages ofStacked Storage: stacked storage, when used in combinationwith EOR, would allow for commercial volumes ofCOz to be storedby the same existing facilities that arebeing used to produce tertiaryoil by EOR. EOR combined with stacked storage therefore takes advantage ofexistingpipeline 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 onlyin oilfields butin the formations associated with oilfields at a lesser capital cost.

Clean Air Task Force 22-Aug-13 3

### Illustrations above-- Left: Illustration of stackedsaline storage lj

### Pashin). Right: Illustration of layered oil, gas andsaline formations (and intervening caprockin white] atthe SECARB Frio project, TX thatcould be accessed in stackedstorage. 

### IV. Updates onNorth American Commercial C02 Storage Projects 1. 

### DOE Regional Carbon Sequestration Partnership Updates SECARB/Southern Co. Plant Barry-Cintmnelle. COz is captured at Plant Barrywith Mitsubishi Heavy Industries amine technology and transported 12 miles bypipeline to Denbury Resources' Cintronelle oilfield. The plantbegan capturing COz in the 4th quarter of2011 at a rate ofup to 650 ofnaturally occurring COz per day, amountingto a target ofapproximately 50,000 tons peryear. 12 

### Alabama Powerhas constructed a pipeline from Plant Barryto Denbury's nearby Cintronelle oilfield where injection ofthe captured COz into a saline unitin the PaluxyFormation began in 2012. Duringthis project, a consortium led byLBNL and EPRI have developed an innovative newmethod thatwill allowthe 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 ofsummer 2013. In March 2012 itwas reported that 1.5 Mt had been produced and recycled, summingto about 6 Mt injected. The projecthas beenthe site of numerous monitoring efforts and experiments thathave substantially improved scientists' understanding ofwhatis needed to ensure secure geologic storage ofCOz. Big Sky Partnership. Kevin Dome, MT.1 3 14 

### Injection of 1 Mt ofCOz into a northern Montana saline aquifer is planned to begin in 2015 and continue through 2018 to demonstrate the viability ofKevin Dome as a securetarget for regional COz emissions. Kevin Dome is a geologic structurewith naturallyoccurring COz thathas beentrapped for SO Ma, thatpromises the ability to hold commercial volumes ofcaptured COz. In the test, COz will beproducedfrom the dome, thentransported 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 TaskForce 22-Aug-13 4

### MGSC PartnershipIllinois Basin Decatur Project: Asuccessful 7,000 foot deep saline injection testis underway in Decatur IL, including a comprehensive monitoringprogram.ltis a cooperative project oftheArcher Daniels Midland (ADM), The Midwest Geological Sequestration Consortium (MGSC) and Schlumbergerwith $4.4 million ofDOE support. 15 During the 3-yearinjection program, 1.1 million tons ofC02 will be captured atADM's ethanol plant usingAlstom's amine captureprocess and will be injected into the Cambrian Mt. Simon Formation. Asecond well is planned which will bringthe total to approximately 1 million tons peryear. Monitoringtools utilized atthe site include four shallow groundwaterwells and soil gas measurements, 3-D seismic profiling, a dedicated monitoringwell with embedded geophones for walk-awayvertical seismic profiling (VSP) and a dedicated in-zone monitoring well. The success ofthis projectunderscores the availability ofcommercial scale saline geologic sequestration in the Mt. Simon Formation under the Midwest United States, a locus ofcoalbased electric powergeneration. The projecthas injected 0.5 Mt ofcaptured C02 as ofJune 2013.1 6 

### PCOR Regional Partnership. Bell Creek. WY: Beginning Spring 2013, 1 million tons ofC02. sourced from the Lost Cabin natural gas separation plant, is beinginjected for EORY Costeffective monitoring protocols will bethe focus ofthis study. MRCSP PartnershipNorthern Lower Michigan PIQj_ect: 1 Mt ofC02 captured at a Antrim Shale natural gas separation facility is beinginjected over a 4 year period into several small oil fields in Niagran Pinnacle Reefcarbonateformations for thepurposes ofEOR and storage and accompanying monitoring development.1s 19 

### 2. OtherNorthAmerican Projects 

### Pakota Gasification/Weyburn. Saskatchewan, Canada: Weyburn-Midaleoil field is an EORstorage projectlocated 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 ofthe field, approximately 44 Mt will be injected atWeyburn, 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 methodsfor ensuring C02

### injected for EOR is securely stored. In 2011 itwas alleged that COz from the projectwas leaking atthe surface at Kerr Farm. Subsequentindependent, peer-reviewed analysis bythe University ofTexas suggests, however, thatthe methane in the soils atthe farm are ofbiologic and notgeologic origin.21 Aquistore/Boundary Dam. Saskatchewan Canada: This SaskPower projectwill add postcombustion captureto a 110 MW EGU (Unit 3 atBoundary Dam Power Station) and will capture 90% ofthe COz, approximately 1 million tons peryear.22 23 SaskPowerreceived approvalfrom the Saskatchewan Governmentto build the project in April 2011 and construction is underway. Operation ofthe plantwill begin in 2014. COz capture from Boundary Dam will beinjected at the SasketchewanAquistore facility and attheWeyburn EOR project. The IEAGHG's Aquistore Program, a collaborative industryand governmentprogram, is being operatedby Canada's nonprofit Petroleum TechnologyResearch Centre (PTRC).24 

### Aquistore is a 3-kilometer deep 100 meter thick Cambro-Ordovician age saline sandstonereservoir located in theWilliston Basin in Saskatchewan, Canada.25 Aquistore is setto be drilled in 2013 and will also accept COzfrom a nearbyrefinery atthe end of2013. Captured COz from the SaskPower Boundary Dam project Clean Air Task Force 22-Aug-13 

### 5

### two kilometers awaywhereitwill mostlikely become the largest commercial and fully integrated carbon dioxide capture and storage facility in the world. Fort Nelson BC: APCORpartnership planned saline testand MVA strategy developmenteffort will injectl-2.2 Mt/yr COz from the FortNelson natural gas processingplantin British Columbia. When completedthis could be the largest deep salinetestin North America.26 

### Shell Quest. Alberta: Questwill capture 35

### o/o ofthe COz emissions, 1 Mt/y, from the Scotford upgrader (Alberta oil sands) near Fort Saskatchewan,Alberta, will beinjected into a saline aquifer into the Basal Cambrian Sands startingin 2015. 27 

### References.

1 See USGS at: http:jjpuivsJtsgs.govjdsj774( 2 DOE, The National Carbon StorageAtlas (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 storageinthe Midwestbypipeline. or in the offshore outercontinental shelf(OCS) along Georges Bank as was suggestedby an abandoned CCS projectthatwould have stored its C02 in the Mississauga Formation 70 miles offofthe coastofNewjersey. 4 Meckel. etaL. Offshore CCS in theNorthern Gulf of

Mexico andSouthAtlantic, Poster, Regional Carbon Sequestration Partnership Meeting Pittsburgh (September 2011). attached as Exh. Ill·89. 5http:

## J jwww.netLdoe.gov/publications/proceedings/11

## J carbon_storage/tuesdayj11_1115_Meckel_D0E_Review

_ mtg_offshore_compress.pdf 6 http:jjwww.aapg.org/explorer/2010J09sep/co2storage0910.cfm 7See: h tt_p_:_/jVV-':YYY,co2_QJnfe_r_q1ce.JW

__tj Vv'**lX~:_c_o** ntqrg_/up_lq**~l** __ ds/_2_(1) _3/ Q_5_/_Fox**-~**__ Kl\'J Prq0_t:_1_1tat_i__Q

__ 

## n-SA_(_B0 C.pc_l_f 8 Vella Kuuskraa, Advanced Resources International. Inc. (2012). Usingthe Economic value ofC02·EORto accelerate the deployment ofC02 capture, utilization and storage. (CCUS, EPRI CostWorkshop, Palo Alto, CA, April 25-26, 2012. 9 Meckel, etaL, Offshore CCS in the Northern Gulf of

Mexico andSouth Atlantic, Poster, Regional Carbon Sequestration Partnership Meeting Pittsburgh (September 2011), attached as Exh. Ill-89. 1Dhttp:

### J jwww.netl.doe.gov/publications

### J proceedings

### J 11

### J carbon_storage/tuesday/11_1115_Meckel_DOE_Review _mtg_offshore_compress.pdf 11 http:/jwww.aapg.orgjexplorerj2010/09sepjco2storage0910.cfm 1' Koperna, etaL, The SECARB anthropogenic test: the first U.S. integrated C02 capture, transportation andstorage 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:**jj_,c;

__ e_qu**(~5_t_rati_Qn_n** 1itg;i_u**/t(~_p_l_** s

### J p_rgjcct::;/J£_ev i**11__~]__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** __sjp,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: _[1ttp_:_//21_Q

_ 

### _.J0 9

### .?J_Q. 10_2_/ys c**_nl~l_t.a /_F_r_qscrl_t<_~_ti** **on~** j__lYIR**e__:~l~_%J2**Q_}?_Qstcr_(;_H G T_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 of Gas Chemistry atthe 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,ver·.con1j su:.;tainablc__gnJ\.Yth/_<1Ssets/**cl_ean_co~l** 

## t inf()pnatiq_n_shect.pdf Attached as Exh. III65. 24 For more information on Aquistore, see: Fvv'yvw._i[p_qne_rgi_esn_o_qye!l**c_~_:;_,_I_.'O**m

__cy(1

_ _2.Fcn

__ J_}_tent1 :!\1_?.F dq_w_nl o<1(_FXJ2F_(i_7_983')h_2F14:7J_837__%}**Ffi_h~%** 2

### F2.

__§_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\,gQv/_t_c_c_hno_l_qg_(e:;/_c_<ll-_b_(_)**JL~:c_q/_f** r_1__fr2l_S_tg1 {:tllTt?

### lrc5}2/_p_co_r_J_1tml 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_lsgjtt_p;)Jrcatp/<Ji**1~ s_~lDd**  5_/_q_y_es

_ _t_._h_t_p_1I 

### CleanAir 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 oftons of capacity

### 8**·~· ll~'W** **·~·**



# -**~·**

D 150 fiOO 75G 1,000KUlMEfEAS
0 250 500MilES B"ia ""'l'imrnJaM8 al!d**olhe~SI2008)** CGVIR-Consortium 1mSpariallnfo!mation SRTM9fulDataba•a 

# @ TASK FORCE 

# USGS (2013): Estimated Storage 

# =3,000 Gt

.w 

# ...

Alaska Pacific Northwest l\4 Gt) California

## I270Gtl·~· · .. 9%

. ·. 

# I ISO Gtl Western 3% Mid-Continent (150 Gt)

5% Eastern Mesozoic Rift Basins IOMGtl

<1%
Rocky Mountains

and Northern GreatPlains

1110Gtl 

# \ 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 unlikelyto have significant**storag~;~Jesources.** Regions and study areas are plotted over a shaded·reliel image showing higher elevations in brown end ten and lowerelevations 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.usIntroduction
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 EmissionTarget·· 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

2power 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 Basisfor 

### Our CCS Cost Estimates

A number of organizations, including the US DOE, MIT, EPRI, and others, have developed estimates ofthe cost of building new coal power plants with CCS. Of all ofthese the US DOE estimates
-- which are produced under contract to the National Energy Technology Laboratory (NETL) by engineering firms using 'bottom-up' estimates ofthe 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



### 3Several 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 Methodologyfor DerivingIncremental Costs Dueto 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



### 4the 'internal rate of return' ofthe 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.


### OurAssumptionsAboutCoal PowerProjectDesign MeetingEPA'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 ofthe 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



### 6system, 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 ofthis 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

7v 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 overthe 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 ofCCS on Cost ofElectrldtyfor Coal (Greenfield) $150 

## or-------------------·------------'-----­**~**
.:**~** 

## l$10<> -!-·-···-··················

$1$ 

# +-------

Conclusions and FurtherAnalysis
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



### 8optimized 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.

9Notes

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 1cost 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 ofoperation, 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 atTable 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 ofthe 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 ofJanuary 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


### 10values 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 Developments 11

, 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