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Carbon Capture and Storage


  • [ GWh of Electricity Added: ]

    32,300
  • [ Jobs Impact: ]

    • Low
    • Medium
    • High
  • [ Budget Impact: ]

    • Low
    • Medium
    • High
  • [ Conventional Pollutants Reduced: ]

    SO2
    5420 tons
    NOx
    -3506 tons
    Hg
    -.651 tons
    PM
    -.057 tons
  • [ Megatons of GHG Reduced: ]

    39.6

Overview

Carbon capture and storage (CCS) traps carbon dioxide from fossil fuel power plants or industrial plants and then transports captured carbon dioxide by pipeline to underground storage. Recent regulatory developments have brought attention to this emerging technology. Future legal challenges notwithstanding,1 EPA’s 2013 New Source Performance Standards (NSPS)2 will encourage new coal plants to adopt CCS technology. Adopting CCS lets the U.S. continue to take advantage of its domestic coal and natural gas resources, keeps more fossil fuel power plants open, and reduces greenhouse gas emissions. But smoothing the regulatory road and making the necessary investments to get there remain major challenges.


Analysis

In 2011, the U.S. had eight large power plant CCS projects in the works. Three years later, only five continue towards operation,3 due to high and rising construction costs, an unclear ability to recover operating costs, the uncertain regulatory future, and the lack of a national energy plan.4

It is more expensive both to build and operate a CCS plant than an ordinary coal power plant. The very first CCS power projects are designed for coal plants. Analysts estimate a large, new conventional coal power plant costs $ 2.2 billion,5 while an equivalent CCS coal power plant costs 60-80% more.6 In addition, because a CCS plant captures emitted CO2, it is more expensive to operate.7 CCS proponents believe exploiting potential CO2 revenue streams could reduce the added cost to 10-20% for plants that capture half of emitted CO2.8 Future experience constructing CCS plants will lower costs,9 while ongoing R&D efforts may yield cheaper carbon dioxide capture techniques.10

Enhanced oil recovery (EOR) is a mature technology that offers CCS plants an ability to recover operating costs.11 Instead of directing CO2 straight into underground storage, oil field operators buy CO2 and pump it underground into an oil field to increase production. This additional revenue stream lowers the cost gap between CCS and ordinary fossil fuel power. However, 80% of EOR CO2 currently comes mined from natural sources.12 In addition, the market value of mined CO2 is currently far lower than the cost for a power plant to capture CO2. Nevertheless, there is proven potential both to store large amounts of carbon emissions and recover a significant amount of oil with the captured carbon.

The EOR industry has injected CO2 into oil wells for decades using a Safe Drinking Water Act permitting program.13 Now, federal and state governments are beginning to set up legal frameworks specific to carbon storage, but unresolved issues remain.14 Although new permitting processes commonly experience delays, the operator of the first project to file under the new CO2-specific rule is still waiting for an injection permit, more than 30 months after applying.15 Moreover, federal rules assign indefinite liability for eventual CO2 leakage to the project operator.16 Because companies may not exist for hundreds of years, this will be impractical in the long term.

Moreover, because most plants are not and would not be built on or near underground storage facilities, they would need a build-out of CO2 pipeline transportation networks. The U.S. has 4,000 miles of CO2 pipelines, built to carry mined CO2 to oil fields for EOR. These run mainly from the Rockies to Texas, as well as from Mississippi to Louisiana.17 Whether destined for storage alone or EOR operations, sequestered CO2 emissions from other regions will require hundreds, if not thousands, of miles of new pipelines, at significant cost.

Implementation

To continue developing CCS, the U.S. should focus on policies that enhance economic incentives to invest in capturing, using, and storing carbon dioxide.

Revise the Tax Credit for EOR Operations

Congress should amend the §45Q tax credit to make it easier and more attractive to use captured CO2 for EOR operations. The revised tax credit should achieve cost parity, making it as attractive for EOR operators to purchase CO2 from CCS projects as from natural wells.18 Modifications should improve transparency in credit registration and allocation, as well as make it easier to transfer credits. If these changes are made, modeling analysis shows this proposal will generate federal revenue over the course of a decade, as it enhances U.S. oil production.19

Start Permitting Federal Lands for Carbon Storage

 The Bureau of Land Management (BLM) should begin to pre-permit federal land for carbon storage. As a starting point, the United States Geological Survey recently identified suitable basins for storing carbon dioxide.20 Previously, BLM has issued programmatic environmental impact statements for wind, geothermal and solar energy, which have significantly streamlined the often time-consuming environmental reviews.21 Building upon this precedent, BLM can pave the way to expedite CO2 storage permitting by conducting comprehensive impact statement and guiding developers through applications for a few specific injection sites on its land. As a further incentive, BLM can allow these projects to inject CO2 without collecting royalties for a limited number of years.

Allow EOR Operations to Continue Current Injection Permitting Processes

EPA should clarify that EOR operations can continue permitting CO2 injection according to current practices that have been in place for decades. EPA recently directed some EOR projects to file for the new CO2-specific permit.22 As the possibility of having to re-permit wells may make oil field developers wary of buying captured CO2,23 new EPA regulations could stifle the emerging CCS-EOR industry. Similarly, while EPA has directed pilot projects to file for the new CO2-specific injection permits,24 the Agency should allow these to continue using experimental well class designations.

Create a Geologic Sequestration Trust Fund

Congress should create a carbon storage trust fund to provide backup financing for the 50 years after injection is finished but for which continual monitoring is still required. Small companies may have difficulty securing financial proof they can monitor a site or compensate damages for 50 years. While initial government funding would start the trust fund, private funding would replace this as more CCS companies pay into the trust. As a whole, the trust fund would allow Congress to foster more entrepreneurial ventures in CCS.

Make CO2 Capture Eligible for Master Limited Partnerships

As proposed by Sen. Coons, Congress should pass legislation that extends Master Limited Partnerships to CO2 capture and related electricity generation projects, which would open up cheaper and earlier financing options. Master Limited Partnerships are addressed in the PowerBook's Finance Component.

EndNotes
  1. Lyle Denniston, “Court to Rule on Greenhouse Gases,” SCOTUS blog, October 15, 2013, Accessed October 15, 2013. Available at: http://www.scotusblog.com/2013/10/court-to-rule-on-greenhouse-gases/
  2. United States, Environmental Protection Agency, “2013 Proposed Carbon Pollution Standard for New Power Plants,” September 20, 2014, Accessed March 13, 2014. Available at: http://www2.epa.gov/carbon-pollution-standards/2013-proposed-carbon-pollution-standard-new-power-plants
  3. The three withdrawn projects include: AEP Mountaineer Project in New Haven, WV; Southern Company Project in Mobile, AL; and Basin Electric Power Project in Buelah, ND. Three projects advancing with DOE CCS demonstration funding include Texas Clean Energy Project in Penwell, TX; NRG Energy Project in Thompsons, TX; and Hydrogen Energy California in Kern Country, CA. In addition, Futuregen in Meredosia, IL and the Kemper County plant in Mississippi continue as planned. See United States, Congressional Research Service, Peter Folger, “Carbon Capture and Sequestration: Research, Development, and Demonstration at the U.S. Department of Energy,” Report, pp. 10, 16, June 10, 2013, Accessed October 15, 2013. Available at:http://www.fas.org/sgp/crs/misc/R42496.pdf. See also Mississippi Power, “Kemper County Energy Facility.” Accessed March 17, 2014, Available at: http://www.mississippipower.com/kemper/home.asp.
  4. Folger, pp. 11-12.
  5. An NREL study estimates a new supercritical coal plant costs $ 2024 / kW in 2007 dollars. A large, 1 GW plant would cost $ 2.24 billion in 2012 dollars. See United States, Department of Energy, National Energy Technology Laboratory, “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity,” Report, Revision 2A, p. 10, September 2013, Accessed January 9, 2014. Available at: http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/OE/BitBase_FinRep_Rev2a-3_20130919_1.pdf; See also United States, Bureau of Labor Statistics, “Consumer Price Index,” Accessed January 9, 2014. Available at: http://www.bls.gov/cpi/.
  6. United States, Congressional Budget Office, “Federal Efforts to Reduce the Cost of Capturing and Storing Carbon Dioxide,” Report, p. 20, June 2012, Accessed October 20, 2013. Available at: http://www.cbo.gov/publication/43357.
  7. Generated electricity will come at a 70-80 % premium over average coal power plants. Ibid, p. 20.
  8. Mike Fowler et al., “How Much Does CCS Really Cost?” Clean Air Task Force, p. 2, December 20, 2012, Accessed October 10, 2013. Available at: http://www.catf.us/resources/whitepapers/files/20121220-How_Much_Does_CCS_Really_Cost.pdf
  9. Folger, pp. 10, 16
  10. Top contenders to lower costs of capture include cheaper production methods to deliver oxygen for oxyfuel combustion, molecular organic frameworks that function as molecular sieves, and catalyzed solvents. Source: Julio Friedmann, Interview by Ingrid Akerlind, Personal Interview, Third Way, December 3, 2013.
  11. United States, Department of Energy, National Energy Technology Laboratory, “Carbon Dioxide Enhanced Oil Recovery,” Report, p. 17, March 2010, Accessed December 26, 2013, Print.
  12. G. Moritis, “Special Report: EOR/Heavy Oil Survey: CO2 miscible, steam, dominate enhanced oil recovery processes,” Oil and Gas Journal, April 19, 2010, Accessed March 14, 2014. Available at: http://www.ogj.com/articles/print/volume-108/issue-14/technology/special-report-eor.html.
  13. EPA has permitted over 150,000 wells as Class II wells, of which 80% are related to EOR projects. See United States, Environmental Protection Agency, “Class II Wells – Oil and Gas Related Injection Wells (Class II),” May 9, 2012, Accessed March 17, 2014. Available at: http://water.epa.gov/type/groundwater/uic/class2/index.cfm.
  14. CO2 Capture Project, “Update of Selected Regulatory Issues for CO2 Capture and Geological Storage,” Report, pp. i-v, November 2010, Accessed November 20, 2013. Available at: http://unfccc.int/resource/docs/2011/smsn/ngo/275.pdf.
  15. Bob Van Vorhees, “Progress and Lessons from Implementing the US EPA Class VI Rule,” Presentation, 5th IEA International CCS Regulatory Network Meeting, Slide 9, June 18-19, 2013, Accessed December 20, 2013, Print.
  16. Although the EPA has recognized that leaving liability in the hands of the operator indefinitely is impractical, it lacks the authority to regulate long-term liability or transfer such ownership. See “Update of Selected Regulatory Issues for CO2 Capture and Geological Storage,” pp. 89-90.
  17. “Carbon Dioxide Enhanced Oil Recovery,” p. 10.
  18. The current credit provides just a $10 per ton tax credit to CO2 destined for EOR operations, but the market value of CO2 for EOR, at $10 to $35 per ton, is far lower than the cost of a power plant to capture CO2, at $100 to $150 per ton. See 26 USC Sec., 45Q, 2009, Accessed March 14, 2014. Available at: http://www.law.cornell.edu/uscode/text/26/45Q; See also National Enhanced Oil Recovery Initiative, “Carbon Dioxide Enhanced Oil Recovery: A Critical Domestic Energy, Economics and Environmental Opportunity,” Report, p. 24, February 2012, Accessed December 26, 2013. Available at: http://www.neori.org/NEORI_Report.pdf ; See also “Carbon Dioxide Enhanced Oil Recovery,” p. 17.; See also Mohammed Al-Juaied and Adam Whitmore, “Realistic Costs of Carbon Capture,” Discussion Paper, Belfer Center for Science and International Affairs, p. ii, 2009, Accessed March 17, 2014. Available at http://belfercenter.ksg.harvard.edu/files/2009_AlJuaied_Whitmore_Realistic_Costs_of_Carbon_Capture_web.pdf.
  19. National Enhanced Oil Recovery Initiative, “Recommended Modifications to the 45Q Tax Credit for Carbon Dioxide Sequestration,” Report, pp. 1-4, February 2012, Accessed December 26, 2013. Available at: http://neori.org/publications/neori-45q/.
  20. United States, Department of the Interior, United States Geological Survey, “National Assessment of Geologic Carbon Dioxide Storage Resources—Results,” Report, September 2013, Accessed November 18, 2013. Available at: http://pubs.usgs.gov/circ/1386/pdf/circular1386.pdf.
  21. BLM has issued programmatic environmental assessments for solar energy, wind energy, geothermal energy and transmission lines. See United States, Department of the Interior, Bureau of Land Management, “Renewable Energy Resources,” September 23, 2013, Accessed March 14, 2014. Available at: http://www.blm.gov/wo/st/en/prog/energy/renewable_energy.html.
  22. EPA finalized its new, CO2-specific Class VI rule for CO2 storage under the Safe Drinking Water Act in 2010. EPA recently released draft guidance requiring Class II wells to transition to Class VI wells if injecting CO2 becomes a primary purpose according to a determination by the EPA Underground Injection Control program manager. See United States, Environmental Protection Agency, Office of Water, “Draft Underground Injection Control (UIC) Program Guidance on Transitioning Class II Wells to Class VI Wells,” Report, pp. ii, 16 December 2013, Accessed December 30, 2013. Available at: http://water.epa.gov/type/groundwater/uic/class6/gsguidedoc.cfm.
  23. EOR wells fall under Class II requirements, while the new CO2-specific Class VI requirements are more onerous. Class VI places additional requirements on plugging wells, sets additional requirements for operating, monitoring, and keeping records, asks for additional information in the application, and requires a 50-year post-injection monitoring period. See “Draft Underground Injection Control (UIC) Program Guidance on Transitioning Class II Wells to Class VI Wells,” pp. A1 – A22.
  24. EPA has directed all pilot projects to apply for Class VI injection permits instead of experimental Class V permits. See Bob Van Vorhees, slides 5, 22.
  25. United States, Congress, Senate, “Master Limited Partnerships Parity Act,” 113th Congress, 1st Session, April 24, 2013, Accessed December 31, 2013. Available at: http://thomas.loc.gov/cgi-bin/query/z?c113:S.795.IS:/.