Toward Market Launch of Coal/Biomass Coproduction Technologies with CCS

By Robert H.Williams
Senior Research Scientist, Princeton Environmental Institute,
Princeton University

Article Background

This is the second installment of a two-part article prepared for Cornerstone discussing how   coal/biomass coprocessing technologies for making synthetic fuels and electricity with carbon capture and storage (CCS) can enable continuing major roles for coal in a carbon-constrained world. The first installment1 presented a long-term vision highlighting the merits of the strategy. This second installment focuses on establishing the key technologies in the market in the near term (next 10–15 years). The acronyms used in this article are defined in Table 1.

Coal/Biomass conversion

Carbon flows for conversion of coal and biomass into synthetic liquid fuels and electricity with CCS.
The “cradle-to-grave” GHG emission rate for a system like that shown depends on the biomass input percentage. For the CBTL-OTA-5%-CCS system (see Table 2B and Figure 1) for which sustainably grown biomass accounts for 5% of input feedstocks, the net fuel-cycle-wide GHG emissions associated with production and consumption of liquid fuels and electricity is half of the GHG emission rate for the conventional fossil fuels displaced.


The first installment of this article showed that (a) the profitable production of low-carbon transportation fuels (hitherto an elusive goal) is feasible under a carbon mitigation policy by coprocessing some non-food biomass with coal in systems that involve pre-combustion capture of CO2 and its storage underground; (b) for specified carbon footprint and biomass input rate, it is more profitable to generate electricity as a major coproduct than to make only liquid fuels; and (c) in an era of high oil prices, such coproduction systems are more profitable than coal electricity-only plants that have the same carbon footprint.1

Market Launch Table 1

Table 1. Acronym definitions

However, before the coal/biomass coproduction with CCS concept can be regarded as a major option for coal’s future in a carbon-constrained world, the technology must be demonstrated at commercial scale and costs must be reduced to levels at which  the technologies can compete without subsidy.

The strategic importance of these objectives was recognized by the National Coal Council (NCC) in its 2012 report to U.S. Department of Energy Secretary Steven Chu.2 Two major recommendations from the report were that the U.S. coal industry and the Energy Secretary work together to find ways whereby: (a) early-mover coal-based CO2 capture projects linked to CO2 enhanced oil recovery (CO2 EOR) could be financed and built to enable technology cost reductions via experience (i.e., learning by doing) and (b) a coal/biomass coproduction plant with captured CO2 used for EOR be financed, built, and demonstrated at commercial scale. This article suggests how both of these NCC report recommendations might be implemented in the near term in the absence of a carbon mitigation policy.

EOR for Early-Move CCS Projects

Storing CO2 via CO2 EOR is an important option for helping launch CO2 capture technologies in the market in the absence of a price on GHG emissions, because the CO2 provider is paid for captured CO2.  CO2 EOR is a well-established technology in the U.S., where there are 6600 km of CO2 pipelines serving 127 EOR projects; in 2012, CO2 EOR provided 6% of U.S. crude oil production: 280,000 barrels/day (bbls/d) (13.8 million tonnes/year). Most CO2 for EOR comes from natural sources; U.S. crude oil production via EOR could be greatly expanded by supplementing natural CO2 with anthropogenic CO2, the largest potential supplies of which are coal energy systems from which CO2 is captured.

Drawing in part on assessments of U.S. CO2 EOR prospects (e.g., U.S. DOE NETL3), the National Coal Council reached the judgment that it is feasible to increase U.S. crude oil production via CO2 EOR by 2035 to 3.6 million bbls/d (177 million tonnes/year) using captured CO2 from coal energy systems, while storing annually over 400 million tonnes of anthropogenic CO2 in mature oil fields from which the extra crude is extracted.2 This is enough to support a large number of early-mover CCS projects, each of which will typically provide 1–5 million tonnes of CO2 annually.

The NCC report found that in the absence of a price on GHG emissions, once CO2 capture technologies are commercially established: (a) coal power plants retrofitted with CO2 capture equipment could provide CO2 profitably for EOR if sited near CO2 EOR opportunities, and (b) new synthetic fuels plants and plants coproducing electricity and synthetic fuels, even if remote from CO2 EOR opportunities, are likely to be profitable in CO2 EOR applications if an adequate CO2 pipeline infrastructure is in place.

That is the good news. The bad news from this report is that first- of-a-kind (FOAK) and subsequent early-mover projects will not be able to provide CO2 for EOR applications profitably without subsidy in the absence of a price on GHG emissions, because such projects will be very costly. Early-mover projects are typically more costly than commercially established [Nth-of-a-kind (NOAK)] projects for various reasons.  An engineering, procurement, and construction (EPC) firm building a novel plant may add spare capacity for some components to promote integrated system reliability. For pieces of equipment with which there is little experience, an EPC firm will estimate costs with higher-than-normal process contingency factors (which are added to reflect costs that cannot be fully accounted for). Moreover, for novel plant configurations, project contingency factors will tend to be higher than normal even if all components are commercially established. And for such novel plant configurations, equipment layout may be suboptimal, requiring more investment for linking processes.

The High-Cost Challenge Posed by Early-Mover CCS Projects

In the absence of carbon mitigation policy, the subsidies required for early-mover CCS project are huge (e.g., the subsidy required for a single FOAK CCS project is likely to comparable to the total applied energy R&D budget of the U.S. Department of Energy), so that supporting, via conventional government funding mechanisms, a series of such projects in efforts to “buy-down” technology costs through experience (learning by doing) is beyond the reach of most, if not all, governments. These high early-mover subsidy costs have slowed progress in establishing CCS as a major carbon-mitigation option.  For perspective, in 2009 the International Energy Agency (IEA) set out a road map4 calling for building 100 CCS projects by 2020, together capturing ~150 million tonnes of CO2 annually as needed, to be on track for realizing ~50% reduction in global CO2 emissions for energy by mid-century.5 At present, however, the prospects are that, at best, 20 projects will be completed by 2020.6

Proposed CO2 Capture Technology Cost Buydown Strategy

Because the CO2 EOR opportunity alone cannot provide adequate incentives for launching coal/biomass coproduction and other capture technologies in the market, going forward with CCS technologies in the absence of a strong carbon mitigation policy requires additional incentives that are affordable even by fiscally constrained governments.

In the U.S., sponsors of the National Enhanced Oil Recovery Initiative (NEORI) have proposed a competitively bid tax credit to help “buy down” the cost from FOAK to NOAK levels for plants that capture CO2 and make it available for CO2 EOR applications.7 The NEORI sponsors propose that this tax credit be financed via new federal corporate income tax revenue streams from EOR-produced oil that would replace otherwise imported crude oil. The basic idea is that, as a result of learning by doing, the required tax credits would decline with experience to levels below the levels of these new federal tax revenue streams, so that this strategy would provide new revenues to the federal government that could help “buy down the federal deficit” at the same time that the proposed subsidy would help “buy down the cost” of CO2 capture technologies.

Here a variant of the NEORI buy-down proposal developed by the author8 is summarized. It involves providing subsidies in the form of competitively bid grants (rather than tax credits, so that the subsidy magnitude is not limited by tax liability) that are proportional to the amount of captured CO2 made available for EOR. The grants would be financed to the extent feasible with new federal revenues arising from these projects in the forms of corporate income taxes from synfuels production (for CO2 capture technologies that provide synthetic fuels), corporate income taxes from crude oil production via CO2 EOR, and royalties from crude oil produced via CO2 EOR on federal lands. Revenues needed to finance the subsidies in excess of what can be provided by these new federal revenue streams would be paid for out of general federal funds (GFF).

IRRE Screening Analysis

Market Launch Table 2A

Table 2A. Candidate power-only options for technology cost buydown
aBased on US DOE NETL.9
bBased on NCC.2
cGHGI (the greenhouse gas emissions index) is defined as the ratio of the “cradle-to-grave” GHG emissions for the system to the emissions for the conventional fossil energy displaced. The latter are assumed to be electricity from new supercritical coal plants venting CO2 (Sup PC-V) and the equivalent of crude oil-derived products.

The first step in the CO2 capture cost buydown analysis is to identify the capture technologies that, after buydown, are likely to be profitable in CO2 EOR applications without subsidy or a price on GHG emissions. To this end, internal rate of return on equity (IRRE) analyses were carried out for four electricity systems and two systems coproducing electricity and Fischer-Tropsch liquid synthetic fuels (diesel and gasoline). The candidate electricity-only systems (see Table 2A) are (a) a new supercritical coal plant with post-combustion (amine scrubber) CO2 capture (Sup PC-CCS); (b) a new coal integrated gasification combined cycle plant with pre- combustion capture (IGCC-CCS); (c) a subcritical coal plant retrofitted with an amine scrubber (PC-CCS retrofit); and (d) a natural gas combined cycle plant with an amine scrubber (NGCC- CCS). The candidate coproduction options (see Table 2B) make electricity as a major coproduct (accounting for 28–32% of total energy output) of manufacturing Fischer–Tropsch liquid transportation fuels. One option is CTL-OT-CCS, a coal-only system with mild CO2 capture option for which GHGI = 0.70. The other is CBTL-OTA-5%-CCS, a coal/biomass system with “aggressive” CO2 capture that coprocesses enough biomass (5% on an energy basis) to realize a 50% reduction in GHG emissions (GHGI = 0.50). Figure 1 shows how a 50% reduction in GHG emissions can be realized for transportation fuels with only 5% biomass.

Market Launch Figure 1

Figure 1. Carbon balances and GHG emissions for Fischer-Tropsch liquid fuels from CBTL-OTA-5%-CCS (GHGI = 0.50)

  • 1st bar shows fuel-cycle-wide GHG emission rate for crude oil-derived diesel and gasoline displaced
  • 2nd and 3rd bars show carbon balance for plant (carbon output = carbon input)
  • 4th bar shows fuel-cycle-wide GHG emissions by component (+tive and –tive elements)
  • 5th bar shows net fuel-cycle-wide GHG emissions for Fischer-Tropsch liquid fuels
  • Credit for emissions from electricity {@0.50 * [841 kg CO2e/MWhe (rate for new Sup PC-V)]} = (0.106 MWhe/GJ FTL)*(420 kg CO2e/MWhe) = 44.0 kg CO2e or 12.0 kg Ce per GJ of Fischer–Tropsch liquid fuels.

The coproduction options considered as power generators would satisfy the U.S. Environmental Protection Agency’s proposed New Source Performance Standard for CO2 emissions from new power plants (the EPA has proposed a limit of 1000 lbs CO2/gross MWhe for new plants): Allocating all CO2 emissions from the coproduction plant to gross power, the emission rates would be 609 lb/MWhe for CTL-OT-CCS and 265 lb/MWhe for CBTL-OTA-5%-CCS (see Table 2B).

Market Launch Table 2B

Table 2B. Candidate coproduction options for technology cost buydown
*Based on Liu et al.10

The IRRE analysis is carried out as a function of the crude oil price, assuming the average Permian Basin CO2 price during 2008–2010 [in $/t = 0.444 × (crude oil price, in $/bbl); see Wehner11] and a CO2 transport cost of $10/t (nearby CO2 EOR opportunity).

The results of the NOAK IRRE screening analysis are presented in Figure 2, which shows IRRE values as a function of crude oil price when the GHG emissions price is $0/t CO2e. This analysis shows that the coproduction options and pulverized coal plants with CCS retrofit (PC-CCS retrofit) should be considered as serious candidates for technology cost buydown because an IRRE rate of 10%/year (a minimally acceptable level of profitability for many investors) is realizable for these options at plausible future crude oil prices. But, notably, none of the new power-only plants with CCS clear this IRRE “hurdle rate” at any of the crude oil prices considered, so these options are not considered further here.

Market Launch Figure 2

Figure 2. IRRE vs. crude oil for NOAK plants listed in Tables 2A and 2B (for plants selling CO2 into EOR markets in the absence of a price on GHG emissions)

Technology Cost Buydown Analysis

The technology cost buydown analysis aims to estimate the subsidies required for early-mover projects and provide a perspective on the benefits as well as the costs of providing subsidies for the screened technologies. For this exercise, FOAK costs are estimated by “back-casting” from NOAK cost estimates in Tables 2A and 2B. Key assumptions in addition to those for the IRRE screening analysis are:

  • FOAK costs [for capital and operation and maintenance (O&M)] are 2.0 × NOAK costs, which is consistent with Duke Energy’s experience with its Edwardsport IGCC-V plant being built in Indiana;
  • The learning rate for capital and O&M costs is the same as the historical learning rate for SO2 scrubbers12, some 11% for each cumulative doubling of output—which means that those costs for the second plant are 11% less than for the first, those costs for the fourth plant are 11% less than for the second, those costs for the eighth plant are 11% less than those for the 4th, etc.;
  • The subsidy provided over the 20-year economic life of the plant is sufficient to reduce the levelized cost of electricity to that for a natural gas combined cycle power plant that vents CO2;
  • Subsidies are financed to the extent feasible from new federal revenue streams from new domestic liquid fuel production; the shortfall is provided by general federal funds (GFF); and
  • The crude oil price is $90/bbl.

Figure 3 shows, for the three screened options, the required subsidy versus the number of the plants built. [The required subsidies decline at different rates because the fraction of the levelized cost of electricity amenable to learning by doing (capital + O&M costs) varies from technology to technology.] For CTL-OT-CCS, the required subsidy is reduced through learning by doing to zero after only 13 plants have been built. The zero subsidy point is reached for the 25th plant with CBTL-OTA-5%-CCS and for the 133rd plant with PC-CCS retrofit. Figure 3 also shows that for all three plants the GFF contribution to the subsidy is zero for the third plant.

Market Launch Figure 3

Figure 3. Total subsidy and GFF contribution for technology cost buydown for $90/bbl crude oil in the absence of a price on GHG emissions

Table 3 presents total subsidy requirements together with net new government tax/royalty revenues associated with the liquid fuels production arising from deployment of these plants. The subsidies for the very first plants are huge ($1.6 to $3.1 billion), and the average subsidies for the first 13 plants are also large (~$1 billion per plant). Nevertheless, these technology cost buydown investments are profitable for the government. By the time the fourth to sixth plant is built, the government is generating net new federal revenues arising from taxes and royalties associated with new domestic liquid fuels production. The average net new federal revenues per plant for the first 13 plants amount to $0.95 billion, $0.60 billion, and $0.33 billion for CTL-OT-CCS, CBTL-OTA-5%-CCS, and PC-CCS retrofit, respectively.

Table 3. Buydown subsidies and net new federal revenues for technologies selected for buydown

Table 3. Buydown subsidies and net new federal revenues for technologies selected for buydown

Subsidy requirements would be less at higher crude oil prices. For example, at $115/bbl: (a) the first CTL-OT-CCS plant would require a $2.1 billion subsidy, (b) only the first five plants would require subsidies (at an average rate of $0.82 billion per plant), (c) net new government revenues would average

$1.8 billion per plant for these first five plants, and (d) net new government revenues would be positive ($0.77 billion) for the very first plant.

Technology Readiness

The buydown analysis suggests favorable economic prospects for launching, in the near term, coproduction technologies coprocessing a modest amount of biomass with coal and using captured CO2 for EOR. In addition, all technological components required for a FOAK plant are ready to be demonstrated at commercial scale—especially if a demonstration project were to involve cogasification of a low-rank coal and biomass (the CBTL-OTA-5%-CCS system described in Table 2B is for bituminous coal and biomass gasified in separate gasifiers), as illustrated by recent Southern Company experience.

Southern Company (an energy company serving the Southeast United States through its subsidiaries) has developed (with long-term U.S. DOE support) the transport gasifier that is well suited for cogasification of biomass with low-rank coals (e.g., lignite or subbituminous coal). Already this gasifier is being deployed in a 580 MWe lignite-fired U.S. DOE-supported commercial-scale demonstration project (Kemper County, Mississippi, IGCC-CCS project) that will use captured CO2 for enhanced oil recovery (EOR). The National Carbon Capture Center at the Power Systems Development Facility in Wilsonville, Alabama, has carried out tests on the cogasification of up to 30% biomass with low-rank coals utilizing pure oxygen as the oxidant (to provide syngas quality necessary for synthetic fuels manufacture) at a test-scale version of the transport gasifier, and such percentages were found to pose no adverse impact to gasification system operations.13

Southern also has experience with biomass supply logistics at supply levels higher than are needed for a demonstration project—evolving in large part from experience with its 100 MWe waste wood-fired Nacogdoches power plant in Texas, which consumes annually about 1 million short tons of wood [as- received (wet) basis]. Assuming that the as-received wood has a 50% moisture content, this implies that the Nacogdoches plant already consumes dry biomass at a rate that is about 2.3 times the rate for the CBTL-OTA-5%-CCS system described in Table 2B.


Success with the proposed course of action for early-mover coal/biomass coprocessing systems that coproduce electricity and liquid fuels could (a) help get the global CCS enterprise back on track;6,14 (b) undermine the conventional wisdom that addressing climate change and seeking domestic energy independence often represent contradictory goals;15 and (c) provide a technological platform that would enable the coal industry to thrive in a carbon-constrained world.1



The author is grateful for fruitful discussions with the late Jim Katzer in developing several of the concepts presented here. For financial support, the author thanks The Edgerton Foundation and the BP-supported Carbon Mitigation Initiative at Princeton University.



  1. R.H. Williams, Coal/biomass coprocessing strategy to enable a thriving coal industry in a carbon-constrained world, Cornerstone, 2013a, 1 (1), 51–59.
  2. National Coal Council, Harnessing Coal’s Carbon Content to Advance the Economy, Environment, and Energy Security, 2012: Washington, DC, 22 June.
  3. U.S. DOE National Energy Technology Laboratory, Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR), 2011: DOE/NETL-2011/1504 Activity 04001.420.02.03, June.
  4. International  Energy  Agency,  Technology  Roadmap:  Carbon Capture and Storage, 2009: Paris, OECD/IEA.
  5. International Energy Agency, Energy Technology Perspectives 2012: Pathways to a Clean Energy System, 2012: Paris, International Energy Agency,
  6. R. Van Noorden, Europe’s Untamed Carbon, Nature, 2013, 493, 141–142, 10 January.
  7. National Enhanced Oil Recovery Initiative, Carbon Dioxide Enhanced Oil Recovery: A Critical Domestic Energy, Economic, and Environmental Opportunity, 2012. Report sponsored by the Center for Climate and Energy Solutions and the Great Plains Institute, February.
  8. R. Williams, Market Launch Strategy for Low-Carbon, Low Air- Polluting, Secure Energy from Coal: 2013b, Review draft.
  9. U.S. DOE National Energy Technology Laboratory, Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2, 2010: DOE/NETL-2010/1397, November.
  10. G. Liu, E.D. Larson, R.H. Williams, T.G. Kreutz, X. Guo, Making Fischer–Tropsch Fuels and Electricity from Coal and Biomass: Performance and Cost Analysis, Energy and Fuels, 2011, 25 (1), 415–437.
  11. S. Wehner (Chapparal Energy), U.S. CO2 and CO2 EOR Developments, 9th Annual CO2 EOR and Carbon Management Workshop, Houston, 5–6 December 2011.
  12. E.S. Rubin, M.R. Taylor, S. Yeh, D.A. Hounshell, Learning Curves for Environmental Technology and Their Importance for Climate Policy Analysis, Energy, 2004, 29, 1551–1559.
  13. J. Northington (Southern Company Services, National Carbon Capture Center, Wilsonville, Alabama), Private communication, 22 May 2013.
  14. V. Scott, S. Gilfillan, N. Markusson, H. Chalmers, R.S. Haszeldine: Last Chance for Carbon Capture and Storage, Nature Climate Change, 2013, 3 (2), 105–111.
  15. J.M. Broder, M.L. Wald, Cabinet Picks Could Take on Climate Policy, New York Times, 4 March 2013.


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The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

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