GHG Mitigation Technologies Workshop

Research Triangle Park, NC

November 3, 2009

FINAL REPORT

Submitted to:

National Center for Environmental Assessment

Office of Research and Development

U.S. Environmental Protection Agency

Submitted by:

Eastern Research Group, Inc.

1600 Perimeter Park

Morrisville NC 27560-8421

December 1, 2009
i

Notice

This report was prepared by Eastern Research Group, Inc., a contractor for the U.S. 

Environmental Protection Agency, as a general record of discussion during a workshop, 

sponsored by EPA’s Office of Research & Development (ORD) and held November 3, 2009, in 

Research Triangle Park, North Carolina. Although this report attempts to capture everything said 

during the workshop, it is not a complete record of all details discussed, nor does it embellish, 

interpret, or expand on matters that were incomplete or unclear. Statements represent the views 

of workshop participants.
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TABLE OF CONTENTS

Section Page

Introduction and Discussion of Workshop Agenda and Objectives................................................1

Welcome ..........................................................................................................................................2

Session 1 Topic: Discussion and identification of available technologies, strategies and options 

for GHG mitigation from EGUs..........................................................................................2

Session 2 Topic: Discussion of cost, performance and availability of various technologies, 

strategies and options...........................................................................................................8

Session 3: Theresa Pugh presentation, titled: ―Technical and Non-technical Challenges of 

Sequestration‖ ....................................................................................................................14

Session 3 Topic: Discussion of barriers (technical and non-technical) to implementation of the 

various technologies, strategies and options......................................................................15

Session 4 Topic: Identification of promising (but still early stage) technologies, wrap-up, and 

summary of workshop........................................................................................................19

Appendix A – Attendees List

Appendix B – Workshop Agenda

Appendix C – Technical Presentation and Supporting White Papers

Technical and Non-technical Challenges of Sequestration Presentation 

Geologic CO2 Sequestration Issue Spotting and Analysis 

Will Water Issues/Regulatory Capacity Allow or Prevent Geologic Sequestration for New 

Power Plants? 
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Welcome:

INTRODUCTION AND DISCUSSION OF WORKSHOP AGENDA AND OBJECTIVES

Nick Hutson introduced the workshop stating that one of the primary reasons for this workshop 

is to discuss the development of a comprehensive GHG mitigation technologies (and strategies) 

database that includes retrofit and new build technologies for the power sector, transportation 

sector and other industrial sectors (e.g., pulp and paper, cement, etc.).

Dr. Hutson identified some fields that should be identified in the database:

o Stage of development of each technology

o Barriers to implementing technologies

o Legitimate costs

o Impacts associated with those tech’s (water consumption, parasitic load)

Dr. Hutson then posed the following questions as topics for discussion throughout the workshop:

o What are currently available GHG mitigation technologies for power sector?

o What are the leading candidates not yet demonstrated?

o What are the realistic investment and schedule for commercial application?

o What is the definition of CCS-Ready?

o What are the possible regulatory frameworks to enable CCS-ready investments?

o What does EPA consider to be the pathway of tech development leading to a technology 

becoming fully commercial (and we have to define what it means to be fully 

commercial)?

o What are the near-term control options for industry? 

o Discuss any mercury control issues or requirements specific to application of GHG 

mitigation technologies

o What are the technologies that are currently in developmental stage?

o What barriers exist that prevent development testing implementation?

o Discuss policy impacts of near-term and developing tech options.

o What are the potential co-benefits of GHG mitigation technologies (i.e., effects on other 

pollutants?)?

o Discuss the distinction between research, demonstration, and commercial readiness for 

the utility industry (noting that there is a difference between testing a slip stream and 

being able to make a decision for a 50+ year investment)

o What is the parasitic demand for CO2 capture systems?

o What is the expected date for availability of CCS?

o What are the prospects of using of CCS on NG and coal-fired units?

o What are the linkages between criteria pollutant control and CCS?

o What are the realistic achievable deployment ramp rates for nuclear and coal + CCS 

capacity in the first 20 years after these technologies become commercially available?

o Are there new technologies that capture CO2 as solid waste for use as byproduct?

o How does geography affect CO2 mitigation options with respect to varying water 

availability, altitude, and suitability of local geological formations for sequestration?
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WELCOME

Frank Princiotta welcomed the participants and stated that the reason for pushing this project is 

that there is a tremendous need for reduction in CO2 emissions over an extended period of time. 

He noted that the IEA concluded that it will take a technology revolution to achieve a 50% 

reduction by 2050. According to Mr. Princiotta’s numbers, conservation can achieve 1/3 of the 

needed reductions, so new technologies will play a large role (particularly CCS for coal and 

nuclear power). The point of the database is to keep track of these technologies with unbiased 

opinions. He stated the need to look at all technologies as objectively as possible and stressed the 

importance of power sector technologies, followed by the industrial and transportation sectors. 

Mr. Princiotta noted that the database will have an objective array of information (that will be 

updated periodically) that will allow policy makers to make intelligent decisions on what 

technologies are currently available and those that will be available within a given timeframe. He 

hopes the developers of technologies can find it useful to see how their emerging technologies 

compare to those in the database. Additionally, he believes technology evaluators will be 

interested in the database to get snapshots of where we are with these technologies and what 

RD&D might be needed to accelerate these technologies.

Mr. Princiotta highlighted two discussion items: 

- How can this database be a useful product and for whom?

- How do we fill this database with the most useful data in the right format?

Session 1 Topic: Discussion and identification of available technologies, strategies 

and options for GHG mitigation from EGUs.

Dr. Hutson then facilitated a discussion asking 1) what near term mitigation technologies and 

strategies are available? And 2) what do we mean by near-term?—that is, what can be done 

almost immediately?

Larry Monroe stated that Southern Company is trying to build 2 new nuclear plants. It currently 

has 6 nuclear units, each roughly 1000 MW, and is attempting to build 2 more reactors (Vogtle 

site). He considers this near term in planning, and stated that Southern Company is currently in 

the process of obtaining permits. Frank Princiotta asked how long will it take to build and how 

much will it cost? Larry Monroe responded saying 10-12 years, and the 2 nuclear units will cost 

$14B. 

Ravi Srivastava asked how will permitting by NRC affect implementation with regard to the 

materials that can withstand natural disasters and airplane attacks? Larry Monroe said Southern 

is hoping to build a pre-approved design (Westinghouse) and that the concern is for the structure 

to withstand an airplane attack as well as seismic activity and major tornadoes and other storms..

Larry Monroe added that Southern Company is also attempting to build new coal generation –

IGCC; a plant that has Clean Coal Power Initiative (CCPI) Round 2 dollars and Mississippi tax 

credits. The project, which uses Southern Company’s own technologies (e.g., transport reactor 

gasifier), will capture 65% CO2 from start-up and the CO2 will be sold for EOR in oil fields.
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- Status $2.5B dollars cost; this is an attempt to take advantage of geography for close 

EOR application.

- The project will likely use off-the-shelf market capture technology (the exact technology 

was not specified during the discussion). 

- The project needs approval from Mississippi PUC.

- PUC hearings for the IGCC plant –

o First hearing concerns whether or not there is a need for more generation? Second 

hearing next May, 2010, will concern the best way(s) to meet new demand. The 

PUC will also decide if Southern Company can charge ratepayers for the costs 

associate with site construction before power is generated.

- Expected start-up is 2014

Larry Monroe stated that Southern Company is converting an old coal plant to burn 100% 

biomass, which would drop generation from 125MW to 95MW. The question for biomass is: is 

there enough available biomass? Southern Company research shows that ideally biomass would 

be harvested from within a 100-mile radius. Additionally, one problem is that the pulp and paper 

industry is a major customer (to Southern Company) that may become a competitor for 

resources. He said it will take 5 years to convert, which he considers near term. Nick Hutson

agreed that a 5 year window is near term. Larry Monroe added that Southern Company is doing 

a lot of research on coal-based capture and they are just starting to demonstrate that. Essentially, 

something you could buy right now or within the next 5 years is near term. It should be noted 

that the change in fuel for the coal-to-biomass conversion could have ramifications under the 

industrial boiler MACT.

Larry Monroe added that Southern Company is looking at classic renewables (i.e., wind and 

solar), but stated that they are not ideal in the southeast. Southern Company is also looking at gas 

as a near term mitigation alternative to coal if reduced CO2 emissions are required.

Praveen Amar asked what would be the costs to replace nuclear with coal plants CCS. Larry 

Monroe said that it is a wide range of number, but a 1000MW CCS coal plant (90% capture) 

will probably be $3.5B, roughly half the cost of the equivalent nuclear unit.

Gary Rochelle asked if there is any consideration of capturing CO2 from the biomass plant? 

High CO2 concentration would make removal cost effective.

Larry Monroe said no, it’s too small scale but after considering the ability to plant new trees 

and other considerations, it will probably be 80%+ carbon neutral.

Theresa Pugh is a representative of the American Public Power Association (APPA). APPA 

represents the interests of the 2,010 municipal or public power utilities, in aggregate they are 

perhaps the size of Southern Company. Ms. Pugh stated that in the short term she believes it will 

largely be renewable with natural gas (NG) and energy efficiency. Her preference is energy 

efficiency first, saying that it is ill-advised to fuel-switch to natural gas. She thinks short term 

measures will be dominated by energy efficiency measures, including demand side management 

(i.e., efficiency improvements performed by ratepayers). Nick Hutson asked why NG 
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conversion shouldn’t be considered a short term measure. Theresa Pugh responded saying that 

there is always the huge question mark about NG prices in the future - volatility. Another 

concern is natural gas storage—where does one store all this gas? Most of the country isn’t like 

West Texas where there is NG infrastructure and storage or oil/gas production with infrastructure 

needed for CCS or places to inject the CO2. Base load NG vs. coal plants, face different dispatch 

issues and efficiency. She believes that the presumption that you can switch from coal to NG and 

get 50% reduction in CO2 is naïve. In short term, she thinks the answer is energy efficiency, 

some NG, and she hopes that CCS will work but thinks it is 20 plus years away from commercial 

wide scale deployment. As a representative of local government and taxpayers, she would not 

risk taxpayer money on something with such great uncertainty.

Anna Wood asked if anybody is thinking about doing CCS on NG in the long term? Larry 

Monroe said it depends on what you mean by long term: if you mean a 10 yr window, then no, 

Southern Company isn’t thinking about it. Robert Hilton added, according to EPRI’s 

projections, that CCS on NG isn’t necessary to achieve 2020 reduction targets, but beyond that it 

ends up on natural gas in order to get to the 83% reductions by 2050. He stated that even with a 

reasonable nuclear mix, you still end up doing a lot of natural gas. The reality is, how many 

nuclear units can be constructed by 2020, 100 units aren’t realistic.

Frank Princiotta stated the importance of retrofitting and retiring coal plants – can’t achieve 

global reductions without addressing existing plants. China is adding two new units a week.

Larry Monroe responded saying that in his personal opinion, if there isn’t a technology 

breakthrough to reduce the energy penalty, then it’s very unlikely that we’ll see very many coal 

retrofits. Extracting that much steam and retrofitting the turbine for the reduced steam flow is 

working against retrofits. He stated that Southern Company’s strategy is to work on capture 

because it’s the same issue new or retrofit; so unless the costs associated with the energy penalty 

and the unknown costs associated with the externalities surrounding sequestration come down, 

we will probably be unlikely to do new or retrofits. 

Frank Princiotta asked what are the issues concerning space and water availability? Larry 

Monroe said that water is not as big of an issue in the southeast as it may be in other regions, but 

space is a huge consideration – need to find room to put a CO2 capture unit down.

Robert Hilton agreed with Theresa’s Pugh’s emphasis on energy efficiency as a short term 

measure, although there are a lot of barriers to it. Concerning retrofits, he stated that everything 

Alstom is working on is retrofittable. Chilled ammonia is a net water generator because of flue 

gas. Space is what you make of it, you build in the space you have. In his opinion, CCS will have 

to play a role because right now we can’t build new plants, can’t build nukes, can’t shut down 

coal fleet; what is the breakthrough? A parasitic load of 34% in the old amine process is not

technologically feasible; he believes that if we can get the energy penalty down to 20% or lower, 

then we are probably there. The focus is always on retrofits, and space is always an issue and it 

depends on the combustion and mitigation technology.

Mike Surface agreed with most of the short term strategies that have been discussed 

(specifically, energy efficiency, co-firing biomass). He stated that Dominion does not have 
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geologic storage sequestration sites around most of its plants. The question is where do we put 

the CO2? There is no pipeline and it is extremely contentious to put in new pipelines.

Mike Surface also stated that pipeline construction costs are significant. If policy makers, state 

legislatures, and state utility commissions don’t resolve pipeline costs then CCS could be 

derailed; independent of the development of mitigation technologies.

Jose Figueroa agreed and added that we have to consider the financial indemnification of CO2

along value chain (i.e., capture, compressions, transport, and sequestration) and the long-term 

stewardship costs that go with that. Once a site is full, it will get plugged, abandoned, and who is 

liable after that?

Andy Miller stated that there seems to be some promise in improving efficiency of existing 

plants and asked for comments of that approach for improving CO2 capture.

Jose Figueroa said you could repower existing plants but then have to consider the age and size 

of plant among other parameters. Retrofitting a small plant may not be viable. One has to 

account for life of the plant, size of the plant, and when you consider these issues, you could 

knock out 1⁄4 of the existing fleet for CCS candidacy.

Larry Monroe added that New Source Review is a very powerful impediment to efficiency 

improvements. He stated that Southern Company is doing everything it can to improve 

efficiency, mainly in the turbine—but even these improvements are somewhat modest (trying to 

recover 1-1.5% loss). He agrees with Jose Figueroa that below a certain size of plant he wouldn’t 

even consider doing anything. 

Jose Figueroa stated that there are a couple options as you start ramping up deployment: 

capture-ready plants and bypassing CO2 capture technology. Not all capture technologies are 

amenable to being shut down or ramping down—have to ramp down slowly because they don’t 

take shocks to their system very well. It’s not a switch, you have to operate it in accordance to 

technology specific parameters. Large scale CCS technologies, all along the value chain, have 

not been demonstrated. For example, for oxy-combustion, air separation units at the size and 

production capacity doesn’t exist worldwide, which could overwhelm the system. He added that 

replacement power is a major issue: the grid has limited excess capacity in certain areas of the 

country and building new plants to compensate for the ~30% parasitic load could overwhelm the 

system.

Theresa Pugh stated that it is helpful to think about CCS becoming commercially available by 

thinking backwards: start at sequestration and ask who owns it and manages it? This will reveal 

more cost issues. She states that we will have to have a lot of start up/shut down/malfunction

(SSM) capacity in the system to deal with CCS—because not only will we have those issues with 

other control devices, we will have these issues for geological injection as well. Even in most 

optimal locations, you don’t extract oil and gas continuously (24 hours a day, 7 days a week and 

for 50 years), but that’s the way you run a power plant. These operating systems are so 

different—startup/shutdown/malfunctions on back end sequestration will have major effects on 

front end. She believes that power plants will look like a chemical plant with a lot of pipelines 
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and storage pipelines because you can’t inject continuously and the power plant operations in 

addition to the ―chemical plant.‖

Raj Gaikwad said that in thinking about ―near term,‖ he look at targets. He considers near term 

targets as 2020: 20% reduction by 2020. In his view the short term, the industry is looking at 

renewables and biomass. He believes there is a possibilities for good return on investment 

through energy auditing, stating that at least 50% of power plants have such bad leaks (15-30% 

leakage) that energy audits could get you 1-5% efficiency improvements. 

Mike Surface states that plants were designed for optimization and doesn’t agree that we can get 

such high savings from efficiency improvements. He notes that that the biggest hit is in the steam 

cycle so going with an ultra-supercritical unit will get vastly improved steam cycle and much 

better efficiency. In his opinion, efficiency improvements without replacing a unit will only yield 

incremental improvements at best. Larry Monroe agreed, saying that getting back fractions of a 

percent is more likely. Theresa Pugh stated that a 2% efficiency improvement is probably 

optimistic (energy efficiency with the ultimate user or customer of electricity is an entirely 

different matter).

Nick Hutson then shifted the conversation to identifying some of the technologies that might be 

implemented in the longer term. Leaving the complications associated with sequestration aside, 

what are the pros and cons of those technologies?

Frank Princiotta suggested that short term be understood as being able to achieve substantial 

reductions by 2020; long term would be substantial reductions by 2050 with implementation in 

the 2040’s. 

Jose Figueroa also added the caveat of risk because if your risk aversion is low, you will go 

with something tried and true (amines, variations of amines, may even go with oxy-combustion 

since it utilizes commercial equipment, dealing with integration and scale up) in the short term. 

He believes that everything else is long term, around 2020 or later because a lot of technologies 

are still in the lab (the ones with lower energy penalties) and still require time for improvements

and advancement through each maturation stage. Risk will influence how the longer term 

technologies may become commercially available. He thinks that realistically a lot of 

technologies will become available around the 2020 timetable unless there is a greater 

acceptance to risk or increased research funding from industry and government.

Robert Hilton agreed and believes that amines and chilled ammonia will be deployed before 

2020. He also thinks oxy-coal will be available by 2020. However, he thinks that it’s too difficult 

to identify technologies that will be available between 2020 and 2050. R&D will drive long term 

technologies. He states that it’s naïve to think we know what technologies will generate power in 

2050, but he strongly states that by 2020, amines and chilled ammonia will be commercially 

available by 2015—that is, with performance guarantees, schedule, and price. Larry Monroe 

interjected that a utility sees commercial differently – it’s commercially available when one can 

make a decision with all the risk accounted for (go out and buy it, get financing, and get public 

utility commission approval). Nick Hutson stressed the ambiguity of the term ―commercially 

available‖. 
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Ben Yamagata noted that it may be good to think about technology paths as ―demonstrated‖, 

―ready for deployment‖, and ―deployed‖. One can say that something is ready for deployment 

after you’ve done a project, but doesn’t mean it’s been done widely, but just that it’s been 

demonstrated in one particular instance and someone is willing to say it’s available. Even with 

respect to ―ready to be deployed,‖ we may mean we have dealt with a large amount of technical 

risks but it may not mean we’ve dealt with the financial risks.

Gary Rochelle drew an analogy to building flue gas desulfurization (FGD) units in the 1970’s, 

which took 7 years to get commercial. In his opinion, we can deploy CCS in 7 years as long as 

there is a driving force like a new source performance standard (NSPS); today we don’t have a 

driving force, but if there was one then there is a deadline, we’d be ready.

Jose Figueroa agreed but stated that if we did it in 7 years, the energy penalty would be 30%—a 

tremendous hit compared to an FGD system. He stressed that we have to keep the magnitude of 

what we’re looking to do in context. Existing plants with current capture technology would see a 

30% generation hit—we’d have to replace that power at some point. 

Gary Rochelle responded saying that he didn’t say we could do it cheaply. Robert Hilton also

agreed saying that we need a regulation to move forward. Nick Hutson added that only 1/3 of 

the coal fleet capacity has FGD units, even after 30 years of development. Gary Rochelle noted 

that this too was a driving force issue, not a technical issue.

Theresa Pugh thinks that the likely date for commercial availability is 2030 due to the need to 

acquire safe drinking water permits. If you can’t get an injection permit, it isn’t commercially 

demonstrated. She believes we will have too much CO2 saturating oil reservoirs within the first 

decade of new power plants in (or very near) oil/gas extraction locations. There may be other 

industries (perhaps gasification, ethanol, or refineries where there might be a separate hydrogen 

of CO2 steam already in the industry) that can go first but it isn’t the power sector.

Frank Princiotta stated less optimism about the FGD comparison—FGD was 2% penalty. He 

noted the greater complexities (political, liability, sequestration), nothing like that was associated 

with the FGDs. Additionally, the capital and operating costs, tremendous difference between 

CCS vs. FGDs. In his opinion, those are substantial differences.

Praveen Amar noted that we generate 2 billion tons of CO2 per yr from coal; the mass ratio of 

CO2 vs. SO2 control is 100 to 1. From a weight perspective, controlling for CO2 is 2 orders of 

magnitude higher than SO2; we shouldn’t extrapolate too much from FGDs. 

Mike Surface agreed, warning that there will be more CO2 going out of a plant than coal coming 

in. 
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Session 2 Topic: Discussion of cost, performance, and availability of various 

technologies, strategies, and options.

Nick Hutson asked what are realistic expectations for cost performance and availability of nearterm mitigation technologies?

Ben Yamagata noted a constant friction between what a vendor considers the cost of capture 

system vs. what a developer considers real cost. He thinks baseline costs should capture these 

differences because the costs to capture vs. the all-in cost that developers are experiencing are 

orders of magnitude in difference. 

Nick Hutson asked what is driving those differences?

Andy Yaros responded saying the differences are in financing, how you match the equipment up 

to rest of the plant, retrofit issues, cost of capital, and design.

Larry Monroe used FGDs as an example: for scrubber projects, the scrubber island itself is 1/3 

of cost itself. Just the equipment and hooking it up is about 1/3 of total project. 

Nick Hutson asked if it is consistent that quoted price is significantly less than the actual cost? 

Andy Yaros responded yes, the vendor cost is consistently less. Larry Monroe said it depends 

on how you structure the project: Southern Company chooses to do a lot of construction 

themselves, so project structure is different; so it’s a difference between turnkey and 

owner/manager.

Jim Staudt reminded that none of this stuff has been built at scale. There is degree of 

uncertainty and we are using estimates for techs that have never been used at that scale. If 

technology A looks slightly more expensive than technology B, it shouldn’t be taken to the bank 

because there is a certain amount of uncertainty in these estimates.

Nick Hutson asked Jose Figueroa if knows the guidelines for costs—turnkey vs. non-turnkey. 

Jose Figueroa stated that NETL has developed a lot of baseline estimates for CCS plants based 

on an EPRI Technical Assessment Guide (TAG) perspective. He stated that DOE does 

collaborate with a lot of engineering construction firms and manufacturers so that their analyses

may provide more realistic estimates than an extrapolation of someone else’s estimate. Turnkey 

estimates are usually plus-minus 10% estimates. He doesn’t think anyone has a turnkey cost or at 

least would be willing to publically disclose their estimate.

Larry Monroe noted that there are slip-stream demonstrations of CCS being between 1 and 2 

orders of magnitude higher in cost than an equivalent FGD. He hasn’t seen the order of 100 

times more expensive for CCS, but more like 10-15 times more expensive. He expects cost to be 

significantly higher than FGD.

Jose Figueroa stated that we have to account for pipelines and other infrastructure—will there 

be tipping fees? He thinks it will be difficult to understand the life-cycle cost because there will 
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be permutations of what the total system will eventually look like, and that kind of information 

will likely not be disclosed. 

Nick Hutson said that for purposes of database, cost would be capital and OM just for capture 

tech. 

William Brownell brought up risk and liability issues, saying that we can define the cost of 

equipment and cost, but liability and long-term costs of liability will drive up financing the 

projects, which will make costs very complicated.

Theresa Pugh suggested that hired contractors must understand the differences in industries. 

Pipeline costs have been grossly underestimated. Pipeline companies usually take a certain 

percentage of the profits of a field, which makes a huge difference for costs. She encouraged 

ancillary costs to be considered in the database.

Nick Hutson asked if there were any other questions on costs?

William Stevens stated interest in costs pertaining to an owner’s perspective, costs within the 

last 5 years and the next 5 years. Will we be able to afford anything considering the real cost 

escalations? He noted concern for building of new infrastructure abroad (China and Southeast 

Asia). Resurgence will take 20 years for manufacturing and resource capability to catch up, 

which will drive up costs in real terms. Where will the cost go next and how do you think about 

costs in terms of long term policy considerations? 

Larry Monroe stated that when the industry started building scrubbers in this last wave, there 

were uncontrolled costs mainly due to commodity and labor increases. However, he thinks it’s a 

second order issue because the primary cost is the initial cost of building and integrating. He 

adds that commercialization is a huge issue for Southern Co, particularly the risks associated 

with building a new coal plant. 

William Stevens asked whether the preference should be to think in terms of constant real costs 

today or real escalations in costs going forward.

George Offen noted that because we’re talking about database approach, the important thing is 

to identify the scope clearly and be very transparent in the economic assumptions. 

Teresa Pugh said that one of the reasons she is pessimistic about CCS is because of total costs. 

She reminded that municipal governments don’t go away, so the cost will be passed directly to 

the customers, and worse, if the technology isn’t right, we’ve invested in stranded assets. The 

municipal government is also responsible for the ground water, so it wouldn’t take much 

displacement before municipal governments have to pay for clean-up. From her perspective, 

these issues make the affordability of CCS dubious.

Nick Hutson shifted the conversation, asking what would be the expectations for cost reductions 

and performance improvements over time for amines and chilled ammonia, those systems that 

are somewhat ready for implementation in near term?
10

Jose Figueroa stated that even in the near term, if you are able to build an absorption cycle, 

amine or chilled ammonia, you will be constantly seeing incremental improvements, and when 

there are a sufficient number of those improvements, they will be implemented. But the first 

movers will be handicapped compared to those that wait 10 years. There has to be some 

incentive for those first movers—he noted CCPI, which contains a 50-50 cost sharing to 

compensate first movers. He believes more incentives will come and that short term 

improvements will automatically occur. For amines, stranded assets won’t happen because it will 

get better over time.

Larry Monroe returned to the FGD analogy, stating that third generation FGDs are now being 

installed. Some FGDs incrementally improved over the first designs, and some have a totally 

different design. He thinks that optimization will happen over time: 35 years from now, we’ll see 

changes in all coal-based generation equipment but it’s hard to predict where those 

improvements will happen for CCS. Getting to the mid-high teens (energy penalty) makes all the 

difference—getting from 25% to the mid-teens.

Jose Figueroa provided an example analysis: at a 50% capture rate and 40% energy penalty, we 

would need an additional 165 GW of replacement power; a 10% energy penalty would require 

only 25 GW of additional replacement capacity. From a deployment standpoint, that’s a 

significant improvement.

Robert Hilton stated that cost reductions will occur; the numbers often get skewed on 

demonstrations. It’s the difference between the first price vs. the n

th price. 

Gary Rochelle thinks that the minimum energy is about 11% of plant output, but he thinks it 

will be difficult to get amine systems below 20%. To get lower you invest more capital cost, but 

then it becomes a trade-off with capital costs.

Jose Figueroa added that project financing requires thought about major long lead items 

(compressors, vessels—will they be steel or concrete?). Just adding a capture plant will come 

close to the time it took to build the original plant, which has an associated cost. We haven’t seen 

this type of energy growth since back in the 1970s, and back then the industry was already 

ramped up. He noted that the industry and the supporting industry to the power sector are not 

ramped up and the question remains if the supporting industry is still here in this country. 

Theresa Pugh noted the issues of reliability assurance and cyber security. She posed the 

question: where will the necessary money come from? The consumer cannot afford this (e.g, 

California, Alaska, Texas electricity prices have recently increased dramatically), and a lot of 

utilities are asking themselves where the money will come from in light of industrial load 

dropping in recent years. 

Mike Surface raised the issue of what the legal structure will require for performance–will a 

90% capture rate be required at each unit or within each State? He thinks a wider umbrella will 

make it easier to cope, stating that a 90% requirement on every unit would render many units 

economically inoperable. If the performance standards allow scrubbing on the utilities’ flagship 
11

units and they can use those to umbrella other units, it provides flexibility; but a command-andcontrol policy will force the shut down of older smaller units. All of those units will be needed in 

order to meet load demands.

Jose Figueroa added that the sweet spot is technology dependent. The 60% sweet spot usually 

refers to amine scrubbing. Oxy-combustion can not reduce CO2 emissions by 100% until you 

clean up the flue gas stream—usually about 65% concentration prior to clean-up. 

Theresa Pugh added that removal is also contingent on disposal and the injection technology, so 

the sweet spot for geoquestration may be actually 40% not 90%.

Jose Figueroa stated that after sequestration sites have been filled, we may be need interstate 

transportation lines, generally where the huge saline formations are. In near term, onsite 

sequestration may be possible, but in the long-term we will need interstate transportation to the 

Midwest. CO2 transportation costs from the east coast will be higher than those for other regions. 

Ben Yamagata said that regarding the long-term view for the database, think about cost of CCS 

in terms of cost of electricity. He also added that this only makes sense if CCS costs come 

down—there are some estimates that we thought we could get capture costs down to the price of 

electricity for a new supercritical plant, but that’s not realistic anymore (DOE has numbers of 

10-20% cost increase in 20 years). His point is that we think we can get costs down, but it’s 

important that we do homework necessary to be fairly competent that our price projections are 

generally right. He thinks we shouldn’t leave with impression that it’s so expensive that we 

won’t do it; we can identify equipment and processes that will bring the cost down.

William Brownell added that when you are looking at a piece of equipment, you learn about 

how the cost comes down, but it may not be the case when considering the whole system 

including transportation and sequestration. Overall, costs may not come down. 

Jose Figueroa responded that the issue is not - ―Can it be done?‖, but rather ―at what price and 

how quickly can it be done?‖ What is the lowest possible cost?

Frank Princiotta returned to the FGD analogy to acknowledge that estimates for FGDs were 

initially low – 3 or more times lower than actual costs. He warned against assuming that current 

numbers are what they will be in the field. He thinks it’s reasonable that costs may escalate 

before we see reductions.

Jose Figueroa asked if the database is something that will be presented to financial and 

insurance industry because how they evaluate the risks associated with technologies will affect 

the premium they will charge. For the newer technologies, they will have risk aversion and 

questions about operability and reliability. He thinks it is critical to educate the financial and 

insurance industry because they have been the laggards; they have stayed out of the 

conversation. He raised another issue concerning the liability associated with having to install 

unproven capture technologies and the resulting impacts on investor confidence.
12

Nick Hutson stated that with respect to availability of the database, initially it will only be 

available within the Agency as a means of vetting the content and functionality. However, he 

did state that, once the database has been reviewed internally, it will be made available to the 

general public. He added that it currently has comparison tables to compare technologies based 

on performance and cost, with references to original sources available.

Jose Figueroa asked: so you are keeping audience in mind? An engineer is going to be looking 

for certain information different from what financial firms and state permitting agencies will be 

looking for. Nick Hutson answered that the database will contain different views so the user can 

filter out data.

Larry Monroe stated that Southern Company believes sequestration is the critical path. CCS has 

four sequential actions: capture, compressions, transport, and sequestration. Whereas capture and

compression present technical and cost issues, transport and sequestration technologies have 

been proven. Therefore, the main issue surrounding transport and sequestration is working 

through the associated externalities. He thinks that in practice, the progress of capture technology 

development will be limited by the speed of sorting through the externalities of transportation 

and sequestration. Sequestration is the critical issue that is wagging the whole system. 

Nick Hutson asked if Southern Company’s Mississippi CCS demonstration intends to do any 

sequestration.

Larry Monroe said it will sell the CO2 for EOR (which does have some sequestration) but 

probably not direct saline reservoir sequestration, but Southern Company has a start-up next year 

that is 25-MW capture plant (100-125k tons CO2 per year). Southern Company has applied for 

CCPI funding to scale up the 25-MW KS-1 (Mitsubishi Heavy Industries solvent) to 175-200

MW to get 1 million tons CO2/year. These are technology development steps to get 1 million 

tons of CO2 in the ground and gain experience. He states that if everything goes without delay, 

the industry may have a couple of sequestration sites (injecting 1MM tons CO2/year) by 2020 

from coal. Nick Hutson asked if the timing for that is dependent on government funding. Larry 

Monroe answered yes, stating that sequestration for Southern Company’s small system is 

currently funded by Southeast Regional Carbon Sequestration Partnership (SECARB), but the 

capture side is all privately funded.

George Offen said that there are many actions internationally that should be documented 

because a lot of information will be developed in parallel.

Nick Hutson responded that the database will be an accumulation of all the information out 

there.

William Stevens asked regarding timing and pace of demonstrations, is it sufficient to say that if 

we’ve demonstrated a 200MW plants, then we’re ready for commercial development at 

1000MW?

Jose Figueroa stated that it depends on the technology. For example, amine processes will have 

multiple trains around the 200-250MW range. But if you are dealing with a membrane system, 

once you have one module at commercial scale, it’s all about replication vs. scale-up. The piping 
13

is not an issue of technology, but scale. A demonstration at 100MW would probably be 

sufficient. The answer is, it’s dependent on the technology and how far you want to scale up.

William Stevens asked if demonstrating a 1000MW plant with a 200MW module the same as a 

1000MW plant with five 200MW modules? George Offen answered no, you have to integrate 

thermally. William Stevens thinks we do have to demonstrate at full scale. Jose Figueroa said 

that it becomes an issue of what is the technical potential—does it makes sense to take on the 

risk of a 500MW absorber?

Theresa Pugh added that the geology will drive much of the commercial size issue. One can’t 

build and demonstrate and ask questions about commercial development without merging the 

issue. The type of geology will be different depending on location: seismic issues, water issues, 

and what are you going to do with all the water you bring out impacts the determination of 

―commercial‖. 

Nick Hutson asked: is it safe to say that early captured CO2 would be used for EOR?

Robert Hilton does not think so; it makes sense but it depends on where it is captured. He stated 

that even in the Southern Illinois basin, we don’t know who owns those fields. Who moves and 

for what purpose? The question will be, are you really going to get the money for EOR?

Nick Hutson asked if permitting for non-EOR sites would make it easier to move forward with 

CCS.

George Offen responded saying that if you inject in EOR fields for combined EOR and storage, 

you have to treat it as if it were CO2 storage (Class VI wells). If it is just used for EOR, then it 

might be easier. Anna Wood added that under the Underground Injection Control (UIC) 

program, EOR is under Class II wells.

Larry Monroe returned to the question regarding whether or not 200 MW is enough for scaling 

up to 1000MW. He thinks that from a vendor perspective, it certainly is, but not from a utility 

perspective. A utility would want to see several 200 MW demos before deeming it proven. When 

it becomes commercial depends on who you are. 

Nick Hutson shifted the discussion to availability, asking how availability and sequestration 

affects our ability to begin CO2 reductions at the plant.

Larry Monroe stated that he would normally think about 3 things when thinking about 

sequestration by itself: 1) how the UIC and carbon allowance systems work together, how that 

regulatory system works together; 2) ownership of the pore space, how you acquire that is very 

grey and it looks like a state by state issue; 3) risk management – liability, tort damages, drinking 

water issues; how do I make my executives and board directors feel like they can manage risk? 

In his opinion, the issue isn’t technology but externalities—how do we get the externalities dealt 

with (e.g. public acceptance)? Anna Wood asked for clarification concerning the first point on 

permitting. Larry Monroe said that we need a unified system, like a one-stop shop to obtain all 
14

necessary permits. Having to obtain permits from 4 or 5 different organizations in different 

instances would not be ideal. 

Anna Wood asked if the utilities anticipate operating the injection site or handing off to 

injection companies?

Larry Monroe stated that it’s too soon to tell – could be a tipping fee ($/ton), or partnership, or 

a large utility (vertically integrated) which build and operates a sequestration site. 

Theresa Pugh said that in the oil industry, extraction (similar to injection) sites are run by the 

drilling companies. A utility may breakthrough and try to do it, but drilling co’s own the 

technology and the 3D, 4D, 5D, and 6D drilling technology and acoustic reading technologies 

are propriety. She warned that there are barriers of entry into that field.

George Offen confirmed that the bigger companies are looking at the 3 options Larry 

mentioned. He added that in order to gain public and regulatory acceptance, we must be able to 

characterize the sites underground; they are extremely heterogeneous and at this point it is very 

difficult to measure everything. To be able to characterize throughout the entire region is 

difficult and he thinks there is a need for technology development for site characterization, postinjection monitoring, and predictive models.

Mike Surface agrees that public acceptance is still a huge issue. He pointed to the nuclear 

industry as an example for how safety and risk will be a major concern. In his opinion, one leak 

in a pipeline would create an outcry against the whole system.

Anna Wood asked: in terms of insurance market and insuring long term risk, is it your sense that 

there will be insurance products to provide long-term coverage?

Larry Monroe said that it doesn’t exist today; there are only year to year policies with limited 

coverage. His personal opinion is that insurance will be the winner in risk management tools and 

he thinks that there will be 3 different policy areas: 1) have a policy during operations phase; 2) a 

different policy for stabilization; and 3) another policy after closure that covers the residual risk 

long-term.

Theresa Pugh added that the oil and gas industry is mostly self-insured. She said she would be 

surprised if there is a real insurance product for long-term CCS projects.

Session 3: Theresa Pugh presentation, titled: “Technical and Non-technical 

Challenges of Sequestration” The presentation is provided as Appendix C.

She stated that the most favorable locations for sequestration are oil and gas formations but that 

those would be saturated very early in the transition years. That leaves deep saline aquifers, close 

proximity to existing CO2 pipelines, low seismic activity, and proximity to transmission and rail. 

The least favorable locations consist of moderate or high levels of seismic potential, unfavorable 

geology, and lack of transmission and rail. She noted that not many current locations meet the 

favorable conditions listed above.
15

She also stressed the strong influence the Safe Drinking Water Act will have on CCS, saying that 

many states have state drinking water protection programs and some states have different 

standards for injection of any substance to protect groundwater resources.

Her presentation introduced a timeline for CCS projecting that it will take until 2030 to achieve 

the necessary compliance and permitting for sequestration sites other than non-oil and gas 

locations. Noting that the UIC would want to see 10 years of proven injection projects before 

approving sites, she asked the question: how long will it take for CCS plants to comply with 

every component under the current UIC program? She reiterated that geology drives injection 

and she reminded that at this point there is lack of certainty pertaining to how much CO2 a 

formation can take.

She concluded by stating that the focus should be on energy efficiency with the ultimate 

customer or user of electricity because it is readily available.

Sessions 3 Topic: Technical barriers currently preventing wide-spread 

implementation of CO2 mitigation technologies or strategies (including renewables 

and nuclear).

Jose Figueroa said one barrier for CO2 capture is flue gas composition, which needs to be 

treated. Pre-treatment and deep scrubbing will be necessary because very few technologies can 

take raw flue gas composed of sulfur, mercury and other impurities.

Nick Hutson added that the impurities, particularly sulfur, affect the cost of a retrofit plant if you 

have to add another FGD unit. Noting that the EPA is proceeding toward a proposal of a utility 

MACT (Maximum Achievable Control Technology), he then asked: how does carbon capture 

affect other pollutants that have to be dealt with? 

Jose Figueroa said that with CO2 capture, a unit will have to fire more coal to compensate for 

parasitic load, so emissions will go up to a certain degree and flue gas treatment will be a 

concern. 

Robert Hilton stated that there is a trade-off: the industry knows capture units will capture 

everything, but it doesn’t know if that’s good or bad or indifferent. He said it isn’t known where 

the trade-off comes economically. As an example, he noted the Mountaineer plant and its ability 

to remove all the sulfur—the potential is there, but the question remains as to what would be 

economically optimal.

Anna Wood asked if CO2 capture would also remove constituents like arsenic.

Robert Hilton answered that with amines and chilled ammonia, everything is removed. When 

CO2 comes off, it’s 99.7% CO2 and .25% moisture; the rest is cycled back and you’re left with 

whatever else is in the liquid. Anna Wood asked: can you choose to take that portion out so that 

you have a pure CO2 at compression? Robert Hilton responded yes, it is a small stream that is 

removed as a fertilizer (in the chilled ammonia process).
16

Larry Monroe stated that the MACT probably requires any coal plant to be scrubbed. If it turns 

out that way, many older and smaller units will be retired. He sees decision making hinging on 

MACT and then carbon on top of that. Most of these CCS systems are packed columns that are 

good at removing particulates and acid, so it’s too early to tell the purity of CO2 and what might 

come from flue gas. His concerns are twofold: 1) Whether it’s ammonia or amines, some leakage 

is expected into stack emissions which could be a volatile organic compound (VOC) issue; and 

2) What do you do with the stuff that you’re drawing off the process stream (waste solvent)? It 

just creates another stream for disposal. Robert Wayland asked if a discharge stream would 

further complicate what you can do with some of the off stream issues. Larry Monroe thinks it 

is a significant problem even for FGDs by themselves. The technology forcing nature of the 

water effluent guidelines will require spending to deal with typical FGD water. What do we do 

with waste amine? At present, it is placed on the coal and re-burned, but he noted that this is not 

a solution for full scale CCS. FGDs require a big-picture perspective that considers how water, 

solid, and air emissions work together.

William Stevens asked how much of the existing coal fleet may have to be retired if there is, for 

example, a requirement to emit no more than a certain amount of CO2. 

Larry Monroe said that if he would have to decide for the January 2015 MACT compliance 

and, that if every coal plant had to be scrubbed, he would have to decide within a year from now 

whether a unit will be retired and replaced. Cap-and-trade regulations allow a utility to overcomply with large new units so that the smaller older units can still operate – but MACT requires 

compliance on every unit. Because of this, he estimates that industry-wide about 20% of coal 

facilities would be retired. 

J. Edward Cichanowicz added that it is very costly to install FGDs and SCRs on older plants; 

the smaller and older units have less space. He suspects that the answer depends on variables like 

heat rate and how much gas has to be processed.

Theresa Pugh noted that industrial load has dropped around 20%, and residential load has 

flattened in most cities, so utilities are planning on retiring units but don’t know what will 

replace them. She said that for municipal governments, it is difficult to build a power plant, even 

a gas plant, in this economy. 

George Offen raised the issue concerning the potential decision by the EPA to determine how 

coal combustion products (or residues) will be designated. If they are designated as hazardous, 

the impact on cost is significant. He noted an EPRI study on a couple of North American Electric 

Reliability Council (NERC) regions that concluded 20% of the capacity is at risk in the 

concentrated coal-based regions. Nick Hutson asked what drove the cost increases in that study. 

George Offen answered: the cost of switching from wet to dry ash, the cost of landfilling in 

general (as opposed to beneficial use), and landfilling hazardous waste. Nick Hutson asked if the 

study assumes a rule that prohibits beneficial use. Anna Wood said it has to do with the change 

of characterization of solid waste to hazardous waste. George Offen added that the implications 

of the designation are more of a policy issue than a technical issue and asked the utility 

professionals what the designation of coal combustion products as hazardous would do.
17

Robert Hilton asked if it’s hazardous in the landfill, is it hazardous in the precipitator? Who’s 

going to do beneficial use if it’s designated hazardous?

Larry Monroe added that the designation of ―hazardous waste‖ does not make it a beneficial 

use, but forces it all to be landfilled. He believes that most users of fly ash would stop if it were 

to be designated hazardous waste, therefore making the utility landfill all of it. Theresa Pugh

also added that there are only 12 landfills that have the capacity to take electric utility coal 

combustion product waste designated as hazardous waste.

Gary Rochelle noted that if we use CCS and have loss of production, there is a good chance that 

it is system dependent. There won’t be any need for capacity because we have excess capacity. 

He used Texas as an example, which has enough gas capacity to replace the production loss from 

CCS plants. Additionally, Austin is trying to replace some coal capacity by ramping up 

renewable capacity to 35%, which is exactly the capacity decrease that would take place with 

CCS plants.

Nick Hutson shifted the discussion to renewables, asking what are the technical or non-technical 

barriers of increasing renewable capacity?

George Offen stated the barrier is fuel source.

Jose Figueroa added the issues of real estate, back-up power when the fuel source isn’t 

available, and wide-scale availability—that is, some of the technologies are not ideal for certain 

regions. Transmission is also an issue. 

Nick Hutson asked: renewable power is expensive but when you start implementing CCS, does 

it become more competitive? Larry Monroe said that the theory is that all the costs rise, so 

everything becomes competitive.

Frank Princiotta reminded that Germany is trying to meet their reductions through renewables 

solely. Nick Hutson added that the cost of electricity is already high in Germany, so renewables 

are more viable. Frank Princiotta agreed and stated that it has to do with the tax but also 

because they have less fuel available.

George Offen encouraged considering the environmental impacts and the life-cycle costs of 

renewables. As an example, he raised the growing concern over the impacts that wide-scale wind 

generation may be creating as it takes energy from the atmosphere. 

Theresa Pugh said that yes, renewables are becoming more cost-effective given a higher cost of 

everything else. She raised two concerns about renewables: 1) Ice sheeting with wind turbines, 

where ice forms on the blade and operators are forced to consequently shut down the turbines to 

prevent accidents; and 2) How much biomass can a power plant burn before you consider it an 

incinerator?

Mike Surface noted that the ethanol debacle is a pre-cautionary tale about biomass. Is it more 

efficient to use a solar technology or storage? He said there is a finite amount of biomass we can 
18

use and thinks that after treating and transporting biomass, there may not be as much of a gain as 

we think.

Robert Wayland asked how feasible is it on existing units to use renewables to get a small 

efficiency gain (e.g. wind turbine to make up for parasitic load)?

Jose Figueroa said you could use solar thermal to heat up water, but many power plants may not 

have sufficient space in addition to the CCS requirements. He thinks that renewables could play 

a small role.

Larry Monroe added that if you’re in an area that doesn’t have a good solar or wind potential, it 

would make no sense. At this point the best bang for buck is to mix in wood or biomass at the 

coal plant (assuming the biomass doesn’t interfere with the control technologies); about 5% 

biomass by heat input. Theresa Pugh added that labor becomes an issue when you go above 5%, 

due to significant fire suppression.

William Stevens returned to wind and solar, noting the intermittent nature of renewables, and 

asked if it is reasonable to assume that national electricity generation could be 30% renewable. 

Theresa Pugh said that NERC considers 20% renewable without triggering reliability concerns 

is extremely optimistic. Jose Figueroa noted a study that showed that from a system’s 

standpoint, regional variability in renewable fuel sources equal out across the country and 

dampen the need for standby power.

Robert Hilton mentioned that hydropower is still a very viable source of power. Jose Figueroa 

asked Robert Hilton if he knows a lot about geothermal power? Robert Hilton answered that 

Alstom has a number of plants in California and Mexico. Theresa Pugh added that most 

locations are CA because geothermal is a very niche application.

Larry Monroe raised concerns about tying renewables and CCS together as a system. The first 

concern is that an intermittent supply of wind at a coal plant would require more capital to 

maintain grid stability and reliability. CCS may turn coal plants into baseload units not because 

we need the power but because the system needs to be run constantly to maintain the chemical 

process.

Nick Hutson asked if it makes sense to plan for 60-65% CO2 removal?

Jose Figueroa said it depends on who you are. From an economic standpoint, yes, it makes 

sense to find out what the technical sweet spot is—whatever it is, go with it if it’s economically 

viable. Nick Hutson clarified that a cap and trade system would allow you to make those 

choices. Jose Figueroa responded that it’s the legislation that will tell you at what rate you will 

capture or buy credits.

Gary Rochelle said that his research included trying to understand and design amine systems 

that can handle and react to steam pressure.
19

Theresa Pugh suggested revising cap and trade to be a ―bubble‖ policy, where a power plant 

works toward a mission across its operations, moving toward mitigation as opposed to something 

like cap and trade that Congress would have to set up. She suggests thinking about a bubble 

policy for power plants similar to State Implementation Plans (SIP).

Anna Wood asked Theresa if she is talking about enabling the power plant to take credit under 

its cap for things like demand-side management? In the context of energy efficiency 

improvements, the tension we typically see is between the power plant (that doesn’t want to 

trigger NSR) and the environmental community (that we shouldn’t allow units with outdated 

technology a lifetime extension).

Theresa Pugh asked how can we have a Plant Applicability Limit (PAL) over CO2? An electric 

utility will serve load based on population and demand; if you set a PAL you cap economic 

prosperity since the permit limits CO2 emissions—inherently tied to the electric utility’s number 

of customers.

Anna Wood answered saying that one would start by looking at existing regulations, setting a 

baseline (from an NSR perspective) and establish a cap. The utility can then make necessary 

changes to improve efficiency over time, controlling their units on it’s timeframe to make sure 

there are no increases in tons/unit. The end result is the aggregate accumulation of reductions 

regardless to where they occur.

Theresa Pugh stated that as a power plant under that scenario, if you have only 10 industrial 

customers, you have to shrink the emissions over time; how do you do that without limiting 

economic prosperity in the community?

Anna Wood said that these are issues EPA is trying to work through. She insists that a PAL is 

potentially attractive and notes that the issue Theresa raises is more a question about how a 

facility can make sure it is meeting demand growth. William Brownell asked how strictly would 

a PAL be set, and Anna Wood responded that EPA is currently thinking through that issue.

Session 4 Topic: Identification of promising (but still early stage) technologies, 

wrap-up, and summary of workshop.

Nick Hutson addressed questions that were submitted by participants prior to the workshop:

1) Currently available mitigation techs for the power sector: Amine and chilled ammonia 

are the front runners for CCS in the power sector, what are the others?

Frank Princiotta welcomed thoughts on supercritical and ultra-supercritical technologies, which 

he considers truly commercial technologies. Robert Hilton agreed that they are available, but 

stated that no one can currently get a permit. He said the major issue is that CCS is demanded for 

new plants, but there are no commercially available CCS systems, so the plant gets tied up in 

permitting. Or you try to build a ―CCS ready‖ plant, but the lack of a robust definition for ―CCS 

ready‖ also stalls the permitting process. He added that American Electric Power is building a 

plant even without a permit.
20

Nick Hutson stated his understanding of ―CCS ready‖ as meaning having the space for and 

design of the system in place but not built. Robert Hilton asked: but how can you do that when 

there is no commercial design available? The problem with the definition is that it presumes you 

know how to do it before it’s commercially available. He thinks the only thing you can say is 

maybe there is space there and we know you can put something here at the end. Jose Figueroa

agreed that there is no industry-wide CCS ready definition. However, his understanding of ―CCS 

ready‖ is not merely that there is a designated plot of land; it’s more involved, i.e., what kind of 

technology types are being considered. Once the technology is identified, you begin working 

through the assumptions about how much heat is needed, piping, integration, and what kind of 

permitting will be required. CCS ready requires an understanding of whether or not a CCS 

technology is viable for a particular power plant and developing a plan.

Larry Monroe said that from his perspective, he would not build a coal plant without some level 

of carbon capture, so the term ―capture ready‖ holds little meaning now. He noted that in 

anticipation of carbon legislation, Southern Company does not even talk about ―capture ready‖ 

plants because any coal plants they build will by default capture CO2.

Mike Surface stated that Dominion follows a practical definition, which is what the public 

utility commission considers ―capture ready.‖ In other words, a plant is capture ready if the PUC 

recognizes it as capture ready. He noted that there isn’t a concrete definition written yet, so it 

will likely be a contentious issue.

Robert Hilton added that the problem is that one must commit to a technology without knowing 

how much it will cost and when it will be ready. Therefore, the plant cannot be financed because 

its cost is not known.

Ben Yamagata said (in response to Larry Monroe’s comments above) the government’s funding 

strategy for CCS has changed: 2 years ago funding was available for capture ready plants; now it 

is available if the plant captures 50-60% CO2. He added that in climate legislation today, there is 

a performance standard that requires a certain number of gigawatts of CO2 capture. Initially 

permitted plants will have to retrofit anyway, so there is a de facto framework being established.

Nick Hutson asked: if you were going to build or recommend a new facility for your fleet, what 

would that technology look like, supercritical, ultra-supercritical, IGCC, oxy-coal, and why?

Larry Monroe answered that Southern Company is currently building an IGCC and some 

people believe that, for conventional pollutants, IGCC is the superior technology. However, in 

his own opinion, he thinks the conventional pollutant benefits may not be superior when CCS is 

added to the back end of a PC unit. Thus, he suggests pulverized coal (PC) units with CCS basis

may be on the same level as IGCC with CCS with respect to conventional (SOx, NOx, 

particulate), and he thinks PC with CCS may control NOx and sulfuric acid even better. He 

noted that NETL studies suggest IGCC with CCS is incrementally cheaper than PC with CCS; 

and conversely, with no CCS, IGCC is incrementally more expensive than supercritical or ultrasupercritical PC units. He added that if there was confidence in CCS technologies, Southern 

Company might consider a new PC unit with carbon capture (likely a supercritical unit to 
21

optimize front-end efficiency as much as possible). Larry stated that Southern Company is 

currently not deeply involved with oxy-firing due to scale issues (similar to IGCC, you can’t take 

a slip stream to do RD&D). In his opinion, Southern Company’s research priorities are 1) IGCC, 

2) ultra-supercritical PC with CCS, and 3) oxy-firing, in that order.

Frank Princiotta asked Larry if the IGCC unit uses pure oxygen with a water-gas shift reaction, 

and if so what is the justification for the rationale. Larry Monroe answered that it is air-blown, 

stating that Southern Company considers air-blown the optimal option for use with their 

transport reactor gasifier. The IGCC unit will start up as 65% capture with a 2-stage water-gas 

shift. Frank Princiotta then asked Larry if he thinks the FutureGen RD&D is going the wrong 

direction with oxygen-blown IGCC. Larry Monroe answered no because he is in favor of 

looking at all different options. 

Mike Surface expressed that in his opinion, supercritical and ultra-supercritical units would be 

good with membranes on the back-side. He acknowledges that this development is years away, 

but the operational systems on the back-end would be less complicated.

2) RD&D Spending

Nick Hutson asked if there is a feeling that we aren’t spending enough money on R&D?

Gary Rochelle said that more demonstration money is needed.

Larry Monroe opined that the industry will need a lot of help if it needs to move at the pace at 

which society demands CCS. He stated that while the Clean Coal Power Initiative (CCPI) is 

good, multiple demonstration projects are needed – and therefore continued funding by the 

federal government beyond CCPI 3. He added that doing projects (particularly sequestration) in 

close proximity to Southern Company’s plants is important for the regulatory commissions in 

Alabama. Thus, while international projects are helpful, multiple projects will be needed 

domestically just to get them close enough to where the new plants might be built. 

Praveen Amar agreed, adding that demonstrations at scale with 4 or 5 different sites with 

different coals, different geologies, and different sites will be necessary for CCS to be considered 

acceptable and commercial.

Jose Figueroa said that if a lot of money is invested upfront, the demonstrations will take place 

repeatedly for the more mature technologies which have high energy penalties. He thinks the 

emerging technologies, which show promise with respect to lowering the energy penalty, would 

then have difficultly gaining market entry and market share due to the expected time for 

commercial readiness. How to avoid the situation where legislation is based on higher penalty 

technologies, thereby having deployment based on technologies that were demonstrated first 

needs to be in the discussion.

Ben Yamagata agreed, but added that more robust programs need to be considered. Speaking 

from the perspective of the Coal Utilization Research Council (CURC), he stated that a robust 

R&D program requires at least $500M/year over the next 15 years. Demonstration projects 
22

across different coal types and geographies, on the other hand, would require $20B over the next 

15 years. He also believes that we need to incentivize large scale fully commercial projects that 

are looking to capture large amounts of CO2 for use in EOR, which would cost another $20B. So 

just for demonstrations, we would be looking at well over $40B over the next 15-20 years, 

minimum. He added that currently there are $1B in tax credits, about $1B in CCPI programs 

over the last year, and $5-6B in loan guarantees for coal based projects—thus, in his opinion, we 

are not anywhere close to the amount of investment required to establish commercial 

acceptability from a regulatory standpoint.

George Offen agreed with Jose that current technology demonstrations should not be replicated, 

but added that in order to demonstrate storage—which is necessary to speed the development of 

CCS—the mature technologies have to be demonstrated now.

Jose Figueroa stated that capturing CO2 presents a different set of circumstances. He thinks the 

emerging technologies coming up need to be funded; there is a lot of research going on at 

research and industrial level and a lot of technologies are showing great promise at lab-scale. His 

concern is that by the time the emerging technologies get to large scale pilot demonstration, we 

will have demonstrated amines and the opportunities for emerging technologies may not be as 

readily available.

Frank Princiotta added that there is danger moving forward with demonstrating uncertain 

technologies. From his experience, billions of dollars have been spent for many clean coal 

technologies for commercial scale demonstration, and many of them have not moved forward. 

He warned against jumping the gun on demonstrating new technologies.

Larry Monroe stated that Southern Company learned a great deal from four Clean Coal projects 

in the 1990s, noting successful learning from low-NOx retrofit and SCR demonstrations. He 

added that all of Southern Company’s FGD technologies have been developed out of the DOE 

Clean Coal research programs. 

Frank Princiotta clarified that he was talking about transformational technologies: e.g., 

chemical coal cleaning, oil shale. His point is that what is needed is a transformation in how 

energy is generated and past experiences have not demonstrated a good record concerning

investments in those endeavors.

3) Mercury and other pollutant effects on capture systems

Nick Hutson shifted the conversation to discussing any mercury control issues (and other 

pollutants) or requirements specific to the application of GHG mitigation technologies. From his 

understanding, carbon capture systems negate mercury issues before the flue gas is emitted.

Larry Monroe added clarification, noting the concern about mercury and other substances on 

the flue gas are on the inlet of the CCS system—and these other pollutants, particularly sulfuric 

acid, SO2, HC, HF, particulates, which could impact the operation of the CO2 capture system. 

The question is how thoroughly will we have to pre-treat flue gas to meet the requirements of a 
23

given capture system. It them becomes an issue of economic trade-off: how much do we clean 

the flue-gas vs. how often do we replace solvent/materials?

4) Policy impacts on developing technologies

Nick Hutson shifted the discussion to how policies might impact both near-term and developing 

technology options.

Anna Wood said that EPA recently announced the proposal of a light duty vehicle rule; when it 

becomes final (anticipated in March, 2010), it will automatically trigger a PSD (prevention of 

significant deterioration) permitting program under the Clean Air Act (CAA). She stated that all 

the issues discussed today are front and center and will be important in addressing that program 

and the policies that EPA will pursue.

Praveen Amar added that the CAA Advisory Committee subgroup will discuss a PSD

determination for stationary sources; this will be discussed in a policy context. He said that states

are suggesting that we need practical guidance by next year to determine PSD.

Anna Wood clarified that the PSD is not only for power sector, but for all industrial sectors; it’s

unrealistic to think that all industrial sectors will move forward with CCS at the same time. 

Nick Hutson moved the discussion to the potential co-benefits associated with deployment of 

specific technologies. He anticipates further reductions in other pollutants through the

installation of capture systems and asked for comments.

Gary Rochelle pointed out that amine scrubbing will remove SO2, but it may increase NOx. 

Nick Hutson asked if there are any effects of NOx on the capture system. Gary Rochelle 

answered that it remains to be seen.

Nick Hutson asked: What is known about possible environmental implications of different GHG 

mitigation technologies, including possible ways to minimize or eliminate these? He asked for 

specific comments on water usage and hazardous waste generation.

Larry Monroe commented that there is the potential slip of reagents from the capture process.

Frank Princiotta commented on the additional mining of 25%-30% coal, drainage mining 

problems. There are life-cycle consequences associated with CCS.

Robert Wayland noted the scrubber sludges and other sludges that could come out of CCS 

process, generating another waste stream that would have to be managed. 30% more coal means 

30% more fly-ash.

Gary Rochelle disagreed, stating that there is no guarantee that more coal will be burned—he 

thinks we will likely replace power with other fuels sources.
24

5) Expected date for availability of CCS

Nick Hutson recalled earlier discussion on this issue as indicating that carbon capture is 

available in the near-term, but that sequestration dictates the timeline for the whole integrated 

process. EOR may be an easier initial option because the permitting process for sequestration 

will be complicated.

Gary Rochelle returned to the FGD analogy, saying that we are now an order of magnitude 

ahead in terms of knowledge of amine scrubbing. He thinks that since we know that we can 

capture carbon with an amine scrubber at 400 MW scale, the question is not technical but 

economic. The risks are primarily economical. William Stevens added that it is a question of 

how the amine scrubber will affect the power plant—in other words, it remains to be seen if a 

400 MW plant will work with an amine system on it. 

6) Use of CCS on natural gas (NG) and oil-fired units:

Nick Hutson recalled that the general consensus for CCS on NG units is that it is not 

economically viable. 

Robert Hilton stated that there is already demonstration on oil and there will be two 

demonstrations on NG. He said current carbon legislation would necessitate CCS on NG and oil 

units unless nuclear units carry the load.

Gary Rochelle asserted that this is a demonstration issue, noting that Mitsubishi and Fluor are 

building systems with traditional NG combustion. They aren’t operating like power plants, but 

they are demonstrating it. His guess is that with NG units the 6% CO2 concentration is 6% rather 

than 12%, so it’s twice the volume per ton.

Theresa Pugh stated that the CAA is agnostic; it goes after the pollutant. In her view, gas will be 

regulated just as coal will, so we will eventually have to look at CCS for gas, but it will be wiser 

to start with certain applications first. Gasification facilities which will be regulated under CAA 

as well, it may make more sense to look at other industries before proceeding to the power 

industry.

7) What are realistically achievable deployment ramp rates for new nuke and coal + CCS 

capacity during the first 20 years after the technologies become commercially available?

Gary Rochelle recalled that with FGDs, we always worried about whether or not we could get 

all the materials and supplies, but we did it. His impression is that if they need to be built, then 

somebody will step forward and build it.

Jose Figueroa reminded that there was a different industry profile in 1970s and 80s than today. 

Plants were being built and resources and manpower were available. He contends that today, 

relative to then, we may not have the same resources available.
25

Larry Monroe added that FGD did not establish deep penetration until after 2000—and we are 

still building, and we are probably only half way through the utility fleet.

Frank Princiotta agreed, noting that if we expanded nuclear, we would push the technology to 

the limit because worldwide supply of uranium and forgings is scarce.

8) New technologies that capture CO2 as a solid waste or useful by-product

Gary Rochelle thinks that the quantity of CO2 that will be produced will pre-empt the potential 

for useful product. Larry Monroe agreed but thinks that while CO2 from power plants is good 

for growing algae, but it should not be considered a sequestration option because it will 

eventually be emitted to the atmosphere. Mike Surface agreed, stating that algae have no impact 

on negating CO2 emissions. Jose Figueroa noted a study in Arizona that concerns FTR 

membranes, capturing CO2 and feeding it into an algae pond. 

Theresa Pugh said a very useful use of CO2 is to inject on the outer-continental shelf of the U.S.

to bring up additional oil and gas. Robert Hilton added that the same application of CO2 could 

be used for the gulf coast. Theresa Pugh agreed, saying that injection along the outercontinental shelf would appease concerns about geo-sequestration and drinking water, in 

particular.

9) How does geography affect mitigation options? Is Water availability a concern? What

if technologies are applied at higher altitudes? 

Praveen Amar took the opposite point of view, raising the issue that the CO2 mitigation option 

will determine the location of the power plant. He asked: if CCS is required in the future, where 

would you put a plant?

Robert Hilton provided an example with the steel industry, where steel plants went to where the 

coal and iron ore was; but the paradigm shifted as they realized it was better to locate plants in 

1) the most environmentally friendly places; 2) cheap power markets; and 3) close proximity to 

farmers (because farmers are less afraid of hazardous waste). Accordingly, Robert Hilton thinks 

the strategic location of CCS plants will follow the same paradigm.

10) Feedback on impressions of promising CO2 capture and mitigation options that are 

early in development:

Mike Surface expressed interest in designer molecules—both solvents and sorbents—that show 

promise for improved performance. He added that chemical looping is also an attractive option

in early stage.

Gary Rochelle has a dim view of such solvents, saying that the cheaper molecules will be 

sufficient for removing impurities from coal. He has less optimism about the work being done on

sophisticated organic molecules. 
26

Marty Lail commented that over time the degradation of the solvent when reacting with flue 

gases is an issue if you tailor a molecule to have a regeneration temperature smaller than what is 

required for MEA.

Gary Rochelle stated that in spite of intuitive feel of solvents, if you try to tailor solvents you 

should be looking for a higher heat of reaction because that would make the thermal swing 

absorption stripping system work better. He thinks that 90% of the solvent research right now is 

screening the wrong thing (lower heats of reaction). Mike Surface said the problem is energy—

the energy costs would be so high that there must be a balancing point. Gary Rochelle

responded that though it is unintuitive, you get better energy with a higher heat of reaction.

Nick Hutson asked for the audience’s impressions of solid sorbents? 

Larry Monroe said he is still waiting to see results from research programs, so it is too early to 

tell.

Jose Figueroa stated that the issue with sorbents is material management and process 

integration; he asked: If it is a solid sorbent, what’s the process and how is it integrated into the 

plant? If it’s a sorbent, how can you move that sorbent around and how will that effect the 

sorbent? He thinks that no matter how you approach it, the issues are material handling and 

process. A lot of researchers aren’t looking at the process and how they are going to put the 

process and the sorbent together in a power plant.

11) Suggestions for fields in the database

William Stevens suggested a field accounting for the consequences of doing nothing and the 

associated cost to global economies. Nick Hutson thinks that it is too difficult to agree on what 

those consequences are. Theresa Pugh said it depends on what your endangerment 

determination is based on: it’s going to be public welfare, public health, or both. She stated that 

EPA will make the determination and regulate that for us. In her opinion, EPA has all the data to 

make a determination and she thinks the use of the database is to help influence the regulatory 

decisions made, and she recommends that the database includes practical information on what 

technologies are available in the short term (e.g., energy efficiency). 

Praveen Amar added that the database should include qualitative information, which could be 

just as useful as the quantitative information. He thinks a comment section could be very helpful.

Mike Surface suggested a field for CO2 product quality because the analysis of CO2 can 

determine what type of pipeline you are going to build.

Ben Yamagata suggested a field indicating where the technology has been applied and what 

kind of field source it’s been applied to.

Jose Figueroa asked what the cut off is for technologies in terms of scale, warning that 

demonstration technologies will have much less information available. Nick Hutson said that 

EPA is starting with the low-hanging fruit and has not yet determined the cut off point, which 

may depend on funding.
27

Jose Figueroa suggested fields for projected capture rates and references to support publicly 

available data. Jim Staudt stated that for every field in the database, there will be references for 

every technology so that the user can learn more about it (may include hyperlinks).

Jose Figueroa said that it would be useful to have information on technical barriers for 

technologies and how researchers are addressing these barriers.

Anna Wood stated that permitting authorities will be interested in life-cycle impacts. 

Nick Hutson responded that life-cycle impacts will be difficult to quantify but may be included 

in the qualitative comment sections.

Jose Figueroa suggested that from a financial and insurance perspective, it would be useful to 

have a reference tool-type section that provides analysis concerning CCS. He said this could be 

simply a section showing that a finance study was completed.

Ben Yamagata asked if there was a timeline established and if there would be periodic status 

updates. Nick Hutson responded that the goal is to have the first version of the database by June, 

2010. 

John Sorrels asked what the format of the database will be. 

Alexis Zubrow stated that the exact format is still under review; it will be web-based and easily 

adaptable because it will need to be constantly updated with data. Nick Hutson added that the 

functionality of the database will be updated as well, and the user will have the ability to 

download data into Access or Excel.
Appendix A

Attendees List
A-1

United States

Environmental Protection Agency

Air Pollution Prevention and Control

Greenhouse Gas Mitigation Technologies 

Workshop

EPA Research Triangle Park Campus

Research Triangle Park, NC

Tuesday, November 3, 2009 

Final List of Participants

Praveen Amar

Director, Science and Policy

NESCAUM

89 South Street - Suite 602

Boston, Mass 02111

617-259-2026

Fax: 617-742-9162

Email: pamae@nescaum.org

William Brownell

Partner

Hunton & Williams

1900 K Street, NW 

Washington, DC 20006

202-955-1555

Fax: 202-778-2201

Email: bbrownell@hunton.com

Ward Burns

Air Permitting and Compliance

Air and Waste Management - Region 7

U.S. Environmental Protection Agency 

901 North 5th Street (AWMD/APCO)

Kansas City, KS 66101

913-551-7960

Fax: 913-551-9960

Email: burns.ward@epa.gov

John Chang

Engineer

Air Pollution Technology Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-03 109)

Research Triangle Park, NC 27711

919-541-3747

Fax: 919-541-0554

Email: Chang.John@epa.gov

J. Edward Cichanowicz

Consultant for the Utility Air 

Regulatory Group

P.O. Box 905 

Saratoga, CA 95071

408-395-1085

Fax: 408-395-1085

Email: ec@jecinc.info

Luke Coleman

Center for Energy Technology

RTI International

3040 Cornwallis Road 

Research Triangle Park, NC 27709

919-541-6840

Fax: 919-541-8002

Email: lcoleman@rti.org

Christian Fellner

Engineer

U.S. Environmental Protection Agency

109 TW Alexander Drive (D243-01)

Research Triangle Park, NC 27711

919-541-4003

Fax: 919-541-5450

Email: fellner.christian@epa.gov

Jose Figueroa

Project Manager

National Energy Technology Laboratory

Existing Plants Division

U.S. DOE

626 Cochran Mill Road (922-321)

Pittsburgh, PA 15236

412-386-4966

Fax: 412-386-4604

Email: Jose.Figueroa@netl.doe.gov

David Foerter

Executive Director

Institute of Clean Air Companies

1730 M Street, NW - Suite 206 

Washington, DC 20036

202-457-0911

Fax: 202-331-1388

Email: dfoerter@icac.com

Raj Gaikwad

Vice President

Advanced Fossil Power Technologies

Sargent & Lundy

55 East Monroe 

Chicago, IL 60603

312-269-3830

Fax: 312-269-2499

Email: rajendra.gaikwad@

sargentlundy.com

Erin Gorman

Air Policy Manager

PSEG

80 Park Plaza - 17th Floor

Newark, NJ 10128

973-430-6359

Fax: 973-624-9047

Email: erin.gorman@pseg.com

Scott Heacock

Senior Analyst

GAO

441 G Street, NW 

Washington, DC 20548

202-512-2850

Fax: 202-512-2850

Email: heacocks@gao.gov
A-2

Robert Hilton

Vice President, Power 

Technologies for Government Affairs

Allstom

801 Pennsylvania Avenue, NW 

Suite 85 5th Floor - West tower

Washington, DC 20004

202-495-4965

Fax: 202-495-4961

Email: robert.g.hilton@power.alstom.com

Nick Hutson

Research Chemical Engineer

Office of Research and Development

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-01)

Research Triangle Park, NC 27705

919-541-2968

Fax: 919 541-0554

Email: hutson.nick@epa.gov

Jeffrey Ingraham

Manager of Power Generation Strategies

Strategic Engineering

Progress Energy

410 South Willmington Street (PEB 07)

Raleigh, NC 27519

919-546-3847

Fax: 919-546-4576

Email: jeffrey.ingraham@pgnmail.com

Timothy Johnson

Physical Scientist

Office of Research and Development

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-02)

Research Triangle Park, NC 27711

919-541-0575

Fax: 919-541-7885

Email: johnson.tim@epa.gov

Mary Johnson

Environmental Engineer

Office of Air Quality Planning & Standards

Sector Policies and Programs Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (D243-01)

Research Triangle Park, NC 27711

919-541-5025

Fax: 919-541-5450

Email: johnson.mary@epa.gov

Wojciech Jozewicz

Department Manager

ARCADIS

4915 Prospectus Drive - Suite F 

Durham, NC 27713

919-544-4535

Fax: 919-544-5690

Email: wojciech.jozewicz@arcadis-us.com

Marty Lail

Air Pollution Technology Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-01)

Research Triangle Park, NC 27711

919-541-3871

Fax: 919-541-0554

Email: lail.marty@epa.gov

William Linak

Air Pollution Technology Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-01)

Research Triangle Park, NC 27711

919-541-5792

Fax: 919-541-0554

Email: linak.bill@epa.gov

Dan Loughlin

Environmental Scientist

Air Pollution Technology Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-02)

Research Triangle Park, NC 27711

919-541-3928

Fax: 919-541-7885

Email: loughlin.dan@epa.gov

Aaron Marks

Research Assistant

Department of Engineering 

and Public Policy

Carnegie Mellon University

5000 Forbes Avenue 

Pittsburgh, PA 15213

978-852-3331

Fax: 412-268-1089

Email: amarks@andrew.cmu.edu

Douglas McKinney

Assistant Lab Director for Global Change, 

Mercury, and Sustainability

Immediate Office of the Director

National Risk Management 

Research Laboratory

U.S. Environmental Protection Agency

109 TW Alexander Drive (E-343-04)

Research Triangle Park, NC 27711

919-541-3006

Fax: 919-541-5227

Email: mckinney.douglas@epa.gov

Andy Miller

Branch Chief

Atmospheric Protection Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-02)

Research Triangle Park, NC 27711

919-541-2920

Fax: 919-541-7885

Email: miller.andy@epa.gov

Larry Monroe

Senior Research Consultant

Research and Environmental Affairs

Southern Company

600 North 18th Street - Bin 14N-8195 

P.O. Box 2641

Birmingham, AL 35291

205-257-7772

Fax: 205-257-5367

Email: lsmonroe@southernco.com

Thomas Nelson

Research Chemical Engineer

Center for Energy Technology

RTI International

3040 Cornwallis Road - Johnson Building

Research Triangle Park, NC 27709

713-942-7864

Fax: 919-541-8002

Email: tnelson@rti.org

George Offen

Senior Technical Executive

Electric Power Research Institute

3420 Hillview Avenue 

P.O. Box 10412

Palo Alto, CA 94303

650-855-8942

Fax: 650-855-8759

Email: goffen@epri.com

Theresa Pugh

Director, Environmental Services

American Public Power Association

1875 Connecticut Avenue NW 

12th Floor

Washington, DC 20009

202-467-2943

Fax: 202-467-2910

Email: tpugh@appanet.org

Gary Rochelle

Professor

Department of Chemical Engineering

University of Texas

512-471-7230

Email: gtr@che.utexas.edu

Brian Shrager

Environmental Engineer

Office of Air Quality Planning & Standards

Sector Policies and Programs Division

U.S. Environmental Protection Agency

109 TW Alexander Drive

Research Triangle Pakr, NC 27711

919-541-4789

Fax: 919-541-5450

Email: shrager.brian@epa.gov
A-3

Carl Singer

Associate Project Manager

ARCADIS

4915 Prospectus Drive - Suite F 

Durham, NC 27713

919-544-4535

Fax: 919-544-5690

Email: carl.singer@arcadis-us.com

David Solomon

Office of Air Quality Planning & Standards

Sector Policies and Programs Division

U.S. Environmental Protection Agency

109 TW Alexander Drive 

Research Triangle Park, NC 27711

919-541-5375

Fax: 919-541-5375

Email: solomon.david@epa.gov

John Sorrels

Economist

Air Benefit and Cost Group

Health & Environmental Impacts Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (C439-02)

Research Triangle Park, NC 27711

919-541-5041

Fax: 919-541-0839

Email: sorrels.larry@epa.gov

Ravi Srivastava

Chief, Air PollutionTechnology Branch

Air Pollution Technology Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E-305-01)

Research Triangle Park, NC 27711

919-541-3444

Fax: 919-541-0554

Email: srivastava.ravi@epa.gov

William Stevens

Senior Advisor - Power Technology

Office of Atmospheric Programs

U.S. Environmental Protection Agency

1200 Pennsylvania Avenue, NW (6204J)

Washington, DC 20460

202-343-9642

Fax: 202-343-2359

Email: stevens.william@epa.gov

Kumar Sugavanam

Technical Marketing Manager

BASF Corporation

1111 Bagby Street - Suite 2600 

Houston, TX 77002

713-759-3020

Fax: 713-759-3031

Email: kumar.sugavanam@basf.com

Mike Surface

Engineer III

Dominion

5000 Dominion Boulevard 

Glen Allen, VA 23060

804-273-2530

Fax: 804-273-3614

Email: Mike.Surface@dom.com

Hiroaki Tokuchi

Deputy General Manager

Environmental Systems Division

Mitsubishi Heavy Industries America, Inc.

630 Fifth Avenue - Suite 2650 

New York, NY 10111

212-397-6117

Fax: 212-262-3301

Email: hiroaki_tokuchi@mhiahq.com

Dr. Robert J. Wayland

Leader, Energy Strategies Group

Ofice of Air Quality Planning & Standards

Sector Policies and Programs Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (D243-01)

Research Triangle Park, NC 27709

919-541-1045

Fax: 919-541-5450

Email: wayland.robertj@epa.gov

Anna Marie Wood

Senior Policy Analyst

Office of Air and Radiation

Office of Policy Analysis and Review

U.S. Environmental Protection Agency

1200 Pennsylvania Avenue, NW (6103A)

Room 5442 ARN

Washington, DC 20460

202-564-1664

Fax: 202-564-1554

Email: wood.anna@epa.gov

Ben Yamagata

Executive Director

Coal Utilization Research Council (CURC)

1050 Thomas Jefferson Street, NW 

Washington, DC 20007

2022981857

Fax: 2023382416

Email: bny@vnf.com

Andy Yaros

Manager - Fossil & Hydro Operations

Dominion Resources

5000 Dominion Boulevard 

Glen Allen, VA 23060

804-314-5725

Fax: 804-273-4550

Email: andy.yaros@dom.com

Will Yelverton

Engineer

Air Pollution Technology Branch

Air Pollution Prevention & Control Division

U.S. Environmental Protection Agency

109 TW Alexander Drive (E305-01)

Research Triangle Park, NC 27711

919-541-9737

Fax: 919-541-0554

Email: yelverton.william@epa.gov

Yongxin Zhao

Projet Enginer

ARCADIS

4915 Prospectus Drive - Suite F 

Durham, NC 27713

919-541-1333

Fax: 919-544-5690

Email: yzhao@arcadis-us.com

Alexis Zubrow

UNC Chapel Hill - Institute 

for the Environment

137 East Franklin Street (CB6116)

Chapel Hill, NC 27599

919-966-1395

Fax: 919-843-3113

Email: azubrow@unc.edu

Contractors

Clint Burklin

ERG

1600 Perimeter Park Drive - Suite 200

Morrisville, NC 27560

Email: clint.burklin@erg.com

Tim Chung

ERG

1600 Perimeter Park Drive - Suite 200

Morrisville, NC 27560

Email: tim.chung@erg.com

Bryan Lange

ERG

1600 Perimeter Park Drive - Suite 200

Morrisville, NC 27560

Email: bryan.lange@erg.com

James Staudt

President

Andover Technology Partners

112 Tucker Farm Road 

North Andover, MA 01845

978-683-9599

Fax: 978-683-9599

Email: staudt@andovertechnology.com

Jody Tisano

ERG

1600 Perimeter Park Drive - Suite 200

Morrisville, NC 27560

Email: jody.tisano@erg.com
Appendix B

Workshop Agenda
B-1

United States

Environmental Protection Agency

Air Pollution Prevention and Control

Greenhouse Gas Mitigation Technologies Workshop

EPA Research Triangle Park Campus www.epa.gov/rtp

Research Triangle Park, NC

Tuesday, November 3, 2009 

9:00am - 4:00pm

Conference Room C111A,B

Workshop Agenda

8:30 – 9:00 AM Attendees arrive at EPA RTP Campus (see www.epa.gov/rtp for a campus map), Enter 

building through main entrance, go through entrance security, sign-in at front desk, and 

proceed downstairs to workshop check-in just outside of RM C111B. 

Note: The conference room is very near the cafeteria, which will be serving coffee and 

breakfast if desired.

9:00 – 9:10 AM Introductions - attendees will be asked to introduce themselves (i.e., name, affiliation and 

background/interests)

9:10 – 9:20 AM Introduction and discussion of workshop agenda and objectives

Nick Hutson, EPA ORD

9:20 – 9:30 AM Welcome

Frank Princiotta, Director, Air Pollution Prevention & Control Division, EPA Office of Research 

& Development (ORD)

9:30 – 10:30 AM Discussion and identification of available technologies, strategies and options for 

GHG mitigation from EGUs.

10:30 – 10:45 AM BREAK 

10:45 – Noon Discussion of cost, performance and availability of various technologies, 

strategies and options.

Noon – 1:00 PM Lunch – EPA Cafeteria

1:00 – 2:30 PM Discussion of barriers (technical and non-technical) to implementation of the 

various technologies, strategies and options.

2:30 – 2:45 PM BREAK

2:45 – 4:00 PM Continuation of discussion, identification of promising (but still early stage) 

technologies, wrap-up and summary of workshop.
Appendix C

Technical Presentation and Supporting White Papers

Technical and Non-technical Challenges of Sequestration Presentation

Geologic CO2 Sequestration Issue Spotting and Analysis

Will Water Issues/Regulatory Capacity Allow or Prevent Geologic 

Sequestration for New Power Plants?
Appendix C 

Technical Presentation and Supporting White Papers 

Technical and Non-technical Challenges of Sequestration Presentation 

Geologic CO2 Sequestration Issue Spotting and Analysis 

Will Water Issues/Regulatory Capacity Allow or Prevent Geologic 

Sequestration for New Power Plants? 
Sober Thou

for Retrofi

Plants as

a 

Measure fr

Theresa PughDirector, Envir

American Pub

EPA GHG Miti

Research TrianNovember 3, 2
• APPA represents the interests of the 2,010 munic

power utilities, which provide electricity to reside

commercial and industrial customers.

• Created in 1940 as a non‐profit, non‐partisan org

• APPA’s purpose is to advance the public policy in

members and their consumers, and to provide m

ensure adequate, reliable electricity at a reasona

proper protection of the environment.

• Public Power provides electricity for approximate

Americans.

• Public power utilities are in small, medium and la

in 49 states (all but Hawaii). Seventy percent of p

systems are located in cities with populations of 

• Overall, public power accounts for about 16 perc

hour sales to consumers. More than 90% of APPA 

meet the definition and qualify under Small Busin

Enforcement and Fairness Act of 1996 (SBREFA).

• Over half of APPA‘s members in the electricity se

particularly in the Midwestern and Southeastern 

country. 

Background on the American Public Pow

Public Power Generation (MWH) by Energ

Source: Ventyx (formerly Energy Velocity) Database
• Most Favorable Locations

– Deep Saline Aquifers

– Proximity to CO2 pipelines

– No or extremely low Seismic Potential

– Proximity to Transmission

– Proximity to Rail for Coal Transportatio

• Least Favorable Locations

– Moderate or High levels of Seismic Pot

– Unfavorable geology

– Lack of Transmission and/or rail for co

transportation

Assessing Preliminary Guesses for M

Favorable Locations for CC
Deep Saline Aquifer Locatio
Deep Saline Aquifer Locations & ‘Len
Deep Saline Aquifer Locations & ‘Strin
Saline Aquifers, CO2 Pipelines, & ‘Len
Other Considerations – Transmiss
Other Considerations – Railro
Optimal Sites – Using Existing CO2 
Optimal Sites – Not Requiring Proximity t
Natural Gas Pipelines

In case Fuel Switching to Natural Gas is the GHG Mitigation 

Interstate Pipeline Shortage
Natural Gas Storage
States with UIC Primacy:

CO2 Injection Most Likely Under 

Source: http://www.epa.gov/ogwdw000/uic/primacy.html 
“Best Guess” Timeline for Baseload 

CCS Plant in Non‐EOR/EGR St
Subsurface space required for only 4

Carbon Dioxide from a 300 MW p

for one year:

2,750 Ac

Source: J. Gledhill, Policy 
Subsurface space required to seque

the Carbon Dioxide from approxim

Nine 500 MW Plants over their 40‐y

2,580 s

Roughly 

size of R

Roughly 

Connect
2009 EPRI Prism analysis assumptions:

– 90% CO2 capture for all new coal and natu

combined‐cycle plants built after 2020

– CCS retrofit for 60 gigawatts of existing co

90% capture efficiency

For Retrofit of 60 GW @ 90% capture effic

– Approximately 77,400 square miles of sub

– Roughly the size of Nebraska or

– Roughly twice the size of Maine

PLUS area for 90% capture for all new foss

after 2020. This is highly dependent upoaccess to CO2 pipelines – all geology can

sequestration for 50 years continuously

EPRI “Prism” Analysis
• Parasitic Energy Losses

• Capital Requirements for Older Plants

• Pipelines• Dealing with Financing older plants

• Lucky Location?• Lucky Geology

• Proximity to USDW (drinking water sou

protective regulations

Retrofit of Existing Fossil Plants: How 
Dealing with approx. 30% Parasitic Energ

Designing New Plants or Retrofitting 

Source: Adapted from L.D. Carter, White Paper, "Retrofitting Carbon Capt

Existing Coal‐fired Power Plants," November 2007

Parasitic Energy Loss refers to power lost from existing pla

the technologies related to CCS which are circled in the ab
Source of Map: NatCarb Atlas; Overlay: APPA Optimal Location Criteria Ma

Note: Optimal Locations are for new plants, not retrofit of existing power 

Existing Fossil Generation & Optimal CC

Without Any Drinking Water Resource Loc
Available at http://www.appanet.org/files/htm/ccs.html

• Marianne Horinko, "Carbon Capture and Sequestration 

Environmental Challenges Ahead," August 2007

• L.D. Carter, "Carbon Capture and Storage From Coal‐ba

White Paper on Technology for the American Public Po

(APPA)," May 2007

• L.D. Carter, "Retrofitting Carbon Capture Systems on Ex

Power Plants," November 2007

• Jonathan Gledhill, Policy Navigation Group; James Rolli

Group; Theresa Pugh, APPA, White Paper, "Will Water 

Capacity Allow or Prevent Geologic Sequestration for N

Review of the Underground Injection Control Program a

and Storage," November 2007

• Carbon Capture and Storage: Analysis of Potential Liab

Groundwater Contamination Due to Geological SequesSeptember 10, 2008

Prepared by Fredric P. Andes and Kari A. Evans, membe

Thornburg LLP Water Team, for the American Public Po

(APPA)

• Timothy Gablehouse, White Paper, "Geologic CO2 Issue 

Analysis" July 2009 

APPA’s White Papers on CC
Link to APPA’s White Papers on CCS:

http://www.appanet.org/files/htm/ccs.htm

• For More Information, Contact:

Theresa Pugh

Director, Environmental Services

202‐467‐2943TPugh@APPAnet.org• For Questions on CCS Maps, Contact:

J.P. BlackfordEnvironmental Services Engineer

202‐467‐2956JPBlackford@APPAnet.org

APPA’s CCS Information & Con
GEOLOGIC CO2

 SEQUESTRATION

ISSUE SPOTTING AND ANALYSIS WHITE PAPER

Timothy R Gablehouse1

Gablehouse Calkins & Granberg LLC

July 22, 2009

OBJECTIVE

This paper has been prepared for APPA’s electric utility members and water utilities for

the purpose of surveying the wide range of issues that will influence the implementation of

geologic carbon sequestration. As with many things, sequestration is not as simple as it seems. 

Injection of anything into the subsurface is regulated. Which agencies will act to regulate and

the criteria they will follow depends upon the answer to the questions raised in this paper –

questions that Congress and state legislatures will need to address if sequestration is to be

2

implemented on a scale remotely adequate to make a difference in the amount of CO reaching

the atmosphere.

Without a doubt sequestration projects will go forward. Many are already underway. 

Nothing in this White Paper should change anyone’s view on the technology available for

geologic sequestration. Nor should anyone read this paper to suggest that there are fatal legal

impediments to these projects. There are substantial legal issues and a prudent manager would

be well advised to factor these issues into the business plan for a sequestration project.

Much of this paper looks at the existing rules that apply to geologic sequestration. From

where we stand today it is these rules that will apply absent action by legislative bodies. For

example, if the CO2 being injected is a waste we next need to know if its hazardous waste and

Timothy Gablehouse is the managing partner of the environmental law firm of Gablehouse Calkins & Granberg

1

LLC in Denver Colorado. 410 17 St, Ste 1375 Denver CO 80202

th

tgablehouse@gcgllc.com

1
regulated under RCRA. If injection is limited to producing oil and gas operations for enhanced

recovery, then injection will be regulated by the state agencies that permit oil and gas

operations. The policies and procedures of these agencies and which permits might be required 2

are sometimes radically different state-by-state having the potential to drastically change the

regulatory burden and economics of any project. 

 Common law theories dealing with trespass, mineral rights and water rights all are

implicated as injection may result in trespass or harm to surface property rights, mineral rights or

water rights. Depending upon in which state injection operations occur, there are significant

questions regarding 2 the ownership and access to the subsurface spaces where the CO will be

placed. As the CO2 is intended to remain in the ground in perpetuity, then we also need to

examine who remains responsible in perpetuity. Regardless of whether these entities are private

corporations or public entities long-term liability issues will need to be address and understood. 

Absent new legislative action existing statutes such a CERCLA (“Superfund”) will play a role

which means that the landowner, mineral owner, injection operator and the entity that produced

2

the CO all may have some liability in perpetuity. 

It’s important to understand what this White Paper is not intended to accomplish. While

it will identify a broad range of property and liability issues associated with injection projects, it

will not suggest solutions to all of them. It will not address the range of liability issues

associated with the high-pressure pipeline infrastructure necessary to move acid gases from the

point of generation to the point of injection. For geolog 2ic CO sequestration to become broadly

viable there will need to be predictability on how these issues are handled. Many will have no

predictable solution until and unless we have federal and state legislation.

Acid gas injection for enhanced recovery of oil & gas is different from hydraulic fracturing which is also used to

2

enhance recovery by physically opening the subsurface formations using very high pressure, proprietary formulas

and particulates to hold the fractures open.

2
BACKGROUND

Much work ha 2s gone into the technical review of geologic CO sequestration. 

(Frequently this is referred to more generically as carbon capture and storage or “CCS” – the

remainder of this paper will utilize this nomenclature.) Some work has gone into potential

regulatory programs based upon extensions of the current EPA Underground Injection Control

(“UIC”) program. EPA has proposed a regulatory approach which is the topic of a September

10, 2008 White Paper available to readers. (As nothing has really changed on this front, this

White Paper will not cover that effort in any detail.)

Some states are adopting regulatory programs with various degrees of complexity. In

general they are based upon existing UIC programs or on injection of “acid gas” for production

enhancement in existing oil or gas operations. These can be radically different approaches and

the internal political situation along with the perceived importance of the oil and gas industry has

a large impact. 

It is critical to distinguish between production enhancement injection programs and

2

injection of CO solely for sequestration purposes as they are radically different in intent,

liability, risk and regulatory regime. A mineral owner typically has substantial rights to use

techniques such as fluid injection in order to produce the “minerals” like natural gas and

petroleum. Oil and gas production companies have substantial experience with this activity and

tend not to view it as very risky even though it’s currently benign regulatory posture is under

attack. 

As an example, the long-term liabilities associated with production enhancement versus

CCS scenarios have substantially different legal postures. For example, a land owner or even an

impacted neighbor may have products liability claims against the producer of the injected

3
enhancement fluid should it cause adverse impacts outside of the natural gas or petroleum

production pool. In a CCS project we would instead need to look to CERCLA or RCRA for 3

guidance 2 on long-term responsibility for the CO .

Not resolved to any satisfactory degree are the questions of legal access to property for

the purpose of CCS, whether it is waste disposal or something else, liability for the entire host of

things that people can imagine might go wrong, and long-term maintenance/monitoring. All one

need do is examine EPA’s 2008 Technical Support Document entitled “Vulnerability Evaluation

Framework for Geologic Sequestration of Carbon Dioxide” to get a sense of the complexity of

the problem and the difficulty of assessing potential risks. 

4

That these risks are a real concern when it comes to permitting and operation should be

obvious. Some examples may help to illuminate the risks that the public will fear:

- Fluid injection is suspected of causing Texas earthquakes. Wall Street Journal, June

12, 2009, Page A3.

- Earthquakes caused by deep well injection of wastes at Rocky Mountain Arsenal. 

http://earthquake.usgs.gov/regional/states/colorado/history.php

2

- Crystal Geyser UT – CO cold water eruptions through a manmade well. 

http://www.uweb.ucsb.edu/~glennon/crystalgeyser/

- 1986 Lake Nyos eruption and deaths.

- “CCS mobilization of hazardous, naturally occurring materials is a risk that must be

characterized.” “Injection into saline formations has the potential to disturb regional

ground-water flow systems and could contaminate drinking water.” Paraphrased

from the testimony of Dr. Burruss, USGS, Subcommittee on Environment and

Hazardous Materials, House Committee on Energy and Commerce, July 24, 2008

2

- Transportation infrastructure to transport CO to injection sites does not exist – USGS

projects that an infrastructure larger than the existing natural gas/petroleum industry

will be required to achieve meaningful levels of CCS. 

http://energy.er.usgs.gov/health_environment/CO2_sequestration/CO2_illustrations.html

See Modesto, City of v. The Dow Chemical Co., et al., No. 98-999345, Calif. Super., San Francisco Co. (liability

3

based on products liability theories found for dry cleaning fluid off-site impacts)

4

http://www.epa.gov/climatechange/emissions/downloads/VEF-Technical_Document_072408.pdf

4
ISSUES and DISCUSSION

I. Liability During Injection / Operational Liability

Operational liability includes the environmental, health, and safety risks associated with

CO2 capture, transport, and injection. Enhanced fluid recovery contractors are already subject to

a duty of care defined under tort law and are usually subject to standards of conduct under their

contractual arrangements. Companies providing these specific services have experience in their

industries, and are subject to liability for worker safety and property damage resulting from their

conduct. These companies are best positioned to manage the risks associated with their own

conduct and are able to obtain liability insurance for their conduct and workers. In surveys and 5

case studies, these companies were willing to provide services on a commercial basis and

generally willing to accept liability for their actions.6

However, it is foreseeable that large-scale CCS could make it less likely that companies

will be willing to accept liability for injection. For example, if there was contamination at the

surface during injection operations it could potentially affect drinking water. There is currently

no law protecting commercial or public operations from the full range of liabilities should they

cause contamination.

In theory government agencies could conduct the injection operations to limit liability

associated with injection. An example of this is Lawrence v. Buena Vista Sanitation District. 

7

Neighbors brought a trespass claim against the sanitation district, alleging contamination from

leakage at the district's wastewater treatment facility but did not argue that negligence was

M.A. de Figueiredo, D.M. Reiner, H.J. Herzog, Towards a Long-Term Liability Framework For Geologic Carbon

5

Sequestration, Presented at the Second Annual Conference on Carbon Sequestration, Alexandria, Va. May 2003.

Craig A. Hart, Advancing Carbon Sequestration Research in an Uncertain Legal and Regulatory Environment: A

6

Study of Phase II of the DOE Regional Carbon Sequestration Partnerships Program, Discussion Paper 2009-01,

Cambridge, Mass.: Belfer Center for Science and International Affairs, January 2009 (finding drilling companies

willing to participate in CCS and accept liability for their actions).

Lawrence v. Buena Vista Sanitation Dist., 989 P.2d 254 (Colo.App. 1999)

7

5
present. The court held that the district was immune from a trespass claim under Governmental

Immunity Act “unless negligence is proven”. Trespass is not a dangerous condition of a public

water facility or public sanitation facility; because the trespass claim did not require proof of

negligence it was barred by Governmental Immunity. Nobody should take this sort of outcome

as an indication that government agencies can conduct these operations with impunity – there are

many other available theories of liability. 

II. Post Injection Liability

A. Ownership of Pore Space

The surface owner usually owns pore space because mineral conveyances, including

leases, normally only pass title to the minerals, not the pore space itself. That does not, however,

end the conversation over who controls the pore space property right. The surface owner cannot

violate the mineral estate owner’s or lessees’ rights by doing something interfering with access

to the minerals, making the minerals more expensive to exploit or making the development of

the minerals economically impractical. Clearly injection into the pore space could cause this sort

of harm. The surface owner must also allow reasonable use of the property to give access to the

mineral estate. For CCS projects to proceed it is somewhat reckless to assume that agreement 8

with the surface owner is the only necessary step. It seems prudent to have agreements with

both surface and mineral owners even though it seems likely that the surface owner owns the

pore space. 

9

B. Risk of Leakage

Post-injection liability includes harm to human health, the environment, property, and the

climate liability related to leakage or migration of carbon dioxide from geological reservoirs and

Cassinos v. Union Oil, 14 Cal.App.4th 1785 (1993)

8

Geologic CO2 Sequestration: Who Owns the Pore Space?, 9 WY LR 98, 2009.

9

6
the effect on climate change. Potential pathways for carbon dioxide release include leakage

through the pores of low-permeability cap rocks if the carbon dioxide is injected at too high a

pressure, leakage through openings in the cap rock, leakage through abandoned or improperly

sealed wells, and migration via faults. 

10

Reportedly, there is a low risk of captured carbon leaking into the atmosphere in amounts

2

significant enough to pose a risk. CO and natural gas has been stored naturally in geologic 11

formations for millions of years and companies already store natural gas underground with a lot

of experience. The 2re are naturally occurring CO reservoirs in the western states that have held

gas for 2 millions of years. Furthermore, over 100 million tons of CO has been injected into oil

reservoirs for enhanced fluid recovery as well as into deep saline aquifers (over 80 projects have

been implemented worldwide). Commercial and experimental projects have shown the 12

potential for CCS across a wide range of geological settings. 

There are, however, reports suggesting that an exceptionally detailed analysis of geologic

conditions is critical to understanding 2 how the CO is being sequestered in each case. Whether

CO2 is being mineral trapped, in which case it may be stable on geologic time scales, versus

dissolution in groundwater is critical to an assessment of whether a potential for leakage is

present. Dissolution in groundwater is not preferred as it has the greatest potential for eventual

leakage to the atmosphere.13

The long 2-term liability associated with CO leakage that damages health or property is

difficult to establish because it is dissimilar to other regulatory schemes and has a timeframe of

thousands of years. We simply do not know what risks long-term geologic storage presents. 

IPCC, IPCC special report on carbon dioxide capture and storage; 2005.

10

Feidman, This work performed under the auspices of the U.S. Department of Energy by Lawrence Livermore

11

National Laboratory under Contract DE-AC52-07NA27344

Rocky Mountian Mineral Law Institute

12

Aeschbach-Hertig, Clean Coal and Sparkling Water, NATURE, Vol 458, Page 583, April 2009.

13

7
Exposure to CO2

 typically is not dangerous except in very high concentrations (> 15,000 ppm). 

For example, in Lake Nyos 1,500 people died when a lake over a magma pool released large

amounts of CO2. This is unlikely to occur at injection wells when properly monitored. 

Researcher 2s have successfully plugged and abandoned CO injection wells, even badly damaged

and fa 2iled wells. In wells that have failed and released CO , almost all were detected quickly and

stopped. 

14

EPA produced a July 2008 white paper entitled Approaches To Geologic Sequestration

Site Stewardship After Site Closure. They describe the advantages and disadvantages of 15

stakeholder developed models as well as models based upon existing federal laws ranging from

the Nuclear Industries Indemnity Act through CERCLA. If CCS is viewed as waste disposal the

“cradle-to-grave” model of the RCRA and perpetual nature of liability under CERCLA would be

2

inconsistent with any effort to limit responsibility for injected CO and especially any potentially

hazardous contaminants entrained in the injected materials. 

EPA’s ana 2lysis has been criticized as unrealistic given that geologic storage of CO is

intended to be indefinite and well beyond 50 years. The authors of a recent report view this as

the single greatest legal obstacle to commercial deployment of CCS. Quite obviously,

16

legislation will be required to address this issue if there is to be any time limit on liability.

C. Property Rights Issues Re 2lated to Migration of Injected CO

1. Natural Gas Storage Law May Provide Some Insight

S. Julio Friedmann, Carbon Management Program APL Global Security Principle Directorate, LLNL. .S.

14

Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344

15

http://www.epa.gov/OGWDW/uic/pdfs/support_uic_CO2_stewardshipforsiteclosure.pdf

World Climate Change Report, 87 WCCR, 05/08/2009, BNA.

16

8
Gas that is injected for storage remains the property of the injector. Injection of gas 17

into property that the injector does not own is a trespass. Pore space for such projects can be 18

purchased or leased from the landowner, and/or the mineral estate owner, so long as it does not

damage other persons. Agreement with the mineral estate owner or lessee will generally be 19

prudent in order to avoid later damage or trespass claims as there is ambiguity in some states

regarding whether a mineral owner owns the pore space previously occupied by the minerals,

natural gas or petroleum they have removed. Liability for negligent operation of storage

20

operations exists.21

Under many federal and state laws utility companies have eminent domain rights for

utility facilities. This begs the question of whether CCS operations represent a utility facility

under these statutes – if viewed as waste disposal, there is doubt. These statutes do not address

the ability to exercise eminent domain rights over buffer zones that may be desirable because of

the potential for gas migration. Buffer zones should be included because gas escape is a

trespass; however, how such a buffer might be valued in an eminent domain action is unknown.

With regards to carbon sequestration the concept of condemnation poses several

problems. CCS potentially involves large areas of land – hundreds of acres - depending upon the

subsurface conditions and resulting available storage volumes. The uncertainty over whether 22

statutory authority to exercise imminent domain applies suggests an initial effort to negotiate and

purchase rights. If injection requires approval from any landowner that could be affected, then it

Ellis v. Arkansas Louisiana Gas Co., 450 F. Supp. 412, 419 (D.C. OKL 1978) and many others

17

Kuntz, The Law of Oil and Gas s 2.6, p.71

18

Ellis, at 450 F. Supp. 412

19

Geologic CO2 Sequestration: Who Owns the Pore Space?, 9 WY LR 98, 2009.

20

In a recent case from Louisiana a jury awarded $9.2M to a petroleum company whose ability to exploit reserves

21

was adversely impacted by improper maintenance and operation of a neighboring salt dome storage facility.

Separation and capture of CO2 from large stationary sources and sequestration in geological formations--

22

coalbeds and deep saline aquifers. J Air Waste Manag Assoc. 2003 Jun;53(6):645-715

9
will be necessary to secure consent from a potentially large number of people. Negotiation and

condemnation will therefore impose high costs and long acquisition times. 

As it will not be the intent (in most cases) to later retrieve the gas, there are interesting

questions and serious unknowns regarding the rights and duties of the property owners later in

2

time. Establishing ownership of CO in perpetuity is a key part of this problem, especially given

the vast amounts of time it will be sequestered. If there is no intent to recover perhaps there is

no duty 2 to protect and preserve the CO or the associated surface facilities. If the entity that

owned the CO2 when it was injected disappears, then whether the CCS process is waste disposal

or something else will be critical to understanding the on-going duties of the landowner. Any

resolution of this issue will require legislation.

2. Enhanced Oil Recovery

Oil and gas leases typically contain the right to inject fluids to aid in the production of

gas or oil, but not for disposal of waste. Leases and state laws often give the producer the right

to “unitize” for secondary recovery allowing injection in various locations of a field. These

enhanced recovery 2 efforts are not necessarily designed to sequester CO even if “acid gas” is

used. Given the lease/contract rights these processes are probably not a good mechanism to

examine the broader liability issues associated with CCS projects unassociated with oil and gas

production. 

As noted before liability for the injected materials, such as hydraulic fracturing fluid or

acid gas, exists regardless of why these materials were injected. Contract or lease theories will

apply and may be of value in the short-term until the normal statute of limitations runs. Beyond

these theories liability is likely perpetual under federal environmental laws as these fluids will

10
typically contain hazardous substances. As noted earlier, products liability theories may apply to

the entity that produced the fluid if it harms third persons.

3. Waste Injection 

Wastewater wells are subject to permitting by EPA and/or states. Failure to obtain

permits or operate within the terms of a permit will make the operator subject to agency

enforcement and citizen suits. Obviously the party injecting must have the legal right to do so;

however, what those rights mean will be highly variable. In Chance v. BP Chemical, the

Supreme Court of Ohio determined that the defendant committed a trespass when chemicals

injected underground migrated under plaintiff’s property for which no rights had been acquired. 

Even so, the proper evaluation of damages is very uncertain. 

The court held that the surface owner’s rights were not absolute, but were contingent on

the reasonable and foreseeable use of their property. According to the court, subsurface rights 23

include the right to exclude invasions of the subsurface property that actually interfere with the

property owner’s reasonable and foreseeable use of the subsurface. This would most certainly 24

include harm to minerals or oil and gas resources leased by the landowner. 

This sort of analogy would work well for CCS because landowner’s that are not harmed

by 2 stored CO would have no cause of action. It seems to follow that there would only be a

cause 2 of action after CO specifically damages the health or property of a landowner – not for

speculation that gas could potentially leak from geologic formations or interfere with access to

minerals or oil and gas. Many courts would likely disagree and would find diminished value

simply due to the trespass. Legislation, rather than litigation, is by far the best way to establish

the rules in this arena.

Chance v. BP Chemical, 1995 WL 143827 (Ohio Ct. App 1995)

23

Id.

24

11
4. Wastewater

In Cassinos v. Union Oil Co., the owners of a mineral estate sued defendant for damages

when defendant injected wastewater into the mineral estate. The California Appeals Court

rejected the defendant’s claim that it should not be liable because the plaintiff did not establish

the extent of damage to the mineral estate. The court held that there was substantial evidence the

defendant’s actions interfered with and damaged the mineral estate. Therefore, the defendant

committed a trespass. The court also held that the plaintiff in the case could waive the tort claim

and collect on an alternative theory of contract implied in law to recover the value of the use

taken.25

From Chance (supra) and Cassinos, it is apparent that a cause of action is not likely to

occur if there is no damage done. Interference with mineral rights should be a concern because

CCS can displace subsurface gases and groundwater, which could damage mineral estates. The

holder of a mineral estate or lease would have a cause of action along with the surface owner.

If the activity is allowed by statute it does not necessarily mean that the injector will be

absolved of liability. In Tidewater Oil Co. v. Jackson, there were damages to plaintiffs' oil wells

as a result of water flooding operations conducted by defendant on adjoining property. The Court

of Appeals held that where defendant's water flooding activities were intentional and damage to

wells on adjoining land was foreseeable, defendant was liable under Kansas law for damage to

wells of adjoining leaseholders. 

These findings were inconsistent with the administrative findings to the effect that the

water flooding operations were carried on in a lawful manner. In the view the court took, it was

unnecessary to reconcile the findings. It was sufficient that the water flooding activities were

intentional and the consequences foreseeable. A legal claim was available, even though the

Cassinos v. Union Oil Co., 14 Cal.App.4th 1770, 18 C (Cal App 1993)

25

12
flooding was lawfully carried on, because it caused substantial injury to the claimants. This 26

case is important because it highlights that regulations that allow CCS may not absolve the

defendant of common law property law liability. 

4. Water Law

It most of the Western US surface and groundwater is a public resource dedicated to the

beneficial use of public agencies and private persons wherever they might make beneficial use of

the water. (Texas is a bit different in that groundwater belongs to the landowner and is not

subject to prior appropriation. That can result in significant fights between neighbors should one

pump so much groundwater that a neighbor’s well becomes dry. This law of the “biggest pump”

has been mitigated through administrative processes such as conservation districts regulating the

use of groundwater. ) Under the general western approach, including surface water in Texas, 27

water quality and quantity are property rights subject to statutory and common law protections. 

The biggest difference between water and real property is that the protections available for water

frequently exceed those available for real property. 

The right of water use includes the right to cross the lands of others to place water into,

occupy and convey water through, and withdraw water from the natural water bearing

formations within the state in the exercise of water use right. Natural water bearing formations

may also be used for the transport and retention of water. Water authorities can inject water for 28

later withdrawal with no payment for the pore space. The property rights of landowners or

mineral estate owners/lessees do not include the right to control the use of water in the ground

and cannot claim control of aquifers as part of their estate. Except for Texas, groundwater is part

of “waters of the state” and either by Constitution or statute, the general assembly of each state

Tidewater Oil Co. v. Jackson, 320 F.2d 157 (C.A. Kan. 1963)

26

Sipriano v. Great Spring Waters of America, et al., 1 SW3d 75 (Texas 1999)

27

Board of County Com’rs of County of Park v. Park County Sportsmen’s Ranch, 45 P.3d 693, 706 (Colo. 2002)

28

13
has control over the use and disposition of groundwater regardless of whether it is or is not

directly discharged to a natural stream. 

The law in most states prohibits the taking of private property for public or private use

without the property owner’s consent, but there are frequently exceptions which pertain to

constructed water facilities. For example many western state constitutions provide for access 29

to the water source across the lands of others and further recognize and address the private right

of condemnation for the construction of waterworks. There is a requirement for compensation 30

for use of another’s land, but that does not extend to employment of natural water bearing

subsurface formations on or within the landowner’s property for the movement of appropriated

water. An applicant for a conditional decree to utilize available aquifer storage space must 31

demonstrate that it will capture, possess, and control water lawfully available to it and without

injury to other water rights. 

32

Water storage under a landowner’s property is not a trespass if it does not inhibit the use,

benefit, or enjoyment of property. In Board of County Commissioners v. PCSR, LLP, PCSR 33

proposed to store water in underground aquifers underlying approximately 115 square miles. 

The landowners claimed that storage of water underground in aquifers underneath their land

would constitute a trespass. The Court held that it would not be a trespass and the project would

not require the Landowner’s consent or condemnation and the payment of just compensation

under the provisions of Article XVI. The court, in applying Causby, found that the project did 34

not include construction of any facilities on or in the Landowner’s properties and the

Colo. Const. art. XVI § 7

29

Colo. Const. art. II § 14

30

Sportsmen’s Ranch, at 45 P.3d 708

31

Id.

32

Sportsmens’s Ranch, 45 P.3d at 708

33

U.S. v. Causby, 328 U.S. 256 (1946) (ruled that property owner’s rights were not unlimited with respect to

34

airspace).

14
Landowner’s had not alleged that the use, benefit, and enjoyment of their properties would be

invaded or compromised in any way. Therefore, it was not a trespass. 

The court stated that the General Assembly, in authorizing the use of aquifers for storage

of artificially recharged projects further supplanted the Landowners’ common-law property

ownership theory. The court found it “particularly [significant]” that: 35

 (1) [F]ederal patents to land do not include water, (2) ground water is not a mineral

under the federal mining laws ..., (3) federal statutes as interpreted by the Supreme Court

recognize [a state’s] authority to adopt its own system for the use of all waters within the

state in accordance with the needs of its citizens, subject to the prohibitions against

interference with federal reserved rights, with interstate commerce, and with navigability

of any navigable waters, (4) the right of prior appropriation applies ... to waters of the

natural stream, including surface water and tributary ground water; (5) the property rights

of landowners do not include the right to control the use of water in the ground, whatever

the character of that water; and (6) the General Assembly has plenary control over the

use and disposition of ground water that is not part of the natural stream.36

In sum, the holders of water use rights may employ underground as well as surface water

bearing formations in the state for the placement of water into, occupation of water in,

conveyance of water through, and withdrawal of water from the natural water bearing formations

in the exercise of water use rights. Consent or just compensation was not required because the 37

plaintiffs did not have the right to restrict the defendant’s use of the water that was done within

regulations. 

CCS 2 presents a unique problem because the underground storage of CO could

potentially affect the flow and location of groundwater. This could occur because the process of

physical trapping may displace naturally occurring water and other gases. Any effect on water 38

resources could pose potential liability if it limits access to water that has already been

Id. at 703

35

Id.

36

Id. at 712

37

Statement of Dr. Robert Burrus, Research Geologist, Enerby Resources Team U.S. Geological Survey U.S. Dep.

38

Of the Interior Before the Subcommittee on Environement and Hazardous Materials House Committee on Energy

and Commerce Hearing on “Carbon Sequestration: Risks,

15
appropriated to beneficial use. Physical displacement of groundwater can also have adverse

practical impacts on private owners and utilities. As a result it will normally be prudent to

evaluate whether on-site groundwater wells, especially those used by public water systems, will

be disrupted by CCS operations.

In most places a water right includes the right to a particular quality as well as a

particular quantity of water. These cases are typically framed in the context of deprivation of

quantity but these water rights are also protected from activities of another that injure the quality

of a water right. Therefore, if water quality is affected by the precipitate that hopefully forms 39

from the geochemical reactions intended as part of CCS operations the owner of that water could

have a cause of action against the entity injecting and the owner of the gas injected. Historically

such interference involved the discharge of mine and other wastes into the stream but there is no

reason to believe the result would be different with CCS. 

40

III. Regulation

A. EPA UIC Rulemaking

The UIC Program regulates underground injection under five different classes of

injection wells, depending on the type of fluid being injected, the purpose for injection, and the

subsurface location where the fluid is to remain. States are allowed to assume primary

responsibility for implementing the UIC requirements in their borders, as long as the state

program is consistent with EPA regulations and has received regulatory approval. Injection

operators are required to provide financial assurance in case they cease operations, with the level

of assurance a function of the estimated cost of plugging and abandoning the injection well. If

there is a violation of a UIC permit, an enforcement action may be brought by the EPA

2A COPRAC § 76.11

39

Game & Fish Comm'n v. Farmers Irr. Co., 162 Colo. 301, 426 P.2d 562 (1967); Wilmore v. Chain O'Mines, 96

40

Colo. 319, 44 P.2d 1024 (1934).

16
Administrator or the applicable state agency. Violators may be subject to administrative orders,

civil penalties, and criminal penalties. The scope of the UIC statute is contamination of drinking

water 2, and under its current application to CO storage, the UIC Program gives more limited

treatment, if any, to other harms to human health, the environment, and property.

41

While there are requirements for constructing and monitoring injection well operation,

there are no federal requirements for monitoring actual movement of fluids within the injection

zones, nor are there requirements for monitoring in overlying zones to detect leakage with the

exception of specific class I hazardous wells, where this monitoring can be mandated.42

On July 15 2008, the EPA proposed a rulemaking package that would regulate geologic

sequestration of carbon dioxide under the UIC. The proposed rules would create a new category

of UIC well (Class VI) designed specifically for injection of CO2 into geologic formations. The

proposal includes detailed technical requirements for characterizing the scope and suitability of

the target formations, assuring that the injection zone will not affect any actual or potential

source of drinking water, monitoring and reporting on well conditions during and after the

sequestration is complete, and requiring as part of well permit applications plans for 50 years of

post-injection monitoring.43

The proposed rules do not direc 2tly address air quality issues. The Class VI CO injection

well requirements are designed to assure 2 that there are no significant releases of CO or

contaminants in the CO2 2 into the ambient atmosphere. The EPA declined to classify CO as a

hazardous wa 2ste but the proposed rules place a burden on the permittee to assure that the CO

does not contain impurities that would trigger RCRA hazardous waste management

Craig A. Hart, Advancing Carbon Sequestration Research in an Uncertain Legal and Regulatory Environment: A

41

Study of Phase II of the DOE Regional Carbon Sequestration Partnerships Program, Discussion Paper 2009-01,

Cambridge, Mass.: Belfer Center for Science and International Affairs, January 2009.

Regulating the ultimate sink: managing the risks of geologic CO2 storage. Page 3479

42

http://www.epa.gov/ogwdw/uic/wells_sequestration.html

43

17
requirements. The risks associated with this classification are manifest. Injection of hazardous

waste is highly regulated and would likely bring a CCS project to a screeching halt. 

None of this overrides the applicable provisions of CERCLA or RCRA. To the extent

there are hazardous substances released from the sequestration process liability under CERCLA

may be present. Likewise if materials injected are hazardous waste the daunting permitting and 44

corrective action provisions of RCRA and the state programs will apply. 

As an example, EPA issued orders under RCRA to require management of propane that

had leaked from an underground distribution system. In EPA’s view, the moment the propane

leaked from the distribution system it was a waste and presented a hazard. Depending upon the

factual setting, CCS operations could find themselves in the same situation. 

B. State Regulation

In the absence of federal action on the carbon sequestration issue, many states are in the

process of enacting their own regulations. Some examples follow:

1. Wyoming

House Bill 89 (created Wyoming Statute § 34-1-152 and amended Wyoming Statute §

34-1-202) addresses the ownership of Pore Space. The Bill establishes that the surface owner

owns pore space underneath the surface estate and that the pore space is conveyed upon the

conveyance of the surface, unless the space has been previously conveyed or is explicitly

excluded in the surface conveyance (in the same manner as a mineral interest). In addition, legal

requirements for notice to surface owners and/or mineral interest owners shall not be construed

to require notice to the pore space owner unless the law specifies that such notice to the pore

space owner is required. The statute expressly recognizes the dominance of the mineral estate

http://www.hhclimatechange.com/climate_change/2008/07/epa-releases-pr.html

44

18
and does not alter the common law as it relates to the rights of the mineral estate. The bill states

explicitly that it does not affect the common law regarding the dominance of the mineral estate.45

House Bill 90 (effective July 1, 2008; created Wyoming Statute §§ 30-5-501 and 35-11-

313 and amended Wyoming Statute § 35-11-103(c)) mandates UIC permit for GCS. It makes a

clear distinction from EOR. It instructs the Wyoming Department of Environmental Quality to

establish and issue permits to new “sub-classes of wells” within the UIC program and to regulate

well standards, bonding and monitoring. The bill requires the DEQ to create an advisory board

and rules to expand the UIC program to include carbon sequestration. Under the bill, a working

group including the supervisor of the oil and gas commission, the state geologist, and the

director of the DEQ will set bonding procedures. Jurisdiction subsequent extraction of

sequestered carbon dioxide rests with the Wyoming Oil and Gas Conservation Commission. The

bill does not impact the oil and other mineral interest owners’ right to drill or bore through

sequestration sites, nor does it include within its scope the regulation of enhanced oil recovery

operations using carbon dioxide.46

Like HB 89, Wyoming's carbon capture and sequestration legislation recognizes the

continuing dominance of the mineral estate. § 30-5-501 states specifically that the carbon

sequestration legislation enacted by § 35-11-313 shall not “affect the otherwise lawful right of a

surface or mineral owner to drill or bore through a geologic sequestration site” so long as the

drilling is conducted in conformity with rules for protecting the sequestration site against the

escape of CO2.

47

Id. at 143-45

45

Delissa Hayano, Guarding the Viability of Coal & Coal-Fired Power Plants: A Road Map For Wyoming’s Cradle

46

to Grave Regulation of Geologic CO2 Sequestration, 9 Wyo. L. Rev. 139, 145-49 (2009)

Id.

47

19
2. Oklahoma

Senate Bill 1765 (May 2008) was a proposal that required the development of GCS

permitting regime and transferred ownership of wells to state and released owners from liability

10 years after closure. The Bill that was passed, however, was relatively disappointing. It

mandated a task force to report to the Governor with GCS permitting recommendations by

December 2008 (extended to December 2009) and is modeled based on the IOGCC model

statute.48

3. Kansas 

Under HB 2419 (2007), GCS rules were supposed to be developed by July 2008 (draft in

progress). Under the Bill, a state GCS fund would pay long-term GCS related monitoring and

remedial activities. It also exempts GCS property and any electric unit utilizing GCS from taxes

for 5 years. Finally, it allows for accelerated depreciation of GCS equipment.49

4. Washington

ESSB 6001, passed April 17 2008. It codifies the emissions-reduction goals and policy

recommendations for the state. The bill also sets an Emissions Performance Standard (EPS) that

limits electric utilities’ ability to sign new or renewed long-term contracts with power plants

whose greenhouse-gas emissions exceed those of a modern natural gas-fueled power plant. The

bill essentially ends construction of pulverized coal plants to serve Washington loads, makes the

price of IGCC power reflect some of its emissions disposal costs, and jumpstarts the process

toward a comprehensive greenhouse-gas emissions reduction plan for the state.

50

de Figueiredo MA, Reiner DM, Herzog HJ. Framing the long-term in situ liability issue for geologic

48

carbon storage in the United States. Mitigation Adapt. Strat. Global Change 2005;10:647-57.

Melisa F. Pollak ,Humphrey Institute of Public Affairs, Big Sky Carbon Sequestration Partnership Annual Meetin.

49

Oct. 28, 2008

NW Energy Coalition, April 19, 2007. www.nwenergy.org/publications/fact-sheets/6001%20FINAL%2

50

20
Will Water Issues/Regulatory Capacity

Allow or Prevent Geologic Sequestration

for New Power Plants?

A Review of the Underground Injection Control Program and 

Carbon Capture and Storage

Authors:

Jonathan Gledhill, Policy Navigation Group

James Rollins, Policy Navigation Group

Theresa Pugh, Director, Environmental Services, APPA

and

American Public Power Association

1875 Connecticut Ave, NW

Suite 1200

Washington, DC 20009-5715
and 1

Executive Summary

International concern over global climate change has spurred a search to identify ways to 

reduce greenhouse gas (GHG) emissions. Of the six gases comprising greenhouse emissions, 

carbon dioxide (CO2 – “carbon”) emissions far exceed the other five in the amount emitted.1

The U.S. is considering a number of voluntary options for an 18 percent reduction in CO2

emissions by the year 2012. One technology receiving serious consideration by the 

international agencies, Congress, states, and the Bush Administration is carbon capture and 

storage (CCS) or sequestration2

First the carbon dioxide from a power plant would have to be separated and removed from 

the power plant. Carbon sequestration really refers to the geologic storage in deep 

geological formations below the earth’s surface. Carbon dioxide injection has been used for 

several years in enhanced oil recovery operations. Through government and private 

partnerships, the U.S., through the Department of Energy (DOE), is evaluating the viability of 

long-term CCS by conducting demonstration and validation testing of CCS pilot projects.

APPA supports carbon storage demonstrations through the DOE and FutureGen to determine if 

the injection of CO2 is safe and effective as a mitigation measure. 

The CCS issue is of considerable import to the electricity/power plant sector which the U.S. 

DOE considers to be one of the largest emitters of CO2, accounting for 38 percent of CO2 

emissions among all energy sectors.3

While the U.S. DOE is pushing aggressively to deploy CCS for full-scale commercial use, there 

are a number of technical, regulatory, and policy issues related to long-term CO2 storage or 

geosequestration that remain to be studied and resolved. 

The U.S. Environmental Protection Agency (EPA) has regulatory authority over injection of 

wastes into wells through the Underground Injection Control program (UIC) created by 

Congress under the Safe Water Drinking Act. Congress specifically created the program out of 

concern for the protection of underground drinking water sources. Although the UIC program 

has established five classes to address various injection well activities, the Agency currently 

does not have a regulatory framework by which to regulate CCS activities. U.S. EPA has 

recently issued guidance to assist its regional offices and state regulators with permitting and 

operational decisions related to CCS pilot projects.

The U.S. EPA has classified CCS pilot projects as Class V experimental technology; however, 

the regulatory framework for Class V wells is insufficient to provide the necessary safeguards 

to ensure protection of groundwater sources. Therefore regulators have relied on the 

stringent requirements established for Class I hazardous waste wells, which includes the 

requirement that operators demonstrate no-migration of injection fluids (which would include 

CO2) for a period of 10,000 years.

1 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference 

Document (“NETL Reference Document”), Aug. 2007, at 1-2. See also, Electric Power Research Institute, 

Electricity Technologies in a Carbon-Constrained World, (“Electricity sector is responsible for 1/3 of U.S. CO2

emissions”).

2

Sometimes sequestration is also referred to as geosequestration.

3 NETL Reference Document, at 1-2.
and 2

In summary, there are major limitations in the technical, regulatory, and administrative 

requirements of the UIC program that appear to preclude, in the short term, commercialscale sequestration of carbon in non-oil and gas sites in large parts of the country. These 

limitations are important for utilities and policy officials to evaluate as they consider CCS 

projects. For electric utilities that wish to build additional generation to meet the needs of 

their communities, the challenges include very difficult issues.

APPA recommends that States and Public Utility Commissions consider and investigate the 

several limitations identified in this paper prior to mandating CCS as a part of permit 

approval. APPA also recommends working with the U.S. EPA on the cross-cutting and 

multimedia regulatory issues as the Agency moves forward towards determining the best 

regulatory framework for CCS.
and 3

Introduction

What is the Issue and Why does it Matter to Utilities and Municipal Government?

Policy officials and scientists alike, searching for viable ways to reduce carbon dioxide (CO2)

emissions, have identified carbon capture and storage (CCS) 4as a promising technology. This

technology separates CO2 from emissions of large stationary sources like power plants and 

injects the captured CO2 deep into the earth. Figure 1 gives a simple picture of this 

technology. The Intergovernmental Panel on Climate Change (IPCC) has identified CCS as a 

way of achieving overall reductions in greenhouse gas emissions.5This enthusiasm is shared 

by the U.S. government. The U.S. Department of Energy (DOE) is engaged in research and 

development of various CCS technologies to determine the viability of full scale deployment 

of CCS by the year 2012. The U.S. DOE is leading the Regional Carbon Sequestration 

Partnerships to conduct research and development of CCS and supporting small scale 

demonstration and validation pilot projects to determine the potential of this technology.

Figure 1: Diagram of a Carbon Capture and Storage Operation6

The benefits of reducing CO2 emissions through CCS must be balanced against the potential 

increased risks of groundwater pollution from CCS. Utilities provide water and power to their 

4 Carbon Capture and Storage is also referred to as Carbon Geologic Sequestration.

5

Intergovernmental Panel on Climate Change, Special Report: Carbon Dioxide Capture and Storage, Summary of 

Policymakers, 2005.

6 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference 

Document, Aug. 2007, at 3-53 Fig. 3-22.
and 4

communities and rely on available water supplies to produce power. Utilities are uniquely 

positioned and therefore must understand the potential promise and limitations of CCS. 

The potential trade-offs will tighten in the future as demand increases for power, water, and 

GHG reductions. According to EPA, ground water systems account for 91 percent of the total 

public drinking water systems in the U.S., serving 36 percent of the U.S. population.7 Demand 

for drinking water increases with population growth, number of households, and 

manufacturing. While conservation has reduced this need for some new sources, groundwater 

levels in many parts of the U.S. are declining due to increased pumping.8 Meanwhile, the 

demand for electric is expected to increase by 39 percent from 2005 to 2050,

9

requiring new 

capacity. If new power plants use CCS as some states are considering, underground drinking 

water sources will face pressure from both power and water needs.

The American Water Works Association (AWWA) and the American Public Power Association 

(APPA) commissioned this paper to consider the drinking water and groundwater issues with 

CCS and to identify the regulatory and technical hurdles that might minimize opportunities 

for CCS. More than 1,000 of the nation’s municipalities provide electricity to homes;

businesses and factories also manage many water utilities providing drinking water to 

residential, industrial, and commercial customers.

There are several cautions to assuming a seamless fit between current regulation and CCS. 

First, the existing regulations and regulatory program arose over 20 years ago, long before 

CCS was envisioned. Since CCS does not fit neatly into the existing program for power plants, 

the EPA is still in the process of crafting a regulatory approach. Second, for CCS to have a 

meaningful impact on U.S. emissions, the volume of CO2 to be injected underground will 

dwarf current amounts by 10 to 20 times. While the nation has the ingenuity to tackle this 

challenge, it will require investing in technical skills, data, research, and education both in 

the private sector and in regulatory agencies. Currently, regulatory agencies do not have the 

capacity to review and permit CCS at any significant level. To illustrate this issue, this paper 

reviews the current UIC program, its current implementation, the current regulatory 

framework for CCS, and the skill shortages states and EPA will face if CCS moves toward fullscale implementation. Finally, this paper highlights the major limitations for CCS that power 

plant and water utility managers should consider.

What is Underground Injection?

Underground injection involves the use of simple or complex technology to inject fluids into 

the earth most often for purposes of waste disposal or extraction of fossil fuels and minerals.

Wells regulated by the EPA include common shallow septic tank systems to highly-engineered, 

large volume systems that inject materials more than a mile underground. While shallow 

wells may only dispose of a few gallons per day, large disposal systems may each day pump 

the volume of an Olympic-sized swimming pool. 

7 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006.

8

Source: U.S. Geological Survey at http://ga.water.usgs.gov/edu/gwdepletion.html.

9

Energy Information Administration, Annual Energy Outlook 2007, Feb. 2007, at 82.
and 5

What is the Underground Injection Control (UIC) Program?

Congress and EPA established the legal framework for regulating underground disposal over 30 

years ago. Congress established the UIC program as part of the Safe Drinking Water Act 

(SDWA) of 1974 providing EPA with the authority to regulate underground injection activities 

to ensure the protection of the nation’s underground sources of drinking water. Almost all 

U.S. public water systems rely on some groundwater for drinking water.

10 Congress 

strengthened the regulatory requirements for hazardous waste UIC disposal in 1984. In the 

last 20 years, there have not been significant changes to the UIC program’s legal authority.

Congress intended for the UIC program to be administered by states due to the large number 

of wells and to the tradition of local control and regulation of drinking water. As such, the 

SDWA allows states to submit an application to EPA for primary enforcement or “primacy” for 

each part, or “class,” of the program. EPA can delegate primacy to a state, U.S. territory, or 

a federally recognized Native American tribe. The UIC program may be executed by the EPA, 

the state, or both under four separate scenarios:

1) EPA administers the program for all well classes within a state if the latter chooses not 

to apply for primacy;

2) a state is delegated primacy for all five classes;

3) a state has primacy for Class II (oil and gas) wells only; or,

4) a state has primacy for all classes except Class II oil and gas wells.

EPA has delegated primacy for the entire program to 34 states and three territories, shares 

responsibility with six states, and retains full responsibility in ten states. The ten states for 

which EPA has primacy are: Arizona, Hawaii, Iowa, Kentucky, Michigan, Minnesota, New York, 

Pennsylvania, Tennessee, and Virginia. These states have determined that committing state 

resources to run the program is not a high priority. 

How does EPA Regulate Underground Injection?

EPA established five classes of injection wells (Class I, II, III, IV, and V) under the UIC program 

based upon how the well is used, constructed, and operated.

11 The classes provide a 

consistent way for EPA to apply technical standards to similar activities to ensure the 

protection of underground drinking water and human health.

The classes are ranked by their potential hazard. Class I wells are for the largest volume and 

the most hazardous wastes. Class V wells are for shallow septic systems, dry wells, and low 

volume systems. Most UIC wells are either Class V, Class I, or Class II wells.

All underground injection wells must have a permit. For each class, EPA has established 

minimum technical standards, public participation, and a permitting process review that 

10 See EPA website, http://www.epa.gov/safewater/uic/whatis.html.

11 40 CFR Part 144.6.
and 6

states must include in their permitting process. With approximately 834,000 wells across the 

U.S.,

12 the UIC program is one of the largest environmental permitting programs.

12 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006; 

http://www.epa.gov/safewater/uic/classes.html.
and 7

What are the Five Classes of Injection Wells under the UIC Program?

Class I Injection Wells

Subject to the most stringent regulations, Class I wells include industrial hazardous, 

nonhazardous, and municipal sewage waste. Class I wells inject wastes deep into rock 

formations that are located beneath the lowest underground sources of drinking water13 and 

that are capped by an impermeable rock formation between the injection zone and drinking 

water sources above.

Figure 2: Diagram of Class I Well14

13 Class I hazardous wastes are injected to depths anywhere from 1,700 feet down to 10,000 feet below the earth’s 

surface.

14 U.S. EPA Office of Water, Class I Underground Injection Control Program: Study of the Risks Associated with 

Class I UIC Wells, Mar. 2001, at 11.
and 8

In 1984, Congress tightened Class I requirements by instituting a no-migration standard for 

disposal of hazardous waste via injection and creating a petition process by which operators 

must obtain approval to continue hazardous waste injection operations. Specifically, 

Congress prohibited injection of untreated hazardous wastes unless it is demonstrated that 

the waste has been treated to be non hazardous or unless the waste will not migrate out of 

the injection zone or contaminate drinking water for at least 10,000 years.

15 Because of the 

large volume of wastes injected, Class I injection is economical if it can show a “no 

migration” of the waste. Well operators, filing the petition to operate such wells, must 

accomplish this demonstration by modeling waste behavior underground.16

While there are a total of 529 Class I wells nationwide, there are only 163 Class I hazardous 

waste wells nationwide. Most Class I wells are found in Texas and Louisiana. Class I wells are 

banned in Missouri. The map below shows the location of Class I hazardous waste wells in the 

U.S.

17 As the map below shows, only 11 states have active Class I hazardous waste wells.

15 NRDC v. EPA, 907 F. 2d at 1158

16 RCRA, Section 3004, 40 CFR Part 148 (53 FR 28118). In the final regulations, EPA explained that 10,000 year 

requirement is based on ensuring for long term waste confinement. Specifically, demonstrations that can show nomigration over a 10,000 year period are likely to result in containment for an even longer period of time. 

Additionally, confinement for that period of time can result in waste immobilize due to geochemical 

transformation. 

17 See EPA website, http://www.epa.gov/safewater/uic/classi.html.
and 9

Figure 2: Hazardous Waste Wells in the U.S.
and 10

There are 366 nonhazardous Class I waste wells in 19 states. Nonhazardous Class I waste wells are required to comply with the 

same technical standards as hazardous waste wells. 

Class II Injection Wells

Oil and gas production facilities use Class II wells to inject fluids to pump hard-to-get oil and gas deposits to the surface. The 

recovered crude oil and natural gas comes to the surface mixed with salty water and other impurities. States require 

injection of this salty water underground so as not to pollute drinking water. Class II wells must comply with strict 

construction and operating standards and are often similar in construction to Class I deep wells. There are approximately 

167,000 Class II wells, predominantly found in the southwestern U.S. The map below shows the location of Class II wells in the 

U.S.

18 Twenty-two states do not have any Class II wells.

18 See EPA Website, http://www.epa.gov/safewater/uic/classii.html.
and 11

Figure 3: UIC Class II Oil & Gas Wells in the U.S.
and 12

Class III and Class IV Injection Wells

Class III wells typically involve using injection of fluids to extract minerals. Mining operations 

for salt, sulfur, and uranium rely heavily on injection using Class III wells. Class III wells have 

minimum standards for which operators must comply, including required casing and 

cementing of wells to prevent the migration of fluids into drinking water sources, a 

prohibition on injection of fluid between the outermost casing and well bore, and required 

integrity tests of well casings every five years.

In Class IV wells, hazardous waste is injected directly into or above underwater drinking 

water. Although Class IV wells, like Class V, generally involve shallow wells, EPA created a 

separate class for injection activities that present a heightened risk. Class IV wells have been

banned except in very narrow circumstances.

Class V Injection Wells

Most injection wells in the U.S. are Class V wells with an estimated 650,000 Class V wells in 

the nation.

19 Class V wells inject nonhazardous waste into or above underground drinking 

water and occur in a variety of residential and commercial settings including sewage disposal, 

aquifer recharge, and mineral recovery. Class V wells include advanced systems used by 

industry for wastewater disposal as well as less advanced types found in septic systems,

cesspools, and agriculture drainage wells. 

Injection activities that do not fit into the other classes - like CCS - are called Class V wells.

Experimental technologies that are in the demonstration phase are classified as Class V

injection.

20 Although there are no federal requirements that specifically address Class V 

experimental technology wells, over the years EPA has issued guidance to cover certain

experimental technologies. Notably, EPA issued guidance in 1983 clarifying that technologies 

in the experimental phase which would have otherwise fallen under another UIC programclass based upon well function, may be reclassified into one of the five classes once the 

technology has advanced for commercial use. However, the technology remains under Class V 

until proven for commercial use and it is shown that the technical standards of the other class 

would provide sufficient protection of underground drinking water and human health once the 

new technology is deployed for commercial use. If the technical standards of the other 

classes are unable to provide sufficient protection, the new technology remains under Class V 

until EPA adopts protective technical standards.21

EPA did not establish technical standards for Class V wells until the 1990s. Because of the 

diversity and sheer number of these wells, EPA did not set minimal technical standards for 

Class V wells. Since EPA finished the Class V rule over 10 years ago, EPA has not issued major 

policy changes to the program. 

19 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006.

20 See, Underground Injection Control (UIC) Regulations as amended, 40 CFR Part 146.05(e), Aug. 27, 1981 (46 FR 

43156), and 40 CFR Part 146.03, Feb. 3, 1982 (47 FR 1416).

21 Victor J. Kimm, Memorandum: Appropriate Classification and Regulatory Treatment of Experimental 

Technologies. Ground-Water Program Guidance No. 28 (GWPG #28), May 31, 1983.
and 13

How Does CCS Fit into the UIC Program and Why Does this Matter to Electric Utilities?

Congress and EPA did not envision sequestration of carbon dioxide when they established the 

program for the chemical industry over 30 years ago so no federal regulatory framework exists 

to regulate CCS activities specifically. Yet, EPA has considered how CCS is regulated under 

the UIC program. In 2006 EPA determined that CCS activities are “underground injection” 

and that SDWA mechanisms are sufficient to regulate and to permit pilot projects. As a 

result, EPA issued a directive that CCS pilot projects are to be permitted as Class V 

experimental technology wells.22 This policy directive might be supplanted by an EPA 

rulemaking in 2008.

Since there are no federal requirements governing Class V experimental technology wells, 

there has been a lot of confusion and uncertainty. In March 2007 EPA issued guidance for 

permitting and operation of CCS pilot projects as a Class V experimental technology wells.23

This guidance for CCS pilot projects tries to straddle between the current legal framework 

and the environmental standards necessary to inject a large volume of carbon dioxide safely. 

Legally, EPA confirms that Class V is “the best mechanism for authorizing pilot GS project,”

24

and that Class V general permitting and public participation requirements apply. The permits 

can remain in effect as long as needed to cover the timetable of project goals and may be 

modified or extended to alter the goals or timetable, but cannot exceed state or federal 

permit limits.

As a counterpoint to the flexibility inherent in a Class V permit, the guidance then lays out 

why states should consider more stringent permit conditions in the CCS Class V permit. EPA 

emphasizes throughout the guidance that protection of underground drinking water and 

human health is the overriding concern. EPA lays out a number of considerations for regional 

and state directors to take into account for purposes of permitting and operation, including:

§ Siting considerations;

§ Consideration of the underground area affected by the injection;

§ Injection well construction;

§ Injection well operation and monitoring program considerations; and,

§ Site closure.

UIC program directors are also encouraged to consult with deep well experts including Class I 

and Class II directors to ensure appropriate standards are applied for CCS pilot projects.

However, EPA stops short of recommending CCS pilots have all the features of Class I permits, 

although UIC directors can opt for Class I requirements. The 2007 EPA guidance stresses that 

the primary goal of pilot projects is for EPA, the states, and well operators to collect and 

share data to better understand how CO2 reacts and moves underground, as well as

22 Cynthia C. Dougherty, Letter to State Regional UIC Contacts re: CCS pilot projects, U.S. EPA Office of Water, 

Jul. 5, 2006. http://www.epa.gov/safewater/uic/pdfs/memo_wells_sequestration_7-5-06.pdf

23 UICPG # 83. http://www.epa.gov/safewater/uic/pdfs/guide_uic_carbonsequestration_final-03-07.pdf

24 UICPG # 83, at 6.
and 14

understanding what the risks are associated with CO2 injection. To determine how best to 

manage commercial scale CCS injection operations, the guidance suggests EPA regional and 

state directors adopt a more flexible approach in approving permits and identifying permit 

conditions to allow operators to “achieve project objectives.”25

How have States Regulated CCS Pilots?

EPA and the states have looked to Class I and II regulations for permit conditions for CCS

pilots because of the depth of injection and the larger volume of CO2 injected. Today CO2 is 

currently is being injected to recover oil and gas in wells subject to Class II well 

requirements. Some CCS pilots have occurred in oil and gas formations in Class II wells.26 In 

the few cases to date, states have granted Class V permits for CCS pilots sequestration with 

many – if not all – of the technical requirements for a Class I permit.

What are the Specific Class I and II Technical Requirements? 

The technical requirements for Class I and II wells include siting, well construction, operation, 

reporting, monitoring, permitting, financial assurance, and closure standards. The regulatory 

system is designed to minimize leaks into drinking water formations as waste and fluids are

pumped down through these layers and after they are put underground.

Siting

Class I permits require three separate hydrogeologic investigations to permit a deep injection 

well: reviewing the geology of the area, conducting an area of review study, and finally 

submitting a no migration petition. 

In the geologic study, permit applicants must show that the area is geologically stable; the 

area is not seismically active now and has not had earthquakes in recent geologic time. The 

formation must have suitable room to store the injected wastes and thick enough to dissipate 

the pressure without cracking the confining layer. The geologic study must also show the 

area around the well is free of vertical faults that could allow the injected fluids to migrate 

up to drinking water layers. Finally, the geologic study must also demonstrate that the 

injection layer’s rocks are chemically compatible with the waste. 27

The second study is the Area of Review. In this study, well operators must investigate all 

wells in the area that penetrate the injection or the confining layer. Operators must 

demonstrate that all of these wells are sufficiently capped and closed to prevent migration 

out of the injection layer. Under federal regulations for Class I hazardous waste wells, the 

Area of Review is defined as either a 2 mile radius from the well or to the zone of 

endangering influence on underground drinking water, whichever is a greater distance. 

States require larger Areas of Review; Texas, for example, uses a 2.5 radius for its Area of 

Review. For nonhazardous waste, the Area of Review can be a low as 1⁄4 of a mile.28

25 UICPG #83, at 3.

26 According to U.S. DOE, there are at 75 oil reserve carbon sequestration projects in the following states: 

Arkansas, Colorado, Louisiana, Oklahoma, and Texas. See, U.S. DOE National Energy Technology Laboratory, 

Carbon Sequestration Program Environmental Reference Document, Aug. 2007, at 3-60.

27 U.S. EPA Office of Water, Class I Underground Injection Control Program: Study of the Risks Associated with 

Class I Injection Wells, Mar. 2001, at 18.

28 Ibid, at 19.
and 15

One of the biggest challenges for Class I operators is to demonstrate no-migration of waste for 

at least ten thousand years. This demonstration requires computer modeling, knowledge of 

regional geology, and detailed geologic information of the area around the well. Small faults 

or buried channels can create a connection between deep formations and shallower drinking 

water sources. Injecting fluids also changes the volume and pressure underground, possibly 

activating dormant faults. Permit applicants must also search for abandoned wells that might 

connect the injection zone with upper layers.

Construction 

Operators prevent leaking by wrapping their wells in impermeable casing. Operators of 

enhanced recovery and hydrocarbon storage wells are required to case and cement the wells 

to prevent migration of fluids into underground drinking water. Specific casing and 

cementing requirements are determined by the state on a case-by-case basis; however, as 

part of that process they must take into account injection zone depth, depth of the bottom of 

all drinking water formations, injection pressures, and the nature of fluids to be injected.29

The well has essentially three walls so that breaching one still contains the waste. As shown 

in Figure 4, the injection tubing transports the waste to the injection zone. It is made of 

corrosion-resistant material and it is surrounded by the long string casing. This casing is 

sealed at the bottom by the packer and at the top by the well head. Operators must 

pressurize this space between the long string casing and the injection tubing to monitor for 

and to prevent leaks. Finally, the outermost wall, the well casing, supports the well 

structurally. Operators must maintain mechanical integrity of the well until plugged and 

abandoned.30

29 40 CFR Part 144.28(e)

30 40 CFR Part 144.28(f)
and 16

Figure 4: Diagram of Class I Well Technology31

Monitoring

Monitoring requirements include monitoring of the well and other formations. Class I well 

operators are required to analyze injection fluids to identify fluid characteristics, to use 

continuous recording devices to monitor injection pressure, flow rate, and volume, and to 

monitor for any leaks into drinking water with monitoring wells.32 Operators also minimize 

any leaks by carefully watching injection pressure. If there is a leak in a well, the pressure in 

the well will drop as the fluids escape out of the circumference. Regulations require well 

operators to use continuous recording devices to monitor injection pressure, flow rate, and 

volume.33 To demonstrate mechanical integrity, well operators must show that fluids will not 

31 Source: U.S. EPA website: http://www.epa.gov/safewater/uic/idealwel.html.

32 40 CFR Part 144.28(g)(1). 

33 40 CFR Part 144.26(g)(1). 
and 17

leak while traveling to the well, will not leak out of the well as it is injected, nor move into 

underground drinking water once injected into the deep rock.

34 The UIC program requires 

mechanical integrity demonstrations at least once every five years for both Class I and Class II 

wells.35

Class I operators are also required to develop approved ambient monitoring programs as 

determined by the Program Director to protect against fluid movement out of the injection 

zone. Monitoring programs are based upon a site-specific assessment and must include at a 

minimum annual monitoring for injection zone pressure.36 The Director may also require the 

following as part of the monitoring program:

1) Continuous monitoring for pressure in the aquifer located directly above the 

injection zone;

2) Other site specific data to include information on the position of the waste front 

within the injection zone or water quality;

3) Monitoring of ground water quality of the aquifer located directly above the injection 

zone;

4) Monitoring of ground water quality in the lowest underground source of drinking 

water; and, 

5) Any additional monitoring to determine if there is fluid movement into underground 

sources of drinking water.37

Class II well operators are required to monitor injected fluids to determine how it moves and 

changes while in the injection zone, and the frequency of which is determined in each permit 

based upon site specific criteria.

38 Operators are also required to monitor and record 

injection pressure, flow rate, and cumulative volume, the frequency of which can vary from 

daily to monthly, dependent upon the type of well operations.

39 Well operators must

demonstrate mechanical integrity at least every five years.40

Reporting

Reporting requirements also differ between Class I and Class II wells. Operators of Class I 

wells must submit quarterly reports with the following information: various characteristics of 

the injection fluid, monthly average and minimum and maximum values for injection 

pressure, flow rate/volume, well pressure monitoring well results, and the results of injection 

34 40 CFR Part 146.8

35 40 CFR Parts 146.13 and 146.23. 

36 40 CFR Part 146.13(d)(1).

37 40 CFR Part 146.13(d)(2).

38 40 CFR Part 146.23(b)(1).

39 40 CFR Part 144.28(g)(2); 40 CFR Part 146.23(b)(2).

40 40 CFR Part 144.28(g)(2)(iv); 40 CFR Part 146.23(b)(3).
and 18

well tests.41 Class II well operators are required to submit annual reports providing a 

summary of results from any required monitoring activities.42

Financial Assurance

For now, APPA is not aware of any additional financial assurance programs or systems 

envisioned for CCS. However, the existing law does require that financial responsibility is 

met. APPA has caution about embracing CCS technology and long-term storage or 

geosequestration for new power plants until this financial responsibility issue is better 

understood. To APPA’s knowledge, there has been nothing like this level of financial 

assurance required in the electric power sector for conventional pollution issues and liability 

concerns.

Currently, Class I operators must demonstrate and maintain financial responsibility for each 

well to ensure the operator is financially able to eventually close and abandon the well in 

accordance with an approved well abandonment plan.43 Class I operators have several options 

from which to choose in order to demonstrate financial responsibility.

1) Establish a trust fund in an amount equal to the estimated cost of plugging and 

abandonment;

2) Obtain a surety bond to guarantee payment into a standby trust fund;

3) Obtain a surety bond to guarantee well plugging and abandonment;

4) Obtain a letter of irrevocable plugging and abandonment letter of credit;

5) Plugging and abandonment insurance;

6) Meet financial criteria and obtain a corporate guarantee for plugging and 

abandonment; or,

7) Demonstrate financial responsibility using a combination of options 1, 2, 4, 5.44

Closure

Well operators must submit plans for plugging and abandonment as part of the permit 

approval process. 45 UIC program regulation requires Class I, II, III, and V wells to be plugged 

with cement sufficiently to prevent migration or leakage of the injection fluid. Class I permit 

holders must also monitor groundwater until they can demonstrate that the pressure in the 

injection zone decays to the point where there is no potential to influence underground 

drinking water sources.

46 Class V operators are also required to dispose of any waste, sludge, 

fluids, etc., that are found near the wells.47 Well operators are required to submit a report 

41 40 CFR Part 144.28(h)(1).

42 40 CFR Part 144.28(h)(2).

43 40 CFR Part 144.28(d).

44 40 CFR Part 144.63.

45 40 CFR Part 144.28(c).

46 40 CFR Part 14.28(g)(1)(iii).

47 40 CFR Part 146.10.
and 19

certified as accurate to the Director stating that well abandonment was conducted and 

completed in accordance with the abandonment plan. 

What are the Challenges for Permitting CCS Under the UIC Program for Electric Utilities 

Evaluating CCS Options?

With the international, federal, and state interest in CCS, academic, public interest groups,

and the federal government researchers are promoting the availability of sequestration sites. 

The Department of Energy estimates that North America has the capacity to store all of its 

annual power plant emissions underground. The APPA is very skeptical of DOE’s optimistic 

view because APPA does not believe that hydrological concerns and proximity to transmission 

lines, water issues and other infrastructure needs have been considered. Yet, new electric 

utilities are being asked to respond and to consider CCS as part of new plant design now. 

The APPA is concerned that these studies do not fully consider the technical, regulatory, and 

practical limitations of commercial-scale CCS. The current UIC regulatory program illustrates 

some of the major limitations utilities and policy officials must consider: 

Cost and Space Requirements for CCS at the Power Plant

The DOE estimates that a 300 MW power plan will require 60 acres of land to build and to 

operate the carbon capture technology.48 Constructing the pipeline terminus for C02

compression and transport via pipeline will require an additional 20 acres of land. DOE 

further estimates that carbon capture will consume 0.5 millions of gallons of water per day 

and over 15 megawatts of power or approximately 0.8 MGD per day for a 500 MW power 

plant. If utilities do not have readily available land and water, and can afford the costs of 

excess generating capacity, they will face limitations on their ability to construct CCS.49

Uncertainty Concerning Regulatory Requirements

Since EPA is formulating guidance or regulation on CCS and the UIC program, there is 

substantial uncertainty as to the ultimate siting, construction, and other permit 

requirements. If EPA embarks on a rulemaking, a final rule may not be promulgated until 

2012. Once EPA completes its policies, states may enact their own more stringent provisions. 

This uncertainty complicates commercial scale planning for new power plants with coal on 

the drawing board today.

Operators of Class I, II, or III wells are expected to take corrective measures when there is 

noncompliance or malfunction of the injection system, which may include temporary shut 

down and capping of the well. The operators are required to notify the UIC regulatory 

manager within 24 hours of when the operator becomes aware of the problem. Operators are 

also expected to include in their noncompliance report its cause, period of time it occurred, 

actions taken (or are taking) to correct the issue, and plans to prevent recurrence.50 Other 

specific requirements may be established as part of the operators UIC permit. However, the 

difficulty for well operators involved in CCS operations is finding an alternative means of 

disposing CO2 emissions if injection operations must temporarily cease. Operators may have 

to negotiate this issue as part of the well permitting process.

48 NETL report, at 2-44.

49 NETL report, at 2-44.

50 40 CFR Part 144.28(b)
and 20

Limitations on Class I Well Siting

If EPA and states draw upon the criteria for Class I wells for CCS wells, there are regulatory, 

technical, and transportation limitations for CCS that utilities must consider. On a technical 

basis, some areas of the U.S. would be unsuitable due to the relatively increased risk of 

earthquakes, for example. Many of the coal regions of the United States also correspond to 

areas that are relatively geologically active (e.g., areas of Wyoming51). Injection near 

population centers along the West Coast also might be ruled out due to seismic concerns. 

Until the siting criteria are defined, utilities may not be certain whether they can inject 

locally or be required to pipe CO2 hundreds of miles to areas with Class I wells such as the 

Gulf Coast. 

Sheer Size of CCS to Have Meaningful Impact on U.S. GHG Emissions

Another limitation is that the EPA and states may not have the human and financial resources 

to administer an expansion of the UIC program for CCS. Comparing the relative size of CO2

emissions and current underground injection gives some answer to this question. Power 

plants accounted for 2.4 billion metric tons of CO2 emissions in 200652 or approximately 86 

percent of point source CO2 emissions in the U.S.53

By way of comparison, EPA reported that 21.8 million tons were injected into hazardous 

waste wells in 2005,54 less than one percent of the amount of carbon dioxide released. 

Approximately 43 million metric tons of carbon dioxide is injected into wells today for 

enhanced oil and gas recovery.55

If perhaps 10-20 percent of carbon dioxide emissions were captured, the UIC programs would 

need to permit wells injecting masses 10 – 20 times the total mass currently injected for oil 

recovery or for all hazardous waste disposals. This expansion would pose a substantial 

challenge to the existing state permitting systems. APPA remains skeptical that more than a 

slip stream of CO2 can be separated and injected and remains doubtful that a new coal power 

plant (regardless of type) could separate and inject more than 50 percent of the CO2 from the 

plant.

51 http://ga.water.usgs.gov/edu/gwdepletion.html

52 Electric Power Research Institute, Electricity Technologies in a Carbon-Constrained World. 

53 Carbon Sequestration Atlas, at 11.

54 U.S. EPA Office of Solid Waste and Emergency Response, National Biennial RCRA Hazardous Waste Report: Based 

on 2005 Data, Dec. 2006, at 2-5, Exhibit 2-5.

55 Source: Advanced Resourced International, 2007.
and 21

Figure 5: Comparison of CCS Volumes to Current UIC Volumes

Injected Material Mass of Material

(mil. Metric tons/year)

CO2 emissions from power plants 2,40056

CO2 in Class II wells for oil recovery 4357

Class I hazardous waste 2258

Regional Carbon Sequestration Partnerships, total 2

Space Requirements for the Injection Well

DOE has estimated that injecting 0.9 million metric tons of CO2 will require a land area of 

over 2,750 acres. This carbon mass is only 40 percent of one year’s generation from a 300 

MW coal power plant with a 90 percent efficient CCS. Using DOE’s estimate, to hold 30 years 

of CO2 captured from a 300 MW boiler, the surface area requirement is over 200,000 acres, or 

312.5 square miles.59 This land choice must also consider load, transmission lines, coal or rail 

access, surface water (used to produce electricity) and conventional air pollution issues such 

as SO2 and NOX. The injection well, observational well and Area of Review (AoR) space issues 

will dictate where the future power plants can be built.

The U.S. DOE’s estimate may significantly underestimate the land area needed. As a gas, 

carbon dioxide is different then diluted wastewaters currently injected in Class I wells. It is 

more buoyant than the underwater fluids and will rise to the top of the injection layer. If the 

injection layer has dips and rises, CO2 will flow to fill in each rise first. In other words, unlike 

current injected fluids, it will migrate via diffusion on its own away from the injection well. 

Like natural gas, it will concentrate in traps miles away from the injection zone. In other 

words, applicants could have areas of review much greater than 2.5 miles currently thought

protective for liquid injection. A study in the saline formations of Texas where there are 

many Class I wells suggests that a formation large enough to store 30 years of CO2 from a 

single power plant could have traps over a 13 mile by 13 mile area.60

A further complication is the difference in property law traditions across the United States. 

In several Homestead laws, Congress gave away land to settlers who stayed upon and 

improved the land. However, the federal government retained the subsurface rights to the 

land, creating “split-estate” properties where the surface owner does not have title to the 

subsurface. Over 20 million acres of land in western U.S. states have split estates between 

private entities and the federal government.61 In other states, the mineral rights have been 

sold to private parties creating split estates between parties. In the eastern U.S., property 

titles typically include surface and subsurface rights. Depending on the state, utilities may 

56 Electric Power Research Institute, Electricity Technologies in a Carbon-Constrained World.

57 Source: Advanced Resourced International, 2007,

58 U.S. EPA Office of Solid Waste and Emergency Response, National Biennial RCRA Hazardous Waste Report: Based 

on 2005 Data, Dec. 2006, at 2-5, Exhibit 2-5.

59 NETL report, at 2-71

60 J.P. Nicot et al., Area of Review: How large is large enough for carbon storage?, Bureau of Economic Geology, 

Jackson School of Geosciences, The University of Texas at Austin, 2006.

61 NETL report, at 4-83.
and 22

face the limitation that it is impractical, impossible, or extremely costly to acquire title to 

hundreds of thousands of acres of land.

Unique Potential Hazards of Carbon Dioxide Injection

While deepwell injection of liquids has occurred safely for over 20 years, there is less 

experience with injecting gasses like CO2. While most CO2 injections for enhanced oil 

recovery have occurred safely, problems that have occurred illustrate the unique hazards that 

utilities and regulators must consider. A few of these potential hazards include the following.

Blowout

Well blowouts occur when gas escapes through old or unknown wells. In January 2001, a 

natural gas leak from a cracked gas well casing leading to salt caverns and used as a natural 

gas storage facility resulted in an initial gas explosion below two stores in downtown 

Hutchinson, KS. The initial gas explosion was followed by an eruption of natural gas and 

water geysers two miles east of the initial explosion later that day and for several days 

thereafter. Two people residing in a trailer home were killed as a result of one of the 

explosions. The gas leak originated from a cracked well casing at a depth close to 600 feet 

and proceeded to migrate horizontally, traveling along abandoned brine wells and ultimately 

reaching the surface some distance away from the initial explosion.62

In another case involving CO2, a blowout occurred during drilling at a production well in March 

1982 causing the free flow of CO2 at the well head and leakage from ground fractures directly 

above the site. The high rate of CO2 from the well caused containment not to occur until the 

following month.63

A report jointly funded by U.S. EPA and U.S. DOE looked at injection well accidents in both 

the U.S. and abroad and issued recommendations for protecting against future accidents.64

The report issued a number of recommendations including: determining the potential for CO2

migration along unsealed fault and fracture zones; the potential for magmatic or seismic 

activity to cause damage to sealing caps resulting in CO2 releases; the potential for wells to 

transport CO2 to the surface; and implementation of public education and CO2 monitoring 

programs to minimize impact to human health and the environment from releases.65

The risk of blowout is hard to quantify since there is little information on the number of 

abandoned wells in the United States. It is difficult to estimate the number of these wells 

since some do not have observable caps or metal casings that can be detected through 

sensors. Texas estimates that there are approximately 11,000 orphan abandoned wells that it 

is gradually closing through a state program.66 Operators of CCS injection wells will have to 

find, close, and cap abandoned wells within the Area of Review.

62 Lewicki et al., at 41-2.

63 Lewicki et al., at 39-40.

64 Jennifer L. Lewicki et al., Natural and Industrial Analogues for Release of CO2 from Storage Reservoirs: 

Identification of Features, Events, and Processes and Lessons Learned, Earnest Orlando Lawrence Berkeley 

National Laboratory, Feb. 2006.

65 Lewicki et al., at 48-9.

66 Source Texas Railroad Commission at: http://www.rrc.state.tx.us/news-releases/2006/100606.html..
and 23

The DOE has a method of finding abandoned wells under its SEQURE program, however this 

program is not set up for national application. The SEQURE program uses low flying airplanes 

to detect abandoned wells and, as discussed above, aerial methods may not detect wells 

which do not have metal cases or other markers.

Economic Damage

The saline formations in Texas produce some oil and gas in formations nearby or overlaying 

the potential injection formations. In addition to well blowout, less apparent seeps from the 

injection zone into oil and gas producing layers can dilute the value of these deposits and 

ultimately return the CO2 to the atmosphere.67

Corrosion

As CO2 rises to the top of the injection layer, it may contact closed wells or the cement 

casings of older wells. If the CO2 reacts with water to form acidic compounds, these acids 

could start to erode the concrete. As more is eroded, the process accelerates, creating a 

reinforcing-negative cycle that could allow the CO2 to rise up the abandoned well to drinking 

water layers. While this problem can be prevented through different well closure 

approaches, the potential problem will increase the cost of an applicant’s Area of Review 

study and demonstration.68

Permitting Costs

In 2001, EPA estimated the costs of the siting requirements – the geologic study, the Area of 

Review study, and the no migration petition – as at least $2 million for a Class I hazardous 

waste well.69 EPA based its estimate on applicant experience, including an Area of Review of 

2.5 miles. If, as discussed above, the zone of influence could stretch to a radius of 13 miles, 

the Area of Review would be 26 times larger than for a typical Class I well. The siting studies 

and corrective measures for closing abandoned wells could approach $20 to $50 million. 

Operators (presumably electric utilities) would still need to pay for the well construction 

costs (estimated to be well over $1 million), permitting fees, operating, and the other costs.

Regulatory Capacity

In all, a Class I permit application can fill a bookcase with the required plans, analyses, and 

reports. States may spend over a year reviewing a renewal permit and several years 

reviewing a new Class I well permit.70 Because of the regulatory burdens, APPA staff 

speculates that states will require considerable permit fees to pay for these new state 

employees as well as analyses of new and renewed71 permit applications. Class II permits can 

be approved more rapidly. However, and as the maps show, as the UIC program has matured, 

Class I and II wells primarily now only occur where there is ample experience and knowledge 

of local and regional geography.

67 Nicot, et al. 

68 Nicot, et al.

69 EPA, 2001, at 20.

70 Source: Texas Commission on Environmental Quality (TCEQ) at 

http://www.tceq.state.tx.us/assets/public/comm_exec/pubs/sfr/057_06.pdf.

71 Class I permits may remain in effect for up to ten years as determined by the Program Director. See, 40 CFR 

144.28.
and 24

Even moderate adoption of CCS by new electric utilities would be the biggest expansion of 

underground injection in U.S. history. From the volumes above, the U.S. must undertake a 

dramatic expansion in its technical infrastructure to support safe CCS. In the private sector, 

engineers and geologists must identify, map, and investigate many more UI sites. In the near 

term there may be a shortage of experienced investigators. For the public sector, the skill 

gap is even more critical. Regulatory agencies must have sufficient in-house experience to 

review all of the technical information provided and to evaluate permit applications against 

the regulatory standards.

The size of the current regulatory skill shortage is illustrated by the following:

§ Less than half of regulatory agencies across the states have experience reviewing 

Class I or Class II permits. As the charts show, only about 20 states have experience 

permitting deep, high-volume injection wells. For CCS to occur in geologic formations 

around the U.S., many states must hire and train permitting staff or rely on EPA 

regional offices.

§ Experience is concentrated in a few regions of the country. Current experience is 

not distributed throughout the country, but concentrated in Texas, Louisiana, Florida, 

and a few other states. Unless states accept deep well injection in their states, CCS 

may require special CCS pipelines or via surface shipping carbon dioxide gas hundreds 

or thousands of miles from a power plant to an injection well. Pipeline shipment and 

booster compressors along the CCS pipeline increase the cost and perhaps the 

perception of the hazards of CCS. 

§ EPA regions must also boost their technical capacity. It is not only states that will 

be deluged with CCS permit applications. EPA regions approve UIC permits in some of 

the nation’s largest states and in states with large coal-fired power plants. EPA 

regions must craft their own approaches and technical requirements for CCS Class V 

permit applications.

§ Even in states with experience, states would need a significant boost in resources 

to permit a larger number of CCS wells. In 2006, Texas had ten new and eight Class 

I hazardous waste permit renewals under review. The average processing time was 

over one year for these permits. If CCS increases by a factor of ten the effective 

number of Class I wells in Texas, the regulatory system must either grow rapidly or the 

time needed to gain approval will soar.

Another consideration is the increased regulatory burden faced by electrical utilities when 

partnering with enhanced oil recovery (EOR) operations. Electrical utilities partnering with 

Class II well operators for EOR presumably would be subject to current Class I regulatory 

provisions, and ultimately any new regulatory requirements or framework established by U.S. 

EPA specifically to address CCS injection activities. 

Conclusion

Although the concept of CCS sounds promising, regulatory agencies’ paramount responsibility 

will be to ensure current and future protection of the nation’s drinking water supplies. For 

CCS to have a meaningful impact on U.S. power plant emissions, the mass of CO2 to be 

injected underground will dwarf current amounts by 10 to 20 times. While the nation has the 

ingenuity to tackle this challenge, it will require investing in technical skills, data, research, 
and 25

and education both in the private sector and in regulatory agencies. At the same time, there 

are major limitations that appear to preclude commercial-scale CCS in many parts of the 

country. APPA commissioned this paper to demonstrate the necessary regulatory systems 

needed to properly permit CCS into non-oil and gas or EOR sites. 

This paper does not outline the necessity to deal with other issues such as amending state 

drinking water laws or amending federal environmental laws such as the Comprehensive 

Environmental Response, Compensation, and Liability Act (CERCLA); Endangered Species Act 

(ESA), Resource Conservation and Recovery Act (RCRA), and CERCLA’s Natural Resource 

Damage Assessment Act (NRDA). These issues have been addressed by other APPA papers 

located at www.appanet.org/files/HTM/ccs.html

Recommendations

APPA recognizes that controlling CO2 emissions can bring about reductions in greenhouse 

gases . While there is considerable support for CCS and its promise for achieving sizeable 

emissions reductions, it is not clear the current regulatory structure and framework 

adequately addresses the limitations and adverse impacts related to CCS that have been 

noted above. APPA wants to ensure that these issues receive consideration and are 

appropriately addressed prior to moving forward with commercial-scale use of CCS.

1. APPA recommends that establishment of a process to ensure states and Public Utility 

Commissions are made aware of the limitations of CCS as addressed in this paper and 

that the issues be fully investigated prior to mandating CCS as part of permit approval.

2. APPA looks forward to working with the U.S. EPA on the cross-cutting or multimedia 

regulatory issues such as water use, drinking water, and air issues as they move 

forward with determining the best regulatory framework through which to review, 

approve, monitor commercial-scale carbon capture and storage projects.

American Public Power Association

1875 Connecticut Ave, NW

Suite 1200

Washington, DC 20009-5715