# 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 discussio n 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 o f all details discussed, nor does it embellish, interpret, or expand on matters that were incomplete or unclear. Statements represent the views of workshop participants.

### ii 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 o ptions

................................ ................................ ...... 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 P resentation and Supporting White Papers T echnical and Non

- technical Challenges of Sequestration Presentation Geologic CO 2 

### Sequestration Issue Spotting and Analysis Will Water Issues/Regulatory Capacity Allow or Prevent Geologic Sequestration for New Power Plants?

### 1

Welcome :

I NTRODUCTION 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 sector s (e.g., pulp and paper, cement, etc.)

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

o Stage of development of each te chnology

o Barriers to implementing technologies

o Legitimate costs

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

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

o What are currently av ailable 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 fra meworks 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
t he 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 CO 2 

### capture systems ?

o What is the e xpected date for availability of CCS?

o What are the prospects of using of CCS on NG and coal

- fired units?

o What are the l inkages between criteria pollutant control and CCS?

o What are the r ealistic achievable deployment ramp rates for nuclear and coal + CCS capacity in the f

irst 20 years after these te chnologies become commercially available?

o Are there n ew technologies that capture CO 2 

### as solid waste for use as byproduct?

o How does geography affect CO 2 

### mitigation options with respect to varying water availability, altitude, and suitability of local geolo gical formations for sequestration?

### 2

W ELCOME

Frank Princiotta welcomed the participants and stated that the reason for pushing this project is that there is a tremendous need for reduction in CO 2 

### 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 th e 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 b e 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.

D r . 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 a ffect 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% CO 2 

### from start

- up and the CO 2 

### will be sold for EOR in oil fields.

### 3

- Status $2.5B dollars cost; this is an attempt to take advantage of geography for close EOR application.

- The project will likely use off

- t he

- 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 generatio n? 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 consider s 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 w ithin 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 CO 2 

### emissions are required

.

Praveen Amar asked what would be the costs to replace nuclea r 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 captu ring CO 2 

### from the biomass plant? High CO 2 

### 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

### 4

conversion shouldn’t be considered a short term measure

. Theresa Pugh responded saying that there is always the huge que stion 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 infrastructur e needed for CCS or places to inject the CO 2


### . 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 CO 2 

### is naïve

. In short term, she think s 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 wi th 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 Hil ton 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 st ill 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
ret rofits

. 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 assoc iated 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 availabi lity? 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 CO 2 

### capture unit down.

Robert Hilton agreed with Theresa’s Pugh’s emphasis on energ y 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

### 5

geologic storage sequestration sites around most of its plants

. The question is where do we put the CO 2 

### ? 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 CO 2


### a long value chain (i.e., capture, compressions, transport, a nd 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 a nd asked for comments of that approach for improving CO 2 

### capture.

Jose Figueroa said you could repower existing plants but then have to consider the age and size of plant among other parameters. R etrofitting a small plant may not be viable

. One has to

acc ount 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 CO 2 

### capture technology

. Not all capture technologies are amenable to being shut down or ramping down

— hav e 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 do es n’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 o wns 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 w ill 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 di fferent

— 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

### 6

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

re newables 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 v astly 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

. T heresa 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 technolo gies 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 substanti al 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 la b (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
te chnologies 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 2 020

. 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 commer cial 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 ―commercial ly availab le ‖.

### 7

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 wit h 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 p erformance 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 FG D 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 th is 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 a n injection permit, it isn’t commercially demon strated

. She believes we will have too much CO 2 

### 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 mi ght be a separate hydrogen of CO 2 

### 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, s equestration), 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 CO 2 

### per yr from coal; the mass ratio of CO 2 

### vs. SO 2 

### control is 100 to 1

. From a weight perspective, controlling for CO 2 

### is 2 orders of magnitude higher than SO 2 

### ; we shouldn’t extrapolate too much from FGDs

.

Mike Surface agreed, warning that there wi ll be more CO 2 

### going out of a plant than coal coming in

.

### 8



### 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 avail ability of near

term 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

.

Nic k 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 them selves , 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 fo r 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 kno ws 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 manufacture r s 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 co st 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 tim es 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

### 9

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 ca pital 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 cost s 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 las t 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 ca pability 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 w ave , 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 Southe rn 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 t hat 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 ta ke 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 perfo rmance 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, y ou 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 ha ppen 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 t he 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 deplo yment 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 minimu m 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 th ought 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.

The resa 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, C alifornia , Alaska, Texas electricity prices have recently increased dramaticall y), 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 requir ed 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 ’ flags hip

### 11

units and they can use those to umbrella other units, it provides flexibility; but a command

- and

control policy will force the shut down of older smaller units

. A ll 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 CO 2 

### 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 lin es, 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

. CO 2 

### transportation costs from the east coast will be higher than those for o ther 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 homew ork 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 Br ownell 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 Figue roa responded that the issue is not

- ―C an 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 re liability

. 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 c apture 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 source s 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 t hat 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 pr ogress 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 M ississippi CCS demonstration intends to do any sequestration.

Larry Monroe said it will sell the CO 2 

### 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 CO 2 

### 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 CO 2 

### /year

. These are technology development steps to get 1 million tons of CO 2 

### 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 CO 2 

### /year) by 2020 from coal

. Nick Hutson asked if the timing for that is depen dent on government funding

. Larry Monroe answered yes, stating that sequestration for Southern Company ’s small system is currently funded by Southe a st 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 Steven s 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 proce sses 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 a bout replication vs

. scale

- up

. The piping

### 13

is not an issue of technology, but scale

. A demonstr ation 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? Ge orge 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 absor

ber?

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: s eismic 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 CO 2 

### would be used for EOR?

R obert Hilton does not think so; it makes sense but it depends on where it i s capture d

. 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 CO 2 

### storage (Class VI wells). If it i s jus t used for EOR, then it might be easier. Anna Wood added that under the Underground Injection Control (UIC) program, EOR is under C lass 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 t o availability, asking how availability and sequestration affects our ability to begin CO 2 

### 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 allo wance 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 fir st 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 integrate d) which build and operates a sequestr ation 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 drill ing 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 publ ic 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, post

injection 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 safet y 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 t o 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 pro duct for long

- term CCS projects.



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

- technical Challenges of Sequestration” The presentation is provided as A ppendix C.

She sta ted 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 d eep saline aquifers, close proximity to existing CO 2 

### 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 liste d 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 groundwa ter 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 thi s point there is lack of certainty pertaining to how much CO 2 

### 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 CO 2 

### mitigation technologies or strategies (including renewables and nuclear).
Jose Figueroa said one barrier for CO 2 

### capture is flue gas composition, which needs to be treated. Pre

- tre atment 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 t o 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 CO 2 

### 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 CO 2 

### capture would also remove constituents like arsenic.

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

. When CO 2 

### comes off, it’s 99.7% CO 2 

### 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 CO 2 

### 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 MAC T 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 CO 2 

### 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 guideli nes 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 CO 2


### . 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 over

comply with large new units so that the smaller older units can still operate

– but MACT requires compliance on every unit

. Because of this, h e estimates that industry

- wide about 20% of coal facilities would be retired

.

J. Edward Cichanowicz added that it is very c ostly 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 2 0%, 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 coupl e 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 switchin g 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 character ization 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 cap acity 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 becaus e 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 Fig ueroa 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 t hrough 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 Of

fen 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 Pug h said that yes, renewables are becoming more cost

- effective given a higher cost of everything else

. She raised two concerns about renewables: 1) I ce sheeting with wind turbines, where ice forms on the blade and operators are forced to consequently shut do wn 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 natu re 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 not ed 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 basel oad 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% CO 2 

### 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 po wer 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 ten sion 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 Lim it (PAL) over CO 2 

### ? An electric utility will serve load based on population and demand; if you set a PAL you cap economic prosperity since the permit limits CO 2 

### emissions

— inherently tied to the electric utility’s number of customers.

Anna Wood answered say ing 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 su re 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 raise s 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 prom ising (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

ar e 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 t he 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 des ign of the system in place but not built

. Robert Hilton asked: but how can you do that when there i s 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 desig nated 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 w ill 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 CO 2


### .

Mike Surf

ace 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 t here isn’t a concrete defini tion written yet, so it

w ill likely be a contentious issue.

Robert Hilton added that the problem is that one must commit to a tech nology without knowing how much it will cost and when it will be ready . Therefore, the plant cannot be financed because its c ost 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% CO 2 

### . He added that in climate legislation today, there is a performance standard that requires a certain number of gigawatts of CO 2 

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

Nick Hutson a sked: if you were going to build or recommend a new facility for your fleet, what would that tech nology look like, supercrit ical , ultra

- super critical

, IGCC , oxy

- coal, and why?

Larry Monroe answered that Southern Company is currently building an IGCC and s ome 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 pulveri zed coal (PC) units with CCS basis may be on the same level as IGCC with CCS with respect to conventional (SO x 

### , NO x 

### , particulate)

, and he thinks PC with CCS may control NO x 

### 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 ultra

supercritical 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,

a nd 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 t hink s the FutureG en RD&D is going the wrong direction with oxy gen

- blown IGCC

. Larry Monroe answered no because he is in favor of looking at all different options.

Mike Surface expr essed that in his opinion, supercrit ical and ultra

- supercrit ical 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) R D &D Spend ing

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 s ociety 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 seques tration) 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 pl ants might be built.

Praveen Amar agreed, adding that demonstrations at sc ale 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 technologie s which have high energy penalties . He thinks the emerging technologies, which show promise with respect to lower ing the energy pe nalt y , would then have difficultly gain ing 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 technologie s 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 progra m 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 believe s that we need to incentivize large scale fully commerci al projects that are looking to capture large amounts of CO 2 

### 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 c redits, 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 am ount of investment required to establish commercial acceptability from a regulatory standpo int.

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

, but added that in order to demo nstrate storage

— which is necessary to speed the development of CCS

— the mature technologies have to be demonstrated now.

Jo se Figueroa stated that capturing CO 2 

### presents a different set of circumstances. He thinks the emerging technologies coming up need to be fund ed; there is a lot of research going on a t research and industrial level and a lot of technologies are showing gre at promise at lab

- scale. His concern is that b y the time the emerging technologies get to large scale pilot demo nstration, we will have demonstrated amines and the opportunities for emerging technologies may not be as readily available.

Frank Princiotta a dded that there is danger moving forward wi th demonstrating uncertain technologie s . From his experience, billions of dollars have been spent for m any clean coal tech nologies for commercial scale demonstration, and many of them have not moved forward

. He wa rned 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 19 90s, noting successful learning from low

- NOx retrofit and SCR demonstrations. He added th at a ll of Southern Company ’s FGD technologie s 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 conversat ion to d iscuss ing any mercury control issues (an d other pollutants) or requirements specific to the application of GHG mitigation tech nologies. From his understanding, carbon capture systems negate mercury issues before the flue gas is emitted.

Larry Monr oe 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, SO 2 

### , HC , HF, particulates , which could impact the operation of the CO 2 

### 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 /mate rials ?

4) Policy impacts on developing technologies

Nick Hutson shifted the d iscussion to how policies might impact both near

- term and developing tech nology options

.

Anna Wood said that EPA recently announced the proposal of a light duty vehicle rule; w hen 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 A dvisory C ommittee subgroup will discuss a PSD deter mination for stationary sources; this will be discussed in a policy contex t. He said that st ates

are suggesting that we need practical guida nce 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 p otential co

- benefits associated with deployment of specific technologies . He anticipates further reduction s in other pollutants through the installation of capture systems and asked for comme nts.

Gary Rochelle pointed out that amine scrubbing will remove SO 2 

### , but it may increase NO x 

### . Nick Hutson asked if there are any effect s of NO x 

### on the capture system. Gary Rochelle answered that it remains to be seen.

Nick Hutson asked: What is known ab out possible env ironmental implications of diff erent 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 th e potential slip of reagents from the capture process.

Frank Princiotta commented on the additional mining of 25%

- 30% coal, drainage mining problems. There are li fe

- cycle consequences associated with CCS

. Robert Wayland noted the scrubber sludges and oth er 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 f or 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 w e 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 econo m i cal. 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 unit s 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 t he load.

Gary Rochelle asserted that this is a demonstration issue, noting that M itsubishi 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 uni ts the 6% CO 2 

### 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, g as will be regulated just as coal will, so we w ill eventually have to look at CCS for gas, but it will be wiser to start with certain applications first . G asification 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 realistical ly achievable deployment ramp rates for new nuke and coal + CCS capacity during the first 20 y ea rs after the tech nologies become commercially available ?

Gary Rochelle recalled that with FGD s, we always worried about whether or not we could get all the mat erials 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 80 s than today

. Plants were being built and resources and manpower were available. He contends that t oday, relative to then, we may not have the same resource s available

.

### 25

Larry Monroe added that FGD did not establish deep penetration until after 2000

— and we are still building, and we are probably o nly 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 tech nologies that capture CO 2 

### as a solid wa ste or useful by

- product

Gary Rochelle thinks that the q uantity of CO 2 

### that will be produced will pre

- empt the potential for useful product. Larry Monroe agreed but thinks that while CO 2 

### from power plants is good for growing algae, but it should not be co nsidered a sequestration option because it will eventually be emitted to the atmosphere. Mike Surface agreed, stating that algae have no impact on negating CO 2 

### emissions. Jose Figueroa noted a study in Arizona that concerns FTR membranes, capturing CO 2 

### and feeding it into an algae pond.

Theresa Pugh said a very useful use of CO 2 

### 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 CO 2 

### could be used for the gulf coast

. Theresa Pugh agreed, saying that injection along the outer

continental shelf would appease concerns about geo

- sequestration and drinking water, in particular.

9) How does geograp hy affect mitigation options? Is Water availability a concern ? What if tech nologies are applied at higher altitudes?

Praveen Amar took the opposite point of view, raising the issue that the CO 2 

### mitigation option will determine the location of the power plant . He asked: i f CCS is required in the future, where would you put a pla nt?

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 env ironmentally friendly place s; 2) cheap po wer 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) Feed back on impressions of promising CO 2 

### 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 c hemical 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 solvent s, if you try to ta ilor 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 audien ce’s impressions of solid sorbents?

Larry Monroe said he is s till waiting to see result s from research programs, so it is too early to tell.

Jose Figueroa stated that the issue with sorbents is material m a n agement and process integration ; he asked: I f i t i s 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 issue s are material handling a nd
process

. A lot of researchers aren’t looking at the process and how they are going to put the process and the sorbent tog ether in a power plant

.
11) S uggestions for fields in the database

William Stevens suggested a field accounting for the consequenc es of doing nothing and the associated c ost 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 t he use of the database is to help influence the regulatory decisions mad e, 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 info rmation, which could be just as use ful as the quantitative information. He thinks a comment section could be very helpful. Mike Surface suggested a field for CO 2 

### product quality because the analysis of CO 2 

### can determine what type of pipeline you are going to build.

Ben Yamagata suggested a field indicating w here the tech nology 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 info rmation available. Nick Hutson said that EPA is star ting 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 bar riers for technologies and how researchers are addressing these barriers.

Anna Wood stated that permitting aut horities will be interested in life

- cycle impacts.

Nick Hutson responded that life

- cycle impacts will be difficult to quantify but may be inclu ded in the qualitative c omment section s.

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 showin g 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 d atabase by June, 2010

.

John Sorrels aske d 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 th e database will be updated as well, and the user will have the ability to download data i nto Access or Excel.

## Appendix A

Attendees List

### A

- 1United StatesEnvironmental Protection AgencyAir Pollution Prevention and Control 

# Greenhouse Gas Mitigat ion 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

- 2 026 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 Manageme nt

- 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 Di vision 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

Chr istian 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 Labor atory 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 20 6 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@

sar gentlundy.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

Jeffr ey 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 Plann ing & 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 P rotection 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 Forb es 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 Labora tory 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 Cornwal lis 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

- 85 5

- 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 Roc helle 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 Protecti on Agency 109 TW Alexander D rive 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

- 56 90 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

- 5 375 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

- 0 839 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 Pa rk , 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 2 02

- 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 En gineer 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 P rotection 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 Jefferso n 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.w illiam@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 (CB 6116) 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 2 00 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 0184 5 978

- 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

- 1United StatesEnvironmental Protection AgencyAir 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), E nter building through main entrance, go through entrance security, sign

- in at front d esk, 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 Divisi on, 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 availa bility 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 o f Sequestration Presentation Geologic CO 2 

## 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 P resentation Geologic CO 2 

## Sequestration Issue Spotting and Analysis Will Water Issues/Regulatory Capacity Allow or Prevent Geologic

Sequestration for New Power Plants?SoberThoughtsAboutCCSforRetrofitorNewFossilPlantsasaCO2MitigationMeasurefrom2009‐2029TheresaPughDirector,EnvironmentalServicesAmericanPublicPowerAssociationEPAGHGMitigationMeasuresWorkshopResearchTrianglePark,NCNovember3,2009•APPArepresentstheinterestsofthe2,010municipalorpublicpowerutilities,whichprovideelectricitytoresidential,institutional,commercialandindustrialcustomers.•Createdin1940asanon‐profit,non‐partisanorganization.•APPA’spurposeistoadvancethepublicpolicyinterestsofitsutilitymembersandtheirconsumers,andtoprovidememberservicestoensureadequate,reliableelectricityatareasonablepricewiththeproperprotectionoftheenvironment.•PublicPowerprovideselectricityforapproximately45millionAmericans.•Publicpowerutilitiesareinsmall,mediumandlargecommunitiesin49states(allbutHawaii).Seventypercentofpublicpowersystemsarelocatedincitieswithpopulationsof10,000orless.•Overall,publicpoweraccountsforabout16percentofallkilowatt‐hoursalestoconsumers.Morethan90%ofAPPAmemberutilitiesmeetthedefinitionandqualifyunderSmallBusinessRegulatoryEnforcementandFairnessActof1996(SBREFA).•OverhalfofAPPA‘smembersintheelectricitysectorburncoal,particularlyintheMidwesternandSoutheasternpartsofthecountry.2BackgroundontheAmericanPublicPowerAssociation34PublicPowerGeneration(MWH)byEnergySource–2007Source: Ventyx (formerly Energy Velocity) Database•MostFavorableLocations–DeepSalineAquifers–ProximitytoCO2pipelines–NoorextremelylowSeismicPotential–ProximitytoTransmission–ProximitytoRailforCoalTransportation•LeastFavorableLocations–ModerateorHighlevelsofSeismicPotential–Unfavorablegeology–LackofTransmissionand/orrailforcoaltransportation5AssessingPreliminaryGuessesforMost&LeastFavorableLocationsforCCSDeepSalineAquiferLocations6DeepSalineAquiferLocations&‘Lenient’Seismic7DeepSalineAquiferLocations&‘Stringent’Seismic8SalineAquifers,CO2Pipelines,&‘Lenient’Seismic9OtherConsiderations– TransmissionLines10OtherConsiderations– Railroads11OptimalSites–UsingExistingCO2Pipelines12OptimalSites– NotRequiringProximitytoCO2Pipelines13NaturalGasPipelines14IncaseFuelSwitchingtoNaturalGasistheGHGMitigation– seeStateswithInterstatePipelineShortage15NaturalGasStorageStateswithUICPrimacy:CO2InjectionMostLikelyUnderSDWASource:http://www.epa.gov/ogwdw000/uic/primacy.html16“BestGuess”TimelineforBaseload(<600MW)CCSPlantinNon‐EOR/EGRStates17Subsurfacespacerequiredforonly40%oftheCarbonDioxidefroma300MWpowerplantforoneyear:2,750AcresSource:J.Gledhill,PolicyNavigationforAPPA18Subsurfacespacerequiredtosequester40%oftheCarbonDioxidefromapproximatelyNine500MWPlantsovertheir40‐yearlifetime:2,580squaremilesRoughly1.5timesthesizeofRhodeIslandRoughlyhalfthesizeofConnecticut192009EPRIPrismanalysisassumptions:–90%CO2captureforallnewcoalandnaturalgascombined‐cycleplantsbuiltafter2020–CCSretrofitfor60gigawattsofexistingcoalgenerationat90%captureefficiencyForRetrofitof60GW@90%captureefficiency:–Approximately77,400squaremilesofsubsurfacespace–RoughlythesizeofNebraskaor–RoughlytwicethesizeofMainePLUSareafor90%captureforallnewfossilplantsbuiltafter2020.ThisishighlydependentupongeologyoraccesstoCO2pipelines– allgeologycannotpromisesequestrationfor50yearscontinuously20EPRI“Prism”AnalysisOR•ParasiticEnergyLosses•CapitalRequirementsforOlderPlants•Pipelines•DealingwithFinancingolderplants•LuckyLocation?•LuckyGeology•ProximitytoUSDW(drinkingwatersource)andprotectiveregulations21RetrofitofExistingFossilPlants:HowRealistic?22Dealingwithapprox.30%ParasiticEnergyLossesWhenDesigningNewPlantsorRetrofittingOldPlantsSource:AdaptedfromL.D.Carter,WhitePaper,"RetrofittingCarbonCaptureSystemsonExistingCoal‐firedPowerPlants,"November2007ParasiticEnergyLossreferstopowerlostfromexistingplanttoadministerthetechnologiesrelatedtoCCSwhicharecircledintheabovediagram23SourceofMap:NatCarbAtlas;Overlay:APPAOptimalLocationCriteriaMapswithoutCO2pipelinesNote:OptimalLocationsarefornewplants,notretrofitofexistingpowerplantsExistingFossilGeneration&OptimalCCSLocationsWithoutAnyDrinkingWaterResourceLocationAnalysisAvailableathttp://www.appanet.org/files/htm/ccs.html•MarianneHorinko,"CarbonCaptureandSequestrationLegalandEnvironmentalChallengesAhead,"August2007•L.D.Carter,"CarbonCaptureandStorageFromCoal‐basedPowerPlants:AWhitePaperonTechnologyfortheAmericanPublicPowerAssociation(APPA),"May2007•L.D.Carter,"RetrofittingCarbonCaptureSystemsonExistingCoal‐firedPowerPlants,"November2007•JonathanGledhill,PolicyNavigationGroup;JamesRollins,PolicyNavigationGroup;TheresaPugh,APPA,WhitePaper,"WillWaterIssues/RegulatoryCapacityAlloworPreventGeologicSequestrationforNewPowerPlants?AReviewoftheUndergroundInjectionControlProgramandCarbonCaptureandStorage,"November2007•CarbonCaptureandStorage:AnalysisofPotentialLiabilitiesAssociatedwithGroundwaterContaminationDuetoGeologicalSequestrationOperations,September10,2008PreparedbyFredricP.AndesandKariA.Evans,membersoftheBarnes&ThornburgLLPWaterTeam,fortheAmericanPublicPowerAssociation(APPA)•TimothyGablehouse,WhitePaper,"GeologicCO2IssueSpottingandAnalysis"July200924APPA’sWhitePapersonCCSLinktoAPPA’sWhitePapersonCCS:http://www.appanet.org/files/htm/ccs.html•ForMoreInformation,Contact:TheresaPughDirector,EnvironmentalServices202‐467‐2943TPugh@APPAnet.org•ForQuestionsonCCSMaps,Contact:J.P.BlackfordEnvironmentalServicesEngineer202‐467‐2956JPBlackford@APPAnet.orgAPPA’sCCSInformation&Contacts252 

### GEOLOGIC C O SEQ UESTRATIO N ISS UE SPOTTING A ND ANA LYSIS WHITE P AP ER

Timot hy R Gablehouse 1 

### Gablehouse Calkin s & G ranberg LLC

July 22, 2009

OBJECT IVE

This paper

has bee n prepa

red f or APPA’s elec tric utility members a

nd water utilit ies for

the purpose of

survey ing the wide ra

ng e of issues that will influenc e the implementation of

g eolog ic ca

rbon seque stration. As with many things, seque stration is not as simpl e as it see ms.

I njection of a

ny thing into the subsurfa ce is re g ulated. Which ag encie s will act to reg ulate and

the cr iteria they

will follow depends upon the a nswer to the que stions raised in this paper –

questions that Congre ss and state leg islatures will need to a ddress if se questration is to be

2 

### implemented on a sc ale r emotely adequate to make a

differ ence in the amount of CO rea ching

the atmosphere

.

Wit hout a doubt sequestra tion projects will go f orwa rd. Many are alre ady

underw ay

. Nothing in this Whit e Paper should chang e any one’s view on the technolog y

available for

g eolog ic seque stration. Nor should any one re ad this paper to sugg est that there are fata l leg al

impediments to these projec ts. There are substantial leg al issues and a prudent mana g er w ould

be we ll advised to fac tor these issues into the business plan for a seque stration projec t.

Much of this pape r looks at the existi ng rules that apply to ge ologic sequestra tion. From

wher e we stand today

it is t hese r

ules that will apply

absent a ction by

leg islative bodies. For

2 

### example, if the CO being injected is a w aste we next need to know if its hazardous waste a nd

T i m o t h y G a b l e h o u s e i s t h e m a n a g i n g p a r t n e r o f t h e e n v i r o n m e n t a l l a w f i r m o f G a b l e h o u s e C a l k i n s & G r a n b e r g 1

L L C i n D e n v e r C o l o r a d o

. 4 1 0 1 7 S t , S t e 1 3 7 5 D e n v e r C O 8 0 2 0 2 t h t g a b l e h o u s e @ g c g l l c

. c o m


### 1

### reg ulated under RCR A. I f injection is limit ed to produc ing oil and g as oper ations for e nhance d

rec overy , then injection will be re g ulated by the state a g encie s that permit oil and g as

opera tions. The policies a nd proce dures of

these a g encie s and which pe rmits might be re quired 2



### are sometimes radica lly

differ ent state-by -state ha ving the potential to drastically chang e the

reg ulatory

burden a nd economics of

any projec t.

Common l aw theor ies dea ling with tre spass, mineral r ights a nd water rig hts all are

implicated as injec tion may result in trespass or

harm to surfa ce pr operty rig hts, mineral rig hts or

water rig hts. Depending upon in which state injec tion operations occ ur, there are signific ant

2 

### questions reg arding the owner ship and ac cess to the subsurf ace space s where the CO will be

2 

### place d. As the CO is intended to remain in the g round in perpe tuity , then we a lso need to

examine who rema ins responsible in perpe tuity . Reg ardle ss of whethe r these e ntities are pr ivate

corpor ations or public entities long -term liability issues will need to be a ddress a nd understood.

Absent newleg islative action existi ng statutes such a CERCL A (“ Superfund” ) will play a role

which mea

ns that the landowne r, minera l owner, injec tion operator a nd the entity

that produce d

2 

### the CO all may

have some liability

in perpe tuity

.

I t’s important to understand wha t this W hite Paper is not intended to ac complish. W hile

it will i dentify

a broa d rang e of pr operty and liability

issues associate d with injection projects, it

will not sugg est solutions t o all of them. I t will not address the ra ng e of liability

issues

associate d with the high- pressure pipeline infra structure nece ssary to move acid g ases f

rom the

2 

### point of g ener ation to the point of injection. For g eolog ic CO sequestra tion to become broa dly

viable ther e will need to be predic tability on how these issues a

re ha ndled. Many

will have no

predic table solution until and unless we have f eder al and state leg islation.

A c i d g a s i n

j e c t i o n f o r e n h a n c e d r e c o v e r y o f o i l & g a s i s d i f f e r e n t f r o m h y d r a u l i c f

r a c t u r i n g w h i c h i s a l s o u s e d t o 2

e n h a n c e r e c o v e r y b y p h y s i c a l l y o p e n i n g t h e s u b s u r f a c e f o r m a t i o n s u s i n g v e r y h i g h p r e s s u r e , p r o p r i e t a r y f o r m u l a s

a n d p a r t i c u l a t e s t o h o l d t h e f r a c t u r e s o p e n

. 

### 2

### BACK GR OUND

2



### Much work ha s g one into the technic al re view of g eolog ic CO sequestra tion.

(F reque ntly

this is refer

red to more g ener ically

as ca rbon ca pture a nd storag e or “ CCS ” – the

rema inder of this pape r will utili ze this nom encla ture.) Some wor k has g one into potential

reg ulatory

prog rams base d upon extensions of the curre nt EPA Underg round I njection Control

(“U I C”) prog ram. EPA has pr oposed a r eg ulatory approa ch which is the topic of a September

10, 2008 Whit e Paper

available to rea ders. ( As nothing ha s rea lly chang ed on this front, this

Whit e Paper

will not cover that e ffor

t in any detail.)

Some states are adopting reg ulatory prog rams with var ious deg ree s of complexity . I n

g ener al they

are based upon e x isting UI C prog rams or on injec tion of “ac id ga s” for production

enhanc ement in exist ing oil or g as oper ations. These c an be r adica lly differ ent appr oache s and

the interna l politi cal situation along with the perc eived importanc e of the oil and g as industry has

a lar g e impact.

I t is critical to distinguish betwee n production enha nceme nt injection prog rams and

2 

### injection of CO solely

for se questration purpose s as they are radic ally

differ ent in intent,

liability , risk and re g ulatory reg ime. A minera l owner ty pically has substantial rig hts to use

techniques suc h as fluid injection in order to produce the “miner als” like na tural g as and

petroleum. Oil and g as produc tion companies have substantial experience with this activity and

tend not to view it as very risky even thoug h it’s curre ntly benig n reg ulatory

posture is under

attack.

As an e x ample, the long -term liabilities associate d with production enha nceme nt versus

CCS scena

rios have substantially

differ ent leg al postures. F or example, a land ow ner or even a n
impacted ne ighbor

may have pr oducts liability

claims ag ainst the produce r of the injec ted

3

### enhanc ement fluid should it cause a dverse impacts outside of the na tural g as or pe troleum

production pool. I n a CCS project we w ould instead nee d to look to C ERCL A or RCRA for 3

2 

### g uidance on long- term re sponsibili ty for the CO

.

Not resolved to a

ny satisfac tory

deg ree are the questions of leg al ac cess to prope rty for

the purpose of

CCS , whether

it is waste disposal or something e lse, liability for the e ntire host of

things that pe ople ca

n imag ine might g o wrong , and long -term maintena nce/monitoring . All one

need do is e x amine EPA’s 2008 Te chnica l Support Document entitled “Vulne rability Evaluation

Fr amewor

k for Ge ologic Sequestration of Car bon Diox ide” to g et a se nse of the c omplex ity of

the problem a

nd the difficulty

of asse ssing potential r isks. 4



### That these r isks are a

rea l conce rn whe n it comes to permitting a nd opera tion should be

obvious. Som e examples may help to illumi nate the r isks that the public will fear:

- Fluid injection is suspected of causing Texas ear

thquakes. W

all Street Journal , J une 12, 2009, Pag e A3.

- Earthqua

kes ca used by deep w ell injection of wa stes at Rocky Mountain Arsena l. http:// ear thquake.usg s.g ov/reg ional/states/colorado/history .php

2 

### - Cry stal Gey ser UT – CO cold wate r er uptions through a

manmade w ell. http:// www.uwe b.ucsb.edu/~g lennon/cry stalg ey ser/

- 1986 L ake N y os eruption and de aths.

- “CCS mobi liz ation of hazardous, na turally occur ring materia ls is a risk that must be char acte rized.” “I njection into saline forma tions has the potential to disturb reg ional
g round-water flow sy stems and could contaminate drinking water .” Para phrase d from the testimony

of Dr. B urruss, USGS, Subcommitt ee on E nvironment and Hazardous Ma terials, House Commi ttee on Ene rg y and Commerce , J uly

24, 2008

2 - 

### Transpor

tation infrastruc ture to transpor t CO to injection sites does not ex ist – USGS projec ts that an infra structure larg er tha n the exist ing natural g as/petroleum industry will be require d to achieve meaning ful levels of CCS.
h t t p : / / e n e r g y

. e r

. u s g s

. g o v / h e a l t h

_ e n v i r o n m e n t / C O 2

_ s e q u e s t r a t i o n / C O 2

_ i l l u s t r a t i o n s

. h t m l

S e e M o d e s t o , C i t y o f v

. T h e D o w C h e m i c a l C o

. , e t a l

. , N o

. 9 8

- 9 9 9 3 4 5
, C a l i f

. S u p e r

. , S a n F r a n c i s c o C o

. ( l i a b i l i t y 3

b a s e d o n p r o d u c t s l i a b i l i t y t h e o r i e s f o u n d f o r d r y c l e a n i n g f

l u i d o f f

- s i t e i m p a c t s )
4 h t t p : / / w w w

. e p a

. g o v / c l i m a t e c h a n g e / e m i s s i o n s / d o w n l o a d s / V E F

- T e c h n i c a l

_ D o c u m e n t

_ 0 7 2 4 0 8

. p d f



### 4

### ISS UES an d DISCUSS ION

I. Liab ility During In jec tion / Op erat ional L iabil ity

Oper ational liability

includes the e nvironmental, hea lth, and safe ty risks associate d with

2 

### CO captur e, tra

nsport, and injection. Enha nced f luid recove ry

contra ctors ar e alr eady

subject to

a duty of ca re de fined unde r tort law a nd are usually

subject to standar ds of conduc t under their

contra ctual ar

rang ements. Companies providing these spec ific ser vices ha ve experienc e in their

industries, and ar e subjec t to liabili ty for wor ker sa fety and prope rty

damag e re sulting fr om their

conduct. The se compa

nies are best positioned to manag e the r isks associated with their ow n

conduct a nd are able to obtain liability insurance for their

conduct a

nd worke rs. I n survey s and

5



### case studies, these compa nies wer e willing to pr ovide servic es on a c ommercia l basis and

g ener ally willing to ac cept liability for their actions. 6



### Howeve r, it is forese eable that larg e-sc ale CCS could make it less likely that companies

will be willing to ac cept liability for injec tion. For e x ample, if ther e wa s contamination at the

surfa ce dur ing injec tion operations it could potentially aff ect dr inking wa

ter. The re is cur

rently

no law prote cting commerc ial or public oper ations from the full ra ng e of liabilities should they

cause contamination.

I n theory g overnme nt ag encie s could conduc t the injection opera tions to l imit l iability

associate d with injection. An example of this is L awr ence v. Bue na Vista Sanitation District. 7



### Neig hbors broug ht a trespa ss claim ag ainst the sanitation district, alleg ing c ontamination from

leaka g e at the district' s wastewa ter tre atment fa cility

but did not arg ue that neg lige nce w as

M

. A

. d e F i g u e i r e d o , D

. M

. R e i n e r , H

. J

. H e r z o g , T o w a r d s a L o n g

- T

e r m L i a b i l i t

y F r a m e w o r k F o r G e o l o g i c C a r b o n 5

S e q u e s t r a t i o n , P r e s e n t e d a t t h e S e c o n d A n n u a l C o n f e r e n c e o n C a r b o n S e q u e s t r a t i o n , A l e x a n d r i a , V a

. M a y 2 0 0 3

. C r a i g A

. H a r t , A d v a n c i n g C a r b o n S e q u e s t r a t i o n R e s e a r c h i n a n U n c e r t a i n L e g a l a n d R e g u l a t o r y E n v i r o n m e n t : A 6

S t u d y o f P h a s e I

I o f t h e D O E R e g i o n a l C a r b o n S e q u e s t r a t i o n P a r t n e r s h i p s P r o g r a m , D i s c u s s i o n P a p e r 2 0 0 9

- 0 1
, C a m b r i d g e , M a s s

. : B e l f e r C e n t e r f

o r S c i e n c e a n d I n t e r n a t i o n a l A f f a i r s , J a n u a r y 2 0 0 9 ( f

i n d i n g d r i l l i n g c o m p a n i e s

w i l l i n g t o p a r t i c i p a t e i n C C S a n d a c c e p t l i a b i l i t y f o r t h e i r a c t i o n s )

. L a w r e n c e v

. B u e n a V i s t a S a n i t a t i o n D i s t

. , 9 8 9 P

. 2 d 2 5 4 ( C o l o

. A p p

. 1 9 9 9 ) 7



### 5

### prese nt. The cour t held that the district was immune fr om a trespa ss claim under G overnme ntal

I mmunity Act “unle ss neg lige nce is prove n”. Tre spass is not a dang erous c ondition of a public

water fac ility or public sanitation fa cility ; beca use the tre spass claim did not require proof of

neg lige nce it wa s barr ed by Gover nmental I mmunity . Nobody should take this sort of outcome

as an indica tion that gove rnment ag encie s can c onduct these ope rations with impunity – there are

many other a vailable theor ies of liability

.

II. P ost Inject ion L iabil ity

A. Own ership of

P ore Space

The surf ace owner

usually owns pore spa ce be cause mineral c onvey ance s, including

lease s, normally

only pass title to the minerals, not the pore space itself. That does not, howe ver,

end the c onversa tion over who c ontrols the pore spa ce pr operty rig ht. The surfa ce ow ner c annot

violate the minera l estate owne r’s or le ssees’ r ights by doing some thing inter fer ing w ith acce ss
to the minerals, making the minera ls more expensive to expl oit or making the deve lopment of

the minera ls economica lly impractica l. Clearly

injection into the pore spac e could c ause this sort

of har m. The surfa ce ow ner must also allow re asonable use of the pr operty to give acc ess to the

mineral e state. For

CCS projec ts to procee d it is som ewha t rec kless to assume that ag ree ment 8



### with the surfa ce ow ner is the only nece ssary

step. I t seems prude nt to have ag ree ments with

both surfac e and miner al owner s even thoug h it seems likely that the surfa ce ow ner ow ns the

pore spa ce. 9



### B. Risk of

Leakage

Post-injection liabili ty

includes har

m to human health, the envir onment, proper ty , and the

climate liability

rela ted to leaka g e or mig ration of c arbon dioxide from g eolog ical re servoirs a nd

C a s s i n o s v

. U n i o n O i l
, 1 4 C a l

. A p p

. 4 t h 1 7 8 5 ( 1 9 9 3 ) 8

G e o l o g i c C O 2 S e q u e s t r a t i o n : W h o O w n s t h e P o r e S

p a c e ?
, 9 W Y L R 9 8
, 2 0 0 9

. 9



### 6

### the ef

fec t on climate cha

ng e. Potential pathway s for c arbon dioxide relea se include le akag e
throug h the pore s of low-pe rmea bility cap r ocks if the c arbon dioxide is inj ecte d at too high a

pressure , leaka g e throug h opening s in the cap r ock, lea kag e throug h abandone d or improper ly

seale d wells, and mig ration via fa ults. 1 0



### Reportedly , there is a low risk of ca ptured c arbon le aking into the atmosphere in amounts

2 

### signific ant enoug h to pose a risk. CO and natur al g as has be en stored naturally in ge ologic 1 1



### formations for

milli ons of y ear s and compa nies alre ady

store natur al g as under g round with a lot

2 

### of experienc e. The re a

re na turally

occur ring CO rese rvoirs in the we stern states that have held

2 

### g as for milli ons of y ear s. Furthe rmore, ove r 100 million t ons of CO has bee n injected into oil

rese rvoirs for

enhanc ed fluid re cover

y as we ll as into deep saline a quifers ( over 80 pr ojects have

been implemente d worldwide)

. Commercial and e x perimenta l projects have shown the 1 2



### potential for CCS across a wide ra ng e of g eolog ical setting s.

There are , howeve r, re ports sug g esting that an exceptionally detailed a

naly sis of g eolog ic

2 

### conditions is critical to understanding how the CO is being sequester ed in ea ch ca se. Whether

2 

### CO is being mineral tra

pped, in which c ase it may be stable on g eolog ic time scale s, versus

dissoluti on in gr oundwater is critical to an a ssessment of whe ther a potential for lea

kag e is

prese nt. Dissoluti on in gr oundwater is not prefe rre d as it has the g rea test potential for e ventual

leaka g e to the atmospher e. 1 3

2 

### The long -term liability

associate d with CO leaka g e that dama g es hea lth or proper ty is

difficult to establish beca use it is dissi milar to other re g ulatory scheme s and has a

timeframe of

thousands of y ear s. We simpl y do not know what risks long -term g eolog ic storag e pre sents.

I P C C
, I P C C s p e c i a l r e p o r t o n c a r b o n d i o x i d e c a p t u r e a n d s t o r a g e ; 2 0 0 5

. 1 0

F e i d m a n , T h i s w o r k p e r f o r m e d u n d e r t h e a u s p i c e s o f t h e U

. S

. D e p a r t m e n t o f E n e r g y b y L a w r e n c e L i v e r m o r e 1 1

N a t i o n a l L a b o r a t o r y u n d e r C o n t r a c t D E

- A C 5 2

- 0 7 N A 2 7 3 4 4 R o c k y M o u n t i a n M i n e r a l L a w I n s t i t u t e 1 2

A e s c h b a c h

- H e r t i g 

### , C l e a n C o a l a n d S p a r k l i n g W a t e r , N A T U R E
, V o l 4 5 8
, P a g e 5 8 3
, A p r i l 2 0 0 9

. 1 3



### 72



### Ex posure to CO ty

pically is not dang erous e x cept in ver y high c oncentr ations (> 15,000 ppm).

For example, in L ake N y os 1,500 people died w hen a la ke over a mag ma pool rele ased la rg e

2 

### amounts of CO . This is unli kely to occur at injection wells whe n proper ly monitored.

2 

### Resear cher s have suc cessf ully plugg ed and a

bandoned CO injection wells, eve n badly damag ed

2 

### and fa iled wells. I n wells that have failed a nd rele ased CO , almost all were detec ted quickly and

stopped. 1 4



### EPA produce d a Jul y

2008 white pape r entitled Approaches To Ge ologic Sequestration

Site Stewardship After Sit e Closure

. They descr ibe the adva

ntag es and disadva

ntag es of 1 5



### stakeholder

develope d models as well as mode ls based upon existi ng fede ral law s rang ing f rom

the Nucle ar I ndustries I ndemnity Act throug h CERCL A. I f CCS i s viewed a s waste disposal the

“cr adle- to-g rave ” model of the RCR A and pe rpetua l nature of liability under CERCL A would be

2 

### inconsistent with any

eff ort to limi t responsibility

for injec ted CO and espe cially any potentially

hazardous conta

minants entrained in the injec ted mater ials.

2 

### EPA’s ana ly sis has been c riticized as unrea listi c g iven that g eolog ic storag e of CO is

intended to be indef

inite and well bey ond 50 y ear s. The author s of a r ece nt report view this as

the sing le g rea test leg al obstacle to commerc ial deploy ment of CCS. Quite obviously
,

1 6



### leg islation will be re quired to addr ess this issue if there is to be a ny time limi t on liabilit y

.

2 

### C. P ropert y Rights Issu es Re lated to Migr ation of Inject ed CO

1. Natural G as Storage Law May P rovide Som e Insight

S

. J u l i o F r i e d m a n n , C a r b o n M a n a g e m e n t P r o g r a m A P L G l o b a l S e c u r i t y P r i n c i p l e D i r e c t o r a t e , L L N L

. . S

. 1 4

D e p a r t m e n t o f E n e r g y b y L a w r e n c e L i v e r m o r e N a t i o n a l L a b o r a t o r y u n d e r C o n t r a c t D E

- A C 5 2

- 0 7 N A 2 7 3 4 4
1 5 h t t p : / / w w w

. e p a

. g o v / O G W D W / u i c / p d f s / s u p p o r t

_ u i c

_ C O 2

_ s t e w a r d s h i p f o r s i t e c l o s u r e

. p d f

W o r l d C l i m a t e C h a n g e R e p o r t , 8 7 W C C R
, 0 5 / 0 8 / 2 0 0 9
, B N A

. 1 6



### 8

### Gas that is injected f or storag e re mains the proper ty of the injec tor. I njection of g as 1 7



### into property

that the injector doe s not own is a trespass. Pore spac e for such projec ts can be 1 8



### purcha sed or lea sed fr om the landowner , and/or the miner al estate owner , so long a s it does not

damag e other

persons. Ag ree ment with the mineral e state owne r or lesse e will g ener ally be 1 9



### prudent in orde r to avoid later damag e or tre spass claims as ther e is ambig uity in some states

reg arding whether

a minera l owner ow ns the pore spa ce pr eviously occupie d by

the minera ls,

natura l ga s or petrole um they have r emoved. L iability for ne g lige nt opera tion of storag e 2 0



### opera tions ex ists. 2 1



### Under many fede ral a nd state laws utility

companies ha

ve eminent domain r ights for

utilit y fac iliti es. This beg s the question of whe ther CCS operations repr esent a utilit y fac ility

under the se statutes – if viewe d as wa ste disposal, there is doubt. These statutes do not addre ss
the ability to exercise eminent domain r ights ove r buff er zones that may

be desira ble bec ause of

the potential for g as mig ration. B uffe r zones should be included be cause g as esc ape is a

trespass; howe ver, howsuch a buf fer might be va lued in an eminent domain a ction is unknown.

Wit h reg ards to ca

rbon seque stration the conc ept of c ondemnation poses seve ral

problems. CCS pot entially involves larg e ar eas of

land – hundre ds of ac res - depending upon the

subsurfac e conditions and re sulting ava ilable storag e volumes. The unc erta inty over w hether 2 2



### statutory authority to exercise imminent domain applies sug g ests an initial effor t to neg otiate and

purcha se rig hts. I f injection re quires appr oval from a ny landowner

that could be a ffe cted, then it

E l l i s v

. A r k a n s a s L o u i s i a n a G a s C o

. , 4 5 0 F

. S u p p

. 4 1 2
, 4 1 9 ( D

. C

. O K L 1 9 7 8 ) a n d m a n y o t h e r s 1 7

K u n t z , T h e L a w o f O i l a n d G a s s 2

. 6
, p

. 7 1 1 8

E l l i s , a t 4 5 0 F

. S u p p

. 4 1 2 1 9

G e o l o g i c C O 2 S e q u e s t r a t i o n : W h o O w n s t h e P o r e S

p a c e ?
, 9 W Y L R 9 8
, 2 0 0 9

. 2 0

I n a r e c e n t c a s e f

r o m L o u i s i a n a a j u r y a w a r d e d $ 9

. 2 M t o a p e t r o l e u m c o m p a n y w h o s e a b i l i t y t o e x p l o i t r e s e r v e s 2 1

w a s a d v e r s e l y i m p a c t e d b y i m p r o p e r m a i n t e n a n c e a n d o p e r a t i o n o f a n e i g h b o r i n g s a l t d o m e s t o r a g e f a c i l i t y

. S e p a r a t i o n a n d c a

p t u r e o f C O 2 f r o m l a r g e s t a t i o n a r

y s o u r c e s a n d s e q u e s t r a t i o n i n g e o l o g i c a l f o r m a t i o n s

- - 2 2

c o a l b e d s a n d d e e

p s a l i n e a q u i

f e r s

. J A i r W

a s t e M a n a g A s s o c

. 2 0 0 3 J u n ; 5 3 ( 6 ) : 6 4 5

- 7 1 5



### 9

### will be nece ssary to secure consent fr om a potentially larg e number

of people . Neg otiation and

condemna tion will t here fore impose high c osts and long a cquisition ti mes.

As it will not be the intent (in most case s) to later r etrieve the g as, there are interesting

questions and serious unknowns r eg arding the rig hts and duties of the prope rty owner s later in

2 

### time. Establishing owne rship of CO in perpe tuity is a key part of this problem, e specia lly g iven

the vast amounts of time it will be sequester ed. I f there is no intent to recover perha ps there is

2 

### no duty to protect a

nd prese rve the CO or the a ssociated surf ace fac iliti es. I f the e ntity that

2 

### owned the CO when it was injec ted disappea rs, then whe ther the CCS process is wa ste disposal

or something else will be c ritical to understa nding the on-g oing duties of the landowne r. Any

resolution of this issue will require leg islation.

2. Enh anced Oil Recover y
Oil and g as lea ses ty

pically contain the r ight to inject f luids to aid in t he produc tion of

g as or oil, but not for disposal of wa ste. L ease s and state law s often g ive the produc er the rig ht

to “unitiz e” f

or sec ondary

rec overy allowing injection in various locations of a field. These

2 

### enhanc ed re cover

y eff orts are not nece ssarily

desig ned to seque ster CO even if “ac id ga s” is

used. Given the lease /contrac t rig hts these proc esses a re pr obably

not a g ood mecha

nism to

examine the broade r liability issues associate d with CCS projec ts unassociated w ith oil and ga s
production.

As noted bef

ore liability

for the injec ted mater ials, such as hy draulic f rac turing fluid or

acid g as, exists reg ardle ss of why these mate rials wer e injecte d. Contract or le ase the ories will

apply and may be of va lue in the short-ter m until t he norma l statute of limitations runs. B ey ond

these theor ies liability

is likely perpe tual under f

eder al environme ntal laws as these fluids will

10

### ty

pically contain hazar dous substances. As note d ear lier, produc ts liabili ty theories may

apply to

the entity that produce d the fluid if it harms third persons.

3. Waste Injec tion

Wastewater

wells are subject to permitting by EPA and/or states. F ailure to obtain

permits or oper ate within the ter ms of a per

mit will make the ope rator subje ct to ag ency

enfor ceme nt and citizen suits. Obvious ly the par ty injecting must have the leg al rig ht to do so;

howeve r, wha t those rig hts mean will be hig hly varia ble. I n Chance v. BP Chemical, the

Supreme Court of Ohio de termined that the de fenda nt committed a trespass whe n chemica ls

injected unde rg round mig rate d under pla intiff’s prope rty for whic h no rig hts had bee n acquir ed.

Even so, the pr oper e valuation of da mag es is very uncer tain.

The c ourt held that the surf ace owner ’s rig hts were not absolute, but were conting ent on

the re asonable and for esee able use of their pr operty

. Acc ording to the court, subsurf ace rig hts 2 3



### include the r ight to exclude invasions of the subsurf ace proper

ty that actua lly

interfe re w ith the

proper ty owner ’s re asonable and for esee able use of the subsurf ace

. This would most certainly 2 4



### include har

m to minerals or oil and g as re source s leased by the landowne r.

This sort of ana logy

would work we ll for CCS because la ndowner ’s that ar e not har med

2 

### by stored CO would have no c ause of action. I t seems to follow that there would only be a

2 

### cause of ac tion after CO specific ally damag es the he alth or prope rty of a la ndowner – not for

specula tion that ga s could potentially leak f rom g eolog ic forma tions or interfer e with ac cess to

minerals or oil and g as. Many courts would likely

disag ree and would find diminished value

simply due to the tre spass. L eg islation, rather tha n litigation, is by

far the best wa

y to establish

the rules in this are na.

C h a n c e v

. B P C h e m i c a l
, 1 9 9 5 W L 1 4 3 8 2 7 ( O h i o C t

. A p p 1 9 9 5 ) 2 3

I d

. 2 4



### 11

### 4. Wastewater

I n Cassinos v. Union Oil C o., the owner s of a miner al estate sued def endant f or dama g es

when de fenda

nt injected wa stewate r into the mineral e state. The Ca lifornia Appe als Court

reje cted the de fenda

nt’s claim that it should not be liable beca use the plaintiff did not establish

the extent of damag e to the minera l estate. The court he ld that there w as substantial evidenc e the

defe ndant’s ac tions int erf ere d with and damag ed the miner al estate . There fore , the def endant

committed a trespa ss. The cour t also held that the plaintiff in the c ase c ould waive the tor t claim

and collec t on an alter

native theor

y of contra ct implied in law to rec over the value of the use

taken. 2 5



### Fr om Chance ( supra) and Cassinos, it is apparent that a cause of ac tion is not likely to

occur if there is no damag e done. I nterfe renc e with minera l rig hts should be a conc ern be cause

CCS can displac e subsurfa ce g ases a nd g roundwa ter, whic h could damag e minera l estates. The

holder of a

mineral e state or lea se would have a ca use of a ction along with the surfa ce ow ner.

I f the a ctivity

is allowed by

statute it does not nece ssarily mean that the injec tor will be

absolved of liability . I n Tidewa ter Oil Co. v. J ackson, the re w ere damag es to plaintiffs' oil wells

as a r esult of wate r flooding opera tions conducted by defe ndant on adjoining proper ty . The Court

of Appe als held that whe re de fenda nt's w ater flooding activities wer e intentional and da mag e to

wells on adjoining land was f orese eable , defe ndant was liable under K ansas law for da mag e to

wells of adjoining lease holders.

These f indings we re inc onsistent with the administ rative f indings to the e ffe ct that the

water flooding opera

tions were c arr ied on in a lawf ul manner. I

n the view the c ourt took, it was

unnece ssary

to rec oncile the f

indings. I t was suffic ient that the wate r flooding activities wer e

intentional and the conse quence s fore seea ble. A leg al claim wa s available , even thoug h the

C a s s i n o s v

. U n i o n O i l C o

. , 1 4 C a l

. A p p

. 4 t h 1 7 7 0
, 1 8 C ( C a l A p p 1 9 9 3 

### ) 2 5



### 12

### flooding was law fully car ried on, be cause it caused substantial injury to the claimants. This 2 6



### case is important because it highlig hts that reg ulations that allow CCS may not absolve the

defe ndant of c ommon law proper ty law liability

.

4. Water Law

I t most of the Western US surfac e and g roundwa ter is a public r esourc e dedic ated to the

benef icial use of public a g encie s and private persons whe reve r they might make benef

icial use of

the wate r. (Te x as is a bit differ ent in that g roundwa ter be longs to the la ndowner and is not

subject to prior a

ppropriation. Tha t can r esult in significa nt fig hts betwee n neig hbors should one

pump so much g roundwa ter that a neig hbor’s we ll becomes dry . This law of the “ bigg est pump”

has bee n mitigated thr oug h administrative proc esses such a s conser vation districts regulating the

use of g roundwa ter. ) Unde r the g ener al weste rn appr oach, inc luding surf ace water in Texas, 2 7



### water quality and quantity

are proper

ty rig hts subject to statutory and common law pr otections.

The big g est diffe renc e betwe en wa ter a nd rea l property

is that the protections ava ilable for w ater

fre quently

exceed those a

vailable f or re al prope rty

. The rig ht of wate r use include s the rig ht to cross the lands of othe rs to place water into,

occupy and conve y

water throug h, and withdra

w wate r fr om the natura l water bear ing

formations within the state in the exerc ise of wa ter use r ight. Natural wa ter be aring formations

may also be used f

or the tra nsport and re tention of wate r. Water authorities c an inject water for 2 8



### later w ithdrawa l with no pay ment for the por e spac e. The proper ty rig hts of landowner s or

mineral e state owne rs/lessees do not include the rig ht to control the use of w ater in the g round

and ca nnot claim control of a quifers a s part of the ir estate. E x cept f or Texas, g roundwa ter is par t

of “w ater s of the state” and either by Constit ution or statute, the g ener al assembly of ea ch state

T i d e w a t e r O i l C o

. v

. J a c k s o n , 3 2 0 F

. 2 d 1 5 7 ( C

. A

. K a n

. 1 9 6 3 ) 2 6

S i p r i a n o v

. G r e a t S

p r i n g W a t e r s o f A m e r i c a , e t a l

. , 1 S W 3 d 7 5 ( T e x a s 1 9 9 9 ) 2 7

B o a r d o f C o u n t y C o m ’ r s o f C o u n t y o f P a r k v

. P a r k C o u n t y S p o r t s m e n ’ s R a n c h
, 4 5 P

. 3 d 6 9 3
, 7 0 6 ( C o l o

. 2 0 0 2 ) 2 8



### 13

### has control ove r the use a nd dispositi on of g roundwa ter re g ardle ss of whethe r it is or is not

direc tly discharg ed to a na

tural strea m.

The lawin most st ates prohibits the taking of private proper ty for public or

private use

without the property

owner ’s conse nt, but there a re f reque ntly exceptions which perta in to

constructe d water

fac iliti es. For

example many

wester n state constitutions provide for a cce ss 2 9



### to the water

source acr oss the lands of other s and fur ther re cog nize and addre ss the private r ight

of conde mnation for the c onstruction of wa terwor ks. There is a requir ement for compensa

tion 3 0



### for use of anothe r’s land, but that doe s not ex tend to employ ment of natura l water

bear ing

subsurfac e for

mations on or within the landowner ’s prope rty for the move ment of appr opriated

water

. An applica

nt for a c onditional decre e to utiliz e ava ilable aquife r storag e spac e must 3 1



### demonstrate tha t it will captur e, possess, and c ontrol water lawfully available to it and without

injury to other wa ter rig hts. 3 2



### Water storag e under

a landowne r’s prope rty

is not a trespass if it does not inhibit the use,

benef it, or enjoy

ment of prope rty

. I n Boa rd of County

Commi ssioners v. PCS R, L L P, PC SR 3 3



### proposed to store w ater

in underg round aquife rs under ly ing a pproxi mately

115 square miles.

The landow ners c laimed that storag e of w ater underg round in aquife rs under neath their

land

would constitute a trespa ss. The Court held that it would not be a tre spass and the pr oject would

not require the L andowne r’s c onsent or conde mnation and the pay ment of just compensation

under the provisions of Article X VI . The c ourt, in apply ing Ca usby
, found that the proje ct did 3 4



### not include construc tion of any fac iliti es on or in the L andowne r’s prope rties and the

C o l o

. C o n s t

. a r t

. X V I § 7 2 9

C o l o

. C o n s t

. a r t

. I I § 1 4 3 0

S p o r t s m e n ’ s R a n c h
, a t 4 5 P

. 3 d 7 0 8 3 1

I d

. 3 2

S p o r t s m e n s ’ s R a n c h
, 4 5 P

. 3 d a t 7 0 8 3 3

U

. S

. v

. C a u s b y , 3 2 8 U

. S

. 2 5 6 ( 1 9 4 6 ) ( r u l e d t h a t p r o p e r t y o w n e r ’ s r i g h t s w e r e n o t u n l i m i t e d w i t h r e s p e c t t o 3 4

a i r s p a c e )

. 

### 14

### L andowne r’s ha d not alleg ed that the use , benef it, and enjoy

ment of their pr operties would be

invaded or

compromised in any

way . There fore , it was not a trespa ss.

The c ourt stated that the Ge nera l Assembly , in authorizing the use of aquife rs for stora g e

of ar tificially rec harg ed proje cts furthe r supplanted the L andowne rs’ c ommon-law prope rty

owner ship theory

. The c ourt found it “par ticularly [si g nificant]” that: 3 5



### (1) [F]eder al patents to land do not include w ater , (2) g round wa ter is not a minera l under the fede ral mining laws ..., (3) fede ral statutes a s interpre ted by the Supreme Court

rec og nize [ a state’ s] authority to adopt its own sy stem for the use of all wa ters within the state in ac corda

nce w ith the needs of its citizens, subject to the prohibitions ag ainst interfe renc e with fe dera l reser ved rig hts, with int erstate commerc e, and w ith naviga bility of any navig able wa

ters, (4) the rig ht of prior a ppropriation applies ... to wa ters of the
natura l stream, including surfa ce w ater and tributary

g round wa ter; (5) the prope rty rig hts of landowne rs do not include the r ight to contr ol the use of water in the g round, wha tever the cha rac ter of tha t water ; and (6) the Gene ral Asse mbly has plena ry control over

the use and disposition of g round wa ter that is not part of the natura l stream. 3 6



### I n sum, the holders of wa ter use r ights may

employ underg round as we ll as surfac e wa ter

bear ing f ormations in the state for

the place ment of wa ter into, occ upation of wa ter in,

convey ance of wa ter throug h, and withdra wal of w ater

from the na tural wa ter be aring formations

in the exercise of

water use rig hts. Consent or just compensation was not re quired be cause the

3 7



### plaintiffs did not have the r ight to re strict the def endant’ s use of the w ater

that was done within

reg ulations.

2 

### CCS prese nts a unique problem be cause the under g round storag e of CO could

potentially

aff ect the f low and loca tion of g roundwa ter. This could oc cur be cause the proc ess of

phy sical trapping

may displace na turally

occur ring water

and other g ases. Any

eff ect on water 3 8



### resour ces c ould pose potential liability if it lim its acce ss to water tha t has alre ady been

I d

. a t 7 0 3 3 5

I d

. 3 6

I d

. a t 7 1 2 3 7

S t a t e m e n t o f D r

. R o b e r t B u r r u s , R e s e a r c h G e o l o g i s t , E n e r b y R e s o u r c e s T e a m U

. S

. G e o l o g i c a l S u r v e y U

. S

. D e p

. 3 8

O f t h e I n t e r i o r B e f

o r e t h e S u b c o m m i t t e e o n E n v i r o n e m e n t a n d H a z a r d o u s M a t e r i a l s H o u s e C o m m i t t e e o n E n e r g y

a n d C o m m e r c e H e a r i n g o n “ C a r b o n S e q u e s t r a t i o n : R i s k s , 

### 15

### appropr iated to bene ficial use. Phy sical displace ment of g roundwa ter c an also ha ve adve rse

prac tical impacts on private owner s and utiliti es. As a r esult it will normally be prude nt to

evalua te whethe r on-site g roundwa ter we lls, especially those used by

public water

sy stems, will

be disrupted by

CCS opera

tions.

I n most places a w ater

rig ht includes the rig ht to a particula r quality as we ll as a

particula r quantity of wa ter. The se ca ses ar e ty

pically fra med in the context of deprivation of

quantity but these wa ter rig hts are a lso protected f rom ac tiviti es of a

nother that injure the quality

of a w ater rig ht. There fore , if wate r quality is affe cted by

the pre cipitate that hopef ully forms 3 9



### from the g eoche mical re actions intended a s part of CCS operations the owne r of that wa ter c ould

have a cause of ac tion ag ainst the entity injecting and the owne r of the g as injecte d. Historically

such interf

ere nce involved the discharg e of mine a nd other wa stes into the stream but there is no

rea son to believe the r esult would be diffe rent with CCS. 4 0



### III. Regulation

A. EP A UIC Rulem akin g

The UI C Progr am re g ulates under g round injection under five diff ere nt classes of

injection wells, depe nding on the ty pe of f luid being injec ted, the purpose for injec tion, and the

subsurfac e loca tion where the fluid is to remain. States ar e allowe d to assume primary

responsibility

for implementing the UI C require ments in their border s, as long as the state

prog ram is consistent with EPA reg ulations and has re ceive d reg ulatory approva l. I njection

opera tors are require d to provide financ ial assura nce in c ase the y

cea se oper ations, with the level

of assura nce a function of the e stimated cost of plug g ing a nd abandoning the injection well. I f

there is a violation of a UI C permit, an enf orce ment action may

be broug ht by

the EPA

2 A C O P R A C § 7 6

. 1 1 3 9

G a m e & F i s h C o m m 'n v

. F a r m e r s I r r

. C o

. , 1 6 2 C o l o

. 3 0 1
, 4 2 6 P

. 2 d 5 6 2 ( 1 9 6 7 ) ; W i l m o r e v

. C h a i n O 'M i n e s , 9 6 4 0

C o l o

. 3 1 9
, 4 4 P

. 2 d 1 0 2 4 ( 1 9 3 4 )

. 

### 16

### Administrator or the a pplicable state ag ency . Violators may be subjec t to administ rative or ders,

civil penalties, and c riminal penalties. The scope of the UI C statute is contamination of drinking

2 

### water , and under

its curre nt application to CO storag e, the UI C Progr am g ives more limited

trea tment, if any , to other har ms to human health, the environme nt, and prope rty

. 4 1



### Whil e ther e ar e re quirements for constructing and monitoring injection well oper ation,

there are no fede ral re quirements for monitoring a ctual movement of fluids within the injection

zones, nor are there require ments for monitoring in overly ing zones to dete ct leaka g e with the

exception of specif

ic class I hazardous we lls, where this monitoring c an be ma ndated. 4 2



### On J uly 15 2008, the EPA proposed a rulemaking packa g e that would re g ulate g eolog ic

sequestra tion of car

bon diox ide under

the UI C. The proposed r

ules would cre ate a

new c ateg ory

of UI C well (Class VI ) desig ned spec ifically for injec tion of CO2 into geolog ic forma tions. The

proposal includes de tailed technic al re quirements for char acte rizing the scope and suitability of

the targ et forma tions, assuring tha t the injection zone will not affec t any actua l or potential

source of drinking water , monitoring a nd repor ting on we ll conditions during and a fter the

sequestra tion is complete, and re quiring as par t of well per

mit applications plans for 50 y ear s of

post-injection monitoring. 4 3

2 

### The propose d rules do not direc tly addre ss air quality

issues. The Class VI

CO injection

2 

### well re quirements ar e desig ned to assure that there are no signific ant re lease s of CO or

2 2 

### contaminants in the CO into the ambient atmosphere . The EPA dec lined to classify CO as a

2 

### hazardous wa ste but the proposed r ules place a burde n on the per mittee to assure tha t the CO

does not contain impurities that would trig g er RCRA hazardous wa ste manag ement

C r a i g A

. H a r t , A d v a n c i n g C a r b o n S e q u e s t r a t i o n R e s e a r c h i n a n U n c e r t a i n L e g a l a n d R e g u l a t o r y E n v i r o n m e n t : A 4 1

S t u d y o f P h a s e I

I o f t h e D O E R e g i o n a l C a r b o n S e q u e s t r a t i o n P a r t n e r s h i p s P r o g r a m , D i s c u s s i o n P a p e r 2 0 0 9

- 0 1
, C a m b r i d g e , M a s s

. : B e l f e r C e n t e r f

o r S c i e n c e a n d I n t e r n a t i o n a l A f f a i r s , J a n u a r y 2 0 0 9

. R e g u l a t i n g t h e u l t i m a t e s i n k : m a n a g i n g t h e r i s k s o f g e o l o g i c C O 2 s t o r a g e

. P a g e 3 4 7 9 4 2

h t t p : / / w w w

. e p a

. g o v / o g w d w / u i c / w e l l s

_ s e q u e s t r a t i o n

. h t m l 4 3



### 17

### require ments. The risks assoc iated with this classification ar e manife st. I njection of ha zardous

waste is hig hly

reg ulated and w ould likely bring a CCS project to a scr eec hing ha lt.

None of this overrides the a

pplicable pr ovisions of CERC L A or RCRA. To the extent

there are hazardous substance s relea sed fr om the sequestra tion process liability under CERCL A

may be pre sent. L ikewise if mate rials injected a re ha zardous waste the daunting permitting a nd 4 4



### corr ective a ction provisions of RCR A and the sta te prog rams will apply

.

As an e x ample, EPA issued orde rs under RCR A to require manag ement of pr opane tha t

had lea ked fr om an under g round distribution sy stem. I n EPA’s view, the moment the pr opane

leake d from the distribution sy stem it was a wa ste and pre sented a hazard. De pending upon the

fac tual setting, CCS operations could find themse lves in the same situation.

B. State Re gulation

I n the abse nce of

fede ral a ction on the ca

rbon seque stration issue, many states ar e in the

proce ss of ena cting their own re g ulations. Som e examples follow:

1. Wyom ing

House B ill 89 (created Wy oming Statute § 34-1- 152 and ame nded Wy oming Statute §

34-1-202) addre sses the owne rship of Pore Spac e. The Bill establishes that the surf ace owner

owns pore spa ce unde rnea th the surfa ce e state and tha t the pore spa ce is c onvey ed upon the

convey ance of the surf

ace , unless the spac e has be en pre viously convey ed or is explicitly

excluded in the surfa ce c onvey ance (in the same ma nner a s a minera l interest). I n addition, leg al

require ments for notice to surfac e owne rs and/or miner al intere st owners shall not be c onstrued

to require notice to the pore space owner unless the law spe cifies that suc h notice to the pore

space owner

is require d. The statute e x pressly rec og nizes the dominance of the mineral e state

h t t p : / / w w w

. h h c l i m a t e c h a n g e

. c o m / c l i m a t e

_ c h a n g e / 2 0 0 8 / 0 7 / e p a

- r e l e a s e s

- p r

. h t m l 4 4



### 18

### and does not a lter the c ommon law as it relate s to the rig hts of the minera l estate. The bill st ates

expli citly that it does not affe ct the common law r eg arding the dominance of the minera l estate. 4 5



### House B ill 90 (effe ctive Jul y 1, 2008; cre ated Wy oming Statute §§ 30-5- 501 and 35-11-

313 and ame nded Wy oming Statute § 35-11- 103(c) ) manda tes UI C permit for GCS. I t makes a

clea r distinction from EOR. I t instructs the Wy oming De partment of E nvironmental Qua lity to

establish and issue per

mits t o new “ sub-classe s of wells” w ithin the UI C prog ram a nd to reg ulate

well standar ds, bonding a nd monitoring. The bill requires the D EQ to cre ate a n advisory

board

and rule s to ex pand the UI C prog ram to include c arbon se questration. Unde r the bill, a working

g roup including the supervisor of the oil and g as commission, the state g eolog ist, and the

direc tor of the DE Q will set bonding pr ocedur es. Jurisdi ction subsequent extraction of

sequester ed ca

rbon diox ide re sts with the W y oming Oil and G as Conserva tion Com mission. The

bill does not im pact the oil and othe r minera l interest owner s’ rig ht to drill or bore throug h

sequestra tion sit es, nor doe s it include within it s scope the r eg ulation of enha nced oil re cover

y

opera tions using ca

rbon diox ide. 4 6



### L ike HB 89, Wy oming' s car bon captur e and se questration leg islation recog nizes the

continuing dominanc e of the mineral e state. § 30-5- 501 states spec ifically that the ca

rbon

sequestra tion legislation ena cted by § 35-11-313 sha ll not “affe ct the other wise lawf ul rig ht of a

surfa ce or mineral owne r to drill or bore thr oug h a g eolog ic seque stration site” so long as the

drilling is conduc ted in confor mity with rules for pr otecting the seque stration site ag ainst the

2 

### esca pe of CO

. 4 7

I d

. a t 1 4 3

- 4 5 4 5

D e l i s s a H a y a n o , G u a r d i n g t h e V i a b i l i t y o f C o a l & C o a l

- F i r e d P o w e r P l a n t s : A R o a d M a p F o r W y o m i n g ’ s C r a d l e 4 6

t o G r a v e R e g u l a t i o n o

f G e o l o g i c C O 2 S e q u e s t r a t i o n , 9 W y o

. L

. R e v

. 1 3 9
, 1 4 5

- 4 9 ( 2 0 0 9 )
I d

. 4 7



### 19

### 2. Oklah om a

Senate B ill 1765 (May

2008) wa s a proposa l that require d the deve lopment of GCS

permitting r eg ime and tra nsfer red ow nership of w ells to state and re lease d owner s from liability

10 y ear s after

closure. T he B ill that was passed, howe ver, w as re latively disappointing. I t

mandated a

task forc e to re port to the Gover nor with GCS permitting re commendations by

Dec ember

2008 (extended to Dec ember 2009) and is modeled ba sed on the I OGCC model

statute. 4 8



### 3. Kansas

Under HB 2419 (2007), GCS rules we re suppose d to be deve loped by J uly 2008 (dra ft in

prog ress). U nder the Bill, a state G CS fund would pay long- term GCS relate d monitoring a nd

reme dial activities. I t also exempts GC S property and any elec tric unit utili zing GCS from taxes

for 5 y ear s. Finally , it allows for ac cele rate d depre ciation of GCS equipment. 4 9



### 4. Washin gton

ESSB 6001, passed Apr il 17 2008. I t codifies the e missions -re duction g oals and policy

rec ommendations for the state . The bill also sets an Emissions Performanc e Standar d (EPS) that

limit s elec tric utiliti es’ a

bility to sign ne w or re newe d long- term contra cts with power pla nts

whose g ree nhouse-g as emissions exceed those of a modern na tural g as-f

ueled powe r plant. The

bill essentially

ends construc tion of pulverized coal plants to ser ve Washing ton loads, makes the

price of I GCC power re flec t some of its emissions di sposal costs, and jumpstarts the proc ess

toward a compre hensive g ree nhouse-g as emissions reduc tion plan for the state

. 5 0

d e F i g u e i r e d o M A
, R e i n e r D M
, H e r z o g H J

. F r a m i n g t h e l o n g

- t e r m i n s i t u l i a b i l i t y i s s u e f o r g e o l o g i c 4 8

c a r b o n s t o r a g e i n t h e U n i t e d S t a t e s

. M i t i g a t i o n A d a p t

. S t r a t

. G l o b a l C h a n g e 2 0 0 5 ; 1 0 : 6 4 7

- 5 7

. M e l i s a F

. P o l l a k
, H u m p h r e y I n s t i t u t e o f P u b l i c A f f a i r s , B i g S k y C a r b o n S e q u e s t r a t i o n P a r t n e r s h i p A n n u a l M e e t i n

. 4 9

O c t

. 2 8
, 2 0 0 8
N W E n e r g y C o a l i t i o n , A p r i l 1 9
, 2 0 0 7

. w w w

. n w e n e r g y

. o r g / p u b l i c a t i o n s / f a c t

- s h e e t s / 6 0 0 1 % 2 0 F I N A L % 2 5 0



### 20

### Will Water Issues/Regulatory Capacity Allow or Prevent Geologic Sequestration

for New Power Plant s ?
A Review of the Underground Injection Control Program and

Carbon Capture and Storage

Authors:
Jonathan Gledhill, Policy Navigation Group

James R ollins, Policy Navigation Group
Theresa Pugh, Director, Environmental Services, APPA

a nd

American Public Power Association 1875 Connecticut Ave, NW Suite 1200 Washington, DC 20009

- 5715and 1 Executive Summary
International concern over global climate chang e has spurred a search to identify ways to reduce greenhouse gas (GHG) emissions . Of the six gases comprising greenhouse emissions, carbon dioxide (CO 2 – “carbon” ) emissions far exceed the other five in the amount emitted. 1 The U.S. is considering a numb er of voluntary options for an 18 percent reduction in CO 2 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 seque stration 2

First the carbon dioxide from a power plant would have to be separated and removed from the power plant. C arbon sequestration really refers to the geologic sto ra ge in deep geological formations below the earth’s surface. Carbon dioxide injectio n 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 t esting of CCS pilot projects

. APPA suppor t s carbon storage demonstrations through the DOE and FutureGen to determine if the injection of CO 2 is safe and effective as a mitigation measure.
The CCS issue is of considerable import to the electricity/power p lant sector which the U.S. DOE considers to be one of the largest emitter s of CO 2 , accounting for 38 percent of CO 2 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 nu mber of technical, regulatory, and policy issues related to long

- term CO 2 storage or geosequestration that remain to be studied and resolved.

The U.S. E nvironmental Protection Agency (E PA ) has regulatory authority over injection of wastes into wells thro ugh the Underground Injection Control p rogram (UIC) created by Congress under the Safe Water Drinking Act . Congress specifically created the p rogram out of concern for the protection of underground drinking water sources . Although the UIC program has est ablished 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 wi th 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 safeguard s to ensure protection of groundwater sources . T herefore 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 CO 2 ) for a period of 10,000 years.

1 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Envi ronmental 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. CO 2 emissions”). 2 Sometim es 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, commercial

scale sequestration of carbon i n 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 thei r communities, the challenges include very difficult issue s

. 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 Munic ipal Government ?

P olicy officials and scientists alike , searching fo r viable ways to reduce carbon dioxide ( CO 2 ) emissions , have identified carbon capture and storage (CCS) 4 as a promising technology

. This technology separates CO 2 from emissions of large stationary sources like power plants and inject s the captured CO 2 deep into the earth

. Figure 1 gives a simple picture of this technology. The Intergovernmental Panel on Climate Change (IPCC) has identified C CS as a way of achieving overall reductions i n greenhouse gas emissions. 5 This 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 2 012

. The U.S. DOE is leading the Regional Carbon Sequestration Partnerships to conduct research and development of C CS 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 Operation 6

The benefits of reducing CO 2 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 Cap ture 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 a vailable 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 red uctions. According to EPA, g round 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, a nd 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, t he demand for electric is expected to increase by 39 percent from 2005 to 2 050 , 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 A merican Public Power Asso ciation (A PPA ) 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 provid e el ectric ity 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 sea mless fit between current regulation and CCS

. First, t he 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, f or CCS to have a meaningful impact on U.S. emissions, the volume of CO 2 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, da ta, 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 pro gram, its current implementation, the current regulatory framework for CCS , and the skill shortages states and EPA will face if CCS moves toward full

scale implementation. Finally, this paper highlights the major limitations for CCS that power plant and w ater 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 extracti on of fossil fuels and mineral s

. 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) P rogram?
Congress and EPA established the legal framework for regulating underground disposal over 30 years ago. Congress established the UI C program as part of the Safe D rinking Water Act (SDWA) of 1974 providing EPA with the authority to regulate underground injection activities to ensure the protect ion of the nation’s underground s ources of drinking water

. Almost all U.S. public water syst ems rely on some g roundwater 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 int ended 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 s tates to submit an application to EPA for primary enforcement or “pri macy” for each part, or “class , ” of the program

. EPA can delegate primacy to a s tate, U.S. territory, or a federally recognized Native American tribe

. The UIC p rogram may be executed by the E PA, the s tate, or both under four separate scenarios:
1) EPA adm inisters the program for all well classes within a s tate if the latter chooses not to apply for primacy;
2) a s tate is delegated primacy for all five classes;
3) a s tate has primacy for Class II (oil and gas) wells only; or , 4) a s tate has primacy for all c lasses e xcept 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: Ari zona, 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 d oes EPA R egulate U nderground I njection?

EPA established f ive classes of injection wells (Class I, II, III, IV, and V) under the UIC p rogram based upon how the well is used , construct ed, and operat ed

. 11 The classes provide a consistent way for E PA to a pply 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 C lass V, Clas s I, or Class II wells

. All underground injection wells must have a permit. For each class, EPA has established minim um 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 the ir permitting process. With approximately 8 3 4,000 wells across the U.S. , 12 the UIC program is one of the largest environmental permitting program s

.

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 C lasses of I njection W ells under the UIC P rogram?

Class I Injection W

ells
Subject to the most stringent regulations, Class I wel ls include industrial hazardous, nonhazardous, and municipal sewage waste

. Class I wells inject wastes deep into rock formations that are located be neath the low est underground sources of drinking water 13 and that are capped by an impermeable rock formation between the injection zone and drinking water sources above

. Figure 2: Diagram of Class I Well 14

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

I n 1984 , Congress tightened Class I requirements by instituting a no

- migration stand ard 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 prohibit ed injection of untreated hazardous wastes unless it is demonstrated that the waste has been t reated 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 C lass I wells nationwide , t h ere 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 no

migration over a 10,000 yea r 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 3 66 nonhazardous Class I waste wells in 19 states

. Nonhazardous Class I waste wells are required to comply with the

same technical standa rds as hazardous waste wells.
Class II Injection W

ells

O il 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 . S tates 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 d eep wells. There are approximately 167,000 Class II wells , p redominantly found in the s outhwest ern U.S. The map below shows the loca tion 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 W ells

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 well s have minimum standards for which operators must comply , including requir ed 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 r equired 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 create d 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 W

ells

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 us ed by industry f or wastewater disposal as well as less advanced types found in septic systems , cesspools , and agriculture drainage wells

.
I njection activities that d o not fit into the other classes

- like CCS

- are called Class V wells

. E xperimental tec hnologies 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, o ver the years EPA has issued guidance to cover certain experim ental technologies

. Notably, EPA issued guidance in 1983 clarifying that t echnologies in the experimental phase which would have otherwise fall en under another UIC p rogram

class based upon well function, may be reclassified into one of the five classes on ce 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 wa ter 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 standa rds. 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 Sta tistics 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 sequestratio n of carbon dioxide when they established the program for th e chemical industry over 30 years ago so n o federal regulatory framework exists to regulate CCS activities specifically

. Yet, EPA has considered how CCS is regulated under the UIC program. I n 2006 EPA determined that CCS activities are “underground injec tion” 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 Th is policy directive might be supplanted b y an EPA rulemaking in 2008.

Since t here are no federal requirements governing Class V experimental technology wells , there has been a lot of confusion and uncertainty. I n March 2007 EPA issued guidance for permitting and operation of CCS pilot projects a s 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 tha t Class V is “the best mechanism f or 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 mod ified or extended to alter the goals or timetable, but cannot exceed s tate or federal permit limits.
As a counterpoint to th e 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 g uidance that protection of underground drinking water and human health is the overriding concern. EPA lays out a number of considerations for r egional and s tate d irectors 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 pr ogram d irectors 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

. Th e 2007 EPA g uidance s tresse s that the primary goal of pilot projects is for EPA, the s tates, and well operators to collect and share data to better understand how CO 2 reacts and m oves 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://ww w.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 CO 2 injection

. To determine how best to manage commercial scale CCS injection operations , the g uidance suggests EPA r egional and

s tate d irectors adopt a more flexible approach i n approving permits and identifying permit conditions to allow operators to “achieve project objectives.” 25

How have S tates R egulated CCS P ilots?

EPA and the s tates have looked to Class I and II regulations for permit conditions for CCS pilots because of t he depth of injection and the larger volume of CO 2 injected

. Today CO 2 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 t he 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 R equirements?
The technical requirements f or 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 fi nally 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 suitab le 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 f ederal regulations for Class I hazardous waste wel ls, 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 comp uter 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 chang es 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 s tate 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 t hree 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 i t 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 t he 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 Technology 31

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. R egulations require well operators to use continuous recording de vices 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/s afewater/uic/idealwel.html.

32 40 CFR Part 144.28(g)(1).

33 40 CFR Part 144.26(g)(1).and 17

le ak while traveling to the well, will not leak out of the well as it is injected, nor move into underground dr inking 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 o perators are also required to develop approved a mbient m onitoring pr ograms 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 Dire ctor 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 th e 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 determ ine 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 eac h permit based upon site specific criteria

. 38 O perators 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 o perators 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 submi t 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 noth ing 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 opera tor is financial ly 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 abandonmen t letter of credit;
5) Plugging and abandonment insurance;
6) M eet financial criteria and obtain a corporate guarantee for plugging and abandonment; or , 7) D emonstrate 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 perm it 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 1 46.10.and 19

certified as accurate to the Director stating that well abandonment was conducted and completed in accordance with the abandonment plan.

Wha t are the C hallenges for P ermitting CCS U nder the UIC P rogram for Electric Utilities Evaluating CCS Options ?
With the international, f ederal, and state interest in CCS, academic, public interest groups , and the f ederal 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 believ e 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:

C ost and Space Requirem ents 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 C0 2 compression and transport v ia 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 utilitie s 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 Conce rning Regulatory Requirements
Since EPA is formulating guidance or reg ulation 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 whe n th ere 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 th e operators UIC permit. However, the difficulty for well operators involved in CCS operations is finding an alternative means of disposing CO 2 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 Clas s 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 technica l 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 Wyoming 51 ). 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 CO 2 hundreds of miles to a reas with Class I wells such as the Gulf Coast.
Sheer Size of CCS to Have Meaningful I mpact 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 f or CCS. Comparing the relative size of CO 2 emissions and current underground injection gives some answer to this question. Power plants accounted for 2.4 billion metric tons of CO 2 emissions in 2006 52 or approximately 86 percent of point source CO 2 emissi ons 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 4 3 million metric tons of carbon dioxide is injec ted 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 CO 2 can be separated and injected and remains doubtful that a new coal p ower plant (regardless of type) could separate and inject more than 50 percent of the CO 2 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 1 1.

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)
CO 2 emissions from power plan ts 2,400 56

CO 2 in Class II wells for oil recovery 43 57

Class I hazardous waste 22 58 Regional Carbon Sequestration Partnerships, total 2
Space Requir ements for the Injection Well
DOE has estimated that injecting 0.9 million metric tons of CO 2 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 CO 2 captured from a 300 MW boiler, the surface area r equirement 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 SO 2 and NOX

. The inject ion 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 th en dilute d wa stewaters 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, CO 2 will flow to fill in each rise first. In other words, unlike

cur rent 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 mi les currently though t 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 CO 2 from a single power plant could have traps over a 13 mile b y 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 f ederal government retaine d 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 f ederal governm ent. 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, Electrici ty 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 N ETL 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 limi tation that it is impractical, impossible, or extremely costly to acquire title to hundreds of thousands of acres of land.
Unique Potential Hazard s of Carbon Dioxide Injection
While deepwell injection of liquids has occurred safely for over 20 years, there is less experience with injecting gasses like CO 2 . While most CO 2 injection s 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 potentia l h azards 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 i nitial 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 res iding 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 CO 2 , a blowout occurred during drilling at a production well in March 1982 causing the free flow of CO 2 at the well head and leakage from ground fractures directly above the site. The high rate of CO 2 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 protec ting against future accidents. 64 The report issued a number of recommendations including: determining the potential for CO 2 migration along unsealed fault and fracture zones; the potential for magmatic or seismic activity to cause damage to sealing caps r esulting in CO 2 releases; the potential for wells to transport CO 2 to the surface; and implementation of public education and CO 2 monitoring programs to minimize impact to human health and the environment from releases. 65

The risk of blowout is hard to quan tify 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 estima tes 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 CO 2 from Storage Reservoirs: Identification of Features, Events, and Processes and Lessons Learned , Earnest Orlando Lawrence Berkeley National Labora tory, Feb

. 2006.

65 Lewicki et al ., at 48

- 9.

66 Source Texas Railroad Commission at: http://www.rrc.state.tx.us/news

- relea ses/2006/100606.html

. .and 23

The DOE has a method of fin ding abandoned wells under its SEQURE program , h owever this program is not set up for national application. The SEQURE program uses low flying airplanes to detect abandoned wells and , as discussed abov e , aerial methods may not detect wells which do not ha ve 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 o il and gas producing layers can dilute the value of these deposits and ultimately return the CO 2 to the atmosphere. 67

Corrosion

As CO 2 rises to the top of the injection layer, it may contact closed wells or the cement casings of older wells. If the CO2 rea cts 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 CO 2 to rise up the abandoned well to drinking water layers. Whi le 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 Cos ts
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 w ith 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 renewed 71 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. mu st 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 investi gators. 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 permitt ing 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 experien ce 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 cap acity. 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 tech nical 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 well s

. In 2006, Texas had ten new and eight Class I hazardous waste permit renewal s 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 so ar. 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 cur rent 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 concep t of CCS sounds promising, regulatory agencies’ paramou nt 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 CO 2 t o 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 ap pear 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 t o deal with other issues such as amending state drinking water laws or amending f ederal environmental laws such as the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA); Endangered Species Act (ESA), Resource Conservation and R ecovery 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 CO 2 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 m ade aware of the limitations of CCS as addressed in this paper and that the issues be fully investigate d prior to mandating CCS as part of permit app roval.

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, appr ove, monitor commercial

- scale carbon capture and storage projects.

American Public Power Association 1875 Connecticut Ave, NW Suite 1200 Washington, DC 20009

- 5715