emerging technologies & first plants for ......the emerging technologies 21 energy center...

EMERGING TECHNOLOGIES & FIRST PLANTS FOR CARBON CAPTURE UTILIZATION/

SEQUESTRATION – A CONFERENCE REPORT

U N C K E N A N - F L A G L E R B U S I N E S S S C H O O L E N E R G Y C E N T E R R E P O R T

CONTENTSExecutive Summary 2

Principal Findings: 2

Recommendations for Modifying the 45Q Tax Credits 10

Emerging Technologies & First Plants for Carbon Capture Utilization/Sequestration 13

Essential Background 13

What is CCUS? A Brief Overview 13

What Are the Emerging Technologies? What Challenges do They Face? 14

Federal Tax Credits for CCUS 16

The Need for CCUS 17

The Emerging Technologies 21

Energy Center Scholar’s Report - Modeling CCUS’ Economics for First of a Kind Plants 26

45Q Tax Incentives, Sequestration and MRV Rules - Opportunities & Issues 29

C02 Utilization - EOR and Other Uses 31

Conclusions and Recommendations 36

Appendix 42

Conference Program 48

KENAN INSTITUTE REPORT • EMERGING TECHNOLOGIES & FIRST PLANTS FOR CARBON CAPTURE UTILIZATION/SEQUESTRATION

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EXECUTIVE SUMMARYA conference on Emerging Technologies for Carbon Capture Utilization/Sequestration

(CCUS) was convened by the University of North Carolina’s Kenan-Flagler Energy Center

on March 29-30, 2019. The conference was undertaken in response to three developments

that suggested a more prominent role for CCUS in national energy policy. The three

developments are: 1) the emergence of two new technologies which produce plus

electricity from fossil fuels while capturing the associated carbon dioxide emissions; 2)

the passage of substantially greater Federal tax incentives for CCUS investments; and 3) a

Department of Energy request to the National Petroleum Council (NPC) for a new, in-depth

study of how to stimulate CCUS deployment in the U.S.

These developments caused us to ask whether the referenced emerging technologies

were ready for deployment at scale. The technologies in question are the Fuel Cell Inc./

ExxonMobil Molten Carbonate Fuel Cell and NETPower’s Allam Cycle. The former is

primarily a retrofit technology; the latter provides new built generation plants. Both promise

to generate electricity from natural gas while capturing 90+% of all C02 that would otherwise

be emitted.

Many promising technologies have stagnated because initial projects produced large cost

overruns and/or unreliable operations (e.g. ‘clean coal’). Accordingly, the Center invited

representatives from the technology developers, the NPC, major utilities, environmental

organizations and fossil fuel energy companies to discuss the prospects for a successful

launch of these emerging CCUS technologies.

CCUS is a complex subject encompassing technology, energy markets, investment

economics and public policy. To assist readers in understanding the topic, the section

following this Executive Summary, the first section of the main report, provides essential

background. Readers relatively new to CCUS may want to review this section first before

turning to the Executive Summary’s Principal Findings that follow immediately below.

PRINCIPAL FINDINGS:OVERVIEW

• The emerging technologies are promising. Collectively they offer the possibilities

of 1) retrofitting the U.S. natural gas power plant fleet, rendering its emissions almost

carbon free while generating plus electricity, and 2) new build, carbon free natural

gas power plants that offer the efficiency, reliability and flexibility of today’s CCNG

plants. When modeled with ‘lined out’ capital costs, these investments generate

positive returns which become quite robust when 45Q tax credits are included.

Once proven at commercial scale, together they offer a pathway to a broad de-

Many promising technologies have stagnated because initial investment projects produced large cost overruns and/or unreliable operations (e.g. ‘clean coal’).

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EMERGING TECHNOLOGIES & FIRST PLANTS FOR CARBON CAPTURE UTILIZATION/SEQUESTRATION • KENAN INSTITUTE REPORT

carbonization of the U.S. electricity sector. The risks are serious that this potential

will not be realized. Both technologies face material technical and economic

challenges on the path to 1) being technically proven at scale and 2) stimulating

the number of projects needed for them to get capital and operating costs to a ‘lined

out’ state. These challenges render it unlikely that the emerging technologies will

be widely deployed at commercial scale by the 2024 start-of-construction date for

the 45Q federal tax credits. Even the narrower goal of having these technologies

‘proved at scale’ may not be achieved due to 1) uncertainties and flaws in the

current structure of the 45Q tax credits and 2) the limited state of oil/gas company

and utility industry cooperation around who will sponsor these First of a Kind (FOAK)

investments.

• The multiple uncertainties surrounding 45Q are impeding progress towards even

1-2 FOAK CCUS projects commencing by the 2024 start date. These uncertainties

are more complex than those which earlier applied to wind/solar investments.

The principal complications involve responsibility for assuring that captured C02

is securely sequestered. Currently, the applicable Monitoring, Reporting, and

Verification (MRV) rules are receiving most of the attention, but the trickier issue

concerns allowing 45Q credits to be flexibly transferred to financial sponsors. This

flexibility will be needed to encourage widespread CCUS deployments; however, if

transfers to financial sponsors are allowed, who then has the responsibility for MRV

compliance? Financial sponsors won’t feel competent to take this responsibility,

and they may be reluctant to take on an exposure to tax credit recapture if the C02

sequestration is ultimately found non-compliant.

• The aforementioned 45Q issues, by paralyzing consideration of at-scale CCUS

investments, are rendering the 2024 ‘eligible facilities’ start date unrealistic. Major

revisions in the current structure of 45Q are required to unlock CCUS deployments.

We present suggestions for these revisions at the conclusion of this Executive

Summary.

THE STATE OF THE EMERGING TECHNOLOGIESTECHNICAL & ECONOMIC

• NETPower’s Allam Cycle technology is significantly closer to an attempted FOAK

at-scale plant. The fact that NETPower has constructed a significant (50 MW)

Demonstration Plant (Demo) plant conveys its confidence in the technology’s

potential while providing investors with the opportunity to examine the Allam Cycle’s

performance and scale-up challenges. The technology also produces diverse

revenue streams which can make its FOAK projects more economically resilient.

The multiple uncertainties

surrounding 45Q are impeding progress towards even 1-2

FOAK CCUS projects commencing by the

2024 start date.

Major revisions in the current structure of 45Q are required

to unlock CCUS deployments.


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Finally, as outlined by its developer, the Allam Cycle is a capital efficient producer

of electricity. These positive characteristics have attracted the support of serious

investors, e.g. Exelon and Occidental Petroleum, in itself a strong endorsement of

the Allam Cycle’s potential.

• Pro forma Allam Cycle economic models show very positive returns are possible.

A research team modeled the construction of a 300 MW plant in West Texas, and

obtained returns in the 17% IRR range without the benefit of 45Q tax credits. After

applying a 50% contingency to capital costs, a low-teens IRR was still achieved.

These results reflect a number of factors:

1. Diverse revenue streams, approximately 1/3 each, from the sales of

electricity, industrial gases and C02 into EOR

2. Capital efficiency relative to CCNG plants, due to the avoidance of heat

capture/transfer equipment and a smaller plant footprint

3. The fact that a pure C02 stream is produced as a process by-product as

opposed to having to be captured from a flue gas stream

The Allam Cycle economics suggest that with 45Q credits added to the picture, a FOAK

Allam Cycle plant could be financially robust and able to withstand a final capital cost

number well above the developer’s current estimates.

• These favorable developments make a successful testing of the Demo plant the

critical factor in progressing to a FOAK commercial plant. Here some doubts

must be acknowledged. Originally, the Houston Demo plant was expected to

produce power in August ’18. As of mid-2019, it still was not putting power into the

grid. Reports from the company indicate that the front end combuster has been

tested successfully and that Toshiba, the designer and provider of the turbine, is

undertaking a very careful test process for that equipment. The Allam Cycle uses

‘super-critical (i.e. very hot) C02 to drive its turbine, and the turbine’s blades are

a custom design. A careful test of this equipment thus makes sense. That said,

it is exactly in this design segment where operating issues might be anticipated.

It remains to be seen what issues NETPower has encountered, whether fixes

have been found for said issues, and when the firm can demonstrate that its plant

generates power as anticipated on a sustained basis.

These favorable developments make a successful testing of the Demo plant

the critical factor in progressing to a FOAK commercial

plant

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• Successful Allam Cycle scale up will have to focus on enlarging the custom design

turbine and assuring it can sustain operations with super-critical C02 flowing

through the equipment at volumes 6+X the Demo plant. The other components

in the process, e.g the air separation unit and combuster, are mature technologies

with long track records of working at scale.

• A larger question for the Allam Cycle is whether once proven it can be widely

deployed in the U.S. electricity market. It may prove easier to get the first plant built

than say the 10th plant. An Allam Cycle plant will be most attractive under the

following conditions:

1. Growing electricity demand creates the need for new base load power

generation

2. The plant is located in an electricity market with healthy wholesale prices,

i.e. prices which can support new generation investment

3. The plant will have ready access for disposing of its C02, i.e. there will be

C02 transport logistics available and either an EOR market or available

sequestration

4. There is a ready market for its industrial gas bi-products

There are at most a handful of U.S. markets that meet some of these criteria, and almost

none that meet all of them. The 45Q credits can go some way towards compensating for

the absence of some needed conditions; however, the need to develop C02 movement

logistics is a formidable barrier (discussed in more detail below) that will take time and an

environmental consensus to overcome at scale.

• Deploying Allam Cycle technology as ‘co-gen’ or off-grid power sources may be an

alternative. New industrial sites looking to operate with de-carbonized natural gas

and EOR operations needing both power and additional C02 could see attractive

economics for building an Allam Cycle plant. They may also see benefits from the

industrial gas bi-products. Such projects may help the technology mature, bring

down manufacturing costs, and pave the way for further deployment within the

power industry.

Successful Allam Cycle scale up will

have to focus on enlarging the custom

design turbine and assuring it can sustain operations with super-critical

C02 flowing through the equipment at volumes 6+X the

Demo plant


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• The Fuel Cell Energy technology is significantly behind the Allam Cycle in terms of

readiness for at-scale deployment. Plans to build a Demo plant have been deferred

over a several year time span. Moreover, the technology developer, FCI is financially

challenged and recently underwent a top management change. Its partner,

ExxonMobil (XOM), has lowered the public profile it affords this technology, and

has not chosen to drive the technology forward to a Demo plant. The reasons for

XOM’s reticence are not clear. One explanation is that XOM is pursuing a cautious

technical research pathway, i.e. one which aims at considerable certainty as to how

the Fuel Cells will perform when eventually a scale-up is attempted. However, it

is also possible that they see the economics of a FOAK fuel cell plant to be quite

challenged. Three factors would account for XOM being cautious regarding the

Fuel Cell technology’s economics.

• The first reason has to do with XOM, and much of the oil industry’s, unsatisfactory

investment history in alternative energy. Some decades ago XOM owned a solar

company, a nuclear company and Reliance Electric. All disappointed economically

and were divested or shut down. Industry experience at BP, Shell, Chevron and

Total is similar. No major oil & gas company has had a successful diversification

experience into alternative energy and the investment dollars committed to these

endeavors have not been small.

• The second reason has to do with the scale-up challenge of this Molten Carbonate

Fuel Cell technology. We understand these fuel cells to be, at present, a small scale

manufacturing design. Said differently, each such fuel cell is today, something like a

special order. Thus, there are currently no economies of scale in their manufacture,

and likely will not be until a pipeline of retrofit plant orders seems assured. This

implies that the FOAK Fuel Cell retrofit will be much more expensive than the 5th

or 10th such project; correspondingly, the first plant’s economics will be more

challenged. The dilemma for the fuel cell retrofit technology is this – who is willing

to build the first plant and incur what may be a negative NPV in order to prove the

technology works at scale and create the opportunity for fuel cell manufacturing to

bring down the cost of subsequent retrofits?

• Finally, there is the question of how to frame the economics of a FOAK Fuel Cell

retrofit’ as an investment decision. If you evaluate the Fuel Cell technology on an

incremental cash flow basis, one is making a large investment that generates a

relatively small amount of plus-electricity. There is also the captured C02; that can

be a revenue source if sales to EOR are possible. We modeled a retrofit investment

at a West Texas natural gas power plant to test the economics with EOR logistics/

disposal readily available. Even using Fuel Cell Inc’s aggressive capital cost

The Fuel Cell Energy technology

is significantly behind the Allam Cycle in terms of

readiness for at-scale deployment Plans to

build a Demo plant have been deferred over a several year

time span

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assumptions, the IRR was less than 8%. Add in a FOAK capital cost contingency

and a negative IRR quickly results. The FCI technology does have the potential

to produce hydrogen as a bi-product, albeit with some requirement for additional

natural gas feed (this value proposition was beyond the scope of our study, but

could be significant if the retrofit project were located on the Gulf Coast). Given the

possibility, even the likelihood, that a FOAK Fuel Cell retrofit will incur a cost overrun,

it is not hard to see that a sponsor, looking at traditional project economics, might

see the project as high risk.

• However, these ‘marginal’ economics don’t tell the whole story; the retrofit

investment’s hidden benefit is protecting the underlying plant from either early

retirement, carbon taxes and/or alternative decarbonizing investments. From the

point of view of the oil/gas industry, such retrofits also protect their market for primary

fuel sales. Historically, the oil/gas industry has been reluctant to assign these credits

to potential projects; such credits are hard to value and often have been used to

try to justify questionable projects. That said, the challenge of de-carbonization

may be more significant, more existential, than was the diversification challenge

that spurred the first industry foray into alternative energy. In sum, the case is now

stronger for energy companies, utilities and their regulators to add these ‘defensive

credits’ to retrofit economics; failing to do so may materially understate the value of

de-carbonizing existing plants and markets.

• The ‘marginal economics’ problem throws light on an additional issue – who really

has the incentive to invest in CCUS? As the above paragraph makes clear, utilities’

economics may be driven by what else might happen to their underlying plant; oil/

gas companies’ incentive lies in preserving markets for their produced commodities.

Which of these potential sponsors may be more willing and able to commercialize

the emerging CCUS technologies? To this we next turn.

PROJECT SPONSORS FOR FOAK CCUS

• It is an open question who would build plants using either of the emerging

technologies. The utility industry is unlikely to be a ‘first mover’ here. The reasons

for this are several. First, many utilities don’t see an immediate need for CCUS to

meet their carbon emission goals; continuing to replace coal plants with CCNG

can sustain progress through the end of the coming decade. Second, utilities

operating in merchant markets are struggling to generate capital and profits. They

do not feel themselves in a strong enough financial position to take on the risk of

FOAK CCUS. Third, many utilities lack tax absorption capacity needed to get value

from 45Q tax credits. Finally, utilities not located near EOR operations, which is

The retrofit investment’s hidden benefit is protecting

the underlying plant from either early retirement,

carbon taxes and/or alternative

decarbonizing investments From

the point of view of the oil/gas industry,

such retrofits also protect their market

for primary fuel sales


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to say most utilities, face the challenges and costs of disposing of captured CO2.

This is discussed further below. The situation is not all negative as a small number

of utilities may be tempted strategically to back a first plant; broad utility industry

support for CCUS deployment however, is today absent.

• That leaves the fossil fuel industry as a potential backer with the resources to prove

up these emerging technologies at scale. Historically, the oil/gas industry has

viewed de-carbonizing electricity as a power industry issue. Its own interest in de-

carbonization has been confined to its existing plants and operations; as just noted,

their recent actions also imply skepticism regarding the economics of low-carbon

power investments. The only oil/gas companies enthusiastically interested in low

carbon power appear to be those which make use of C02 in EOR and who thus see

immediate revenue gains from securing a larger supply of low cost C02.

• Finally, there appears to be a limited dialogue on de-carbonizing electricity among

the utility and oil/gas industries – a fact confirmed by the sparse participation of

utilities in the current NPC study. All this adds up to the absence of a ‘visible investor

base’ for de-carbonized fossil fuel power among either the utility or the oil/gas

industries. This is significant for a reason beyond the obvious one that these are

the two industries most directly responsible for C02 emissions from power/industrial

facilities. The 45Q tax credits are currently written in such a way that they are likely

to be realized only by players from one of these industries, i.e. someone owning

the capture equipment or responsible for secure geologic storage. With these two

industries struggling with constraints and reservations, the need for an additional set

of investors is apparent. Financial sponsors could be this additional source of risk

capital, as they were for wind/solar. The entrance of Financial Sponsors would not

only bring added capital, but it would allow for more precise and diverse allocation

of risks among FOAK project stakeholders. However, for this to happen, the 45Q tax

credits must be clarified and amended, as we discuss in detail below.

OTHER CCUS BARRIERS AND UTILIZATION OPPORTUNITIES

• Carbon capture at the plant level is only part of the challenge facing CCUS. The

remainder involves transporting and using/sequestering the capture C02. The

conference confirmed that EOR remains the most attractive disposition of captured

C02. EOR offers the simultaneous opportunity for those capturing C02 to get paid

for the gas and to see it stored in secure underground storage. EOR using C02

flooding is a widespread practice in the Permian Basin; some operators there

indicate a large slate of pending projects if they can secure more C02 on economic

terms. EOR opportunities are not widespread however. Eastern and West Coast US

With these two industries struggling

with constraints and reservations,

the need for an additional set of

investors is apparent.

All this adds up to the absence of a

‘visible investor base’ for de-carbonized fossil fuel power

among either the utility or the oil/gas

industries.

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utilities thus face the formidable challenge of transporting and disposing of captured

C02. This barrier will likely limit their interest in CCUS for some years to come.

• The conference shed light on an underappreciated problem – that of undifferentiated

opposition to new pipelines by environmental groups. Recent years have seen

tenacious opposition and legal challenges by these groups to many new pipelines.

Less appreciated is the fact that these groups don’t differentiate between opposition

to a tar sands pipeline (e.g. Keystone XL), a crude line (Dakota Access) or a natural

gas pipeline (Atlantic Coast). This raises two questions: 1) would the Sierra Club

and similar groups take a different posture towards inter-state C02 pipelines? and

2) if such a pipeline network were constructed to facilitate CCUS, would that cause

them to reconsider their opposition to natural gas pipelines? These groups should

be asked to take a public position on C02 pipelines tied to CCUS so that potential

investors in this infrastructure can assess realistic timelines and costs.

• The conference also identified an unexpected utilization opportunity. Fracking with

C02 was indicated to be an attractive opportunity for unlocking natural gas and

natural gas liquids. EOR operations in the Permian Basin do not ‘frack’ with C02;

rather, they use C02 to ‘flood’ conventional oil reservoirs. However, the conference

discussed certain advantages of using C02 to frack for natural gas (as opposed to

crude oil). Apparently, C02’s adsorption and re-pressurizing qualities work better

on gas than oil in ‘tight’ formations. This might create opportunities for C02 EOR

in Eastern US gas-rich shale formations like the Marcellus and the Utica. Eastern

utilities might then have an option to retrofit existing CCNG plants and dispose of

the C02 into fracking operations producing more natural gas. Similar C02 disposal

would also apply to retiring remaining coal-fired plants and replacing them with a

new Allam Cycle facility.

• Other types of utilization of captured C02 remains challenged. Some progress has

been made in terms of rendering carbonate cements economic. Conversions to

chemicals and fertilizers continue to be studied but attractive economics remain to

be demonstrated.

A PATHWAY FOR U.S. CCUS DEVELOPMENT

• Considering all the above, the pathway to CCUS development should unfold in four

stages:

1. Successful construction/operation of Demonstration plants for the Allam

Cycle, and Fuel Cell technology.

The conference also identified

an unexpected utilization

opportunity Fracking with C02 was

indicated to be an attractive opportunity for unlocking natural

gas and natural gas liquids

This might create opportunities for

C02 EOR in Eastern US gas-rich shale

formations like the Marcellus and the

Utica Eastern utilities might then have an

option to retrofit existing CCNG plants

and dispose of the C02 into fracking

operations producing more natural gas


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2. Formation of a utility/oil company/financial sponsor consortium to build the

FOAK plants for these technologies, with the CO2 going into Permian Basin

EOR and/or EOR opportunities near to the U.S. Gulf Coast

3. Construction of additional plants/retrofits in the Permian, East Texas, and

possibly Pennsylvania, with the C02 going into EOR

4. Build out of an inter-state C02 pipelines system for disposition of captured

C02 into diverse EOR operations or secure geologic storage.

• This pathway diversifies the risks associated with proving up and building out the

emerging technologies. The technology sponsors bear the Demo plant risks. For

the Allam Cycle, that means NETPower getting their LaPorte plant up and running.

For XOM, that means finding capital for a Fuel Cell Demo Plant within their capital

budget. The FOAK plant risks are then ‘socialized’ among the utility/oil company/

financial sponsor consortium. Some of the capital risk is laid off to the financial

sponsors who also use the 45Q tax credits; the utility gets the equipment built and

operated while the oil company moves the C02, captures the EOR benefits and

takes responsibility for the secure sequestration. Variations of this model can then

be spread to other EOR basins, bringing other utilities and energy companies into

play while driving down the costs of manufacturing the CCUS equipment. With

multiple success cases in hand, the case for building out the C02 pipeline system

will be strong; this system in turn will enable projects in diverse locations to become

commercial.

• Such a pathway will require a major restructuring of the current 45Q tax credits.

As significant as were the modifications made in 2017, they will not achieve their

stated objectives as currently drafted. The changes required should not be hugely

expensive, given that they are targeted on a limited number of initial plants. To these

restructuring measures we now turn.

RECOMMENDATIONS FOR MODIFYING THE 45Q TAX CREDITS1. Presently, 45Q requires qualifying investments to commence construction

by 2024. If broad deployment is the goal, this date is now unrealistic for both

emerging technologies. Under a best case scenario, perhaps 1-2 Allam

Cycle plants might start construction by that deadline; given the absence

of a Demo plant project, it is unclear whether any retrofit projects will be off

the ground by then.

Such a pathway will require a major

restructuring of the current 45Q

tax credits. As significant as were the modifications

made in 2017, they will not achieve their

stated objectives as currently drafted.

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2. Proper technology development requires time to build, test, and de-bug

small scale and demonstration plants. Given the capital cost risk associated

with FOAK technologies, we recommend extending the 45Q deadline

well beyond the current 2024 date for ‘qualifying facilities.’ An extended

and perhaps more flexible deadline would enable sound technology

development without encouraging a race to commercialize. If the aim is

to incentivize wide deployment of these technologies, care must be taken

to avoid FOAK cost overruns whose magnitude discourages others from

attempting similar projects.

3. Extending the ‘qualifying facilities’ deadline will also be important for

stimulating utility company interest in CCUS. Today many utilities are

focused on retiring their coal plants and replacing them with natural gas

and renewables generation. However, after 2030 this opportunity set

will largely be harvested. Something else will then be needed to sustain

progress on emissions. CCUS could be that something else, especially as

regards de-carbonizing the recently built natural gas fleet. The ‘qualifying

facilities’ deadline should be extended out to at least 2035 to allow time for

both the needed maturing of CCUS technology and for utilities to identify

an impactful set of projects.

4. U.S. Treasury/IRS need to provide prompt guidance on a number of

issues tabled by potential CCUS investors. Foremost among these is

clarification around how 45Q tax credits can be ‘transferred’ to 3rd parties

with tax absorption capacity. Here it is tempting to assume a solution that

parallels that afforded to wind/solar projects. However, CCUS also involves

compliance with the MRV rules, where the penalty for breach is recapture

of the tax credit. Said differently, the MRV responsibilities add a tricky

environmental compliance issue to the ‘tax transfer’ process. Financial

sponsors interested in the tax credit may have no interest in risking its

being recaptured due to MRV non-performance. Treasury/IRS can solve

this dilemma by stating that recapture risk transfers with the tax credits but

industry and financial sponsors must work out appropriate ‘indemnification’

contractual arrangements.

5. We also recommend providing initial FOAK commercial plants with 45Q

incentives that are higher than current law but then decline for later plants.

Specifically, we recommend that the first five CCUS projects be allowed the

$50/ton credit whether their captured C02 is sequestered or utilized in EOR.

This structure would help offset the greater cost barriers that first plants face

Proper technology development

requires time to build, test, and de-

bug small scale and demonstration plants Given the capital cost

risk associated with FOAK technologies,

we recommend extending the 45Q

deadline well beyond the current 2024

date for ‘qualifying facilities’

We also recommend providing initial

FOAK commercial plants with 45Q

incentives that are higher than

current law but then decline for later

plants Specifically, we recommend

that the first five CCUS projects be allowed the $50/

ton credit whether their captured C02

is sequestered or utilized in EOR


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due to immature supply-chain, production and product markets. This would

be especially important for the Fuel Cell retrofit technology, which faces

more of a challenge in getting manufacture of its modules to commercial

scale.

6. At present 45Q is capped at a maximum of 50% of taxes over a 12-year

timeline. Extending the cap or tying recoveries to C02 captured on an open-

ended basis would be a second way of improving incentives for first plants.

Later plants can see the current caps applied.

7. An optimized 45Q might look something like this: the allowed credit might

be raised to $50/t for C02 utilized in EOR or another application – this to

apply to the first 5 qualifying facilities. Thereafter, the credit for EDR/Utilization

drops to $35/t for subsequent plants as provided in current law. Operators

or owners of the carbon capture equipment or the party performing the

ultimate sequestration can transfer the credit to any third party, but must

indemnify that party fully if the tax credit is subsequently recaptured due

to the operator/owner’s failure to comply with applicable (MRV rules). The

amount of tax credit is tied solely to C02 captured by the first 5 qualifying

facilities over their economic life. Subsequent plants have their credit limited

as in current law.

8. Finally, we urge ERCOT to re-consider its electricity pricing model for the

Permian Basin market. Today that model is producing one of the lowest

wholesale electricity prices in the country. As attractive as that may be

to nearby consumers, it is impeding the development of CCUS in what

almost certainly is the premier EOR location for using and sequestering

C02. Allowing power producers to charge some form of ‘clean capacity’

credit for C02 captured and delivered into EOR would incentivize utilities

and EOR producers to team up on CCUS projects. This in turn would result

in the emerging technologies being tested, then proven, and subsequently

made available for other electricity markets.

Finally, we urge ERCOT to re-

consider its electricity pricing model for the Permian Basin

market. Today that model is producing

one of the lowest wholesale electricity

prices in the country. As attractive as that may be to

nearby consumers, it is impeding the

development of CCUS in what almost

certainly is the premier EOR location

for using and sequestering C02.

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EMERGING TECHNOLOGIES & FIRST PLANTS FOR CARBON CAPTURE UTILIZATION/SEQUESTRATIONA CONFERENCE REPORTA conference on Emerging Technologies for Carbon Capture Utilization/Sequestration

(CCUS) was convened by the University of North Carolina’s Kenan-Flagler Energy Center

on March 29-30, 2019. The conference was undertaken in response to developments that

suggested a more prominent role for CCUS in national energy policy. Foremost among

these was the 2017 passage of increased Federal tax incentives for CCUS investments. This

was followed by a U.S. Department of Energy request to the National Petroleum Council

(NPC) to examine in depth means by which CCUS investments might be promoted. As this

report is being written, the NPC is preparing that report.

These developments raised a question – which are the CCUS investments that might be

promoted? Our conference focused on two technologies whose emergence might provide

the basis for fulfilling the DOE/NPC’s CCUS goals. The technologies in question are Fuel Cell

Energy Inc.’s Molten Carbonate Fuel Cells and NETPower’s Allam Cycle. These essential

questions our event considered were these: 1) how ready technically are these emerging

technologies for ‘at scale’ investments? and 2) are these technologies economically viable

in the face of typical First of a Kind (FOAK) investment risks? This report details the answers

given at the conference and draws implications and recommendations for moving these

CCUS technologies towards the goals sought by DOE/NPC.

ESSENTIAL BACKGROUNDWHAT IS CCUS? A BRIEF OVERVIEWCarbon Capture Utilization/Sequestration involves a chain of activity to first capture C02

emissions from power, industrial and ethanol plants, and then move it to a location where

it might either be used to produce a marketable product or fuel, or otherwise sequestered

in a secure location. Said differently, the chain involves emissions separation & capture,

logistics and then either use or sequestration. Exhibit 1 below depicts this chain graphically

and shows the variety of forms it may take.


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Exhibit 1: Carbon Capture Utilization/Sequestration Chain

The obvious CCUS benefit is to enable existing and future plants to operate carbon free.

However, it has proven challenging to render CCUS a value creating chain. Capturing

C02 from flue gas streams with concentrations of 4% has proven technically difficult and

expensive. There are few pipelines available to move the captured C02. Manufacturing

fuels or chemicals using captured C02, while feasible, has not proven cost competitive with

existing processes. Approved sequestration sites are few in number, and sequestration is

both costly and brings with it enduring environmental responsibilities.

It thus comes as no surprise that CCUS projects have been few in number. Some success

has been achieved putting captured C02 into Enhanced Oil Recovery (EOR). There a dual

benefit is achieved – EOR yields a readily marketable commodity at the same time that

the C02 used to coax more oil out of the ground is securely stored in a proven geologic

formation. These advantages hold out some hope for more CCUS projects tied to EOR. In

their wake, attention has shifted back to improving the capture ‘front end.’ It is there that the

emerging technologies discussed at the conference have focused.

WHAT ARE THE EMERGING TECHNOLOGIES? WHAT CHALLENGES DO THEY FACE?

There has been minimal deployment of CCUS to date. The economics of capturing carbon

from plant flue gases have proved daunting. The best available technology, capture via

amines saturation/separation, requires copious amounts of power drawn from the plant

it is de-carbonizing; i.e. it is ‘net power parasitic.’ Second, disposal of captured carbon

has proved challenging. Utilizing C02 to manufacture cement or chemical products

has yet to prove economic on a widespread basis. Pure sequestration is not only a cost-

15


sink, but subject to exacting environmental requirements and persistent skepticism from

the environmental community. Injecting C02 into oil reservoirs to improve recovery, i.e.

‘enhanced oil recovery,’ has proven the most economic means of disposal. EOR yields a

readily- monetized product; moreover, established oil reservoirs are widely considered to

offer reliable storage for C02 and are regulated as such. The best known CCUS project in

the U.S., the PetraNova project in East Texas, combines amines capture with EOR. To date,

this project has not inspired imitation. Rather, it has led to the search for an even more

economic capture technology.

Two promising CCUS technologies have recently emerged. The Molten-Carbonate Fuel

Cell technology is primarily a retrofit technology developed as a joint research project by

Fuel Cell Energy Inc. (FCI) and ExxonMobil. The Allam Cycle is a new-build technology

developed by NETPower and its financing affiliate, 8Rivers Capital. At the present time, both

contemplate using natural gas as fuel, with potential evolution to coal as a later possibility.

The fuel cell technology promises to capture 90+% of the CO2 from an existing natural gas

power plant, while also generating net electricity over and above what is consumed in the

capture process. The NETPower technology promises to generate electricity at efficiency

rates/costs comparable to the most advanced Combined Cycle Natural Gas plants (CCNG)

while capturing all generated C02 for utilization or sequestration.

Successful commercialization of a new technology involves a careful, often prolonged

development path. The technology must first be proven at ‘bench scale’ in a laboratory,

i.e. the ‘proof of concept’ stage. If technically and economically promising, the next stage

is construction and operation of a Demonstration plant. This plant may be 10x or more

in size versus the bench scale, and also 1/5-1/10 the scale of a commercial sized plant.

Such ‘Demo plants’ can be expensive, costing tens to even more than one hundred

million dollars. Demo plants teach sponsors whether a plant using their technology can

produce results similar to those achieved in the lab; they also show how the equipment

‘scales up,’ what ‘bugs’ should be expected when starting up the plant and whether the

new technology allows the reliable operations needed for acceptable economics. Only

after extensive testing and the achievement of satisfactory results on all of these fronts will

most technology sponsors attempt the jump to a fully ‘at-scale’ First-of-a-Kind (FOAK) plant.

The track record of FOAK energy plants is dotted with failures. The Kemper ‘Clean Coal’

project incurred a massive cost overrun, leading its owner to turn the project into a

conventional natural gas plant. ‘Advanced nuclear’ technologies incurred massive overruns

in Georgia and South Carolina. The latter put its owner utility, SCANA, into bankruptcy.

Efforts to produce bio-fuels from wood-based pyrolysis oil led to an abandoned plant in

Mississippi and the bankruptcy of KiOR, the owner firm. These and similar cases have caused

both utilities and their regulators to become cautious about attempts to commercialize

emerging technologies.


16

NETPower has advanced its Allam Cycle technology to the point of constructing a 50 MW

Demo plant near Houston, Texas. Major energy firms, including Exelon and Occidental

Petroleum, are backing NETPower in this endeavor. This plant has been undergoing testing

for about one year and has yet to put and maintain power to the grid. The FCI/XOM fuel cell

technology has yet to be tested at Demo plant scale.

FEDERAL TAX CREDITS FOR CCUS

Recognizing both the strong need to develop CCUS and the multiple obstacles facing

private companies in the space, the U.S. government recently enhanced tax incentives for

investing in carbon capture equipment. An initial tax credit provision was created in 2008.

This provision (Section 45Q) was then greatly expanded in the tax reform act passed at

the end of 2017. Under the new provision, investors in CCUS equipment shall be entitled

to claim a federal tax credit of up to $50/ton of C02 captured and securely sequestered. A

credit of up to $35/ton will be available to investors whose capture and provide C02 into

EOR or other forms of commercial utilization. These provisions are accompanied by several

conditions. To qualify, CCUS projects must begin construction by 2024. Moreover, the

total amount of credit available is capped at 50% of aggregate tax liability over a 12 year

horizon. Finally, the C02 must be securely stored under rules devised and administered by

the Environmental Protection Agency (EPA).

Industry groups have brought to the Federal government’s attention multiple uncertainties

regarding the current version of 45Q. Foremost among these has been the rules that must be

followed for the EPA to deem C02 ‘securely sequestered.’ A coalition of energy companies

and other interests have wanted the ‘Monitoring, Reporting, and Verification’ rules (MRV) to

be those currently pertaining to EOR operations (Section RR of the EPA’s Greenhouse Gas

Reporting Regulations). Under these rules, the company’s MRV obligations cease when

production is terminated and the wells deemed properly secured. Pure sequestration

however, operates under a different EPA set of rules (Section UU); there the operator’s

responsibilities for secure sequestration are open ended. In 2016 the IRS put out a form

which seemed to suggest that only Section UU could be used to claim the 45Q tax credit.

Several environmental groups strongly support the position that UU should be the standard

for CO2 stored via EOR. These uncertainties threaten to paralyze industry investment in

CCUS/EOR. Potential sponsors face the prospect of open ended responsibility/cost

for MRV, and the risk of having tax credits recaptured if later on it is determined that the

operator applied the wrong standard. The U.S. Treasury Department and IRS are currently

engaging with industry groups and interested parties to clarify how the 45Q credits will be

administered.

17


The economics of a new technology CCUS project are thus quite complicated. They involve

not only the capital and operating costs of the project itself, but the price of natural gas, the

wholesale price for generated electricity, whether the captured C02 will be sequestered

or used for EOR/something else, transportation costs for the C02, whether 45Q tax credits

are fully captured, and the value of by-product gases such as hydrogen. They also involve

major risk factors. Principal among these are 1) the possibility of a massive cost overrun for

constructing a FOAK technology plant; and 2) the risk of recapture of the 45Q credits due

to uncertainties in the tax rules and/or failure to comply with the EPA’s rules.

These are the major facts setting the context in which the emerging technologies will

attempt to advance to commercial scale projects. The next steps for these emerging

technologies are to prove that they work ‘at scale’ and that they can be built at something

like the costs being estimated by their developers. To establish these conditions, developers

and sponsors are going to have to take the risk of building large FOAK plants or retrofitting

large existing plants. These risks are not small, as is discussed below. However, the need

is great. At the conference multiple speakers emphasized that CCUS is essential to forging

the energy transition urgently needed. To this need we now turn.

THE NEED FOR CCUSThe conference began with presentations focused on the ‘dual challenge,’ i.e. the challenge

of continuing the global economy’s growth and development while also lowing its carbon

footprint. The essence of this discussion was that CCUS has a vital role to play in meeting

this dual challenge. Energy demand is going to grow and with that growth will come more

use of fossil fuels. CCUS provides the means to enable fossil fuels to meet demand which

other energy sources can’t serve or can’t serve at acceptable cost, while also allowing

this fossil fuel use to take place on a low carbon emissions basis. Here are the specifics

discussed at the event.

• Economic growth/development will stimulate demand for more energy. Reputable

outlooks out to 2040 see global energy demand growing from today’s 13+ BTOE

(Billion Tons of Oil Equivalent) to some 18-23 BTOE. Even a dramatic change in

global policies, amounting to an all-out effort to reduce emissions, will still see

energy demand grow above 15 BTOE. Thus, the ‘dual challenge’ of continued

growth with lower emissions requires a combination of more and cleaner energy.

Exhibit 2 depicts energy demand growth under various scenarios: ET (Evolving

Transition) is the reference case, while RT (Rapid Transition) represents the ‘all out’

effort to reduce emissions. Note that even in this RT scenario, oil & gas utilization is

higher than in 2017 and coal does not completely ‘go away.’


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Exhibit 2: Energy Demand Growth

• Under the RT scenario, the targeted GHG reduction amounts to lowering projected

emissions from 35 GT/yr. (Gigatons/year) of C02 to about 18 GT/yr. There appears to

be no ‘silver bullet’ for meeting this challenge. Rather, a portfolio of initiatives might

accomplish the task. Efficiency, more renewable power, nuclear and fuel switching

(e.g. coal to natural gas) are needed to make major contributions. CCUS makes up

a component of this effort, contributing about 7% of the targeted reduction. Exhibit

3 below depicts the contributions of these various initiatives to reducing emissions

under the Rapid Transition scenario:

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Exhibit 3: Carbon Capture Utilization/Sequestration Contributions

• While small in percentage, the CCUS contribution is large in absolute terms, i.e.

1.2 GT/yr. of C02 captured and utilized/sequestered. The location of CCUS within

this scenario is also strategic, i.e. it will enable deeper renewables penetration into

electricity generation by providing the flexible backup power to compensate for

their intermittency and for battery storage limitations. A broad consensus exists

that CCUS must form part of the global approach to de-carbonizing the economy.

Exhibit4 below shows an extensive set of energy forecasts out to 2040. Note how

significant amounts of CCUS form part of these outlooks


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Exhibit 4: Energy Forecasts to 2040

• The CCUS scale-up challenge implied by this goal is formidable. Today, global

CCUS amounts to 65 MT/yr., most of which goes into EOR in the U.S. This means

we are talking about a ~20X global scale up over a 20 year period. Today’s CCUS

projects are also small relative to need, checking in a ~30 MT/yr. per project. Finally,

it matters where future projects are built. De-carbonizing coal plants in China and

India will be much more impactful on emissions that equipping U.S. CCNG plants

with comparable technology.

THE NEED FOR ADVANCED CCUS TECHNOLOGIES

• To date, three noteworthy CCUS projects are operating in the U.S.: the PetroNova

project (NRG/JX Nippon Oil), an Air Products plant at Valero’s Port Arthur refinery,

and an Archer Daniels Midland facility next to a Decatur, Illinois ethanol plant. The

first two put captured C02 into East Texas EOR. The third sequesters its C02, and

is the first to receive EPA approval for a Class VI well permit to put C02 into deep

saline storage.

• Cost estimates for these facilities range between $60-80/ton of C02 captured

and disposed. This cost level is a positive barrier to larger scale deployment. The

facilities employ solvent technologies which require heat to separate the C02 from

the solvent; as such they are energy ‘parasitic’ and thus expensive. Chart 4 shows

the DOE’s estimates of these costs and a prospective pathway to reductions by

2030.

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Exhibit 5: Cost of CO2 Capture

• The U.S. Department of Energy (DOE) believes a cost reduction of 50% or more is

needed to stimulate large scale investments in CCUS. While refinements to existing

technologies and scale manufacturing can lower their, it is questionable whether

these advances alone can lower CCUS costs to the level envisioned by DOE. The

fundamental fact that these technologies soak off copious amounts of power from

the plant they are de-carbonizing poses a major cost hurdle. The sparse number

of projects overall, and the fact that FOAK plants like those listed haven’t been

imitated, testifies to the widespread belief that the existing CCUS technologies are

not a ‘good enough’ answer.

THE EMERGING TECHNOLOGIESTwo emerging CCUS technologies promise to do better. Both generate more electricity

than they consume in the capture process. Both capture 90+ % of the C02 that otherwise

would be vented to the atmosphere. Even better, the technologies are complementary; one

would allow existing natural gas plants to be retrofitted and de-carbonized. The second

is a new build power plant promising CCNG efficiency and performance but with no C02

emitted. Both are in the technology development stage; how close to ‘commercial’ are

they?

• NETPower/8Rivers Capital Allam Cycle relies on superheated C02 to drive its

turbine. The basic concept is that ‘supercritical’ C02 provides much greater mass

than hot air; this allows the C02 to drive a turbine with superior efficiency. As shown

in Chart 5 below, the Allam Cycle generates a pure C02 stream by combusting

natural gas with pure oxygen and then puts the C02 through its turbine. The cooled


22

C02 is then re-heated via heat exchange and new combustion, and re-cycled

through the turbine. This recycling and the greater mass of using C02 to drive the

turbine provides the efficiency gain needed to pay for an upfront Air Separation Unit

(ASU). This ASU creates the pure oxygen stream used in initial combustion while

producing valuable bi-product gases. The operation eventually yields a pure C02

emissions stream suitable for pipeline transport to EOR, sequestration or other use.

Exhibit 6: 8Rivers Capital Allam Cycle

• NETPower estimates the Allam Cycle first plant can produce electricity at ~$65/

MWH. This cost is about $20/MWH above a CCNG plant and comparable to that

same plant equipped with today’s CCUS. When however, NETPower factors in

the revenue from the sales of C02/industrial gases, its mature technology plant net

costs would drop to ~$35 MWH. Moreover, NETPower assumes its first plant could

capture robust industrial gas revenues. If this proves the case, NETPower’s FOAK

plant could come in well below its lined out $35 MWH long term outlook. Federal

tax credits would further improve these economics. NETPower’s net cost figures

are provided in Chart 6 below:

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Exhibit 7: Levelized Cost Comparison

• NETPower plans a final investment decision on a 300 MW commercial scale plant

in 2020. It’s ability to adhere to this schedule depends upon the successful startup

of its 50 MW Demo plant in LaPorte, Texas. While components of this plant have

been tested successfully, the key Toshiba turbine shell remains in a test phase; the

plant has yet to put power to the grid and sustain operations. It’s ability to do so will

be the key test of whether the use of denser, super-heated C02 to drive turbines is

viable and will cost what NETPower currently projects.

• The Fuel Cell Energy Inc./ExxonMobil Molten Fuel Cell technology uses reactants

within a fuel cell to both capture C02 and generate net electricity. As depicted

below, the fuel cells take in gas turbine exhaust with 4% C02 content. Within

the cathode, the C02 reacts with oxygen, becoming C03 -2 ions while releasing

electrons. These components then pass through a molten electrolyte to the anode,

where they further react with input methane and water. The reformed methane

yields hydrogen, which in turn converts the C03 -2 to C02 while the electrons are

released as produced electricity. The C02 is released for use or sequestration and


24

the surplus H2 is a valuable bi-product. Exhibit 8 below depicts the workings of

a molten carbonate fuel cell while Exhibit 9 places such a cell in the context of a

working power plant.

Exhibit 8: Molten Carbonate Fuel Cell

Exhibit 9: Molten Carbonate Fuel Cell in a Working Plant

• Today’s carbonate fuel cells are manufactured as cells suitable for stacking. This

allows for configurations where stacks of cells are added to plants either vertically, in

side-by-side stacks or within boxes resembling parallel trains (see Exhibit 2 below).

Stack size and the number of side-by-side stacks can be varied with the size of

the adjoining facility, and the fuel cell footprint is small. Connections to existing

facilities are straightforward. This makes carbonate fuel cells a physically feasible

retrofit option for existing power, industrial or biofuels plants. Various configurations

of carbonate fuel cells are installed at or on order for over 50 sites amounting to

300 MW of capacity. Most of these facilities have been installed as ‘off the grid’

investments rather than as carbon capture projects.

25


Exhibit 10: Molten Carbonate Cells Current Status

• That said, FCI and XOM have yet to test their retrofit configuration at a large scale

or Demo size power/industrial plant. It is unclear why this is the case. However, a

UNC Energy Center Scholars’ study points to two possible explanations. First, the

stand-alone economics of a fuel cell power plant retrofit are not yet compelling.

Even if constructed at projected cost (a serious question discussed just below),

the combination of electricity and C02 to EOR revenues produces only a single

digit return. This seriously understates the retrofit’s value, a good portion of which

involves defending the underlying plant from carbon taxes, early retirement or other

carbon reduction investments.

• The bigger issue may be that capital costs for a first at-scale retrofit could greatly

exceed current projections. Carbonate fuel cells are today a niche product with an

undeveloped supply chain. Manufacturers will want to see prospects for sustained,

large scale demand before creating large scale capacity. Cells ordered for a Demo

plant may thus incur costs closer to a ‘small scale production order’ than to those

from lined-out manufacturing. These facts plus the reality that carbon taxes etc. are

not yet widespread may be tempering sponsor appetite to invest in Demo-scale

plants.

• Longer term, a flexible CCUS retrofit option could prove a low cost pathway to

decarbonizing electricity generation. The electricity industry, environmental

groups and regulators need to properly aggregate the costs associated with

deep renewables penetration. These include not only the costs of renewable

power when it is generating, but also the costs associated with 1) adding flexible

backup power and/or storage; 2) running existing plants less efficiently because


26

renewables’ intermittency imposes stops/starts on other plants; 3) higher capacity

reserves because the generation mix becomes more variable as renewables

make up a bigger percentage; and 4) early retirements of existing plants whose

economics are undermined by renewables’ ability to bid to zero marginal cost in

merchant market auctions. Compared with these costs fully aggregated, retrofitting

natural gas plants with 85% capacity factors and load- following flexibility may be

the low cost option.

ENERGY CENTER SCHOLAR’S REPORT - MODELING CCUS’ ECONOMICS FOR FIRST OF A KIND PLANTS

• How close are the emerging technologies to being economically attractive at scale?

To find out, a team of Kenan-Flagler Energy Center Scholars undertook a research

project modeling deployment of these technologies at a ‘favorable location.’ The

favorable location was defined as being the site of a large scale natural gas power

plant with ready access to EOR, CO2 pipelines and markets for industrial gases.

These conditions were judged conducive to secure sequestration of captured C02,

monetization of all products/bi-products, as well as affording favorable conditions

for constructing new facilities. Odessa, Texas offered many of these conditions

and became the selected site. The modeling was done with the cooperation of

the power plant owner, the technology providers and nearby EOR/C02 pipeline

operators.

• ‘Reference Case’ modeling of these FOAK commercial-scale plants showed

positive Internal Rates of Return (IRR) for both technologies without incorporating

any Federal (45Q) tax credits. While the Fuel Cell retrofit case showed 7.4% IRR, the

new-build Allam Cycle power plant demonstrated an IRR of 17.7%. Applying a 10.5%

weighted-average cost of capital (WACC) produces a negative Net Present Value

($170 M) for the Fuel Cell case while the Allam Cycle generates a positive $323 M

NPV. These economics use capital contingency factors normally associated with

technologies previously demonstrated at several plants. Consequently, sensitivity

cases testing more stringent contingencies were undertaken. The Allam Cycle

results also reflected a diverse blend of revenue generation, i.e. its production and

sale of industrial gases, plus C02 and electricity in the West Texas location. Detailed

economics for both the Allam Cycle and Fuel Cell investments, including both

reference and sensitivity cases, are found in the Appendix.

• Net Present Values (NPV) of both economic models demonstrated significant

sensitivity to capital cost overruns; larger contingencies normally associated

27


with FOAK plants greatly impact and could eliminate the NPVs. For example, a

+/-50% upfront capital cost increase for the Fuel Cell retrofit case drops the NPV

to ($442M). The new-build Allam cycle plant models more robustly, with a 50%

capital cost contingency still producing an NPV of $112M. This suggests that the

key risks for a FOAK Allam Cycle lie a) on the revenue side and b) on the possibility

of much greater capital cost overruns for this emerging technology. Results for

both technologies underscore the need for a careful technology development path,

including a thoroughly tested, successful demonstration plant.

• The recent U.S. tax reform provides enhanced Federal tax credits (45Q) available to

qualifying CCUS investments. Using the $35/ton 45Q carbon tax credits available

for disposing captured CO2 into Enhanced Oil Recovery (EOR), our models show

the credits to be appreciable cost-buffers; these could play an important role in

offsetting potential cost overruns. With this credit, the Fuel cell retrofit case NPV

jumps from ($170 M) for reference case to $436M. The new-build Allam cycle plant

NPVs improve from $323 M for reference case to $473 M with 45Q credits.

• Allam cycle plant’s revenue breakdown reflects nearly 1/3rd contribution each from

electricity revenues, CO2 sale revenues, and industrial gas sales. Industrial gases

have fragmented regional markets and cyclically variable pricing. This suggests

that early Allam Cycle plants will achieve the most attractive economics if located

on the U.S. Gulf Coast, which offers access to a deep, liquid industrial gas market.

• The results suggest that the Allam Cycle technology is closer to FOAK at-scale

deployment than the Fuel Cell retrofit. Even with a significant cost contingency,

an Allam Cycle built in the right location it could generate an economic return. Even

a 100% cost contingency, not unreasonable for FOAK plants, might not render a

first Allam Cycle plant uneconomic if it could be buttressed by the 45Q tax credits

and gas sales. These results suggest considerable commercial potential for the

Allam Cycle technology, assuming its 50 MW demonstration plant, now undergoing

testing near Houston, can demonstrate power to the grid on a sustained basis. That

demonstration plant is testing unique design features in its turbine as well as the

plants ability to operate continuously using super-heated CO2 to drive a turbine. At

present the tests are several months behind originally announced schedule.

• The Fuel Cell retrofit economics do not reflect the full value of the technology.

These projections are traditional ‘marginal economics.’ This means they measure

only the direct cash flow changes created by installing the Fuel Cell technology. In

this analysis, the marginal effects consist of the capital and operating costs on one

side and the sales of electricity and C02 on the other. By this measure, fuel cells


28

are a relatively inefficient producer of net electricity. Thus, the marginal revenue

from a Fuel Cell retrofit is limited. Not reflected in this framework is the benefit of

defending the underlying plant from other negative impacts. Future regulations,

e.g. carbon taxes, a Clean Power Plan, can render underlying plants less economic

or even uncommercial to operate. Mandate driven wind/solar can force other plants

into inefficient backup operating modes. By providing carbon free operations, Fuel

Cell retrofits can shield underlying plants from such effects and avoid these costly

outcomes. Thus, retrofit economics need to look further than just the marginal

effects triggered by their installation.

• Further dissecting the capital costs for a Fuel Cell retrofit case revealed the fuel cell

modules being a major (40%) contributor to the total capital costs. This rendered

the retrofit FOAK plant to be considerably less capital efficient than the Allam cycle

on a unit cost of production basis. With the fuel cell modules along with the inverter

component totaling 48% of the capital costs and both cost factors only scaling

1:1 with plant capacity (whereas other cost factors scale 2/3:1), bringing down the

module manufacturing costs was highlighted as a key future challenge.

• The study also revealed the locational challenges associated with deploying

these technologies. The West-Texas location was chosen for having local CO2

EOR demands and available pipeline infrastructure. However, these advantages

were substantially offset by the nature of the local power market. West Texas

turns out to have very low wholesale power prices and little prospect for near term

improvement. Texas’ building of substantial wind power, the merchant structure of

its electricity market, and the extremely low price of stranded natural gas all combine

to produce wholesale power prices among the lowest in the U.S. The resulting

dilemma is this – the nation’s best EOR market for CO2 turns out to have one of its

more distressed electricity markets. However, many other, better power markets

won’t offer the opportunity for efficient CO2 disposal into EOR – widely considered

the most economic disposal option.

• Generalizing from these West Texas findings, it is still unclear where to find an

advantaged location for testing these new technologies at scale. Many factors,

the power market, C02 logistics and disposal, a mature plant construction industry

and access to industrial gas markets, are major influences on the economic

viability of these FOAK plants. Taking all factors into consideration, East Texas or

Louisiana may emerge as the best sites, offering some EOR and good industrial gas

opportunities, and a better wholesale electricity market.

29


• Finally, the study’s results suggest that ‘lined out’ applications of the emerging

technologies combined with the 45Q credits could be very economic. As noted, the

retrofit case jumps from a negative NPV to a positive $436 M and the Allam Cycle’s

already robust return rises above $470 M NPV. If the 5th+ version of these plants

can attain the capital efficiencies promised by their sponsors, the combination

of the technologies’ inherent economics and 45Q credits could promote a wide

dissemination of their use. This makes the suitability of the 45Q credits, as written

in current law, critical to near term CCUS deployment.

45Q TAX INCENTIVES, SEQUESTRATION AND MRV RULES - OPPORTUNITIES & ISSUES

• An initial tax credit (IRS Code Section 45Q) for CCUS was enacted in 2008. It

provides a credit of $10/ton for carbon captured and used as an injectant in EOR,

and $20/ton for C02 placed in secure geologic storage. The credit is available

to CCUS equipment placed in service by February 9, 2018. The tax reform law

enacted late in 2017 amended these provisions. Principal innovations include the

following:

• The credit amounts were raised to $35/ton for C02 into EOR and $50/ton for C02

placed in secure storage

• Certain earlier limitations were lifted. The CCUS investor/owner can now achieve

credits on C02 captured for up to 12 years of operations

• The definition of injectant usage was expanded to include use in biological

processes, chemical manufacturing and other uses where a commercial market

exists

• It is no longer necessary to own both the underlying industrial facility and the

capture equipment to claim the credit. Ownership of only the equipment is now

sufficient. Moreover, use of the credit is not limited to the owner of the capture

equipment. It can be transferred to a party using the C02 as a tertiary injectant in,

for example, EOR and being responsible for its sequestration.

• To be considered a ‘qualifying facility’ eligible to claim the credits, the facility must

begin construction no later than January 1, 2024, and the CCUS equipment must

either begin construction before that date or be included in the original design of a

plant that meets the commencement deadline.


30

A fuller version of these tax law changes along with a discussion of open issues is provided

in the Appendix to this report.

• While welcome, these new guidelines raised a host of questions for the industry as

regards qualifying for and then retaining the CCUS tax credit. Industry groups are

currently engaged in an effort to secure clarifications and detailed rules/regulations

from the U.S. Treasury Department. These clarifications also involve the IRS and the

Environmental Protection Agency.

• Foremost among these issues is how to ‘monetize’ a valid CCUS tax credit. The rules

only contemplate that the owner of the capture equipment or the party using the

C02 as an injectant can claim the credit. In many circumstances, neither of these

parties may have sufficient or even any ‘tax capacity’ to use the credit. Experience

from the wind/solar industries suggest that clear guidelines allowing transfers of

the credit to financial players with tax capacity are needed for 45Q to become fully

effective. This guidance does not now exist. Moreover, such ‘tax transfer’ rules

would need to address the extent to which the ultimate user of the credit has to be

responsible for the secure sequestration of the C02. Such a requirement depositing

storage liability with a financial player using the tax credit would inhibit full use of

45Q.

• A second issue concerns the start date for a project to be deemed a ‘qualifying

facility.’ January 1, 2024 is less than five years away. When one considers: 1) the

time required to secure clarifying guidance from U.S. Treasury; 2) the time required to

technically scale-up the new technologies and demonstrate their viability, and 3) the

time required to plan and finance a major capital project involving new technology,

the law’s deadline seems to foreclose widespread used of 45Q for CCUS. Indeed,

this deadline is so tight that it may prevent any new CCUS technologies from being

deployed in new or existing plants.

• The third issue concerns what is required for those claiming the credit to establish

that the C02 is going into ‘secure geologic storage.’ Secure geologic storage

is defined in Treasury Regulations applicable to the earlier and the new tax law.

Those sequestering C02 must place it in formations and operations which meet

various standards set by the Environmental Protection Agency (EPA). These

standards cover monitoring, reporting and verification and are generally known as

the Agency’s MRV rules. A failure to comply with these rules could lead to loss of

the 45Q tax credits (and recaptured of those already taken). There is also the risk

of additional damages due to law suits brought by private and other governmental

parties on the grounds that the MRV rules were not followed.

31


• A key uncertainty has been the obligations of those storing C02 to continue

reporting over time. Two potential sets of EPA Greenhouse Gas reporting rules exist,

those currently applying to EOR operations (Section UU) and those more recently

issued which likely apply to sequestration in saline caverns or similar structures

(Section RR). The latter are more stringent and include requirements for monitoring

and reporting well after injection of added C02 into the reservoir has ceased.

• The existence of two sets of rules has created concern on the part of oil/gas

operators that the more stringent criteria might now apply to EOR operations or

might later be determined to have applied. This concern was amplified by an IRS

form, issued in 2016, which implied that only compliance with Section RR was to

be considered. Some EOR operators are concerned that operating under the RR

rules could require them to verify and report on wells long after their access rights

under land leases have expired. Various EOR operators and industry groups are

now seeking clarification from EPA on which rules apply and from the Treasury as

to the precise consequences for a failure to comply.

• Subsequent to the conference, the International Organization for Standardization

(ISO) issued a standard addressing secure geologic storage, monitoring and

reporting. Various industry groups are now urging U.S. Treasury to recognize this

standard as providing added support and transparency for EOR operations using

C02. Said differently, the industry is recommending that Treasury endorse industry

meeting their MRV reporting requirements under Section UU if they also meet the

ISO standard. As of the issuance of this report, Treasury has yet to provide final

guidance on these matters.

C02 UTILIZATION - EOR AND OTHER USESEnhanced Oil Recovery (EOR) is currently most economic disposition of captured C02. At

least 3 Permian Basin producers (KinderMorgan, Occidental and Danbury) use C02 to flood

conventional oil reservoirs and squeeze out more production. This process has been going

on for decades, and a considerable C02 infrastructure, including long distance pipelines,

has been created to serve it. Producers currently pay $25-30/ton for C02. This means that

industrial users and utilities capturing C02 at their plants have an opportunity to generate

plus revenue and obtain secure geologic storage by directing their C02 streams to EOR

operations. The 45Q tax credit provides additional incentives on top of the revenue from

selling C02 into EOR.


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• Unfortunately, C02 EOR operations are currently limited to West Texas and scattered

sites in East Texas. Other locations along the Gulf Coast may offer opportunities,

as may certain areas in the Rocky Mountains and California. These latter areas

face, however, significant environmental obstacles to EOR operations and/or C02

logistics infrastructure. Charts 11 and 12 below provide some details on the U.S.

C02 pipeline infrastructure:

Exhibit 11: Capture and Production of Co2 in the United States

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Exhibit 12: Co2 Pipeline Infrastructure in the United States

• These circumstances pose a serious limitation for utilities and industrial users

interested in CCUS but located outside of the Gulf Coast. For them, disposition of

captured C02 looks like a major cost sink. Not only must secure geologic storage

be created and moved through environmental reviews, but the infrastructure to

get C02 to these locations doesn’t exist. Moreover, disposing of captured C02 in

this fashion generates no revenue. Utilities and industrial users will thus be wholly

reliant on the 45Q tax credit to offset the costs of moving and sequestering their

C02. It is not clear that the $15/ton ITC ‘premium’ ($50/t vs. $35 going into EOR)

can compensate for these formidable cost barriers.

• A hopefully note on Eastern U.S. EOR was presented at the conference. Fracking for

natural gas was discussed as a potential use for CO2. Some technical clarifications

help here. Current EOR with C02 is flooding conventional reservoirs with porous

rocks. There the entry of C02 maintains reservoir pressure and forces crude oil

to the well bore. Oil prone ‘tight’ shales however, are not porous enough for this

process to work economically. Consequently, Permian operators do not use C02

in their fracking operations, which mostly target crude oil production.

• Gas-prone shales offer a different prospect. Natural gas consists of smaller

molecules, so injecting C02 does produce the pressure restoration effect that boosts


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production. Moreover, C02 has an ‘Adsorption’ effect. Organic materials located

within shales prefer associating with C02 rather than natural gas. Consequently,

injecting C02 into shales allows the C02 to displace natural gas, which then

migrates to the well bore. This exchange of C02 for methane can be quite prolific –

the organics prefer C02 adsorption at a 2-5X basis versus natural gas. The result is

substantially higher and more sustained gas production from fracked natural gas

wells.

• East Coast U.S. is blessed with highly prolific and productive gas fields, especially

the Marcellus located in Pennsylvania, Ohio, NY and West Virginia. Eastern and

Midwest utilities could thus potentially capture C02 and move it to these gas

producing fields for EOR and sequestration. The result could be better economics

than those associated with pure sequestration.

• This possibility was presented by a highly reputable oil field services provider. Other

energy company representatives present raised various technical concerns. Further

examination and discussion are needed to firm up this EOR possibility. It is likely

that further R&D is needed followed by a C02 fracking pilot project to demonstrate

the potential of this option.

• If EOR is not available and sequestration is too expensive, C02 utilization becomes

the third disposal option. Currently, about 200 M metric tons of C02 are utilized

annually worldwide for various products/processes. The majority goes into EOR or

the manufacture of fertilizer (urea). This level of consumption is tiny (< 1%) relative

to annual global C02 emissions of 37 billion metric tons. Chart 13 below provides

a look at historic and forecast C02 utilization.

Exhibit 13: Historic and Forecast CO2 Utilization

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• Intensive research efforts are underway around the globe to develop economic

uses for C02. The most promising efforts fall into four categories: 1) construction

materials; 2) fuels; 3) chemical intermediates; and 4) polymers.

• Of the four, construction materials are closest to economic deployment at scale.

Curing concrete using C02 has produced a 20% improvement in compressive

strength relative to traditional methods. The availability of 45Q tax credits may

combine with this quality gain to encourage some concrete utilization projects to

break ground before 2024. Tying an optimal location for concrete production with

the availability of a high quality C02 stream will be the challenge to overcome.

• Despite the considerable research efforts and successes like the manufacture of

ethanol from syngas (carbon monoxide), none of the other areas appears close to

large scale deployment. In most cases the production process involves multiple

steps and considerable amounts of energy. Typically, such new processes using

C02 compare unfavorably in economic terms with existing processes at currently

operating plants. Efforts to connect C02 utilization with renewable electricity

involves both cost and reliability concerns. Thus, few developers in the fuels,

chemicals and polymer spaces seem poised to jump to commercial scale projects.

To date the availability of 45Q credits has not changed this outlook. The NREL

chart below, providing subsidy levels required for various C02 utilization options,

reinforces the point.

Exhibit 14: Levels of Required Subsidy for Different CO2 Utilization Options


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CONCLUSIONS AND RECOMMENDATIONS

The development of CCUS technologies and facilities is of critical importance for reconciling

economic growth and climate risk mitigation. There are at least four major reasons why this

is so. First, the world will continue to need additional energy. This will be needed not only

to develop but to maintain the progress already achieved. The world economy is globally

integrated. It will be difficult to foster growth in the developing world if the develop countries

are stagnant or declining – and growth everywhere requires more energy. Climate risk

mitigation implies meeting growing energy demand with low carbon supply. Wind/Solar

plus batteries cannot do there everywhere, at every time at anything like affordable cost.

Fossil fuels not only remain in the picture, but almost all reputable forecasts foresee demand

for them growing. Including CCUS into new electricity generation would provide a way for

much of this growth to also be low carbon.

Second, there is a massive installed base of fossil fuel power plants. Adding more wind/solar

to the grid and replacing all this capacity likely is infeasible for many reasons. The sheer

scale of the replacement effort would strain resources and project execution capability. In

many places, factors such as supply security or employment favor retention of the current

operations. Political resistance will surely mount as consumers discover the land use and

environmental consequences of truly massive wind/solar deployments, not to mention the

reliability decay likely to characterize the electricity grid. Retrofitting existing plants with

CCUS represents an opportunity to avoid all of these adverse consequences while still

progressing de-carbonization.

The above factors connect with a third reason – lower cost. The fully aggregated costs of

wind/solar + storage go beyond their directly observable costs. They also include the need

for other backup power, for grid integration investments, and the adverse consequences

they impose on existing plants. Non-despatchable wind/solar cause other plants to have to

operate inefficiently. Increasingly, they cause gas, coal and nuclear plants with significant

remaining economic life to have to close prematurely. These costs are never captured in

supposed ‘Levelized Costs of Electricity’ as calculated by the EIA, Lazard and others. Yet,

these costs are real. When properly aggregated, retrofitting existing plants with CCUS could

well prove more cost effective than shutting those plants, writing off their remaining life, and

investing in new wind/solar + storage.

Considered together, the points above point to a fourth reasons – that there is an optimal

configuration for low carbon electricity generation and it involves CCUS. Natural gas is

probably the best companion fuel for wind/solar. Only natural gas plants provide the quick

stop/start capability to compensate for wind/solar intermittency that lasts longer than a few

hours. Natural gas plants can deal with intermittency or run in base load if weather or other

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factors cause wind/solar capacity to disappear for a while. Coal is harder to de-carbonize

and nuclear should never be run in other than base load mode. De-carbonized natural gas

generation in some form is the optimal partner for renewable power. Even a state as pro-

renewables as California recognized this when it made room for natural gas with CCUS in

its Clean Power legislative mandates for 2045.

Thus, there is a strong case at the macro level that CCUS will be needed and needed at

scale. Yet, the challenge of actually deploying CCUS is formidable. The BP Rapid Transition

case foresees CCUS providing 7% of the emissions reductions needed. This may seem a

small target. However, when measured in terms of C02 captured, this capacity provides

something like 1.5 trillion tons/year of avoided emissions. Moreover, it enables higher

renewables penetration, which is providing something on the order of 7.5 trillion tons/

year of avoided CO2. Given that the world is starting from a negligible base of CCUS,

accomplishing this scale of deployment by 2040 will be a tall task.

It is for these reasons that the conference focused on the emerging technologies that could

make the transition to CCUS feasible. In the Fuel Cell Energy/ExxonMobil and NETPower

technologies, we have potential low carbon retrofit and new capacity solutions. Both claim

to be ‘net energy positive’ and NETPower’s claims are even more ambitious – ‘truly clean,

truly economic electricity.’ How real is this potential? How close to commercialization are

these technologies. We aimed to find out.

The conference revealed how formidable are the barriers to CCUS economic deployment.

This is especially true of those venturing to build a first at-scale plant with FOAK technology.

To date, most CCUS research has focused on making the ‘capture’ portion of the value

chain more economic. This is true of the efforts surrounding development of the two

FOAK technologies presented at the conference. Sponsor’s views in this regard can be

summarized as follows: ‘If we can’t make the carbon capture piece more economic, there

is little point in worrying about sequestration or utilization.’ The point was driven home by

the Fuel Cell technology presentation where the speaker emphasized the challenge of

capturing 4 molecules of carbon out of an average 100 emitted by a power plant – and

where the carbon is distributed randomly in the flow.

As legitimate as the focus may be, it obscures the ‘first project’ obstacles lurking down the

rest of a C02 value chain. Today, there is little infrastructure for moving C02. Almost all C02

pipelines head towards west Texas and EOR. That leaves utilities and industrial plants in the

rest of the nation wondering how they will move C02 to any destination – EOR, utilization or

sequestration. Tenacious NGO opposition to new pipeline construction only compounds

the challenge. As for utilization, the conference revealed few applications where converting


38

C02 to power or chemicals can compete with existing processes. Sequestration in saline

caverns or similar formations is a pure cost sink that brings with it material monitoring/

reporting obligations plus environmental risk and liability. EOR is left standing as the clear

winner for C02 disposal. Unfortunately, this limits the suitable locations for first CCUS to the

SW region of the U.S.

On top of these barriers lies the almost certain knowledge that a FOAK plant will cost

much more than estimated and encounter serious operating difficulties. Recent projects

like Southern Company’s Kemper ‘Clean Coal’ plant and KiOR’s Mississippi bio-fuels

refinery testify to these risks. The behaviors of the two technology sponsors featured at

the conference underscores their awareness of these risks. NETPower’s advice early in

2018 was that their LaPorte 50 MW Demonstration plant would start up in August of that

year. As of July 2019, it still has not sustained putting power to the grid. NETPower advises

that this is due to careful testing of the turbine custom designed by Toshiba. This history

underscores the challenge of perfecting operations designed to use ‘super-critical’ C02 to

drive turbines rather than just air. Similar types of concerns have deterred ExxonMobil and

FCI from advancing beyond the research stage to a demonstration plant.

Summarizing the overview, a proven and deployable CCUS technology is an essential

part of any realistic strategy to meet the global dual challenge of fostering growth while

mitigating climate risk. However, as of today we lack an economically attractive technology

that has been proven to work at scale, and CCUS sponsors face both limited disposal

options and an almost total lack of infrastructure to move C02 from where it is generated

to where it can be disposed.

The way forward from this situation begins with proving up an economically promising

technology at scale. This is the essential first step. Once the technology is proven, industry

players can begin confronting the challenges of infrastructure and disposal – these are

familiar problems where solutions have been found before in analogous circumstances.

As noted, the NETPower Allam Cycle technology is both closer to commercialization and

offers better prospects for an economic FOAK plant. This is so because it has built a serious

Demo plant and because of the diverse revenue mix a first plant could generate in the right

location.

The daunting risks facing a FOAK plant suggests that an industry consortium might be

considered as a means for sharing the risks among multiple ‘deep pockets.’ NETPower’s

current configuration points to a way this could be accomplished without starting from

scratch. Currently, both Occidental Petroleum and Exelon are equity investors in the firm.

Other industry players could join them in taking equity stakes in the firm. Alternatively,

39


NETPower could put its Allam Cycle technology and its FOAK investment in a separate

subsidiary and allow industry players to take equity directly in that affiliate. These stakes

could come with provisions of technical assistance and leverage in contracting for and

constructing the facility. NETPower’s demo plant difficulties suggest it could use the help

of firms long experienced with high heat/pressure processes and the de-bugging of new

technologies. Financial sponsors can also supplement industry players as providers of risk

capital, and they will be more inclined to do so if they feel NETPower is getting the project

execution help in needs from experienced players.

The availability of 45Q tax credits can help this approach. NETPower is unlikely to have

use for the 45Q investment tax credits on its own. Passing through the credits to equity

investors with significant tax capacity would ensure efficient use of the credits and bolster

the economics for a FOAK plant. As noted in the Energy Center Scholars report, full capture

of the 45Q ITC materially buffers the positive returns modeled for a NETPower plant in West

Texas.

Unfortunately, the 45Q credits lack the clarifying guidance necessary to encourage their

use. Moreover, they are structurally ill-suited to actually get many CCUS projects built. The

January 1, 2024 start date for plant construction is a ‘killer deadline.’ Said differently, it

almost ensures that at most one CCUS project may meet the requirements for a ‘qualifying

facility.’

This is so for many reasons. Start with the fact that U.S. Treasury/IRS are still considering

industry input for clarifying the 45Q regulations. It will take 6-12 months for this process

to play out. Nobody is going to start a CCUS investment until these rules are clear. New

legislation may also be needed to fix problems the process identifies. Meanwhile, utilities

and the oil industry will be watching to see if NETPower can fix its demo plant problems.

All of this suggests it will be well into 2020-21 before NETPower and its ultimate equity

investors can consider moving forward to a full scale plant investment. That plant will need

to be sited, designed, and contracted for construction, during which both the oil/gas and

utility industries will be watching to see: a) how much it actually costs to build the plant; b)

does it run as planned and c) how much does it cost and how long does it take to fix the

unanticipated problems.

All this implies that NETPower may get an at-scale plant started by the January 1, 2024

deadline but it is highly doubtful that any other plants will begin construction by that date.

Said differently, the current configuration of the 45Q tax credits will fail in its primary objective

of promoting large scale deployment of CCUS technologies. These sober conclusions lead

directly to our recommendations:


40

RECOMMENDATIONS• Treasury/IRS should take a broadly flexible approach to allowing ‘transfer’

of 45Q tax credits to a wide cast of sponsors with tax absorption capacity.

This is essential to assure the efficient use of the credits for first plants whose

economics will be most challenging. If these first plants are never built or

successfully operated, 45Q becomes a ‘dead letter.’

1. Since EOR is unquestionably the most economic and environmentally

viable CCUS approach today, Treasury/IRS should clarify the MRV rules with

an eye to enabling broad disposal of captured C02 into such operations.

This may be accomplished by withdrawing/editing the 2016 Form which

implied only section UU was acceptable for fulfilling these obligations,

embracing the new ISO standards as the basis for compliance or such other

solution as would allow oil companies to consider taking captured C02 into

their EOR operations.

2. Perhaps most important, Congress should revise the January 2, 2024 start

date for qualifying facilities to a much later time – 2035 would be best and

certainly no earlier than 2030.

3. Congress should also consider boosting the size of the 45Q tax credits

for the first several CCUS projects and then have the $/t credit decline for

subsequent facilities. The aim here is to incentivize early risk-taking, much

as feed-in tariffs did for wind/solar projects. As project risks and cost decline,

the need for incentives can also be reduced and ultimately eliminated.

4. The oil/gas industry has a very large, if unquantified economic interest in the

successful deployment of CCUS. Increasingly governments and substantial

portions of their electorates are convinced a) that these industries need

to be curtailed or even phased out of existence and b) that punitive

regulations and taxes will be required to accomplish such ends. These

‘existential risks’ are not today being recognized in the industry’s approach

to project economics – hence the industry’s tepid approach to risk taking

on CCUS. The industry should recognize the need for CCUS technologies

to be proven at scale and support their progress through demo plants

to commercial projects. This can be done both by equity investments in

promising projects and by providing technical and operating support which

technology developers may lack.

41


5. ERCOT has a role to play in progressing CCUS. Since the Permian Basin is

the obvious location for FOAK CCUS projects, ERCOT needs to consider

steps which bolster wholesale electricity prices earned by these first

projects. Some form of ‘low carbon’ capacity factor should be introduced

into wholesale power pricing there, so that the nation’s best EOR location

is not negated as a C02 disposal site by also being one of the nation’s most

distressed electricity markets.

6. Finally, the oil/gas industry is going to need to work more closely with utilities

and industrial generators of C02 emissions. Utilities can advise on the best

plant locations for retrofit or new build investments, but will need help

building and operating the capture equipment and with moving/disposing

of the captured C02. Unless these two industries build a robust dialogue

around CCUS, it is difficult to foresee how a truly economic C02 value chain

can be constructed. Here the NPC can play a role by using the issuance of

its forthcoming report as the catalyst for convening an ongoing working

group among the two industries.


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APPENDIXENERGY SCHOLARS RESEARCH REPORTMODEL RESULTS AND SENSITIVITY CHARTS

Fuel Cell Retrofit Model

Appendix Exhibit 1: Fuel Cell Retrofit Project Economics

Appendix Exhibit 2: Fuel Cell Retrofit Plant Parameters

43


Appendix Exhibit 3: Fuel Cell Retrofit – Revenue and Expenses

Appendix Exhibit 4: Sensitivity Chart - Relative effect on Fuel Cell Retrofit NPV (ceteris

paribus)


44

Appendix Exhibit 5: Allam Cycle Project Economics

Appendix Exhibit 6: Allam Cycle Plant Parameters

45


Appendix Exhibit 7: Allam Cycle Revenue Stream Parameters

Appendix Exhibit 8: Allam Cycle New-Build – Revenue and Expenses

Appendix Exhibit 9: Sensitivity Chart - Relative effect on Allam Cycle NPV (ceteris paribus)


46

47



48

CONFERENCE PROGRAMKenan CenterKenan-Flagler Business SchoolFRIDAY, MARCH 29

7:30A.M. CONTINENTAL BREAKFAST

8:30A.M. Conference Opening Remarks Stephen Arbogast Douglas A. ShackelfordKenan-Flagler Business School

8:45A.M.

KEYNOTE ADDRESS: New Possibilities in CCUSA View from the National Petroleum Council

John Minge BP North America/National Petroleum Council

9:30A.M. The Need for CCUS within a Hybrid Approach to Grid De-Carbonization

Jarad DanielsUS Department of Energy

10:15A.M. BREAK

10:35A.M.

PANEL DISCUSSION: Historical Issues with CCUS: Existing Technology Economic, Environmental & Liability issues

Frank Morton Southern Company Scott Anderson Environmental Defense Fund Ron DeGregorio Exelon

49


11:30A.M. New Incentives for CCUS: 45Q Investment Tax Credit

Jonas Monast (MODERATOR)UNC Law Kyle Simpson Thompson Coburn LLC Jordan MintzKinder Morgan Inc.

12:15P.M. LUNCH

12:45P.M.

LUNCHEON ADDRESS: New form of Cost-Effective Power Generation from Natural Gas with Zero Emission

Damian Beauchamp 8Rivers/NETPower

1:30P.M. BREAK

2:00P.M. New Carbon Capture Technology for Retrofitting Natural Gas Power Plants

Tim BarckholtzExxonMobil

2:45P.M. Deploying New CCUS Technologies at a West Texas Plan - How Good Does it Look?

Anuj ChowdharyAditya KapoorTim SingerEnergy Center Scholars

3:15P.M. BREAK

3:30P.M.

Captured Carbon into Enhanced Oil Recovery; Potential use in Conventional & Unconventional Oil/Gas Production

Charlene Russell Occidental Petroleum James Glass Kinder Morgan Inc Wayne Rowe Schlumberger

4:15P.M. Carbon Capture into Alternative Dispositions: Alternative Routes, End Products & Comparative Economics

Thomas FoustNational Renewable Energy Lab

5:00P.M. CLOSING REMARKS: CCUS Prospects & Challenges

Sally Benson Stanford University

5:30P.M. ADJOURN & RECEPTION AT KENAN LOUNGE

SATURDAY, MARCH 30

8:30A.M. Utilities Looks at CCUS “First Plant” Projects w/New Technologies - Issues/Risks

9:00A.M.

ROUNDTABLE DISCUSSION: CCUS Commercialization Projects – Demo plant plans & results; How much improvement w/Experience? Retrofit vs. Newbuild for 1st @ Scale Project Risk sharing among utilities & Oil/Gas Disposition Options Outside of W. Texas EOR

10:00A.M. BREAK

10:15A.M. PANEL DISCUSSION: Regulatory & Environmental Issues around utilizing 45Q ITC MRV Issues

11:15A.M. State Regulatory Support for CCUS

11:45A.M. Summary Comments

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