- Clear your browser's cache - Guide to clearing browser cache
- Close and re-open your browser
- If the above two steps do not help, please try another browser. Internet Explorer or Microsoft Edge have the highest level of compatibility with our player.
Witness Panel 1
The Honorable David GarmanUndersecretary of EnergyU.S. Department of Energy
Testimony of David K. Garman
U.S. Department of Energy
Committee on Energy and Natural Resources
United States Senate
May 1, 2006
Thank you for this opportunity to testify before the Committee on the subject of industrial scale gasification in the context of implementation of the Energy Policy Act of 2005.
Gasification technology is poised to make a revolutionary impact in the U.S. and global marketplace, so this is an extremely timely topic for the Committee’s consideration. Simple combustion technologies have served us well since early humans first employed fire for warmth, light, and cooking. But it is appropriate that we in the 21st century transition toward large industrial and utility-scale gasification in the quest for greater efficiency and the cleaner use of combustible energy resources, particularly in light of the abundant supplies of coal and renewable biomass we have available.
The Department of Energy and industry have been investing in gasification systems research for decades. Very early in our work, we realized that commercially mature gasification-based power systems could nearly double the efficiency of the current combustion-based fleet. The average efficiency of today’s combustion-based coal power plant fleet is 32 percent and state-of-the-art coal-fired power plants operate at about 38 percent efficiency. We believe commercially mature gasification-based power plants can achieve efficiencies in the 55 to 60 percent range. To the extent that any of the remaining waste heat can be channeled into process steam or heat, perhaps for nearby factories or district heating plants, the overall fuel use efficiency of future gasification plants could reach as high as 70 to 80 percent.
However, the potential efficiency gains only tell part of the story. Today, new gasification applications have emerged that were not even imagined at the start of our research efforts.
For example, near-zero atmospheric emission systems, emitting minimal pollutants and carbon dioxide, are within our technical reach. In addition, gasification-based systems can be configured to produce clean hydrogen or liquid fuels, or a variety of petrochemicals, synthetic natural gas, or any combination of these products and electricity. Gasification-based systems are also projected as having the potential to produce these products at reasonable cost while using some of our most abundant domestic fuel resources—coal and biomass.
This simple diagram describes gasification-based system concepts. A variety of feedstocks, including coal, biomass, petroleum coke and residuals, or even waste can be gasified into a synthesis gas (or syngas) comprised mainly of carbon monoxide and hydrogen. From there a variety of pathways leading to a number of products are possible. But whether you are generating liquid fuels, electricity via combustion turbines, electricity via steam turbines,
electricity via fuel cells, or hydrocarbon based products, gasification is the common technology at the heart of the process.
Of course, the prototype for the ultimate gasification based system, FutureGen, is now under way led by a Government/Industry Consortium that is dedicated and committed to its success. Other governments and international companies have expressed strong interest in joining the FutureGen effort (and some have already joined), which will pave the way for the global deployment of gasification based zero emission systems.
In the State of the Union address, President Bush announced the Advanced Energy Initiative. The initiative’s technology focus includes both power and transportation technologies, and it is important to stress that gasification has important contributions to make in each of these areas. For example, just as gasification can dramatically increase the efficiency and lower the environmental impact of power production as mentioned earlier, it can also be a pathway to the production of clean diesel, ethanol, synthetic crude, and other fuels and help reduce our dependence on foreign sources of energy—one of the key goals of the Advanced Energy Initiative.
The challenge that confronts the broader introduction of gasification-based systems is the same challenge that confronts many energy systems—the up-front capital costs are substantial. Lenders lack experience with these projects, so they are less willing to assume the extra risks involved in early generation commercial deployments of gasification technologies. In addition, combustion-based systems have been the beneficiary of centuries of incremental improvement and cost reduction, so they understandably enjoy some “first cost” advantages. We have every reason to expect that the costs of gasification-based technologies will decline as experience with the technology increases—the 10th plant will be more affordable and reliable than the first. We are also encouraged by the fact that manufacturers are beginning to offer performance warrantees, management and operating contracts, fixed-price construction contracts, and other instruments to diminish risk.
Gasification technologies offer benefits such as lower emissions and greater efficiencies. The widespread deployment of utility and industrial gasifiers may provide an economic alternative to natural gas for consumers who are able to switch to syngas, thereby increasing availability of natural gas for other residential, industrial, and commercial consumers who find it more challenging to change fuel or feedstock.
The industrial sector is the largest consumer of natural gas in the United States, accounting for a third of U.S. consumption. Bulk chemicals and petrochemical refining are the largest consumers of natural gas by volume, and natural gas is also a significant cost component of many other industrial sectors. Natural gas is used in the industrial sector as a feedstock in the production of chemicals, fertilizers, and refined petroleum products, and in the production of process heat. Among the industries that rely heavily on natural gas for process heat are paper and other forest products; food and beverage; primary metals, including steel, aluminum, and metal castings; and glass and other non-metallic production industries. All of these commodity industries are characterized by globally competitive markets with low margins. Thus for some plants, rising natural gas prices have increased the cost of domestic operations.
Much of industry is looking to gasification as an important element in reducing the impact of rising natural gas prices on their production costs. They believe that gasification of the Nation’s abundant domestic energy feedstocks can play a significant role in creating a more affordable substitute for natural gas. Gasification of coal, petroleum coke, black liquor, and biomass can be used to create a synthetic gas suitable for providing either process heat or as a feedstock source for chemicals and fertilizers.
As mentioned earlier, gasification can be linked with other processes to produce liquid fuels. Liquid fuels used in transportation comprise about 27 percent of total U.S. energy use. Some industrial interests are looking at liquid fuels based on gasification as a source of energy. Co-production of some mix of power, chemicals, fertilizer, synthetic gas, process heat and steam, and liquid fuels may yield resilient business opportunities and greater energy security.
The ongoing gasification RD&D program and complementary programs now underway across the Department of Energy have the potential to accelerate commercial use of gasification technologies in the industrial marketplace, providing a substitute syngas suitable for relieving pressure on both fuel and feedstock availability and cost. These programs are actively pursuing advancements in membranes for more efficient separation of gas mixtures, catalysts for conversion of syngas into substitute natural gas, and fuel gases for combined cycle power production. At the same time, we support R&D underway in the hydrogen fuel initiative, which is looking at technologies for the production of hydrogen. The gasification program also is coordinated with major efforts now underway to address the issues of carbon management. It is the goal of the long term program to develop essentially emission free processes for the production of power, industrial feedstocks, and substitute fuels.
We are fulfilling our responsibilities with respect to EPAct 2005 tax credits that provide incentives to help bring these technologies into early commercial use and, eventually, widespread adoption across the American economy if they prove economic. In this regard, working with industry, the Department of Defense, and the Environmental Protection Agency, we are studying the business risks associated with industrial gasification and are performing financial modeling to understand the impact of EPAct 2005 incentives on early commercial plants.
.Let me turn now to the topic of loan guarantees. Loan guarantees are only one part of a toolkit—one best used after the technology development cycle is complete. The toolkit established in EPAct 2005 contains several tools, including authorization of R&D for developing technologies, tax credits to reduce the cost of plants that utilize them or improve cash flows, and loan guarantees.
We are confident in the underlying technology behind gasification plants. Indeed, some gasification plants in certain applications have worked well for years. But early gasification plants face “first mover” issues such as permitting delays, longer shakedown periods, and higher costs since learning curves in fabrication, construction, and operations have not yet taken hold. Therefore, the business risks of the first plants remain greater than combustion plants.
Therefore, consistent with the new authorities provided us in the Energy Policy Act of 2005, we are establishing a loan guarantee program within DOE. We are mindful that the Department does not have an enviable record of accomplishment with loan guarantees issued in the past, but we will follow the Federal Credit Reform Act of 1990 (FCRA) and Office of Management and Budget (OMB) guidelines issued since our last experience with loan guarantees, and we will emulate the best practices of other federal agencies. We will move prudently to ensure that program objectives are achieved while meeting our responsibilities to the taxpayer. Toward that end:
• We have established a small loan guarantee office under the Department’s Chief Financial Officer.
• We have detailed staff from other programs and may soon be detailing staff from other agencies with some of the necessary experience in Federal loan guarantee programs.
• We are drafting program policies and procedures.
• We are establishing a credit review board.
• We will employ top outside experts for financial evaluation, construction engineering evaluation, and credit market analysis to assist us in our evaluations of applicants.
We are proceeding, but we are doing so with no small measure of caution and prudence. While the provisions of the Energy Policy Act provide a “self pay” mechanism that, in theory, reduces the need for appropriations, it does not eliminate the taxpayer’s exposure to the possible default of the total loan amount.
It is possible that the ultimate cost to the taxpayer could be significantly higher than the cost of the subsidy cost estimate. Therefore, DOE’s evaluations of loan guarantee applications will entail rigorous analysis and careful negotiation of terms and conditions.
It is also our view that the Federal Credit Reform Act of 1990 contains a requirement that prevents us from issuing a loan guarantee until we have an authorization, such as a loan volume limitation, to do so in an appropriations bill. We do not believe we have the authority to proceed with an award absent having explicit necessary authorizations in an appropriations bill.
Again, I thank you for this opportunity to appear today, and I welcome your questions either today or in the future.
Witness Panel 2
Mr. Brian FergusonChief Executive OfficerEastman Chemical Company
Testimony Submitted to
U. S. Senate Committee on Senate Energy & Natural Resources
May 1, 2006
ENERGY POLICY ACT OF 2005
Written Statement by
Brian Ferguson, Chairman and Chief Executive Officer
Eastman Chemical Company
P.O. Box 431
Kingsport, TN 37662
Mr. Chairman, members of the Committee, I am Brian Ferguson, CEO and Chairman of Eastman Chemical Company, headquartered in Kingsport, Tennessee. I want to thank you for the invitation to come before you today and give you my perspective on the Energy Policy Act of 2005. And I appreciate the opportunity to discuss with you our concerns with certain provisions of the Act, particularly those around the Section 48B Federal Industrial Gasification Investment Tax Credits in Title 13 and the self-pay Federal Loan Guarantees for industrial gasification projects under Title 17.
Introduction to Eastman
The corporation I represent is Eastman Chemical Company. Eastman manufactures and markets chemicals, fibers and plastics worldwide. It provides key differentiated coatings, adhesives and specialty plastics products; is the world’s largest producer of PET polymers for packaging; and is a major supplier of cellulose acetate fibers. Founded in 1920 and headquartered in Kingsport, Tenn., Eastman is a FORTUNE 500 company with 2005 sales of $7 billion and approximately 12,000 employees. For more information about Eastman and its products, visit www.eastman.com
Eastman is not unlike many chemical companies in the United States today. That is to say that we are all under extreme pressure from rising costs of energy and raw materials. My industry has experienced a cumulative $60 billion – that's billion with a 'B' – a $60 billion increase in our natural gas bill since the beginning of the decade.
What's the result? Let me give you a quick example.
One report in Business Week noted that there were 120 global chemical sites valued at more than $1 billion currently under construction in the world. Of those, only one was located in the United States. The remaining plants – offering high wages and stable employment – are being constructed in places where energy and raw materials not only cost less, but their availability and prices are more stable, too.
Dow Chemical Company, for example, is currently building a $4 billion plant in Oman. This plant was originally going to be built in Freeport, Texas. But the high cost of natural gas in this country – which was 12 times higher in Texas than on the Arabian Peninsula – forced Dow to site it in the Middle East instead.
With that decision, America has lost a new plant that will employ 1,000 people in high-paying science, engineering and operations jobs – and we have taken on more step toward creating for our chemicals industry the same kind of dependence that we face with imported oil. One thousand employees who could have been U.S. employees and billions of dollars that could be flowing into – rather than from the U.S. economy – if we had an energy policy that worked to help – not punish – industrial manufacturers like Dow.
Dow isn't alone, of course. Every industrial company is facing the same dilemma. Build in the U.S. or build overseas. Invest where the energy prices are a liability – or go where they are an asset.
That's why I was so pleased when I saw that Congress finally created within the Energy Policy Act of 2005 the incentives that would help correct 20 years of short-sighted energy regulations and finally begin to move us away from a costly and wasteful dependence on natural gas for electricity generation.
Importance of Gasification
Wide spread deployment of sound, proven gasification technology is an important tool that can help keep currently-natural-gas-dependent globally competitive American industries in America. Gasification provides the opportunity for American industry to use a wide array of feedstocks such as coal, petcoke, biomass and even many industrial waste materials in lieu of expensive natural gas. On the market side, creation of synthesis gas permits a very broad suite of products and uses. So, gasification technologies offer important flexibility to industry.
• Feedstock Diversity - Reduced cost and greater flexibility of feedstock input. Industrial manufacturers operate in a globally competitive market where their price of natural gas makes a huge difference in final product prices. Unlike the electric utility industry, for example, production costs largely determine where our goods are manufactured.
• Jobs - Preservation of U.S. jobs, especially high-paying ones in the chemical industry which has already lost more than 100 plants and 100,000 jobs between 1999 and 2005. But notably, other natural gas dependent sectors have also suffered dramatically, i.e., agriculture, paper, metals, iron and steel. See Attachment 3.
• Avoids Mid-East Energy Dependency - Maintains U.S. economic strength and avoids “oil style” dependence on Middle East - truly a slippery slope.
• Environment - Even using fossil fuels, emissions of SO2 and NOx from gasification processes are similar to sources using natural gas. Also, gasification can capture mercury and CO2 for safe disposal-sequestration, etc.
• Trade balance – The U.S. has lost $484 billion in domestic industrial production between 1999 and 2005, further exacerbating our Nation’s huge trade deficit in manufactured goods. As capital costs decline with broad deployment of gasification technology, new plants will produce synthesis gas that permits domestic production to be competitive with foreign plants.
• All Natural Gas Consumers – With industrial gasification, natural gas prices for all domestic consumers (48A program also contributes to this benefit) will fall. Facilities operational under 48B tax credits will reduce costs to all American natural gas consumers over the long term and pay for themselves in about six months. This is a conservative estimate which assumes only the output of the plants receiving the credit and does not reflect the subsequent stimulation of additional, cheaper gasification plants which will reduce natural gas demand and prices further.
Need for Timely Action
There is suddenly a lot of hype regarding gasification technologies. Not a week goes by that I don’t read or hear some story in the news about a new gasification technology that will be the panacea for the Nation’s energy ills. Development of new technology is important –important in the next decade or the one after that. For gasification to make a difference to American industry now, when industry needs it most, we must deploy sound, proven, currently available technology.
For both the Section 48B Investment Tax Credits and Federal Loan Guarantees to be effective in my industry – if they're to change the course of investment in energy and feedstock technology investments in this country – they need to support commercial scale projects that address global market risks, now. I want to emphasize that point. Industry needs deployment of proven, commercial scale gasification technology now, not just more research and more demonstration projects that may, or may not be adopted by industry ten or fifteen years from now. While there is a need for future demonstration projects to validate key technologies, the real difference for America now is to assure that these incentives support investment in commercial scale industrial gasification projects that are calculated to meet global competition so that these industries will still be contributing mightily to the American economy when those new technologies become available.
America will need technology improvements in the future if we are to remain competitive in the global industrial marketplace, but only if we take the necessary steps now to ensure that the U.S. still has an industrial base in the next decade. That may sound like hyperbole until one considers the more than 2 million American manufacturing job losses overall since 1999, and particularly in the natural gas dependent industries - in chemicals, forest products, glass, steel, and even agriculture.
Need to Maintain the Original Focus
The Section 48B tax credits were added to HR 6 specifically for the gasification of coal, biomass, petcoke and waste materials to serve the fuel and/or feedstock requirements of certain globally competitive industries that were facing economic distress due to rapidly rising natural gas prices in the U.S. The focus for these incentives needs to continue to be squarely aimed at domestic industries that are suffering under the burden of high natural gas prices, as identified in the new law. We anticipate that the availability of these incentives will attract a number of project developers who will try to claim qualification even though they are not in the intended group of recipients.
It is important that the focus of the incentives remain on the group of eligible entities that were listed in Section 48B of the Energy Policy Act. Now is not the time to dilute the impact of the incentives by spreading the relatively moderate amount of incentives across too many projects or to unintended projects. The selected projects should be adequately funded, should be focused on directly helping the intended industries, and should be ones deemed most likely to succeed in the near term.
Hard Work Ahead
The subject of today’s hearing: the passage of legislation (PL 109-58) was only the first of many steps needed to realize the potential of gasification technologies.
The hard work has just begun for both industry and government.
The second step – the step that is in play right now – is the drafting of regulations to implement the authorities conveyed to the Administration by the energy bill.
I have serious concerns about the implementation of the Investment Tax Credit and the self-pay Federal Loan Guarantee programs.
Congress passed Public Law 109-58 more than nine months ago (July 29, 2005); yet, to date, there has been no formal dialogue between the private sector and the Department of Energy (or other federal agencies) regarding implementation of the loan guarantee provisions of Title 17. Of greater and more immediate concern is that the regulations published this February regarding the 48B industrial gasification tax credits need major revision if the credits are to be awarded effectively, fairly and for sound projects, as I believe Congress intended.
The Section 48B tax credits were originally added to HR 6 as a Senate Finance Committee amendment totaling $850 million. As mentioned above, these funds were provided specifically for the gasification of coal, biomass, petcoke and waste materials to serve the fuel and/or feedstock requirements of certain globally-competitive industries that were facing economic distress due to rapidly rising natural gas prices in the U.S.
Even at the $850 million amount, it was generally assumed that there would be many more applicants for the tax credit than available funds. Given the cost premium for the first generation of gasification projects to be built, parceling out the limited funding to all qualified applicants on a pro rata basis was recognized as potentially spreading the money too thinly to advance any projects. Consequently, industry proposed that DOE and Treasury jointly solicit tax credit applications on a single date after which DOE would evaluate and rank the projects according to technical and economic merits for Treasury’s subsequent award of the credits on a “competitive” basis.
When funding for Section 48B was cut to $350 million in Conference, the need for a strong DOE role to assess and rank applicants by merit became even more apparent to industry.
The competitive award of the 48B tax credits is a novel way for Congress to target limited financial resources to the most meritorious applicants within a class. Such an approach might not be appropriate for many types of tax credits; but I believe it clearly is when the intent of Congress is to stimulate investment in technology to achieve broad public benefits with limited funds.
Fortunately, even though there was no direct legislative requirement to do so, Treasury and the DOE did agree to establish a “competitive process” for accepting, evaluating and awarding certificates of eligibility for the limited pool of 48B industrial tax credits.
Both departments should be commended for the novel mechanism that has been crafted to promote the most effective use of taxpayer resources to spur the early introduction of gasification technology leading to the many benefits identified at the beginning of this testimony. But more can and must be done by both departments to ensure that fairness, process transparency, merit and technical readiness for deployment are the final determinants in the awards that are made later this fall.
Government sources anticipate perhaps six or seven times [Note: if recent estimates of 48 projects are correct, that would be sixteen times] the number of project applications that can be supported by the $350 million available. And, each industrial applicant will spend, on average, more than $1 million developing their application. In such a competitive and expensive situation where industry is preparing to commit very large financial resources to build these gasification projects (greater than $1billion in many cases), fairness, transparency and judgment on project merits seem like a small request. And, it is just “good government.”
Detailed Concerns and Recommendations
Eastman Chemical Company joined with numerous other companies and trade associations (also known as the Industrial Gasification Initiative) to present unified recommendations to both departments related to the process for awarding the 48B investment tax credits. Subsequently, the Department of the Treasury published guidelines in the Federal Register on February 21st for the joint conduct of the 48B Industrial Gasification Program with DOE. Certainly the intent of IRS and DOE to work together to award the tax credits on a competitive basis is a good first step. However, the process described in the February announcement ignored many constructive suggestions proposed by the Industrial Gasification Initiative.
Specifically, the 48B process designed by Treasury will not utilize DOE’s capability to evaluate, compare and rank multiple large projects applications, such as it does in the Clean Coal program. Instead, Treasury has asked DOE to simply determine whether a project meets a “pass – fail” standard in several categories. Obviously, an evaluation process of this nature does not separate the simply good projects from the superior ones.
Did Congress intend that the industrial gasification investment tax credits potentially be awarded to “B” grade projects over “A+” projects? I hope not.
There is still time to fix this problem if key Members of Congress move quickly to do so. The Committee has jurisdiction over DOE; but of course Treasury, and specifically IRS, has the lead in determining the process for awarding the 48B industrial gasification tax credits. I urge the Senate Energy and Natural Resources Committee to collaborate with the Senate Finance Committee to ensure that the Industrial Gasification Initiative’s recommendation for a transparent and competitive process for industrial gasification tax credit awards based on merit is achieved.
Members of the Industrial Gasification Initiative would be pleased to work with the Congress and the agencies on these improvements.
The Initiative members have many additional concerns about the criteria that may, or may not, be used by the DOE and IRS to evaluate projects. Mr. Chairman, you were one of the first Senators to recognize the need for legislation addressing the adverse impacts of rising natural gas prices on domestic manufacturing industries’ ability to compete in world markets, in fact on their very ability to continue operations in the U.S.
The Section 48B Industrial Gasification Investment Tax Credits were born of that very concern. Congress intended for the credits to stimulate investment in gasification plants that can use a wide variety of fuels to displace natural gas as a fuel and/or feedstock. The credits are intended to assist early adopters of gasification technologies to “buy down” the high price of these first plants to be deployed.
This approach is quite different than DOE’s usual mission of developing and demonstrating new technologies. Yet, there appear to be suggestions in the February IRS guidelines that novel technologies, not proven technologies, will be favored in the selection of projects. This “research” bias is reflected in two of the three Program Policy Factors listed in Appendix B, section “F” of the February Notice: 1) “Diversity of technology approaches and methods, and 2) Geographic distribution of potential markets. These factors would be suitable for a technology demonstration program such as Clean Coal, but they are wholly inappropriate for the purposes of Section 48B - - - to deploy technically sound synthesis gas plants that can begin to reduce natural gas demand in globally competitive domestic industries, to reduce the cost penalty associated with those plants, to offer hope for saving U.S. industrial jobs, and to do so in an environmentally sound manner.
So, the Industrial Gasification Initiative members ask the Committee to ensure that the 48B program is not hijacked to become just another extension of existing federal RD&D programs.
Beyond these points, the Industrial Gasification Initiative is concerned by the process for obtaining clarification on many technical issues raised by the February Federal Register notice (IRS Notice 25-2006). The Initiative submitted ten questions to the DOE more than one month ago. The DOE responses are underlined. Additionally, questions that appear in italics were also submitted to the IRS at that time. To date, no response has been received from the Service.
The Initiative’s questions and answers received to date follow as Attachment 1 at the end of my testimony.
I call your attention to submitted question #4b and the “non-answer” as an illustration of the confusion that still exists less than 60 days before applications are due. Although obviously a technical question, DOE deferred it to the IRS, which has provided no timetable of their response – nor is IRS likely to possess the technical background to appreciate the basis for this question. If this language were to remain, and depending on its interpretation, potentially, no project would qualify. All projects need start-up fuels, chiefly natural gas, in the testing and ramp-up period. These start-up fuels will be used in far less quantities during normal operations. As soon as a project uses the first molecule of natural gas for start-up, it fails this criterion based on current language. While this outcome might seem like a ridiculous scenario, unanswered, the question raises considerable doubts about how the notice will be applied. There needs to be an allowable and adequate start-up period before which such language is applied, or else there needs to be a more distinct boundary regarding its application to only the production of syngas from the gasification block (which is the primary boundary of the eligible property definition for application of the tax credit). Companies that are spending considerable time and money to develop applications and, more importantly, to develop projects that are essential to our nation’s energy objectives, deserve a straight answer, especially to questions as purely technical as #4b.
Another basis for concern is the non-response to question #5c and the second part of question #5b. This process-type question was again deferred to the IRS. Eastman and most of the companies that may apply for the ITC are public companies with extremely sensitive disclosure requirements. We need to know the process of public announcements in enough time so that we can be prepared with our concurrent public disclosure. This is a process question, not a policy question, so again it should be fairly straightforward to address.
Both of these questions were raised according to the DOE procedure on March 25th. DOE indicated a response time of about five business days. It is now May 1, the closing date for questions. Any applicant that has follow up questions regarding any response, or non-response, to previous questions will not be allowed to seek further clarification after today.
Let me close by encouraging you to maintain the integrity of this process. It is crucial, not only for those beneficiaries who have projects in the pipeline, but crucial for the country as well.
If the desire of this Congress continues to be one of providing help to the job-producing portion of the American economy – to keep jobs here in the U.S. – it is critical that you protect the funding for those sectors where it can do the most good: commercial, industrial projects.
That's where American jobs are on the line and that's where the real power of the country's economic engine lies.
For convenience, I have included a summary of the Industrial Gasification Initiative’s recommendations under Attachment 2 of my testimony.
Again, I thank you for the opportunity to share our concerns. And I thank you for the leadership you've already demonstrated on this important topic.
Mr. Bill DouglasVice PresidentEcono-Power International Corp.
Testimony of William C. Douglas
Senior Vice President Business Development
Econo-Power International Corporation
1502 Augusta Drive, Suite 100
Houston, TX 77057
Submitted to the
SENATE COMMITTEE ON ENERGY AND NATURAL RESOURCES
Hearing on May 1, 2006
Good morning, Mr. Chairman and members of the Committee. My name is Bill
Douglas. I am the Senior Vice President for Business Development for Econo-
Power International Corporation or EPIC. We also have Mr. John Keller, Vice-
President and Chief Financial Officer. We appreciate the opportunity to testify
We are pleased to be here today to share with you our views about the benefits
that Industrial Coal Gasification Systems technology can deliver. ICGS can
produce a synthetic fuel gas at prices below that of Natural Gas by converting
solid fuels, such as coal, which are abundant and economically available in the
US. If ICGS can achieve wide spread adoption in the industrial sector, it will help
the country displace usage of scarce natural gas, put additional US workers to
work mining, transporting and converting coal. Use of economical synthetic fuel
gas will assist industry in meeting environmental goals of reducing NOx, mercury
and other air pollutants, while also advancing sound energy policy goals of
retaining a secure and diverse mix of fuels for industrial process and electric
EPIC, The Clean Coal Gasification Company™, builds, owns and operates
industrial coal gasification systems to convert coal to a clean alternative to
natural gas. The use of domestic coal offers a stable-priced, clean alternative to
volatile-pricing for domestic and imported natural gas and LNG.
EFFECT OF EPACT 2005 ON INDUSTRIALS IN THE US
EPACT 2005 is a major step in providing incentives to bring clean coal initiatives
to the very large industrials and Utility companies. It has a very select impact on
the small to medium size industrial that is evaluating alternative energy such as
Coal Gasification. The major credit available is the ITC. However, these credits
are restricted to certain industries and/or require that the fuel be used for a
specific purpose such as the production of electricity. This eliminates a large
proportion of the US industrial base as potential users of synthetic fuel gas. The
small and medium sized industrials are the companies having the greatest
difficulty in dealing with the high price of natural gas and electricity used in their
facilities. They are rapidly becoming non-competitive with other nations because
of high energy costs. These same companies are also reluctant to change
energy sources from the tried and true natural gas and electricity infrastructure.
For them, a commitment to change to a coal-based syngas will require some
financial incentive. The most effective way to induce a company to change to
Coal Gasification is through economic incentives. The way to provide these
incentives is to modify EPACT to include the smaller industrials with incentives to
use alternative energy sources such as Coal Gasification.
OVERVIEW OF ICGS TECHNOLOGY
ICGS is a process that converts low value fuels such as coal, biomass, and
municipal wastes into a high value, low Btu, environmentally friendly natural gastype
fuel, also called “synthesis gas” or simply “syngas”. ICGS uses air-blown,
modular gasifiers to accomplish the conversion.
Coal gasification has undergone many evolutions and improvements. The EPIC
system of gasification and sulfur removal is an updated version of a time tested
method to convert coal to a low Btu fuel gas. The EPIC system is covered by US
patents (pending) and is manufactured in the US. There are dozens of similar
systems in operation for many years in other parts of the word that provide fuel
gas for varied industrial processes. The potential US industrial users need some
incentive to allow them to accept the system in the US.
Industrial uses include virtually any natural gas fueled industrial process such as
boilers, kilns, process furnaces, etc. The ICGS can also refuel older coal fired
plants for environmental compliance without adding pollution control systems.
EPIC has also worked with major gas turbine suppliers to gain acceptance of the
fuel gas produced in EPIC’s system. This acceptance opens the Integrated
Gasification Combined Cycle (IGCC) area for even small and medium sized
ENVIRONMENTAL ADVANTAGES OF ICGS
ICGS provides some significant environmental advantages. When ICGS is used
to replace direct coal combustion in boilers or kilns, the following benefits are
• Elimination of particulate emissions.
• Reduction of SOx emissions by at least 100 times over unscrubbed coal.
• Reduction of NOx emissions by 90% or more.
• Removal of mercury at greater than 90%.
When ICGS is used to replace natural gas, NOx reductions of at least 50% are
It is important to note that only minimal modifications are required to boilers, kilns
or process furnaces to use ICGS. For most industrial boiler, kiln or furnace
systems, major capital expenditures would be required to achieve compliance
with even current environmental regulations. ICGS allows US industrial
companies to employ capital to improve process efficiency without having to
dilute it for investing non-productive pollution control systems.
In the ICGS process, harmful pollutants are removed from the syngas stream
before combustion, rather than in post combustion flue gas treatment. The
pressurized syngas stream represents less than 1/100 of the volume of the flue
gas from direct coal combustion and the contaminants in syngas are
concentrated. Therefore, IFGS pre-combustion clean-up is far more effective
and much lower cost than the post-combustion clean-up employed in direct
combustion coal steam-boiler plants.
In ICGS, coal ash is converted in the gasifier into a solid, which is similar to
conventional coal fired ash which can be employed in the construction industry
as road fill or as strengthening aggregate for building concrete. ICGS does not
require secure landfill sites for ash storage.
The sulfur is removed from the gas before combustion and is recovered in
elemental, non-hazardous form. This sulfur may have economic in certain
industrial processes and agriculture. Even if sulfur disposal is required, nonhazardous
disposal is easily accomplished.
ICGS SHOULD BE VIEWED AS A FUEL SWITCH AND NOT A NEW SOURCE
In the case of retrofit for industrial boilers, kilns, furnaces, etc, the facility is
normally permitted to operate on its present fuel. In general, the facility will
continue to operate at the same production level (at a minimum) as with the
ICGS should be viewed as merely a fuel change and not a major modification
triggering NSPS standards. Expedited permitting would also help the industrial
user to keep competitive advantages while maintaining domestic fuel sources.
Consideration of ICGS’s environmental benefits should lead to placing ICGS as
PACT (Preferred Available Control Technology) for industrial energy users.
PACT designation would allow industrial customers to more rapidly achieve
energy cost stability and remove this aspect of the perceived permitting risk when
The EPIC ICGS is inherently “modular” and is easily applicable to most industrial
processes. The number of gasification modules is determined to closely match
the fuel gas needs for each individual user. There is no “one size must fit all”
requirement, as is the case with larger oxygen-blown systems being offered for
large IGCC plants.
Gasification is a steady state chemical process and steady state industrial
processes are the best candidates for its use. With modular ICGS, should the
user’s fuel gas needs expand, the ICGS is normally easily expandable to match
the expanded needs.
Another industrial strategy could be to co-fire ICGS gas with natural gas to obtain
partial benefits. The ICGS system can be expanded in the future for increased
coal gas use. This strategy could allow the user to more rapidly obtain some
ICGS benefits while a larger system is being constructed.
EPIC is working to improve the process and overall efficiency, thereby offering
the user increased benefits from ICGS use.
The nature of ICGS requires a significant capital commitment to build the system.
Past and present incentives have only been available to the gas supplier/coal
converter. ICGS is nominally quite competitive to natural gas. However, the
requirement to commit to a long-term contract for the ICGS system complicates
the decision. If tax incentives for ICGS were available to the user in the form of
credits for Btu’s of syngas used, the economic benefits would be more obvious
and promote more rapid ICGS implementation.
For users that are able to directly combust coal, tax incentives for ICGS use
would expedite the “fuel switch” and offer more rapid environmental clean-up of
these polluting systems while minimizing the economic impact of the additional
“conversion” cost of the coal to ICGS fuel gas.
For the system provider of the ICGS, capital cost is a major issue. Investment
tax credits would help to minimize the “conversion cost”, to the fuel gas user and
therefore, facilitate the acceptance by the financial communities for conventional
VALUE TO INDUSTRY AND THE COUNTRY
?? Reduce industrial dependence on natural gas or foreign LNG.
?? Use the 225 year supply of US coal resources for a broad base of
?? Help US industrial producers keep competitive with foreign competitors
with cheaper synthetic fuel gas.
?? Reduce industrial emissions.
?? Allow industrial producers to stabilize energy prices over the long term
without the high volatility of natural gas prices.
?? Keep and create new US jobs.
NEEDED TO ACCOMPLISH BROAD ICGS IMPLEMENTATION
?? Broaden the base of industries and applications in which EPACT 2005
and other legislation encourage the use of gasification technologies by
removing restrictions as to the types of industry and ends use of the
?? Incent the ultimate gas user by providing incentives based on the amount
of energy in Btu’s obtained from coal gasification
?? Adopt ICGS as Preferred Allowable Control Technology (PACT) to allow
environmental regulators to more easily issue permits for fuel switching
rather than the full new source reviews that could be required without
?? ICGS can benefit a broad spectrum of US industries.
?? ICGS can significantly reduce industrial pollution
?? Additional broad based tax incentives available to the fuel user would
expedite implementation of ICGS.
?? ICGS can be a viable means of reducing US dependence on imported
energy (oil and natural gas/LNG).
Thank you for the opportunity to testify before your committee and we would be
happy to provide additional information if required.
Mr. Bill BoycottGeneral ManagerAgrium U.S.A., Inc.
AGRIUM BLUE SKY PROJECT
United States Senate
Committee on Energy and Natural Resources
Industrial Gasification Provisions of the Energy Policy Act of 2005
William A. Boycott
Kenai Nitrogen Operations
Agrium U.S. Inc.
May 1, 2006
Good afternoon Mr. Chairman, Members of the Committee. Thank you for the opportunity to appear before the committee to discuss the Energy Policy Act of 2005 and its applications to industrial coal gasification. My name is Bill Boycott. I am the General Manager of the Agrium U.S., Inc. Kenai Nitrogen Operations (KNO). I am here to address how provisions of the Energy Policy Act of 2005 (EPAct 05) could potentially benefit Agrium’s Blue Sky coal gasification project.
KNO is a manufacturing facility located in Kenai, Alaska, that relies upon natural gas as a feedstock to produce ammonia and urea fertilizers. Like many U.S. fertilizer manufacturers, we are unable to assure ourselves of a reliable, long term, reasonably priced supply of natural gas the primary feedstock required for fertilizer production. As a result, KNO actively is evaluating the feasibility of constructing a coal gasification facility to produce the necessary hydrogen and carbon dioxide feedstocks for fertilizer production. As part of our feasibility evaluation, we have analyzed all of the provisions of the Energy Policy Act of 2005 that potentially could facilitate investment in and development of the Blue Sky coal gasification project. We have determined that two particular provisions – the Internal Revenue Code §48B industrial gasification tax credit and the Title XVII loan guarantee authority – could be of significant value to the project, depending on how they are implemented.
Agrium is a leading global producer and marketer of agricultural nutrients. Our wholesale division manufactures, markets and distributes over 8 million tons of nitrogen, potash and phosphate fertilizers each year from 12 production facilities in the United States, Canada and Argentina. Agrium is also one of the largest agricultural retailers with more than 500 retail centers in 31 States and more than 30 stores in South America. These facilities are staffed by more than 8,000 employees worldwide.
KENAI NITROGEN OPERATIONS
Agrium acquired the Kenai facility from Unocal Agricultural Division in 2000. The facility was constructed in 1968 and expanded in 1977. It is the second largest nitrogen complex in North America with the capacity to produce in excess of 2.0 million tons of fertilizer per year when operating at full capacity. KNO is one of the largest manufacturers in Alaska, employing 230 employees when operating at full capacity. It is one of Alaska’s few value added industries – for every one thousand cubic feet of natural gas used, more than $9 in total economic output is generated.
COOK INLET NATURAL GAS SUPPLY & DEMAND
The Cook Inlet region of Alaska has a variety of established industries that were built around an abundance of low cost natural gas. The local natural gas supply is finite. The once large reservoirs of natural gas have been depleted, the historic pricing structure has not promoted exploration for new reserves, and demand, principally for electric power generation and commercial and residential uses, has grown significantly. Gas dependent industries have ceased operations and the cost of natural gas to electric utilities and their customers, as well as end-users of the fuel, has risen dramatically. This combination of factors has created a situation in which we are unable to contract for a long-term reliable supply of natural gas.
KNO has been confronted with ever deepening supply shortages since 2002 and acquiring and maintaining a steady supply of natural gas has been a challenge. Because of these shortages, long-term natural gas contracts are not possible and we now operate on year-to-year gas contracts. Under these short-term arrangements we have been unable to acquire sufficient natural gas to meet our needs and, as a result, reduced our operations to 50% in 2005. This resulted in a reduction of 85 of our 230 full-time employees. This January, during a cold spell that significantly increased residential and commercial demand for heating, we were forced to shut down the entire operations for almost two weeks. See Appendix A for a depiction of the reduction in gas use at KNO over the last four years as a result of lack of available supply.
We only have an assured supply of natural gas for another six months, until October 31, 2006. If we are not successful in arranging additional supplies beyond that date we will be forced to shut down the plant on November 1, 2006. Closing the KNO facilities will have a devastating effect on the Kenai Peninsula area of Alaska -- 230 high paying skilled jobs will be eliminated and another 420 indirect jobs will be lost along with the more than $100 million KNO injects into the Alaska economy each year. It will also add to the long list of domestic fertilizer production facilities that permanently have shut down due to feedstock pricing and supply issues.
Mr. Chairman, I should explain here why the Alaska natural gas pipeline, which has been the subject of much discussion in this Committee over the last several years, is not a solution to KNO’s dilemma. As you know, that pipeline will access the 35 trillion cubic feet of known natural gas reserves on Alaska’s North Slope. To achieve the economies of scale necessary to finance the extraordinary capital costs of such a project, the pipeline needs to transport a very large volume of gas (4.5 billion cubic feet per day) to a market that can absorb such a large volume. The residential, commercial, utility and industrial consumers of the lower-48 states comprise the market for North Slope gas. As a result, none of the vast North Slope gas reserves will be available for consumption in the State of Alaska until a project to deliver that gas to lower-48 consumers is constructed. Even then, a small “spur” pipeline of approximately 340 miles would have to be constructed at an approximate cost of $750 million to deliver North Slope gas from the main trunk line to the Kenai Peninsula. Under the best-case scenario, KNO would not have access to Alaska North Slope natural gas before 2016. We can not last that long on current Cook Inlet supplies and need to find another solution if we are to keep the KNO facility operational.
THE BLUE SKY PROJECT
To maintain operations at the KNO facility, Agrium must find a long-term supply of feedstock to substitute for natural gas. Fortunately, multi-year supplies of undeveloped Alaskan coal can be found some 25 miles from the KNO facility. Given the proximity of these coal reserves, coal gasification may be the answer to providing the long-term feedstock that is essential to keep KNO operational.
In 2005, KNO initiated a two-year feasibility study to examine the use of gasification technology utilizing Alaskan coal and other appropriate indigenous fuel resources to produce the hydrogen, nitrogen and CO2 we need to manufacture fertilizer. We are calling the gasification project the Blue Sky Project. This project would utilize commercially offered gasification technology and capitalize on unique market conditions and strategic partnerships to provide a long-term commercial alternative to natural gas reliance in the Cook Inlet region of Alaska. Our engineering work to date has led us to the conclusion that our project will not be designed as an IGCC facility. Rather, we plan to construct a state of the art gasification facility as well as a traditional pulverized coal-fired power plant, using the latest in emissions control technology. The power plant will provide needed electricity to the Kenai fertilizer facility as well as coal-fired power to Alaska residences and other Kenai industries. If we move forward, the plan is for the facility to be commissioned in 2011. To date, Agrium has committed $3.3 million to this study.
The benefits of the Blue Sky project are substantial: we could retain the annual production of 0.8 million tons of ammonia and 1.3 million tons of urea, along with associated jobs, community support and business opportunities for Alaska companies. In addition, the project could provide low cost power for use in the population centers of Alaska, which currently rely heavily on natural gas fired generation. Blue Sky also could capture and supply excess CO2 to recover up to 300 million barrels of Cook Inlet oil through enhanced oil recovery. The project also provides the anchor demand necessary to develop a world-class coal mine. This will in turn assist in the economic development of other Alaskan communities and companies by supplying an alternative for by-products and demand for services.
Given the cost and magnitude of Blue Sky, the current view is that the ultimate business structure will include several strategic partners with an interest in the overall structure or perhaps individual components with strong contractual ties. Agrium could bring nitrogen production experience and use its existing marketing capacity and network to market the product. Usibelli Coal Mine Inc. (UCM) brings to the project over 60 years of experience as the only operating Alaskan coal mining company. The proven experience of Agrium and UCM, combined with the excellent operating performance of the Kenai Nitrogen Operations, is a strong foundation on which to build Blue Sky. Ultimately this project will need additional equity participants to be successful. These participants could include power producers, gasification technology providers, and oil and gas companies interested in enhanced oil recovery.
COMPONENTS OF THE BLUE SKY PROJECT
See Appendix B.
The Blue Sky Project envisions constructing two Shell coal gasification trains to produce the hydrogen, nitrogen, steam and carbon dioxide required by KNO. The process dries and pulverizes delivered coal conveying it to the gasifier where the coal reacts with sub-stoichiometric amounts of pure oxygen to form a gas stream rich in carbon monoxide and hydrogen (syngas). This gas is reacted with water in shift converters where the carbon monoxide (CO) is shifted into carbon dioxide (C02) and hydrogen (H2). The CO2 is then removed from the syngas along with sulfur and other impurities. Finally a pure hydrogen stream is supplied to the KNO nitrogen plant where it will be combined with pure nitrogen from the air separation unit and then converted into ammonia (NH3).
Air Separation Unit
The air separation unit (ASU) processes air directly from the atmosphere to generate the nearly pure oxygen required by the gasification block. The air separation unit is the largest power consumer in the envisioned complex due to the large compressors required to liquefy and separate pure oxygen and nitrogen from the air. The gasifier block requires pure oxygen to process the coal, all of which is supplied by the air separation unit.
The nitrogen plant takes pure hydrogen from the gasifier and pure nitrogen from the air separation unit and combines them in a high-pressure converter to form ammonia (NH3). Some of the ammonia is then refrigerated and sold into the global market. The remaining ammonia is combined with carbon dioxide (CO2) in a high-pressure reactor to form urea (NH2CONH2). The urea is sold as the highest grade of solid nitrogen fertilizer produced for agricultural and industrial markets.
The Blue Sky Project will require approximately 100 MW of electricity to power the gasifier block, the ASU and the nitrogen plant. Since there is not sufficient power generating capacity in the Kenai area to supply this amount of electricity, the Blue Sky Project envisions building a pulverized coal-fired facility to supply power to the Project. These units also have the potential to generate additional power for sale into the electrical grid that serves the population centers of the Kenai Peninsula, Anchorage and the Matanuska Valley. The project will use best available control technology (BACT) for emissions control. We are also considering the application of additional technology that could further reduce emissions.
Enhanced Oil Recovery
CO2 not used in the fertilizer manufacturing process may be captured and sold to Kenai area oil producers who will inject it into the aging Cook Inlet oil fields to produce an estimated 300 million barrels of additional crude oil from these fields. The potential daily oil production increase is estimated to be as much as 25000 barrels per day. The use of CO2 to enhance the recovery of oil from existing fields has been proven in many fields across North America. The unique properties of CO2 allow this gas to dissolve into the remaining heavy oil in the reservoir and change the oil’s flow characteristics. The result is that more oil is able to flow from the reservoir, be recovered and CO2 emissions to the environment are reduced. The Department of Energy has sponsored two studies that have identified the high potential for oil recovery in the Cook Inlet fields.
The Blue Sky Project could utilize up to five million tons of coal per year. The long-term nature, volume and location of this demand can support the development of new coal mining opportunities in Alaska. UCM is evaluating options associated with utilization of coal from the Beluga coal fields on the west side of Cook Inlet as well as from the existing coal mine at Healy, Alaska. UCM is also evaluating the transportation of coal to the Blue Sky facility. A draft report is expected by early summer 2006. Phase 2 of the project will continue to expand on this and will narrow the scope to identify the most viable strategic option. See Appendix C.
EVALUATING THE ECONOMICS OF THE BLUE SKY PROJECT
Our preliminary estimates are that the total cost of the Blue Sky Project will be between $1.5 and $2 billion. Determining whether Agrium and its partners should invest this amount of capital in the project is a challenging and expensive undertaking.
Keep in mind that KNO is in a substantially different position than most other U.S. industrial firms that are reliant on natural gas and that are evaluating a gasification project. These other firms basically have three options from which to choose – continue current operations using high priced natural gas for energy and feedstock; convert to coal or another alternative source of energy and feedstock by installing gasification technology; or cease U.S. operations and move overseas. Because KNO does not have an assured supply of natural gas at any price, we in effect have only two options – develop a coal gasification capability or permanently close the facility.
Our limited options do not mean, however, that we can construct the Blue Sky Project regardless of the economics. We still must market our ammonia and urea competitively. And, as production of fertilizer shifts from traditional industrialized nations to the areas of the world with low cost stranded natural gas, these areas are setting the world price. Thus, we are using very sharp pencils to determine if the Blue Sky Project makes sense.
KNO is evaluating the economics of the Blue Sky Project through a two-phase feasibility study. Phase 1 began in October of 2004 and consists of preliminary engineering, commercial and environmental feasibility assessments. We anticipate having the results of Phase 1 within the next four to six weeks. If the results of Phase 1 are positive, we will advance to Phase 2, in which we will develop a Front End Engineering and Design (FEED) package. We hope to complete Phase 2 by late 2007 at which time we will be in a position to make the “go / no go” decision on the Project.
We expect the total cost of Phase 1 to approach $ 4.0 million and that Phase 2 will cost at least another $28 million. Mr. Chairman, for the Committee to fully understand the difficulty in advancing one of these projects to the construction stage and the role EPAct 05 plays in that regard, it is important for the Members to appreciate that these Phase 1 and Phase 2 expenditures are “at risk” dollars. In other words, if we determine at the end of Phase 2 that the Blue Sky Project is not commercially viable, Agrium and its partners will have spent nearly $32 million and all we will have to show for those dollars are a number of studies and analyses. A key component of these plans and any decisions to put more dollars at risk is the certainty of the federal government’s assistance if it is offered. Suffice to say at this point, if we determine that federal assistance is crucial once the studies are completed, then it is imperative that the federal assistance be there.
ENERGY POLICY ACT OF 2005
A significant component of our Phase 1 work has been a comprehensive analysis of the EPAct 05 to determine whether any of the programs authorized by the Act could improve the commercial viability of the Blue Sky Project. We have concluded that there are two programs that could be beneficial – the industrial gasification tax credits authorized by §48B of the Internal Revenue Code and the innovative technologies loan guarantee program authorized in Title XVII of EPAct 05. These programs have the potential to provide significant benefits to the Project. However, the potential value of these programs will be determined by the manner in that they are implemented by the Executive branch.
That only two of the multiple programs authorized by EPAct 05 are relevant to our Blue Sky Project may be surprising to some. It was somewhat of a surprise to us. One of the basic reasons for this is that a significant majority of the EPAct 05 programs are applicable only to research and development projects, and are not available for commercial scale projects. While we believe it is appropriate for the federal government to support long-term research and development, we would suggest that, if development of capital intensive commercial scale projects utilizing innovative energy technologies is a priority, the Congress may want to consider focusing additional resources on assisting such projects to get over the financial risk hurdles that confront them.
Before discussing the two specific programs, we would like to note that we have found EPAct 05 to be beneficial in an intangible way. It has been our experience that the enactment of EPAct 05 has sent a strong signal to government agencies, particularly the Department of Energy (DOE), and the commercial market place that supporting and promoting the development of these projects is a high priority of the Congress. This signal, in turn, has resulted in a more favorable environment for projects such as Blue Sky. It does not mean that we can ignore commercial realities, but it does mean that we have a greater opportunity to present the case for such projects.
Under IRC §48B, the Blue Sky Project could be eligible for a maximum of $130 million in tax credits. Our preliminary analysis shows that these tax credits could improve the rate of return on investment in the project by up to one half of one (0.5) percent, which could be the difference between going forward and not. However, the manner in which the Internal Revenue Service (IRS) proposes to implement the tax credit authority creates some fundamental uncertainties, not only the Blue Sky Project, but also for other industrial gasification projects. The guidance issued by the IRS calls for DOE to determine which projects should receive the tax credits through a competitive process. Since the total amount of credits is currently limited to $350 million, it is highly likely that only two or three projects will be chosen to receive the credits. Applications for the credits must be submitted by June 30, 2006 with the final decisions regarding which Projects qualify for the credits to be made by November 2006. Given that our Phase 2 detailed study will be just underway on June 30, we will, by necessity, have to submit an application for the tax credits that is somewhat contingent on the outcome of that analysis. We already have amassed a great deal of reliable information but the timing for tax credit applications may be a factor that works against the Blue Sky Project. While we understand the IRS’s desire to expeditiously implement the §48B program, the proposed schedule does not match well with the timing of the Blue Sky Project and other projects being evaluated in the United States.
Mr. Chairman, I understand that you played a significant role in the development of the Title XVII loan guarantee program. Thank you for your foresight. The policy behind Title XVII – that the federal government should share some of the risk of commercializing capital intensive projects such as Blue Sky – has the potential to be the most beneficial and far-reaching contribution of EPAct 05 to the development of innovative energy technologies. However, this potential may not be realized if the Administration takes an overly restrictive approach to implementation of the program.
First, there does not seem to be a uniform commitment within the Executive branch agencies to this program. While DOE appears to be anxious to move forward and lay the groundwork for implementation, it is our understanding that the Office of Management and Budget (OMB) has not yet approved the funding necessary to staff and operate the program. Second, once the program is up and running, every project that hopes to take advantage of a loan guarantee must address the issue of the “risk premium” for the guarantee. Unlike other federal loan guarantee programs, Title XVII permits the DOE to collect funds for the project seeking a loan guarantee to “cover” the probability that the project will default on the guaranteed loan (so-called “risk premium”). Other guarantee programs require that federal appropriations be provided to cover the risk premium in order to support the issuance of a guarantee. While the self-funding device is a creative means to initiate the Title XVII program without impacting the federal budget, everything depends upon how the premium amount is determined.
DOE, in consultation with OMB, will determine the amount of the required risk premium by estimating the probability of default on the guaranteed loan. This default probability determination will be the most important factor in whether the Blue Sky Project (or any other gasification project) will benefit from a Title XVII loan guarantee. If DOE and OMB employ a very conservative approach designed to protect the federal government from virtually all risk, then the premiums for the loan guarantees are likely to be so large that either a federal appropriation will be infeasible or payment of the premium by the applicant will more than offset whatever financing cost benefits are gained by the loan guarantee. As an example, if the total cost of the Blue Sky project were $1.5 billion and we sought a loan guarantee for the maximum 80% of the cost allowed by Title XVII, the guaranteed amount of debt would be $1.2 billion. If the default probability were determined to be 10%, the risk premium would be $120 million. In light of the current federal budget situation, it is doubtful that Congress would appropriate this amount for one project. In the alternative, KNO and it partners would have to provide the $120 million thus increasing the overall cost of the project by 8 percent. This added cost is likely to make the project uneconomic.
In addition to the risk premium issue, we understand that DOE is considering requiring "risk sharing" from lenders. It also appears that DOE has an expectation that the federal loan guarantee will only cover certain negotiated risks during project execution as opposed to providing 100% guarantee coverage on 80% of total project cost as authorized by Title XVII. Likewise, it appears that DOE may limit the applicability of the guarantee to certain identified periods of time rather than the life of the construction loan and/or the term of the permanent financing for a project.
As noted earlier, the policy behind Title XVII is that the federal government will share some of the risk in order to move these new technologies into the marketplace. If DOE and OMB administer the program to eliminate virtually all of the government’s risk exposure then the objective of the Title XVII program will be lost. We would encourage the Congress to provide special oversight to this portion of Title XVII implementation.
Finally, I would note that we have not yet determined whether using the Title XVII loan guarantee program would force Agrium to comply with other federal requirements, specifically the Davis Bacon prevailing wage provisions or some type of domestic content requirements. Having to comply with one or more of these types of requirements will simply add to the overall cost of the project and diminish whatever benefit is gained from the loan guarantee.
Thank you again, Mr. Chairman and Members of the Committee for this opportunity to present our Blue Sky Project. As you see, these projects are massive undertakings that involve a great deal of risk. Enactment of EPAct 05 has created an environment that is more favorable toward industrial gasification projects than in the past and certain programs authorized by the Act have the potential to improve the commercial viability of some projects. However, unless these programs are implemented in the manner that you intended they will not provide sufficient support to stimulate or sustain value added industrial manufacturing in the United States.
Mr. William BrucePresidentBRI Energy, LLC
Mr. Chairman and Members of the Committee, good afternoon. It is a pleasure to be here. My name is William Bruce and I am appearing on behalf of my company, BRI Energy. I appreciate the invitation to appear before this Committee today and have the opportunity to share with you an exciting new ethanol technology developed over the past 15 years by many dedicated scientists and engineers and aided by the Department of Energy. As one of your esteemed colleagues told me recently, “You are really sitting on top of the right technology, you just need to get it to the appropriate people.”
BRI Energy is now ready to commercialize a validated technology that can cost effectively produce ethanol and electricity from any carbon material. This technology can utilize carbon from coal, petroleum coke, agriculture products, and even municipal solid waste. In the simplest of descriptions, we have a patented process that uses heat in modern gasification equipment to break apart carbon molecules, creating a syngas that is converted, via a biocatalytic process, into ethanol. For example, we are able to produce approximately 150 gallons of ethanol per dry ton of coal. I am submitting a technology summary for the record that details the technical specifics of our process.
In short, BRI’s technology is a breakthrough for three reasons:
1. Our process is Environmentally Friendly
2. Our process is Economically Viable
3. Our process uses “Home Grown” Energy
First, our commitment to the environment and reduction of greenhouse gases is to produce ethanol and electricity with little or no air emissions. I am proud to announce today that we have been successful in meeting that commitment at our demonstration facility, which has been operating for two years. The only air emissions produced through our process will come when the ethanol we produce is combusted in an automobile by the end-user.
Second, the passage of last year’s National Energy Policy has laid some very important foundation blocks for us. Our next step is to gain the approval of the financial community by building a commercial scale plant and demonstrating that this technology holds the most cost effective means to produce ethanol and electricity through gasification. We hope that the numerous loan guarantee provisions in the current energy legislation will help us to achieve this goal. With the assistance of a federal loan guarantee, a 7,000,000 gal/yr coal to ethanol production facility can be constructed and fully operational within 1 year. In light of the many challenges in today’s fuel and energy economy, we are able to offer a viable economic solution.
Third, our process uses domestic sources of feedstock to produce ethanol and electricity. As I stated, we can utilize any carbon-based material to produce both ethanol and electricity. But as you all know, the United States is the Saudi Arabia of coal, and with the abundance of coal located throughout most of the nation, our technology will allow each state to have its own commercially viable ethanol production facility.
We have been working quietly to arrive at this point in time with a technology that has been technically studied and accepted by private international engineering firms and uses commercially available equipment. I can sit before you today and clearly state that a real solution is now available to make a significant contribution to solving our nation’s energy challenges, especially in assisting our country in eliminating the need to import foreign oil.
In closing, I would like to reiterate that our technology is a plausible energy solution because it is environmentally friendly, economically viable, and uses home-grown resources.
Again, I truly appreciate this opportunity and would be happy to address any questions that you may have.
Dr. Antonia HerzogClimate Center Staff ScientistNatural Resources Defense Council
Testimony of Antonia Herzog
Staff Scientist and Climate Advocate, Climate Center
Natural Resources Defense Council
Full Committee Hearing on
Energy and Natural Resources
United States Senate
May 1st, 2006
Thank you for the opportunity to testify today on the subject of coal gasification technology. My name is Antonia Herzog. I am a staff scientist and climate advocate of the Climate Center at the Natural Resources Defense Council (NRDC). NRDC is a national, nonprofit organization of scientists, lawyers and environmental specialists dedicated to protecting public health and the environment. Founded in 1970, NRDC has more than 1.2 million members and online activists nationwide, served from offices in New York, Washington, Los Angeles and San Francisco.
One of the primary reasons that the electric power, chemical, and liquid fuels industries have become increasingly interested in coal gasification technology in the last several years is the volatility and high cost of both natural gas and oil. Coal has the advantages of being a cheap, abundant, and a domestic resource compared with oil and natural gas. However, the disadvantages of conventional coal use cannot be ignored. From underground accidents and mountain top removal mining, to collisions at coal train crossings, to air emissions of acidic, toxic, and heat-trapping pollution from coal combustion, to water pollution from coal mining and combustion wastes, the conventional coal fuel cycle is among the most environmentally destructive activities on earth.
But we can do better with both production and use of coal. And because the world is likely to continue to use significant amounts of coal for some time to come, we must do better. Energy efficiency remains the cheapest, cleanest, and fastest way to meet our energy and environmental challenges, while renewable energy is the fastest growing supply option. Increasing energy efficiency and expanding renewable energy supplies must continue to be the top priority, but we have the tools to make coal more compatible with protecting public health and the environment. With the right standards and incentives we can fundamentally transform the way coal is produced and used in the United States and around the world.
In particular, coal use and climate protection do not need to be irreconcilable activities. While energy efficiency and greater use of renewable resources must remain core components of a comprehensive strategy to address global warming, development and use of technologies such as coal gasification in combination with carbon dioxide (CO2) capture and permanent disposal in geologic repositories could enhance our ability to avoid a dangerous build-up of this heat-trapping gas in the atmosphere while creating a future for continued coal use.
However, because of the long lifetime of carbon dioxide in the atmosphere and the slow turnover of large energy systems we must act without delay to start deploying these technologies. Current government policies are inadequate to drive the private sector to invest in carbon capture and storage systems in the timeframe we need them. To accelerate the development of these systems and to create the market conditions for their use, we need to focus government funding more sharply on the most promising technologies. More importantly, we need to adopt reasonable binding measures to limit global warming emissions so that the private sector has a business rationale for prioritizing investment in this area.
Congress is now considering proposals to gasify coal as a replacement for natural gas and oil (as discussed in testimony NRDC provided before this committee in the April 24th, 2006 hearing on “Coal Liquefaction and Gasification” ). These proposals need to be evaluated in the context of the compelling need to reduce global warming emissions steadily and significantly, starting now and proceeding constantly throughout this century. Because today’s coal mining and use also continues to impose a heavy toll on America’s land, water, and air, damaging human health and the environment, it is also critical to examine the implications of a substantial coal gasification program on these values as well.
Reducing Natural Gas Demand
The nation’s economy, our health and our quality of life depend on a reliable supply of affordable energy services. The most significant way in which we can achieve these national goals is to exploit the enormous scope to wring more services out of each unit of energy used and by aggressively promoting renewable resources. While coal gasification technology has been touted as the technology solution to supplement our natural gas supply and reduce our dependence on natural gas imports, the most effective way to lower natural gas demand, and prices, is to waste less. America needs to first invest in energy efficiency and conservation to reduce demand, and to second promote renewable energy alternatives to supplement supply. Gasified coal may have a role to play but in both the short-term and over the next two decades, efficiency and renewables are the lead actors in an effective strategy to moderate natural gas prices and balance our demand for natural gas with reasonable expectations of supply.
We know that today’s natural gas prices have had a particularly significant impact on the agricultural sector by raising the cost of making fertilizer among other products. We agree that effective steps should be taken to fix this problem. In our view a package of measures to increase the efficiency of current gas uses, substitution of renewable energy for other gas uses, and judicious use of coal gasification with CO2 capture and disposal would be the most effective program. With respect to the coal gasification component of this policy package, it is important to address and prevent the additional harmful impacts to land and water that would result if incremental coal production were carried out with current mining and production practices. As pointed out later in Appendix A, current practices are causing unacceptable and avoidable levels of damage to land, water and mining communities.
Increasing energy efficiency is far-and-away the most cost-effective way to reduce natural gas consumption, avoid emitting carbon dioxide and other damaging environmental impacts. Technologies range from efficient lighting, including emerging L.E.D. lamps, to advanced selective membranes which reduce industrial process energy needs. Critical national and state policies include appliance efficiency standards, performance-based tax incentives, utility-administered deployment programs, and innovative market transformation strategies that make more efficient designs standard industry practice.
Conservation and efficiency measures such as these can have dramatic impacts in terms of price and savings. Moreover, all of these untapped gas efficiency “resources” will expand steadily, as a growing economy adds more opportunities to secure long-lived savings. California has a quarter century record of using comparable strategies to reduce both natural gas consumption and the accompanying utility bills. Recent studies commissioned by the Pacific Gas & Electric Company indicate that, by 2001, longstanding incentives and standards targeting natural gas equipment and use had cut statewide consumption for residential, commercial, and industrial purposes (excluding electric generation) by more than 20 percent.
Renewables can also play a key role in reducing natural gas prices. Adoption of a national renewable energy standard (RES) can significantly reduce the demand for natural gas, alleviating potential shortages. The Energy Information Administration (EIA) has found that a national 10 percent renewable energy standard could reduce gas consumption by 1.4 trillion cubic feet per year in 2020 compared to business as usual, or roughly 5 percent of annual demand.
Studies have consistently shown that reducing demand for natural gas by increasing renewable energy use will reduce natural gas prices. According to a report released by the U.S. Department of Energy’s Lawrence Berkeley National Laboratory, “studies generally show that each 1% reduction in national gas demand is likely to lead to a long-term (effectively permanent) average reduction in wellhead gas prices of 0.8% to 2%. Reductions in wellhead prices will reduce wholesale and retail electricity rates and will also reduce residential, commercial, and industrial gas bills.” EIA found that increasing renewable energy to 10 percent by 2020 would result in $4.9 billion cumulative present value savings for industrial gas consumers, $1.8 billion to commercial customers, and $2.4 billion to residential customers. EIA also found that renewable energy can also reduce electricity bills. Lower natural gas prices for electricity generators and other consumers offset the slightly higher cost of renewable electricity technology.
Implementing effective energy efficiency measures is the fastest and most cost effective approach to balancing natural gas demand and supply. Renewable energy provides a critical mid-term to long-term supplement. Analysis by the Union of Concerned Scientists found that a combined efficiency and renewable energy scenario could reduce gas use by 31 percent and natural gas prices by 27 percent compared to business as usual in 2020.
In contrast to these strategies, pursuing coal gasification implementation strategies that address only natural gas supply concerns, while ignoring impacts of coal, is a recipe for huge and costly mistakes. Fortunately, we have in our tool box energy resource options that can reduce natural gas demand and global warming emissions as well as protecting America’s land, water, and air.
Environmental Impacts of Coal
Some call coal “clean.” It is not and likely never will be compared to other energy options. Nonetheless, it appears inevitable that the U.S. and other countries will continue to rely heavily on coal for many years. The good news is that with the right standards and incentives it is possible to chart a future for coal that is compatible with protecting public health, preserving special places, and avoiding dangerous global warming. It may not be possible to make coal clean, but by transforming the way coal is produced and used, it is possible to make coal dramatically cleaner - and safer - than it is today.
Global Warming Pollution
To avoid catastrophic global warming the U.S. and other nations will need to deploy energy resources that result in much lower releases of CO2 than today’s use of oil, gas and coal. To keep global temperatures from rising to levels not seen since before the dawn of human civilization, the best expert opinion is that we need to get on a pathway now to allow us to cut global warming emissions by 60-80% from today’s levels over the decades ahead. The technologies we choose to meet our future energy needs must have the potential to perform at these improved emission levels.
Most serious climate scientists now warn that there is a very short window of time for beginning serious emission reductions if we are to avoid truly dangerous greenhouse gas reductions without severe economic impact. Delay makes the job harder. The National Academy of Sciences recently stated: “Failure to implement significant reductions in net greenhouse gases will make the job much harder in the future – both in terms of stabilizing their atmospheric abundances and in terms of experiencing more significant impacts.”
In short, a slow start means a crash finish – the longer emissions growth continues, the steeper and more disruptive the cuts required later. To prevent dangerous global warming we need to stabilize atmospheric concentration at or below 450 ppm, which would keep total warming below 2 degrees Celsius (3.6 degrees Fahrenheit). If we start soon, we can stay on the 450 ppm path with an annual emission reduction rate that gradually ramps up to about 2.4% per year. But if we delay a serious start by 10 years and continue emission growth at the business-as-usual trajectory, the annual emission reduction rate required to stay on the 450 ppm pathway jumps almost 3-fold, to 6.9% per year. (See Figure 1.) Even if you do not accept today that the 450 ppm path will be needed please consider this point. If we do not act to preserve our ability to get on this path we will foreclose the path not just for ourselves but for our children and their children. We are now going down a much riskier path and if we do not start reducing emissions soon neither we nor our children can turn back no matter how dangerous the path becomes.
In the past, some analysts have argued that the delay/crash action scenario is actually the cheaper course, because in the future (somehow) we will have developed breakthrough technologies. But it should be apparent that the crash reductions scenario is implausible for two reasons. First, reducing emissions by 6.9 percent per year would require deploying advanced low-emission technologies at least several times faster than conventional technologies have been deployed over recent decades. Second, the effort would require prematurely retiring billions of dollars in capital stock – high-emitting power plants, vehicles, etc. – that will be built or bought during the next 10-20 years under in the absence of appropriate CO2 emission limits.
It also goes without saying that U.S. leadership is critical. Preserving the 450 ppm pathway requires other developed countries to reduce emissions at similar rates, and requires the key developing countries to dramatically reduce and ultimately reverse their emissions growth. U.S. leadership can make that happen faster.
To assess the global warming implications of a large coal gasification program we need to carefully examine the total life-cycle emissions associated with the end product, whether electricity, synthetic gas, liquid fuels or chemicals, and to assess if the relevant industry sector will meet the emission reductions required to be consistent with the “green” pathway presented in Figure 1.
More than 90 percent of the U.S. coal supply is used to generate electricity in some 600 coal-fired power plants scattered around the country, with most of the remainder used for process heat in heavy industrial and in steel production. Coal is used for power production in all regions of the country, with the Southeast, Midwest, and Mountain states most reliant on coal-fired power. Texas uses more coal than any other state, followed by Indiana, Illinois, Ohio, and Pennsylvania.
About half of the U.S. electricity supply is generated using coal-fired power plants. This share varies considerably from state to state, but even California, which uses very little coal to generate electricity within its borders, consumes a significant amount of electricity generated by coal in neighboring Arizona and Nevada, bringing coal’s share of total electricity consumed in California to 20 percent. National coal-fired capacity totals 330 billion watts (GW), with individual plants ranging in size from a few million watts (MW) to over 3000 MW. More than one-third of this capacity was built before 1970, and over 400 units built in the 1950s—with capacity equivalent to roughly 100 large modern plants (48 GW)—are still operating today.
The future of coal in the U.S. electric power sector is an uncertain one. The major cause of this uncertainty is the government’s failure to define future requirements for limiting greenhouse gas emissions, especially carbon dioxide (CO2). Coal is the fossil fuel with the highest uncontrolled CO2 emission rate of any fuel and is responsible for 36 percent U.S. carbon dioxide emissions. Furthermore, coal power plants are expensive, long-lived investments. Key decision makers understand that the problem of global warming will need to be addressed within the time needed to recoup investments in power projects now in the planning stage. Since the status quo is unstable and future requirements for coal plants and other emission sources are inevitable but unclear, there will be increasing hesitation to commit the large amounts of capital required for new coal projects.
Electricity production is the largest source of global warming pollution in the U.S. today. In contrast to nitrogen and sulfur oxide emissions, which have declined significantly in recent years as a result of Clean Air Act standards, CO2 emissions from power plants have increased by 27 percent since 1990. Any solution to global warming must include large reductions from the electric sector. Energy efficiency and renewable energy are well-known low-carbon methods that are essential to any climate protection strategy. But technology exists to create a more sustainable path for continued coal use in the electricity sector as well. Coal gasification can be compatible with significantly reducing global warming emissions in the electric sector if it replaces conventional coal combustion technologies, directly produces electricity in an integrated manner, and most importantly captures and disposes of the carbon in geologic formations. IGCC technology without CO2 capture and disposal achieves only modest reductions in CO2 emissions compared to conventional coal plants.
A coal integrated gasification combined cycle (IGCC) power plant with carbon capture and disposal can capture up to 90 percent of its emissions, thereby being part of the global warming solution. In addition to enabling lower-cost CO2 capture, gasification technology has very low emissions of most conventional pollutants and can achieve high levels of mercury control with low-cost carbon-bed systems. However, it still does not address the other environmental impacts from coal production and transportation discussed in more detail in Appendix A.
The electric power industry has been slow to take up gasification technology but two commercial-scale units are operating in the U.S.—in Indiana and Florida. The Florida unit, owned by TECO, is reported by the company to be the most reliable and economic unit on its system. Two coal-based power companies, AEP and Cinergy, have announced their intention to build coal gasification units. BP also has announced plans to build a petroleum coke gasification plants that will capture and sequester CO2.
Another area that has received interest is coal gasification to produce synthetic natural gas as a direct method of supplementing our natural gas supply from domestic resources. However, without CO2 capture and disposal this process results in more than twice as much CO2 per 1000 cubic feet of natural gas consumed compared to conventional resources. From a global warming perspective this is unacceptable. With capture and disposal the CO2 emissions can be substantially reduced, but still remain 12 percent higher than natural gas.
In Beulah, North Dakota the Basin Electric owned Dakota Gasification Company’s Great Plains Synfuels Plant is a 900MW facility which gasifies coal to produce synthetic “natural” gas. It can produce a 150 million cubic feet of synthetic gas per day and 11,000 tons of CO2 per day. However, it no longer releases all of its CO2 to the atmosphere, but captures most of it and pipes it 200 miles to an oil field near Weyburn, Saskatchewan. There the CO2 is pumped underground into an aging oil field to recover more oil. EnCana, operator of this oil field, pays $2.5 million per month for the CO2. They expect to sequester 20 million tons of CO2 over the lifetime of this injection project.
A potential use for coal-produced synthetic gas would be to burn it in a gas turbine at another site for electricity generation. This approach would result in substantially higher CO2 emissions than producing electricity in an integrated system at the coal gasification plant with CO2 capture at the site (i.e. in an IGCC plant with carbon capture and disposal). Coal produced synthetic natural gas could also be used directly for home heating. As a distributed source of emissions the CO2 would be prohibitive to capture with known technology.
Before producing synthetic pipeline gas from coal a careful assessment of the full fuel cycle emission implications and the emission reductions that are required from that sector must be carried out before decisions are made to invest in these systems.
The chemical industry has also been looking carefully at coal gasification technology as a way to replace the natural gas feedstock used in chemical production. The motivator has been the escalating and volatile costs of natural gas in the last few years. A notable example in the U.S. of such a use is the Tennessee Eastman plant, which has been operating for more than 20 years using coal instead of natural gas to make chemicals and industrial feedstocks. If natural gas is replaced by coal gasification as a feedstock for the chemical industry, first and foremost CO2 capture and disposal must be an integral part of such plants. In this case, the net global warming emissions will change relatively little from this sector. However, before such transformation occurs a careful analysis of the life cycle emissions needs to be carried out along with an assessment of how future emissions reductions from this sector can be most effectively accomplished.
The issue of converting coal into a liquid fuel was explored in detail in testimony NRDC provided before this committee in the April 24th, 2006 hearing on “Coal Liquefaction and Gasification”. To briefly reiterate, to assess the global warming implications of a large coal-to-liquids program we need to examine the total life-cycle or “well-to-wheel” emissions of these new fuels. Coal contains about 20 percent more carbon per unit of energy compared to petroleum. When coal is converted to liquid fuels, two streams of CO2 are produced: one at the coal-to-liquids production plant and the second from the exhausts of the vehicles that burn the fuel. With the technology in hand today and on the horizon it is difficult to see how a large coal-to-liquids program can be compatible with the low-CO2-emitting transportation system we need to design to prevent global warming.
Based on available information about coal-to-liquids plants being proposed, the total well to wheels CO2 emissions from such plants would be nearly twice as high as using crude oil, if the CO2 from the coal-to-liquids plant is released to the atmosphere. Obviously, introducing a new fuel system with double the CO2 emissions of today’s crude oil system would conflict with the need to reduce global warming emissions. If the CO2 from coal-to-liquids plants is captured, then well-to-wheels CO2 emissions would be reduced but would still be higher than emissions from today’s crude oil system.
This comparison indicates that using coal to produce a significant amount of liquids for transportation fuel would not be compatible with the need to develop a low-CO2 emitting transportation sector unless technologies are developed to significantly reduce emissions from the overall process. But here one confronts the unavoidable fact that the liquid fuel from coal contains the same amount of carbon as is in gasoline or diesel made from crude. Thus, the potential for achieving significant CO2 emission reductions compared to crude is inherently limited. This means that using a significant amount of coal to make liquid fuel for transportation needs would make the task of achieving any given level of global warming emission reduction much more difficult. Proceeding with coal-to-liquids plants now could leave those investments stranded or impose unnecessarily high abatement costs on the economy if the plants continue to operate.
CO2 Capture and Disposal
Methods to capture CO2 from industrial gas streams have been in use for decades. In the U.S., for example, they are used to separate CO2 from “sour gas” at natural gas processing plants and are even in use at a few coal-fired power plants to produce CO2 for sale to the food and beverage industries. As previously mentioned, in North Dakota a large coal gasification plant captures CO2 and ships it by pipeline to an oil field in Saskatchewan, where it is injected to produce additional oil. In Wyoming, a large gas processing plant captures CO2 for sale to oil field operators in that state and in Colorado. Smaller plants in Texas do the same thing to serve oil fields in the Permian Basin.
Once captured, the CO2 must be disposed of and the currently viable approach is to inject the CO2 into deep geologic formations that are capable of permanently retaining it. Geologic injection of CO2 has been underway in the U.S. for a couple of decades as a method for producing additional oil from declining fields. Today, oil companies inject about 30 million tons annually into fields in the Permian Basin, Wyoming, Colorado and other states.
Because industrial sources can emit CO2 for free under current U.S. policy, most of the injected CO2 is supplied from natural CO2 reservoirs, rather than being captured from emission sources. Ironically, due to the lack of emission limits and the limited number of natural CO2 fields, a CO2 supply shortage is currently constraining enhanced oil recovery from existing fields. There is, of course, a huge supply of CO2 from power plants and other sources that would become available to supply this market, but that will not happen as long as CO2 can be emitted at no cost.
Such enhanced oil recovery (EOR) operations are regulated to prevent releases that might endanger public health or safety but they are not monitored with any techniques that would be capable of detecting smaller leak rates. Small leak rates might pose no risk to the local surroundings but over time could undercut the effectiveness of geologic storage as a CO2 control technique. Especially in EOR operations, the most likely pathways for leakage would be through existing wells penetrating the injection zone.
Much of the injected CO2 is also brought back to the surface with the oil produced by this technique. That CO2 is typically reinjected to recover additional oil, but when oil operations are completed it may be necessary to inject the CO2 into a deeper geologic formation to ensure permanent storage.
In addition to these EOR operations, CO2 is being injected in large amounts in several other projects around the world. The oldest of these involves injection of about 1 million tons per year of CO2 from a natural gas platform into a geologic formation beneath the sea bed off the coast of Norway. The company decided to inject the CO2 rather than vent it to avoid paying an emission charge adopted by the Norwegian government—a clear example of the ability of emission policies to produce the deployment of this technology. The Norwegian operation is intensively monitored and the results from over seven years of operation indicate the CO2 is not migrating in a manner that would create a risk of leakage. Other large-scale carefully monitored operations are underway at the Weyburn oil field in Saskatchewan and the In Salah natural gas field in Algeria.
While additional experience with large-scale injection in various geologic formations is needed, we believe enough is known to expand these activities substantially under careful procedures for site selection, operating requirements and monitoring programs. The imperative of avoiding further carbon lock-in due to construction of conventional coal-fired power plants and the capabilities of CO2 capture and storage technologies today warrant policies to deploy these methods at coal gasification plants without further delay.
Conventional Air Pollution
Dramatic reductions in power plant emissions of criteria pollutants, toxic compounds, and global warming emissions are essential if coal is to remain a viable energy resource for the 21st Century. Such reductions are achievable in coal gasification plants. In particular, integrated gasification combined cycle (IGCC) systems enable cost-effective advanced pollution controls that can yield extremely low criteria pollutant and mercury emission rates and facilitates carbon dioxide capture and geologic disposal. Gasifying coal at high pressure facilitates removal of pollutants that would otherwise be released into the air such that these pollutant emissions are well below those from conventional pulverized coal power plants with post combustion cleanup. These technologies will not be widely employed, however, without a sustained market driver, which requires vigorous enforcement of clean air standards, new limits on global warming emissions, and market oriented incentives to deploy carbon capture and disposal
Mining, Processing and Transporting Coal
The impacts of mining, processing, and transporting 1.1 billion tons of coal today on health, landscapes, and water are large. To understand the implications of continuing our current level of as well as expanding coal production, it is important to have a detailed understanding of the impacts from today’s level of coal production. A summary is included in Appendix A and was also given in testimony NRDC submitted on April 24th, 2006 to the Senate Energy and Natural Resources full committee hearing on “Coal Liquefaction and Gasification.” It clear that we must find more effective ways to reduce the impacts of mining, processing and transportation from coal before we follow a path that would result in even larger amounts of coal production and transportation.
“Carbon Capture Ready” and the “Energy Policy Act of 2005”
Among the various environmental concerns associated with coal use, the global warming emissions are particularly critical as coal fired power generation emits more carbon dioxide per unit of energy than any other power generating process. It is clear that for coal to remain a major source of electricity generation within a carbon constrained world, carbon capture and disposal technologies will have to be deployed in conjunction coal fired power plants.
The three required elements of a coal-based CO2 capture and disposal (CCD) system have all been demonstrated at commercial scale in numerous projects around the world. But there is large potential for optimization of each element to bring down costs and improve efficiency. In addition, the experience with large scale injection of CO2 into geologic formations is still limited.
For coal, the first element of a CCD system is a method to convert coal into useful energy that produces a waste stream that makes CO2 capture relatively inexpensive. The method for doing this that is commercially demonstrated is through gasification of coal. In contrast to the conventional coal combustion methods used in electric power generation, gasification converts the coal under pressure and temperature to produce a smaller gas stream with higher CO2 concentrations. This approach significantly reduces the cost and energy required to capture CO2.
In the “Energy Policy Act of 2005” (EPACT05), while there are myriad incentives for deploying coal gasification technology, there are no requirements to include CO2 capture and disposal. Scattered throughout the Act is language referring to the capability of coal gasification technology to capture its carbon emissions or to be “carbon capture ready”. However, nothing requires the facilities to actually capture and dispose of their CO2 emissions. Several examples are the following:
• Title IV – Coal - section 413 (b)(3) Western Integrated Coal Gasification Demonstration Project: “Shall be capable of removing and sequestering carbon dioxide emissions.”
• Title VIII - Hydrogen – section 805(e)(1)(A) “Fossil fuel, which may include carbon capture and sequestration;”
• Title X111 – Energy Policy Tax Incentives - section 1307(b) “Sec. 48A. (c) Definitions (5) GREENHOUSE GAS CAPTURE CAPABILITY- The term `greenhouse gas capture capability' means an integrated gasification combined cycle technology facility capable of adding components which can capture, separate on a long-term basis, isolate, remove, and sequester greenhouse gases which result from the generation of electricity.”
“Sec. 48B. (c) Definitions (5) CARBON CAPTURE CAPABILITY- The term `carbon capture capability' means a gasification plant design which is determined by the Secretary to reflect reasonable consideration for, and be capable of, accommodating the equipment likely to be necessary to capture carbon dioxide from the gaseous stream, for later use or sequestration, which would otherwise be emitted in the flue gas from a project which uses a nonrenewable fuel.”
• Title XVII – Incentives for Innovative Technologies – Section 1703(c)(1)(A)(ii) “that have a design that is determined by the Secretary to be capable of accommodating the equipment likely to be necessary to capture the carbon dioxide that would otherwise be emitted in flue gas from the plant;”
The issue I would like to address here is the definition of “carbon capture ready.” Adding carbon capture capabilities to a coal gasification power plant is not a simple modification. Without any current regulatory or economic incentives for these facilities to capture and dispose of their carbon emissions the extent of the capture modifications that will be incorporated into the gasification facilities remains extremely unclear. I would, in fact, argue that due to the vagueness of this term the result will be a “race to the bottom”, a minimal effort to incorporate the necessary design elements and equipment that would allow coal gasification plants to qualify for EPACT05 incentives.
What are the required technical details associated with coupling coal gasification plants with carbon capture and disposal? Carbon capture in a coal gasification plant occurs after the coal gasification process. I will focus on the case for electricity generation (an IGCC plant) where the syngas produced then enters a gas turbine. It is at this stage that the chemical process can be inserted to separate and capture the CO2 and other pollutants from the syngas. Once the CO2 is separated it can be transported to a disposal location.
In addition to adding the CO2 separation and capture equipment, changes in other components are also necessary for electricity generation case. The removal of CO2 prior to combustion in the turbine alters the composition of the gas to be burned, increasing the hydrogen content, which may affect the design or operational requirements of the turbine. In addition, the CO2 capture process may alter the optimal design of the desulphurization and other gas clean-up processes. For these reasons, an IGCC plant built without consideration for CO2 capture technology designed to produce power at a minimum cost and maximum efficiency will be significantly different than an IGCC plant designed to incorporate CO2 capture technology.
“Three major technological components need to be added to a basic IGCC plant to allow for separation and capture of the CO2: (1) the shift reactor to convert the CO in the syngas to CO2, (2) the process to separate the CO2 from the rest of the gas stream, and (3) a compressor to reduce the volume of separated CO2 before it can be transported.” Furthermore, other components will require modification, as previously mentioned, including the gas turbine that will have to be capable of operating with a hydrogen enriched gas stream, the timing of the sulphur removal process and some scaling up to accommodate the larger quantities of coal needed to generate the same amount of power.
A further consideration is the CO2 transportation and disposal. Once the CO2 is captured and compressed at the plant it must be transported and injected into an underground geologic formation. Therefore, the location of the plant can also become a significant factor in the ease of transformation.
What should be clear from this listing of requirements for integrating capture and disposal of CO2 into an existing IGCC plant is that the term “carbon capture ready” could encompass a whole host of definitions. Does it simply mean that one builds an IGCC plant? Does it mean that you leave space in the design for separation, capture and compression equipment? Does it mean you include the appropriate turbine to burn a high H2 gas stream? Does it mean you locate the plant within proximity to a geologic reservoir where the CO2 can be disposed of? The list and variations of the possibilities could go on and on, calling into question whether the term “carbon capture ready “ has any real meaning..
The likely result is that companies when taking advantage of the coal gasification incentives provided in the “Energy Policy Act of 2005” will follow the least cost option, i.e., build an IGCC plant with little or no design elements necessary for the future integration of CO2 capture and disposal -- unless there is a clear policy to reduce CO2 emissions or if it is required that they include all the necessary equipment to capture their CO2.
NRDC strongly advocates that all government funds that leverage the building of coal gasification plants should only go to those facilities that actually capture their CO2. Subsidizing gasification by itself wastes taxpayers’ money by subsidizing the wrong thing. Gasification is commercial and needs no subsidy but capture and storage is the primary policy objective and is likely to require subsidies pending adoption of CO2 emission control requirements.
The first proposed coal gasification plant that will capture and dispose of its CO2 was recently announced on February 10, 2006 by BP British Petroleum and Edison Mission Group. The plant will be built in Southern California and its CO2 emissions will be pipelined to an oil field nearby and injected into the ground to recover domestic oil. BP’s proposal shows the technologies are available now to cut global warming pollution and that integrated IGCC with CO2 capture and disposal are commercially feasible.
The Path Forward
The impacts that a large coal gasification program could have on global warming pollution, conventional air pollution and environmental damage resulting from the mining, processing and transportation of the coal are substantial. Before deciding whether to invest scores, perhaps hundreds of billions of dollars in deploying this technology, we must have a program to manage our global warming pollution and other coal related impacts. Otherwise we will not be developing and deploying an optimal energy system.
One of the primary motivators for moving toward coal gasification technologies has been to reduce natural gas prices. Fortunately, the U.S. can have a robust and effective program to reduce natural gas demand, and therefore prices, without rushing to embrace coal gasification technologies. A combination of efficiency and renewables can reduce our natural gas demand more quickly and more cleanly.
Implementing effective energy efficiency measures is the fastest and most cost effective approach to reducing natural gas demand. Efficiency standards, performance-based tax incentives, utility-administered deployment programs, and innovative market transformation strategies will bring energy efficient technologies to market and make efficient designs standard industry practice.
Renewable energy provides a critical mid-term to long-term supplement to natural gas use. Potential renewable resources in the U.S. are significant and renewable electricity generation is expanding rapidly, with wind and biomass currently offering the most cost-effective power in both countries. Some 20 U.S. states have adopted renewable portfolio standards requiring electricity providers to obtain a minimum portion of their portfolio from renewable resources. Federal tax incentives have also played an important role, particularly for wind.
With current coal (and oil) consumption trends, we are headed for a doubling of CO2 concentrations by mid-century if we don’t redirect energy investments away from carbon based fuels and toward new climate friendly energy technologies.
We have to accelerate the progress underway and adopt policies in the next few years to turn the corner on our global warming emissions, if we are to avoid locking ourselves and future generations into a dangerously disrupted climate. Scientists are very concerned that we are very near this threshold now. Most say we must keep atmosphere concentrations of CO2 below 450 parts per million, which would keep total warming below 2 degrees Celsius (3.6 degrees Fahrenheit). Beyond this point we risk severe impacts, including the irreversible collapse of the Greenland Ice Sheet and dramatic sea level rise. With CO2 concentrations now rising at a rate of 1.5 to 2 parts per million per year, we will pass the 450ppm threshold within two or three decades unless we change course soon.
In the United States, a national program to limit carbon dioxide emissions must be enacted soon to create the market incentives necessary to shift investment into the least-polluting energy technologies on the scale and timetable that is needed. There is growing agreement between business and policy experts that quantifiable and enforceable limits on global warming emissions are needed and inevitable. To ensure the most cost-effective reductions are made, these limits can then be allocated to major pollution sources and traded between companies, as is currently the practice with sulfur emissions that cause acid rain. Targeted energy efficiency and renewable energy policies are critical to achieving CO2 limits at the lowest possible cost, but they are no substitute for explicit caps on emissions.
A coal integrated gasification combined cycle (IGCC) power plant with carbon capture and disposal can also be part of a sustainable path that reduces both natural gas demand as well as global warming emissions in the electricity sector. Methods to capture CO2 from coal gasification plants are commercially demonstrated, as is the injection of CO2 into geologic formations for disposal. On the other hand, coal gasification to produce a significant amount of liquids for transportation fuel would not be compatible with the need to develop a low-CO2 emitting transportation sector. Finally, gasifying coal to produce synthetic pipeline gas or chemical products needs a careful assessment of the full life cycle emission implications and the emission reductions that are required from those sectors before decisions are made to invest in these systems.
In the absence of a program that requires limits on CO2 emissions IGCC systems with carbon capture and disposal will not be brought to market in time. We need to combine CO2 limits with financial incentives to start building these integrated plants now, because industry is already building and designing the power plants that we will rely on for the next 40-80 years.
To reduce our natural gas demand we should follow a simple rule: start with the measures that will produce the quickest, cleanest and least expensive reductions in natural gas use; measures that will put us on track to achieve the reductions in global warming emissions we need to protect the climate. If we are thoughtful about the actions we take, our country can pursue an energy path that enhances our security, our economy, and our environment.
Mining, Processing and Transporting Coal
The impacts of mining, processing, and transporting 1.1 billion tons of coal today on health, landscapes, and water are large. To understand the implications of continuing our current level of as well as expanding coal production, it is important to have a detailed understanding of the impacts from today’s level of coal production. The summary that follows makes it clear that we must find more effective ways to reduce these impacts before we follow a path that would result in even larger amounts of coal production and transportation.
Health and Safety
Coal mining is one of the U.S.’s most dangerous professions. The yearly fatality rate in the industry is 0.23 per thousand workers, making the industry about five times as hazardous as the average private workplace. The industry had 27 fatalities in 2002, an all-time low, and there were 55 deaths in 2004 and 57 deaths in 2005. The first month of 2006 was particularly deadly, however, with 18 fatalities through February 1st. Sixteen of these deaths occurred in West Virginia mines, leading the Governor to call for an unprecedented suspension of production while safety checks were conducted. Coal miners also suffer from many non-fatal injuries and diseases, most notably black lung disease (also known as pneumoconiosis) caused by inhaling coal dust. Although the 1969 Coal Mine Health and Safety Act seeks to eliminate black lung disease, the United Mine Workers estimate that 1500 former miners die of black lung each year.
Coal mining - and particularly surface or strip mining - poses one of the most significant threats to terrestrial habitats in the United States. The Appalachian region , for example, which produces over 35% of our nation’s coal , is one of the most biologically diverse forested regions in the country. But during surface mining activities, trees are clearcut and habitat is fragmented, destroying natural areas that were home to hundreds of unique species of plants and animals. Even where forests are left standing, fragmentation is of significant concern because a decrease in patch size is correlated with a decrease in biodiversity as the ratio of interior habitat to edge habitat decreases. This is of particular concern to certain bird species that require large tracts of interior forest habitat, such as the black-and-white warbler and black-throated blue warbler.
After mining is complete, these once-forested regions in the Southeast are typically reclaimed as grasslands, although grasslands are not a naturally occurring habitat type in this region. Grasslands that replace the original ecosystems in areas that were surface mined are generally categorized by less-developed soil structure and lower species diversity compared to natural forests in the region. Reclaimed grasslands are generally characterized by a high degree of soil compaction that tends to limit the ability of native tree and plant species to take root. Reclamation practices limit the overall ecological health of sites, and it has been estimated that the natural return of forests to reclaimed sites may take hundreds of years. According to the USEPA, the loss of vegetation and alteration of topography associated with surface mining can lead to increased soil erosion and may lead to an increased probability of flooding after rainstorms.
The destruction of forested habitat not only degrades the quality of the natural environment, it also destroys the aesthetic values of the Appalachian region that make it such a popular tourist destination. An estimated one million acres of West Virginia Mountains were subject to strip mining and mountaintop removal mining between 1939 and 2005. Many of these mines have yet to be reclaimed so that where there were once forested mountains, there now stand bare mounds of sand and gravel.
The terrestrial impacts of coal mining in the Appalachian region are considerable, but for sheer size they cannot compare to the impacts in the western United States. As of September 30, 2004, 470,000 acres were under federal coal leases or other authorizations to mine. Unlike the East, much of the West– including much of the region’s principal coal areas –is arid and predominantly unforested. In the West, as in the East, surface mining activities cause severe environmental damage as huge machines strip, rip apart and scrape aside vegetation, soils, wildlife habitat and drastically reshape existing land forms and the affected area’s ecology to reach the subsurface coal. Strip mining results in industrialization of once quiet open space along with displacement of wildlife, increased soil erosion, loss of recreational opportunities, degradation of wilderness values, and destruction of scenic beauty. Reclamation can be problematic both because of climate and soil quality. As in the East, reclamation of surface mined areas does not necessarily restore pre-mining wildlife habitat and may require scarce water resources be used for irrigation. Forty-six western national parks are located within ten miles of an identified coal basin, and these parks could be significantly affected by future surface mining in the region.
Coal production causes negative physical and chemical changes to nearby waters. In all surface mining, the overburden (earth layers above the coal seams) is removed and deposited on the surface as waste rock. The most significant physical effect on water occurs from valley fills, the waste rock associated with mountaintop removal (MTR) mining. Since MTR mining started in the United States in the early 70’s, studies estimate that over 700 miles of streams have been buried from valley fills, and 1200 additional miles have been directly impacted from valley fills through sedimentation or chemistry alteration. Together, the waterways harmed by valley fills are about 80 percent as long as the Mississippi River. Valley fills bury the headwaters of streams, which in the southeastern U.S. support diverse and unique habitats, and regulate nutrients, water quality, and flow quantity. The elimination of headwaters therefore has long-reaching impacts many miles downstream.
Coal mining can also lead to increased sedimentation, which affects both water chemistry and stream flow, and negatively impacts aquatic habitat. Valley fills in the eastern U.S., as well as waste rock from strip mines in the west add sediment to streams, as does the construction and use of roads in the mining complex. A final physical impact of mining on water is to the hydrology of aquifers. MTR and valley fills remove upper drainage basins, and often connect two previously separate aquifers, altering the surrounding groundwater recharge scheme.
Acid mine drainage (AMD) is the most significant form of chemical pollution produced from coal mining operations. In both underground and surface mining, sulfur-bearing minerals common in coal mining areas are brought up to the surface in waste rock. When these minerals come in contact with precipitation and groundwater, an acidic leachate is formed. This leachate picks up heavy metals and carries these toxins into streams or groundwater. Waters affected by AMD often exhibit increased levels of sulfate, total dissolved solids, calcium, selenium, magnesium, manganese, conductivity, acidity, sodium, nitrate, and nitrite. This drastically changes stream and groundwater chemistry. The degraded water becomes less habitable, non potable, and unfit for recreational purposes. The acidity and metals can also corrode structures such as culverts and bridges. In the eastern U.S., estimates of the damage from AMD range from four to eleven thousand miles of streams. In the West, estimates are between five and ten thousand miles of streams polluted. The effects of AMD can be diminished through addition of alkaline substances to counteract the acid, but recent studies have found that the addition of alkaline material can increase the mobilization of both selenium and arsenic. AMD is costly to mitigate, requiring over $40 million annually in Kentucky, Tennessee, Virginia, and West Virginia alone.
There are two main sources of air pollution during the coal production process. The first is methane emissions from the mines. Methane is a powerful heat-trapping gas and is the second most important contributor to global warming after carbon dioxide. Methane emissions from coal mines make up between 10 and 15% of anthropogenic methane emissions in the U.S. According to the most recent official inventory of U.S. global warming emissions, coal mining results in the release of 3 million tons of methane per year, which is equivalent to 68 million tons of carbon dioxide.
The second significant form of air pollution from coal mining is particulate matter (PM) emissions. While methane emissions are largely due to eastern underground mines, PM emissions are particularly serious at western surface mines. The arid, open and frequently windy region allows for the creation and transport of significant amounts of particulate matter in connection with mining operations. Fugitive dust emissions occur during nearly every phase of coal strip mining in the west. The most significant sources of these emissions are removal of the overburden through blasting and use of draglines, truck haulage of the overburden and mined coal, road grading, and wind erosion of reclaimed areas. PM emissions from diesel trucks and equipment used in mining are also significant. PM can cause serious respiratory damage as well as premature death. In 2002, one of Wyoming’s coal producing counties, Campbell County, exceeded its ambient air quality threshold several times, almost earning non-attainment status. Coal dust problems in the West are likely to get worse if the administration finalizes its January 2006 proposal to exempt mining (and other activities) from controls aimed at meeting the coarse PM standard.
Coal Mine Wastes
Coal mining leaves a legacy of wastes long after mining operations cease. One significant waste is the sludge that is produced from washing coal. There are currently over 700 sludge impoundments located throughout mining regions, and this number continues to grow. These impoundment ponds pose a potential threat to the environment and human life. If an impoundment fails, the result can be disastrous. In 1972 an impoundment break in West Virginia released a flood of coal sludge that killed 125 people. In the year 2000 an impoundment break in Kentucky involving more than 300 million gallons of slurry (30 times the size of the Exxon Valdez spill) killed all aquatic life in a 20 mile diameter, destroyed homes, and contaminated much of the drinking water in the eastern part of the state.
Another waste from coal mining is the solid waste rock left behind from tunneling or blasting. This can result in a number of environmental impacts previously discussed, including acid mine drainage (AMD). A common problem with coal mine legacies is the fact that if a mine is abandoned or a mining company goes out of business, the former owner is under no legal obligation to cleanup and monitor the environmental wastes, leaving the responsibility in the hands of the state.
Effects on Communities
Coal mining can also have serious impacts on nearby communities. In addition to noise and dust, residents have reported that dynamite blasts can crack the foundations of homes , and many cases of subsidence due to the collapse of underground mines have been documented. Subsidence can cause serious damage to houses, roads, bridges, and any other structure in the area. Blasting can also cause damage to wells, and changes in the topography and structure of aquifers can cause these wells to run dry.
Transportation of Coal
Transporting coal from where it is mined to where it will be burned also produces significant quantities of air pollution and other environmental harms. Diesel-burning trucks, trains, and barges that transport coal release NOx, SOx, PM, VOCs (Volatile Organic Chemicals), CO, and CO2 into the earth’s atmosphere. Trucks and trains (barge pollution data are unavailable) transporting coal release over 600,000 tons of NOx, and over 50,000 tons of PM10 into the air annually. , In addition to health risks, black carbon from diesel combustion is another contributor to global warming. Land disturbance from trucks entering and leaving the mine complex and coal dust along the transport route also release particles into the air. For example, in Sylvester, West Virginia, a Massey Energy coal processing plant and the trucks associated with it spread so much dust around the town that “Sylvester’s residents had to clean their windows and porches and cars every day, and keep the windows shut.” Even after a lawsuit and a court victory, residents – who now call themselves “Dustbusters” – still “wipe down their windows and porches and cars.”
Almost 60 percent of coal in the U.S. is transported at least in part by train and coal transportation accounts for 44% of rail freight ton-miles. Some coal trains reach more than two miles in length, causing railroad-crossing collisions and pedestrian accidents (there are approximately 3000 such collisions and 900 pedestrian accidents every year), and interruption in traffic flow (including emergency responders such as police, ambulance services, and fire departments). Local communities also have concerns about coal trucks, both because of their size and the dust they can leave behind. According to one report, in a Kentucky town, coal trucks weighing 120 tons with their loads were used, and “the Department of Transportation signs stating a thirty-ton carrying capacity of each bridge had disappeared.” Although the coal company there has now adopted a different route for its trucks, community representatives in Appalachia believe that coal trucks should be limited to 40 tons.
Coal is also sometimes transported in a coal slurry pipeline, such as the one used at the Black Mesa Mine in Arizona. In this process the coal is ground up and mixed with water in a roughly 50:50 ratio. The resulting slurry is transported to a power station through a pipeline. This requires large amounts of fresh groundwater. To transport coal from the Black Mesa Mine in Arizona to the Mohave Generating Station in Nevada, Peabody Coal pumped over one billion gallons of water from an aquifer near the mine each year. This water came from the same aquifer used for drinking water and irrigation by members of the Navajo and Hopi Nations in the area. Water used for coal transport has led to a major depletion of the aquifer, with more than a 100 foot drop in water level in some wells. In the West, coal transport through a slurry pipeline places additional stress on an already stressed water supply. Maintenance of the pipe requires washing, which uses still more fresh water. Not only does slurry-pipeline transport result in a loss of freshwater, it can also lead to water pollution when the pipe fails and coal slurry is discharged into ground or surface water. The Peabody pipe failed 12 times between 1994 and 1999. The Black Mesa mine closed as of January 2006. Its sole customer, the Mohave Generating Station, was shut down because its emissions exceeded current air pollution standards.