Senate Energy Committee
Oil Shale Field Hearing
Grand Junction, Colorado
June 1, 2006

Members of the Committee, Colorado Congressional members and staff, and local officials -- welcome to Western Colorado.  I am Russell George, Executive Director of the Colorado Department of Natural Resources (DNR).  As the lead state agency responsible for natural resource management, I appreciate the opportunity to present our latest thoughts on oil shale development on behalf of Colorado Governor Bill Owens. 

In April 2005, I presented detailed testimony focusing on what worked and what did not work in the oil shale boom of the early 1980’s – including, federal incentives, cumulative impact assessments, coordinated permitting, technology implications, and environmental concerns. It was my hope, then as now, that oil shale development will proceed in a fashion that will allow for adequate public review and comment and regulatory oversight at the state and local level. 

Today, I would like to amplify those comments specific to the socioeconomic impacts of oil shale development, as well as issues related to water quantity and quality, and the need for power generation to develop of the oil shale resource.  I do so with the caveat that many project specifics are unknown pending the submittal of permit applications. 

Background Principle

The State of Colorado has consistently supported the development of oil shale resources in Northwest Colorado since the Arab Oil Embargo of the early 1970’s.  Our focus has been to ensure that the projects are fiscally and environmentally sound, and that the communities do not incur extraordinary economic burdens either before the boom or after any bust.  As history has shown, if development pays its way, the community impacts are less if the projects do not materialize.  With perhaps as much as two trillion barrels of oil locked in the shales of western states, it is important for federal, state and local governments to partner in the development of this vast resource. 

While we still do not know the specifics of the technologies and projects that may be pursued in the current research and commercialization cycle, we do know water availability, materials handling, power requirements, and transportation networks must be assessed in detail and the impacts mitigated in an appropriate and timely manner. 

Where we are today.

We have record coal production that is straining existing transportation networks.  We have record natural gas production levels and ever increasing permit applications for natural gas development.  The development of this resource has dotted the landscape, increased truck traffic on county roads, and access to the resource has impacted many private landowners where the surface and mineral estates are severed.  Additionally, there is a growing public sensitivity to in-situ activities, such as fracking with “proprietary fluids.”

This development overlaps an area with increasing tourism and recreation opportunities and an expanding urban population.  Oil shale leasing on top of this existing network of energy development and changing land uses may put more pressure on an already fragile ecosystem and public temperament. 

The federal Programmatic Environmental Impact Statement (PEIS) is underway, and the details will be critical.  A prioritized use of public lands for the development of specific resources is essential.  Federal financial support must be sustainable over several decades to encourage private sector investment.  The environmental review process must be thorough.  A financial safety net for local governments that allows for growth to pay its way, and allows front-end financing of infrastructure assessment tools and capital needs, is critical.  Technology and environmental oversight must be rigorous, and developers must use the best available practices to minimize impacts.  Environmental regulatory standards must be set in a way that addresses impacts in the Research, Development, and Demonstration (RD&D) phase as well as the commercial phase in order to achieve desired production levels.  In addition, the cumulative impact of mineral and energy development on both public lands and private lands must be mitigated. 

DNR intends to participate either formally or informally, in the preparation of the PEIS.  During the development of the PEIS, DNR will work with the BLM and other interested entities to ensure that the concerns expressed here are reflected and addressed in the PEIS.  The timeframe for development of the PEIS is very aggressive because of the mandate established in the Energy Policy Act of 2005.  This timeframe and the magnitude of the issue will result in additional demands on DNR staff.  We are prepared to spend the resources necessary to participate in the development of the PEIS because of the importance of this issue to the residents of Colorado.

During the past year my department has participated in the review and evaluation of the Research, Development, and Demonstration (RD&D) proposals submitted by industry to the Bureau of Land Management. The evaluation group included representatives of the governors of Utah and Wyoming, Department of Energy, Department of Defense, and Bureau of Land Management. Ten of the twenty proposals to demonstrate the commercial viability of oil shale were located in Colorado and five of those have advanced to the final stages of approval by BLM.

Our State Geologist also worked with the State Geologist of Wyoming, with BLM personnel, and the Utah Geological Survey to develop the geologic setting and Reasonable and Foreseeable Development scenario for the initial stages of the Environmental Impact Statement for the area-wide commercial leasing of oil shale mandated in the 2005 Energy Bill.  The Department is also providing information and working with BLM during the development of this PEIS.  Finally, my office has been working with the Department of Energy Task Force on Strategic Unconventional Fuels. 

Development Impacts and Carrying Capacity

A key component of the socioeconomic impact of intense and rapid oil shale development is the cumulative impact of growth on the carrying capacity of the region.  Given the density of natural gas and coal development in some areas of NW Colorado, the need for recreational/wildlife habitat/undeveloped areas, and the network of privately held oil shale lands that did not exist in the last boom, the federal government must determine those areas where oil shale development could be accommodated in a manner that is least disruptive to communities and existing activities.  Not all types of resource development can occur everywhere.  The carrying capacity of the land, communities and infrastructure must be evaluated.  That will determine the suitable areas for coal, natural gas, and oil shale development – as well as realistic production scenarios. 

One type of mineral and energy development today, may preclude or limit another type of resource development tomorrow.  We cannot forget that a consequence of the oil shale pull-out of the 1980's, and the sustained soft energy market in the 1990’s, has been the transformation of the NW Colorado economy from an energy base to a tourism, retirement, second home and recreation base -- and public attitudes have changed as well.  That cannot be underestimated if accelerated development is to occur. 

The Department of the Interior should provide this cumulative impact analysis and identification of areas suitable for oil shale development as an element of any environmental review, leasing plan, and build out over time.  Existing resource management plans may also need to be amended and impacts mitigated.

Cumulative Economic Impact

Once the development area is determined, a procedure must be established to evaluate economic impacts at the local level.  The federal government should fund, either through a bonus bid process or other authorizing legislation, a process to analyze the cumulative financial impacts of multiple and simultaneous resource development.  This analysis would not only guide the timing of needed permanent and temporary community services and infrastructure, but also allow local governments to establish fiscal tools that would insure that growth could pay its own way. 

To assess the fiscal impact to individual communities and counties in high development areas, it is essential to model the budgets, revenues and expenditures of affected jurisdictions in Northwest Colorado.  The key task would be to determine what projects would cause what economic impacts to what jurisdictions in what years based on different population and development scenarios. 

Financial Impact Mitigation

Another component of socioeconomic impacts is the financial burden to local economies to mitigate those impacts.   Along with an oil shale lease process that generates production royalties for the federal government, the 1970's concept of the front end bonus bid should be applied to any oil shale leases.

The federal government leased two tracts in each state-– Colorado, Utah, and Wyoming-in the early 1970’s.  Bonus payments accompanied each of these leases—that determined the winning bid for the lease.  Half of those bonus payments were distributed back to the state.  The Colorado General Assembly established the State Oil Shale Trust Fund and Program which developed planning and coordination mechanisms for federal, state, and local governments and provided funding for designated local government services and projects ($100+ million).  This economic cushion is essential to community stability, and the ability to withstand the economic shock of a project termination.  The federal leasing program should include front-end financing for infrastructure needs and impact mitigation –with the objective to mitigate the “boom town” syndrome.

The federal government should not subsidize private investment by foregoing revenues that would mitigate financial impacts at the state and local level.  If favorable tax and royalty terms in the early years are necessary, the federal government must identify the alternative source of state and local impact mitigation funds.  A cumulative economic assessment will determine the necessary amount.  This analysis would identify major infrastructure requirements, including roads, sewer, water supply and storage, schools and key government services.  The investment of industry funds to mitigate these impacts should coincide with the project development schedule.  Industry funds should also finance the local government planning and permitting requirements.  It will also include the financial reserves necessary to maintain the services, facilities and infrastructure well before industry-generated revenues are available.

If the federal government is willing to forego front-end revenues, a credit against future federal royalties for investment by operators in the socio-economic and infrastructure needs identified by the affected state/local governments is another option.  Make no mistake, this will still be a significant upfront investment by industry as well as lost federal revenue—but it would also send the money directly to the area in need in a timely and efficient manner.  Provision of adequate funds should be a necessary and binding condition of any commercial lease.

A condition for a project to move forward should be that no unfunded liabilities should exist for the affected local government.  History has proven that low rate loans, loan guarantees and bonds are not practical, if the project and associated future revenues do not occur.  Outstanding financial obligations by local entities are not an option.  Upfront payment in full for the needed infrastructure and impact mitigation has been proven to be the only effective safety net if a bust occurs.

Coordinated Permitting Process 

To fully understand the socioeconomic and environmental impacts of oil shale development, a coordinated and integrated permitting process is essential.  The environmental and land use permitting process can be complex and time-consuming when all the local, state and federal requirements are considered.  Coordinating the process is essential, and cannot be underestimated.  For the requirements in place 20 years ago, the average timeframe to permit an oil shale project was about 42 months.  Some processes have become more complex since then -- and certainly public interest is more organized and focused. 

As a reminder, the Colorado Joint Review process grew out of the concerns raised over the concept of the Energy Mobilization Board.  That Board would have had the power to preempt local and state regulatory requirements in the national interest.  The reaction in the West was to coordinate and streamline, not dismantle, the existing process.  And it worked.  Attempts in recent years to truncate the process have been met with public criticism and lawsuits.  Such efforts have proven to be counterproductive to the goal of developing these important resources.

Community acceptance is the only way to avoid what could be well organized and sophisticated opposition to oil shale development.  Seeking, tracking and addressing stakeholder concerns and encouraging participation is essential for project implementation in the timeframe contemplated by Congress.

Today’s Colorado Coordinating Council is an option that the federal government should consider fully funding, or partially funding along with industry, to assure a rigorous review with adequate public input and consultation.  A coordinated permitting process will reduce uncertainties by clarifying technical requirements, timeframes, lead regulatory agencies and public input.

The outcome is a centralized facilitation of the permit process at the local, state, and federal level.  The council would determine the timelines of the various required permits, coordinate the scoping process for the environmental impact statements, and facilitate public hearings and public comments.  The overall coordination of the effort could allow for the application of several permits for an individual project to occur simultaneously. 

Power Generation Requirements

According to the RAND report, an in-situ extractive type operation is estimated to consume 1000 MW of dedicated electrical generating capacity for each 100,000 barrels of shale oil produced daily.    The power requirements for the commercial base will be based on the technologies used.

But, here is where we are today.  Colorado’s current permitted coal production capacity is about 48 million tons – about 10 million tons higher than current production.  The Craig power Plant, at 1274 MW, uses 5 million tons of coal annually.  Therefore, the current productive capacity could fuel two Craig Plants.  The key is rail transportation.  We urge Union pacific and private investors to resolve those infrastructure needs.  Increasing permit capacity at existing mines is a relatively routine process; construction of new coal mines -- of which one may be in the works for Northwest Colorado -- could take several years to permit and construct.

Xcel Energy tells us that their current system on the Western Slope is anticipated to be in balance for the next couple of years – with some supply relief when the Comanche 3 plant comes on line in 2010.  The company intends to compensate for additional growth by buying from other regions – or building, if necessary.

Water Requirements

Water will be required for communities, recovery processes, disposal and reclamation purposes.  Requirements vary by technology, and will not become apparent until the RD&D applications are submitted.  Colorado’s permitting process requires a permit applicant to provide an estimate of project water requirements, to include flow rates and annual volumes for development, mining and reclamation.  The applicant must also indicate projected amounts from each of the sources of water.  It is yet to be determined if the public or the private sector will be required to develop the necessary water storage facilities if senior water rights are not available.  It may be necessary for the federal government to play a significant role in defining, planning and constructing the necessary water storage and distribution systems.

The U.S. Water Resource Council estimates that oil shale development will increase annual consumptive water use in the Upper Colorado Region by about 150,000 acre-feet per year for each million barrels (oil equivalent) per day of production, about a 3 to 1 ratio water to oil.  The range given is 2.1 to 5.2 barrels of water per barrel of shale oil produced dependent upon the extractive technology used. The RAND report goes on to say that the availability of water in the region does not appear to be a “constraining factor,” but this statement is too simplistic.  What certainly is a continuing factor is the water supply infrastructure. 

Air and Water Quality

The permitting issues at the RD&D and commercial phases are yet to be determined based on the permit submittals.  Probably the best overview of air and water quality issues is contained in the 2005 Rand Report.  Let me summarize several of the issues that permitting agencies will review and applicants must mitigate.

Air Quality.  The proposed development regions are high quality Class II areas.  Therefore, only moderate increases in ambient air quality pollution levels are allowed.  Specially protected areas are within the Piceance Basin—including the Flat Top Wilderness Area.

Oil shale operation emissions may emit pollutants currently on the list of air toxins by the Clean Air Act.  The Rand Report recommends an approach in which emissions limits for initial plants are established so that future production can occur within the allowable PSD Class II and Class I increments.  This could be useful input for the Programmatic PEIS and any work by the Air Quality Control Commission of the Colorado Department of Public Health and Environment.

Water Quality.  The regulatory structure for water quality is an evolving science for hybrid mineral and energy extraction methods such as those proposed in the first round of RD&D leases. 

SB 89-181 delegated authority to the Oil and Gas Conservation Commission and the Division of Minerals and Geology for ground water.  Classification as a Designated Mining Operation will require an Environmental Protection Plan by the Division of Minerals and Geology.  Drill hole casing requirements may be set by the Oil and Gas Conservation Commission for enforcement by the Division of Minerals and Geology.  Class II, III and V underground injection wells will be subject to state or federal oversight depending on the type and liquids used.  The Water Quality Control Commission will regulate surface water; and the Hazardous Waste Program may have oversight of waste disposal.  So, the regulatory regime will be a function of the technology employed.

Conclusion

It is essential that Congress consider the life cycle of oil shale development as it unfolds its national oil shale effort.  Only this view will portray the complete picture, so that the appropriate technology, environmental and economic structures can be defined and funded for a successful long-term effort.  I look forward to working with you in the months ahead. 
 

Mr. Chairman and Members of the Committee:

My name is Kim Cook, County Commissioner of Rio Blanco County, Colorado. I am here today to present testimony on behalf of Rio Blanco County and two organizations that Rio Blanco County is a member of; Club 20, a community based organization representing cities, counties, businesses and citizens throughout Western Colorado; and the Associated Governments of Northwest Colorado (AGNC), which represents the cities and counties in the five-county region of Mesa, Garfield, Rio Blanco, Moffat and Routt.

I would like to begin my remarks by referring back to comments made by AGNC before this committee in April 2005, when we gave the overall impression that local governments were pleased with the course that the Federal government was taking during this time of oil shale development. We further commented on the need for supporting local governments’ ability to mitigate socioeconomic and environmental impacts.

In fact, not much has changed in the minds of AGNC members.  We still believe oil shale presents an opportunity to provide a secure domestic fuel source. And, we still believe that since more than 80% of the oil shale resource is located on federally-owned public land and recognizing that the future development is driven by national interests, the federal government must play a lead role in addressing the socioeconomic and environmental impacts and costs.  We do not want to see local governments (and local taxpayers) stuck with the costs of new infrastructure and the mitigation of environmental impacts.   

As an example, you must travel on Rio Blanco County roads to reach all of Colorado’s oil shale RD&D leases.  These roads have no base, or at best a shale base, and were never designed for the heavy energy traffic we are currently experiencing due to gas drilling, and expect to receive from oil shale development

To reconstruct one mile of paved road so that it is designed to carry heavy loads currently costs approximately $1 million.  With 65 miles of paved roads in the Piceance Basin at present and the possible need for more asphalt roads in the future, that is a cost that that cannot be born by Rio Blanco’s 6500 citizens.

Rio Blanco County has concerns related to the initial DOE report to Congress on “Development of America’s Strategic Unconventional Fuels Resources.”  Efforts to develop “A fiscal regime that improves attractiveness of capital investment through tax and royalty terms in the early years” need to provide adequate compensation to state and local funds which would normally use these revenue streams to mitigate development impacts.  Proposed incentives to industry relating to royalties, severance tax, and property tax are likely to be detrimental to current sources of local revenue available to mitigate impacts and develop local infrastructure.  Allowing capital costs for unconventional fuels to be expensed or depreciated on an accelerated schedule could also have a negative effect on local taxes derived from real and personal property.  Likewise, production tax credits could negatively affect severance tax revenues which contribute to the Energy and Mineral Impact Assistance fund--our major source of grants for impact mitigation.

Funding for socioeconomic impact assessment and community infrastructure planning and development is very important.  This needs to be followed up with funding for implementation of these plans and for the operation and maintenance of the expanded infrastructure as well.   Much of this region lies within the public domain and has low population density, both of which limit the ability of local governments to study and finance large scale improvements.  Therefore, establishing a federal impact fund and/or a local/regional trust fund for the mitigation of impacts is critical to local government efforts to mitigate impacts and create new infrastructure.

Rather than cutting corners in “streamlining” regulatory processes or gutting existing processes and procedures, the integrated program plan should allocate funds to provide levels of staffing to these agencies (BLM, FERC, EPA, etc.) which are adequate to produce the needed throughput in the desired timeframes.  Cooperation between intra-agency regions (ie: BLM White River Field Office and Vernal Field Office) as well as between agencies should not only be streamlined but required.  Be careful in granting regulatory agencies quasi-judicial powers; placing such power in federal agencies risks the loss of local participation in the decision making process.  The Colorado joint review process is a model to be encouraged for interagency cooperation.

The Colorado-Wyoming-Utah transportation network needs study and funding to develop efficient and time-effective routes between development sites, communities, and markets.  Interstate traffic, even in the current natural gas development boom, follows inadequate and circuitous routes throughout this region.  State funding for maintenance of existing roads, much less the development of new roads, is not sufficient for the task.  Significant interstate traffic is occurring on county roads which were never designed for such impacts and stretch limited county resources to maintain.  Such a regional study in conjunction with the development of unconventional resources should involve state, federal, and local governments in planning, development, and funding.

The future needs of the electrical power infrastructure in the Piceance Basin, considering the current conventional natural gas development and the potential oil shale need for in-situ heating, may be very significant and beyond the current capacity.  The demand for electrical power might be best addressed in conjunction with other unconventional resources such as a coal gasification process to generate electricity.   Rio Blanco and Moffat Counties have significant coal resources, current CO2 injection in the Rangely Weber Sand oil field, along with the need for additional electrical power in the Piceance Basin. 

Rio Blanco County hopes that research park development and community college training programs would be housed within the immediate locale being affected by the resource development, as these types facilities help grow and diversify the local economy and provide for the tax base of the local governments.  Any community college unconventional resource programs should include Colorado Northwestern Community College.

Finally, a small number of corporations within the industry have already invested significant private funds in oil shale research and development.  Any new federal incentives and initiatives to accelerate the research and development process need to respect this investment and avoid inclusion of those corporations or companies operating in a more speculative and opportunistic fashion.

One final AGNC concern has to do with the funds being accumulated in the U.S. Treasury through the oil and gas lease payments that are occurring on the Naval Oil Shale Reserve lands

Last year we reported to you that in a letter from the Department of Interior, some $44 million may be accumulated by March 2007 in a U.S. Treasury account from the current natural gas leases on their NOSR lands.  These NOSR lands were transferred by Congress from DOE to the Department of Interior with a Congressional priority established for natural gas leasing.

Some of these funds, estimated at $6 million, are earmarked for environmental cleanup of the Anvil Points spent shale pile.  Otherwise, we believe Congress has the opportunity for the remainder of these funds to be made available to address the socioeconomic and environmental aspects of oil shale development in Northwest Colorado.

In the future, more revenue should be available from this source.  According to industry estimates, additional leasing of the NOSR lands could produce leasing bonuses of up to $360 million (to be shared 50% federal and 50% state), plus ongoing production leases of an estimated $32 million annually for at least 20 years.  That would be another $640 million total also to be split 50/50, federal and state.  Congress should establish a priority to address oil shale and other energy development impacts in Northwest Colorado from these leasing revenues.

However, on December 15, 2005, Colorado State BLM Director Sally Wisely informed AGNC that, as of November 29, 2005, the Treasury had accumulated $37 million.
This leaves only $7.25 million left to be collected. With recent increased gas prices, royalties are averaging $1.25 million per month over the past 11 months. At this rate, the remaining funds should be recouped by June 2006, nearly a year ahead of schedule.

The Transfer Act states that the Secretaries of Interior and Energy must jointly certify to Congress that the monies have been recouped prior to making revenue available for distribution to the State of Colorado.  As these funds should be recouped by June, DOI and DOE should currently be coordinating the certification process to Congress.

We respectfully request that the Committee monitor the activities of these Departments in the coming months and push for the earliest possible release of these funds to the states upon certification, per section 7439 (f) (2) of the Transfer Act. 

We believe this type of funding is necessary to make sure the DOE research and demonstration projects can proceed without interruptions from fluctuations in the price of oil.

Attached to my testimony is an Oil Shale Policy Resolution from Club 20, which is the coalition of individuals, businesses, and local governments representing Western Colorado since 1953.

As indicated in the resolution, Club 20 supports the current R & D leasing program underway to test various oil shale technologies.  Three of the leasing applicants are located in Rio Blanco County—Shell, Chevron and EGL.  Club 20 supports the conversion of these to commercial scale if the technology proves out.

Club 20 also supports a prudently paced commercial scale leasing program including the Environmental Impact process now being initiated by BLM.  We believe the carrying capacity provisions being considered in the EIS will help protect our Western Colorado air quality, water resources, wildlife, and socioeconomic values.  Club 20 also supports the establishment of a commercial scale royalty credit, proposed by AGNC, to encourage companies to contribute to the mitigation of socioeconomic and environmental impacts.  These mitigation efforts are very important to Rio Blanco County, where most of the development of federal oil shale resources will occur.

Club 20 also appreciates the involvement and participation of local governments in both the DOI Oil Shale leasing program (with affected local governments designated cooperating agency status) and the DOE Strategic Fuels Program (with a local government representative as a member of the Task Force on Strategic Unconventional Fuels).

I would like to thank the Committee for coming holding this field hearing here in Northwest Colorado.  I would be happy to answer any questions you may have.

Kim Cook
Rio Blanco County Commissioner

Attachment
Club 20 Oil Shale Policy

TESTIMONY OF STEPHEN MUT, PRESIDENT OF SHELL UNCONVENTIONAL RESOURCES ENERGY, BEFORE THE U.S. SENATE ENERGY AND NATURAL RESOURCES COMMITTEE FIELD HEARING ON POTENTIAL OIL SHALE DEVELOPMENT IN COLORADO, UTAH and WYOMING
JUNE 1, 2006
GRAND JUNCTION, COLORADO
Good morning, Mr. Chairman, Senator Hatch, and Senator Salazar. My name is Stephen Mut and I lead Shell Unconventional Resource Energy.

As you know, for about a quarter of a century, Shell has been working to develop and to advance, hopefully to commercial success, an innovative technology which we are increasingly optimistic can open up the vast oil shale resources located in the Rocky Mountain area. This technology, once thoroughly proven, will allow Shell to produce clean, high quality transportation fuels such as gasoline, jet fuel and diesel as well as clean burning natural gas from oil shale in an economically viable and very environmentally sensitive fashion. Because the oil shale resource in the United States represents the largest, most concentrated onshore “hydrocarbon” resource on Earth, Shell’s ICP technology holds promise for significantly increasing U.S. domestic energy production. When unlocked, this critical national asset will help to provide an energy bridge to 22nd century clean energy. If these resources are properly managed, there is the potential to reduce price volatility and political turbulence caused in part by tight energy supply-demand balances.

As a diversified energy and petrochemicals company, Shell is investing heavily in a wide variety of energy sources, including renewables such as wind, solar, and hydrogen. We are making progress increasing the role those energy sources will play in the energy mix, but in the meantime America and the world will continue to need oil and natural gas to meet rapidly growing energy demand.

For decades, energy companies have been trying, without success, to transform oil shale resources here in the West into affordable energy products. Oil shale can be found in large parts of the Green River Basin and is over 1,000 feet thick in many areas. According to DOE estimates, the Basin contains in excess of 1 trillion recoverable barrels of hydrocarbons locked up in the shale. It is thus easy to see why this vast resource has remained a target.

In 1982 Shell commenced laboratory and field research on a promising in ground conversion and recovery process. This technology is called the In-situ Conversion Process, or ICP. In general terms the ICP process accelerates the natural process of oil and gas maturation by literally tens of millions of years. This is accomplished by slow sub-surface heating of petroleum source rock containing kerogen, the precursor to oil and gas. This acceleration of natural processes is achieved by drilling many holes into the resource, inserting electric resistance heaters into those heater holes and heating the subsurface over a 3 to 4 year period. During this time very dense oil and gas is expelled from the kerogen and undergoes a series of changes that allow the lighter hydrocarbon products that are more mobile to move in the subsurface through existing or induced fractures to conventional producing wells from which they are brought to the surface. The process has the potential to produce a significant proportion of the original carbon in place in the subsurface—substantially more than the normal recovery efficiency of conventional oil and gas production. The carbon that remains in the subsurface resembles a char, is extremely hydrogen deficient, and if brought to the surface, would require extensive energy-intensive upgrading and saturation with hydrogen. We call this process Smart Carbon Sequestration because the easiest carbon to sequester is that which is not brought to the surface in the first place.

Since 1996, Shell has successfully carried out five small field tests on its privately owned Mahogany property in Rio Blanco County, Colorado. In the most recent test conducted in 2004 and 2005, more than 1,500 barrels of light oil plus associated gas were produced from a very small test plot using the ICP technology. We are pleased with these results, not only because oil and gas was produced, but also because it was produced in quantity, quality and on schedule as predicted by our computer modeling.

As an update, Shell has commenced work on the first of two final tests needed to prove the technology commercially viable. The first of these is a purely environmental test of the capacity of our freeze wall technology to protect the groundwater system from the ICP process and the ICP process from the groundwater. We hope to replicate the results from our initial freeze test performed in 2003, this time by building a football field sized freeze wall that will extend down to commercial depths. This larger size and
greater depth will give us sufficient information to allow us to confidently scale up to commercial size. Once the freeze wall is created and found to properly contain, we plan to stress test it to failure and then test various repair techniques. Over the next 18-24 months, we will gain sufficient knowledge to validate the adequacy of this technology in a commercial setting.

Secondly, once the BLM completes its ongoing oil shale R&D leasing processes and issues the leases for which Shell has applied, we intend to proceed with permitting and then development of a small oil shale production test in which we would expect to produce 500-1500 barrels of oil and gas per day to validate our 24 years of research again at a size and in an area that would allow us to scale up to a commercial development.

It is important to point out that the cost of all of these past and presently projected field tests has been entirely on Shell’s dime and none of the projects have been underwritten by any governmental dollars whatsoever.

When these two field tests have advanced sufficiently over the course of the next several years, we will have gained sufficient technical knowledge to validate the technology as an integrated unit. It is important to remember though, that we are still in a research mode and that any final decision on a commercial development would come near the end of this decade.

Though the DOE estimates that this general part of the tri-state area may contain in excess of 1 trillion barrels of potentially recoverable hydrocarbon resources, or some four times the reserves found in Saudi Arabia, we at Shell say that it contains somewhere between zero and a huge amount of marketable energy barrels. On the upside, it is important to remember that technology and its limits will determine how much of this resource can be economically recovered. On the downside, we remind ourselves that “Zero” barrels is a possibility because no one has yet been able to develop oil shale on a sustainable commercial basis. In order to meet this challenge Shell or any other company must clear three distinct hurdles:

• Demonstrate that its recovery technology would be viable on a commercial basis at oil prices lower than today’s levels
• Demonstrate the capability for protecting the environment, and
• Minimize socioeconomic impacts to surrounding communities and their citizens.

These criteria collectively translate into Sustainable Development---one of Shell’s core principles. Stated more simply it means caring for People, the Planet, and Profits.
Relative to protection of the environment, the ICP process has a number of positive attributes. Despite the fact that ICP requires substantial amounts of electricity, the reduced processing required for the lighter cleaner product mix when combined with sequestration of concentrated CO2 streams may result in a carbon dioxide footprint on par with and in some cases better than existing heavy oil production on a life cycle basis. The concentration of the resource leads to a smaller physical footprint and one that can be rather easily reclaimed. The in-situ nature of the process eliminates tailings piles. Process and cooling water needs are reduced relative to past efforts. Though it may not be as economic, we would likely move to air-cooling to reduce project water demand. Groundwater is protected by a robust freeze-wall. We are working to achieve a combination of these ingredients that will create an environmentally attractive package.

Equally importantly, Shell is committed to working closely with the communities in this area first to identify issues and then to develop plans to address, in advance, the potential socio-economic impacts of a commercial development. Even though Shell is still several years away from making a commercial decision, we anticipate commencing very early substantive discussions with a range of community stakeholders in this area to begin to analyze potential community impacts and to partner together to find solutions. We feel it is critically important to commence this more specific dialogue long before we make any firm decisions as to what a commercial oil shale project might look like. By doing so, we can jointly identify potential infrastructure and socioeconomic impacts that might arise from large-scale development and then jointly move forward to arrive at responsible and practical solutions to satisfy those identified needs. So later this year or early next, we hope to begin this collaborative process with area stakeholders. This will mean publicly identifying in nominal terms the potential size, scope and impact of a commercial operation. It will not mean that Shell has made any specific decisions because those are still years away. But just as in any commercial project, we find that spending more time, effort and money upfront with our stakeholder partners almost always results in a better and more fiscally sound development.

Finally, we feel strongly that government has a significant leadership role to play in the development of oil shale. We feel that the leadership role for government is best channeled in four specific areas including:

I will be happy to address any questions you might have.