Hearings and Business Meetings
June 1, 2006
250 North Street Grand Junction, CO Grand Junction City Hall Auditorium 09:30 AM
Mr. Russell George
Executive Director , Colorado Department of Natural Resources
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.
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 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.
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.