The Fourth Assessment Report of the Intergovernmental Panel on Climate Change (www.ipc.ch) includes these conclusions:
1. Global Greenhouse gas emissions (carbon dioxide, methane, nitrogen oxide, etc.) have grown since pre-industrial times, with a 70% increase between 1970 and 2004. CO2 emissions have grown between 1970 and 2004 by about 80% and represented 77% of total anthropogenic GHG emissions in 2004.
2. The largest growth in global GHG emissions between 1970 and 2004 has come from the energy supply sector (an increase of 145%). On a brighter note, during that same period, the emissions of ozone depleting substances controlled under the Montreal protocol, such as halons, chlorofluoro- and hydrochloroflouorcarbons, carbon tetrachloride, which are also GHG gases, dropped to about 20% of their 1990 level.
3. With current climate change mitigation policies, global GHG emissions will continue to grow over the next few decades.
4. Globally, many natural systems are being affected by regional climate changes, and it is likely that anthropogenic warming has had a discernible influence on many physical and biological systems.
5. There is substantial economic potential for mitigation of global GHG emissions over the coming decades that could offset the projected growth or reduce emissions below current levels in all sectors – energy supply, transport, buildings, industry, agriculture, forestry, and waste management. The IPCC Report Summary for Policymakers includes a chart summarizing key mitigation technologies and practices by sector, which is included in the appendix.
6. Policies that price carbon could create incentives for producers and consumers to significantly invest in low-GHG products, technologies and processes. Such policies include economic instruments, government funding and regulation. A chart from the IPCC Report reflecting practices and policies that were identified as effective.
In June 2005, the U.S. National Academy of Sciences joined with the scientific academies of ten other countries in stating that “the scientific understanding of climate change is now sufficiently clear to justify nations taking prompt actions.”
There is general agreement within the scientific community, that emissions of greenhouse gases should be reduced by 60-80% by mid-century to minimize irreversible effects of climate change. There is also general consensus that we have a relatively brief period in which to restructure the manner in which we produce and consume energy, before the exigencies of climate change will impose more dramatic costs on our communities and our economy and narrow our options to mitigate, rather than adapt, to climate change.
b. Growing Business Consensus On Need For National Response
The United States Climate Action Partnership, a group of businesses and six of the nation’s leading environmental organizations, have issued a collective call for the federal government to swiftly enact legislation that includes mandatory significant reductions of greenhouse gas emissions from all sectors through a mandatory market-based cap-and-trade system. Members include Duke Energy, GM, GE, Ford, Alcoa and Alcan, and many others.
In the CAP “Call to Action,” the CAP noted that:
each year we delay action to control emissions increases the risk of unavoidable consequences that could necessitate even steeper reductions in the future, at potentially greater economic cost and social disruption. Action sooner rather than later preserves valuable response options, narrows the uncertainties associated with changes to the climate, and should lower the costs of mitigation and adaptation.
The CAP proposed a U.S. policy framework that includes:
mandatory approaches to reduce greenhouse gas emissions from the major emitting sectors including emissions from large stationary sources, transportation, and energy use in commercial and residential buildings that could be phased in over time, with attention to near-, mid- and long-term time horizons;
flexible approaches to establish a price signal for carbon that may vary by economic sector and could include, depending on the sector: market-based incentives; performance standards; cap-and-trade; tax reform; incentives for technology research, development, and deployment; or other appropriate policy tools; and
approaches that create incentives and encourage actions by other countries, including large emitting economies in the developing world, to implement GHG emission reduction strategies.
The CAP “Call for Action” can be found at www.us-cap.org. It calls for a mandatory emission reduction pathways with specific short and mid-term targets of stabilizing emissions within five years, lowering to 90% within 10 years, and a reduction to between 70-90% of today’s levels within 15 years with a target of 60 – 80% reduction from current levels by 2050. A national emissions baseline registry is also recommended.
With respect to coal-based energy facilities and other stationary sources, the CAP calls for policies to speed transition to low- and zero-emission stationary sources that can cost-effectively capture CO2 emissions for geologic sequestration, and for EPA to promulgate regulations to permit long-term geologic sequestration of CO2 from stationary sources, with funding for three demonstration projects in depleted oil and gas fields and saline aquifers at levels equivalent to emissions produced by a large coal-based power plant.
c. Congressional Response
Attached is a chart showing the current bills before Congress on climate change.
d. Impact on Coal’s Future in a Carbon Constrained World
The National Academies of Science has released a prepublication version of a new report entitled Coal: Research and Development To Support National Energy Policy, which has a number of findings that are significant to those gathered here and to our Commonwealth.
The NAS made these observations:
The context for any assessment of future coal production is inextricably linked with the development of a national carbon emissions policy. Potential constraints on greenhouse gases (especially CO2) emissions, and the technical and economic feasibility of CO2 control measures, are the dominant issues affecting the outlook of the future of coal use over the next 25 years and beyond. The difficulty of predicting prices and availability of alternative energy sources for electric power generation provides additional uncertainty.
The NAS Committee, which was charged with the task of reviewing coal resources assessments, technologies and research and development activities to determine priority coal R&D needs, including areas of exploration, discovery, reserve assessment, extraction, preparation, transportation, waste disposal, reclamation, health and safety, community impact, environmental practices, education, training and productivity, made a number of recommendations for increased investment in R&D to assure that the nation’s coal resource is used efficiently, safely and in a more environmentally responsible manner, and recommended significant increases in funding for environmental protection, reclamation, resource mapping and characterization and mining productivity.
If coal is to continue as a primary component of the nation’s future energy supply in a carbon-constrained world, large-scale demonstration of carbon management technologies – especially carbon capture and sequestration (CCS) are needed to prove the commercial readiness of technologies to significantly reduce CO2 emissions from coal-based power plants and other energy conversion processes. In addition, detailed assessments are needed to identify potential geological formations in the United States that are capable of sequestering large quantities of CO2, to quantify their storage capacities, to assess migration and leakage rates; and to understand the economic, legal and environmental impacts of both near-term and long-term timescales.
Reflecting that uncertainty, the NAS reflected that the assessment of forecasts for coal use in the next 15 years ranged from 25 percent more to 15 percent less than 2004 levels, and from 70 percent higher to 50 percent lower by 2030.
The NAS panel also critically assessed the oft-stated claim that our nation has 250 years of coal supply, noting that the present estimates are based on methods that have not been reviewed or revised since 1974, and may be significantly overstated. The NAS recommended a coordinated federal-state-industry initiative would be important to determine the magnitude and characteristics of recoverable coal reserves.
II. Kentucky’s Situation
Nationally, coal provides around 49% of the nation’s electricity. In Kentucky, coal and petcoke provide between 97 and 98%. What has historically been our strength could become, in a carbon-constrained future, our vulnerability.
Impact on ratepayers in each sector from internalizing carbon costs by retrofitting the existing fleet to capture and sequester carbon, or to purchase carbon credits, or to deploy new base-load plants that offer more efficiency or more effective carbon capture.
Postcombustion capture not yet cost-effective or efficient. Draft DOE/NETL study predicted increases approaching 60% in the cost of electricity and loss of 25% of power from installation of a MEA or chilled ammonia CO2 scrubber.
Kentucky 2nd or 3rd in lowest combined electricity rates. Yet, in 2005, 20 states with lower monthly residential electricity bills than Kentucky’s. In that year, Kentucky’s residential ratepayers consumed more electricity than our counterparts in 43 other states; our businesses, more than 19 other states and our industries, more than counterparts in 47 other states.
III. Kentucky’s Response
House Bill 1, enacted during the 2007 Second Extraordinary Session of the Kentucky General Assembly, includes a specific mandate for development of a report on carbon management and carbon emissions.
Section 52 mandates, in a fairly abbreviated timeframe, the development of a collaborative Carbon Management Study intended to address the issue of carbon management in existing coal-fired power plants, and carbon emissions in general.
The Governor's Office of Energy Policy, the University of Kentucky’s Center for Applied Energy Research, the Geological Survey at the University of Kentucky, the Public Service Commission, and the Environmental and Public Protection Cabinet are directed to produce a report and present recommendations to the Legislative Research Commission on or before November 30, 2007. In developing the report, the agencies are encouraged to consult and collaborate with stakeholders, including industry, research institutes, and other universities to develop the report and recommendations.
Among the items that the report is to address are:
(1) The current status of research and technology to manage carbon dioxide in existing coal-fired power plants;
(2) Existing sources of support for research related to managing carbon dioxide in existing coal-fired power plant and the adequacy of such sources;
(3) The estimated capital and energy costs associated with installing the technology or upgrading existing coal-fired power plants to better manage carbon;
(4) Identification of specific potential research projects and demonstration projects to enhance the development and deployment of new technology in this area;
(5) Identification of the types of incentives or other government assistance that would be helpful in supporting the development and implementation of new technologies to reduce carbon emissions at existing coal-fired power plants, including strategies for isolation, capture, and management of carbon dioxide;
(6) The current status of research and technology in the capture and sequestration of carbon dioxide;
(7) Identification of marketing opportunities and uses for carbon dioxide as a value-added commodity, the maturity and long-term feasibility of those markets, the potential for carbon utilization relative to the anticipated generation of carbon, and the economic and environmental risks associated with these uses of carbon dioxide;
(8) Identification of other uses for carbon dioxide and the feasibility of large-scale implementation of such uses;
(9) Identification of feasible methods for capturing and transporting carbon dioxide from the generation point to end users, including the construction of carbon dioxide pipelines, rail transportation, or other means, and the positives and negatives for each method;
(10) Identification of any issues or concerns relating to carbon dioxide that are unique to Kentucky;
(11) Assessment of long-term risks and uncertainties associated with carbon-management options;
(12) Identification of existing collaborative efforts and partnerships developed to address carbon dioxide issues that Kentucky participates in; and
(13) Identification of the types of incentives or other government assistance necessary to support the development and implementation of new technologies to capture and sequester carbon.
Of particular interest to the electric utility industry, Section 50 of HB 1 also included a directive to the Public Service Commission to make recommendations regarding:
- Eliminating impediments to adoption of cost-effective DSM strategies as a preferred strategy prior to consideration of any proposal for increasing generating capacity;
- Encouraging utility portfolio diversification;
- Incorporating full life-cycle accounting for various strategies for meeting energy demand, including energy, economic, public health and environmental costs;
- Modifying rate structures and cost recovery to better align the financial interests of the utility with the consumer goals of achieving energy efficiency and lowest life-cycle energy costs for all classes of ratepayers.
IV. Coal Conversion
HB 1 also proposed new financial incentives intended to attract coal gasification and coal-to-liquid facilities to the Commonwealth through a package of sales and use tax, severance tax, wage assessment and other mechanisms.
Despite these incentives, it is highly unlikely that a commercial coal-to-liquid facility will be sited or built, either in Kentucky or elsewhere, in the near future. The only commercial-scale facility, SASOL, operated under significant subsidy for the majority of its existence, and such incentives are unlikely to be forthcoming from Congress nor to be affordable to the individual states.
A February 9, 2007 Report of a Task Team appointed by the Minister of Finance in South Africa, Possible reforms to the fiscal regime applicable to windfall profits in South Africa’s liquid fuel energy sector, with particular reference to the synthetic fuel industry, reflects that the government subsidies of the synthetic fuels industry were both significant and long-term. SASOL was described by the Task Team as “[a] private sector company with strong competitive advantages secured through government subsidy and regulation.” The report describes the history of that country’s synfuel program in this manner:
The drive towards self sufficiency was a key feature of the evolution of the industry in South Africa because of the country’s increasing isolation and sanctions during the second half of the 1900’s as the world responded to the apartheid government’s policies.
This gave rise to the development of a refining industry which developed through the provision of generous incentives to multinational oil companies to establish refineries in South Africa. More significantly, it also saw the establishment of a highly developed and unique synthetic fuels industry, initially owned by government, built on the basis of what appears to be generous levels of government support for the technology, construction and continued operation of synthetic fuels manufacturing plants.
Id. at 56.
The generous levels of support included tariff protection, a refinery investment incentive, market protection in the form of an uplift agreement in which the oil companies were required to uplift (purchase) the entire production according to market share at import parity pricing, giving priority to synfuels, transportation infrastructure investments, a levy on petroleum products when oil prices were low, and government loans.
In sum, the report concludes that “[i]t is clear that very large amounts of the tax payer’s money have been used to support and maintain the synthetic fuels industry.” Id. at 77. The goal of security of supply through development of synfuels was achieved, according to the report, but at a cost of some inefficiencies and higher prices for consumers.
The RAND Corporation summarized the three major impediments make the future of CTL unclear – uncertainty about the costs and performance of coal to liquid plants, uncertainty about the future course of world oil prices, and uncertainty about whether and how greenhouse gas emissions, especially carbon dioxide, might be controlled in the United States. Bartis, Policy Issues for Coal-to-Liquid Development, May 24, 2007.
In terms of environmental impacts, the impacts include those associated with the particular type of mining and water usage requirements, which may in certain states or regions limit the number of locations at which coal-to-liquid plants employing the Fischer-Tropsch technology, could be sited. If no provisions are in place to manage carbon dioxide emissions, then the use of F-T coal to liquids fuels to displace petroleum fuels for transportation use will roughly double greenhouse gas emissions, primarily due to the large amount of CO2 emissions that come from the production plant relative to a conventional oil refinery.
The lack of a management strategy, whether through sequestration or otherwise, will is a significant impediment and it is there that RAND recommended state’s strategically invest R&D funds. The Air Force, which is viewed as a prime force in pushing for CTL and is seeking to replace half of its petroleum-based jet fuel by 2015 with synthetic fuels requires that the well-to-wheels, or “mine to contrail” footprint for greenhouse gases be less then the alternative. One Air force official involved in the program called sequestration “dumb” and favors processes for electrolysis of the CO2 to create CO and oxygen for further processing into methanol and methane.
Coal gasification faces the same issues regarding the management of captured CO2. While advances in the use of certain membrane filters to capture CO2 are promising, the question of management of the CO2, as well as life-cycle impacts of coal extraction and transportation, remain.
V. Legal Issues Affecting Carbon Sequestration
There are a host of legal issues associated with any proposal to sequester carbon dioxide, and to a lesser extent, for use of CO2 for tertiary recovery of oil or gas reserves. A June 2007 Report produced by the Mew Mexico Energy, Minerals, Natural Resources Department, Carbon Dioxide Sequestration: Interim Report On Identified Statutory and Regulatory Issues, does an excellent job of summarizing those issues, which include:
- Potential current and future conflicts with surface and subsurface interests concerning ownership of pore space, groundwater use, and extraction or waste of mineral resources;
- Long-term liability issues, including accounting for unknowns, state role in monitoring, measurement and mitigation, funding long-term liability and management;
- Regulatory authority for regulation of the sequestration, including protection of surface owner interests, characterization of reservoir, emergency response plans, bonding, integrity demonstrations for site and reservoir, monitoring, plugging and reclamation;
- Condemnation powers and reservoirs and transportation corridors;
- Pooling / Unitization of Injection Reservoirs.
KRC has recommended that as part of a more balanced energy policy, a multi-stakeholder advisory group should be empanelled to explore the many legal and regulatory issuers associated with use of CO2 for tertiary recovery and for sequestration. Issues of ownership of the pore space, of the various mineral and surface interests, of groundwater and its use, of ownership of the formation and the right to sequester, of long-term monitoring, ownership and liability, and of how best to protect public and private interests from liability and unknowns related to sequestered carbon dioxide – all need thorough vetting with involvement from mineral and surface owners.