If carbon dioxide (CO2) emissions restrictions are mandated at a federal level, the method almost certainly will be a cap-and-trade system based on both the European Union and United States emissions trading systems. A cap-and-trade system likely will be chosen over other alternatives for four fundamental reasons: 1) dramatic success of the U.S. SOx and NOx cap-and-trade systems; 2) compatibility with other regional trading frameworks; 3) economic efficiency in distributing credits, and; 4) business acceptance due to flexibility of abatement options.
The U.S. SOx and NOx cap-and-trade system, implemented in 1995, has been hailed widely as a success and has familiarized U.S. companies with emissions trading. However, the major problem with the SOx/NOx program is that it does not restrict a local geographic concentration of polluting sources. SOx and NOx are “local pollutants” that cause the most damage when concentrated within a specific geography. The problem of local concentration does not apply to CO2, since CO2 restrictions are designed to reduce global rather than local concentrations of atmospheric CO2.
To mitigate climate change, a reduction in CO2 is equally useful regardless of geography. This makes a cap-and-trade program even better suited to CO2 than to SOx and NOx. The global scope of the climate-change problem justifies that restrictions be implemented at a federal rather than at a state level, and it ensures that the restrictions eventually will be extended to facilitate a global emissions-trading system.
Although the U.S. federal government has not yet taken steps to limit CO2 emissions, many states have taken the initiative to develop their own restrictions.1 In September 2006, California passed legislation that would reduce its current CO2 emission levels 25 percent by the year 2020, bringing the state’s emissions to 1990 levels. The legislation also mandates a reduction of CO2 emission to 80 percent below 1990 levels by 2050. To assist in this effort, California plans to participate in a cap-and-trade plan already in development with seven Northeastern states.2
With multiple other states considering similar measures, it is easy to assume that federal CO2 emission restrictions are no longer a question of “if” but “when.” These restrictions can be enacted in the following ways: 1) cap-and-trade; 2) carbon tax; 3) subsidies, grants or tax incentives; and 4) a combination of approaches.
Cap-and-trade sets an annualized emissions limit over specific geographies and industries. Within this limit, or “cap,” firms would be able to sell or trade the rights to these emissions. This program imposes the lowest cost for a given cap since the industry is able to pursue the lowest cost-abatement options. An obvious benefit to this approach is that the emissions reductions are known with certainty. Credits also can be distributed through auction to offset the implementation costs associated with such a program. With a cap-and-trade program, regulators can set a ceiling price for credits based on the penalties imposed for over-emitters. This ensures that the cost of compliance under a cap-and-trade system would not become excessive.
Opponents of a cap-and-trade system say that it would set a limit on annual emissions improvement and therefore only give firms incentive to do the very least. A strict program could result in costs higher than the actual benefits intended, while a cap-and-trade system that includes a “safety valve” would not guarantee compliance.
A cap-and-trade program can be implemented from either of two different approaches—upstream and downstream trading. Upstream trading programs are implemented at the point where carbon enters the economy (i.e., fossil-fuel importers and producers). Since the number of fossil-fuel producers is concentrated, implementation would be relatively easy. This scenario can be seen as most beneficial since it would place a cap on all potential carbon emissions. Opponents to upstream trading may point out that the impact is too far from the consumer, reducing exposure and incentives to reduce end-use emissions.
Downstream trading focuses on carbon emissions from end users (at the point of combustion). This type of program could be seen as beneficial because it is closest to the consumer and would therefore have the greatest exposure and impact. The difficulty in running such a program comes from the size and diversity of end users.
Initial downstream programs would regulate only the largest carbon emitters—electric utilities. This type of system is similar to that implemented in the European Union. This system also was implemented in the United States in 1995 to reduce SOx and NOx emissions, and has been widely hailed as a success.
The major problem with the SOx/NOx program is that it does not act to restrict concentration of polluting sources. This is not a concern when dealing with CO2 restrictions, since CO2 restrictions will be implemented to reduce global, rather than local, concentrations of atmospheric CO2. Given that the electric utilities market already is comfortable with SOx/NOx trading programs, implementation of a carbon-trading scheme would be relatively easy. The main concern with this approach is that alone, it only addresses roughly 40 percent of the total current carbon emissions.
A form of emissions control would tax each ton of CO2 produced. This tax ideally would affect the price of all goods and services associated with CO2 production. Proponents of this approach say that “a carbon tax would motivate consumers to control emissions up to the point where the cost of doing so was equal to the tax.” In this manner, the tax (cost) can be set to equal the damage created by CO2.
Opponents of a carbon tax point out that it does not guarantee that the intended target of emissions reduction would be met. There is another issue of what to do with the tax dollars generated by the carbon tax. While some propose to return it to those most affected by the tax through income and corporate tax breaks, this would only help negate the incentive to reduce emissions in the first place.
In terms of subsidies, grants, and tax incentives this method would be seen as an expansion of the current U.S. legislative approach to controlling CO2. Additional incentives could be created to promote the development of less carbon-intensive technologies. Given that the rate of CO2 emissions steadily has increased despite the existence of similar subsidies, this approach, in isolation, will not reduce the use of carbon-intensive fossil-fuel technologies.
Alternatively, when using a combination of approaches, the most politically acceptable and effective method to reducing emissions may include a combination of all three approaches described here. The imposition of a cap-and-trade scheme is practically a certainty for the utilities industry, while a carbon tax may be most appropriate for the transportation sector. Additionally, the federal government likely will use any income from these programs to promote development of carbon-efficient technologies through subsidies and various incentives.
Energy producers should take steps to prepare for the coming U.S. cap-and-trade system. Specific steps can be taken now to position a company to minimize the inevitable business expense and disruption that will be caused by the implementation of CO2 emission caps.
Companies that will prosper in this new environment should have in place, prior to the implementation of an emissions trading system (ETS):
1. Mechanisms to influence regulatory and legislative actions;
2. CO2 monitoring and reporting processes;
3. Strategic alliances;
4. Internal and external trading capabilities;
5. Pricing carbon emission credits (CECs) and abatement options as part of an acquisition strategy;
6. Systems for accessing and understanding abatement costs at each facility;
7. CEC price-dependent plans of action;
8. Technology and sequestration assessments;
9. Fuel-mix assessments; and
10. Reputational positioning plans.
Each company should strive to create a regulatory framework that will create a competitive advantage. Strict and broad federal requirements will not necessarily put undue burden on any individual player. They may, however, put the industry as a whole at a competitive disadvantage by substitution of industries and foreign competition that is not covered by the cap-and-trade system. While foreign competition to U.S.-based electric generators is minimal, electric-power generators will be affected by decreased demand as their customers switch from electricity to other forms of energy not covered by a cap-and-trade system. This could mean a move from electric heating to natural gas, or a move by industrial customers to build small generating stations not covered by the cap-and-trade system.
It is in the best interest of all electricity producers to lobby for a broad program that covers multiple industries and a wide geography. Additionally, there are numerous specific regulatory factors that will determine the industry winners and losers. The early winners will be the companies best able to shape regulations, recognizing that the industry’s initial position and reaction will influence the structure and implementation of an expanded program.
Moreover, the implementation of any cap-and-trade system will require that point-source emissions be measured according to specified guidelines. In addition to these monitoring requirements, businesses likely will face stringent reporting requirements. Businesses should design, in advance, processes to ensure compliance by meeting monitoring and reporting requirements.
CO2 emissions from power plants probably will need to be monitored by continuous emission monitors and reported to the U.S. Environmental Protection Agency (EPA) under guidelines similar to those specified under Title IV of the 1990 Clean Air Act Amendments. While this is a fairly straight-forward process and the technology is readily available, it may require extensive industry-wide retrofitting that significantly could disrupt ongoing operations. Alternatively, emissions may be self reported and independently audited, similar to the system adopted by the Chicago Climate Exchange, where emissions are audited independently by the National Association of Securities Dealers.
Implementing these systems early will reduce the risk of violations and will allow for exploitation of trading opportunities. By keeping ahead of the learning curve, businesses can avoid significant startup costs as all industry players compete for limited technology and expertise in redesigning their business processes and activities.
Companies need to begin forming strategic alliances that can provide expertise and offsets under the new program. By forming alliances, companies can expand their possibilities greatly for cost-effectively implementing abatement. These alliances should include large contributors to CO2 emissions (heavy manufacturing, process industries, and car companies), companies within the supply chain (coal producers and transport providers), and technology providers. Alliances also could include companies that have the potential to create offsets, such as those within the agricultural and forestry industries. Additionally, alliances could pave the way for more cost-effective trading, and could provide greater leverage in shaping regulations.
Industry players also must designate a group internally or expand their current emission-allowance trading group to conduct CEC trading. This same group should have the capability to trade credits externally, or it should designate an external broker with whom to partner. In preparing for regulations, creating an internal trading system often is the first and most effective way to gain experience with trading and to understand internal abatement options.3 Forming such internal groups now will give a company the experience it needs in developing a functioning trading capability to take advantage of all internal and external trading options.
In addition, as the ETS comes into force and the price of CECs increases, operators must consider costs of abatement both internally and externally. CECs and cheap abatement options could play an important role as part of an overall acquisition strategy. For example, as part of an overall acquisition strategy, a carbon-intensive plant can be acquired, cheap abatement (or even closing) instituted, and the excess credits traded to another plant or even traded on the open market. Savvy companies can use this mechanism to reduce otherwise significant abatement costs at existing plants.
Meanwhile, companies must have a detailed understanding of the CO2 abatement costs at each facility. Under the cap-and-trade system, a company will benefit greatly by knowing where its abatement investment will have the most impact. Currently, cost-effective options for CO2 abatement are rare, as they require changing fuel inputs, reducing output, or capturing and sequestering CO2. One tactic is to make plants “capture ready” or flex-fuel, essentially buying the option to more cost-effectively reduce CO2 output in the future. Implementing a carbon capture and sequestration system has been shown to be more cost effective with integrated gasification combined cycle (IGCC) than with pulverized coal (PC).4 Developing IGCC technology has been a core strategy of AEP in preparing for expected regulations.5
The following factors will determine the magnitude of cost imposed by the CO2 cap-and-trade system on individual businesses:
1. Allocation vs. Auction;
2. Allocation Mechanism and Baseline;
3. Monitoring and Reporting Regulations;
4. Cost Pass-through;
6. Offsets and Links to Other ETS Programs and Geographies; and
7. Top-level Cap and Reduction Timeline.
The most important driver of cost for holders of CECs will be the decision between allocation vs. auction. Auctioning credits is the most economically efficient way to allocate initial CECs. Auctioning 100 percent of CECs would:
1. Avoid the need to set a baseline allocation mechanism, thus avoiding the possibility of lobbying/favor seeking;
2. Provide a windfall to the issuing government agency; and
3. Require significant expenditure on the part of industries covered by the ETS.
The most likely allocation mechanism for existing sources will combine free allocation according to a set baseline with an auction of possibly 10 to 20 percent of CECs. Additionally, a policy probably will be set for allocating CECs for new sources. This allocation mechanism is probable due to the precedent set by the U.S. SOx/NOx and the EU ETS allocation mechanisms.6 These two mechanisms were designed to balance efficacy with political and regulatory support, and may act as templates for a future U.S.-based ETS.
Second, recognizing that the initial U.S. ETS may allocate the majority of the CECs, the choice of a baseline for allocating CECs largely will determine winners and losers. In any trading scheme, picking a baseline—the point from which emissions increases and reductions are measured—is controversial. The goal of energy producers will be not only to resist business disruption and high cost, but to fare better than direct competitors.
In choosing a baseline, regulators need to balance the needs of:
1. Rewarding CO2 efficiency improvement; and
2. Rewarding CO2 efficient producers.
In many ways, these needs are opposing. Should benchmarking be a driver towards CO2 efficiency or a compensation for early action?7 If the goal of CO2 emissions restrictions is to reduce the carbon intensity of electricity production, the first need should not be considered. However, ignoring improvement when setting a baseline is unrealistic, since carbon intensity differs drastically across plants and producers. Using both needs to set a baseline recognizes that the initial U.S. ETS will be a transitory program that will, in the long term, lead to shutting down carbon inefficient methods of power production.8
Setting the allocation mechanism for a U.S.-based ETS will have major strategic implications for regulated companies. Companies first must determine the baseline that will position them to gain maximum economic value as compared with competitors. Each company then will lobby for the baseline that is most favorable for its current and planned operations. We expect that the power-generation industry will be divided based on fuel-mix profile. The industry will be divided primarily between heavy coal users and light coal users. Heavy coal users, like AEP and Duke, will lobby for an “as is” allocation based on historic emission profiles. This means that coal plants will get significantly more CECs/MW output than would other types of plants. Light/non-coal users, such as PG&E, will lobby for an “efficiency” allocation based on CO2 efficiency (CO2/MW). This means that operators of coal plants may not be allocated their required number of CECs, and may have to buy CECs from operators that may be allocated more credits than they need.
Furthermore, companies that already have made significant investments in CO2 abatement technology (including fuel switching and plant shutdowns) will lobby to get credit for past “investments.” Regulators will need to signal that they will consider past investment in abatement when determining an allocation mechanism. To not consider past investment would cause companies to delay abatement options until the allocation mechanism has been set. We expect that regulators will also be sensitive to the significant amount of money utilities already have spent on SOx and NOx abatement to meet the Phase II reductions mandated in the 1990 Clean Air Act. Cost of CO2 cap-and-trade will be borne by the same companies that faced the greatest costs under the SOx and NOx programs. Regulators probably will account for this by giving companies a longer timeframe to come into compliance.
Another issue is how to allocate CECs to new plants. Since existing plants essentially will be given CECs, new facilities not allocated CECs will be at a significant cost disadvantage. Not allocating CECs to new plants would be a substantial barrier to entry and would keep newer, more energy-efficient plants from being built. For this reason, it is expected that new plants will be allocated, at no cost, at least a portion of their required emissions credits.
Regulators must implement a system for compliance monitoring. The system must be substantially robust for all participants to have confidence that regulators can ensure compliance, manage data, and institute punishments for violators. These interests must be balanced to minimize costs associated with installing expensive and disruptive monitoring equipment. This becomes especially important as the ETS expands to cover smaller emitters, although at this stage it is unclear how small emitters will be monitored.9
In addition, from an industry-wide perspective, implementation of any ETS scheme will act to increase production costs. To sustain profits, producers must have some ability to pass-through costs to customers. This is especially important for carbon-intensive producers. In this highly regulated industry, producers must have confidence that production costs associated with meeting ETS requirements will be understood by local regulators, who have the power to deny end-user price increases. It is ironic that the first phase of a U.S. ETS certainly will cover large fixed-point sources because “the energy sector has been considered to have the best possibilities to pass on costs for the allowances to the consumers and hence the allocation to this sector is often more restricted than the allocation to other sectors.”10
The U.S. ETS will, like the EU ETS, initially cover large, fixed-point sources. While these sources may account only for a small proportion of overall CO2 emissions, they will be the initial targets because they are best suited to monitoring and abatement. It is in the interest of electricity producers to advocate for as wide a net as possible, so that the economy as a whole helps to pay the price for CO2 reductions, and so that electricity producers have a deeper trading market.
Reducing atmospheric CO2 concentrations will require a worldwide, centuries-long effort. For a U.S. ETS to have any effect on long-term CO2 concentrations, it will have to act as a first step in implementing a wider regime that covers all geographies and industries. From this standpoint, a reduction in CO2 emissions is just as valuable regardless of where it occurs. This gives regulators incentives to link worldwide ETS, so that resources can be spent where they will have the most impact.
The ability to gain credits through offsets will help to limit the costs of abatement. By linking a U.S. ETS to the Kyoto Joint Implementation and CDM programs, companies greatly will expand their options for gaining emission credits. Linking the U.S. ETS to other programs and offering offsets greatly would increase support for an ETS since other players, such as agricultural companies, renewable energy producers, and brokers, would benefit.
At this time, it is unclear how the United States will set the top level cap and timeline for emissions reductions. Many other industrialized countries have settled on the Kyoto goals for reducing CO2 emissions to 1990 levels by 2012. While this has helped to set a baseline and a goal, this expectation is unrealistic. U.S. regulators will have to choose a baseline that will lead to both significant CO2 reductions while also rewarding recent actions by producers to reduce emissions. It should be expected that a baseline will therefore be set at a level determined by historical emissions at least 10 years in the past.
The top-level timeline for reduction will be a large factor in determining the overall cost to the industry and economy for meeting the new cap, but will have much less effect on determining individual winners and losers. While it will be the producers who face the initial business disruption and costs, it is ultimately the energy users and the consumers of their products who will face price increases. From this perspective it is easy to understand the strong and unified resistance to carbon emissions restrictions from energy-intensive industries.11
1. See Appendix - State-Level Programs Addressing CO2 Emissions Reductions.
2. See Appendix - Regional Greenhouse Gas Initiative (RGGI).
3. See article sidebar, “How Coal-Dependent Utilities Will Stay Clean.”
4. Future Carbon Regulations and Current Investments in Alternative Coal-Fired Power Plant Designs Ram C. Sekar, John E. Parsons, Howard J. Herzog and Henry D. Jacoby, MIT Joint Program on the Science and Policy of Global Change, Report No. 129, December 2005.
6. The allocation mechanisms for Phase I of the EU ETS were determined at a national level allowing significant space for experimentation. The allocation mechanisms for Phase II and later will be much more standardized across the EU based upon specific experiences within Phase I EU ETS participant countries.
7. Benchmarking - Creating Incentives for Abatement?, CEPS Task Force on Review of the EU ETS, 24 May 2005, Lars Zetterberg, IVL.
8. For a detailed discussion of theory behind different allocations see Absolute vs. Intensity-Based Emission Caps A. Denny Ellerman and Ian Sue Wing, MIT Joint Program on the Science and Policy of Global Change, Report No. 100, July 2003.
9. Monitoring small emitters would probably require a hybrid scheme whereby one uses emission factors along with inspection certificates, similar to the urban emissions inspections regimes that are now in place for automobiles. See also: “Bringing Transportation into a Cap-and-Trade Regime,” A. Denny Ellerman, Henry D. Jacoby and Martin B. Zimmerman, MIT Joint Program on the Science and Policy of Global Change, Report No. 136, June 2006.
10. “Analysis of National Allocation Plans for the EU ETS”, IVL Swedish Environmental Research Institute, Zetterberg, Lars, August 2004.
11. See: The Alliance of Energy Intensive Industries publications, “Contribution to the EU Energy Strategic Review: Urgent Measures are Required to Improve the Functioning of Electricity and Gas Markets,” Brussels, 22nd September 2006 and “4th Annual Workshop on Greenhouse Gas Emission Trading” 4th & 5th October 2004.