by Gregory Arnold, CE2 Capital Partners
As the international community works toward a climate change pact to succeed the Kyoto Protocol, there is increasing pressure to enact legislation domestically.
The U.S. signed in January a voluntary agreement to reduce greenhouse gas emissions through the Copenhagen Accord, with concrete reduction targets to be defined by domestic legislation. The American Power Act (APA) proposed by Sens. John Kerry and Joe Lieberman provides the most comprehensive framework to date. Such legislation has significant implications for the power sector, particularly utilities and merchant coal generators. Under the proposal, utilities will be forced to reduce significantly their carbon footprints. The Environmental Protection Agency will require electricity generators to procure one permit, or allowance, for each ton of carbon dioxide equivalent emitted. The total number of available allowances, or cap, declines annually to reach the long-term emissions-reduction requirement.
To ease the transition to a low-carbon economy, Congress is proposing initially to allocate for free, some allowances to the power sector, giving companies the freedom to purchase the rest. It is projected in the early years of the program that allocated allowances will be sufficient to cover most electricity industry emissions. Yet, the number of allocated allowances decreases 16 percent in 2016, again in 2026 and declines until 2030 when no allowances will be allocated. As the shift from free allocations occurs, electricity generators will need to reduce their emissions to meet future compliance obligations. Within this framework, power companies have an opportunity to begin planning for climate legislation, to assess how a federal carbon-reduction program will impact costs, and to develop strategies now to minimize the future economic impact of compliance.
As drafted, the APA would begin covering the power sector in 2013. The cost of complying should escalate in the program’s later years as generators face an increasingly tighter cap. APA would create an initial floor of $12 and a price ceiling of $25 per allowance, expressed as per ton of CO2 equivalent (CO2e). The floor and ceiling will increase at an annual rate of 3 and 5 percent, respectively, plus inflation. The top 10 power sector emitters emit on average 80 million tons of CO2e per year. At the 2013 floor price, this equates to nearly $1 billion of costs. Companies that embark now on short- and long-term planning have an opportunity to manage risks and compliance-related costs more effectively.
The power sector must begin planning for the impact of these regulations. Available strategies include procuring carbon offsets through direct investments in carbon emissions-reductions projects or purchasing carbon offsets. Offsets are reductions in emissions generated from sectors not directly regulated, which are expected to be fungible with allowances. Project types include destroying methane gas at landfills or sequestering carbon in forests resulting from sustainable management practices. Offsets can provide an attractive mechanism for containing costs. Utilities might be able to use them to generate savings for ratepayers in the near term and for the long-term bottom line. Apart from regulatory considerations, the driving factor in how much benefit will accrue to ratepayers and shareholders is based on managing the procurement and timing of how and when utilities use allowances vs. lower cost offsets.
The appeal of acquiring offsets to aid in future compliance is that utilities can take advantage of the developing pre-compliance markets for carbon offsets and the existing contango price curve. Today, offsets cost substantially less than the APA’s price floor. This price differential and several provisions in the proposed legislation, such as the ability to bank allowances and offsets for later use, present several options to consider:
- Buy offsets. Companies that do not want to take on development risk should consider offset purchases now through spot or forward agreements. This offtake can begin with deliveries matching the expected program start date. A purchaser of offsets today may consider banking them for use in a federal carbon program. Under the APA, offsets from qualified projects starting after Jan. 1, 2001, with reductions in emissions occurring after Jan. 1, 2004, would be eligible as a ton-for-ton exchange into a compliance program. Under the House-passed Waxman-Markey bill, the reduction in emissions must occur after Jan. 1, 2009. It is expected that these offsets may be banked to meet future compliance obligations. Banking offsets might prove beneficial; future carbon prices are expected to be trading at prices much higher than today. This reduces project and price risk but might include the risk of underdelivery or volumetric risk. As a result, buyers should expect to pay higher prices the more firm the delivery and better the project quality.
- Build internally the infrastructure to develop offset projects. Companies interested in procuring offsets at cost can develop their own projects. This requires upfront investment in human and project capital for carbon offsets development, verification and registration. Choosing this option involves project risk and the willingness to become an expert in project protocols. Scale can be an issue here because project investment size is smaller than that of power projects.
- Invest in projects that create offsets. A third option, partnering with firms that develop offset projects, is similar to investing directly but can create diversification across project types and enables the investor to partner with firms experienced with carbon, lessen development risks and access greater scale.
In any of these strategies, as offsets are procured, utilities should consider banking federal allowances once the program begins and matching emissions with the lower-cost offsets. This allows the utility to weight inventory toward allowances while purchasing and surrendering a lower-cost offset. This strategy might minimize the impact of carbon costs.
As described, ways exist to access carbon offsets. Costs, risk appetite, the local regulatory environment and the need to control offset supply also will affect strategy. Offset purchases or project development also might be from within the service territory concentrating economic and environmental benefits locally while increasing goodwill.
The eventual passage of legislation to curb U.S. CO2 emissions has significant implications for the power sector’s cost structure. Once a federal carbon program passes, the domestic offsets supply will be in short supply, and prices will rise at least to the floor. Given the vagaries of nascent domestic carbon markets, the human capital required to create offset supply will be constrained similarly. As a result, it could take up to two years for the domestic offset supply chain to ramp up, and even more expensive international offsets might be needed to fill any gap. Given the likelihood of an eventual price on carbon, the need for prices to trend upward for a program to be effective and the offset supply constraints mentioned, there is a strong impetus for the power sector to act. As a result, high-profile utilities have begun this effort and are leading to get regulatory clarity soon from a carbon program.
Gregory Arnold is managing partner of CE2 Capital Partners, one of the largest owners of U.S. carbon emissions-reduction projects and carbon commodities.