Policy Updates

Latin America is no stranger to private climate finance. International (and sometimes domestic) companies seek to offset their greenhouse gas emissions with emission reduction credits purchased from both the regulated and voluntary markets. In the regulated market, developed-country industries with capped emissions levels purchase emissions offsets from developing- country projects. On the voluntary market, unregulated companies or individuals purchase reductions either for altruistic reasons or in anticipation of future regulation.

In Latin America’s regulated market, fewer than 500 projects have been approved by the Clean Development Mechanism (CDM). This United Nations-backed system allows projects in developing countries that reduce carbon dioxide to receive carbon credits. Those credits, in turn, can be bought by developed countries to count toward greenhouse gas reduction promises. By 2009, credits from 206 projects had already been purchased by industries and individuals in developed countries. Latin American projects that had been granted credits represented 7 percent of CDM’s overall value (3 percent of global credit sales come from Brazil); nearly 1,000 other projects are in the CDM approval pipeline.

Although the majority of the region’s emissions-reduction opportunities are in the area of forest and land use, the sector’s exclusion from the CDM means that these projects are not represented in the regulated markets. Instead, projects are concentrated in biomass energy production (not carbon neutral, but less polluting than the current fuels used); landfill gas capture (methane is a strong greenhouse gas); wind and hydropower; and energy efficiency.

The voluntary markets, though smaller in absolute terms than the regulated market, are a significant regional force for curbing greenhouse emissions. In 2009, Latin America had the second-largest market share in the voluntary markets by volume, capturing 16 percent of it globally. This represents a tripling of Latin American credits in just one year.

Similar to the regulated market, as of 2009, the majority of voluntary credits (56 percent) originated in Brazil followed by Peru (23 percent). But unlike the regulated market, forest carbon represented 80 percent of the region’s voluntary credits. Further, the minimal amount of action required to create some forms of forestry and land-use credits (e.g., leave trees standing or land fallow) means that the average price for forestry credits on the voluntary markets (less than $4 per ton of carbon dioxide equivalent, or tCO2e) is significantly lower than that for credits on the regulated markets ($11–12/tCO2e).

The expansion of private finance in Latin America is limited by factors such as the exclusion of forestry and land use from the CDM (potentially to be changed) and decreased global demand for voluntary offsets. There are also significant internal hurdles such as low technical capacity, underdeveloped investment markets and high transaction costs. These are not unique to the region but have a disproportionate impact. The region’s forestry and land use projects require significant technical capacity to calculate credits and involve considerable financial uncertainty.

But new public and private institutions are being developed to overcome some of these barriers.

In Colombia, the national government, the Inter-American Development Bank and Fundación Natura are working together to create a system for voluntary mitigation of greenhouse gas emissions. By 2015, when fully operational, this $10.5 million mechanism will encourage voluntary carbon emissions mitigation by domestic companies or institutions through the creation of an exchange-like platform to facilitate project financing and allow trading of verified emissions-reduction credits. Industry education projects and other incentives will also help the domestic emissions-reduction market.

In Chile, a Santiago Climate Exchange (SCX) was proposed in late 2009. The SCX, like its now-defunct North American counterpart the Chicago Climate Exchange, would enlist companies to voluntarily commit to reduce emissions. Emissions reductions
in excess of a company’s commitment would generate
a credit that could then be traded on the exchange. As in Colombia, the SCX aims to increase domestic demand for voluntary credits in
a country that will not be required to regulate emissions reductions
in the short term.

The novel voluntary market mechanisms in Colombia and Chile are likely first steps toward full domestic or regional emissions markets. But until these markets can be developed, the bulk of Latin America’s private climate finance (and the corresponding decisions on what will be invested in) will come from international offset markets.

But SIEPAC only represents the first step. The broader goal is to harness the regional electricity market created by this major transmission project to increase energy efficiencies and reduce operating costs. That market, known as the Mercado Eléctrico Regional, or MER, is expected to be fully implemented later this year. MER would initially function as a seventh market alongside the six national markets. Its basic operating strategy is to engage in electricity trade through long-term contracts and spot transactions, allowing power producers and power traders to purchase and sell electricity while accessing the regional transmission system. Power companies could then install plants in any of the member countries and sell energy at a regional level, creating a market with its own rules and institutions independent of—and parallel to—national markets.

A fully functional MER would increase system reliability, reduce reserve capacity and lead to optimal use of the renewable sources that currently constitute 61 percent of the electricity generated for the region’s transmission networks. Moreover, according to the Consejo de Electrificación para América Central, operating costs could be reduced by 4 percent, with the potential 23 percent drop in average generation costs likely to transfer to customers. Interconnections with Mexico (already operational) and Colombia (expected to be operational by 2014) would further increase the benefits of a MER.

Would a Regional Market Work?

Both the size of the market and the availability of resources suggest that MER could be a successful integration experience. Although the individual electricity markets are not large, together the six countries have an installed generation capacity of more than 10,000 MW and annual energy generation of nearly 40,000 gigawatt hours (GWh). Regional electricity demand, on the other hand, has also seen sustained growth—posting an average annual increase of approximately 4 percent over the last decade.

On the resource front, Central America has a large, untapped potential for renewable power generation. Most of it is hydroelectric power, which is estimated to have a potential of 25,000 MW, less than 20 percent of which has been installed. And looking ahead, renewables account for more than 50 percent of likely capacity additions in Costa Rica, Guatemala, Nicaragua, and Honduras.

Despite this potential, in recent years the region has seen a steady decline in the volume of electricity trade. At the end of 2009, less than 1 percent of disposable energy was traded among countries. The reasons: restricted transmission links and relatively minor gaps between the supply and demand of electricity in most countries. Here is where SIEPAC and MER would make the greatest difference.

Recent market performance also reflects low generation capacity in some of the national power systems. Because of market segmentation, producers have increasingly relied on thermoelectrical generation (power obtained mainly by burning fossil fuels) with its share growing from 30 percent in 1990 to 46 percent in 2008 at the expense of more efficient hydro generation. With a regional market, these short-term solutions to meeting the needs of national energy markets would optimally be replaced with a broader vision and long-term strategy.

But challenges remain for a regional power grid. Chief among them will be exploiting the full potential offered by the transmission line and the now-integrated market power demand. To attract more energy projects, the region must maintain its political commitment to the integration process and the institutions that oversee it. Most important, electrical regulatory and supervisory bodies must be strengthened, especially their technical and legal capacities, to guarantee the enforcement of market rules and fairness in market transactions.

Even with SIEPAC coming on line, larger questions remain regarding how to build and consolidate a successful regional power market. The region’s development is intrinsically linked to a financially strong and technically reliable power system. For that to happen, Central Americans need to see the real benefits of a truly single integrated market—one that would take advantage of the possibilities offered by larger hydro generation projects to attain efficiency gains beyond modest improvements in system performance. Here, cross-border interests must prevail over national concerns when making regional market decisions.

The agency also implemented tougher provisions for its Pattern of Violations (POV), a system designed to increase long-term safety compliance by targeting operations that demonstrate a pattern of health and safety violations. Once a violation is written, MSHA can then withdraw miners under the POV. At the same time, MSHA ordered its inspectors to make sure that no advance warning was given before spot checks—a regulation that is already on the books but has often been ignored.

The new hardline policies have delivered results. In August, MSHA named four mines where it had found “egregious violations”; in September, the agency announced the results of a five-month impact inspection program that targeted 111 coal and metal/nonmetal mines and issued over 200 withdrawal orders. While withdrawal orders do not close a mine, they do suspend production and allow only those involved in safety to enter the mine.

This signals a change in practice. In addition to conducting regular inspections, the agency is attempting to identify the most dangerous mines and target them with increased enforcement and public exposure through surprise inspections, which continued through the fall. In November, 13 mines were identified as having a potential pattern of violations—the first step in giving notice that safety improvements must occur to avoid closure.

In September the agency also issued an emergency temporary standard requiring underground coal mines to apply additional non-combustible material—up to 15 percent in some cases—to roofs, floors and walls. This change in regulation came as a direct result of a finding from the National Institute for Occupational Safety and Health’s research, which concluded that over the last century mechanized mining methods had resulted in coal dust particles becoming smaller and more explosive. Although the standard was likely planned for some time, the Upper Big Branch explosion undoubtedly accelerated its implementation. MSHA estimates that compliance will cost underground bituminous coal operators $22 million.

New federal legislation was also drafted in response to the West Virginia mine explosion. There are several bills. The most prominent—the Robert C. Byrd Mine Safety Protection Act of 2010 sponsored by Rep. George Miller (D-CA)—was defeated in December 2010 by a vote of 214 to 193 but will likely be reintroduced in some form in the new Congress. It included increasing criminal and financial penalties and giving MSHA more powerful enforcement tools while holding it more accountable. If the bill passes in the new Congress, miners who call attention to unsafe conditions will be protected, and operators will be required to notify employees of hazards and violations.

This bill followed a pattern of sweeping mine safety reform in the aftermath of tragedy. In 2006, the Mine Improvement and New Emergency Response (MINER) Act was passed following the Sago Mine Explosion (claiming 12 lives) and Alma Mine fire (five casualties) in West Virginia, and the Darby Mine explosion (two casualties) in Kentucky that year. The MINER Act, sponsored by Sen. Mike Enzi (R-WY), addressed emergency response and preparedness, rescue team availability and the need for wireless communication and tracking. It also raised civil and criminal penalties and led to the development of underground wireless communication.

Advances driven by the MINER Act suggest that new mine safety and health legislation should address the development of explosive conditions rather than disaster response. Technology that can continuously monitor the atmosphere in a mine and prevent the development of dangerous conditions is the next logical step. But one major barrier to adopting the new monitoring and communication technology in underground coal mines is the question of whether it could survive an explosion.

The National Mining Association (NMA) indicates that mine operators have invested $800 million in complying with the MINER Act, and a similarly substantial investment would likely be required with the passage of new mine safety legislation. The NMA opposed the passage of the Robert C. Byrd Mine Safety Protection Act, indicating that enforcement of current legislation by MSHA had been weak. The association maintains that 87 percent of U.S. mines operated in 2009 without a lost time accident and that proposed legislation does little to increase safety.

But mine safety policy should not be decided by those with narrow interests. Each American will consume almost 1,500 tons of raw minerals over his or her lifetime. This means that while mine safety policy directly affects the lives of people who work in mines, getting it right should be a national concern.