Stringent new state, regional and federal air emissions requirements will force “significant” shifts in utility strategies and coal distribution patterns, and they will require utility investments of up to $64 billion to achieve large reductions in sulfur dioxide (SO2), nitrogen oxides (NOx) and mercury emissions by 2020, according to a study by Cambridge Energy Research Associates (CERA).
A combination of existing federal Clean Air Act requirements, state actions and court-ordered consent decrees will require tighter emissions limits around 2010, with a second round of reductions between 2015 and 2018, according to CERA’s report, “Clearing the Air: Scenarios for the Future of U.S. Emissions Markets.”
“The key issue is not whether emissions standards will be tightened, but rather the timing and stringency of new standards,” said Robert LaCount, CERA director and the report’s author. “Under virtually all future scenarios, the power sector will face large required reductions in SO2, NOX and mercury emissions, high SO2 allowance prices and significant capital investments in flue-gas desulfurization (FGD) installations for controlling SO2 and selective catalytic reduction (SCR) installations for controlling NOX.” Most scenarios, he added, also include some form of mandatory CO2 policies.
According to the report, coal will remain the dominant fuel source for power generation for the foreseeable future. “CERA believes under any scenario to 2020, coal will remain the preeminent fuel for power generation, but that changing emission policies will result in significant shifts in coal distribution patterns, pushing generators with retrofitted FGD equipment toward lower-cost sources of coal,” LaCount said.
Operators of retrofitted coal plants have much less incentive to pay a sulfur premium, while plants without FGD will continue to value the premium for low-sulfur coal. Shifts in the balance between plants with and without FGD retrofits will create new competitive dynamics in coal-purchase behaviors and pricing, the CERA study found.
“In general, increased installations of FGD will result in Northern Appalachia (NAPP) and Illinois Basin (ILB) coals taking market share from lower-sulfur and higher-cost Central Appalachia coal. The degree to which this shift occurs depends largely on the timing of FGD retrofits in the Midwest and Southeast and responses by low-sulfur coal producers and transporters from the Powder River Basin,” the report noted.
Although new mining capacity will be needed to meet increased demand for NAPP and ILB coals, new investment is not guaranteed because coal companies are reluctant to commit the amount of capital necessary to open new mines without a long-term commitment from consumers. Similarly, many coal consumers appear reluctant to offer the long-term contracts that would encourage opening new capacity. As a result, a complicated transition period is approaching for the industry where producers and consumers will be challenged to coordinate the timing of critical investment decisions for power plant retrofits and new mining capacity.
Significant utility investment in environmental upgrades occurs in all scenarios outlined in the report, however, the structure and timing of new policy implementation will influence investment strategies. “Whether it’s trading of mercury credits or incentives for early SO2 reductions, various policy options provide significantly different benefits, risks and competitive considerations for different players in the North American power value chain,” said LaCount.
“Power generators’ recovery of environmental costs and selection of optimal environmental strategies is closely linked to the regulatory structure applied in various markets, which is not static. Therefore, matching the timing of environmental implementation with regulatory developments will be critical for companies, both financially and strategically.” Compliance strategies will also be highly dependant on changes in fuel markets, power markets, competitor actions and energy policies, all of which are moving targets, he added.
For information about the study, contact Mike Banville at (617) 866-5352 or email@example.com.
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