Sunday, June 12, 2016

An Economic Assessment of the Supreme Court's Stay of the Clean Power Plan and Implications for the Future

The Clean Power Plan is expected to contribute substantially to US greenhouse gas emissions reductions, but the Supreme Court has halted its implementation. However, the conditions supporting a stay based on economic harms to the coal sector are not met.
Key Findings
  • Because of market, technological, and policy trends that are independent of the Clean Power Plan, combined with compliance flexibility, the economic conditions supporting a stay based on economic harms to the coal sector are not met.
  • The same factors mitigate concerns about large increases in electricity prices and harms to the broader economy until at least the mid-2020s.
  • The gradual phasing of the emissions reductions and the flexibility to reduce emissions by a wide range of approaches are well within the confines of the Clean Air Act.
  • Existing trends suggest that the costs to the public of pushing back the Clean Power Plan deadlines likely far outweigh the benefits to the coal sector.
  • Claims of irreparable harm arise frequently in environmental litigation. Our economic framework for analyzing the potential irreparable harm under the Clean Power Plan is applicable in other contexts.
The Clean Power Plan is expected to play an important role in reducing US greenhouse gas emissions. On February 9, 2016, responding to appeals from the affected industries and states, the Supreme Court issued a "stay" suspending implementation of the Clean Power Plan until after the judicial review process. Industry groups stated the plan will pose large “irreparable” costs to the coal sector during the period of judicial review. However, modeling suggests that because of prevailing market, technological, and policy trends, the Clean Power Plan will result in near-zero costs beyond current trends until 2025, in part because of the plan’s built-in flexibility. These factors and lessons from option theory suggest the stay is economically unjustifiable based on claims of irreparable economic harm to the coal sector. If implementation of the rule proceeds, current trends imply the stay will have little effect on industry’s ability to follow the current compliance schedule. 
[A variety of organizations have performed simulation modeling of the CPP on behalf of the electricity industry and environmental organizations, which they have shared in stakeholder dialogues, workshops, and private briefings. These findings are not generally available in a citable form, and we depend on our own modeling results, which are consistent with the results that other groups report. We have used RFF’s Haiku electricity model to simulate about 50 CPP scenarios, which differ in the compliance approach taken by states, the level of coordination among states, and the levels of future electricity demand and fuel prices. Here, we focus on a scenario in which all states are assumed to participate in a nationwide emissions trading program and choose to cover existing and new sources under their state caps (Burtraw et al. 2016). The assumption of national emissions trading (as opposed to regional or no trading) reduces overall implementation costs, but the coverage of new sources under the cap raises implementation costs. We assume (conservatively) that only half the level of new programmatic energy efficiency assumed by EPA in its modeling. These assumptions should yield a balanced estimate of the overall costs of the CPP and the effect of the CPP on the coal-fired fleet. In this context, we estimate total compliance costs of $6.3 billion per year in 2025 and $8.4 billion in 2030 (2011$). The 2030 estimate can be compared to EPA’s estimates of $5.1 to $8.4 billion for 2030 costs, depending on the approach states choose (EPA 2015). It is noteworthy that EPA finds the costs before 2030 to be substantially lower than in 2030. In 2022, EPA estimates costs of $1.4 to $2.5 billion, and in 2025 costs of $1 to $3 billion. These estimated costs are comparable in magnitude to the costs of existing policies, but not the most expensive among recent policies. For example, for the Mercury and Air Toxics Standards, EPA (2011) estimates annual costs of $10.4 billion in 2016 (2011$). Barbose and Darghouth (2016) report annual compliance costs of $2.5 billion in 2014 for state renewable portfolio standards (2011$).

Photo: alohaspirit/iStock
It is also noteworthy that EPA estimates the CPP costs to be several times lower than the societal benefits of lower emissions. Burtraw et al. (2016) estimate that emissions allowance prices with multistate compliance (trading) rise to only $2 per ton of CO2 by 2025, meaning that existing technological trends and policies will reduce emissions nearly to the levels required for the initial compliance period (2022–24). By 2030, allowance prices rise to $17 per ton of CO2. For comparison, EPA analyzes state-level compliance and estimates allowance prices ranging from $0 to $14.59 per ton in the first compliance period (EPA 2015). Multistate compliance would be expected to have a much lower allowance cost. For an average coal-fired plant, the allowance price in 2030 implies a marginal cost increase of about $17 per MWh (47 percent) and for a natural gas-fired plant, the allowance price in 2030 translates into an increase of about $7 per MWh (15 percent). The CPP therefore provides a relative advantage to natural gas-fired plants compared with coal-fired plants. Without the CPP, generation from coal-fired plants would account for 32 percent of total generation in 2030; under the CPP, they would account for 27 percent of total generation. These shares contrast sharply with the 50 percent share in 2005 and even the 37 percent share in 2012 (EIA 2015a). The CPP is expected to increase the average wholesale generation price by about 4 percent, raising the revenue per MWh of generation at these plants and offsetting some of the higher generation costs caused by the policy. Table 1 shows that, in annual percentage terms, the effect of the CPP on operating profits is a fraction of the effect of the recent natural gas price declines on operating profits. The reduction in generation from coal-fired power plants will be felt at coal mines that face lower demand for coal.]

The Clean Power Plan Will Continue Recent Emissions Reductions Trends, but at a Slower Annual Rate 

Burtraw et al. (2012) compare the influences of natural gas prices and previous federal emissions regulations, including the Cross State Air Pollution Rule and the Mercury and Air Toxics Rule, which is more expensive than the CPP or any other environmental regulation that EPA has promulgated. They find that natural gas prices and electricity demand had a substantially larger impact on electricity prices and the generation mix than did environmental regulations, which led primarily to the installation of postcombustion controls on power plants but caused little change in coal consumption or retirement of coal-fired power plants. In contrast, the decline in natural gas prices caused a sharp drop in coal consumption and the retirement of coal-fired plants (Burtraw et al. 2013). These trends have caused emissions to decline more quickly in recent years than the CPP will cause in coming years. Figure 1 shows that between 2007 and 2013, emissions declined at an average rate of almost 3 percent per year. By comparison, between 2013 and 2030, the CPP would cause emissions to fall by less than 1 percent per year. In that sense, the CPP continues, to a lesser extent, the emissions trajectory that the US power sector is already on
The oil and gas index tracks the S&P rather closely until mid-2014, which coincides with the sudden drop in global oil prices. Cumulative returns of coal-mining companies are fairly similar to those of the other two indexes through late 2011. After 2011, the returns of the coalmining companies are much lower than those of the other indexes. This divergence, which reflects the mounting economic difficulties of the coal-mining sector, precedes the CPP by several years.
In recent years, the United States has experienced unprecedented growth in wind and solar energy. Figure 4 illustrates this growth and documents the investment shift from natural gas-fired plants to wind- and solar-powered plants. In 2005, natural gas accounted for 80 percent of new investment, but by 2014, that share fell below 40 percent; wind and solar account for nearly all of this change. In 2005 and 2006, wind capacity additions accounted for about 15 percent of total capacity additions (Wiser 2015). Although this share has been volatile, after 2006 the share has typically been about twice as large as it was before 2006. The sustained and high levels of investment have caused wind’s share of total generation to increase tenfold, from 0.4 to 4.7 percent between 2005 and 2015.
While solar power remains a relatively small source of electricity for most of the country, its rate of growth in recent years has surpassed that of other sources. From 2005 to 2014, annual solar capacity additions grew by an average rate of 68 percent, and annual capacity additions were, on average, 16 times larger in the last five years of this period than they were in the first five years (Wiser and Bolinger 2015). The EIA projects that solar will account for the largest share of investment in 2016 (37 percent)....
The total cost of new solar electricity systems, which includes the cost of the module (which converts sunlight to electricity), as well as the cost of labor, land, other equipment, and construction permits, has fallen relative to the cost of both wind power and natural gas-fired plants. Panel A of Figure 5 shows the levelized cost of energy for utility-scale solar, which is equal to the average cost of electricity over the life of a system constructed in the indicated year. The average cost fell by about one-third between 2010 and 2014, or 8 percent per year. Underlying the total cost reduction have been technological and manufacturing advances to the photovoltaic modules, as well as reductions in the other cost components and installation costs (which are sometimes referred to as “balance of system” costs). Costs of residential and commercial systems have also fallen. As seen in Panel B of Figure 5, between 2002 and 2005, the average installed price for residential rooftop solar photovoltaic systems declined by 7 percent per year.14 Largely because of bottlenecks in the production of silicon, an important input in most photovoltaic cells, production costs of new systems leveled off between 2005 and 2009. Silicon prices fell after 2008, and between 2009 and 2014 the cost of photovoltaic systems decreased by 15 percent per year (Barbose and Darghouth 2015). 

Does the Clean Power Plan Meet the Two Economic Conditions for Irreparable
Harm to the Coal Sector? With the structure of the CPP and technology trends as background, we now examine the two conditions that together would lend economic support to claims of irreparable harm to the coal sector during the period of judicial review.
Will the Clean Power Plan Cause Large and Irreversible Costs? Conceptually, because coal-fired power plants emit more CO2 than do other generation technologies, including natural gas-fired plants, the CPP will raise the cost of coal-fired electricity generation relative to other technologies. This will reduce the profitability of coalfired plants, perhaps causing some to shut down. It will also reduce demand for coal and production from coal mines, perhaps causing some coal mines to close. The CPP introduces a cost advantage of natural gas over coal that is in the same direction as the relative cost advantage introduced by the recent decline in natural gas prices relative to coal prices

The historic effect of the recent natural gas price declines on the coal sector provides a method for assessing the future effects that can be expected from the CPP. We estimate the magnitude of the effect of the decline of natural gas prices on the coal-fired fleet by focusing on plants existing in 2008, prior to the drop in natural gas prices. The value of such plants is equal to their future operating profits discounted back to the present. We use the analysis in Linn et al. (2014b) to estimate the effect of the decline of natural gas prices on revenues and costs of power plants, which allows us to estimate the change in value for both natural gas- and coal-fired plants stemming from the change in gas prices. As noted previously, the reduction in natural gas prices between 2008 and 2012 reduced fuel costs of natural gas-fired plants by 60 percent and caused a shift from coal- to gas-fired generation. 
On balance, the annual profits of existing natural gas-fired plants increased 70 percent, and the annual profits of existing coal-fired plants decreased by 50 percent between 2008 and 2012. The large drop in coal-fired plant profits is consistent with the wave of coal-fired plant retirements that began after 2008. We expect the CPP to have a small effect on the profits of operating coal-fired power plants. The ultimate cost will depend on the implementation approach adopted by states and the degree to which states coordinate to reduce their compliance costs. Such coordination has emerged in previous EPA and regional trading programs, including the eastern Nitrogen Oxides Budget Trading Program and the northeastern Regional Greenhouse Gas Initiative. This suggests that states will coordinate for the CPP. 

The full paper is available free of charge at

by Joshua Linn, Dallas Burtraw, Kristen McCormack
Resources For the Future (RFF)
Discussion Paper 16-21; June 8, 2016; 30 pages

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