Clean Power Plan Faces an Uncertain Future

by Emily Audet

The EPA’s Clean Power Plan (CPP), an enforcement plan of the Clean Air Act, establishes caps to carbon dioxide emissions of current power plants []. The CPP has been controversial since its beginning. In December 2016, Texas and West Virginia led 24 states in urging President Trump to overturn the CPP []. In response, many states and cities requested the preservation of the plan.

The implementation of the CPP is on hold as of January 2017 by order of the Supreme Court as the D.C. Circuit Court of Appeals reviews the legality of the plan, which could take days to years [].

On January 13, 2017, the EPA denied the majority of petitions challenging the plan or asking for a suspension of the plan’s implementation. The EPA claims that many of the petitions rejected by the EPA on January 13th raised similar issues to petitions included in the comment period of the CPP’s proposal. Of the 38 petitions asking for revisions of the plan, the EPA retained only 7 for further review. All 22 of the petitions advocating for a suspension of the CPP were rejected by the EPA on the grounds that the Supreme Court’s stay of the plan already achieves this end.

As of January 2017, the CPP’s future grows even more murky as it gets swept up in the uncertainty around environmental regulations in the new Trump administration. Throughout his campaign, Trump claimed that he would overturn the CPP, and an executive order from Trump could end the CPP, even before the courts release an official ruling on the plan. Scott Pruitt, the head of the EPA under the new Trump administration, has expressed his opinion that the EPA’s strategy to lower carbon emissions should focus on individual technology innovations in firms to decrease emissions, rather than encouraging firms to move from coal to other, cleaner forms of energy, which the CPP currently does. If the new administration tried to weaken the CPP, environmental non-profits would likely bring the plan to court. If the CPP is overturned, the EPA continues to hold the authority to implement the Clean Air Act through other vehicles. As of January 2017, the EPA offers resources and other forms of support for states to implement similar regulations on the state-level [].


Rodriguez, Juan Carlos. “EPA Denies Bids To Reconsider Or Stay Clean Power Plan.” Law 360. N.p., 13 Jan. 2017. Web. 24 Jan. 2017.

Profeta, Tim. “Fate of the Clean Power Plan Remains Uncertain.” National Geographic. N.p., 5 Jan. 2017. Web. 24 Jan. 2017.

Holden, Emily. “What Could Replace the Clean Power Plan?” Scientific American. N.p., 23 Jan. 2017. Web. 24 Jan. 2017.

US EPA. “Clean Power Plan for Existing Power Plants.” EPA. N.p., 12 Jan. 2017. Web. 24 Jan. 2017.




America’s “Roadmap” for 100% Renewable Energy by 2050


by Jesse Crabtree

In his new study posted in the Royal Society of Chemistry’s Energy & Environmental Science, Stanford professor of Civil and Environmental Engineering, Mark Jacobson, presents a plan for a 100% renewable energy-powered America by 2050. And what’s more, Jacobson believes this course of action to be not only economically feasible, but economically beneficial. Jacobson’s paper, which lays out specific roadmaps for how each state can work to achieve this goal, can be boiled down to three main ideas: exclusively build wind, solar, and hydro power plants after 2020; implement modest energy efficiency increases; and electrify everything. Although these three points are all required under Jacobson’s plan, this article discusses its most critical and ambitious goal; a complete shift to electric power. Continue reading

The Potential of Carbon Offsetting Programs and Travelers Willingness to Support Them

by Margaret Loncki

Tourism-related air travel has consistently been one of the fastest growing carbon releasing industries. Although, the industry has faced serious pressure to reduce their carbon output, it has struggled to find an efficient way to accomplish this. Choi and Ritchie (2014) aim to discover how much consumers are willing to pay to offset the CO2 emissions released by their travel. Many airlines have carbon offsetting programs that allow passengers to pay a fee to help fund carbon reducing research and development programs as well as the production and support for new and existing clean energy programs and renewable energy sources. Although most travelers understand the implications of the carbon released by their flights, only a fraction of passengers have supported the carbon offsetting programs offered by airlines. Continue reading

Risk Mitigation and the Social Cost of Carbon

by Makari Krause

In 2009 the Obama administration convened a working group to determine the social cost of carbon. To achieve this goal the group used three main models: Nordhaus’ (2008) ‘‘Dynamic Integrated Climate Economy’’(DICE) model; Hope’s (2008) ‘‘Policy Analysis of the Greenhouse Effect’’ (PAGE) model; and Anthoff and Tol’s (2010) ‘‘Climate Framework for Uncertainty, Negotiation, and Distribution’’ (FUND) model. The group decided to use discount rates of 2.5%, 3%, and 5% in each of the models. These discount rates were chosen based on a review of the literature. Continue reading

Reducing CO2 Emissions on the Electric Grid through a Carbon Disincentive Policy

by Stephanie Oehler

While energy production is widely acknowledged as a significant contributor to climate change, there is a discrepancy in opinion about what the most effective solution is to cut back on emissions. The most commonly addressed method of bringing about a smart grid is through new technologies that have the potential to improve distribution efficiency, encourage demand side management behaviors, and reduce the emissions associated with the production process. Policy change, however, is another route that has the potential to be more efficient in reducing emissions in the short term as technological developments are in progress. Li et al. (2013) examined the potential of several types of policy initiatives to modify electricity operator behavior in order to reduce CO2 emissions while continuing to meet energy demand. Basing their assumptions on the energy profile of Michigan, the authors created three models to represent different policy approaches: the first served as a baseline and represented the present energy cost and load distribution, the second imposed demand-side financial penalties for CO2 emissions, and the third created a carbon disincentive that produced a new pricing scheme for energy sources in terms of emissions. Continue reading

Evaluating the Uncertainty in Calculating Greenhouse Gas Emissions for Electricity Generation

Because 40% of U.S. CO2 emissions come from electricity generation and distribution, the ability to calculate CO2 emissions per unit of electricity consumed is crucial in order to perform a life-cycle analysis (LCA), be it of a product or process.  However, the greenhouse gas emissions associated with an individual entity’s electricity consumption is nearly impossible to calculate given the nature of electricity grids.  For this reason, LCA practitioners often employ emissions factors, or estimated average quantity of CO2 emitted per unit of energy consumed.  Unfortunately, emissions factors vary greatly both spatially and temporally due to different energy sources used for generation, as well as differing plant efficiencies. The authors point out that in addition to electricity coming from varying sources (for example, hydroelectric power provides much of the Pacific Northwests’s electricity due to the natural availability of that resource), electricity systems are quite complex because deregulation in the 1990s connected more remote customers with more remote generators, making it even more difficult to trace the source and associated greenhouse gas emissions of one’s electricity.  In this study Weber et al. (2010) calculated the variability in emissions factor estimates and demonstrated the uncertainty in using these estimates for LCA and policymaking.  The authors also made suggestions for how to deal with this uncertainty.—Lucy Block
Weber, C., Jaramillo, P., Marriott, J., and Samaras, C., 2010. Life Cycle Assessment and Grid Electricity: What Do We Know and What Can We Know? Environmental Science & Technology 44, 1895-1901.

          Christopher Weber, Paulina Jaramillo, Joe Marriott, and Constantine Samaras examine the uncertainty of emissions factors at various geographic levels of the U.S. and in different locales by collecting different emissions factors for CO2, SO2 and NOx (though CO2 contributes primarily to global warming and is thus the main focus of the paper).  The authors acknowledge that they did not take into account the emissions of upstream supply chains for electricity generation, noting that accounting for upstream emissions would only slightly increase uncertainty.  The authors calculated emissions factors along several potential regional delineations of the electric grid.  The emissions factor with the largest geographical area was the U.S. continental average (0.69 kg CO2/kWh), followed by three regions based on electrical grid connectivity—the Eastern, Western, and Texas Interconnects.  At a smaller level, Weber et al. used the 24 subregional grid delineations as defined by the EPA’s eGrid and used in the Greenhouse Gas Protocol, a tool for conducting LCAs.  Finally, the authors used data collected by the U.S. Energy Information Administration through voluntary greenhouse gas reporting since 1992.  The different datasets considered form seven independent estimates of electricity emission factors for every combination of U.S. state, eGrid subregion, and grid operator (whether independent system operators or regional transmission operators). 
For their dataset, the authors calculated a coefficient of variation (COV), or the normalized standard deviation.  A higher COV meant more variation between different estimates for electricity emissions factor, and therefore a higher uncertainty of amount of CO2 emitted per unit of electricity generation in the region.  The average CO2, COV for all delineations, or districts, considered out of 101 total was 0.19 (an average uncertainty of ±40% at two standard deviations) and ranged from a maximum of 0.70 to a minimum of 0.08.  The districts with highest associated uncertainty were those that had smaller or larger than average local or regional emissions factors.  Since electricity grids do not correlate closely with state borders, emissions factors estimated along state lines had higher variation than those estimated according to eGrid delineations. 
The authors conclude that LCA practitioners and policymakers generally do not have access to the data required in order to calculate a specific consumer’s electricity-related greenhouse gas emissions.  Therefore, for practical purposes, Weber et al. recommend that standards organizations provide clear guidelines for conducting LCA calculations, and by standardizing these calculations reduce overall comparative uncertainty between different LCAs.  The authors suggest that standards organizations should discourage the use of political borders in calculating emissions intensity for a particular area, as this unnecessarily increases uncertainty.  Furthermore, researchers should report kWhs consumed alongside the assumed grid emissions factor within an appropriate electricity system delineation, in order to increase transparency and allow for normalized comparisons of a specific product.  If estimating indirect CO2 emissions is required, Weber et al. suggest that researchers provide a range for the emissions factor.  In that case, if an entity wants to guarantee an emissions reduction or carbon neutrality, it can use the highest range of emissions factors. 
In public policy decisions, choosing a set of emissions factors will raise issues of equity.  If too general a set of emissions were to be used and an emissions trading market were to be set up, local distribution companies buying lower-carbon electricity would obtain an advantage, and local distribution companies buying higher-carbon electricity would be at a disadvantage.  Additionally, using more locally specific emissions factors could potentially penalize energy users in areas that have higher-carbon electricity simply due to natural resources.  For example, electricity in the Pacific Northwest will be lower-carbon because of the regional hydroelectric resources.  An industry located in the Pacific Northwest stands to lose less from policies to reduce carbon emissions than industries in other regions. 
The authors note that while it may be possible, depending on required level of accuracy for the investigation, to choose an appropriate emissions factor (e.g., if an industry operates in many locales throughout the country and the investigation does not require a particularly high level of accuracy in emissions calculations, one could use the national average emissions factor), consistency in calculating the indirect emissions of electricity consumption is of highest importance, along with transparency and reproducibility of methods.  

The United States may not have as much economically viable underground CO2 storage space as previously thought

A new model to predict the economic viability of CO2 geosequestration in sandstone saline aquifers indicates that previous estimates for storage potential in the U. S. may be overly optimistic (Eccles et al., 2009).  The model identifies an estimated minima for storage costs in a typical basin in the range of $2–7 per ton CO2 sequestered, based on estimates of a maximum CO2 storage potential and a maximum CO2 injection rate.    Eccles et al. use data from carbon capture and storage pilot projects to explain that many assumptions in their model lead to artificially high estimates for the maximum storage potential and the maximum injection rate, and as a result, they conclude that geosequestration will be even more expensive than their model conservatively indicates. However, Eccles et al. proceed to apply the model to identifying economically optimal storage basins in the United States.— Shanna Hoversten
Eccles, J., Pratson, L., Newell, R., Jackson, R., 2009. Physical and Economic Potential of Geological CO2 Storage in Saline Aquifers. Environmental Science & Technology 43, 1962–1969.


J. K. Eccles and colleagues at the Nicholas School of the Environment, Duke University, begin building their model by estimating maximum storage potential as a function of the optimal injection depth and the available void space in the formation.  However, this estimate does not account for the reality of most pilot projects, during which the CO2 has bypassed the majority of the available pore space.  The maximum injection rate is calculated based on a determination of the injection-induced pressure that would cause hydraulic fracturing beyond the perforated zone around the well. However, comparison of the modelled results with the pilot project at Nagaoka, Japan indicates that lower injection rates are probably more realistic due to engineering constraints and actual reservoir conditions.  The cost per ton of CO2 sequestered is generated based on the total cost of drilling, injection, equipment, and operation and maintenance, notably excluding the costs that would arise from capture and transport of the CO2.  Finally, the cost for storage in a typical basin in the United States was computed using estimates for storage potential and the cost per ton of CO2 stored. 

Results from the modelling indicate that although depth is an important determinant of storage potential, it is not the most important factor in storage cost.  While increased depth can increase the cost by a factor of two, layer thickness and permeability of the storage reservoir can increase cost by a factor of fifty.  This hints at the myriad of basin characteristics that need to be assessed before arriving at a viable cost estimate.  Additionally, costs within a single basin are likely to differ considerably due to the extreme variability in aquifer characteristics.  The most important conclusion that can be drawn from this analysis is that the amount of CO2 storage provided by low-cost regions within saline aquifers in the United States is considerably lower than the estimates reported by previous studies.  The study by Eccles et al. suggests that there are only perhaps ten storage reservoirs in the United States that would have an average storage cost of below $10 per ton CO2.  If more basins are to become economically viable for CO2 storage, then policymakers will need to devise a regime that imposes a rather significant cost on carbon.—Shanna Hoversten

Carbon Capture and Storage at power plants could substantially reduce GHG emissions

Carbon capture and storage (CCS) could be responsible for reducing global carbon emissions by up to 20%. To date there are no existing CCS power plants but experiments exist in the form of 1/10th-scale plants with 100% of emissions captured, and full size plants with 0.001% of emissions captured (Haszeldine, 2009). Since commercial CCS plants will not be built until several example plants are built, immediate funding of projects may be necessary if commercial plants are exected to be up and running by 2020.— Jake Bauch
 Haszeldine, R. Stuart, 2009. Carbon Capture and Storage: How Green Can Black Be? Science 325, 1647–1652

Stuart Haszeldine reviews the existing literature on CCS to find the issues to be resolved before construction can take place. There are unresolved issues with the capture, transport and storage of carbon. The three capture techniques, postcombustion, precombustion and oxyfuel combustion, are all comparable in terms of cost and efficiency. Barriers to entry for CCS are lack of legal standing in the form of performance standards and lack of economic incentive in the form of carbon being priced.  Several other factors are delaying construction even though the technology exists. Technological improvements are expected to increase efficiency by 20 to 60% and pipe sharing by multiple plants could reduce costs. New plants can be designed to easily convert to CCS when it is available. When it leaves the plants, captured carbon can be sent through pipes from power plants to the storage sites in aquifers, oil fields or gas fields.—Jake Bauch

How quickly can we switch to low carbon energy for our electrical production?

According to Gert Jan Kramer and Martin Haigh at Shell, not very fast (Kramer and Haigh, 2009). In a concise opinion piece in Nature they coin two laws of energy-technology development—that in the often 30-year start-up phase, all new energy initiatives such as oil, nuclear, liquid natural gas (LNG), biofuels, wind, and solar photovoltaics have grown exponentially at about 26% a year until they finally are producing a world-wide equivalent of about 500 barrels of oil a day, then the grow linearly until they reach their natural market share and level off. Even by shaving off some years in a concerted push to fully develop photovoltaics and carbon capture more quickly, by 2050 two-thirds of the world’s energy will still come from fossil fuels and CO2 concentrations would stabilize at around 550 ppm. If we were to try to stabilize CO2 at 450 ppm which is often thought of as the appropriate goal, we would have to be fully decarbonized—no more fossil fuel burning by the energy sector, or at least capturing all of the CO2 that results—by 2050. The only real solution to meet such an ambitious goal, they suggest, is to accept a decrease in energy consumption.—Emil Morhardt
Kramer, G., Haigh, M., 2009. No quick switch to low-carbon energy. Nature 462, 568-569.