Is a Carbon Tax the Right Fit for Australia?

 

by Blaine Williams

Australia has relatively low overall levels of greenhouse gas emissions. However, due in part to its small population and large amounts of readily-available cheap energy, the country has the highest emissions per capita in the world. In a controversial move to combat these high levels of carbon emissions, the Australian government announced that it would be introducing a carbon emissions tax. Proponents of the tax cite lower emissions as a selling point, but those against the policy claim that economic contractions, spikes in unemployment, and higher fuel prices would make the policy less than worthwhile. Economists Xianming Meng, Mahinda Siriwardana, and Judith McNeill of the University of New England in Australia decided to measure what outcomes should be expected from said carbon tax, using a model other than those that had been presented by the government to support the policy. 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 Impact of Greenhouse Gas Emissions Generated By Industrial Wastewater Treatment Plants

Wastewater treatment plants produce greenhouse gasses (GHG’s) that include C02, CH4 and NOx during the water treatment process (Shahabadi et al., 2009). Industrial wastewater reclamation plants produce more GHG’s than municipal wastewater treatment plants because they contain more suspended solids and have a higher demand for biochemical oxygen. Wastewater treatment plants treat water by three main methods, which include aerobic, anaerobic and hybrid treatments of aerobic reactors and anaerobic solid digestion processes. The most efficient wastewater treatment process is a hybrid system that harnesses and reuses the biogas expelled by bacteria to power the plant. —Acadia Tucker
  Shahabadi B., Yerushalmi L., Haghighat F., 2009. Impact of process design on greenhouse gas (GHG) generation by wastewater treatment plants. Water Research 43, 26792687.

Bani Shahabadi and colleagues at Concordia University measured the GHG emissions created from the three different treatment methods listed above. The GHG calculation was based on both on-and off-site factors which include emissions during the nitrification and denitrification process, the impact and cost of external materials needed to treat the water, the amount of electricity consumed, the emissions from the decomposition of the waste byproduct and the amount of bio gas produced to help reduce the amount of electricity consumed.
They discovered that aerobic treatment methods produce the least amount of green house gasses while anaerobic and hybrid treatment methods produce the most because they require more off-site materials to run the plant effectively. However the best and most efficient treatment method for an industrial wastewater reclamation plant is a hybrid of aerobic rectors and anaerobic solid digestion with the use and recovery of biogas to operate the plant and reduce the demand for external electricity. The hybrid system offers a higher rate of nutrient and contaminate removal compared to anaerobic and aerobic processes alone and produce enough biogas from the decomposition of solid waste to power the whole plant. Furthermore, by lowering the temperature of anaerobic solid digestion, GHG emissions can further be reduced. In addition, producing all the materials needed for treatment on-site instead of transporting them from farther away can reduce GHG emissions produced from transportation. —Acadia Tucker

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.