The Regional Greenhouse Gas Initiative (RGGI) was supposed to be nearing completion of a 2016 Program Review but the election of Donald Trump and the fate of the national Clean Power Plan has delayed that process. This is the second post in a series of posts that will discuss how RGGI has fared so far and how that could affect the program review. As noted previously, I believe that RGGI allowance prices add to the cost of doing business but because the cost of allowances can be added into the bid price it is a nuisance and not a driver of decisions. I will show how this added cost ultimately affects emissions in this post.
I have been involved in the RGGI program process since its inception. Before retirement from a Non-Regulated Generating company, I was actively analyzing air quality regulations that could affect company operations and was responsible for the emissions data used for compliance. The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.
RGGI Region CO2 Emission Reductions
For this analysis the RGGI reductions in the first two compliance periods of 2009-2011 and 2012-2014 will be compared to a pre-program baseline of 2006-2008. Note that this is an update to the estimates provided in an earlier post to incorporate RGGI’s latest Investment Summary Report . table-1-rggi-annual-co2-changes lists the changes in CO2 emissions in the RGGI states by fuel type. Note that this analysis uses EPA data and is not completely compatible with the RGGI affected source inventory.
The total and fuel-type specific annual emissions were subtracted from the baseline to get the reductions during the RGGI program. For the facilities in this dataset in the 2012-2104 compliance period there has been a 36 million ton reduction from the 127 million ton baseline or a 28% reduction. Note that coal and residual oil emissions dropped 49 million tons from the baseline of 85 million tons or 57%. Natural gas emissions increased 13 million tons and other solids (mostly wood) increased 0.5 million tons. Over the same time period, gross loads and steam load declined 20% and 55%, respectively.
According to the most recent RGGI Investment Summary Report “The lifetime effects of these RGGI investments are projected to save 76.1 million MMBtu of fossil fuel energy and 20.6 million MWh of electricity, avoiding the release of approximately 15.4 million short tons of carbon pollution.” In the 2012-2014 compliance period RGGI CO2 emissions were 91,421,635 tons of CO2 so based on this RGGI report were it not for RGGI there would have been 15.4 million more tons of CO2 emitted so total emissions would have been 106,821,635 tons. I also calculated the percentage difference with and without the program and that shows emissions would have been 17% higher than without the program.
A paper by Murray and Maniloff (2015) includes an estimate of RGGI program emission reductions. They concluded that “after the introduction of RGGI in 2009 the region’s emissions would have been 24 percent higher without the program, accounting for about half of the region’s emissions reductions during that time”. The April 29 2016 RGGI stakeholder presentation described that paper and further suggested that “The other half is due to recession, complementary environmental programs and lowered natural gas prices.” The results in this paper are based on an econometric modelling analysis.
After the publication of the Murray and Maniloff paper I contacted the authors with my reservations about their approach. After an initial response from Dr. Maniloff to my reservations I never received a follow up to my response. One disagreement was whether CO2 is different than all other air pollutants such that this undermines their explanation of how firms react to carbon constraints. I took exception to their characterization “firms facing a future carbon price regime may have reacted by retooling power plants to lower emitting processes in advance of the regulation taking effect”. I noted that there are no end of pipe abatement technologies for CO2, as there are for other pollutants (e.g. SO2 scrubbers) save for CCS which is not economic. Dr Maniloff responded that “this hardly means there are not actions that can be taken in response to the carbon constraints. Plants can improve efficiency (heat rate) at fossil units as they have, and firms can engage in fuel switching/redispatch from coal and oil to gas and renewables, as they have.” I responded that this is fine in theory but in practice, especially in a de-regulated market, the control strategy is to simply run with the allowances that are purchased. Heat rate improvements run the risk of running afoul of New Source Review requirements. If EPA determines that facility upgrades improve performance above their thresholds, then that the facility must upgrade its pollution control equipment to new source standards. Improvement to heat rate would likely throw the facility into NSR immediately and the costs of that equipment cannot be directly recovered in the bid price and those costs would overwhelm any value to RGGI compliance. The cost of carbon has been so low relative to the fuel cost that a switch to natural gas was the driver only based on fuel costs. Affected de-regulated sources do not re-dispatch to the operator’s renewables, they simply run less. Practically speaking for RGGI affected sources CO2 control was different because the only viable option was to run based on allowances purchased.
I think the biggest problem is that econometric models cannot fully account for site specific regulation impacts. No model can account for all the effects of regulations on company decisions to invest in new control equipment unless each facility is explicitly considered. Because of my particular experience in New York I have explicitly considered the factors affecting particular facilities when analyzing the impact of regulations. Consider, for example, the coal-fired RG&E Russel station in Rochester, NY and the NRG Huntley station outside Buffalo, NY. Before RGGI began the owners were faced with decisions for the future.
Before 2009, Russel station needed to invest in pollution control equipment for particulates, Hg and NOx or the facility would not be able to operate and meet emission compliance requirements already on the books. It operated from 2006-2008 (emitting ~ one million tons of CO2) but retired before 2009. I believe the owners decided that they might not be able to recover the costs for all the pollution control equipment over time so they decided to retire the facility. RGGI compliance is only an issue when the unit runs and simply adding the allowance cost to the bid price insures that cost is recovered. Therefore, I conclude that none of the observed reductions from this facility can be ascribed to RGGI.
At the other end of the spectrum for New York coal facilities is Huntley. This facility retired in early 2016 even though its owners made investments in pollution controls to meet the opacity, Hg and NOx limits. Despite those investments the facility closed like many other coal-fired plants because the operating cost of burning coal was not competitive with gas-fired competition. Presumably the erosion of load due to the recession and loss of manufacturing higher load requirements also played a factor. It can be argued that adding the allowance price to their bids meant the unit ran less. In practice I believe that this factor was small. It is only when the added price is enough to change the order of the bids in a step-wise fashion that there is an effect. My understanding is that the allowance price is so small relative to the fuel price differential that it was inconsequential. Given the range of factors affecting these coal units we can assume that New York coal retirements and operating reductions are more likely due to non-RGGI factors than RGGI itself. Ultimately, look at it this way – in the absence of RGGI the facilities would still have retired so any modeling approach that presumes that RGGI influenced the NYS coal retirements is wrong.
The lower bound for RGGI program CO2 emissions reductions during this period can also be estimated. It can be argued that the coal and residual oil emissions were lower due solely to the changes in cost differences relative to natural gas and additional regulations and compliance pressure for NOx, Hg, and (in New York) opacity. This assumes that RGGI compliance is incorporated into the bid price and so was not a driver in facility pollution control decisions. Making those assumptions then means that the CO2 reductions directly due to RGGI should be the savings of 76.1 million mmBtu of generation from natural gas specifically and the natural gas emission factor for CO2 should be used for CO2 displacement. Table 3 lists this calculated value, 4,452,850 tons. This calculation shows that emissions would have been only 5% higher than without the program.
To summarize, there is a range of CO2 emissions with and without RGGI based on assumptions and methodology. The upper bound is an econometric model that estimates that emissions would have been 24 percent higher without the program. RGGI estimates that emissions would have been 17% higher than without a program. If you assume that all the savings in fossil fuel use only displaced natural gas use then emissions would have been only 5% higher.
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