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CONSERVATION GROUPS’ COMMENTS UNCOMPAHGRE FIELD OFFICE RMP AND DEIS 87 significantly underestimated and that a far more accurate emissions factor was 9,175 Mcf per well.259 The API/ANGA study suggested that this emission factor is 9,000 Mcf.260 However, these emissions factors are simply broad, generalized estimates for well emissions across the nation, and can vary significantly from one geologic formation to the next. For example, emissions reported in the Piceance Basin – particularly relevant, here – are as high as 22,000 Mcf of gas per well.261 The methane loss rate associated with EPA inventory figures is around 1%. However, other recent peer-review studies of methane emissions based on aircraft sampling, some of which are already identified herein, have reported substantially higher methane loss rates associated with oil and natural gas activity. Analyses conducted by the National Oceanic and Atmospheric Administration and University of Colorado found methane losses from oil and gas development in Colorado’s Denver-Julesberg Basin from 2.3-7.7%. See Petron et al. (attached as Exhibit 120). A study of Utah’s Uintah Basin found methane loss rates from 6-12%. See Karion et. al., (attached as Exhibit 119). A study analyzing air samples collected from tall towers and research aircraft found that methane emissions may be fifty-percent higher than EPA estimates.262 And another recent study, published in March 2014, also based on aircraft sampling, found methane emissions at natural gas drilling sites in Pennsylvania from 100 to 1000 times greater than EPA estimates.263 Despite this variability in methane pollution data, what remains clear is that inefficiencies and leakage in oil and gas production results in a huge amount of avoidable waste and emissions, and, conversely, a great opportunity for the UFO to reduce GHG emissions on our public lands. Many of these uncertainties and underestimates, as EPA has explained, are a result of the fact that emissions factors were “developed prior to the boom in unconventional well drilling (1992) and in the absence of any field data and does not capture the diversity of well completion and workover operations or the variance in emissions that can be expected from different hydrocarbon reservoirs in the country.” Mandatory GHG Reporting Rule, 75 Fed. Reg. 18608, 18621 (April 12, 2010). These underestimates are also caused by the dispersed nature of oil and gas equipment – rather than a single, discrete source, such as a coal-fired power plant, oil and gas production consists of large numbers of wells, tanks, compressor stations, pipelines, and other equipment that, individually, may appear insignificant but, cumulatively, may very well be quite significant. While dispersed, oil and gas development is nonetheless a massive, landscape-scale industrial operation – one that just happens to not have a single roof. BLM, as the agency charged with oversight of onshore oil and gas development, therefore has an opportunity to 259 See EPA, GHG Emissions Reporting at Appendix B at 84-87 (attached above as Exhibit 137). 260 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, at 3-69 (attached above as Exhibit 122). 261 See, e.g., EPA, Natural Gas STAR Program, Recommended Technologies and Practices for Wells, available at: www.epa.gov/gasstar/tools/recommended.html; see also EPA, Natural Gas STAR Program, Reduced Emissions Completions, Oct. 26, 2005, at 14 (attached as Exhibit 140). 262 Scott M. Miller, et al., Anthropogenic emissions of methane in the United States (2013) (attached as Exhibit 141). 263 Dana Caulton, et al., Toward a better understanding and quantification of methane emissions from shale gas development (2014) (attached as Exhibit 142).