Methane and the greenhouse-gas footprint of natural gas from shale formations

Robert W. Howarth • Renee Santoro • Anthony Ingraffea



We evaluate the greenhouse gas footprint of natural gas obtained by high-volume  hydraulic  fracturing from shale formations, focusing on methane emissions. Natural gas is composed largely of methane, and 3.6% to 7.9% of the methane from shale-gas  production escapes  to the atmosphere in venting  and leaks over the life- time  of a well. These  methane emissions  are  at least  30%  more  than  and perhaps more than twice as great as those from conventional gas. The higher emissions from shale  gas occur  at the  time  wells are  hydraulically fractured—as methane escapes from flow-back return fluids—and during drill out following the fracturing. Methane is a powerful greenhouse gas, with  a global  warming  potential that  is far  greater than  that  of  carbon  dioxide, particularly over  the  time  horizon  of  the  first  few decades  following  emission.  Methane contributes substantially to  the  greenhouse gas footprint of shale  gas on shorter time  scales, dominating it on a 20-year  time horizon.  The footprint for shale gas is greater than  that  for conventional gas or oil when viewed on any time  horizon,  but  particularly so over 20 years. Compared to coal, the footprint of shale gas is at least 20% greater and perhaps more  than  twice as great on the 20-year horizon  and is comparable when compared over 100 years.


Many view natural gas as a transitional fuel, allowing continued dependence on fossil fuels yet reducing  greenhouse gas (GHG) emissions  compared to oil or coal over coming decades (Pacala  and Socolow 2004). Development of “unconventional” gas dispersed in shale is part of this vision, as the potential resource may be large, and in many  regions  conventional reserves  are  becoming  depleted (Wood  et al. 2011). Domestic production in the  U.S. was predominantly from  conventional reservoirs through the  1990s, but  by 2009 U.S.  unconventional production exceeded that  of conventional gas. The  Department of Energy  predicts  that  by 2035 total  domestic production will grow by 20%,  with unconventional gas providing  75%  of the  total (EIA 2010a). The greatest growth is predicted for shale gas, increasing  from 16% of total production in 2009 to an expected 45% in 2035.


Although natural gas is promoted as a bridge  fuel over the coming few decades, in part because  of its presumed benefit  for global warming compared to other  fossil fuels, very little is known about  the GHG footprint of unconventional gas. Here,  we define the GHG footprint as the total GHG emissions from developing and using the gas, expressed as equivalents of carbon  dioxide, per unit of energy  obtained during combustion. The  GHG footprint of shale  gas has received  little  study  or scrutiny, although many have  voiced concern.  The National Research Council  (2009) noted emissions from shale-gas extraction may be greater than from conventional gas. The Council  of Scientific Society Presidents (2010) wrote  to President Obama, warning that some potential energy bridges such as shale gas have received insufficient  analysis and may aggravate rather than mitigate global warming. And in late 2010, the U.S. Environmental Protection Agency issued a report concluding  that fugitive emissions of methane from  unconventional gas may be far greater than  for conventional gas (EPA 2010).


Fugitive  emissions  of methane are  of particular concern.  Methane is the  major component of natural gas and a powerful greenhouse gas. As such, small leakages are important. Recent modeling  indicates  methane has an even greater global warming potential than  previously  believed,  when  the  indirect   effects  of  methane on  atmospheric aerosols are considered (Shindell et al. 2009). The global methane budget is poorly constrained, with multiple  sources and sinks all having large uncertainties. The radiocarbon content of atmospheric methane suggests fossil fuels may be a far larger source of atmospheric methane than generally  thought (Lassey et al. 2007).


The GHG footprint of shale gas consists of the direct emissions of CO2  from end- use consumption, indirect emissions of CO2  from fossil fuels used to extract, develop, and transport the gas, and methane fugitive emissions and venting. Despite the high level of industrial activity  involved  in developing shale  gas, the  indirect  emissions of CO2   are  relatively  small compared to those  from  the  direct  combustion of the fuel: 1 to 1.5 g C MJ−1  (Santoro et al. 2011) vs 15 g C M−1  for direct  emissions (Hayhoe et  al. 2002). Indirect emissions  from  shale  gas are  estimated to  be  only 0.04 to 0.45 g C MJ−1  greater than  those  for conventional gas (Wood  et al. 2011). Thus, for both  conventional and shale gas, the GHG footprint is dominated by the direct COemissions and fugitive methane emissions. Here  we present estimates for methane emissions  as contributors to the GHG footprint of shale gas compared to conventional gas.


Our  analysis  uses  the  most  recently   available   data,  relying  particularly on  a technical  background document on GHG emissions  from  the  oil and  gas industry (EPA 2010)  and  materials discussed  in  that  report, and  a  report on  natural  gas losses on federal  lands  from  the  General Accountability Office  (GAO 2010). The EPA   (2010)  report is  the  first  update on  emission  factors  by  the  agency  since 1996 (Harrison et al. 1996). The  earlier  report served  as the  basis for the  national GHG inventory for the past decade.  However, that study was not based on random sampling or a comprehensive assessment of actual industry  practices, but rather only analyzed  facilities  of companies that  voluntarily participated (Kirchgessner et  al. 1997). The  new  EPA  (2010)  report notes  that  the  1996 “study  was conducted at a time  when  methane emissions  were  not  a significant  concern  in the  discussion about GHG emissions” and that emission factors from the 1996 report “are outdated and  potentially understated for some  emissions  sources.”  Indeed, emission  factors presented in EPA  (2010) are much higher, by orders  of magnitude for some sources.



1 Fugitive methane emissions during well completion



Shale gas is extracted by high-volume hydraulic  fracturing. Large  volumes  of water are  forced  under  pressure into  the  shale  to  fracture and  re-fracture the  rock  to boost  gas flow. A significant  amount of this water  returns to the  surface  as flow-back within the first few days to weeks after  injection  and is accompanied by large quantities of methane (EPA 2010). The amount of methane is far more  than  could be  dissolved  in the  flow-back  fluids,  reflecting  a mixture  of fracture-return fluids and methane gas. We have compiled  data  from 2 shale gas formations and 3 tight-sand gas formations in the U.S. Between 0.6% and 3.2% of the life-time production of gas  from  wells is emitted as  methane during  the  flow-back  period  (Table  1). We include tight-sand formations since flow-back  emissions and the patterns of gas production over time are similar to those for shale (EPA 2010). Note that the rate of methane emitted during flow-back (column B in Table 1) correlates well to the initial production rate  for the well following completion (column  C in Table  1). Although the  data  are  limited,  the  variation across  the  basins  seems  reasonable: the  highest methane emissions during flow-back were in the Haynesville, where initial pressures and initial production were very high, and the lowest emissions  were in the Uinta, where  the  flow-back  period  was the  shortest and  initial  production following  well completion was low. However, we note  that  the  data  used  in Table  1 are  not  well documented, with  many  values  based  on  PowerPoint slides  from  EPA-sponsored workshops. For  this paper,  we therefore choose  to represent gas losses from  flow- back fluids as the mean value from Table 1: 1.6%.


More  methane is emitted during  “drill-out,” the  stage  in developing unconventional gas in which the plugs set to separate fracturing stages are drilled out to release gas for production. EPA  (2007) estimates drill-out  emissions  at 142 × 103  to 425 × 103 m3  per well. Using the mean drill-out  emissions estimate of 280 × 103 m3  (EPA 2007) and the mean  life-time  gas production for the 5 formations in Table  1 (85 × 106 m3 ), we estimate that 0.33% of the total life-time production of wells is emitted as methane during the drill-out stage. If we instead  use the average life-time production for a larger set of data on 12 formations (Wood et al. 2011), 45 × 106 m3 , we estimatea percentage emission of 0.62%. More effort is needed to determine drill-out emissions on individual  formation. Meanwhile, in this paper  we use the conservative estimate of 0.33% for drill-out  emissions.

Combining losses associated with flow-back  fluids (1.6%)  and drill out (0.33%), we estimate that 1.9% of the total production of gas from an unconventional shale-gas well is emitted as methane during well completion (Table  2). Again, this estimate is uncertain but conservative.

Emissions  are  far  lower  for  conventional natural gas wells during  completion, since conventional wells have no flow-back  and no drill out. An average  of 1.04 ×103 m3  of methane is released per well completed for conventional gas (EPA 2010), corresponding to 1.32 × 103 m3  natural gas (assuming 78.8% methane content of the gas). In 2007, 19,819 conventional wells were completed in the US (EPA 2010), so  we  estimate a  total  national emission  of  26 × 106 m3   natural gas.  The  total national production of onshore conventional gas in 2007 was 384 × 109  m3  (EIA 2010b). Therefore, we estimate the average  fugitive emissions at well completion for conventional gas as 0.01% of the life-time production of a well (Table 2), three orders of magnitude less than for shale gas.

Table 1  Methane emissions  during  the  flow-back  period  following  hydraulic  fracturing, initial  gas production rates  following  well completion, life-time  gas production of wells, and the methane emitted during flow-back  expressed as a percentage of the life-time production for five unconventional wells in the United States

Flow-back  is the return of hydraulic  fracturing fluids to the surface immediately after fracturing and before  well completion. For these wells, the flow-back period ranged  from 5 to 12 days


a Haynesville: average  from Eckhardt et al. (2009); Piceance: EPA  (2007); Barnett: EPA  (2004); Uinta: Samuels (2010); Denver-Julesburg: Bracken (2008). b Calculated by dividing the total methane emitted during flow-back (column  A) by the duration of flow-back. Flow-back  durations were 9 days for Barnett (EPA 2004), 8 days for Piceance  (EPA 2007), 5 days for Uinta  (Samuels  2010), and 12 days for Denver-Julesburg (Bracken 2008); median  value of 10 days for flow-back was assumed  for Haynesville. c Haynesville: and haynesvilleshalestocks.html; Barnett:; Piceance:  Kruuskraa (2004)  and  Henke (2010);  Uinta: archives/newsComments/6242.htm; Denver-Julesburg: Initial-Production-Rates. d Based  on  averages  for  these  basins.  Haynesville:; Barnett: and Wood et al. (2011); Piceance: Kruuskraa (2004); Uinta: e Calculated by dividing column (A) by column (D)

2 Routine venting and equipment leaks



After  completion, some fugitive emissions continue at the well site over its lifetime. A typical well has 55 to 150 connections to equipment such as heaters, meters,  dehydrators, compressors, and vapor-recovery apparatus. Many of these potentially leak, and  many  pressure relief  valves are  designed  to  purposefully vent  gas. Emissions from pneumatic pumps and dehydrators are a major part of the leakage (GAO 2010). Once a well is completed and connected to a pipeline, the same technologies are used for both  conventional and shale gas; we assume  that  these  post-completion fugitive emissions are the same for shale and conventional gas. GAO (2010) concluded that 0.3% to 1.9% of the life-time production of a well is lost due to routine venting and equipment leaks (Table  2). Previous  studies have estimated routine well-site fugitive emissions as approximately 0.5% or less (Hayhoe et al. 2002; Armendariz 2009) and 0.95%  (Shires  et al. 2009). Note  that  none  of these  estimates include  accidents  or emergency vents. Data  on emissions during emergencies are not available  and have never,  as far  as we can  determine, been  used  in any  estimate of emissions  from natural gas production. Thus, our estimate of 0.3% to 1.9% leakage  is conservative. As we discuss below, the 0.3% reflects use of best available  technology.


Additional venting  occurs  during  “liquid  unloading.” Conventional  wells  frequently  require multiple  liquid-unloading events  as they  mature to mitigate  water intrusion as reservoir pressure drops. Though  not as common,  some unconventional wells may also require unloading.  Empirical data from 4 gas basins indicate  that 0.02 to 0.26% of total  life-time  production of a well is vented  as methane during  liquid unloading (GAO 2010). Since not all wells require unloading,  we set the range  at 0 to 0.26% (Table  2).

Table 2  Fugitive methane emissions associated with development of natural gas from conventional wells and from shale formations (expressed as the percentage of methane produced over the lifecycle of a well).


See text for derivation of estimates and supporting information

3 Processing losses



Some natural gas, whether conventional or from shale, is of sufficient  quality  to be “pipeline ready” without further processing. Other gas contains sufficient amounts of heavy hydrocarbons and impurities such as sulfur gases to require removal  through processing before  the gas is piped. Note that the quality of gas can vary even within a formation. For example,  gas from the Marcellus  shale in northeastern Pennsylvania needs  little  or  no  processing,  while  gas from  southwestern Pennsylvania must  be processed (NYDEC 2009). Some  methane is emitted during  this  processing.  The default  EPA  facility-level fugitive emission factor for gas processing  indicates  a loss of 0.19% of production (Shires et al. 2009). We therefore give a range of 0% (i.e. no processing,  for wells that produce “pipeline ready”  gas) to 0.19% of gas produced as our estimate of processing losses (Table 2). Actual measurements of processing plant emissions in Canada showed fourfold greater leakage  than standard emission factors of the sort used by Shires et al. (2009) would indicate (Chambers 2004), so again, our estimates are very conservative.



4 Transport, storage, and distribution losses



Further fugitive emissions occur during transport, storage, and distribution of natural gas. Direct  measurements of leakage  from transmission are limited,  but two studies give similar leakage  rates in both  the U.S. (as part  of the 1996 EPA  emission factor study; mean  value of 0.53%; Harrison et al. 1996; Kirchgessner et al. 1997) and  in Russia  (0.7%  mean  estimate, with a range  of 0.4% to 1.6%; Lelieveld  et al. 2005). Direct  estimates of distribution losses  are  even  more  limited,  but  the  1996 EPA study  estimates losses at 0.35%  of production (Harrison et al. 1996; Kirchgessner et al. 1997). Lelieveld  et al. (2005) used  the  1996 emission  factors  for natural gas storage  and  distribution together with  their  transmission estimates to  suggest  an overall average  loss rate of 1.4% (range  of 1.0% to 2.5%). We use this 1.4% leakage as the likely lower limit (Table 2). As noted  above, the EPA  1996 emission estimates are  based  on  limited  data,  and  Revkin  and  Krauss  (2009)  reported “government scientists and industry officials caution that the real figure is almost certainly higher.” Furthermore, the  IPCC  (2007)  cautions   that  these  “bottom-up”  approaches for methane inventories often underestimate fluxes.


Another way to estimate pipeline leakage is to examine “lost and unaccounted for gas,” e.g. the difference between the measured volume of gas at the wellhead and that actually purchased and used by consumers. At the global scale, this method has estimated pipeline leakage at 2.5% to 10% (Crutzen 1987; Cicerone and Oremland 1988; Hayhoe et al. 2002), although the higher value reflects poorly maintained pipelines in Russia during the Soviet collapse, and leakages  in Russia are now far less (Lelieveld et al. 2005; Reshetnikov et al. 2000). Kirchgessner et al. (1997) argue  against  this approach, stating  it is “subject  to numerous errors  including  gas theft,  variations in temperature and  pressure, billing cycle differences, and  meter  inaccuracies.” With the exception of theft,  however,  errors  should  be randomly distributed and should not bias the leakage  estimate high or low. Few recent  data on lost and unaccounted gas are publicly available,  but statewide data  for Texas averaged 2.3% in 2000 and 4.9% in 2007 (Percival  2010). In 2007, the State  of Texas passed  new legislation  to regulate lost and unaccounted for gas; the legislation  originally proposed a 5% hard cap which was dropped in the face of industry  opposition (Liu 2008; Percival 2010). We take the mean of the 2000 and 2007 Texas data for missing and unaccounted gas (3.6%)  as the upper  limit of downstream losses (Table  2), assuming that  the higher value for 2007 and lower value for 2000 may potentially reflect random variation in billing cycle differences. We believe  this is a conservative upper  limit, particularly given the industry  resistance to a 5% hard cap.


Our  conservative estimate of 1.4%  to 3.6%  leakage  of gas during  transmission, storage,  and distribution is remarkably similar to the 2.5% “best  estimate” used by Hayhoe et al. (2002). They considered the possible range as 0.2% and 10%.



5 Contribution of methane emissions to the GHG footprints of shale gas and conventional gas



Summing  all estimated losses, we calculate  that  during  the life cycle of an average shale-gas  well, 3.6 to  7.9%  of the  total  production of the  well is emitted to  the atmosphere as methane (Table  2). This  is at  least  30%  more  and  perhaps more than twice as great as the life-cycle methane emissions we estimate for conventional gas, 1.7%  to  6%.  Methane is a far  more  potent GHG than  is CO2 , but  methane also has a tenfold  shorter residence time in the atmosphere, so its effect on global warming attenuates more rapidly (IPCC 2007). Consequently, to compare the global warming potential of methane and CO2   requires a specific time horizon.  We follow Lelieveld  et  al.  (2005)  and  present analyses  for  both  20-year  and  100-year  time horizons. Though the 100-year horizon is commonly used, we agree with Nisbet et al. (2000) that  the 20-year horizon  is critical, given the need  to reduce  global warming in coming  decades  (IPCC  2007). We  use  recently  modeled values  for  the  global warming potential of methane compared to CO2: 105 and 33 on a mass-to-mass basis for 20 and 100 years, respectively, with an uncertainty of plus or minus 23% (Shindell et al. 2009). These  are somewhat higher than  those  presented in the 4th assessment report of the  IPCC  (2007), but  better account  for the  interaction of methane with aerosols.  Note  that  carbon-trading markets use  a lower  global-warming potential yet of only 21 on the  100-year  horizon,  but  this is based  on the  2nd IPCC  (1995) assessment, which is clearly out of date  on this topic. See Electronic Supplemental Materials for the methodology for calculating the effect of methane on GHG in terms of CO2 equivalents.


Methane dominates the GHG footprint for shale gas on the 20-year time horizon, contributing 1.4- to 3-times  more  than  does  direct  CO2   emission  (Fig. 1a). At  this time  scale,  the  GHG footprint for shale  gas is 22%  to 43%  greater than  that  for conventional gas. When  viewed  at  a time  100 years  after  the  emissions,  methane emissions  still  contribute significantly  to  the  GHG  footprints, but  the effect is diminished by the relatively  short residence time of methane in the atmosphere. On this time frame, the GHG footprint for shale gas is 14% to 19% greater than that for conventional gas (Fig. 1b).

Fig. 1 Comparison of greenhouse gas emissions  from  shale  gas with  low and  high  estimates of fugitive methane emissions, conventional natural gas with low and high estimates of fugitive methane emissions,  surface-mined coal, deep-mined coal, and diesel oil. a is for a 20-year time horizon,  and b is for a 100-year time horizon.  Estimates include direct emissions of CO2  during combustion (blue bars), indirect  emissions  of CO2   necessary  to develop  and  use the  energy  source  (red bars), and fugitive emissions  of methane, converted to equivalent value of CO2  as described in the text (pink bars). Emissions  are normalized to the quantity of energy  released at the time of combustion. The conversion of methane to CO2  equivalents is based on global warming potentials from Shindell et al. (2009) that  include  both  direct  and  indirect  influences  of methane on aerosols.  Mean  values from Shindell et al. (2009) are used here. Shindell et al. (2009) present an uncertainty in these mean values of plus or minus 23%, which is not included  in this figure.

6 Shale gas versus other fossil fuels



Considering the  20-year  horizon,  the  GHG footprint for shale  gas is at least  20% greater than and perhaps more than twice as great as that for coal when expressed per quantity of energy available during combustion (Fig. 1a; see Electronic Supplemental Materials for derivation of the estimates for diesel oil and coal). Over  the 100-year frame,  the  GHG footprint is comparable to  that  for  coal:  the  low-end  shale-gas emissions are 18% lower than deep-mined coal, and the high-end shale-gas emissions are 15% greater than surface-mined coal emissions (Fig. 1b). For the 20 year horizon, the GHG footprint of shale gas is at least 50% greater than for oil, and perhaps 2.5- times greater. At the 100-year time scale, the footprint for shale gas is similar to or 35% greater than for oil.


We know of no other  estimates for the GHG footprint of shale gas in the peer- reviewed  literature. However, we can compare our  estimates for conventional gas with three  previous  peer-reviewed studies  on the  GHG emissions  of conventional natural gas and coal: Hayhoe et al. (2002), Lelieveld et al. (2005), and Jamarillo et al. (2007). All  concluded that  GHG emissions  for conventional gas are  less than  for coal, when considering the contribution of methane over 100 years. In contrast, our analysis  indicates  that  conventional gas has  little  or  no  advantage over  coal even over the 100-year time period  (Fig. 1b). Our estimates for conventional-gas methane emissions are in the range of those in Hayhoe et al. (2002) but are higher than those in Lelieveld  et al. (2005) and  Jamarillo et al. (2007) who used  1996 EPA  emission factors now known to be too low (EPA 2010). To evaluate the effect of methane, all three of these studies also used global warming potentials now believed to be too low (Shindell  et al. 2009). Still, Hayhoe et al. (2002) concluded that  under  many of the scenarios  evaluated, a switch from coal to conventional natural gas could aggravate global warming on time scales of up to several  decades.  Even with the lower global warming  potential value,  Lelieveld  et  al. (2005)  concluded that  natural gas has  a greater GHG footprint than oil if methane emissions exceeded 3.1% and worse than coal if the emissions exceeded 5.6% on the 20-year time scale. They used a methane global warming  potential value for methane from IPCC  (1995) that  is only 57% of the new value from Shindell et al. (2009), suggesting  that  in fact methane emissions of only 2% to 3% make  the GHG footprint of conventional gas worse than  oil and coal. Our estimates for fugitive shale-gas emissions are 3.6 to 7.9%.


Our  analysis  does  not  consider  the  efficiency  of final  use.  If fuels  are  used  to generate electricity,  natural gas gains some advantage over coal because  of greater efficiencies  of generation (see  Electronic Supplemental Materials). However, this does  not  greatly  affect  our  overall  conclusion:  the  GHG footprint of shale  gas approaches or exceeds coal even when used to generate electricity  (Table  in Electronic Supplemental Materials). Further, shale-gas is promoted for other  uses, including as a heating  and transportation fuel, where  there  is little evidence  that  efficiencies  are superior to diesel oil.



7 Can methane emissions be reduced?



The EPA  estimates that ’green’ technologies can reduce  gas-industry  methane emissions by 40% (GAO 2010). For instance,  liquid-unloading emissions  can be greatly reduced with plunger  lifts (EPA 2006; GAO 2010); industry  reports a 99% venting reduction in the San Juan basin with the use of smart-automated plunger  lifts (GAO 2010). Use of flash-tank separators or vapor  recovery  units can reduce  dehydrator emissions  by 90% (Fernandez et al. 2005). Note,  however,  that  our lower range  of estimates for 3 out  of the  5 sources  as shown  in Table  2 already  reflect  the  use of best technology:  0.3% lower-end estimate for routine venting and leaks at well sites (GAO 2010), 0% lower-end estimate for emissions during liquid unloading,  and 0% during processing.


Methane emissions during the flow-back period  in theory can be reduced by up to 90%  through Reduced Emission  Completions technologies, or REC  (EPA 2010). However, REC  technologies require that  pipelines  to  the  well are  in place  prior to completion, which is not always possible  in emerging  development areas.  In any event, these technologies are currently not in wide use (EPA 2010).


If emissions  during  transmission, storage,  and distribution are at the high end of our estimate (3.6%; Table 2), these could probably be reduced through use of better storage tanks and compressors and through improved monitoring for leaks. Industry has shown little interest in making the investments needed to reduce  these emission sources, however  (Percival  2010).

Better regulation can help push industry  towards  reduced emissions. In reconciling a wide range  of emissions,  the  GAO (2010) noted  that  lower  emissions  in the Piceance  basin in Colorado relative  to the Uinta  basin in Utah  are largely due to a higher use of low-bleed  pneumatics in the former  due to stricter  state regulations.



8 Conclusions and implications



The GHG footprint of shale gas is significantly  larger  than  that  from conventional gas, due  to  methane emissions  with  flow-back  fluids  and  from  drill  out  of wells during well completion. Routine production and downstream methane emissions are also large, but are the same for conventional and shale gas. Our  estimates for these routine and  downstream methane emission  sources  are  within  the  range  of those reported by most other  peer-reviewed publications inventories (Hayhoe et al. 2002; Lelieveld et al. 2005). Despite this broad agreement, the uncertainty in the magnitude of fugitive emissions  is large. Given  the importance of methane in global warming, these  emissions  deserve  far greater study  than  has occurred in the  past.  We urge both  more  direct  measurements and refined  accounting to better quantify  lost and unaccounted for gas.


The large GHG footprint of shale gas undercuts the logic of its use as a bridging fuel over coming decades,  if the goal is to reduce  global warming. We do not intend that our study be used to justify the continued use of either  oil or coal, but rather to demonstrate that substituting shale gas for these other  fossil fuels may not have the desired  effect of mitigating climate warming.

Finally,  we note  that  carbon-trading markets at present under-value the  greenhouse  warming  consequences of methane, by focusing on a 100-year time  horizon and  by using  out-of-date global  warming  potentials for  methane. This  should  be corrected, and  the  full  GHG footprint of  unconventional gas  should  be  used  in planning   for  alternative energy  futures   that  adequately consider   global  climate change.






Preparation of this paper  was supported by a grant from the Park Foundation and by an endowment funds of the David  R. Atkinson Professorship in Ecology  & Environmental Biology  at  Cornell  University. We  thank   R.  Alvarez,   C.  Arnold, P.  Artaxo, A.  Chambers, D. Farnham, P. Jamarillo, N. Mahowald, R. Marino,  R. McCoy, J. Northrup, S. Porder, M. Robertson, B. Sell, D. Shrag, L. Spaeth,  and D. Strahan for information, encouragement, advice, and feedback on our analysis and manuscript. We thank  M. Hayn for assistance  with the figures. Two anonymous reviewers  and  Michael  Oppenheimer provided very useful comments on an earlier  version  of this paper.






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Received:  12 November 2010 / Accepted: 13 March 2011


Robert W. Howarth • Renee Santoro • Anthony Ingraffea


R. W. Howarth (B) • R. Santoro


Department of Ecology and Evolutionary Biology, Cornell  University, Ithaca,  NY 14853, USA



A. Ingraffea


School of Civil and Environmental Engineering, Cornell  University, Ithaca,  NY 14853, USA




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