Emissions Implications of Future Natural Gas Production and Use in

Oct 20, 2014 - Policy-driven constraints or emissions fees are needed to achieve net reductions. In most scenarios, wind is a less expensive source of...
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Emissions Implications of Future Natural Gas Production and Use in the U.S. and in the Rocky Mountain Region Jeffrey D. McLeod,† Gregory L. Brinkman,‡ and Jana B. Milford*,† †

Department of Mechanical Engineering, University of Colorado at Boulder, Boulder, Colorado 80309, United States Strategic Energy Analysis Center, National Renewable Energy Laboratory, 15013 Denver West Parkway, Golden, Colorado 80401, United States

‡

S Supporting Information *

ABSTRACT: Enhanced prospects for natural gas production raise questions about the balance of impacts on air quality, as increased emissions from production activities are considered alongside the reductions expected when natural gas is burned in place of other fossil fuels. This study explores how trends in natural gas production over the coming decades might affect emissions of greenhouse gases (GHG), volatile organic compounds (VOCs) and nitrogen oxides (NOx) for the United States and its Rocky Mountain region. The MARKAL (MARKet ALlocation) energy system optimization model is used with the U.S. Environmental Protection Agency’s nineregion database to compare scenarios for natural gas supply and demand, constraints on the electricity generation mix, and GHG emissions fees. Through 2050, total energy system GHG emissions show little response to natural gas supply assumptions, due to offsetting changes across sectors. Policy-driven constraints or emissions fees are needed to achieve net reductions. In most scenarios, wind is a less expensive source of new electricity supplies in the Rocky Mountain region than natural gas. U.S. NOx emissions decline in all the scenarios considered. Increased VOC emissions from natural gas production offset part of the anticipated reductions from the transportation sector, especially in the Rocky Mountain region.

1. INTRODUCTION In the past decade, natural gas (NG) has risen to the forefront of the U.S. energy supply landscape as a cheap, domestically abundant fossil fuel with lower direct use emissions than coal and petroleum. The combination of hydraulic fracturing and horizontal drilling has facilitated this rise by enabling economical production of shale gas.1 U.S. proven reserves of shale gas more than quadrupled from 23.3 trillion cubic feet (Tcf) to 132 Tcf between 2007 and 2011; growth in production from shale reserves resulted in a 35% increase in overall NG production from 2005 to 2013.2 Over the same period, electricity generation from NG increased by 46% while generation from coal and petroleum fell by 21% and 78%, respectively.3 The U.S. Energy Information Administration (EIA) projects that NG production and use will continue to expand over coming decades.4 Concerns about the environmental impacts associated with expanded production and use of NG have accompanied the shale gas boom. NG has been touted as a “bridge fuel” between coal and renewables, as its combustion produces about half the carbon dioxide (CO2) per unit of electricity generation of coal.5,6 However, the net GHG emissions impact is less clear, due to uncertainty surrounding the amount of methane leakage during NG extraction, processing, transmission and distribution7−10 as well as the potential for NG to slow penetration of © 2014 American Chemical Society

renewable technologies into the electricity mix. In addition, NG production activities may contribute to adverse effects on local and regional air quality, due to emission of VOC, NOx, particulate matter, and hazardous air pollutants.10 The Rocky Mountain (RM) region contains multiple NG basins that account for a significant portion of past and projected growth in shale gas production. Of the dry NG produced in the U.S. from 2005 to 2012, 18% came from Colorado, Utah, and Wyoming.2 The influence of oil and NG operations on emissions of VOCs and NOx in this region has been demonstrated by direct measurement studies,11−13 and episodes of high tropospheric ozone formation have been linked to these precursors.14−16 The objectives of this study are to characterize future GHG, VOC, and NOx emission trends for the U.S. as a whole and for the Rocky Mountain region that result from contrasting scenarios for future NG production, and from alternative policies for reducing GHG emissions or encouraging renewables. The study includes emissions from NG production as well as from electricity generation and other end-use Received: Revised: Accepted: Published: 13036

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A strength of the EPA MARKAL model is its inclusion of energy-related emissions of criteria pollutants and GHG, including emissions from resource extraction and upstream processing as well as energy conversion processes. The model includes direct emissions control options (e.g., flue gas desulfurization) for electricity generating units and some sources in the industrial sector. Emissions in other end-use sectors, including transportation, are determined by choice of technology. The model incorporates emissions limits corresponding to the Clean Air Interstate Rule,25 and Mercury Air Toxics Standards,26 light duty fuel economy constraints corresponding to the 2012 CAFE standards,27 and state-level renewable portfolio standards. EPA’s US9r database contains inputs that require MARKAL to match real-world conditions for 2005−2010. The least-cost optimization model is solved for subsequent years. Further details on the EPA MARKAL model are available in the model documentation17,28,29 and from previous application studies.17,30−32 2.1. Changes to the MARKAL Base Case Assumptions. Several adjustments to EPA’s US9r database were made in this study to reflect updated or refined source information and correct a few errors. As detailed in McLeod,33 changes included updating the cost and performance data for new electric generating plants to estimates from AEO 2013;34 updating state renewable portfolio standards to reflect 2013 developments (www.dsireusa.org); eliminating geothermal electricity as an option in regions without significant resources; restricting renewal of coal plants to impose a maximum operating lifetime of 75 years; increasing the cost of new electricity transmission capacity to match assumptions from NREL (2012);20 and replacing AEO 2012 cost information for PV and wind with information developed for NREL by Black and Veatch.35 2.2. Changes to NG Supply and NG Production Emissions Assumptions. The unaltered US9r database did not distinguish between unconventional and conventional NG resources. However, emissions may differ between them,7 so for this study unconventional gas production was estimated as a fraction of total NG production in each region. Forecasts from IHS Global Insight36 and AEO 201319 were used for this purpose. The original emissions factors for CO2 and methane from NG production and processing were replaced with values estimated by Weber and Clavin,37 who developed their estimates based on review and reanalysis of several prior studies. GHG emissions for NG distribution were left unchanged from their original values, which EPA derived from the GREET life cycle assessment database.38 For 2010, the new upstream NG emissions factors for methane range from 0.37−0.42 g/MJ across the regions (depending on unconventional production fractions). These emissions factors are equivalent to upstream leakage rates of 2.1−2.4%. Revised NG production emissions factors for NOx, VOC, SO2, and CO were derived from results of the West-wide Jumpstart Air Quality Modeling Study, which covers the main energyproducing basins in the RM region.39 The production-weighted average of emissions per unit of production across these basins was assumed to apply across the country. Additional details about these changes and discussion of the methane leakage rates are provided in the Supporting Information (SI). Going forward, New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAPS) that EPA promulgated for the oil and gas sector in August 2012 are expected to reduce methane and VOC

technologies. It features a scenario-based assessment for a time horizon out to 2050 using the MARKAL energy system optimization model with the U.S. Environmental Protection Agency (EPA)’s U.S. nine-region (US9r) database.17,18 Past modeling studies have used scenario-based approaches to investigate trends in regional and national electricity generation and GHG emissions under various assumptions characterizing the energy system, including some specifically designed to assess the future role of NG.5,19−23 This study is distinguished from previous work in that it utilizes EPA’s nineregion database, which provides detailed estimates of both GHG and criteria pollutant emissions associated with an expansive set of processes describing the U.S. energy system.18 In contrast, previous studies have focused on the electric power sector alone5,20,21,23 or considered GHG emissions but not criteria pollutants.22,23 This study goes beyond the standard US9r database for MARKAL by incorporating recent estimates for NG production-related emissions of VOC, NOx, CO2, and methane, along with updated estimates of cost and performance for renewable technologies. The study thus provides a novel exploration of the implications of future NG production and use on VOC, NOx, and GHG emissions for an important natural gas supply region as well as at the national scale.

2. MATERIALS AND METHODS EPA’s implementation of the MARKAL model is used to compare future scenarios for NG production and use in the context of the overall U.S. energy system, including energy resource extraction, processing and distribution, electricity production, and electricity or fuel use in the transportation, industrial, commercial, and residential sectors. MARKAL finds the least cost means to satisfy future end use demand, under specified constraints including limits on fuel supplies and on rates of capacity expansion and introduction of new technology. Constraints can also be imposed on emissions or use of specified types of technology. Demand is specified in terms of services, rather than energy, allowing for adoption of end-use technologies that improve energy efficiency. In the MARKAL base case “business as usual” modeling results, residential sector energy use increases by 13.5% from 2010 to 2050, commercial by 32.7%, and industrial by 38.4%. Transportation sector energy use decreases by 0.7% despite increased demand, due to projected efficiency improvements. The model is run with EPA’s US9r database, which specifies fuel supply characteristics and energy conversion technology performance and costs from 2005−2055, in five-year steps. Supply of oil and NG is divided into two processes: initial extraction, with costs defined by stepped supply curves and constraints on year-to-year production increases limiting the amount of the resource available to the model; and delivery to end-use sectors, with explicitly specified costs for transmission and distribution and constraints on pipeline capacity. The database is resolved into the nine U.S. Census regions. Energy resources are transported across regions through modeled distribution routes, including pipelines and transmissions lines, for which capacity can be expanded over time, subject to constraints on rates of expansion. The version of the database providing the starting point for this study was released in November 2012 and uses assumptions from the EIA’s 2012 Annual Energy Outlook (AEO).24 The model uses a system-wide discount rate of 5%, supplemented by technology specific “hurdle” rates that reflect additional barriers to new investment. 13037

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The Fossil Cap scenario depicts an accelerated transition away from fossil fuel technologies for electricity generation. The scenario was implemented by using optimistic cost assumptions for PV, wind, centralized solar thermal, centralized biomass-to-electricity, and geothermal technologies, and adding constraints on the share of electricity generated by fossil fuel technologies. The upper bound on electricity generation from fossil fuels was specified at 90% in 2015, decreasing 10% per 5 year period to 20% in 2050 and 2055. It is input as a “global” constraint as opposed to a regional constraint, so the upper bounds apply to the sum of electricity generated in all the regions. In addition, for each region a separate constraint was imposed limiting the sum of electricity generated by wind and photovoltaic (PV) technologies to 50% of total generation. The cost assumptions for wind and PV in the Fossil Cap scenario were adjusted to reflect the most optimistic assumptions from NREL’s Renewable Electricity Futures Study.20 Finally, a simplified treatment of reliability constraints for variable generation technologies was incorporated in the form of an explicitly defined relationship between capacity value and grid penetration.42 The Coal Retirements scenario features a moratorium on post-2010 construction of new coal steam power plants and accelerated retirements of existing coal capacity. Initial constraints were implemented as upper bounds set to 2010 levels for generation from coal in each region. For later years, iterative model runs were used to establish generation constraints corresponding to the goals of retiring 80 GW of coal capacity by 2025 and 100 GW by 2050. These levels were chosen as roughly double the capacity retirements projected by EIA’s 2013 AEO Reference Case for 2025,19 with additional capacity retirements following through 2055. The constraints were applied solely to traditional steam power plants, allowing coal-fired combined heat and power plants or integrated gasification combined cycle plants to remain available. For the GHG Fees scenario, an emissions fee was applied in MARKAL based on the midrange estimates for the “Social Cost of Carbon” (SCC) published by the Interagency Working Group in May 2013.43 The SCC is a metric used by U.S. regulatory agencies to assess climate benefits of policy mechanisms; it provides a measure of economic damages caused by climate-change related impacts projected to occur as a result of increases in GHG emissions. For this study, the SCC estimate with a discount rate of 3% was used, representing the midrange of estimates for the years 2015 through 2050. Fees were phased in from 2015 to 2050, as shown in Table 2. The fees were applied for carbon-equivalent emissions across all regions in the model from the electricity, industrial, commercial, residential, and transportation sectors and from upstream fuel production. Fees were applied for methane using a 100 year global warming potential (GWP) of 25, as currently specified by EPA for GHG reporting.44 The CNG Vehicles scenario explores the implications of increased demand for natural gas in the transportation sector, under the assumptions that CNG attains 100% penetration by

emissions rates by requiring modifications to pneumatic controllers, compressors, and storage tanks used at all new and refractured wells starting in 2015, and requiring reduced emissions completions for unconventional gas wells.40 The effect of these rules was incorporated by lowering the emissions factors for NG production over time, starting in 2015 as described in the SI. In addition, the SI presents results from an extra scenario exploring how emissions would change if more stringent control requirements adopted in Colorado in February 2014 were applied nationwide.41 2.3. Scenarios. As listed in Table 1, a diverse set of scenarios was developed for this study to examine how Table 1. Descriptions of MARKAL Scenarios Modeled in This Study name cheap gas costly gas fossil cap GHG fee coal retirements CNG vehicles

description abundant NG supply, increased shale gas production, low wellhead costs limited NG supply, reduced shale gas production as percentage of overall gas production, high wellhead costs share of electricity generated by fossil fuels decreases to 20% by 2050; optimistic price assumptions for certain renewable technologies a “tax” on carbon emissions from each energy sector is implemented from 2015 to 2050 no new coal plants may be built starting in 2015, and existing coal plants are retired at an accelerated rate penetration of CNG-fueled vehicles increasing to 100% by 2050 in buses, heavy-duty short haul trucks, and light-duty fleet vehicles

emissions from NG production and use might change in coming decades, based on different assumptions about resource supply, demand for NG, and policy measures to reduce emissions or limit fossil fuel use in the electric power sector. The scenarios are designed as clusters of modifications to parameters in the EPA MARKAL model that might reasonably be expected to occur together. Each scenario is briefly described below, with additional information given in the SI. Two scenarios were designed to examine contrasting assumptions about future natural gas production. Cheap Gas represents a future in which NG production grows relatively rapidly and unconventional gas production continues to increase as a percentage of overall production, reaching 100% in some regions. Because of the abundant supply, wellhead prices are comparatively low. In the contrasting scenario, Costly Gas, NG production is constrained, representing a decreased growth rate. Unconventional gas production as a percentage of overall production grows in all regions, but flattens out after reaching reduced levels from the base case. More expensive wellhead prices for NG are specified, consistent with the limited supply. The two NG supply scenarios are implemented in MARKAL through changes in the supply curves that define wellhead prices in each region, allowed rates of yearly production increases and reserve depletions, and regional fractions of NG coming from unconventional deposits.

Table 2. Fees Applied to Emissions of Carbon Dioxide and Methane in the GHG Fees MARKAL Scenario for the Years 20152050, in 2005 Dollars Per Metric Tonne

CO2 CH4

2015

2020

2025

2030

2035

2040

2045

2050

32 792

36 911

40 1010

44 1109

48 1209

52 1308

56 1407

60 1506

13038

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due to the high cost of NG. In 2035 in Costly Gas, the average delivered cost of NG to the electric sector, weighted by regional NG production, is $9.46/mcf. This is nearly twice the average delivered NG price for the electric sector in 2011, which was $4.87.19 The Rocky Mountain electricity mix (Figure 1b) follows trends similar to those observed in the national results. However, in the base case and Costly Gas scenarios, wind is more heavily used in the RM region than in the U.S. as a whole. In Costly Gas, wind reaches 47% of regional generation in 2050, with NG falling below 5% of the generation mix. In this region there is little fuel switching from coal to NG in the Costly Gas scenario as coal continues to be used for meeting base-load demand. As shown in Figure 2a, U.S. GHG emissions in the MARKAL base case and Cheap Gas scenario are about 2−3% higher in

2050 in heavy-duty short haul trucks and buses and in lightduty vehicle fleets of 10 or more vehicles. The constraints for heavy-duty vehicles were phased in starting at 5% of vehicle miles traveled (VMT) in 2020, rising to 100% of VMT in 2050. Those for light-duty fleet vehicles were implemented starting at a 14% share of light-duty fleet VMT in 2020 (∼1% of total light duty VMT), rising to a 100% share of light-duty fleet VMT in 2050 (6.2% of total light duty VMT).

3. RESULTS 3.1. Results for NG Supply Scenarios. As discussed above, the base case, Cheap Gas, and Costly Gas scenarios were designed to represent contrasting trends in NG supplies. In the base case, U.S. production increases by 61% from 23.5 Tcf in 2010 to 37.9 Tcf in 2050, with the fraction of production from unconventional supplies growing from 30% to 60%. In Cheap Gas, U.S. production increases by 110% to 48.6 Tcf in 2050; in Costly Gas production increases by 20% to 27.9 Tcf in 2050 (SI, Figure S6). Cheap Gas features a particularly steep increase (62%) in production from 2010 to 2035. Natural gas production in the RM region follows the same general trends but with proportionately smaller increases (SI, Figure S9). In the base case, NG production in the RM region increases from 6 Tcf in 2010 to 7.7 Tcf in 2050. In Cheap Gas, production reaches 8.5 Tcf in 2050 while in Costly Gas it reaches only 6.3 Tcf. Corresponding to these production changes, shifts in fuels for electricity generation occur in the short term in both the Cheap Gas and Costly Gas scenarios as well as the base case (Figure 1a). For the U.S. as a whole, in Cheap Gas by 2035 electricity generated by NG combined cycle turbines has replaced over half of the electricity generated from coal in 2010. Less switching from coal to NG takes place in the Costly Gas scenario. In this scenario, beginning in 2035 additional electricity demand is met primarily by wind instead of NG,

Figure 2. GHG emissions from (a) the U.S. energy system and (b) the RM region in megatonnes CO2-equivalent (CO2-e). A GWP of 25 is used for CH4. “Production” refers to emissions released during fossil energy extraction and production, including coal, oil and NG. Methane emissions (as CO2-e) are shaded separately.

2050 than in 2010, after a modest decline in the interim. In Costly Gas, 2050 energy system emissions are about 1.4% lower than 2010 levels. Modest reductions from 2010 to 2035 result as increased demand for energy services is met with more efficient or less GHG-intensive technologies, especially in the transportation sector.27 Reductions in GHG emissions from the electricity sector from 2010 to 2050 are offset primarily by increased emissions in the industrial sector, in which steadily increasing demand for energy services continues to be met with fossil fuels. In the base case, GHGs released during extraction of oil and gas also contribute to keeping total emissions relatively flat. In Costly Gas, relatively slow growth in NG production contributes a small share of the GHG savings. In

Figure 1. Annual electricity generated in (a) the U.S. and (b) the Rocky Mountain region, by year, scenario, and technology. 13039

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Cheap Gas, GHG emissions from the electricity sector are about 20% lower in 2035 and 2050 than in 2010. However, these reductions are offset by GHG emissions growth in other sectors, including increased methane emissions from NG production. In the Cheap Gas scenario, overall energy system GHG emissions in 2050 are 3% higher than in 2010 if a 100year GWP of 25 is used for methane. If greater emphasis is placed on near-term consequences and a 20-year GWP of 7245 is used, GHG emissions in 2050 are 6% higher than in 2010. In contrast to the national results, in the RM region GHG emissions for the base case, Cheap Gas and Costly Gas scenarios increase consistently throughout the modeling time frame (Figure 2b). However, using a 20 year GWP of 72 for methane results in a qualitatively different outcome in the Costly Gas scenario. Using the higher GWP value, CO2equivalent emissions in the region decrease from 2010 to 2035 and then increase slightly from 2035 to 2050. The influence of the GWP is due to the regional importance of methane emissions from fuel production. Methane emissions from fossil fuel production play a proportionally larger role in the RM region than in the national results. In Cheap Gas in 2035, for example, methane emissions from fossil fuel production comprise 5.5% of total CO2-e emissions from the U.S. energy sector when using a GWP of 25 for methane; with a GWP of 72 the contribution rises to 14%. In the RM region, the contribution from fuel production-related methane emissions is 12% using a GWP of 25 and 27% using a GWP of 72. U.S. VOC emissions are dominated by emissions from the transportation sector, which decrease from over 4000 kt in 2010 to about 3000 kt in 2050 in the base case (Figure 3a). The decrease is a result of more stringent standards for VOC emissions from new motor vehicles. Total VOC emissions in 2050 are about 6000 kt in the Cheap Gas scenario and 5300 kt in the Costly Gas scenario. The difference in VOC emissions between the scenarios is a result of emissions associated with NG production, which accounts for about 1000 kt of VOC emissions in the Costly Gas scenario in 2050, and 1800 kt in the Cheap Gas scenario. U.S. NOx emissions in the MARKAL model drop sharply in the base case from 13300 kt in 2010 to 7800 kt in 2035, then increase to 8700 kt in 2050 (Figure 3a and SI Figure S8). NOx emissions are dominated by the electric, industrial and transportation sectors in each scenario. Both Cheap Gas and Costly Gas feature slightly lower NOx emissions than the base case from 2010 to 2050. In Cheap Gas, the difference is due to more extensive fuel switching in the electric sector, which would have a larger effect on emissions if not for a concurrent increase in NOx emissions from NG production activities. In Cheap Gas, in 2050, NOx emissions from oil and gas production are 1100 kt, roughly matching the contribution from the electric sector. In 2050, the base case and Costly Gas scenarios have NOx emissions of 870 and 650 kt, respectively, from oil and gas production and 1750 and 1800 kt, respectively, from electricity generation. In the NG supply scenarios, VOC emissions in the Rocky Mountain region decrease in the short term due largely to a significant reduction in transportation sector emissions (Figure 3 and SI Figure S10). In the base case, Cheap Gas and Costly Gas scenarios, regional emissions from oil and gas production decrease from 2010 to 2035 due to EPA’s NSPS and NESHAP rules. From 2035 to 2050, VOC emissions in the Cheap Gas scenario and the base case begin to increase again due to increasing oil and gas production. Regional VOC emissions in

Figure 3. VOC and NOx emitted from (a) the U.S. energy system and (b) the RM region. Results are for 2050 except for the 2010 base case.

the Cheap Gas scenario remain above the base case for the modeling time frame. By 2035, in all three scenarios, NOx emissions in the Rocky Mountain region decrease by about 50% below the 2010 level of 1500 kt, due to stricter controls on power plant and tailpipe emissions (SI Figure S11). As in the national results, small increases in regional NOx emissions from 2035 to 2050 are primarily due to increased emissions from the industrial sector (Figure 3b and SI Figure S11). Cheap Gas and Costly Gas NOx emissions are lower than base case emissions throughout the modeling time frame, for the same reasons as in the national results. 3.2. Results for Reduced Carbon Scenarios. Results for the Fossil Cap, GHG Fees, and Coal Retirements scenarios allow comparison of the effectiveness of three potential GHG reduction strategies, and demonstrate how the corresponding emission trends are affected by NG production and use. In GHG Fees and Coal Retirements, NG production remains close to base case levels throughout the modeling time frame (Figure S6, SI). In 2050, NG production in the base case and Coal Retirements scenarios is about 38 Tcf and that in the GHG Fees scenario is about 36 Tcf. However, NG production in Fossil Cap is about 26% lower than in the base case, at about 28 Tcf (similar to the level in the Costly Gas scenario) due to decreasing use of NG in the electric sector. In the reduced carbon scenarios, NG production in the RM region (SI Figure S9) generally follows the same trends exhibited in the national results, but for somewhat different reasons. Regional NG production in Fossil Cap grows from 6 Tcf in 2010 to about 6.3 Tcf in 2020, and remains almost 13040

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the electric sector nor gasoline use in the transportation sector. Fossil Cap consistently features the lowest total GHG emissions among the scenarios. In Fossil Cap, GHG emissions from the U.S. energy sector are 19% and 18% below 2010 levels in 2035 and 2050, respectively. In the Rocky Mountain region, GHG emissions reductions in the electric sector from 2010 to 2035 are 55%, 34% and 40% in the GHG Fees, Coal Retirements, and Fossil Cap cases, respectively (Figure 2b). In the RM region, GHG Fees has the lowest overall GHG emissions in 2035, whereas Fossil Cap has the lowest emissions in 2050. Despite comparatively low fossil fuel use for electricity generation in the Fossil Cap and GHG Fees scenarios, overall GHG emissions are never reduced by more than 13% compared to 2010 levels. U.S. VOC emissions in 2050 are 5300 kt in the Fossil Cap scenario, 5500 kt in the GHG scenario, and about 5700 kt in the base case and Coal Retirements scenarios (Figure 3a and SI Figure S7). Due to comparatively low NG production, VOC emissions in the Fossil Cap case are 16% lower than those in the base case in 2035, and 34% lower in 2050. Transportation sector VOC emissions in all three reduced carbon scenarios are close to those in the base case. In 2050, U.S. NOx emissions in the GHG Fees and Coal Retirements scenarios of 8000 kt and 8300 kt, respectively, are lower than the base case level of 8700 kt (Figure 3a). Emissions of NOx in 2050 in Fossil Cap are somewhat higher, at 8900 kt. This is because Fossil Cap features constraints on fossil fuel use in the electric sector, but none for the industrial sector, which contributes NOx emissions on roughly the same scale. Reduced NG use in the electric sector in this scenario is offset by increased use in industrial processes. As NOx emissions rates (per unit heat input) are generally higher in the industrial sector in MARKAL than in the electric sector, the result is increased overall NOx emissions in Fossil Cap. For the Rocky Mountain region, the largest reductions in VOC emissions (Figure 3b and SI Figure S10) occur in the Fossil Cap scenario, along with the Costly Gas scenario, due to their having little growth in regional NG production. In 2050, VOC emissions from fuel production are 17% lower in the Fossil Cap scenario than in the base case. Emissions of NOx in the RM region (Figure 3b and SI Figure S11) generally display the same trends as those observed on the national scale. However, in each of the reduced carbon scenarios, percentage reductions in NOx emissions are higher in the RM region than nationally because proportional use of coal in the electric sector is relatively high in this region. GHG Fees features the lowest electricity generation from coal in the region and correspondingly has the lowest NOx emissions. 3.3. Results for the CNG Vehicles Scenario. The CNG Vehicles scenario features increased use of CNG in heavy duty short-haul trucks, buses, and light duty fleet vehicles. As explained in section 2.3, CNG penetration in this exploratory scenario is not driven by cost and performance considerations, but rather is directly specified to examine implications of relatively high CNG use. In the CNG Vehicles scenario, the transportation sector accounts for 16% of U.S. NG use in 2050, whereas in the base case it accounts for 0.5%. However, the scenario yields only 2% more U.S. NG production in 2050, compared to the 2050 base case result (Figure S6, SI), because much of the NG needed for transportation is diverted from the electric and industrial sectors. As shown in Figure 1a, in 2050 the national electricity mix in the CNG Vehicles case features about 30% more wind and 15% less NG than the base case.

constant after that, due to the small amount of NG in the regional electricity mix in this scenario and little growth in industrial sector NG use. Regional NG production in Coal Retirements remains slightly higher than base case levels through 2050. Although less NG is used for electricity production within the region, NG exports from the RM region are higher in the Coal Retirements scenario than in the base case. The increased exports go to neighboring regions where NG use in electricity generation is sustained: the West North Central region in the short term, and the West South Central region in the long term. The electricity mix results for the reduced carbon scenarios show the sensitivity of electric sector NG use to the effects of simplified policies that address the range and cost of electric generating technologies available in MARKAL (Figure 1a). The future electricity mix depicted in the Coal Retirements scenario suggests that NG combined cycle plants are the preferred technology for replacing coal plants and meeting additional demand, under otherwise business as usual assumptions. In the GHG Fees scenario, electricity produced from NG is close to base case levels in 2035 and 2050. This suggests that the SCC estimates used in this scenario (up to $60/tonne CO2-e ($2005)) are not high enough to significantly deter the transition to NG as a primary source of electricity. In 2050 in this scenario, electricity from NG is only 12.5% below that in the base case. The preferred sources of electricity used for meeting additional demand from 2010 to 2050 in the Fossil Cap scenario are wind, PV, and concentrating solar thermal (CST), with CST helping to replace coal as a means of meeting baseload demand. The Rocky Mountain electricity mix exhibits reduced coal use in each reduced carbon scenario, as in the national results, but shows a greater prevalence of wind (Figure 1b). Both wind and NG are used to displace coal in the Coal Retirements scenario. The Fossil Cap scenario also features relatively strong early penetration of wind into the RM electricity mix. However, in this scenario, the constraint on the fraction of generation from fossil fuels is met in part by increasing total electricity generation in the RM region. The extra electricity is mostly exported to the West Coast. By 2050, CST makes a significant contribution toward meeting baseload electricity demand; the RM region has relatively abundant solar resources in states such as Nevada and Arizona. In each reduced carbon scenario, overall U.S. energy system GHG emissions in 2050 are lower than 2010 levels and lower than base case levels in the same year (Figure 2a). From 2010 to 2035, the base case and reduced carbon scenarios all feature GHG emission reductions due largely to fuel switching away from coal in the electric sector and to a lesser extent, more fuelefficient vehicles. GHG emissions reductions in the electric sector from 2010 to 2035 are 38%, 30%, and 53% in the GHG Fees, Coal Retirements, and Fossil Cap cases, respectively. The comparatively high electric sector NG use featured in Coal Retirements helps reduce GHG emissions from base case levels in the short term, but this benefit diminishes between 2035 and 2050 as additional electricity demand is met mostly with NG. In GHG Fees, electric sector GHG emissions decrease throughout the modeling time frame even as electricity production from NG continues to rise, because there is less electricity from coal in later years in addition to a greater contribution from wind. The fees imposed in this scenario result in nationwide GHG emissions that are 10% below 2010 levels in 2050, but do not have a large effect on use of NG in 13041

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Results for the Rocky Mountain region show the importance of exploring regional as well as national trends. The RM region displays relatively strong competition between wind and NG for future electricity generation, along with emissions trade-offs between electricity generation and fuel production. In this region, wind substitutes for NG in the Costly Gas, GHG fee, and Fossil Cap scenarios. In Fossil Cap, total electricity production in the RM region increases, as wind, CST, and PV in this region compensate for lower use of renewables elsewhere. Emissions of methane from fuel production are relatively influential in the GHG budget for the RM region, compared to the rest of the country. In all scenarios, U.S. VOC emissions drop from 2010 to 2035 due to tighter emissions standards in the transportation sector, then rebound slightly or remain flat through 2050. Differences in VOC emissions between scenarios are driven by differences in NG production, so the highest emissions are found in Cheap Gas and the lowest in Costly Gas and Fossil Cap. This study takes into account the 2012 NSPS/NESHAPs for oil and gas production.40 Even so, in the RM region in 2050 VOC emissions from fuel production exceed those from the transportation sector in all scenarios. U.S. NOx emissions are 35% lower in the 2050 base case than in 2010, due mainly to reductions in the transportation sector. NOx emissions are similar across scenarios, due to offsetting changes in emissions from the fuel production, industrial, and electric power sectors. The greatest NOx reductions are achieved in the GHG Fees scenario, with total emissions in 2050 that are 8% lower than in the base case. As with VOCs and methane, fuel production accounts for a relatively large percentage of NOx emissions in the RM region. Atmospheric chemistry and transport modeling is needed to explore the air quality implications of these trends, as VOC and NOx emissions from different sectors have different composition and spatial and temporal distributions. The MARKAL modeling results presented in this study are useful for exploring how the U.S. energy system and emissions might respond to future changes in NG supply characteristics and policy choices. The results depend on numerous modeling assumptions with corresponding limitations. The US9r database incorporates current emissions and efficiency regulations but does not reflect proposed rules such as EPA’s Clean Power Plan.46 The model is demand-explicit, so the full elasticity of supply and demand is not accounted for in the solutions. The industrial sector is resolved into only six broad subsectors, limiting the representation of corresponding emissions control and fuel switching options. The nine-region database averages out subregional variations in renewable and fuel resources, fuel production methods, and access to transmission or pipelines. Although the study has updated and refined estimates of current and future emissions of methane, VOC, and NOx emissions from natural gas production, emissions from the natural gas life cycle are uncertain and warrant further research.9−12,47

U.S. GHG emissions from 2010 to 2050 are slightly lower in the CNG Vehicles scenario than in the base case (Figure 2a). The primary driver of this reduction is CNG replacing some diesel in the transportation sector prior to 2035, and later replacing both gasoline and diesel. Using a GWP of 25 for methane, in 2050 the GHG emissions in the CNG Vehicles scenario are slightly lower than in the base case, and just below the 2010 levels. When using a 20 year GWP of 72 for methane, 2050 GHG emissions in the CNG Vehicles case are slightly higher than emissions in 2010. Total VOC and NOx emissions in the CNG Vehicles scenario differ little from those in the base case (Figure 3a and SI Figures S7 and S8). Results for NG production, electricity mix, and emissions in the CNG Vehicles scenario differed less from the corresponding base case results in the Rocky Mountain region than for the U.S. as a whole (Figures 1b, 2b, 3b, and SI Figures S9−S11). This is because the national-scale requirement for CNG use in light duty fleets was mostly met by use in the Great Lakes, Texas and West Gulf, and Pacific regions that had the lowest combined costs of extracting NG and delivering it to the transportation sector. As the CNG use requirement takes full effect toward the end of the simulation period, other regions start contributing a larger share of the CNG requirements. In the RM region, some of the NG needed to supply CNG is diverted from other sectors, imported from the Midwest, and diverted from exports to Mexico. In the RM electricity mix, there is more wind in the CNG Vehicles scenario in later years when compared with the base case, due to NG being diverted from the electric sector to the transportation sector. 4. Discussion. This study developed scenarios to examine the potential effects on GHG, VOC, and NOx emissions of contrasting trends in NG supply characteristics and policies to reduce GHG emissions or encourage renewables. Growth in U.S. NG production from 2010−2050 ranges from about 20% in the Costly Gas and Fossil Cap scenarios to 110% in the Cheap Gas scenario. NG production trends in this study are within the range of estimates released by EIA in its 2014 projections, which extend to 2040.4,19 All else being equal, the results suggest variations in NG cost and abundance have little impact on overall GHG emissions from the U.S. energy system, due to offsetting changes across sectors. Although NG contributes 60% of U.S. electricity production in 2050 in the Cheap Gas scenario and less than 30% in the Costly Gas scenario, GHG emissions in both scenarios are similar to those in the base case. In Cheap Gas, emissions reductions in the electricity sector are offset by increased emissions from the industrial sector and from fuel production. In Costly Gas, both wind and coal replace some NG generation, with counterbalancing effects on GHG emissions. Among the scenarios considered, the greatest reductions in GHG emissions are found with the Fossil Cap scenario, in which the fraction of electricity generated from fossil fuels is reduced to 20% by 2050. From 2010 to 2050, this scenario achieves a 70% reduction in emissions from electricity generation and an 18% reduction in total energy system emissions. Wind, CST, and PV combine to account for about half of 2050 electricity generation in the Fossil Cap scenario. In the GHG Fees scenario, with a system-wide fee reaching $60 ($2005) per tonne of CO2-e in 2050, U.S. energy system GHG emissions are 10% lower in 2050 than in 2010. Higher fees than those suggested by the midrange estimates for the Social Cost of Carbon43 would be needed to achieve deeper cuts.

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ASSOCIATED CONTENT

S Supporting Information *

Additional details describing methods used in deriving modified MARKAL database assumptions and scenarios; NG production estimates; and additional results for emissions, including a scenario with more stringent emissions control requirements for NG production. This material is available free of charge via the Internet at http://pubs.acs.org. 13042

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carbonyl photolysis in an oil and gas basin. Nature 2014, DOI: 10.1038/nature13767. (17) Loughlin, D. H.; Benjey, W. G.; Nolte, C. G. ESP v1.0: Methodology for exploring emission impacts of future scenarios in the United States. Geosci. Model Dev. 2011, 4 (2), 287−297 DOI: 10.5194/gmd-4-287-2011. (18) Lenox, C.; Dodder, R.; Gage, C.; Kaplan, O.; Loughlin, D.; Yelverton, W.EPA U.S. Nine-region MARKAL DATABASE: Database Documentation, EPA 600/B-13/203; U.S. Environmental Protection Agency: Cincinnati, OH, 2013. (19) Annual Energy Outlook 2013; DOE/EIA-0383(2013); U.S. Energy Information Administration: Washington, DC, 2013; http:// www.eia.gov/forecasts/aeo. (20) Renewable Electricity Futures Study, NREL/TP-6A20-52409; Hand, M. M.; Baldwin, S.; DeMeo, E.; Reilly, J. M.; Mai, T.; Arent, D.; Porro, G.; Meshek, M.; Sandor, D., Eds.; National Renewable Energy Laboratory: Golden, CO, 2012; http://www.nrel.gov/analysis/re_ futures/. (21) Logan, J.; Heath, G.; Paranhos, E.; Boyd, W.; Carlson, K.; Macknick, J. Natural Gas and the Transformation of the U.S. Energy Sector: Electricity, NREL/TP-6A50-55538; Joint Institute for Strategic Energy Analysis, National Renewable Energy Laboratory: Golden, CO, 2012. (22) Newell, R.; Raimi, D. Implications of shale gas development for climate change. Environ. Sci. Technol. 2014, 48, 8360−8368 DOI: 10.1021/es4046154. (23) Shearer, C.; Bistline, J.; Inman, M.; Davis, S. The effect of natural gas supply on US renewable energy and CO2 emissions. Environ. Res. Lett. 2014, DOI: 10.1088/1748-9326/9/9/094008. (24) Annual Energy Outlook 2012; DOE/EIA-0383(2012); U.S. Energy Information Administration: Washington, DC, 2012; http:// www.eia.gov/forecasts/aeo. (25) U.S. Environmental Protection Agency. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call, Final Rule. Fed. Regist. 2005, 70, 25162 − 25405. (26) U.S. Environmental Protection Agency. National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Insititutional Steam Generating Units, Final Rule. Fed. Regist. 2012, 77, 9304 − 9513. (27) U.S. Environmental Protection Agency and National Highway Traffic Safety Administration. 2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards, Final Rule. Fed. Regist. 2012, 77, 62624 − 63200. (28) Shay, C.; DeCarolis, J.; Loughlin, D.; Gage, C.; Yeh, S.; Samudra, V.; Wright, E. EPA U.S. National MARKAL Database: Database Documentation; U.S. Environmental Protection Agency, February 2006. (29) Shay, C.; Gage, C.; Johnson, T.; Loughlin, D.; Dodder, R.; Kaplan, O.; Samudra, V.; et al. EPA U.S. Nine Region MARKAL Database: Database Documentation; U.S. Environmental Protection Agency, June 2008. (30) Brown, K. E.; Henze, D. K.; Milford, J. B. Accounting for climate and air quality damages in future U.S. electricity generation scenarios. Environ. Sci. Technol. 2013, 47 (7), 3065−3072 DOI: 10.1021/ es304281g. (31) Akhtar, F. H.; Pinder, R. W.; Loughlin, D. H.; Henze, D. K. GLIMPSE: A rapid decision framework for energy and environmental policy. Environ. Sci. Technol. 2013, 47 (21), 12011−12019 DOI: 10.1021/es402283j. (32) Trail, M. T.; Tsimpidi, A. P.; Liu, P.; Tsigaridis, K.; Rudokas, J.; Miller, P.; Nenes, A.; Hu, Y.; Russell, A. G. Sensitivity of air quality to potential future climate change and emissions in the United States and major cities. Atmos. Environ. 2014, 94, 552−563. (33) McLeod, J. D. Characterizing the emission implications of future natural gas production and use in the U.S. and Rocky Mountain

AUTHOR INFORMATION

Corresponding Author

*Phone: (303) 492-5542; e-mail: [email protected]. Notes

The authors declare no competing financial interests.

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ACKNOWLEDGMENTS We thank the EPA Office of Research and Development for use of the US9r database for MARKAL. Support for this work was provided by the National Science Foundation’s (NSF) AirWaterGas Sustainability Research Network CBET1240584. Findings or recommendations expressed in this paper are those of the authors and do not necessarily reflect the views of the NSF or the EPA.

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