Energy,environmental and economic effects of Renewable Portfolio Standards (RPS) in a Developing Country

This paper analyses the potential of renewable energy for power generation and its energy, environmental and economic implications in Pakistan, using a bottom up type of long term energy system based on the MARKAL framework. The results show that under a highly optimistic renewable portfolio standard (RPS) of 80%, fossil fuel consumption in 2050 would be reduced from 4660 PJ to 306 PJ, and the GHG emissions would decrease from 489 million tons to 27 million tons. Nevertheless, price of the electricity generation will increase significantly from US$ 47/MWh under current circumstances (in the base case) to US$ 86/MWh under RPS80. However the effects on import dependency, energy-mix diversity, per unit price of electricity generation and cost of imported fuels indicate that, it may not be desirable to go beyond RPS50. Under RPS50 in 2050, fuel consumption of the power sector would reduce from 21% under the base case to 9% of total fossil fuels supplied to the country. It will decrease not only GHG emission to 170 million tons but also will reduce import dependency from 73% under the base case to 21% and improve energy diversity mix with small increase in price of electricity generation (from US$ 47/MWh under the base case to US$ 59/MWh under RPS 50).     

A retrospective analysis of benefits and impacts of U.S. renewable portfolio standards

As states consider revising or developing renewable portfolio standards (RPS), they are evaluating policy costs, benefits, and other impacts. We present the first U. S. national-level assessment of state RPS program benefits and impacts, focusing on new renewable electricity resources used to meet RPS compliance obligations in 2013. In our central-case scenario, reductions in life-cycle greenhouse gas emissions from displaced fossil fuel-generated electricity resulted in $2.2 billion of global benefits. Health and environmental benefits from reductions in criteria air pollutants (sulfur dioxide, nitrogen oxides, and particulate matter 2.5) were even greater, estimated at $5.2 billion in the central case. Further benefits accrued in the form of reductions in water withdrawals and consumption for power generation. Finally, although best considered resource transfers rather than net societal benefits, new renewable electricity generation used for RPS compliance in 2013 also supported nearly 200,000 U. S.-based gross jobs and reduced wholesale electricity prices and natural gas prices, saving consumers a combined $1.3–$4.9 billion. In total, the estimated benefits and impacts well-exceed previous estimates of RPS compliance costs.     

The costs and benefits of large-scale solar photovoltaic power production in Abu Dhabi,United Arab Emirates

The potential for a 10 MW photovoltaic power plant in Abu Dhabi is examined in this paper using RETScreen modeling software to predict energy production, financial feasibility and GHG emissions reductions. Initial results show high energy production potential, generating 24 GWh and saving over 10,000 tons of GHG emissions annually, but poor financial prospects yielding a net present value (NPV) of ?$51 million. Benefits of reducing GHG and air pollution emissions by replacing natural gas with PV generation are calculated to have a net present value of $47 million, with a large range of possible values. Results show that the high initial costs and low expected price for electricity generated are driving reasons why photovoltaic systems are not being implemented in Abu Dhabi. A feed-in tariff rate of $0.16/kWh is recommended to make large-scale PV systems profitable.     

Alternative U.S. biofuel mandates and global GHG emissions: The role of land use change,crop management and yield growth

We investigate the impacts of the U.S. renewable fuel standard (RFS2) and several alternative biofuel policy designs on global GHG emissions from land use change and agriculture over the 2010–2030 horizon. Analysis of the scenarios relies on GLOBIOM, a global, multi-sectoral economic model based on a detailed representation of land use. Our results reveal that RFS2 would substantially increase the portion of agricultural land needed for biofuel feedstock production. U.S. exports of most agricultural products would decrease as long as the biofuel target would increase leading to higher land conversion and nitrogen use globally. In fact, higher levels of the mandate mean lower net emissions within the U.S. but when the emissions from the rest of the world are considered, the US biofuel policy results in almost no change on GHG emissions for the RFS2 level and higher global GHG emissions for higher levels of the mandate or higher share of conventional corn-ethanol in the mandate. Finally, we show that if the projected crop productivity would be lower globally, the imbalance between domestic U.S. GHG savings and additional GHG emissions in the rest of the world would increase, thus deteriorating the net global impact of U.S. biofuel policies.     

Economic accounting and high-tech strategy for sustainable production: A case study of methanol production from CO2 hydrogenation

The global proposal of ‘carbon neutrality’ puts forward higher innovation demand for the cleaner energy production. The potential for employing “green” methanol produced from hydrogen obtained by water electrolysis and collected CO₂ from a gas-fired power station is examined in this study.The consumption of electricity for renewable methanol production is 1.045 times as much as that for traditional methanol production, the traditional method consumes 2.5 times as much thermal energy as the renewable methanol process. In addition, the total direct and indirect CO₂ emissions from renewable methanol production are almost one-third of the emissions from the traditional method. The total cost of setting up the units of a renewable and a traditional methanol production plant with an annual capacity of 100,000 tons is $50.1 million and $46.806 million in this study case, respectively. If the methanol price hits $310 per ton, renewable methanol production will be highly economically viable. But if electricity and gas prices rise or CO2 emission tax is imposed, renewable and conventional methanol production plants will lose their economic feasibility. Therefore, in order to deal with this risk, the establishment of special high-tech parks is of great significance to reduce costs and stabilize the sustainable development of relevant industries.     

Evaluating renewable portfolio standards and carbon cap scenarios in the U.S. electric sector

This report examines the impact of renewable portfolio standards (RPS) and cap-and-trade policy options on the U.S. electricity sector. The analysis uses the National Renewable Energy Laboratory's Regional Energy Deployment System (ReEDS) model that simulates the least-cost expansion of electricity generation capacity and transmission in the U.S. to examine the impact of a variety of emissions caps—and RPS scenarios both individually and combined. The generation mix, carbon emissions, and electricity price are examined for various policy combinations simulated in the modeling.     

Estimating GHG emissions of marine ports—the case of Barcelona

In recent years, GHG inventories of cities have expanded to include extra-boundary activities that form part of the city's urban metabolism and economy. This paper centers on estimating the emissions due to seaports, in such a way that they can be included as part of the city's inventory or be used by the port itself to monitor their policy and technology improvements for mitigating climate change. We propose the indicators GHG emissions per ton of cargo handled or per passenger and emissions per value of cargo handled as practical measures for policy making and emission prevention measures to be monitored over time. Adapting existing methodologies to the Port of Barcelona, we calculated a total of 331,390 tons of GHG emissions (CO₂ equivalents) for the year of 2008, half of which were attributed to vessel movement (sea-based emissions) and the other half to port, land related activities (land-based emissions). The highest polluters were auto carriers with 6 kg of GHG emissions per ton of cargo handled. Knowing the highest emitters, the port can take action to improve the ship's activities within the port limits, such as maneuvering and hotelling. With these results, the port and the city can also find ways to reduce the land-based emissions.     

Reducing greenhouse gas emissions by inducing energy conservation and distributed generation from elimination of electric utility customer charges

This paper quantifies the increased greenhouse gas emissions and negative effect on energy conservation (or “efficiency penalty”) due to electric rate structures that employ an unavoidable customer charge. First, the extent of customer charges was determined from a nationwide survey of US electric tariffs. To eliminate the customer charge nationally while maintaining a fixed sum for electric companies for a given amount of electricity, an increase of 7.12% in the residential electrical rate was found to be necessary. If enacted, this increase in the electric rate would result in a 6.4% reduction in overall electricity consumption, conserving 73 billion kW h, eliminating 44.3 million metric tons of carbon dioxide, and saving the entire US residential sector over $8 billion per year. As shown here, these reductions would come from increased avoidable costs, thus leveraging an increased rate of return on investments in energy efficiency, energy conservation behavior, distributed energy generation, and fuel choices. Finally, limitations of this study and analysis are discussed and conclusions are drawn for proposed energy policy changes.     

A 3E,hydrogen production,irrigation, and employment potential assessment of a hybrid energy system for tropical weather conditions – Combination of HOMER software,shannon entropy,and TOPSIS

The increasing threat to environmental sustainability as a result of greenhouse gas (GHG) emissions from fossil fuel base power plants has necessitated the need to find sustainable energy sources to meet the world's energy demands. This study focuses on assessing the potential of a hybrid power plant for the production of electricity, hydrogen for the production of fertilizer for agricultural activities, farmland irrigation, environmental impact as well as its employment potential in northern Ghana. The Shannon entropy weight and TOPSIS multi-criteria decision-making approach were adopted to rank and identify the optimal configuration out of five possible options for the study area. Results from the simulation show that the winning system, i.e., Hydro + Battery system would generate a total electricity of 1,095,679 kWh/year. A cost of electricity of 0.06 $/kWh with an operating cost (OC) of $18,318 was recorded for the winning system. The total produced hydrogen by the optimum configuration is 8816 kg/year at a levelized cost of hydrogen (LCOH) of 4.47 $/kg. The quantity of low-carbon fertilizer that can be produced from the produced hydrogen is also assessed. The optimum configuration also recorded an employment potential of 4 persons in 25 years. A total GHG equivalence of 383.49 metric tons of CO₂ equivalent indicating the level of emissions that will be avoided should the optimum system be used to meet the demands specified in this study was obtained.     

Read the label! Energy Star appliance label awareness and uptake among U.S. consumers

The Energy Star label program to promote the diffusion of energy efficient home appliances is arguably the most significant government effort to reduce U.S. residential energy consumption. Program effectiveness requires that consumers are aware of the labeling scheme and also change their purchase decisions based on label information. This paper examines the factors associated with consumer awareness of the Energy Star label of recently purchased ‘white’ major appliances and the factors associated with the choice of Energy Star labeled appliances. The paper finds that household characteristics have a much stronger association with consumer awareness of labels than with the choice of Energy Star appliances. Renting the home, Hispanic ethnicity, being poor or near poor, and living in regions with lower ACEEE scores do, however, decrease the propensity for households to purchase Energy Star appliances. Eliminating these gaps in Energy Star appliance adoption would result in house electricity cost savings of $164 million per year and associated carbon emission reductions of about 1.1 million metric tons per year.     

Potential for solar water heating in Zimbabwe

This paper discusses the economic, social and environmental benefits from using solar water heating (SWH) in Zimbabwe. By comparing different water heating technology usage in three sectors over a 25-year period, the potential of SWH is demonstrated in alleviating energy and economic problems that energy-importing countries like Zimbabwe are facing. SWH would reduce coincident electricity winter peak demand by 13% and reduce final energy demand by 27%, assuming a 50% penetration rate of SWH potential demand. Up to $250 million can be saved and CO₂ emissions can be reduced by 29% over the 25-year period. Benefits are also present at individual consumer level, for the electricity utility, as well as for society at large. In the case of Zimbabwe, policy strategies that can support renewable energy technologies are already in current government policy, but this political will need to be translated into enhanced practical activities. A multi-stakeholder approach appears to be the best approach to promoting widespread dissemination of SWH technologies.     

Modeling California policy impacts on greenhouse gas emissions

This paper examines policy and technology scenarios in California, emphasizing greenhouse gas (GHG) emissions in 2020 and 2030. Using CALGAPS, a new, validated model simulating GHG and criteria pollutant emissions in California from 2010 to 2050, four scenarios were developed: Committed Policies (S1), Uncommitted Policies (S2), Potential Policy and Technology Futures (S3), and Counterfactual (S0), which omits all GHG policies. Forty-nine individual policies were represented. For S1–S3, GHG emissions fall below the AB 32 policy 2020 target [427 million metric tons CO₂ equivalent (MtCO₂e) yr⁻¹], indicating that committed policies may be sufficient to meet mandated reductions. In 2030, emissions span 211–428 MtCO₂e yr⁻¹, suggesting that policy choices made today can strongly affect outcomes over the next two decades. Long-term (2050) emissions were all well above the target set by Executive Order S-3-05 (85 MtCO₂e yr⁻¹); additional policies or technology development (beyond the study scope) are likely needed to achieve this objective. Cumulative emissions suggest a different outcome, however: due to early emissions reductions, S3 achieves lower cumulative emissions in 2050 than a pathway that linearly reduces emissions between 2020 and 2050 policy targets. Sensitivity analysis provided quantification of individual policy GHG emissions reduction benefits.     

The long-term life cycle private and external costs of high coal usage in the US

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO_x and NO_x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO₂ emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO₂ emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.     

Reviving manufacturing with a federal cogeneration policy

Improving the energy economics of manufacturing is essential to revitalizing the industrial base of advanced economies. This paper evaluates ex-ante a federal policy option aimed at promoting industrial cogeneration—the production of heat and electricity in a single energy-efficient process. Detailed analysis using the National Energy Modeling System (NEMS) and spreadsheet calculations suggest that industrial cogeneration could meet 18% of U.S. electricity requirements by 2035, compared with its current 8.9% market share. Substituting less efficient utility-scale power plants with cogeneration systems would produce numerous economic and environmental benefits, but would also create an assortment of losers and winners. Multiple perspectives to benefit/cost analysis are therefore valuable. Our results indicate that the federal cogeneration policy would be highly favorable to manufacturers and the public sector, cutting energy bills, generating billions of dollars in electricity sales, making producers more competitive, and reducing pollution. Most traditional utilities, on the other hand, would lose revenues unless their rate recovery procedures are adjusted to prevent the loss of profits due to customer owned generation and the erosion of utility sales. From a public policy perspective, deadweight losses would be introduced by market-distorting federal incentives (ranging annually from $30 to $150 million), but these losses are much smaller than the estimated net social benefits of the federal cogeneration policy.     

Techno‐economic analysis of biomass/coal Co‐gasification IGCC systems with supercritical steam bottom cycle and carbon capture

In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and $0.06–$0.07/kW‐h. The SO_x emissions also decrease by about 190 tons/year (7.6 × 10^?6 tons/MW‐year). Finally, the CCS cost is around $65–$72 per ton of CO₂. For pre‐combustion CCS, sour shift appears to be superior both economically and thermally to sweet shift in the current study. Sour shift is always cheaper, (by a difference of about $600/kW and $0.02‐$0.03/kW‐h), easier to implement, and also 2–3 percentage points more efficient. The economic difference is fairly marginal, but the trend is inversely proportional to the efficiency, with cost of electricity decreasing by 0.5 cents/kW‐h from 0% to 10% biomass ratio (BMR) and rising 2.5 cents/kW‐h from 10% to 50% BMR. Pre‐combustion CCS plants are smaller than post‐combustion ones and usually require 25% less energy for CCS due to their compact size for processing fuel flow only under higher pressure (450 psi), versus processing the combusted gases at near‐atmospheric pressure. Finally, the CO₂ removal cost for sour shift is around $20/ton, whereas sweet shift's cost is around $30/ton, which is much cheaper than that of post‐combustion CCS: about $60–$70/ton. Copyright © 2014 John Wiley & Sons, Ltd.     

Assessment of projected temperature impacts from climate change on the U.S. electric power sector using the Integrated Planning Model®

This study analyzes the potential impacts of changes in temperature due to climate change on the U.S. power sector, measuring the energy, environmental, and economic impacts of power system changes due to temperature changes under two emissions trajectories—with and without emissions mitigation. It estimates the impact of temperature change on heating and cooling degree days, electricity demand, and generating unit output and efficiency. These effects are then integrated into a dispatch and capacity planning model to estimate impacts on investment decisions, emissions, system costs, and power prices for 32 U.S. regions. Without mitigation actions, total annual electricity production costs in 2050 are projected to increase 14% ($51 billion) because of greater cooling demand as compared to a control scenario without future temperature changes. For a scenario with global emissions mitigation, including a reduction in U.S. power sector emissions of 36% below 2005 levels in 2050, the increase in total annual electricity production costs is approximately the same as the increase in system costs to satisfy the increased demand associated with unmitigated rising temperatures.     

Decarbonization of the U.S. electricity sector: Are state energy policy portfolios the solution?

State governments have taken the lead on U.S. energy and climate policy. It is not yet clear, however, whether state energy policy portfolios can generate results in a similar magnitude or manner to their presumed carbon mitigation potential. This article seeks to address this lack of policy evidence and contribute empirical insights on the carbon mitigation effects of state energy portfolios within the U.S. electricity sector. Using a dynamic, long-term electricity dispatch model with U.S. power plant, utility, and transmission and distribution data between 2010 and 2030, this analysis builds a series of state-level policy portfolio scenarios and performs a comparative scenario analysis. Results reveal that state policy portfolios have modest to minimal carbon mitigation effects in the long run if surrounding states do not adopt similar portfolios as well. The difference in decarbonization potential between isolated state policies and larger, more coordinated policy efforts is due in large part to carbon leakage, which is the export of carbon intensive fossil fuel-based electricity across state lines. Results also confirm that a carbon price of $50/metric ton CO₂e can generate substantial carbon savings. Although both policy options – an energy policy portfolio or a carbon price – are effective at reducing carbon emissions in the present analysis, neither is as effective alone as when the two strategies are combined.     

The environmental and economic effects of regional bioenergy policy in the southeastern U.S.

The unique generation, landownership, and resource attributes of the southeastern United States make the region an important test bed for implementation of novel renewable energy policy interventions. This study evaluates the environmental and economic implications of one such intervention, a hypothetical region-wide renewable portfolio standard (RPS) with biomass carve-outs. It utilizes the Forest and Agriculture Sector Optimization Model with Greenhouse Gases (FASOMGHG) to assess the multi-sector and interregional allocation of forest harvest activity, and then uses the Sub-Regional Timber Supply (SRTS) model to assess intraregional variation in forest composition and greenhouse gas (GHG) mitigation potential. The analysis finds that existing resource conditions influence the regional distribution of land use and harvest changes, resulting in a spatially and temporally diverse forest carbon response. Net forest carbon in the Southeast is greater in the RPS Scenario than in the No RPS Scenario in all but the final years of the model run. Accounting for displaced fossil emissions yields net GHG reductions in all time periods. Both research methodology and findings are also applicable to a broader suite of domestic and international policies, including European Union renewable energy initiatives and GHG mitigation under Section 111 of the U.S. Clean Air Act.     

The feasibility,costs, and environmental implications of large-scale biomass energy

What are the feasibility, costs, and environmental implications of large-scale bioenegry? We investigate this question by developing a detailed representation of bioenergy in a global economy-wide model. We develop a scenario with a global carbon dioxide price, applied to all anthropogenic emissions except those from land use change, that rises from $25 per metric ton in 2015 to $99 in 2050. This creates market conditions favorable to biomass energy, resulting in global non-traditional bioenergy production of ~ 150 exajoules (EJ) in 2050. By comparison, in 2010, global energy production was primarily from coal (138 EJ), oil (171 EJ), and gas (106 EJ). With this policy, 2050 emissions are 42% less in our Base Policy case than our Reference case, although extending the scope of the carbon price to include emissions from land use change would reduce 2050 emissions by 52% relative to the same baseline. Our results from various policy scenarios show that lignocellulosic (LC) ethanol may become the major form of bioenergy, if its production costs fall by amounts predicted in a recent survey and ethanol blending constraints disappear by 2030; however, if its costs remain higher than expected or the ethanol blend wall continues to bind, bioelectricity and bioheat may prevail. Higher LC ethanol costs may also result in the expanded production of first-generation biofuels (ethanol from sugarcane and corn) so that they remain in the fuel mix through 2050. Deforestation occurs if emissions from land use change are not priced, although the availability of biomass residues and improvements in crop yields and conversion efficiencies mitigate pressure on land markets. As regions are linked via international agricultural markets, irrespective of the location of bioenergy production, natural forest decreases are largest in regions with the lowest barriers to deforestation. In 2050, the combination of carbon price and bioenergy production increases food prices by 3.2%–5.2%, with bioenergy accounting for 1.3%–3.5%.     

The future of U.S. natural gas production,use, and trade

Two computable general equilibrium models, one global and the other providing U.S. regional detail, are applied to analysis of the future of U.S. natural gas. The focus is on uncertainties including the scale and cost of gas resources, the costs of competing technologies, the pattern of greenhouse gas mitigation, and the evolution of global natural gas markets. Results show that the outlook for gas over the next several decades is very favorable. In electric generation, given the unproven and relatively high cost of other low-carbon generation alternatives, gas is likely the preferred alternative to coal. A broad GHG pricing policy would increase gas use in generation but reduce use in other sectors, on balance increasing its role from present levels. The shale gas resource is a major contributor to this optimistic view of the future of gas. Gas can be an effective bridge to a lower emissions future, but investment in the development of still lower CO₂ technologies remains an important priority. International gas resources may well prove to be less costly than those in the U.S., except for the lowest-cost domestic shale resources, and the emergence of an integrated global gas market could result in significant U.S. gas imports.