This report is one of two companion reports prepared by Pennsylvania State University, with contributions from Seth Blumsack and Thomas Murphy. Their work was performed under contract to CRS, and was part of a multiyear CRS project to examine various aspects of U.S. energy policy. [author name scrubbed], Assistant Director of the Resources, Science, and Industry Division, served as CRS project coordinator. [author name scrubbed], Specialist in Energy Policy, served as CRS reviewer and editor of this report. The second report is CRS Report R43635, Shale Energy Technology Assessment: Current and Emerging Water Practices . This report will not be updated. This report was funded, in part, by a grant from the Joyce Foundation. With shale gas resources in North America and around the world continuing to be identified, evaluated, and developed, there is an increased expectation by many in academia, government, and industry that there is now resource abundance. The United States has led this trend, and the overall U.S. natural gas supply likely will expand in the near term and beyond. The U.S. Energy Information Administration (EIA), in the Annual Energy Outlook 2014 projections, reflects this advancing pace in natural gas production. The United States is facing increasing industrial and power demands for natural gas, as well as possibly becoming a net liquefied natural gas (LNG) exporter and overall gas exporting country by 2016 and 2018, respectively. At the same time, Figure 1 illustrates how prices for the commodity are continuing to trend near historical lows. Current expectations are for those levels to continue in the near and mid-terms. While low prices are generally good news for consumers in the industrial, power generation, commercial, and residential sectors, they do cause a number of closely related technical and market impacts worth further research and analysis. Recent changes in thermal coal use in the United States, illustrated in Figure 2 , impacted by switching from coal to natural gas, are substantial and will likely continue to trend downward due to overall market influences of natural gas prices relative to coal, along with current and pending federal and state policy. Coal-to-gas switching for U.S. power generation doubled in 2012 from the same period in 2011, with gas use for power generation doubling from 3 billion cubic feet per day to 6 billion cubic feet per day. Although coal export to Asian and European electric power generation operators has risen, there has still been a net negative impact on the mining sector in several regions of the United States. Rail capacity that was used to move coal to market is now underutilized. On the other hand, some of the rail capacity is now being redeployed to move crude oil from shale deposits in the upper western United States to eastern refineries where demand for domestic West Texas Intermediate (WTI) priced crude has increased relative to higher-cost Brent priced imports from other global locations. Pipeline capacity to accomplish the same goal has regulatory, right-of-way, and financial challenges, and is viewed by some as insufficiently responsive to the rapid increase in development. It is possible that rail will one day move natural gas as well. The addition of a large number of U.S. and international oil and natural gas companies entering shale gas developments during the last six years, with larger capital budgets and longer investment horizons, has advanced both private and public research on natural gas extraction technologies. The presence of these companies also may increase the likelihood of other countries' developing shale formations. Field service companies are also integral in both these respects. Government agencies have traditionally conducted or funded related energy research and currently are pursuing multiagency initiatives, although federal budgetary constraints may limit the extent of these activities going forward. A historical shift is taking place in how fossil energy is being sourced and utilized when compared to energy development and consumption patterns of the past four decades. Conventional thinking is that North America will now make very significant gains in the goal of achieving energy independence due to both reduced energy use through efficiencies, i.e. increases in the Corporate Average Fuel Economy (CAFE) standards, among other things, and rapidly increasing supply. The technologies and techniques being applied to develop new sources of natural gas from shale are advancing quickly as the science is evolving and the overall size of the resource is better understood. As an example, early estimates of the Marcellus Shale resource in the Appalachian basin proved somewhat conservative, and have been revised upward by the U.S. Geological Survey (USGS) from the original 2 trillion cubic feet to the current projection of 84 trillion cubic feet of undiscovered technically recoverable gas. Figure 3 illustrates recent shale-gas resources estimates. Some third-party firms and academics now indicate that this shale alone could yield upwards of four times the most recent previous estimates, based on a better understanding of the geology, much of which is now based on actual drilling and the resultant data coming from those wells. In the case of Pennsylvania, more than 6,000 wells had been drilled into the Marcellus as of November 2012, and in 2012, Pennsylvania produced more than 2 trillion cubic feet of natural gas (see Figure 4 ). Similar data from West Virginia's shale wells to date indicate a similar trend. In that multistate region, gas volumes are increasing even as the number of drilling rigs operating shows a slowly decreasing year-by-year trend. Figure 5 shows that a majority of the natural gas produced in the United States comes from a small group of states, led by Texas. However, it is important to note that Pennsylvania's rise into the top four producing states is a relatively recent occurrence. Prior to 2011, Pennsylvania was producing less than 1 trillion cubic feet per year, and before then it produced less than 0.2 trillion cubic on average since the 1980s. Pennsylvania's rise in production is significant for overall U.S. supplies, but more importantly because of its proximity to the largest U.S. markets for natural gas, the Northeast. Pipeline capacity in the same region of the United States, both interstate transmission lines and local gathering lines, is currently in need of expansion to accommodate the potential demands of energy companies completing natural gas wells. Approximately 50% of the wells drilled in Pennsylvania do not have access to a pipeline allowing gas to reach commercial markets. This is particularly true in northeastern Pennsylvania, where the industry has a shorter history of drilling than in other regions of the United States, thus necessitating the need to construct more of this infrastructure, particularly gathering-pipeline systems. The gas market is accounting for this bottleneck in supply near large eastern cities, with a lower basis price at key citygate locations when compared to historical premium price levels. In western Pennsylvania, where the natural gas also contains natural gas liquids, fractionation facilities are also an infrastructure constraint to development. Industry estimates indicate there will need to be a nationwide investment of $10 billion per year for each of the next 10 years to develop adequate capacity in gathering and transmission pipelines, along with associated compression facilities en route. Similar trends are also being seen in gas flows in other regions. The Rockies Express Pipeline (REX) built to supply gas from the Rocky Mountains to eastern U.S. markets was at 70% capacity during the winter of 2012. Its unused capacity is largely accounted for due to the net surplus of Marcellus gas produced in Pennsylvania and West Virginia. The combined transmission capacity of the historical pipelines routed from the Gulf Coast to northeastern markets was at 45% of potential volume in 2012. Legacy premium gas pricing seen in northeastern U.S. markets will likely trend to western markets within five years due to increasing demand there; eastern shales are predicted to expand net surpluses in that region during the same period. West-to-east flow in trans-Canadian pipeline capacity has declined as well, partially related to eastern United States shale gas moving into eastern Canada in 2012 at a rate of 400 million cubic feet per day due to closer proximity and upgraded pipeline and compression facilities. In addition, declining Canadian gas production and greater use in western Canada are contributing factors in this trend. Overall, the amount of natural gas being imported from Canada, a traditional supplier, has been dropping (see Figure 6 ), and is now less than 8% of total U.S. usage. Similarly, flow of gas to Mexico is increasing, exceeding 1.8 bcf/d in 2013. The traditional market dynamics in the United States between supply and demand are changing and affecting how natural gas is priced. The Henry Hub in Erath, LA, has been the basis for U.S. natural gas prices, in part because of the numbers of natural gas pipelines that intersect that area. With more natural gas being produced outside of the Gulf area and the amount of natural gas passing through Henry Hub, market distortions are arising that are being reflected in regional prices. For example, the spreads between the Columbia Gas Transmission Appalachian index (TCO Appalachia)—an actively traded location for both physical and financial transactions for natural gas in southwest Pennsylvania—and the Henry Hub are illustrated in Figure 7 . The nature of the spread is changing due mainly to growth in Marcellus production. Natural gas at the TCO Appalachia has historically been priced about $0.25 per million British thermal units above Henry Hub. However, the spread between these two points in spot markets reflects roughly parity now, and in forward markets TCO Appalachia is priced less than at the Henry Hub. This series reflects how some market participants assess the future difference between the southwest Pennsylvania and Gulf Coast natural gas market. As the marketplace better realizes the share that shale gas production is able to add to the total volume of U.S. production, and anticipates the potential drilling successes of energy companies developing this resource, short- and mid-term prices are being held to the lower end of the historical range.