TODAY’S STUDY: THE MAJOR CHANGE THAT NATURAL GAS IS

Natural Gas and the Transformation of the U.S. Energy Sector: Electricity

Jeffrey Logan, Garvin Heath, and Jordan Macknick (National Renewable Energy Laboratory) and Elizabeth Paranhos and William Boyd (University of Colorado Law School) and Ken Carlson (Colorado State University), November 2012 (National Renewable Energy Laboratory)

Executive Summary

Domestic natural gas production was largely stagnant from the mid-1970s until about 2005. Planning had been under way by the early 2000s to construct about 40 liquefied natural gas import terminals along the U.S. coasts to meet anticipated rising demand. However, beginning in the late 1990s, advances linking horizontal drilling techniques with hydraulic fracturing allowed drilling to proceed in shale and other formations at much lower cost. The result was a slow, steady increase in unconventional gas production.

As the technology improved and spread, domestic shale gas output began to increase rapidly, such that by 2008 commentators began to routinely speak of a shale gas “boom.” Today, shale gas accounts for about 30% of total U.S. natural gas production—up from only 4% in 2005— helping to make the United States the largest producer of natural gas in the world by 2009. Within a decade, the question of how much more dependent the country would become on natural gas imports had been replaced by how much the U.S. gas supply will affect the economics and geopolitics of energy around the globe.

Although the long-term outcome of the shale gas revolution is far from decided, significant shifts are already apparent in U.S. power markets. In that context, low-price natural gas has had the greatest impact to date on generation by coal power plants. Since 2008, coal’s share of annual generation has declined from 48% to 36% as of August 2012. This switch from coal to natural gas, combined with growth of renewable energy generation, has led to a reduction of carbon dioxide emissions in the U.S. power sector of about 300 million tons—equivalent to 13% of total power sector emissions in 2008.

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It remains unclear, however, whether natural gas will continue to exert such a dramatic impact on the power sector and the overall U.S. economy. If natural gas prices continue to stay at, or near, historically low levels, then a self-correction in the shale gas boom may occur. Due to price concerns, some companies have shifted away from drilling for dry gas and instead are focusing on plays that provide natural gas liquids. The ongoing debate is about what price is needed for unconventional natural gas production to be more sustainable over the medium term. As an example, analysis from Range Resources indicates that New York Mercantile Exchange prices of $4–$6/MMBtu are needed at the vast majority of plays to generate adequate returns on investment.1 Other factors—including “use it or lose it” lease terms, reserve filings with the Securities and Exchange Commission, and the amount of natural gas liquids that can be recovered—all play a role in continuing investment decisions. But, for now, natural gas markets are still widely acknowledged as oversupplied, and storage facilities held record high amounts of gas as of mid-2012.

Hydraulic fracturing has received negative attention in many parts of the country—especially those areas not accustomed to the oil and gas industry—due to real and perceived environmental and social concerns. Water use and contamination, air pollution, greenhouse gas (GHG) emissions, and truck traffic are among the concerns that have strained the social license to operate, and they have been the subject of multiple national and international reports and continued dialogue. Field practices associated with unconventional natural gas production have evolved rapidly in some regions, either from new regulatory requirements or voluntary company practices. These field practices are still evolving, can be uneven across regions, and are sometimes controversial. At the same time, consolidation within the industry is shifting production from smaller to larger companies.

The Joint Institute for Strategic Energy Analysis (JISEA) designed this study to address four related key questions, which are a subset from the wider dialogue on natural gas:

1. What are the life cycle greenhouse gas (GHG) emissions associated with shale gas compared to conventional natural gas and other fuels used to generate electricity?

2. What are the existing legal and regulatory frameworks governing unconventional gas development at federal, state, and local levels, and how are they changing in response to the rapid industry growth and public concerns?

3. How are natural gas production companies changing their water-related practices?

4. How might demand for natural gas in the electric sector respond to a variety of policy and technology developments over the next 20 to 40 years?

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Major Findings

Although the questions analyzed in this report are interlinked to a certain extent, they have specific requirements in terms of analysis methodologies and associated stakeholders. The key findings are presented very briefly as follows:

• Greenhouse gas emissions: Based on analysis of more than 16,000 sources of air- pollutant emissions reported in a state inventory of upstream and midstream natural gas industry, life cycle greenhouse gas emissions associated with electricity generated from Barnett Shale gas extracted in 2009 were found to be very similar to conventional natural gas and less than half those of coal-fired electricity generation.

• Regulatory trends: The legal and regulatory frameworks governing shale gas development are changing in response to public concerns and rapid industry changes, particularly in areas that have limited experience with oil and gas development. All of the states examined in this study have updated their regulatory frameworks to address the opportunities and challenges associated with increasing unconventional natural gas production.

• Water management: Many regions evaluated in this study are making greater use of innovative water management practices to limit real and perceived risks. However, a lack of reliable, publicly available water usage and management data—such as total water withdrawals, total wells drilled, water-recycling techniques, and wastewater management practices—currently hinders efforts to develop appropriately flexible and adaptive best management practices. Recent studies have documented a number of management practices related to the chemical makeup of fracking fluids, impacts on local freshwater, and on-site wastewater management that may be appropriate in many locations.

However, to date, no public studies have been published on cost-benefit, risk-mitigation potential, or the transferability of practices from one shale play to another.

• Electric power futures: A number of different future electric power scenarios were analyzed to evaluate both the implications of shale gas development and use, and various policy and technology changes. These scenarios include power plant retirements, advances in generation technologies, federal policies to reduce greenhouse gas emissions, and variations in natural gas supply and demand. We find that natural gas use for power generation grows strongly in most scenarios.

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Life Cycle Greenhouse Gas Emissions from Barnett Shale Gas Using Air-Quality Inventory Data

A national debate over life cycle GHG emissions2 from shale natural gas erupted in 2011 after a study was released stating that shale gas had equivalent or even greater GHG emissions than coal.3 Since then, a number of other published, peer-reviewed studies have included contrary findings,4 although data limitations and methodological variability make conclusive statements problematic about the “real” GHG emission profile.

For Chapter 1, the study team conducted original research on life cycle GHG emissions associated with natural gas production in the Barnett Shale play in Texas. This estimate leverages high-resolution empirical data to a greater extent than previous assessments. The data sources and approach used in this study differ significantly from previous efforts, providing an estimate valuable for its complementary methodological approach to the literature.

The authors used inventories from 2009 that tracked emissions of regulated air pollutants by the natural gas industry in the Barnett Shale play. The Texas Commission on Environmental Quality (TCEQ) collected and screened these inventories. These data cover the characteristics and volatile organic compound (VOC) emissions of more than 16,000 individual sources in shale gas production and processing. Translating estimated emissions of VOCs into estimates of methane and carbon dioxide emissions was accomplished through the novel compilation of spatially heterogeneous gas composition analyses.

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Major findings from this analysis of life cycle GHG emissions include:

• Electricity generated using a modern natural gas combined-cycle turbine combusting Barnett Shale gas produced and processed in 2009 has life cycle GHG emissions ranging between 420 and 510 grams carbon dioxide-equivalent emissions per kilowatt-hour (g CO2e/kWh) generated, depending on assumed lifetime production of a well, with a central estimate of about 440 g CO2e/kWh—similar to levels reported in the literature from conventional natural gas and less than half that typical for coal-fired electricity generation (Figure 1).5 Comparisons to conventional natural gas and coal are achieved through harmonization of 200 published estimates of life cycle GHG emissions for those two technologies.6 Harmonization is a meta-analytical process that makes consistent the assumptions and methods between LCAs.

• An estimated 7% to 15% of life cycle GHG emissions from electricity generation (mean = 9%) are from methane emissions throughout the fuel cycle of Barnett Shale gas (well pre-production activities through transmission), mostly from venting during completion and workover, and from the natural gas transmission pipeline network.

• GHG emissions result from many sources throughout the production and use of natural gas. Based on our analysis, more than half can be characterized as sources with potentially controllable leakage—for instance, from tanks or vents. Another 20% are combustion sources, which also have some emission control opportunities. Remaining sources, called fugitive emissions, are more challenging to control because of their dispersed nature.

• An estimated 1.5% of Barnett Shale produced gas is emitted to the atmosphere before reaching the power plant, much of which is potentially preventable, with an additional 5.6% of produced gas consumed along the process chain as fuel for different types of engines. Based on the estimated methane content of this produced gas and average assumed lifetime production of a well, this equates to a central estimate of leakage rate across the life cycle of 1.3% methane volume per volume of natural gas processed.

• Chemical composition of produced gas varies considerably within the Barnett Shale area such that at the county level, estimates of GHG emissions differ significantly from those based on composition averaged at a higher spatial resolution (play or nation). Variability in gas composition has implications for the understanding of emission sources and the design of regulatory emission control strategies.

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A Changing Regulatory Framework for Unconventional Gas Production

Chapter 2 examines the main federal, state, and local regulatory frameworks that govern unconventional natural gas development. Specifically, it focuses on requirements related to water withdrawals used for hydraulic fracturing, disclosure of chemicals used in hydraulic fracturing fluids, setbacks for wells, baseline water monitoring of surface water resources or water wells, well-construction standards, “green” or “reduced emission” completions, storage of waste in closed-loop systems, and the disposal of produced water. It also examines state compliance monitoring and enforcement capabilities, and the efforts by some local governments in key gas- producing states to limit—and, in some cases, ban—unconventional gas development.

Major findings include the following:

• There is a trend toward more regulation at all levels of governance, but there has been a corresponding increase in regulatory fragmentation and differentiation at state and local levels. Better coordination and policy alignment among regulators can help to reduce risks to industry and the public of regulatory fragmentation—including uncertainty, delays, gaps, and redundancies across jurisdictions. Improved communication and sharing of information among regulators at all levels of government and across jurisdictions, as well as increased transparency in the form of publicly available data from industry, would help address regulatory fragmentation and inform regulatory development tailored to specific geographic and geologic characteristics.

• Compliance monitoring and enforcement varies across states, with significant implications for the efficacy of regulations, as well as public confidence. Increased public disclosure of voluntary information—as well as public disclosure of violations, enforcement actions, and company compliance—would increase transparency, offer opportunities to highlight the compliance records of leading companies who have demonstrated a commitment to safe natural gas production, and help address public concerns.

• There is a significant range in the environmental performance of operators in the industry, with some operators performing at a level that goes beyond existing regulations and other operators falling short. There is an evolving portfolio of recommended practices emerging from across the stakeholder community; these practices can complement and supplement regulations.

• The varied state and local approaches to regulation can provide important opportunities for learning and innovation regarding substantive rules, the role of best practices, and compliance and enforcement. Regulators might consider adopting performance-based standards, rather than freezing today’s “best management practices” into prescriptive rules that could become outdated.

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Management Practices in Shale Gas Production: Focus on Water

Chapter 3 addresses current water usage and water management practices at shale gas development sites and discusses risks to water availability and quality. We evaluated publicly available water usage data from six shale plays throughout the United States. When data were available, we conducted statistical analyses from a randomized sample of wells in each play to gauge current estimates of water usage per well. In addition, data were collected on current wastewater management techniques and volumes associated with managing produced water from wells along with the returned fracking fluids. Lastly, in addition to analyzing current industry practices, we evaluated how water usage, well number, and water management techniques have evolved over time, indicating that water risk and management issues in the future may differ from historical issues. Natural gas exploration and production has significant spatial variability in community and environmental issues, current practices, and regulations. Therefore, JISEA is also publishing the water-related results of this study in a web-based GIS format.

The three primary water impact risks are: regional resource depletion due to use of fresh water during hydraulic fracturing, surface water degradation, and groundwater degradation. Impact risks to water resources vary geographically based on three considerations: 1) where the water comes from, 2) what water use and management practices are followed on site for hydraulic fracturing, and 3) how and where produced water and frac flowback water are treated and/or disposed.

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Major findings from this analysis of water impacts include the following:

• Risks to regional freshwater depletion depend on a variety of factors, including water use per well, total number of wells, water recycling rates, and regional water availability. Analysis of use data for four of the six regions from 2007 to 2011 indicated average water use per well ranges from 1.1 to 4.8 million gallons, with a multi-region average of 3.3 million gallons. The total magnitude of water usage depends on the number of wells drilled, which has increased in most regions from 2007 to 2011. In the Eagle Ford play, for example, gas wells increased from 67 in 2009 to 550 in 2011. Total freshwater usage depends on water recycling rates, which may vary greatly depending on location. In 2011, the highest rates of recycling were reported in Pennsylvania, where 37% of produced water and 55% of frac flowback water were recycled, representing nearly 200,000 gallons per well, or 4% of average water use per well in Pennsylvania. Total impacts on regional freshwater resources can be evaluated by comparing total freshwater uses with estimates of regional freshwater availability.

• Wastewater management practices vary regionally and show different trends from 2008 to 2011. In Pennsylvania, 80% of produced water and 54% of frac flowback water was treated through surface water discharge in 2008, whereas in 2011, less than 1% of produced water and frac flowback was treated through surface water discharge. In 2011, centralized disposal facilities and recycling are the primary wastewater management methods, accounting for 80% of produced water volumes and 99% of frac flowback volumes. In Colorado, surface water discharge of both produced water and frac flowback volumes has increased from 2% in 2008 to 11% in 2011. Management of produced water and frac flowback through onsite injection pits and evaporation ponds have remained the dominant practices from 2008 to 2011, representing 72% and 58%, respectively. Treatment at a centralized disposal facility has increased from 26% to 31% from 2008 to 2011. The management and transport of produced water and frac flowback water is considered to be the stage at which spills and leaks are most likely.

• A lack of reliable, publicly available water usage and management data hinders comprehensive analyses of water risks. Data are not publicly available for total water withdrawals, total gas wells drilled, flowback volume per well, water recycling techniques, wastewater management, and other management practices for many regions. These data would assist in developing appropriately flexible and adaptive best management practices. Certain resources—such as the State Review of Oil and Natural Gas Environmental Regulations (STRONGER) and FracFocus—have greatly increased public access to information about risks of hydraulic fracturing; however, further efforts would be beneficial.

• A variety of best management practices are currently being employed in different regions, but there is industry uncertainty over transferability, cost-effectiveness, and risk mitigation potential. Recent studies have documented a number of water-related management practices related to the chemical makeup of fracking fluids (disclosure of additives, minimizing or switching to more benign additives, baseline water quality testing), the impacts on local freshwater (measuring and reporting of volumes, water recycling, use of non-potable or non-water sources), and onsite wastewater management techniques (use of closed-loop drilling systems, elimination of flowback and freshwater mixing in open impoundments, use of protective liners at pad sites) that may be appropriate in many locations. However, to date, there are no publicly available studies that have performed cost-benefit analyses, evaluated the risk-mitigation potential of each strategy, or analyzed practices that could be transferred from one shale play to another.

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Modeling U.S. Electric Power Futures Given Shale Gas Dynamics

In Chapter 4, the study evaluates different electric power scenarios that are influenced by natural gas availability and price, as well as other key policy, regulatory, and technology factors. Many of the scenarios examine sensitivities for the estimated ultimate recovery (EUR) of gas fields. High-EUR corresponds to more abundant and inexpensive natural gas compared to Low-EUR.

Major findings from the electric sector analysis include the following:

• Natural gas demand by the power sector would grow rapidly—more than doubling from the 2010 level by 2050—in the Reference, or baseline, scenario.7 Figure 2 illustrates the range of natural gas power generation in all scenarios. The main Reference scenario suggests that natural gas would replace coal as the predominant fuel for electricity generation. Attributes of this baseline scenario include rising power demand, stable greenhouse gas emissions, and slowly rising electricity prices that reflect natural gas availability and prices. By 2050, in the Reference scenario, gas could represent from 28% to 38% of power-sector generation compared to the 2010 portion of 20%.

• In a coal retirement scenario, natural gas, and wind to a lesser extent, replaces coal-based generation. Our modeling results indicate no impact on power sector reliability from 80 GW of coal retirements by 2025 on an aggregate scale, although additional detailed dispatch modeling is needed to evaluate localized impacts. National average retail electricity prices in the retirement scenario increase by less than 2% in 2030 compared to the baseline.

• Under a clean energy standard (CES) scenario, U.S. power sector carbon dioxide emissions would decrease by 90% between 2010 and 2050, with a corresponding 6%– 12% increase in average retail electricity prices, including transmission build-out that ranges from 3 to 6 times more than the Reference scenario (measured in million MW-miles). Among the CES sensitivity scenarios, large quantities of variable renewable energy and flexible gas generation work synergistically to maintain system reliability requirements.

• Advances in generation technologies can have a significant impact on estimated carbon emissions, electricity diversity, and prices. For example, nuclear capital costs would need to decline by half, while gas prices remain relatively high (as simulated in the low-EUR assumption), for the nuclear generating option to compete economically with other options. Wind and solar electricity could more than double by 2050 compared to the Reference scenario with continued improvements in the cost and performance of these technologies. Likewise, continued improvements in production techniques for unconventional natural gas production could enable natural gas to continue to grow market share.

• We consider a range of potential incremental costs associated with operating practices that could better address some of the public concerns in the production of unconventional natural gas. Some of these options include recycling larger amounts of frac flowback water, reducing methane releases to the atmosphere, setting well locations further from potentially sensitive communities, and assuring consistent use of best practices or regulations in well drilling and completions. Sensitivities in incremental costs were evaluated from $0.50/MMBtu to $2/MMBtu. For example, additional costs of $1/MMBtu associated with some or all of these several dozen operating practices would lead to a 17% reduction in gas use for power generation by 2050 compared to the Reference scenario; however, gas-fired generation still more than doubles from the 2010 level.

• A “dash-to-gas” scenario, where other sectors of the economy increase natural gas demand by 12 billion cubic feet per day by 2030, would likely result in higher domestic gas prices and lead to a roughly 20% reduction in power sector natural gas use by 2050 compared to the Reference scenario in that year, but still nearly twice the level used in 2010. Additional research is needed to understand how natural gas prices respond to rising demand in the new natural gas environment.

The rapid expansion of shale gas has created dynamic opportunities and challenges in the U.S. energy sector. How long the ascendancy of natural gas in the electric sector will last will be a function of a wide variety of market and policy factors. The story of unconventional gas is evolving rapidly, and in some cases, unexpectedly. Robust and up-to-date analysis will remain critical to informing the key decisions that must be made by all types of stakeholders in the energy and environmental arenas.

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