An Analysis of the Potential for Expanded Use of Natural Gas in Electrical Power Generation, Transportation, and Direct Use: Texas as a Case Study

Transcription

1 An Analysis of the Potential for Expanded Use of Natural Gas in Electrical Power Generation, Transportation, and Direct Use: Texas as a Case Study Fred C. Beach, PhD, Marianne Shivers Gonzalez, John C. Butler, PhD, and Michael E. Webber, PhD The University of Texas at Austin 1 University Station C2200 Austin, TX Web: March 17, 2012

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3 Contents 1 Executive Summary Introduction Texas as a Case Study Power Sector Power Increasingly Fueled by Natural Gas Mixed Signals Might Squeeze Out Gas-Fired Generation Incremental Increase in Gas Usage Could Replace 24% of Texas Coal-Fired Generation Transportation Sector Negligible Natural Gas Used for Transport CNG in Transport Reduces Dependence on Foreign Oil and Improves Air Quality CNG Increase for Transportation is Feasible But Needs Policy Support Residential Sector Natural Gas is Common for Heating Water and Homes Improved Consumer Education Could Increase Natural Gas Use Natural Gas Offers Possibility to Live Off-the-Grid Incremental Increase in Natural Gas Used for Water Heaters Could Meaningfully Reduce Coal-Fired Generation Requirements Implications at the National Level Key Conclusion Background and Context 13 3 Texas As A Case Study Texas Energy Production and Use Texas Electricity Generation (ERCOT) Texas Natural Gas Infrastructure and Economy Natural Gas in the Power Sector Environmental Considerations Economic Considerations Relationship with Renewables (Wind and Solar) A Fuel Switching Option iii

4 Contents 5 Natural Gas As An Alternative Fuel in Transportation Natural Gas in Transportation Texas and California The 10% Option Residential Use of Natural Gas Source Energy Versus Site Energy Heating Water The 10% Option Implications for Natural Gas at the National Level 79 8 Conclusions and Future Work Conclusions Future Work Acknowledgements 95 iv Natural Gas in Texas, UT Austin, 2012

5 List of Figures 2.1 Schematic Geology of Natural Gas Resources Assessment of Shale Gas Resources in Selected Countries, Global Natural Gas Proven Reserves and Replacement Ratio Energy Consumption by Sector for Texas and United States, Texas Energy Production and Consumption, by Source Texas Energy Production, Resources, Power Generation and Transmission ERCOT Coverage and Zones, pre Dec ERCOT Zonal versus Nodal Connection ERCOT Installed Capacity and Generation, ERCOT Generation Short and Long-Term Deratings, Texas Natural Gas Proven Reserves, Barnett Shale Field Production, Texas Natural Gas Exports Monthly US Natural Gas Prices Texas Intrastate Natural Gas Pipelines Texas Nonattainment Areas Texas Energy Map Estimated Net Revenue Installed Capacity by ERCOT Zone and Total Marginal Fuel Frequency (West Zone) Wind Dispatch Effect in ERCOT Hour Ozone Nonattainment Areas (1997 Standard) April EPA Nonattainment Areas Populations Within the Texas Triangle Texas Triangle Megaregion Counties Notional Texas Triangle CNG/LNG Infrastructure Trends and Forecast in Residential and Commercial Energy Use Trends and Forecast in Residential and Commercial CO 2 Emissions Source to Site Efficiencies for Electricity Generation Source to Site Efficiencies for Direct Use Fuels v

6 List of Figures 6.5 US NERC Regions Water Heater Source Energy Consumption by NERC Region Water Heater Emission Comparisons by NERC Region and US US Electrical Generation by Fuel Type and Initial Year of Operation US Electric Power Industry Net Summer Capacity by Fuel Type US Electric Power Industry Net Generation by Fuel Source, Monthly Capacity Factors in 2007 for Study Group Coal and NGCC Plants US Interstate Natural Gas Pipeline System US Natural Gas Underground Storage Sites Monthly US Underground Natural Gas Storage Natural Gas Prices in Major Markets, July 2007-April Global Growth in Natural Gas Vehicles US Energy Use by Fuel and Sector (2008) Texas Energy Use by Fuel and Sector (2008) vi Natural Gas in Texas, UT Austin, 2012

7 List of Tables 2.1 Estimated Shale Gas Technically Recoverable (Selected Basins 2009) Texas Coal Plants (2007) Texas Coal Plants Ranked by Net Generation (2007) Texas Coal Plants Ranked by CO 2 Emission Rate (2007) Five Highest Rate Emitters (2007) Texas Coal Plant Cooling Water Source, Method, and Consumption Rates Texas Coal Plants Ranked by Emission Rate, with Water Data Net Environmental Effect of Displacing Coal with NGCC US Average Electricity Generation Source Energy Factors Electricity Generation Source Energy Factors by NERC Region US Average Source Energy Factors for Site Use of Fossil Fuels vii

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9 1 Executive Summary 1.1 Introduction The evolving role of natural gas in the US energy portfolio has become one of the prominent energy stories of the early 21st century. The increase in attention and speculation on the future of natural gas has been driven by two primary factors: 1) the promise of immense domestic quantities of shale gas enabled by horizontal drilling and hydraulic fracturing, which has kicked off what many expect to be an era of low, stable natural gas prices, and 2) the potential of federal legislation or EPA regulation aimed at limiting the emissions of pollutants and carbon dioxide. These two factors are intimately linked and it is not yet clear with any certainty how the interplay between production, consumption, price, legislation, and regulation will affect the role natural gas plays over the next several decades. Irrespective of the multiple causal factors behind natural gas supply, demand, and price, and their complex interplay, US production and consumption of natural gas have both increased on a steady basis from 2006 through 2010[20]. This increase is in stark contrast with the concerns in 2003 that US gas production had hit an all-time peak. This study builds upon previous work done at the national level, 1 but focuses specifically on Texas. The work presented herein is based upon the assumption that shale gas reserves in the US will be developed and that natural gas will play a steadily increasing role in US electricity generation, transportation, and residential use. Though natural gas production and distribution are well established in the US, significantly increasing its use will require both market demand and infrastructure improvements and expansion. Thus, expanded use of natural gas could potentially face several important obstacles, many of which are identified in this report. This study analyzes impacts on the electricity generation, transportation, and residential sectors, with a particular focus on the power sector in Texas, and offers options to facilitate a logical and sustainable increased use of natural gas in each of them. 1 Over the last few years, several studies and reports have been published that investigate and analyze different scenarios for the future of natural gas both nationally and globally (The Future of Natural Gas, MIT Energy Initiative, 2010; Implications of Greater Reliance on Natural Gas for Electricity Generation, Aspen Environmental Group, July 2010; Are We Entering A Golden Age of Gas?, International Energy Agency 2011; Annual Energy Outlook 2011: With Projections to 2035, U.S. Energy Information Administration, April 2011). 1

10 CHAPTER 1. EXECUTIVE SUMMARY 1.2 Texas as a Case Study Because of the non-uniform impacts and opportunities of natural gas, this study focuses on the state of Texas (Electric Reliability Council of Texas (ERCOT) service area for electrical generation) as a case study. There are several motivations for this geographic focus: 1. Texas is the largest natural gas producing state in the nation. If Texas were a nation (and the United States was without Texas), then Texas would be the world s thirdlargest natural gas producer after Russia and the United States[48]. 2. Texas is the largest natural gas consuming state in the nation. Texas is a major consumer of natural gas for non-power industrial applications such as the chemical sector. In 2006, this demand accounted for 42% of natural gas use in the state while electric power generation consumed 47.7%, commercial use 4.9%, and residential use 5.4%[48]. These uses totaled nearly 3.1 TCF or 61% of the states dry gas production, while the remaining 39% was piped out of the state[53]. (NOTE: total production has increased from 5.5 TCF in 2006 to 6.5 TCF in 2010, which will change that breakdown of how much is used in-state vs. exported out-of-state[20].) Consumption of natural gas for transportation in Texas is miniscule in comparison to these uses but still totaled 2.2 Bcf (0.1 %of the states consumption) for the year making Texas the third largest consumer, for transportation, in the country behind California and New York[20]. 3. Texas generates a higher-than-average fraction of its electricity from natural gas. In 2010, 57% of ERCOTs generation capacity and 38% of electricity production came from natural gas[49](the Electric Reliability Council of Texas covers 75% of the state geographically and 80% of the population). By contrast, coal provided 45% and natural gas 24% of electricity production nationally in 2010[20]. 4. Texas is the nation s largest consumer of coal, despite being only the nation s 6thlargest producer of coal, which means a substantial amount of coal is imported from other states (primarily from the Powder River Basin in Wyoming). 5. Texas is the largest carbon emitting state in the nation. If Texas were a country, it would be the 7th-largest carbon emitter in the world[40], thus its exposure to potential financial liabilities associated with GHG legislation are very relevant. These emissions primarily come from the industrial sector (including power generation). 6. Texas has substantial air quality issues (ozone action days, smog episodes, nonattainment zones, etc.), and therefore has a lot to gain by reducing emissions in the power and transportation sectors. 2 Natural Gas in Texas, UT Austin, 2012

11 CHAPTER 1. EXECUTIVE SUMMARY 7. Texas has an independent grid (ERCOT) that covers most of its geographic area and serves most of its population, which means the analysis for the Texas power sector can be isolated from other regions. Furthermore, grid operations within ERCOT are mostly deregulated, which means the interplay of market forces and regulations yield non-obvious possible outcomes for fuel-switching. 8. Texas, with a population of 25 million people, is small enough to model, but large enough to have significance for the rest of the nation. 9. Texas is the largest electricity producer and consumer in the nation[20], which means that its distribution of power generation assets (in terms of location, fuel, technology type, vintage, etc.) is statistically significant. 10. Texas is one of the few states with growing demand for electricity[20] (because of population growth and economic growth), and so the prospect of making substantial capital investments to change the power systems is less daunting in Texas than elsewhere. (That is, it s much harder to contemplate capital-intensive fuel-switching projects in areas where demand for electricity is flat or declining.) 11. Texas has substantial distribution and storage infrastructure already installed, which means that a significant ramp up of natural gas use is likely to be much less expensive in Texas compared with other regions[20]. 12. Texas has a lot of large coal power plants that are years old and lack modern environmental controls. 2 Thus, plant owners and operators are at a point where they would naturally contemplate whether to extend the life of the power plants (by making multi-hundred million dollar investments in control technologies) or retire the plants to invest in new generation capacity. As these decisions are being made in the current environment, where affordable and stable natural gas prices are expected to continue, this topic is very timely. 13. Texas has an industry-friendly regulatory environment, which sometimes makes it easier to permit, build and expand natural gas infrastructure compared with other states. 3 Given all these factors, and the analytical robustness of examining Texas, our hypothesis is that if increased penetration of natural gas can t be justified on economic and environmental grounds in Texas, then it can t be done anywhere in the US. Thus, the purpose of this analysis is to examine the prospects for increased use of natural gas in Texas, with the expectation that the conditions for the displacement of coal with natural gas are quite good. This report examines reasons why the conditions for increased 2 See Table 4.1 & See Section 3.3 Texas Natural Gas Infrastructure and Economy Natural Gas in Texas, UT Austin,

12 CHAPTER 1. EXECUTIVE SUMMARY natural gas use are favorable in the state and identifies the challenges or barriers that might arise. Furthermore, the takeaways from this analysis for other regions will be discussed, as it is expected that there will be some cross-over lessons to other states and regions after examining Texas as a case study. 1.3 Power Sector Power Increasingly Fueled by Natural Gas The percentage of electricity generation and capacity fueled by natural gas has been steadily increasing in the state for several years, similar to what has been happening nationwide. Many analytical projections suggest this trend is unlikely to change in the near term[23]. In 2006, several large utilities were seeking permits to build 19 new coal-fired electricitygenerating units at fifteen sites throughout the state[9]. Though it made economic sense at the time, by 2009 public sentiment over environmental concerns, potential carbon legislation, and low natural gas prices that had not been widely predicted a few years earlier, led to most all of these proposed plans being scrapped or placed on hold[14]. If new coal plants couldn t be built in 2007 when coal costs were low and gas prices were high, it is even more unlikely now and into the future with forecast of low gas prices and steadily increasing fuel and environmental costs for coal plants Mixed Signals Might Squeeze Out Gas-Fired Generation Although it is just a few years after the proposed slate of new coal plants, today a crosssection of political support exists to consider decommissioning a significant portion of the state s coal-fired generation and replace it with combined cycle natural gas, renewable generation, and energy efficiency[28]. This trend could bring to the fore an interesting relationship between natural gas and renewable sources such as wind and solar. Natural gas electrical generation still has a marginally higher fuel cost than coal generation. Consequently, when wind generated power, which has no fuel cost, is available to the grid, it routinely pushes out natural gas-fired generation first. However, since wind generation is intermittent, there has to be sufficient generation capacity available to replace it when the wind is not blowing, and natural gas has served that role well. Thus, natural gas is both a competitor for wind, and an enabler for wind. As more wind power is brought online, two things happen: 1. Natural gas gets displaced as a generation fuel first, which is bad for natural gas. 2. At the same time, the variability of wind increases the need for firming power, which is good for natural gas. The resulting relationship between wind power and natural gas fired power has, to some degree, complicated investment decisions in deploying new natural gas-fired generation. 4 Natural Gas in Texas, UT Austin, 2012

13 CHAPTER 1. EXECUTIVE SUMMARY These investment decisions are further confounded as utilities analyze the economics of cleaning up their existing coal-fired generation facilities. Utilities in Texas are planning to spend or have recently spent over a billion dollars on their coal-fired facilities to meet current and pending EPA regulations under the Clean Air Act[46]. This combination of mixed signals could lead to reluctance to build new natural gas fired generation. In particular, if utilities invest large sums of money to clean up existing coal-fired facilities, they will then need to continue to operate these plants for decades to recover the cost. This capital lock-in effect could squeeze gas-fired generation out of the fuel mix from the bottom by recapitalized coal-fired generation and from the top by wind power and other renewable sources Incremental Increase in Gas Usage Could Replace 24% of Texas Coal-Fired Generation Our analysis uses a notional target of replacing 4,000 MW of realized capacity (35.4 million MWh of annual generation, assuming a capacity factor of 100%) from coal-fired plants in Texas. Doing so would require roughly 0.23 TCF of natural gas per year (based on a combined cycle natural gas heat rate of 6,700 Btu/KWh). This amount of generation is approximately equal to the total generation of the state s five highest (by rate) CO 2 - emitting coal power plants in It is unlikely that a 0.23 TCF increase (1% of national consumption and 3% of Texas production) in demand would have much influence on the natural gas market (e.g. it won t directly cause price increases or tax existing natural gas infrastructure) especially considering that national demand has varied by 1.5 TCF year to year over the last five years[20]. And yet by capitalizing on the efficiency of modern combined cycle natural gas power plants, this marginal 0.23 TCF of natural gas could replace 24% of the state s 2007 coal-fired generation. In the process, this fuel-switching would yield a variety of economic benefits to producers and environmental impacts to the state (most of which are beneficial such as reduced land disturbance, water use, emissions, etc.). 1.4 Transportation Sector Negligible Natural Gas Used for Transport Texas has a well-developed and expansive highway infrastructure, which is heavily used for commercial transport in the state s agricultural economy; heavy industry in the Dallas- Fort Worth, Houston, San Antonio triangle; and trade with Mexico. The state also has among the nation s largest vehicle fleets, including school buses, city buses, and trash collection trucks. Despite the state s extensive natural gas production and consumption in the industrial, commercial, and residential markets, very little natural gas is used in 4 See Table 4.3 Natural Gas in Texas, UT Austin,

14 CHAPTER 1. EXECUTIVE SUMMARY transportation. In 2009, Texas consumed 2.2 billion cubic feet (BCF) of natural gas for transportation, which is much smaller than the 13 billion consumed in California and the 3.8 billion in New York; Texas is tied for third place nationwide with Arizona[20]. Texas is the second largest state in land area, population, economic output, and highway vehicle miles traveled, and the largest in energy production (oil, gas, and wind) and energy consumption. The fact that Texas ranks as high as third in Compressed Natural Gas (CNG) use for transportation is simply due to the size of the state, as on a per capita basis it s use of CNG for transportation is roughly average compared with other states. The state of Maryland, which has a tiny fraction of Texas population and size and has negligible natural gas production, consumed nearly half as much natural gas for transportation in 2009 as Texas did. The high gross and per capita use in California, New York, Arizona, and Maryland are evidence that those states have different policy frameworks or market forces that are affecting choices among transportation fuels CNG in Transport Reduces Dependence on Foreign Oil and Improves Air Quality Unlike the power sector, for which replacing coal with natural gas is just a substitution of one domestic energy resource for another (and thus the impact on energy imports is negligible), replacing petroleum-derived gasoline and diesel with CNG can reduce petroleum imports without impacting American petroleum production. Just as replacing internal combustion vehicles with electric vehicles replaces gasoline produced from imported petroleum with electricity produced from domestic coal and natural gas, shifting from gasoline or diesel in medium and heavy vehicles to CNG decreases reliance on an imported energy source through expanded use of a domestic one. If we as a nation are serious about reducing our dependence on imported petroleum, CNG use in the transportation sector could be an effective tool for making progress towards that goal. In addition to the benefits derived from the domestic sourcing of natural gas, it also costs less than half as much as gasoline or diesel on an energetic or miles-traveled basis. Even during the July 2008 natural gas price peak, it equated to $1.35 per gasoline gallon equivalent. 5 However, there are significant up-front investment costs for on-board natural gas storage tanks, which makes it difficult to invest the dollars necessary to convert vehicles to run on natural gas. The prospect of low and relatively stable natural gas prices going forward could provide greater certainty in calculating the fiscal viability of transitioning fleet vehicles to run on it. Looming policy imperatives related to tailpipe emissions and energy imports might provide additional financial incentives. Compared to diesel vehicles, natural gas vehicles emit up to 80% less particulate matter, 20 to 40% less carbon monoxide and 10% less volatile organic compounds[12]. Texas already experiences difficulty in achieving air quality standards in the Dallas-Fort Worth, 5 Based on gasoline at 114,000 btu/gal, $4.11/gal and natural gas at $12/MMbtu. This calculation does not take into account potential taxes that may be applied to natural gas use in transportation. 6 Natural Gas in Texas, UT Austin, 2012

15 CHAPTER 1. EXECUTIVE SUMMARY Houston, Austin, and San Antonio areas, regions that also have the highest number of heavy vehicles[35]. Therefore, the prospects of transitioning a large percentage of the heavy fleet vehicles operating in these areas to CNG to alleviate the air quality problem is appealing, but moderated by the cost of the refueling infrastructure that would be required to enable it. Based on our analysis, transitioning 10% of the medium and heavy-duty fleet in the Texas Triangle (Dallas/ Fort-Worth, Houston, San Antonio) to CNG/LNG would require 0.04 TCF of natural gas annually (based on mileage data from 2005). This fuel-switching would equate to 7.5% of the state s total medium and heavy-duty vehicles running on natural gas compared to nation-leading California s 0.5%. The dual benefit of decreased reliance on imported petroleum (enhanced energy security) and reduced emissions (improved air quality) provides overlapping motivations to generate increased market penetration of natural gas use in transportation CNG Increase for Transportation is Feasible But Needs Policy Support Over the course of a decade, it is technically feasible for Texas to significantly surpass California in its use of natural gas for transportation much in the same way it did in wind power generation over the last decade. But doing so might require focused education of light and heavy duty fleet vehicle operators and manufacturers to these benefits and clear signals of support in the form of policies and incentives at the state and federal level to initiate the shift. It would also require significant CNG/LNG fueling infrastructure investments. 1.5 Residential Sector Natural Gas is Common for Heating Water and Homes The residential energy consumption survey (RECS) was last conducted by the US energy information administration in The survey showed that nearly 100% of the 8.5 million residences in Texas are connected to the electrical grid while natural gas lines serve only 5 million homes and another 2.5 million have propane tanks[45]. These numbers are indicative of the large rural population in Texas. Residential natural gas distribution is generally limited to urban areas due to the cost of the piping infrastructure and thus rural populations predominately use on-site propane gas tanks that are serviced by delivery trucks. The ratio of natural gas customers to propane customers, as well as percentage of homes with natural gas, is slowly increasing, as the preponderance of population growth in Texas is urban[51]. End use of natural gas in the residential sector is dominated by water heating (4.4 million homes) and space heating (3.9 million homes)[45]. Other gas appliances include stoves/ovens and clothes dryers, though they are less common than the water heaters Natural Gas in Texas, UT Austin,

16 CHAPTER 1. EXECUTIVE SUMMARY and space heaters. The figures for electricity use in water heating and space heating are 4 million and 5 million homes respectively[45]. Direct use of residential natural gas and propane (60% of which comes from natural gas production) are a form of distributed energy in that the fuel (Natural Gas) is converted from stored chemical energy to thermal energy at the point of use and therefore, enables high efficiency. For typical residential uses such as space heating, water heating, and cooking, the natural gas versions of these appliances are typically 2 times more efficient from a total energy perspective than performing the same services with electricity provided by the grid. For example, a natural gas water heater often operates with 65% site efficiency. An electric water heater might have 90% site efficiency, but is powered by electricity generated at a natural-gas-fired power plant with 40% efficiency. In this case the net efficiency of using natural gas to generate electricity to heat water is about 36% overall, while the net efficiency for using that natural gas instead to directly heat water at the home is 60%[47] Improved Consumer Education Could Increase Natural Gas Use Consumers might not be aware of this difference in energetic performance as government mandated energy efficiency ratings on appliances are based solely on the energy consumed at the point of use. It takes about three times as much source energy (including the energy required to produce and transport natural gas and propane) to deliver a unit of electrical energy to a residence, as does natural gas or propane[47]. Only about one third of the energy of the fuel that is combusted in a fossil fuel power plant is delivered to the consumer as electrical energy, the rest being lost to power plant inefficiency and transmission losses. Consequently, when a consumer shops for an appliance, such as a water heater, they are presented with government certified information that portrays an electric unit as being roughly equal or slightly better than a gas unit when in fact, from an overall energy perspective, the gas unit is superior by as much as a factor of two[20]. Because of this simplistic and inaccurate portrayal of efficiency, many consumers might make their decisions based upon purchase price and operational cost without recognizing the efficiency gains that are possible from direct end-use of natural gas. The combination of more environmentally aware and educated consumers and higher electricity costs due to greenhouse gas legislation or regulation (and perhaps improved energy efficiency labeling) could lead to a significant increase in residential gas use and a commensurate decrease in electricity use. Policies and incentives at the state level could encourage the shift as well Natural Gas Offers Possibility to Live Off-the-Grid Furthermore, there are new residential natural gas appliances on the horizon. One of these allows for standalone electricity generation in the residential and commercial sectors. There is already an established market for residential backup electricity generators. These genwww.webberenergygroup.com/natgas 8 Natural Gas in Texas, UT Austin, 2012

17 CHAPTER 1. EXECUTIVE SUMMARY erators are powered by conventional internal combustion engines, which can be configured to run on a wide variety of fuels such as gasoline, diesel, natural gas, and propane. This market is primarily focused on remote, off grid, applications or restricted to backup power applications for critical service installations (for example hospitals) and in areas prone to grid instability due to weather. Technology advances in fuel cell electrical power devices e.g. the Bloom Box, by Bloom Energy, could lead to affordable, standalone electrical power generation devices for intermittent or even continuous use at the residential level. In addition, micro turbines from companies such as Capstone provide natural gas generated electricity. A natural gas powered, residential, electric fuel cell on the order of 5 kw to provide firming power when operated in conjunction with 3 to 5 kw of solar photovoltaics could eliminate the need for any electricity from the utility grid for a typical moderate- to large-sized Texas home. Future increases in electricity prices, due to environmental concerns mentioned above or other causes for upward price trends, combined with more affordable photovoltaics and natural-gas fueled distributed generation technology could make living off the grid, a viable choice in urban residential settings. A significant shift in this area would requires several decades of gradual adoption, but could have a large effect in the overall efficiency, reliability, and environmental impact of residential energy use Incremental Increase in Natural Gas Used for Water Heaters Could Meaningfully Reduce Coal-Fired Generation Requirements Based on our analysis, if 10% of the residential electric water heaters in Texas (400,000) were to convert to natural gas, it would reduce the state s electricity consumption by 1,360,000 MWh per year or about one half of the 2007 generation of the state s smallest coal-fired plant (Twin Oaks). Such a fuel shift would require 0.01 TCF of additional gas or roughly 0.1% of current Texas dry gas production. Other residential appliances that could be adopted (but were not analyzed here) include clothes dryers, furnaces, refrigerators, home-fueling of natural-gas vehicles and new gas-fired air conditioning systems, all of which could cause important shifts in the types, times, and locations that energy is consumed in Texas. Increased residential use of gas for existing and new applications influenced by environmental concerns and economic realities could be a driving force in the coming decades. The degree to which individual residences expand their use of natural gas will be an important factor in determining whether existing residential gas delivery infrastructure is sufficient to meet future demand. In some cases, existing homes might be limited in their ability to expand their use of natural gas by the size of their service line and pressure regulators. For new construction, it might be prudent to review and possibly change gas line sizing practices in anticipation of increased use in the future. Notably, the use of natural gas in the residential sector typically peaks in the winter season and drops off in the summer, as energy demands shift from space and water heating to electrically powered air condition- Natural Gas in Texas, UT Austin,

18 CHAPTER 1. EXECUTIVE SUMMARY ing. However, if natural gas is used for distributed electricity generation, then the seasonal variations in natural gas demand by the residential sector might be reduced. 1.6 Implications at the National Level Most of the trends identified in the Texas case study also apply at the national level. Natural gas is being proposed as an alternative to coal in the power sector in many states nationwide. For example, Colorado is working with utilities to shut down some coal plants in favor of natural gas plants. 6 The nation as a whole is much more dependent on coal for electricity generation than is Texas and the proximity of the Marcellus and New Albany shale formations to the industrial Northeast and Appalachia, which historically have been heavily dependent upon coal for power generation, could spur a shift to natural gas. Similarly, at the national level, the use of natural gas in the transportation sector mirrors that of Texas much more so than California or New York, which means that it is not used much at all. A major shift towards natural gas use in medium and heavy fleet vehicles could make economic sense for many municipalities (for example with garbage trucks) and trucking services, would be environmentally beneficial, and could yield meaningful reductions in petroleum imports. Increased residential use might be another important opportunity nationwide. Conservation and efficiency gains are the most powerful, and often underutilized, tools in reducing energy use. Viewing natural gas delivered at the residential level as a form of distributed energy isn t common but the analogy holds. Converting fuel to energy as close as possible to the point of use is extremely efficient when the transportation cost (in energy as well as fiscal terms) for the fuel is low, as it is with natural gas. Replacing large electrical loads in the home with natural gas devices can produce 2-fold improvements in overall energy efficiency. Recognizing these opportunities with supportive policies at the state and national levels could significantly improve the overall energy efficiency of the country while also reducing emissions. We believe there are five major public perception roadblocks to achieving the expanded uses of natural gas mentioned here. 1. Environmental concerns that could prevent the full exploitation of shale gas, regarding potential contamination of groundwater in the hydraulic fracturing process or air quality problems stemming from on-site emissions. 2. The reliability and safety of the natural gas pipeline infrastructure that serves the country. Recent explosive leaks of natural gas pipelines have raised awareness of these risks. 6 Colorado HB , Signed into law April Emission reductions are achieved by retiring 551 megawatts (MW) of coal-fired electric generation, controlling 742 MW of coal-fired generation with emission reducing retrofits, and fuel switching 443 MW of coal-fired generation to natural gas Natural Gas in Texas, UT Austin, 2012

19 CHAPTER 1. EXECUTIVE SUMMARY 3. The concern and debate over whether a nontrivial fraction of natural gas is lost to the atmosphere during production, transportation, storage, and end-use, thereby potentially diminishing any greenhouse gas benefits gained through increased use of natural gas due to methane s higher global warming potential. 4. The perception that dependence on any fossil fuel cannot be a long-term solution for achieving goals related to sustainability, energy independence, or greenhouse gas reductions. 5. Finally, and perhaps most difficult to address, is the concern that natural gas prices will continue to be as volatile and/or elevated in the future as they have been in the past. Aside from the metaphysical roadblocks mentioned above, there are physical ones as well. A significant increase in the use of natural gas in any of the three sectors discussed will possibly require an expansion of the country s natural gas distribution and storage system. Such an expansion could trigger the requirement for new and extended pipelines, storage facilities, compressor stations, and refineries. Achieving this expansion requires no new technologies or methods, but it will be necessary to continually improve the reliability and safety of the existing system to mitigate public concern and resistance to the expansions. Likewise, expanded use in the power and transportation sectors will require large capital investments in new generation facilities and vehicles, which, as always, will require taking financial risk. 1.7 Key Conclusion Overall, the conclusion of this analysis, based on the assumptions and calculations explained in the body of the report, is that some fuel-switching from coal to gas in the power sector, from petroleum to gas in the transportation sector, and from electricity to gas in the residential sector, has significant economic and environmental benefits for Texas. While such fuel-switching is not impact-free and is exposed to a different set of economic risks than the current fuel mix, with proper policy incentives and fully-functioning markets, the benefits can be harnessed while the risks minimized. The three examples described here, while having minimal impact on natural gas supply and infrastructure, would have large and meaningful impact in improved energy efficiency, air quality, and energy security. Texas has led the way for the nation in rapid growth of wind energy and is poised and capable of doing the same in natural gas. While this analysis does not consider every scenario and resource option (for example, replacing coal-fired power with renewables or efficiency was explicitly not included in this study), the results are still compelling enough to warrant contemplation by policymakers who wish to address opportunities for economic and environmental benefits through shifts in energy consumption. Natural Gas in Texas, UT Austin,

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21 2 Background and Context Dry natural gas production in the United States has increased over the last five years from 18.5 TCF in 2006 to over 21.5 TCF in 2010[41]. This increase was due in large part to the exploitation of the Barnett Shale in Texas, the Haynesville Shale in Louisiana, and the Marcellus Shale in Pennsylvania. Exploration and production in these large shale gas fields continues to grow. However, because of lingering environmental concerns among the general public about possible contamination of groundwater during the hydraulic fracturing process, the future regulatory environment for natural gas production is unclear. After an era of volatility, natural gas prices have been both low and stable since the summer of 2008, which is likely a function of increases in production and a global recession, which has softened demand growth. The fact that production in the shale fields continues, in spite of low market prices is often due to the fact that gas companies must drill and produce on the sites that they have leased within 4 to 6 years or lose their rights and the large sums they paid for them. This continued production has likely worked in conjunction with weak demand to keep prices low. It is possible that once these leases have been secured through drilling and initial production, gas producers may throttle back production until prices are more favorable. The use of natural gas also has good and bad environmental implications. The extent and nature of the greenhouse gas (GHG) and pollution mitigation measures that will be adopted in the United States are still unclear. While GHG legislation has stalled in Congress, it is possible that that the Environmental Protection Agency (EPA) will pursue regulation under the Clean Air Act. In addition, the EPA might pursue more stringent standards related to other pollutants, which would also affect the role of natural gas as a possible alternative to coal in the power sector. The nature and wording of any such regulation will be critical as even though natural gas is a much cleaner fuel than coal, its potential environmental impacts are non-trivial at the point of extraction, during distribution, and at its end-use. Even though natural gas produces approximately half the CO 2 as coal on a BTU for BTU basis when fully combusted, the primary constituent of natural gas is methane, which has a radiative forcing (or global warming potential, GWP) 20 times greater than CO 2. Much like the concern over groundwater contamination during hydraulic fracturing, there is persistent debate over how much natural gas is lost to the atmosphere during drilling, transportation, storage, and utilization. Thus, it is possible that the net CO 2 -equivalent of fugitive emissions from production wells, storage tanks or pipelines might exceed the benefits derived from carbon avoidance through the combustion of natural gas in the place 13

22 CHAPTER 2. BACKGROUND AND CONTEXT Figure 2.1: Schematic Geology of Natural Gas Resources[20] of other fuels. These losses introduce more uncertainty about the impacts of greenhouse gas legislation and how regulation would affect natural gas production and use. Shale gas formations are not a recent discovery. Their existence and role in conventional gas formations (they are the source rock for many natural gas resources) has been known for decades. What is new is their recent accessibility and productivity due to the combination of two existing, oil field technologies: horizontal drilling and hydraulic fracturing. The combination of horizontal drilling and hydraulic fracturing technologies have caused estimates of the amount of recoverable natural gas in North America to increase more than ten fold in the last decade[57]. As shown in Figure 2.1, the application of horizontal drilling technology has provided a means of accessing the horizontal gas bearing shale formations in a more economic way, while hydraulic fracturing provides a means of creating and holding open millions of tiny fissures in the shale to allow the gas to escape. And while much of the attention has been on the gas shale fields of North America, a recent report by the United States Energy Information Administration (EIA) provides new insight to the amount of technically recoverable natural gas in shale deposits located in 14 other countries. As can be seen in Figure 2.2, North America is not the only continent with significant shale gas formations. To the extent that they were analyzed, it is clear that 14 Natural Gas in Texas, UT Austin, 2012

23 CHAPTER 2. BACKGROUND AND CONTEXT Figure 2.2: Assessment of Shale Gas Resources in Selected Countries, 2010[57] South America, Africa, Europe, Asia, and Australia all have substantial shale gas reserves, which are technically recoverable using the same technologies that are being employed in North America s shale gas fields today. Table 2.1 contrasts the proven natural gas reserves for some countries as of 2009 against their new estimates of technically recoverable shale gas resources. For example, the US had TCF of proven conventional natural gas reserves in 2009, but more recent estimates of the recoverable shale gas are 862 TCF, or approximately 3 times the proven reserves of conventional gas[57]. The totals at the bottom of the table show that the ratio of technically recoverable shale gas to 2009 proven conventional gas reserves for all of the countries surveyed combined are greater than five to one. Furthermore, the combined recoverable shale gas from these countries is equivalent to the 2009 estimates of proven conventional gas reserves of the entire world. As impressive as these numbers are, they only portray part of the global picture. The Middle East and Eurasia account for 75% of the world s proven conventional natural gas reserves[39]. If the six to one ratio in technically recoverable shale gas to 2009 proven conventional gas reserves in the countries analyzed in this study is extended to the rest of the world, global technically recoverable shale gas reserves could be in excess of 36,000 trillion cubic feet. Some bullish gas producers have been suggesting this size for the resource base for decades. Figure 2.3 does not incorporate the data from the 2010 EIA report, but still shows a steady increase in global proven reserves from roughly 60 Trillion Cubic Meters Natural Gas in Texas, UT Austin,

24 CHAPTER 2. BACKGROUND AND CONTEXT Table 2.1: Estimated shale gas technically recoverable resources for select basins in 32 countries, compared to existing reported reserves for 2009[57] Area Proven Natural Gas Reserves 2009 (Trillion Cubic Feet) Technically Recoverable Shale Gas Resources (Trillion Cubic Feet) Percent Increase Europe % North America United States Canada Mexico Subtotal , % Africa , % Asia , % Australia % South America , % Total of Areas 1, , % Total World 6,609 Figure 2.3: Global Natural Gas Proven Reserves and Replacement Ratio[20] 16 Natural Gas in Texas, UT Austin, 2012

25 CHAPTER 2. BACKGROUND AND CONTEXT (tcm) in 1975 to nearly 190 tcm in 2009 as the annual, global reserve replacement ratio has exceeded 100% for each and every year (1 cubic meter is approximately 34 cubic feet, thus the 6,600 TCF for the world in Table 2.1 correlates to the 190 tcm in Figure 2.3). As the new shale reserves identified in the EIA report are codified, this 35-year trend of new reserves outpacing consumption could continue. Natural Gas in Texas, UT Austin,

26

27 3 Texas As A Case Study 3.1 Texas Energy Production and Use Because of the non-uniform impacts and opportunities of natural gas, this study focuses on the state of Texas (Electric Reliability Council of Texas (ERCOT) service area for electrical generation) as a case study. There are several motivations for this geographic focus: 1. Texas is the largest natural gas producing state in the nation. If Texas were a nation (and the United States was without Texas), then Texas would be the world s thirdlargest natural gas producer after Russia and the United States[48]. 2. Texas is the largest natural gas consuming state in the nation. Texas is a major consumer of natural gas for non-power industrial applications such as the chemical sector. In 2006, this demand accounted for 42% of natural gas use in the state while electric power generation consumed 47.7%, commercial use 4.9%, and residential use 5.4%[48]. These uses totaled nearly 3.1 TCF or 61% of the state s dry gas production, while the remaining 39% was piped out of the state[53]. (NOTE: total production has increased from 5.5 TCF in 2006 to 6.5 TCF in 2010, which will change that breakdown of how much is used in-state vs. exported out-of-state[20].) Consumption of natural gas for transportation in Texas is miniscule in comparison to these uses but still totaled 2.2 Bcf (0.1 %of the states consumption) for the year making Texas the third largest consumer, for transportation, in the country behind California and New York[20]. 3. Texas generates a higher-than-average fraction of its electricity from natural gas. In 2010, 57% of ERCOTs generation capacity and 38% of electricity production came from natural gas[49](the Electric Reliability Council of Texas covers 75% of the state geographically and 80% of the population). By contrast, coal provided 45% and natural gas 24% of electricity production nationally in 2010[20]. 4. Texas is the nation s largest consumer of coal, despite being only the nation s 6thlargest producer of coal, which means a substantial amount of coal is imported from other states (primarily from the Powder River Basin in Wyoming). 5. Texas is the largest carbon emitting state in the nation. If Texas were a country, it would be the 7th-largest carbon emitter in the world[40], thus its exposure to 19

28 CHAPTER 3. TEXAS AS A CASE STUDY potential financial liabilities associated with GHG legislation are very relevant. These emissions primarily come from the industrial sector (including power generation). 6. Texas has substantial air quality issues (ozone action days, smog episodes, nonattainment zones, etc.), and therefore has a lot to gain by reducing emissions in the power and transportation sectors. 7. Texas has an independent grid (ERCOT) that covers most of its geographic area and serves most of its population, which means the analysis for the Texas power sector can be isolated from other regions. Furthermore, grid operations within ERCOT are mostly deregulated, which means the interplay of market forces and regulations yield non-obvious possible outcomes for fuel-switching. 8. Texas, with a population of 25 million people, is small enough to model, but large enough to have significance for the rest of the nation. 9. Texas is the largest electricity producer and consumer in the nation[20], which means that its distribution of power generation assets (in terms of location, fuel, technology type, vintage, etc.) is statistically significant. 10. Texas is one of the few states with growing demand for electricity[20] (because of population growth and economic growth), and so the prospect of making substantial capital investments to change the power systems is less daunting in Texas than elsewhere. (That is, it s much harder to contemplate capital-intensive fuel-switching projects in areas where demand for electricity is flat or declining.) 11. Texas has substantial distribution and storage infrastructure already installed, which means that a significant ramp up of natural gas use is likely to be much less expensive in Texas compared with other regions[20]. 12. Texas has a lot of large coal power plants that are years old and lack modern environmental controls. 1 Thus, plant owners and operators are at a point where they would naturally contemplate whether to extend the life of the power plants (by making multi-hundred million dollar investments in control technologies) or retire the plants to invest in new generation capacity. As these decisions are being made in the current environment, where affordable and stable natural gas prices are expected to continue, this topic is very timely. 13. Texas has an industry-friendly regulatory environment, which sometimes makes it easier to permit, build and expand natural gas infrastructure compared with other states. 2 1 See Table 4.1 & See Section 3.3 Texas Natural Gas Infrastructure and Economy 20 Natural Gas in Texas, UT Austin, 2012

29 CHAPTER 3. TEXAS AS A CASE STUDY Texas produces more energy than any other state in the nation. As an example, oil and gas extraction in Texas accounts for 52% of the nation s 2006 GDP in that sector.[36] Since Texas is also the nation s leading industrial state, oil and gas extraction only contributed 14.9% of the state s total economic output in 2006[53]. As shown in Figure 3.1, Texas consumes a far greater portion of energy in the industrial sector than the nation because of the prominence of energy intensive industries. Figure 3.1: Energy Consumption by Sector for Texas and United States, 2008, shows that Texas uses a great deal of energy for industrial processes.[20] Texas is the nation s leading crude oil producer and consequently home to 27 petroleum refineries accounting for more than one quarter of total US refining capacity (capable of processing nearly 5 million barrels of crude oil per day). This dominance is replicated in the natural gas sector with Texas producing nearly 1/3 of the nation s total[43]. However, the production, processing, and transportation of natural gas also consume a great deal of energy. This consumption is particularly true in the oil sector. Refining crude oil into the broad range of petroleum products is very energy intensive, most of it provided by petroleum itself. Figure 3.2 shows that even though crude oil accounts for only 22% of energy production in the state, petroleum products account for nearly half of the state s energy consumption, the difference being driven primarily by use in the petroleum industry and transportation. By contrast, natural gas requires much less energy to convert the product at the wellhead to the final fuel sent out in pipelines for use throughout the state and country. It is also worth noting that although coal accounts for 14% of energy consumption in the state Natural Gas in Texas, UT Austin,

30 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.2: Texas Energy Production and Consumption, by Source While natural gas accounts for more than 2/3 of production it is less than 1/3 of consumption.[20] 22 Natural Gas in Texas, UT Austin, 2012

31 CHAPTER 3. TEXAS AS A CASE STUDY it amounts to only 4.3% of energy production. This mismatch is principally due to the fact that most of the state s coal-fired power plants run on low-sulfur subbituminous coal imported from the Powder River basin of Wyoming[25]. Figure 3.3: A map of Texas energy production, resources, power generation, and transmission shows the state has great diversity and potential.[20] Figure 3.3 provides a graphic depiction of energy production in the state by fuel, electricity production, and renewable energy potential. The concentration of natural gas fired power plants (orange triangles) in the vicinity of Dallas-Fort Worth, San Antonio, and particularly Houston, are indicative of the advantage of placing electrical generation near the population and industrial centers. With the exception of three coal-fired power plants in the Panhandle region of the state, all of the state s coal-fired power plants (black triangles) are located on a loosely Northeast to Southwest line running from the Northeast corner of the state down through San Antonio and Houston. It is not a coincidence that these locations coincide with the state s surface and underground lignite coal mines. Several of these power plants were originally designed to operate on this indigenous fuel, but switched to low-sulfur western subbituminous coal to meet air quality requirements. 3 This map also makes clear the unfortunate location of the state s 3 See Table 4.1 Natural Gas in Texas, UT Austin,

32 CHAPTER 3. TEXAS AS A CASE STUDY premier solar and wind renewable energy potential in the sparsely populated far western and Panhandle regions. 3.2 Texas Electricity Generation (ERCOT) To understand the potential role of natural gas in the power sector in Texas, it is useful to first understand the Texas grid, which is isolated from the other grids nationally and has some operational characteristics that are unique to Texas, including: competitive markets, high penetration of renewable energy, long distances between sources and load centers, and historic dominance of natural gas. The Electric Reliability Council of Texas (ERCOT) is one of the eight independent system operators in North America. Formed in 1970, it is the successor to the Texas Interconnected System, which was formed in 1941 to provide excess generation to industrial loads on the Gulf Coast in support of the special requirements during World War II. ERCOT is also one of nine regional electric reliability councils that operate under the authority of the North American Electric Reliability Corporation (NERC). ERCOTs area of responsibility covers the entire Texas interconnection and encompasses nearly the entire state[25]. Figure 3.4 shows ERCOTs coverage of the state and its segregation (until December 2010) into four zones: West, North, South, and Houston. ERCOT represents 85% of the state s electrical load and 75% of the land area. The electrical grid covering the region includes 40,500 miles of transmission lines and more than 550 generation units[25]. The high-voltage transmission and energy market within the Texas interconnection is operated essentially as a single power system as opposed to a network of cooperative utility companies. ERCOT is also responsible for managing financial settlement for the competitive power market as well as administration of customer switching for the 6.6 million Texas consumers that live in competitive choice areas[25]. Prior to December of 2010, the ERCOT grid operated as a zonal market in controlling generation transfer between zones as depicted in the left side of Figure 3.5. This construct had been in place for about a decade since market deregulation in 2002, but contained market artifacts that caused inefficiencies in the commitment and dispatch of generation. Under the zonal market there were often instances where even though excess generation capacity was available it could not be utilized effectively due to transmission congestion between the zones[25]. On December 1st of 2010, ERCOT transitioned to a nodal market, which featured marginal pricing for generation at more than 8000 nodes; a simplified representation is provided in the right side of Figure 3.5. This transition allowed for a day-ahead energy and ancillary services co-optimized market, a day-ahead and hourly reliability-unit commitment, and congestion revenue rights. The nodal market was designed to improve the grid s ability to efficiently and reliably integrate intermittent resources such as wind and solar generating facilities, as well as produce price signals that would better indicate where 24 Natural Gas in Texas, UT Austin, 2012

33 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.4: ERCOT Coverage and Zones, before Dec 2010, when the market switched to a nodal system.[25] Natural Gas in Texas, UT Austin,

34 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.5: ERCOT Zonal versus Nodal Connection[25] new generation is most needed for minimizing congestion and improving reliability[25]. Another significant, but more gradual, change within the ERCOT grid has been the growth in renewable energy, primarily wind from West Texas. This change in the composition of the state s generation portfolio has had consequences for natural gas fired generation. Spurred by state and federal legislation, Texas has led the nation in installing wind generation over the last several years. Wind capacity totaled more than 9.5 GW in the ERCOT region as of December 2010 and exceeded the state s renewable energy credit program goals 15 years ahead of schedule[25]. On December 11, 2010, wind output in the ERCOT grid was 7.23 GW, which represented nearly 26% of the electrical load on that day[25]. These impressive numbers are somewhat mitigated by the fact that wind generation in Texas peaks in the winter and at night, and thus is generally out-of-phase with the daily and seasonal variations of electrical demand. Still, as shown in Figure 3.6, for the year 2010 as a whole, wind generation accounted for 12% of the state s installed capacity and 8% of generation. Even with the shift to a nodal market, wind generation is often stranded in West Texas due to congestion in transmission lines. The growth in wind generation has slowed over the last several years but might pick up when several new transmission lines, including the CREZ (Competitive Renewable Energy Zones) project, to the Dallas-Fort Worth and San Antonio regions are completed over the next few years. Figure 3.6 also highlights the disparity between the fuel mix that comprises the installed capacity and the fuel mix that is used to generate power. In the case of both nuclear and coal, their relative contribution to energy production is approximately twice their share of installed capacity, which is a consequence of their high operational capacity factors. The two nuclear plants (each with two electrical generators apiece) in Texas (Comanche 26 Natural Gas in Texas, UT Austin, 2012

35 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.6: ERCOT Installed Capacity and Generation for 2010 shows excess natural gas capacity that is underutilized and relatively low capacity factors for wind.[44] Peak near Dallas-Fort Worth, and the South Texas Project, located south of Houston) historically operate near or in excess of 90% capacity. Coal-fired power plants in the state operate with capacity factors in the range of 75% to 85%.[32] The majority of coal plant unavailability is due to annual maintenance, which is scheduled in the spring and fall to correlate with minimum electrical demand, though there are some hours of the year when demand is low and wind production is high that coal production is reduced. This periodicity can be seen in Figure 3.7, which graphically portrays the annual variation between installed capacity and available capacity within ERCOT for Planned maintenance is not the only reason for de-rating of power plants. They are also taken off line for economic reasons such as high fuel prices, and, in the case of wind and solar, idled for lack of fuel when wind is insufficient or too strong and when the sun is down or obscured. The Texas Electricity market is mature and well developed but also poised for change. Deregulation and nearly a decade of fine tuning of the market, through ERCOT market controls, have set the table for the industry to more freely respond to market signals in fuel prices, federal emission regulations, and regional variations in electricity demand and growth. 3.3 Texas Natural Gas Infrastructure and Economy Replicating the trend shown in Figure 2.3, both natural gas production and natural gas reserves in Texas have grown steadily over the last decade. As shown in Figure 3.8, proven natural gas reserves in Texas increased 80% from 2000 to Natural Gas in Texas, UT Austin,

36 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.7: ERCOT Generation Short and Long-Term Deratings for 2009 show seasonal variability because of maintenance etc.[49] 28 Natural Gas in Texas, UT Austin, 2012

37 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.8: Texas Natural Gas Proven Reserves ( ) have increased dramatically due to new production techniques.[20] Natural Gas in Texas, UT Austin,

38 CHAPTER 3. TEXAS AS A CASE STUDY Natural gas exploration and drilling continues at a steady pace in Texas. With new fields drilled in 2009 and 2010 it is anticipated that the state s proven reserves have increased by 100% over the last decade[43]. As of 2011, Texas had 18% of the nation s producing gas wells and accounted for approximately 30% of the nation s natural gas supply[43]. Much of this growth is due to horizontal drilling and hydraulic fracturing in Texas shale gas fields. The most prominent of these fields are: the Barnett Shale, the Haynesville field, the Eagle Ford field, and the Permian field. All four fields have proven highly productive. Between 2004 and 2009 the Barnett Shale exhibited a greater than 400% increase in gas production (Figure 3.9). Figure 3.9: Barnett Shale Field Production ( ) has grown exponentially.[43] Even though production has increased in the formation, its proven reserves grew by more than 4 TCF in Similarly, the Haynesville field increases production 12 fold while also increasing its reserves by 9.4 TCF. These two fields combined accounted for nearly half of the nation s net increase in reserves for the year For that same year, total natural gas production in Texas was 6.8 TCF. The next largest producer by state was Wyoming with 2.3 TCF. U.S. total for the year including offshore production was 21.6 TCF[41]. This large increase in proven reserves and production in Texas has been matched by the state s 30 Natural Gas in Texas, UT Austin, 2012

39 CHAPTER 3. TEXAS AS A CASE STUDY increase in exports to other states, which have doubled since 2002 (Figure 3.10). Figure 3.10: Texas Natural Gas Exports ( ) have grown due to increased production.[20] In spite of this large increase in production over the last decade, natural gas prices in the United States have continued to fluctuate erratically over the same time period, from as low as $3 to over $12 per thousand cubic feet (Figure 3.11). Though experiencing a good deal of instability over the last decade, the market and forecast prices have been sufficient to support continued exploration and drilling in Texas. The exploitation of the Barnett, Haynesville, and Eagle Ford shales has also contributed significantly to the economic robustness of the Texas natural gas industry. The state s long history and unmatched depth of experience in the oil and gas industry is perhaps responsible for the lower level of public attention over hydraulic fracturing as compared with states such as New Jersey, New York, and Pennsylvania. This difference may be bolstered by a bill, signed into Texas law in 2011, that requires the public disclosure of chemicals used in the state for hydraulic fracturing. Texas has a vast network of natural gas pipelines for collection and distribution within the state as well as for export out of the state. Of the 58,600 miles of natural gas pipeline in Texas, 45,000 are for intrastate transfer[34]. The intrastate network has expanded consid- Natural Gas in Texas, UT Austin,

40 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.11: Monthly US Natural Gas Prices ( ) show a lot of volatility.[20] erably over the last decade to accommodate increased production from the Barnett shale formation. The two largest intrastate pipeline networks are operated by Enterprise Texas Pipeline Company with 8,750 miles and Energy Transfer Partners LP with 8,800 miles[34]. As can be seen in Figure 3.12, the state s intrastate pipeline network geographically reflects the primary sources and principal points of consumption. In contrast with the federal process for constructing an interstate natural gas pipeline, constructing an intrastate pipeline in Texas is much easier. The Texas Railroad Commission (TRRC) regulates the oil and gas industry in the state and does not require a pipeline company, operating as a designated Public Utility, to obtain formal permission from the state. The key is the Public Utility designation that allows the company to construct pipelines under general state law. As such, government oversight only comes into play if problems are encountered. Some permitting is required from other state agencies such as the General Land Office, Texas Department of Transportation, Texas Parks and Wildlife Department, or the Texas Commission on Environmental Quality, in instances where the pipeline crosses waterways, roads, or areas out of compliance with the Clean Air Act. The powers granted to these designated Public Utilities under state law include the authority of eminent domain, should right-of-way negotiations with landowners reach an impasse. For any new intrastate pipeline construction, the TRRC requires submission of details of the project such as, but not limited to: the proposed origination and termination points, the counties to be traversed, size and type of pipe to be used, design pressure and length, and service type. For pipelines over five miles, the TRRC will conduct inspections to ensure the quality of the pipelines welded joints. Other than this, the TRRC s jurisdiction is limited to safety issues. 4 The combination of: an extensive existing natural gas distribution infrastructure, broad as well as deep industry knowledge and expertise, growing natural gas supply, the potential 4 16 Tex. Admin. Code (2004) Texas Railroad Commission, New Pipeline Construction Natural Gas in Texas, UT Austin, 2012

41 CHAPTER 3. TEXAS AS A CASE STUDY Figure 3.12: Texas Intrastate Natural Gas Pipeline Network is Extensive.[20] for increased commercial and private consumption, and favorable regulatory and economic environment, make the potential for increased use of natural gas in Texas very favorable. As stated before, if it can t be done in Texas, it likely won t happen anywhere in the US. Natural Gas in Texas, UT Austin,

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43 4 Natural Gas in the Power Sector 4.1 Environmental Considerations In 2006, the state of Texas generated 400 million Megawatt-hours (MWh) of electricity within the ERCOT grid. The mix of sources for this electricity was 36% coal, 49% natural gas, 10% nuclear, 2% renewable and 3% assorted others.[53] Since that time, wind generation has increased substantially and natural gas generation has decreased (see Figure 3.6). 1 This heavy reliance on fossil fuels for electricity generation further exacerbates the considerable amount of emissions generated within the state through energy intensive industrial facilities such as petroleum refineries, chemical plants, aluminum smelters, and cement plants. Of the two primary fossil fuels used for electricity generation, natural gas provides opportunities for improved air quality, water conservation, and economic development. For example, coal produces more pollutants when burned than natural gas[20]. On average, coal plants produce twice the CO 2 and nine times the nitrogen oxides (NO x ) as natural gas. In addition, they emit significant volumes of sulfur oxides (SO 2 ), lead, mercury, and particulate matter, which are almost completely absent when burning natural gas. Additionally, modern natural gas combined cycle (NGCC) power plants are significantly more energy-efficient than conventional coal plants[20]. There is also a compounding effect in areas of the state where older, and less efficient (and therefore dirtier) coal plants are located in the same air quality non-attainment areas as some of the aforementioned industrial facilities, including Dallas-Fort Worth, Houston-Galveston-Brazoria, and Beaumont-Port Arthur (Figure 4.1).[3] Thus, shutting down these older, dirtier, less efficient coal plants in favor of newer, cleaner, more efficient natural gas combined cycle plants could save energy while reducing emissions in areas that are prone to air quality problems. Water also plays an important role in power plants. For example, nuclear and coal generation facilities require large amounts of water for cooling. NGCC plants use significantly less water in the process of generating electricity. In a water resource constrained state such as Texas, lessening the burden placed on this scarce resource would be beneficial. Finally, approximately two thirds of the coal consumed for electricity generation in Texas comes from outside the state, which means that more than a billion dollars is sent to out of state coal mines each year.[6] 1 This was partly due to the combination of flat overall electricity demand since 2008 and the continued expansion of wind generation capacity. Because natural gas generation is the marginal generation source, it is then pushed out of the mix first. 35

44 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Figure 4.1: Texas Nonattainment Areas[35] 36 Natural Gas in Texas, UT Austin, 2012

45 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR This situation is in contrast to natural gas, which is principally a local resource that provides economic activity and tax revenue to the state when it is produced. Natural gas production in Texas is levied with a severance tax of 7.5 percent of value.[24] In this tax generated $1.3 billion in revenue for the state. 2 Consequently, in addition to the greater net energy efficiency obtained by utilizing a local fuel resource, there are economic benefits. This analysis looks at these three principal factors: air emissions, water use, and economic impact in assessing the ramifications of decommissioning 4,000 Megawatts (MW) of coal generation assets in favor of NGCC. As of December 31, 2008, Texas had 18 major coal fired power plants feeding into the ERCOT electrical grid with a total generation capacity of 21,000 MW as shown in Table 4.1. Most of these plants were built and / or expanded from and have an average age of 30 years.[41] This plant demographic is the result of a combination of events including the Powerplant and Industrial Fuel Use Act of 1978, which prohibited the construction of new natural gas fired plants, and the attempts of utilities to diversify their generation portfolio to minimize exposure to fuel price swings. The plants typically burn either Subbituminous or Lignite coal as their principal fuel though some have one of the coal types as their principal fuel with the other as a back-up and a few burn a varying mix of the two. Several plants have Natural Gas or Distillate Fuel Oil available as a secondary fuel, while a few have no secondary fuel (See Table 4.1). The amount and characterization of annual emissions from fossil fuel power plants is based on the total amount of power generated, the efficiency of the plant, whether or not emissions control technologies are in place, and the type of fuel burned. Coal is commonly referred to as a dirty fuel source and, in relative terms, it is. While natural gas plants on average are cleaner than coal plants, it is important to note that old natural gas plants can be dirtier than newer coal plants, and old natural gas plants can be dirtier than old coal plants, too. Table 4.2 lists all of the Texas coal plants in descending order of their total generation for calendar year 2007[33]. It is clear that with very little deviation, the plants that produce the most electricity also produce the most CO 2 emissions as one would expect. A more useful means for evaluating which plants are the dirtiest, is to rank the plants by the amount of emissions generated per unit of electricity produced. Table 4.3 lists the same power plants in descending order based on the pounds of CO 2 generated per MWh of electricity produced.[33] It is clear from the table that this ranking is consistent for CO 2 rate and is highly correlated (ρ= 0.94) with the efficiency of the plant as shown by the Nominal heat rate (Number of Btus required to generate a KWh of electricity; a lower number represents a more efficient plant). It is also telling, but to be expected, that with two exceptions (JT Deely and Monticello), the eight plants with the highest emissions rates are all burning the lower heat content 2 For comparison, the revenue for the same period for oil production (levied at 4.6 percent of value) and oil regulation (levied at 3/16th of one cent per barrel) generated a combined $2 billion. Natural Gas in Texas, UT Austin,

46 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.1: Texas Coal Plants (2007) SUB = Subbituminous Coal, LIG = Lignite, NG = Natural Gas, DFO = Distillate Fuel Oil[33] Plant Name County Units Nameplate Capacity (Megawatts) Primary Energy Source Secondary Energy Source Initial Operation Welsh Titus SUB W A Parish Fort Bend SUB NG Twin Oaks Robertson LIG NG Tolk Lamb SUB NG Sandow 4 Milam LIG DFO 1981 San Miguel Atascosa LIG 1982 Pirkey Harrison LIG SUB 1985 Oklaunion Wilbarger SUB 1986 Monticello Titus LIG SUB Martin Lake Rusk LIG SUB Limestone Limestone LIG SUB J T Deely Bexar SUB NG J K Spruce Bexar SUB NG 1992 Harrington Potter SUB NG Gibbons Creek Grimes SUB 1983 Fayette Project Fayette SUB DFO Coleto Creek Goliad SUB 1980 Big Brown Freestone LIG SUB Total Capacity Average IO Natural Gas in Texas, UT Austin, 2012

47 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.2: Texas Coal Plants Ranked by Net Generation (2007) SUB = Subbituminous Coal, LIG = Lignite[33] Plant Name Primary Fuel Capacity Factor Nameplate Capacity (Megawatts) Annual Net Generation (MWh) Annual NO x Emissions (tons) Annual SO 2 Emissions (tons) Annual CO 2 Emissions (tons) W A Parish SUB ,697 20,068,090 4,720 57,804 20,949,866 Martin Lake LIG ,380 18,073,888 15,921 79,038 21,821,564 Monticello SUB ,980 15,399,000 14,567 74,350 18,300,186 Limestone LIG ,850 13,592,152 12,868 14,677 14,223,953 Fayette Project SUB ,690 12,144,361 6,982 33,186 13,297,420 Welsh SUB ,674 10,504,719 9,932 26,413 11,798,412 Big Brown LIG ,187 8,548,875 6,628 76,798 9,956,682 Harrington SUB ,080 7,307,731 9,935 19,191 8,265,848 Tolk SUB ,136 7,168,185 8,219 18,873 7,638,638 J T Deely SUB ,320,426 4,770 23,535 7,682,305 Pirkey LIG ,824,785 4,450 1,953 5,738,749 Sandow 4 LIG ,454,230 4,890 23,365 5,413,397 Coleto Creek SUB ,217,795 3,134 14,274 4,384,926 Oklaunion SUB ,205,893 7,682 4,385 4,555,053 J K Spruce SUB ,107,151 2,914 3,394 4,560,391 Gibbons Creek SUB ,442,748 2,267 11,386 3,524,022 San Miguel LIG ,713,947 3,140 8,369 3,589,409 Twin Oaks LIG ,316,023 1,916 4,564 2,738,265 Natural Gas in Texas, UT Austin,

48 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.3: Texas Coal Plants Ranked by CO 2 Emission Rate (2007)[33] Plant Name Primary Fuel Capacity Factor Nameplate Capacity (Megawatts) Annual Net Generation (MWh) Annual NO x Emission Rate (lbs/mwh) Annual SO 2 Emission Rate (lbs/mwh) Annual CO 2 Emission Rate (lbs/mwh) Nominal Heat Rate (Btu/KWh) J T Deely SUB ,320, ,888 14,073 San Miguel LIG ,713, ,645 12,148 Sandow 4 LIG ,454, ,431 11,163 Martin Lake LIG ,380 18,073, ,415 11,090 Pirkey LIG ,824, ,379 10,925 Monticello SUB ,980 15,399, ,377 10,916 Twin Oaks LIG ,316, ,365 10,860 Big Brown LIG ,187 8,548, ,329 10,698 Harrington SUB ,080 7,307, ,262 11,204 Welsh SUB ,674 10,504, ,246 10,947 J K Spruce SUB ,107, ,221 10,822 Fayette Project SUB ,690 12,144, ,190 10,679 Oklaunion SUB ,205, ,166 10,582 Tolk SUB ,136 7,168, ,131 10,386 Limestone LIG ,850 13,592, ,093 9,612 W A Parish SUB ,697 20,068, ,088 10,382 Coleto Creek SUB ,217, ,079 10,133 Gibbons Creek SUB ,442, ,047 9, Natural Gas in Texas, UT Austin, 2012

49 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR lignite as their primary fuel. The two exceptions to this are principally explained by the fact that JT Deely and Monticello are two of the oldest plants in the state. As such, even though they are burning higher heat content Subbituminous coal, this advantage is likely overridden by the fact that they are based on significantly older and less efficient designs (see Table 4.1). Another important metric reflected in Tables 4.2 and 4.3 is plant capacity factor for the year. Accounting for planned outages to perform routine maintenance and unplanned outages for equipment casualties, coal plants on average have a historical maximum operational availability approaching 80-90%[48] However, the national annual average for the last ten years has varied between 64-74% (nuclear plants during the same period were 79-92%).[41] Coal power plants in Texas, like nuclear plants, provide base load power to the grid. Capacity factor is, therefore, an important metric because it serves as a proxy for operating costs, fuel costs, wholesale electricity price, etc., and can be an indicator of the economic viability of the plant as compared to its neighbors within its service region amidst the constantly changing electricity market. The capacity factors in Tables 4.2 and 4.3 also show that removing a given amount of nameplate capacity at different plants can have different effects on production. As an example, W.A. Parish at 2,697 MW of nameplate capacity is the largest plant in Texas. But for 2007, it operated at a capacity factor of only 58% or two thirds of its theoretical maximum. Decommissioning 500 MW of its nameplate generation capacity (18% of its total) could potentially have zero effect on emissions as the plant could still have produced the same number of MWh (and emissions) for the year simply by operating the remaining generation capacity at a higher capacity factor. 3 Consequently, if the primary goal is to reduce emissions, the plants with the highest emission rates should be retired preferentially and in sufficient quantity to account for 4,000 MW of realized generation capacity (the product of capacity factor and generation capacity) as opposed to just 4,000 MW of nameplate capacity or generation potential. Table 4.4 illustrates one example of how to retire approximately 4,000 MW of realized generation and the gross associated emissions savings. In this example, the five highest rate emitters (as shown in Table 4.3) had a combined realized generation capacity of 4,040 MW. While removing capacity listed in Table 4.4 would cause a significant reduction in emissions, the 4,000 MW of realized generation capacity and 35.4 million MWh of net generation removed represent 22% and 24% of coal powered nameplate capacity and net generation respectively for NO x, SO 2, CO 2, and CO 2 equivalent emissions are not the only emissions concerns: Coal-fired power plants also emit substantial quantities of particulate matter, mercury and lead. These are not highlighted in the tables presented here simply for the sake of brevity, as they are very closely correlated with CO 2 emissions rate and 3 As a simpler example, a plant capable of producing 4,000 MW but only operating 50% of the time produces the same amount of energy as a plant producing 3,000 MW that operates 75% of the time. Natural Gas in Texas, UT Austin,

50 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.4: Five Highest Rate Emitters (2007)[33] Plant Name Primary Fuel Capacity Factor Nameplate Capacity (Megawatts) Realized Generation Capacity (Megawatts) Annual Net Generation (MWh) Annual NO x Emissions (tons) Annual SO 2 Emissions (tons) Annual CO 2 Emissions (tons) J T Deely SUB ,320,426 4,770 23,535 7,682,305 San Miguel LIG ,713,947 3,140 8,369 3,589,409 Sandow 4 LIG ,454,230 4,890 23,365 5,413,397 Martin Lake LIG ,380 2,063 18,073,888 15,921 79,038 21,821,564 Pirkey LIG ,824,785 4,450 1,953 5,738,749 Total 5,033 4,040 35,387,276 33, ,261 44,245,424 heat rate and as such, do not change the overall rankings of the plants.[29] Coal power plants operate on a closed steam cycle that requires a cooling source to condense the steam back into water once it has expanded through the steam-driven electrical turbine. The power plants in Texas achieve this cooling through one of two means: once through (open-loop systems) or a cooling tower (closed-loop systems), and use either ground water, surface water, lake water, or recycled (reuse) water. There are numerous variations on the environmental impact of different combinations of cooling method and water source but this analysis will look only at the amount of water consumed (lost to evaporation and therefore unavailable for other uses) by each plant per unit of electricity generated at the point of the power plant in comparison with the average consumed for a combined cycle natural gas plant. Table 4.5 lists the plants in descending order by the number of gallons of cooling water consumed per KWh of electricity produced.[19] Similar to the analysis in the emissions section, this listing provides a clearer picture of the water intensity of a given plant or, conversely, how efficiently it uses cooling water. Modern NGCC power plants also use a closed cycle steam loop to generate additional electricity after the initial gas turbine is used. This combination is achieved by extracting heat from the exhaust gas produced in the primary gas turbine generator. In Texas, the average amount of water consumed per KWh of electricity produced in these plants, when using cooling towers, is 0.23 gallons[11]. With the exception of the statistical outlier Gibbons Creek (four times higher than the norm), the average for Texas coal plants in Table 4.5 is 0.51, or roughly twice that required of natural gas combined cycle plants. The spread from highest consumption rate to lowest is significant, ranging from 0.22 to 0.88 gal/kwh (again excluding Gibbons Creek). Table 4.6 combines the emissions data from Table 4.4 and the water consumption data from Table 4.5 to highlight the fact that JT Deely, San Miguel, and Pirkey, three of the highest emissions rate plants, are also 42 Natural Gas in Texas, UT Austin, 2012

51 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.5: Texas Coal Plant Cooling Water Source, Method, and Consumption Rates[11] Plant Name Primary Fuel Nameplate Capacity (Megawatts) Annual Net Generation (MWh) Cooling Water Source Water Consumption Rate (Gal/KWh) Water Consumption (Acre- Ft/Year) Gibbons Creek SUB 454 3,611,068 Once Through Lake ,589 Pirkey LIG 721 4,501,460 Once Through Lake ,157 San Miguel LIG 410 2,937,194 Cooling Tower Groundwater ,842 J K Spruce SUB 566 4,040,787 Once Through Reuse ,805 J T Deely SUB 932 5,502,734 Once Through Reuse ,990 Harrington SUB 1,080 7,623,174 Cooling Tower Reuse ,207 Twin Oaks LIG 349 2,351,664 Cooling Tower Groundwater ,258 Welsh SUB 1,674 10,035,850 Once Through Lake ,939 Tolk SUB 1,136 7,342,494 Cooling Tower Groundwater ,168 W A Parish SUB 2,697 20,178,794 Cooling Tower Lake ,582 Limestone LIG 1,706 12,709,534 Cooling Tower Surface ,822 Coleto Creek SUB 600 5,240,154 Once Through Lake ,789 Oklaunion SUB 720 3,964,478 Cooling Tower Surface ,380 Martin Lake LIG 2,380 17,821,177 Once Through Lake ,689 Fayette Project SUB 1,690 10,000,368 Once Through Lake ,741 Sandow 4 LIG 591 3,878,580 Once Through Lake ,166 Big Brown LIG 1,187 8,911,676 Once Through Lake ,931 Monticello SUB 1,980 14,961,282 Once Through Lake ,101 Natural Gas in Texas, UT Austin,

52 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.6: Texas Coal Plants Ranked by Emission Rate, with Water Data[11] Plant Name Fuel Nameplate Capacity (Megawatts) Annual Net Generation (MWh) Cooling Water Source Water Use Rate (Gal/KWh) Annual CO 2 Emission Rate (lbs/mwh) Nominal Rate (Btu/KWh) J T Deely SUB 932 5,502,734 Once Through Reuse ,888 14,073 San Miguel LIG 410 2,937,194 Cooling Tower Ground ,645 12,148 Sandow 4 LIG 591 3,878,580 Once Through Lake ,431 11,163 Martin Lake LIG 2,380 17,821,177 Once Through Lake ,415 11,090 Pirkey LIG 721 4,501,460 Once Through Lake ,379 10,925 Monticello SUB 1,980 14,961,282 Once Through Lake ,377 10,916 Twin Oaks LIG 349 2,351,664 Cooling Tower Ground ,365 10,860 Big Brown LIG 1,187 8,911,676 Once Through Lake ,329 10,698 Harrington SUB 1,080 7,623,174 Cooling Tower Reuse ,262 11,204 Welsh SUB 1,674 10,035,850 Once Through Lake ,246 10,947 J K Spruce SUB 566 4,040,787 Once Through Reuse ,221 10,822 Fayette Project SUB 1,690 10,000,368 Once Through Lake ,190 10,679 Oklaunion SUB 720 3,964,478 Cooling Tower Surface ,166 10,582 Tolk SUB 1,136 7,342,494 Cooling Tower Ground ,131 10,386 Limestone LIG 1,706 12,709,534 Cooling Tower Surface ,093 9,612 W A Parish SUB 2,697 20,178,794 Cooling Tower Lake ,088 10,382 Coleto Creek SUB 600 5,240,154 Once Through Lake ,079 10,133 Gibbons Creek SUB 454 3,611,068 Once Through Lake ,047 9, Natural Gas in Texas, UT Austin, 2012

53 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR three of the highest rate water consumers. The water use rate metric shows that with the exception of Monticello and Big Brown, which rival combined cycle natural gas plants for efficiency of water use, replacing any of the other plants with combined cycle plants would yield significant water savings at the point of use. 4.2 Economic Considerations At the macro-level, utilizing fuel of Texas origin can benefit the state in several ways. The production of lignite coal and natural gas both support jobs (and their associated revenue base) to the benefit of the state s citizens. Additionally, natural gas produced in Texas generates state tax revenue of $0.075 per dollar of market value (coal production revenue is not taxed in Texas). Coal imported to Texas produces few if any direct jobs within the state and represents a net outflow of jobs if that coal could otherwise have been mined within the state. But, replacing out of state Subbituminous coal with Texas Lignite coal might not be feasible, sustainable, or environmentally desirable. This study is simplistic in that it only looks at the impact of shifting 4,000 MW of realized generation from coal to natural gas without respect to whether the fuel for coal and natural gas plants originate within the state or come from outside. In addition, this analysis is restricted to point-of-use, and thus does not include impacts at other points of the lifecycle of extraction, production, storage and transport. Selectively retiring a significant portion of the state s coal-fired electrical generation capacity could have several potential impacts but, in a deregulated market, these impacts are hard to predict with any certainty. In the example given in Table 4.4, the emissions eliminated by retiring the plants listed are assumed to be known with certainty. The type of generation that the market would respond with to replace this lost generation, however, is not. The 35 million MWh that would have to be generated over the course of a year to replace the retired capacity could potentially be provided by NGCC, but could also be provided by a combination of sources. As all of the retired capacity is base load, other coal plants (possibly the more efficient ones in the statewide fleet) could be operated at a higher capacity factor to make up some of the difference. This adjustment could still be beneficial from an emissions perspective as they would be cleaner coal plants, but those emissions savings would be marginal, and might result in a net increase in the importation of Subbituminous coal. Some of the capacity might also be replaced with additional wind power being built over the next few years and from existing wind power that will operate at higher capacity once new transmission lines are built. Some shuttered coal production could be replaced with the several dozen MW of solar generation under construction around the state. Conservation and energy efficiency programs could reduce the amount of capacity that needs to be replaced. And finally, a significant portion could be replaced with natural gas fired generation. In the summer of 2010 ERCOT had a net internal demand of 62,412 MW and capacity Natural Gas in Texas, UT Austin,

54 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Table 4.7: Net Environmental Effect of Displacing Coal Plants from Table 4.4 with NGCC Type Nameplate Capacity (MW) Realized Generation Capacity (MW) Annual Net Generation (MWh) Annual NO x Emissions (tons) Annual SO 2 Emissions (tons) Annual CO 2 Emissions (tons) Annual Water Consumption (Acre-Ft) Total,Table 4.4 5,033 4,040 35,387,276 33, ,261 44,245,424 70,383 Total, 5 GW NGCC 5,000 4,000 35,040,000 4, ,370,780 24,733 Net Savings, NGCC 28, ,189 29,874,644 45,650 resources of 75,181 MW for a calculated reserve of 17%.[31] This margin represents a worst-case situation, as summer demand is the highest. Removing 5,000 MW of nameplate capacity (4,000 MW of realized capacity), as postulated in the Table 4.4 example would have reduced the summer margin in 2010 to 12%. This level is slightly below the 13.75% minimum reserve margin target approved by the ERCOT Board of Directors in Retirement or mothballing of several thousand MW of the state s highest rate emitting coal-fired power plants could yield a net reduction of emissions due to electrical power generation as noted before. It is not possible to determine how and to what extent the market would respond to replace this generation capacity, but if the displaced capacity is replaced with NGCC, then emissions and water use would go down, as summarized in Table A variety of scenarios could be analyzed to determine the reduction based on which plants would be retired and what sources would be utilized to replace the lost generation. It is not a foregone conclusion that coal fired generation will be replaced with combined cycle gas generation in Texas in the near future. In fact, an analysis released in May 2011 by ERCOT Review of Potential Impacts of Proposed Environmental Regulations on the ERCOT System concluded just the opposite. The analysis was instigated by potential rule changes in: Clean Water Act section 316(b) regarding new requirements for cooling water intake structures Clean Air Act new emission limits for Hazardous Air Pollutants (HAP) Clean Air Transport Rule (CATR) Coal Combustion Residuals (CCR) disposal regulations. 4 NGCC numbers based on an existing 830MW NGCC plant operating in Texas with a heat rate of 6,901 (Tenaska Frontier) Natural Gas in Texas, UT Austin, 2012

55 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR ERCOT began the study in January of 2011 and drew information from discussions with environmental experts, several generating entities in the ERCOT region, and published studies on the nationwide impacts of the proposed regulations. The analysis used a rulesbased approach that determined which generating units would have sufficient market value under the new regulations to continue operations. Those that did not were identified as candidates for retirement even if the action would cause reserve margin in their load region to drop below the minimum peak load reserve margin target. The analysis indicated that coal generation in ERCOT would maintain enough market value to justify investing in the environmental controls that would be necessary to meet the new regulations. However, older natural gas fired steam units would require a degree of retrofit that would make them unprofitable. The majority of these plants are less efficient and less flexible than newer gas-fired generation. Consequently, it would be much more profitable for their owners to retire them and replace them with new combined cycle plants that are cleaner and more efficient. The study predicted that over 8000 MW of gas-fired generation would be retired due to the requirement of closed loop cooling towers to comply with changes to section 316(b) of the Clean Water Act. As can be seen in Figure 4.2, (Black triangles represent coal-fired units, inverted orange triangles gas-fired units) there are numerous gas-fired units located in and around the urban centers of Dallas-Fort Worth and Houston. The majority of the units identified as candidates for retirement are in these two areas. The study also determined that, without replacement, the retirement of these units could reduce generation reserve margins, during peak periods, to below 2% by That proposed changes to EPA regulations could result in extending the lives and increasing the use of coal-fired plants while pushing older natural gas-fired units out of the mix is an excellent example of the potential for unintended consequences of regulatory actions. These older gas units often produce as much CO 2 per megawatt hour of generation as do coal-fired units. The ERCOT analysis also reinforces that coal-fired generation is still more economical (for existing units) than natural gas, at today s prices and within today s regulatory environment. Thus, even with low gas prices, it is uncertain whether many coal-fired generation units in Texas will be retired. An excellent example of the decisions faced by utilities with regards to coal-fired units are reflected in the recent fates of the Fayette Power Project (FPP) operated by the Lower Colorado River Authority (LCRA) and the J.T. Deely plant operated by CPS Energy of San Antonio. LCRA s FPP consists of three coal fired generation units. Units one and two were completed in 1979 and 1980 respectively and are each capable of generating approximately 600 MW. The third unit was completed in 1988 and has a net generation capacity of 445 MW. The third unit was built with an SO 2 scrubber system but the first two, which are jointly owned by LCRA and Austin Energy, were not. In 2002, LCRA and Austin Energy made a joint decision to install scrubbers on units one and two. Installation was completed in 2010 at a total cost of approximately $450 million, which is roughly equivalent to the total original cost of the third unit (in nominal dollars). All three units burn low sulfur coal from the Powder River Basin mines of Wyoming.[13] Natural Gas in Texas, UT Austin,

56 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Figure 4.2: Texas Energy Map[20] 48 Natural Gas in Texas, UT Austin, 2012

57 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR CPS Energy s J.T. Deely plant has two generation units. The first has a generation capacity of 486 MW and was completed in 1977, the second has a capacity of 446 MW and came online in Neither unit incorporates SO 2 scrubbing. Faced with having to comply with ever more stringent emissions regulations, in June of 2011, CPS announced that the plant would be shut down in 2018 rather than invest the estimated $500 million necessary to install SO 2 scrubbing systems on the two units. CPS has announced that they will pay a premium for the lowest possible sulfur content coal from the Powder River basin of Wyoming and attempt to minimize the Deely plant s SO 2 emissions until it is shut down in 2018.[4] Units one and two at FPP commissioned in 1979 and 1980 are of roughly the same technology generation as Deely s two units commissioned in 1977 and However, LCRA and Austin Energy in 2002 made the exact opposite decision as CPS in Part of the reason for the difference in recommendation can be traced to changes in the Texas energy market in the nine years between the two decisions. In ERCOT s 2009 State of the Market Report (SOMR), the report s creator, Potomac Economics, LTD, estimated the net revenue that would have been generated in the Houston, North, and South, ERCOT regions for four types of generation units: combined cycle natural gas (CC), simple cycle gas turbine (CT), coal-fired, and nuclear. The results for 2008 and 2009 are shown in Figure 4.3. The estimate indicates that net revenue was substantially lower in 2009 in comparison with the same zones in As stated in the SOMR: Based on our (Potomac Economics) estimates of investment costs for new units, the net revenue required to satisfy the annual fixed costs (including capital carrying costs) of a new gas turbine unit ranges from $70 to $95 per kw-year. The estimated net revenue in 2009 for a new gas turbine was approximately $55, $47 and $32 per kw-year in the South, Houston and North Zones, respectively. For a new combined cycle unit, the estimated net revenue requirement is approximately $105 to $135 per kw-year. The estimated net revenue in 2009 for a new combined cycle unit was approximately $76, $67 and $52 per kw-year in the South, Houston and North Zones, respectively. These values indicate that the estimated net revenue in 2009 was well below the levels required to support new entry for a new gas turbine or a combined cycle unit in the ERCOT region. Prior to 2005, net revenues were well below the levels necessary to justify new investment in coal and nuclear generation. However, high natural gas prices through 2008 allowed energy prices to remain at levels high enough to support new entry for these technologies. The production costs of coal and nuclear units did not change significantly over this period, leading to a dramatic rise in net revenues. With the significant decline in natural gas and energy prices in 2009, these results changed dramatically from recent years. For a new coal unit, the estimated net revenue requirement is approximately $190 to $245 per kw-year. The estimated net revenue in 2009 for a new coal unit was approximately $93, $84 Natural Gas in Texas, UT Austin,

58 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Figure 4.3: Estimated Net Revenue from: Regulation, Reserves, and Energy Sales by Generation Source, in the Houston, North, and South Regions for 2008 and 2009[49] 50 Natural Gas in Texas, UT Austin, 2012

59 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR and $70 per kw- year in the South, Houston and North Zones, respectively. For a new nuclear unit, the estimated net revenue requirement is approximately $280 to $390 per kw-year. The estimated net revenue in 2009 for a new nuclear unit was approximately $194, $187 and $172 per kw-year in the South, Houston and North Zones, respectively. These values indicate that the estimated net revenue for a new coal and nuclear unit in the South, Houston and North Zones was well below the levels required to support new entry in 2009[49]. This shift in the macroeconomics of generating power in Texas has persisted into 2010 and 2011 and is likely to continue as long as natural gas prices remain below $5 per MMBTU or mcf. 4.3 Relationship with Renewables (Wind and Solar) Natural gas generation has had a complicated relationship with renewable energy sources such as wind and solar for at least two decades. In the 1980s and 90s low natural gas prices served as a deterrent to the implementation of both solar and wind in the US and Texas. Natural gas price volatility in the first decade of the 21st century combined with reductions in the cost of wind and solar generated power has begun to shift the balance. West Texas wind power now competes with natural gas units in the northern and western parts of the state. With no fuel costs, and policy support at the state and national level, wind power has a distinct advantage over natural gas because the market operates on bids based on the marginal costs. Consequently, wind power s share of the market is limited primarily by seasonal and daily variations in the wind and transmission line restrictions leading into the Dallas-Fort Worth and Central Texas market[49]. Wind is also a competitor with gas (because it pushes expensive gas off the bid stack), but wind is good for gas (because the more wind we build, the more people will want gas backup as firming power). Gas is good for wind (because it can offset its intermittency) and because historically high gas prices in the last decade made wind power attractive economically; but at the same time, cheap gas is very bad for wind because for new construction, new gas plants look more economically appealing. Going forward however, the interaction between wind power and gas-fired generation in the deregulated, and now nodal, ERCOT grid might take on a new character, as wind power has become a significant component of the grid s generation capacity. The distribution of generation sources is roughly uniform across ERCOT with the exception of nuclear capacity in the North and Houston zones and the large amount of wind capacity in the West. Figure 4.4 shows the installed capacity, in gigawatts, for each zone and for ERCOT as a whole in The nearly 9 gigawatts of wind capacity built in the West zone over the last decade was not required to serve increased load in the zone, but rather for export to the North and South zones[49]. On December 11, 2010, wind output in the ERCOT was 7.23 GW, which represented nearly 26% of the electrical load on that day[44]. These impressive numbers are somewhat Natural Gas in Texas, UT Austin,

60 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Figure 4.4: Installed Capacity by ERCOT Zone and Total[49] mitigated by the fact that wind generation in Texas peaks in the winter and is concurrent with minimum electrical demand. Still, for the year 2010 as a whole, wind generation accounted for 12% of the states installed capacity and 8% of generation. ERCOT has roughly 23 GW of coal and nuclear generation that serve as base load units. However, the load on the grid rarely drops as low as 20 GW, and therefore, natural gas generation units are usually dispatched last and serve to set the balancing energy spot price for most hours. Consequently, even though the base load coal and nuclear units provide roughly half of the generation on the grid throughout the year, because ERCOT bidding is conducted according to the marginal cost of electricity, natural gas units play a significant role in setting spot electricity prices. Since wind capacity has no fuel price and therefore a lower marginal production cost than coal-fired units, it is expected that there will be increasing periods where the coal units may be the marginal units in the future, especially during low demand periods in the spring and fall. In fact, many coal plants already dial back at low-demand hours in the shoulder seasons. This trend might be further enhanced in the South and Houston zones as additional transmission capacity is added to deliver wind generation from the West Zone into the North and South Zones. Figure 4.5 shows the marginal fuel frequency in the West Zone each month for the years 2007, 2008, and The marginal fuel frequency is defined as the percentage of hours for which a given type of generation is on the margin and therefore sets the price in that zone. It is clear from Figure 4.5, that beginning in September 2008 the percentage of 52 Natural Gas in Texas, UT Austin, 2012

61 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR hours for which coal was the price setting fuel for the West Zone experienced a measurable and sustained increase. It is also evident from Figure 4.5, that the percentage of hours for which wind was the price setting fuel for the West Zone experienced a substantial increase beginning in late Most of this increase is likely attributable to growth in wind capacity that has far exceeded the load growth in the West zone as well as the already mentioned limits in transmission capability that restrict the amount of generation that can be exported. Even though it will be possible to export more of the wind power out of the West zone and into the North and Southern zones as new transmission lines are built, continued growth in wind generation coupled with the fact that onshore wind generation is often highest when the load is lowest, might continue to result in a glut of wind generation in the West zone. Figure 4.5: Marginal Fuel Frequency (West Zone)[49] This trend of squeezing natural gas generation out of the market is further exacerbated by the requirement to have a significant amount of capacity online as a spinning reserve (usually in the form of natural gas generation) to firm up the ever-increasing amounts of wind capacity. Wind generation facilities are different from large central power plants in terms of the availability of their generation. Whereas nuclear and fossil fuel power plants are generally available for dispatch at or near their nameplate capacity, wind generation facilities are dependent upon the weather, the time of day, and the season. In the case of West Texas wind, the greatest generation is routinely available at night and the cooler Natural Gas in Texas, UT Austin,

62 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR months of the year when the load is at a minimum. Furthermore, wind generation is not just dependent on whether or not the wind is blowing but also upon how hard it is blowing. Wind generation capacity is calculated based upon optimum wind velocities, normally in the range of 20 to 30 mph. Realized generation drops off rapidly with drop in wind speed and worse yet drops off completely when the wind blows too hard and the turbines automatically feather their blades to prevent damage from an overspeed condition. Grid firming generation is therefore needed to make up the difference between load requirements and actual wind generation versus forecast wind generation. Deregulated power markets such as ERCOT have, over time, developed market-based services for dealing with the intermittent nature of wind-generated power. These services include fast response generating reserves (spinning reserves) and regulation (load following) capabilities, which are predominately provided by natural gas generation. Analysis conducted by the National Renewable Energy Lab (NREL) indicates that as wind generation is expanded to include larger geographic areas, the combination of multiple wind forecast errors are expected to offset, or average out, rather than compound one another.[30] Consequently, they have determined that wind power does not need 1 for 1 matching for backup. Rather, for every 1 GW of wind generation built a reserve capacity of approximately 300 MW, or 30% of the wind capacity is suggested for firming.[30] In order to analyze the degree to which existing natural gas supply in Texas can accommodate the increase in demand that might be needed to provide firming requirements for wind generation it is first necessary estimate the annual utilization of gas-fired generation for compensating the uncertainties in wind forecasts. Based on analysis conducted by NREL on the variation between actual and forecast winds in Wyoming over a period of several years, it is estimated that over the course of a year a firming gas-fired generator would have a capacity factor between 14% and 16%.[30] An excellent example of the combined effects of renewable sources such as wind and solar is highlighted in an analysis conducted by a research group at MIT in their recently released MIT Study on the Future of Natural Gas.[54] Using a combination of energy development market models and hourly, electrical grid, generation models, the MIT group analyzed the effect of varying wind components in the overall ERCOT generation portfolio on both simple cycle and combined cycle natural gas generation. Figure 4.6 shows their model results for a baseline wind case, a case where wind produces one half the amount of the base case (Wind 0.5), and a third example when wind generation is twice the amount of the base case (Wind 2.0). It is interesting to note that in the wind base case and Wind 0.5 case, coal generation is basically unaffected and, like nuclear, serves as base load, while combined cycle natural gas is significantly displaced as the wind generation increases. The transition from the wind base case to the Wind 2.0 case where coal generation begins to be displaced and combined cycle natural gas is further squeezed out. It is also illuminating that simple cycle natural gas generation steadily grows as wind generation increases from the Wind 0.5 case to the Wind 2.0 case.while it is debatable whether wind generation (and solar) will garner this large a percentage of ERCOT s generation portfolio 54 Natural Gas in Texas, UT Austin, 2012

63 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR by 2030, these model results illustrate the effects of increased renewable generation on both combined cycle and simple cycle natural gas generation. The models clearly have some shortcomings. It is difficult, economically and mechanically, for a dozen or more coal-fired power plants to shift from zero generation, cold start, or even hot start, and ramp up to GW of generation by midday and then back down to zero on a daily basis. Yet this ability is assumed and required in the Wind 2.0 case. The MIT study did a similar analysis of the effects of higher and lower penetration of solar power. With the wind power contribution fixed at the base case amount, the solar contribution to the portfolio mix was both lowered and increased by a factor of two as in the wind analysis. Here the results were somewhat different as the solar contribution peaked during the periods of peak demand. Consequently, the base load contribution of coal was unchanged across the different scenarios, the simple cycle natural gas contribution diminished with the increase in solar generation, and there was much less change in the contribution of combined cycle natural gas as the majority of the increase in solar contribution merely offset the midday reduction in wind generation. This analysis showed the importance of balancing the contribution to the overall portfolio from all sources and in particular highlighted the synergistic and balancing effect of wind and solar. 4.4 A Fuel Switching Option As previously discussed, our calculations indicate that replacing 4,000 MW of realized capacity (35,387,276 MWh of annual generation) from coal as postulated in the Table 4.7 example would require roughly 0.23 TCF of additional gas per year based on a combined cycle natural gas heat rate of 6,700 Btu/KWh. In 2008, Texas used a total of 3.15 TCF of natural gas with 1.44 TCF consumed by electricity generation.[7] In 2008 the United States as a whole produced 20.2 TCF and consumed 23.3 TCF of which Texas was responsible for 6.96 TCF and 3.15 TCF respectively.[50] Since that time, production has increased, thus it is unlikely that a 0.23 TCF increase in demand (1% of national consumption and 3% of Texas production) would have much influence on the natural gas market (e.g. it won t directly cause price increases) especially considering that national demand has varied by 1.5 TCF from year to year over the last five years.[50] Natural Gas in Texas, UT Austin,

64 CHAPTER 4. NATURAL GAS IN THE POWER SECTOR Figure 4.6: Wind Dispatch Effect in ERCOT (MIT Study 2030 Forecast) of first squeezing out natural gas generation and then coal.[54] 56 Natural Gas in Texas, UT Austin, 2012

65 5 Natural Gas As An Alternative Fuel in Transportation 5.1 Natural Gas in Transportation There are basically two types of natural gas vehicles (NGVs) available for use in the marketplace. The first type, includes all manner of retrofitted vehicles sometimes referred to as conversions. The second are vehicles that have been specifically built to operate on natural gas by the original equipment manufacturers (OEMs). Similarly, there are two fundamental engine technologies that can be used to power these vehicles: Spark Ignition (SI) engines, which operate on the same combustion cycle principle as gasoline engines, and Compression Ignition (CI) engines, which operate on the diesel cycle. And, just to add one more variable to the mix, there are two common means of storing natural gas in the vehicle: Compressed Natural gas (CNG), where the gas is compressed to 1% of its volume at a pressure of approximately psi and Liquid Natural Gas (LNG), which occupies 1/600th the volume of atmospheric natural gas but requires cooling to cryogenic temperatures. The energy density of LNG is 60% that of diesel fuel and CNG is only 25% of diesel s.[42] Other approaches, such as fuel cell vehicles with onboard reformers or conversion to methanol are not covered here. In the United States, some of the obstacles to developing light-duty natural gas vehicles (LDVs) follow: Light vehicles, due to their smaller size, are less able to accommodate CNG or LNG fuel tanks that are significantly larger than the gasoline or diesel equivalents and thus have a shorter range. The price premium per vehicle is substantial. Honda makes the only OEM LDV available for purchase in America with a price premium in 2008 of nearly $7000 over a similar gasoline powered vehicle. Similar to electric vehicles much of this premium is likely a result of insufficient sales to achieve economy of scale. However, even if the price differential was reduced to only $3000 from a mix of improvements in technology, government incentives, and manufacturing economy of scale, it would still be a formidable barrier. Fueling station infrastructure is inadequate. Of the 140,000 gasoline stations in the United States, only 1,100 offer CNG. Assuming that the cost of installing a two 57

66 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION hose CNG fueling site at an existing gasoline station can cost greater than $500,000; outfitting just 10% of the existing gasoline stations would cost greater than $7 billion. The current federal income tax credit provided for reducing the upfront cost of CNG refueling station investments is only $30,000 or little more than 5% of the investment required. Home refueling of LDVs is an option, but our research suggests that the installed cost of a home system might exceed $3000 even with federal income tax credit incentives. And much like at-home recharging of electric vehicles, refueling can take several hours and doesn t relieve the range anxiety in a society with limited commercial refueling options. Even with a gasoline versus residential natural gas price spread of a dollar and a half per gallon equivalent, the combined cost of the home refueling system and the premium for an LDV will drive the payback period for the consumer to nearly a decade[55]. In light of the above, the portion of the US transportation fleet that many consider to be most suitable for CNG and LNG use are medium to heavy-duty fleet vehicles and heavy-duty long-haul trucks. Both types of vehicles can use either type of natural gas. In fleet vehicles, where range requirements are less stringent and fueling is often accomplished on a routine basis and at a centralized facility, CNG has several advantages. School buses, transit buses, refuse trucks, trailer trucks, and delivery trucks greater than 8,500 lbs make up the majority of this category. With regards to the types of vehicles suitable for CNG or LNG use, it is generally thought that fleet vehicles and heavy trucks are more appropriate than light vehicles such as passenger cars. Fleet and heavy vehicles travel relatively predictable routes and are refueled principally at truck stops and centralized fleet vehicle service areas. Moreover, larger vehicles have more room to accommodate the bulkier tanks that are needed for natural gas. Modifying a significant percentage of the more than 140,000 gasoline stations in the United States to provide CNG and/or LNG for passenger vehicles would be a much larger undertaking than retrofitting a large portion of the 4,000 truck stops in the United States and a large percentage of fleet vehicle service areas. Even though they get considerable use on a daily basis, these vehicles drive set routes, have low daily mileage, and frequently return to central maintenance facilities, making them ideal candidates for CNG. Heavy-duty vehicles including class 7 single and class 8 combination trucks (18-wheelers), are better suited to LNG use, primarily due to the difference in energy densities between CNG and LNG. As LNG is a direct replacement for diesel in these long-haul trucks, the range available between refueling is much more important than with fleet vehicles. For equivalent sized tanks, LNG can provide more than twice the range of CNG but is still only about 60% that of diesel fuel. This 40% difference in energy density between LNG and diesel fuel can be more easily accommodated in the larger and heavier class 8 trucks. Due to the cryogenic temperatures required for LNG, the tanks are double walled with a vacuum in between to provide insulation. Still, over time, the LNG begins to warm and 58 Natural Gas in Texas, UT Austin, 2012

67 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION some boils off into high-pressure gas that must be vented off the pressure relief valve. This restriction requires that the fuel be used within a few days of filling and/or that the tank be refilled on a regular basis, neither of which is a significant problem for long-haul trucks[55]. The price premium for a medium to heavy-duty, fleet CNG or LNG vehicle over its diesel equivalent is $40,000-$70,000. The most recent federal income tax credits covered up to $32,000 per vehicle. Bearing the cost of a half-million dollar CNG fueling site, as well as the price premium for new or retrofitted vehicles, is not a trivial investment even with the combination of federal and local incentives. However, many cities and municipalities have made the commitment with transit buses, refuse trucks, and fleet vehicles. The combined facilities and vehicle cost results in a longer payback than would be encountered by longhaul trucks with their higher annual mileage and the upfront refueling infrastructure cost borne by truck stops. This cost challenge has been ameliorated to some degree by the ability of these entities to issue low-interest bonds to fund the vehicle and infrastructure cost as part of their vehicle maintenance and phased replacement programs. Conversion to natural gas for centralized fleets has the added benefit of helping to minimize urban air pollution. Compared to gasoline and diesel vehicles, NGVs emit much lower levels of particulate matter[55]. The Port of Los Angeles instituted the Clean Truck Incentive Program in 2008 with the goal of converting nearly 10,000 drayage vehicles that service the ports of Los Angeles, Long Beach, and San Pedro to CNG, LNG, or electric power over the next five years. Programs such as this highlight just how large the potential is for medium to heavy-duty trucks. Even if all diesel-powered transit buses in the U.S. ran on CNG or LNG they would burn barely 0.5 BCF per day. 5.2 Texas and California Texas has a well-developed and expansive highway infrastructure and it is heavily used for commercial transport in the state s agricultural economy; heavy industry in the Dallas-Fort Worth, Houston, San Antonio triangle; and trade with Mexico. The state also cumulatively has among the nation s largest heavy vehicle fleets such as school buses, city buses, and trash collection trucks. Despite the state s lead in natural gas production and its extensive use in the industrial, commercial, and residential markets, very little natural gas is used in transportation. In 2009, Texas consumed 2.2 BCF of natural gas for transportation, which paled in comparison to the 13 BCF consumed for transportation in California or the 3.1 TCF used for all purposes.[32] California has more than 39,000 registered NGVs, comprising more than one in four of the 130,000 nationwide. In comparison, Texas has approximately 11,000.[32] As of 2009 California had 460 natural gas fueling stations of which 146 were accessible to the general public. As of 2010, the entire state of Texas had only 20 stations, with public access at 12 of them. There is clearly a chicken-egg relationship between NGVs and NGV fueling stations. It is difficult to justify purchase of NGVs or modification of existing vehicles to CNG/LNG Natural Gas in Texas, UT Austin,

68 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION if there are no stations to fuel them. Likewise, there is no business case for building these fueling stations if there are no NGVs to make use of them. It is for this reason that most market penetration has been with fleet and commercial vehicles where the operators of the vehicles invest in a centralized fueling facility as part of their transition to NGVs in their fleets. In instances where access to these fueling stations (usually in municipal fleet vehicle service areas) is made available to the public there is opportunity for some expansion in the light vehicle sector. But even investment in NGV fleets and refueling infrastructure has required some motivation to gain the level of use it has in California. Nitrogen oxides, carbon monoxide and volatile organic compounds photo-chemically react to create ground-level ozone pollution. In conjunction with high levels of particulate matter, this ground-level ozone creates the atmospheric pollution commonly referred to as smog. California has extremely high levels of gasoline and diesel powered vehicle traffic throughout the state. It is particularly intense in the urban areas of San Diego, Long Beach, Los Angeles, Bakersfield, Fresno, Sacramento, San Jose, and San Francisco as well as the highway corridors connecting them through the Central Valley as illustrated in Figure 5.1. In conjunction with the state s unique meteorological conditions, this emission profile has led to some of the most severe and extensive ground-level ozone pollution in the country. Figure 5.1: 8-Hour Ozone Nonattainment Areas (1997 Standard) April 2011[27] 60 Natural Gas in Texas, UT Austin, 2012

69 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION The National Renewable Energy Lab conducted a study between April 1997 and October 2002 to evaluate the difference in emissions between diesel and CNG powered medium duty vehicles[55]. The test vehicles for this evaluation were United Parcel Service (UPS) package delivery trucks operating in Hartford Connecticut. The test results showed that the CNG trucks had 75% lower emissions for carbon monoxide, 49% lower for nitrogen oxides, 95% lower particulate matter, and 7% lower carbon dioxide[55]. It is these significant reductions in nitrogen oxides and particulate matter, and the resultant reduction in contribution to ozone formation, that has garnered CNG and LNG a reputation as a clean vehicle fuel. The seriousness of the smog and ozone pollution in California s urban areas probably played a large role in the decisions of many cities and municipalities to shift their transit buses and trash collection vehicles to CNG over the last two decades. Likewise, California has several incentives at the city and state level to encourage private and commercial vehicle owners to transition to CNG and LNG.[2] Even though California has 39,000 NGVs on the road, this is still barely 0.5% of the 7.5 million autos and trucks registered in the state (there are 5.8 million automobiles in LA County alone).[2] As the state struggles to meet more-stringent air pollution guidelines under the EPAs clean air act and natural gas supplies in the country continue to expand (and prices remain low) NGV use might increase. Though California does not have the natural gas resources of Texas, the extensive use of natural gas in California s electric power sector, has led to a large and mature distribution network throughout the state, which could likely support increased use in the transportation sector. While Texas does not have ozone and smog problems as severe as California s, as shown in Figure 5.2, the state is not without problems and has three principal ozone nonattainment zones (Dallas-Fort Worth, Houston, and Beaumont-Port Arthur), three early action compact areas (Northeast Texas, Austin, and San Antonio), and two near nonattainment areas (Victoria and Corpus Christi). These zones correlate with the major urban areas of the state and consequently, concentrations of vehicle traffic, industry, and electrical power generation. As discussed in the power generation section, retirement/replacement of the state s dirtiest coal-fired power plants are one way of reducing the ozone pollution in these regions. Shifting some of the state s 8.8 million cars, trucks and tractor-trailers from gasoline and diesel to CNG and LNG would be beneficial as well. Nearly 18 million of the state s 25 million residents (71%) are concentrated in the Texas Triangle, the region bounded by three metropolitan areas, Dallas-Fort Worth, Houston, and San Antonio, and the highways that connect them (I-10, I-35, and I-45). This region continues to grow at a rapid pace and has been identified as one of 11 megaregions in the United States (Figure 5.3). In addition to representing 71% of the state s population, the triangle region also accounts for 80% of the state s population growth between 2000 and Forecasts for the next two decades predict that this trend will continue and that by 2030 the region will have 23 million residents representing 72% percent of the state s population.[52] As seen in Figure 5.4, the area stretches from the Texas-Oklahoma border southward Natural Gas in Texas, UT Austin,

70 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION Figure 5.2: EPA Nonattainment Areas[35] 62 Natural Gas in Texas, UT Austin, 2012

71 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION Figure 5.3: Populations Within the Texas Triangle [5] through the center of the state to the Gulf Coast and Westward to slightly beyond San Antonio. The highway distance from Dallas to Houston is 242 miles, from Houston to San Antonio 196 miles, and from San Antonio to Dallas 278 miles. The triangle also represents the majority of the state s economic activity producing $817 billion in GDP in 2005, which was 84% percent of the state s GDP for 2005 and 7% of the nation s.[1] It is also no coincidence that the Texas triangle region covers the three ozone nonattainment areas and two of the early action compact areas. As shown in Figure 5.5, the three metropolitan areas are connected by Interstate Highway 10 between San Antonio and Houston, Interstate Highway 35 between San Antonio and Dallas-Fort Worth, and Interstate Highway 45 between Dallas and Houston. In addition to the four Metropolitan Statistical Area (MSA) clusters, the area includes sixty-six counties and covers 57,430 square miles or an area roughly equal in size to the state of Georgia. Like its two sisters, the Arizona Sun Corridor and Florida megaregions, the Texas Triangle is completely contained within the borders of a single state. Consequently, it may be easier to draft and implement legislation to encourage coordinated planning across the region. The compact geometric shape of the region lends itself to a simple CNG/LNG infrastructure network. No two points within the region are more than 300 miles apart, within the unrefueled range of some CNG/LNG passenger vehicles, and most light to heavy-duty trucks, and tractor-trailers. Natural Gas in Texas, UT Austin,

72 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION Figure 5.4: Texas Triangle Megaregion Counties[1] 64 Natural Gas in Texas, UT Austin, 2012

73 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION Figure 5.5: Notional Texas Triangle CNG/LNG Infrastructure[8] Natural Gas in Texas, UT Austin,

74 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION 5.3 The 10% Option There are multiple reasons why increasing natural gas use in transportation in Texas and the United States is worthy of further consideration. Unlike the power sector, where replacing coal with natural gas merely substitutes one domestic energy resource for another, replacing petroleum-derived gasoline and diesel with CNG/LNG can reduce petroleum imports without impacting domestic petroleum production. If we, as a nation, are serious about reducing our dependence on imported petroleum, CNG/LNG use in the transportation sector could be an effective means of doing so. In addition to improving energy security, natural gas as a transportation fuel also costs less than half as much as gasoline or diesel at current prices. The average natural gas prices of the last two years roughly equates to $1.50 per gasoline gallon equivalent. Even with the significant fuel savings, there is considerable resistance to invest the dollars necessary to convert vehicles to run on natural gas. This resistance may have been due in part to the volatility in natural gas prices experienced over the last decade and concerns over the lack of fueling infrastructure. The prospect of low and relatively stable natural gas prices going forward should provide greater certainty when calculating the fiscal viability of transitioning fleet vehicles to run on it. Compared to diesel vehicles, natural gas vehicles emit up to 80% less particulate matter, 20 to 40% less carbon monoxide and 10% less volatile organic compounds. Texas already experiences difficulty in achieving air quality standards in the Dallas-Fort Worth, Houston, Austin, and San Antonio areas, regions that also have the highest number of heavy vehicles[35]. Transitioning a percentage of the heavy fleet vehicles operating in these areas to CNG/LNG would help to alleviate the air quality problem. The private and public CNG and LNG refueling stations that would be built to support medium and heavy truck use could have an additional benefit, it might provide some of the refueling infrastructure necessary to support and encourage increased market penetration of CNG passenger vehicles. Based on these facts, the triad of energy security, economic and environmental benefits could be sufficient to generate increased market penetration of natural gas use in transportation. In the 2011 Biennial legislative session, the state passed the Texas Emissions Reduction Plan (TERP). The bill included three parts aimed at encouraging expanded use of CNG/LNG in transportation: 1) the natural gas vehicle rebate program; 2) a program to fund natural gas refueling stations; 3) an alternative fueling facilities program. The amount of funds available under the bill will depend on ongoing budget deliberations. By itself, this bill will probably be insufficient to achieve the 10% market penetration postulated above. However, it could prove to be an important first step. While sufficient motivation to increase market penetration exists, it would be useful to know the feasibility. In 2005, the combination of all transit, school buses and classes of medium to heavy-duty trucks in Texas consumed 476 trillion BTUs of energy[53]. If we assume that the distribution of these vehicles within the state is roughly equal to an 66 Natural Gas in Texas, UT Austin, 2012

75 CHAPTER 5. NATURAL GAS AS AN ALTERNATIVE FUEL IN TRANSPORTATION average of the population and GDP distribution, then we can calculate that approximately 357 trillion BTUs (75% of state total based on an average of 71% of population and 84% of GDP) were consumed within the Texas triangle region. If we further make the gross assumption that these vehicles use diesel fuel exclusively, we can calculate on a BTU per BTU replacement basis that 0.4 TCF of natural gas would be required for complete replacement. Achieving a 0.5% replacement (on the order of what California has achieved to date) would require only TCF annually. If the state, cities and counties aggressively pursued and incentivized transition of these classes of vehicles to CNG/LNG use, over the next few decades it is not unreasonable to envision a fuel transition of perhaps 1 in 10 vehicles. A penetration of 10% into this segment of transportation in the Texas triangle would require 0.04 TCF of natural gas a year based on these 2005 figures. Similar to the calculations for replacing existing coal-fired generation with natural gas combined cycle plants (4,000 MW of realized capacity from Natural Gas would require roughly 0.23 TCF of gas per year), even the 0.04 TCF per year described above is a small fraction of the state s and nation s production and consumption. Natural Gas in Texas, UT Austin,

76

77 6 Residential Use of Natural Gas 6.1 Source Energy Versus Site Energy Residential energy use is a very broad term as it refers to electrical energy consumption in the home that is generated from a mix of fuel sources as well as the direct use of fuels burned for energy in the home such as natural gas. To evaluate environmental impacts of residential energy use it is necessary to compute conversion factors that take into account the energy used at the site as well as its source. By source energy we are referring to the processes involved in generating the electrical energy used residentially such as extraction, transportation, energy conversion losses in generating electricity at the power plant, and transmission losses in distribution. The relevance of the distinction between site and source efficiency is apparent when comparing nationwide use for two primary sources of energy (natural gas and electricity) in the residential and commercial sectors (Figure 6.1). The solid blue and red lines represent the historical and forecast amounts of natural gas and electricity, respectively, used annually in the U.S., in Quads (Quadrillion BTUs). The dashed orange line shows the amount of energy lost in generating the electricity represented by the solid red line. Data from the EIA for 2008 show that nearly 40% of primary energy and 74% of electricity are consumed in residential and commercial use. The combined amount of natural gas and electricity used in these segments in 2008 totaled Quads, or 8.28 and 9.37 Quads respectively.[21] As shown in Figure 6.1, losses associated with the production and transmission of just the electricity was greater than 20 Quads starting in 2005, or more than the residential consumption of natural gas and electrical energy combined. The losses are an average for the nation and vary by region, depending on the local mix of electrical generation sources. For example, combined cycle natural gas plants operate nearly twice as efficiently as older coal plants as noted before.[18] The residential and commercial sectors have also been increasing their CO 2 emissions. As shown in Figure 6.2, the trend of the last 15 years and the forecast for the next 20 mirrors the pattern of the electrical losses line in Figure 6.1. The potential for significant increases in residential electricity consumption from new devices such as electric vehicles could further exacerbate this trend. The two ways to change this trend are to reduce electricity use and / or reduce the carbon intensity of the electrical generation portfolio. For example, significant increases in the amount of low carbon energy sources contributing to the electrical generation portfolio such as wind and solar would mitigate the trend. 69

78 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Figure 6.1: Trends and Forecast in Residential and Commercial Energy Use Show Significant Loses in Electricity Generation[56] Energy is consumed in the process of extracting and transporting fuel, whether it is coal and natural gas used to generate electricity in power plants or heating oil and natural gas for direct residential use. The largest difference between the two comes in the form of losses associated with the generation of electricity at the power plant (Figure 6.3). As a result, the source to site energy efficiency of coal-fired electricity is 29% and natural gas-fired electricity is 37%. However, for site use of home heating oil it is 89% and for natural gas 92%[20]. Electricity use is also further burdened with additional losses in the process of transmission from the power plant to the residence (Figures 6.3 and 6.4). Residential natural gas and propane (which comes from natural gas production and petroleum refining) are a form of distributed energy use. For typical residential uses such as space heating, water heating, and cooking they are 2 to 3 times more efficient from a total energy perspective than utility grid electricity. Most consumers are not aware of this difference as government mandated energy efficiency ratings on appliances are based solely on the energy consumed at the point of use. As shown in Figures 6.3 and 6.4, it takes about three times as much source energy (including the energy required to produce and transport natural gas and propane) to deliver a unit of electrical energy to a residence, as it does natural gas or propane. Only about one third of the fuel energy that enters a fossil fuel power plant is delivered to the consumer as electrical energy, the rest being lost to power plant inefficiency and transmission losses. When a consumer shops for an appliance, 70 Natural Gas in Texas, UT Austin, 2012

79 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Figure 6.2: Trends and Forecast in Residential and Commercial CO 2 Emissions[56] Figure 6.3: Source to Site Efficiencies for Electricity Generation Shows the Increased Efficiency of Gas-Fired Generation[54] Natural Gas in Texas, UT Austin,

80 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Figure 6.4: Source to Site Efficiencies for Direct Use Fuels[54] such as a water heater, they are presented with government certified information providing only the site efficiency, this labeling portrays an electric unit as being roughly equal to a gas unit when in fact, from an overall energy perspective, the gas unit is actually twice as efficient.[21] Because of this simplistic and inaccurate portrayal of efficiency, many consumers might make their decisions based upon purchase price and operational cost. Given the magnitude of source-to-site energy impacts, it is important for energy efficiency and environmental programs to account for total national energy use accurately. Specifically, there is a need for a defensible and easily implemented methodology for calculating building or appliance energy efficiency based on source energy factors for electricity and fossil fuels like natural gas. One attempt at this was conducted by the Gas Technology Institute and published in August 2009 as Source Energy and Emission Factors for Building Energy Consumption[47]. In this study, the authors developed an Electricity Generation Source Energy Conversion Factor for electricity from coal, natural gas and oil fired power plants as well as nuclear, hydro and biomass (Table 6.1). The analysis calculated the efficiencies based on the cumulative energy required for extraction, processing, transportation, generation, transmission, and distribution. The source energy conversion factor is then just the reciprocal of the cumulative efficiency (lower conversion factors imply higher efficiency). These factors were applied to the Environmental Protection Agency (EPA) egrid2007 analysis of electricity generation by National Electric Reliability Corporation (NERC) by region (Figure 6.5) and calculated the resource mix of electric power plant generation, by percentage for coal, oil, natural gas, hydro, nuclear, and renewables such as wind, solar, geothermal, and biomass. They also calculated the source energy conversion factor for electricity generation at the individual state level. The result for NERCs TRE region that covers most of Texas and parts of Oklahoma was 3.15 (See Table 6.2) and for just the state of Texas was Natural Gas in Texas, UT Austin, 2012

81 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Table 6.1: US Average Electricity Generation Source Energy Factors[47] Process Energy Efficiency (percent) Fuel Type Extraction Processing Transportation Conversion Electricity T&D Cumulative Efficiency Source Energy Conversion Factor Coal Natural Gas Fuel Oil Nuclear Hydro Biomass Figure 6.5: US NERC Regions[20] Natural Gas in Texas, UT Austin,

82 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Table 6.2: Electricity Generation Source Energy Factors by NERC Region[47] Process Energy Efficiency (percent) NERC Region Precombustion Conversion Electricity T&D Cumulative Efficiency Source Energy Conversion Factor Alaska Systems Coordinating Council Florida Reliability Coordinating Council Hawaiian Islands Coordinating Council Midwest Reliability Organization Northeast Power Coordinating Council Reliability First Corporation Southeast Reliability Corporation Southwest Power Pool Texas Regional Entity Western Electricity Coordinating Council Average for United States Table 6.3: US Average Source Energy Factors for Site Use of Fossil Fuels[47] Process Energy Efficiency (percent) Fuel Type Extraction Processing Transportation Conversion Electricity T&D Cumulative Efficiency Source Energy Conversion Factor Natural Gas Fuel Oil Neither of these correlates precisely with the ERCOT region, but as ERCOT does not extend beyond the borders of the state and the TRE region does, it is logical to assume that the value for ERCOT would be roughly the same. Using the same method, they determined the source energy efficiency for on-site use of natural gas and heating oil (Table 6.3). 6.2 Heating Water The residential energy consumption survey (RECS) was last conducted by the US Energy Information Administration in The survey showed that nearly 100% of the 8.5 million residences in Texas are connected to the electrical grid, but natural gas lines serve only 5 million while another 2.5 million have propane tanks[45]. More than anything else, these 74 Natural Gas in Texas, UT Austin, 2012

83 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS numbers are indicative of the large rural population in Texas. Residential natural gas distribution is limited to urban areas due to the high cost of the pipeline infrastructure required and thus rural populations predominately use on site propane gas tanks that are serviced by delivery trucks. The ratio of natural gas customers and propane customers, as well as percentage of homes with natural gas, is slowly increasing, as the preponderance of population growth in Texas is urban. End use of natural gas in the residential sector in Texas is led by water heating (4.4 million homes) with space heating (3.9 million homes) a close second place. The figures for electricity use in water heating and space heating are 4 million and 5 million residences respectively[45]. Residential water heating with its near equal split between natural gas and electricity in Texas, serves as a good test case for evaluating the impact of shifting towards natural gas. Both electric and natural gas hot water heaters come in two basic types: storage tank and tankless; the latter is sometimes referred to as instantaneous or on-demand water heating. Storage tank water heaters predominate in the US and consist of an insulated storage tank of anywhere from 20 gallons to 80 gallons and either an electric resistive heater or gas burner that cycles on and off to maintain the water in the tank at a preset temperature. The tank is necessary because the heating element (electric or gas) is of insufficient size to instantaneously heat water at full demand. The tank serves as a reservoir of hot water large enough to serve most single uses (a shower, bath, clothes washer cycle, etc.) and the heating element heats refresh water in the tank up to the pre-set level over an extended period of time between demand cycles. The major drawback of these heaters, regardless of energy source, is that they consume energy maintaining the water in the tank at the preset temperature around the clock. Site energy efficiencies of the best-in-class for this type of water heater is 95% for electric and 70% for natural gas. The natural gas site efficiency is lower as a considerable amount of the heat of the burning gas is lost in the exhaust stream. However, the full fuel cycle efficiency of the two is considerably different. When the source energy factors are included, the full fuel cycle efficiency (FFC) of the electric storage tank heater drops to 31% for grid power, while the natural gas version only drops to 64%[47]. Even though storage tank heaters predominate in the US, tankless or instantaneous water heaters predominate in Europe and many other regions of the world. As their name implies, they heat incoming water to full service temperature nearly instantaneously as it passes through the heater and can do so at full rated demand. This type of system calls for a much larger electric heating element or gas burner but operates much more efficiently overall as it only operates when there is actual demand for hot water. The best in class electric versions have site energy efficiencies as high as 99% and the gas versions 94%. But again, when the source energy factors are included, the FFC efficiency of the best electric model drops to 32% while the gas version drops to 87%[47]. Given FFC efficiencies of 87% and 64% for gas and 32% and 31% for electric instantaneous and storage tank heaters respectively, it seems surprising that any consumer with natural gas or propane already available in their home would choose an electric appliance. Natural Gas in Texas, UT Austin,

84 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Figure 6.6 shows the source energy consumed in MMBtu for electric and gas water heaters in each NERC region. Even though electric water heaters are outnumbered by natural gas (4.4 million vs. 4 million residences), the electric water heaters consume nearly twice the amount of source energy as the gas models. With the predominance of storage tank water heaters in the US and the roughly identical numbers of gas to electric units in the state, it isn t surprising that these total source energy consumption figures closely mirror the two to one efficiency advantage (64% to 31%) of gas over electric storage tank heaters. Figure 6.6: Water Heater Source Energy Consumption by NERC Region[47] The savings in energy use achieved by gas water heaters over electric water heaters is only part of the benefit achieved with gas. The 47% reduction in energy use that could be achieved in switching from electric water heaters to natural gas in the TRE region would equate to an even higher percentage reduction in CO 2 generation. The reduction in CO 2 generated would be greater than the overall energy reduction because the electric water heaters being replaced use electricity from a generation portfolio with a high percentage of coal-fired power plants. Since burning coal produces more CO 2 than burning natural gas on a Btu for Btu basis, the benefit as shown in Figure 6.7 would be a 55% reduction in CO 2. The energy and CO 2 benefits of increased residential use of natural gas for heating hot water extend to residential space heating as well. As mentioned earlier, 3.9 million Texas residences rely on natural gas for space heating while 5 million have electric furnaces. Similar to the water-heating example, the best available electric furnaces have site energy 76 Natural Gas in Texas, UT Austin, 2012

85 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS Figure 6.7: Water Heater Emission Comparisons by NERC Region and US[47] efficiencies of 99% while the best gas furnaces achieve 98%. Once the source to site efficiency is included the FFC for the electric furnace drops to 32% and the gas furnace drops to 90%[47]. Another potential application for residential and rural gas use is on site electricity generation. There is already an established market for residential backup electrical generators, which are powered by conventional internal combustion engines that run on a wide variety of fuels such as gasoline, diesel, natural gas, and propane. This market is primarily focused on remote, off grid, applications or restricted to backup power applications in areas prone to grid instability due to weather or that serve critical functions. Technology advances in fuel cell devices that generate electrical power from natural gas could lead to affordable, standalone electrical power generation devices for intermittent or even continuous use at the residential level. A natural gas powered, residential, electric fuel cell on the order of 5 to 10 kw, in conjunction with and as back up for, 3 to 5 kw of solar photovoltaics could eliminate the need for any electricity from the grid for the typical home. Future increases in electricity prices combined with more affordable photovoltaics and fuel-cell technology could make living off the grid a viable choice even in urban residential settings rather than only as a necessity for remote locations. Like buried electrical lines, buried natural gas pipelines are less prone to disruption from storms and other weather events. However, with increased use of natural gas there will be increased potential for problems from existing shortcomings of natural gas such as: blown Natural Gas in Texas, UT Austin,

86 CHAPTER 6. RESIDENTIAL USE OF NATURAL GAS out pilot lights, gas leaks in residences and pipelines, and gas line explosions. In addition to these safety issues, increased reliance on a single energy source would bring increased financial exposure to natural gas price volatility, which has historically been greater than electricity price volatility. 6.3 The 10% Option Transitioning a significant percentage of any of the many home appliances that can be operated on either electricity or natural gas to the latter could greatly improve overall energy efficiency. Based on our analysis, if 10% of the residential electric water heaters in Texas (400,000) were to convert to natural gas, it would reduce the state s electricity consumption by 1,360,000 MWh per year or about one half of the 2007 generation of the state s smallest coal-fired plant (Twin Oaks). Such a fuel shift would require 0.01 TCF of additional gas or less than 0.1% of current Texas dry gas production. If all four million were replaced with natural gas units, the electricity savings would be equivalent to all of the electricity generated by the state s fourth largest coal-fired power plant (Limestone) in 2007 and would require 0.10 TCF of natural gas. These calculations assume that the natural gas replacement units would be of the tank variety as these are still the norm in the U.S. Replacing with tankless natural gas heaters that have FFC efficiencies of 87% versus 64% for the tank variety would decrease the amount of natural gas required in both examples by 27% Natural Gas in Texas, UT Austin, 2012

87 7 Implications for Natural Gas at the National Level All three of the demand segments analyzed for Texas in this report Power Generation, Transportation, and Residential use are viable for expanded use of natural gas at the national level. However, of the three, increased use of natural gas in electrical power generation offers the greatest potential for near term expansion with the least physical modification given the existing regulatory and policy environment. The U.S. experienced a large expansion of natural gas fired electrical generation between 1998 and 2008 (Figure 7.1). Figure 7.1: US Electrical Generation by Fuel Type and Initial Year of Operation[20] This expansion doubled the share of natural gas in total generating capacity, making it the largest component of national generation capacity (Figure 7.2). A large percentage of these plants were natural gas combined cycle (NGCC) and built to serve as base load. They operate at nearly twice the efficiency of the coal-fired power plants built in the 1960s 79

88 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL and 70s.[18] The remainder were simple combustion turbine plants designed to operate as peaking power plants that would operate only a few hundred hours per year to handle summer demand spikes. Figure 7.2: US Electric Power Industry Net Summer Capacity by Fuel Type 2009[20] Although natural gas now makes up the largest portion of power generation capacity, it still lags behind coal as the principal source of actual electricity generation (see Figure 7.3). The natural gas plant build out from was influenced by several factors: the NGCC technology was very efficient compared with coal generation, the plants could be built relatively quickly and cheaply, the permitting and regulatory process was simpler, and the plants were relatively small and modular in nature, which allowed them to be tailored for specific sizes of demand and increased in capacity over time and aligned better with the availability of capital. In addition, the price for natural gas was relatively low in the 1990s (in the range of $2.00 to $3.00 per MMBtu) and was expected to remain in this range for some time.[17] By the first years of the 21st century, it became clear that the flurry of NGCC construction had created a glut of underutilized generation capacity. The excess in generation capacity was further compounded by increases in natural gas prices starting in The result has been a large fleet of NGCC plants that were built to operate as base load being utilized at well below their rated capacity. In 2007, a study conducted by the Congressional Research Service (CRS) identified 134 NGCC plants nationwide, with a combined generation capacity of 170,627 MW that had an average operational capacity factor of 42% 80 Natural Gas in Texas, UT Austin, 2012

89 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL Figure 7.3: US Electric Power Industry Net Generation by Fuel Source, 2009[20] Natural Gas in Texas, UT Austin,

90 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL for the year.[10] Figure 7.4 shows the monthly capacity factor for these 134 NGCC plants compared with that of 298 similar coal-fired power plants that had an average capacity factor for the year of 75%. Figure 7.4: Monthly Capacity Factors in 2007 for Nationwide Study Group Coal and NGCC Plants[10] This situation at the national level is not dissimilar from that in the ERCOT grid of Texas where, in 2010, natural gas-fired electrical generation accounted for 57% of capacity, but contributed only 38% of electricity produced for the year (see Figure 3.6). Operating the aforementioned 134 NGCC plants at a reasonable base load rate of 84%, for which they were designed, could have allowed for the decommissioning of approximately 85,000 MW of coal-fired generation, based solely on their rated capacity. The shortcoming of such a simple calculation is that it assumes the electrical generation it would replace is currently served by coal-fired generation and that the NGCC generation is geographically close enough to serve it. Even if these conditions are met, there is also the question whether the nation s infrastructure could support delivering the necessary additional natural gas. In the case of the individual pipelines serving existing NGCC power plants, this question is not an issue. As these plants were designed and intended to, and frequently do, operate at their full rated nameplate capacity, they have sufficient regional pipeline infrastructure to support them. The question is a larger one as it relates to the nationwide network of interstate pipelines and storage facilities that balance out seasonal swings in demand and distribute gas from areas of net production to areas of net consumption as illustrated in Figure Natural Gas in Texas, UT Austin, 2012

91 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL Figure 7.5: US Interstate Natural Gas Pipeline System[20] Natural Gas in Texas, UT Austin,

92 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL This system consists of over 217,000 miles of interstate pipeline and has the capacity to transport nearly 0.2 TCF of natural gas on a daily basis[48]. Because natural gas production is relatively constant throughout the year but demand has seasonal peaks and troughs, there is also a system of natural gas storage facilities (Figure 7.6). The 134 NGCC plants identified in the CRS study generated a combined 630,358,373 MWh (630 TWh) in 2007 operating at an average capacity factor of 42%, which required roughly 4.57 TCF of natural gas. Increasing these plants generating capacity to 85% would double their annual generation to more than 1,300 TWh and require an additional 4.6 TCF of natural gas supply. Even though the regional pipeline system is designed to deliver the necessary gas to the individual plants, this shift would require a significant increase of natural gas production and distribution at the national level. 4.6 TCF represents nearly 20% of U.S. natural gas consumption in The U.S. interstate pipeline system can accommodate 66.8 TCF per year[34]. Even though an increase of 4.6 TCF equates to a 7% increase in pipeline capacity it is well within the 22.6 TCF aggregate expansion of the system capacity completed or under construction in 2010 and 2011[34]. Additionally, much of the interstate flow has historically been from the net producing South-Central U.S. to the net consuming Northeast and Great Lakes area. With much of the new shale gas production coming from the Marcellus, Utica, and Devonian Shale formations located in Pennsylvania, West Virginia, and Ohio, this formerly net consuming area might become self-sufficient. Some pipelines between the southern Marcellus region and the gulf coast that used to deliver dry gas to the Northeast have already reversed flow to bring wet gas products (which predominate in the southern Marcellus) to refineries located in the Gulf States. 1 Increasing the nation s annual natural gas consumption by 20% (4.6 TCF) could require expansion of the underground storage capacity, which as of June of 2011 was 8.7 TCF.[42] As shown in Figure 7.7, the amount of gas in storage varies on an annual basis between 1.2 and 3.9 TCF with a maximum variation band of approximately 0.8 TCF at any given time of year since At a macro level it would appear that there is sufficient excess storage available. But even if not, there has also been a 12% increase in storage capacity since 1995 paralleling the expansion of pipeline infrastructure of the last decade.[42] The shift in utilization postulated in the CRS study is clearly very large and was meant to illustrate the significant change that could be made in our national generation portfolio just by modifying our utilization of existing assets. The authors of the report acknowledge that geographic location of these NGCC assets is important and might limit the degree to which their unused capacity could be utilized to offset coal-fired generation. 2 Even if their full capacity could be utilized to offset an equivalent amount of coal-fired generation and the natural gas infrastructure could support the increased demand, the real question as to the viability of such a switch is likely the cost of natural gas going forward plus the limits 1 Personal interview with Gas Industry Expert 2 Only 16% of the 134 plants were within 10 miles of an equivalent coal-fired plant and 28% were within 25 miles Natural Gas in Texas, UT Austin, 2012

93 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL Figure 7.6: US Natural Gas Underground Storage Sites[20] Natural Gas in Texas, UT Austin,

94 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL Figure 7.7: Monthly US Underground Natural Gas Storage[20] or costs of new air quality regulations. The examples for increased use in Texas power generation, transportation, and residential use were, individually and even in the aggregate, probably small enough to have minimal if any effect on natural gas prices. The 20% increase in national consumption that would be caused by the hypothetical example in the CRS study most likely would impact prices. Perhaps the greatest uncertainty in postulating increased uses of natural gas is the future price uncertainty. At the global scale, natural gas has historically been a regional fuel in that the majority of production was consumed in the region in which it was produced. There is reason to believe that this trend will not persist. Petroleum is a global commodity with a global price and a marginal regional cost variance affected principally by variation in transportation costs and quality. As can be seen in Figure 7.8, as recently as 2008, there was close global correlation in natural gas prices as well. There are likely several reasons for the wide divergence that global market prices have experienced since mid However, the nearly 300% price difference between the U.S. and Japan since early 2010 (and 130% between the U.S. and Europe) signals significant opportunity for export of U.S. gas if LNG infrastructure investments are made creating a global market for natural gas. The U.S. isn t the only country hungry for natural gas. We might use only a small fraction of our consumption for transportation, but the trend for other countries is higher. Figure 7.9 shows that natural gas vehicles already have a strong and rapidly growing presence in Asia and South America. This acceptance of the technology coupled with the high forecast population and economic growth in these areas is likely to sustain the 86 Natural Gas in Texas, UT Austin, 2012

95 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL Figure 7.8: Natural Gas Prices in Major Markets, July 2007-April 2011[22] trend and the concomitant growth in natural gas demand. With demand for Texas gas consumption weakening in the Northeastern U.S. due to production from the Marcellus shale, some industry experts have speculated that production from new Texas gas fields such as the Pearsall-Eagle Ford could be piped southwest to meet growing demand in Mexico. 3 Further complicating the future price picture is the growing global demand for coal. Coal, like natural gas has historically been a regional fuel as well. However the huge increase in demand from China over the last decade has resulted in dramatic increases in the amount of coal they import from Australia, and there are already plans by several US coal suppliers to begin exporting coal from the Powder River Basin of Wyoming to China via ports in the Pacific Northwest.[15] Some of the reluctance to aggressively pursue replacement of coal-fired generation with natural gas has been the low cost of coal and the perception that shifting to natural gas would hurt the US coal economy. If growing demand for coal from China and other developing countries turns it into more of global commodity like petroleum, any weakening of demand for coal in the US due to a shift towards more natural gas use in power generation could be offset by US coal exports. This could be good for US coal and natural gas production and would actually make China somewhat dependent on the US for its energy security. As a whole, the production, distribution and use of natural gas in the nation is not radically different than in Texas. The fact that Texas, as a state, is overall more energy efficient than the nation (primarily due to greater site use of natural gas in industry) might be reason enough to craft policies to encourage greater and more efficient use of domestic 3 Personal interviews with Natural Gas Industry Executives Natural Gas in Texas, UT Austin,

96 CHAPTER 7. IMPLICATIONS FOR NATURAL GAS AT THE NATIONAL LEVEL Figure 7.9: Global Growth in Natural Gas Vehicles natural gas to improve the country s economic viability while also reducing emissions.[16] 88 Natural Gas in Texas, UT Austin, 2012

97 8 Conclusions and Future Work 8.1 Conclusions Overall, the conclusion of this analysis, based on the assumptions and calculations explained in the body of the report, is that some fuel-switching from coal to gas in the power sector, from petroleum to gas in the transportation sector, and from electricity to gas in the residential sector, has significant economic and environmental benefits for Texas. One of the principal reasons for these fuel-switching benefits, total fuel cycle efficiency, becomes readily apparent when looking at total energy use in the US and Texas from the macro-level. Figure 8.1, commonly referred to as a Sankey Chart, shows all US energy consumption for The chart is read from left to right (fuel sources flowing in from the left and energy flowing out to the right), the width of the lines represents the quantity of each flow, the one yellow box (Electricity Generation), and four pink boxes, represent conversion of the fuel, or electricity, into useful work, represented as the dark grey lines exiting and aggregated on the far right as Energy Services. The light grey lines exiting to the right from the five boxes, and aggregated under the title Rejected Energy, represent the energy lost each year to the respective inefficiencies of the assorted fuel energy to electricity and energy services conversions. The visual nature of the Sankey Chart makes it readily clear that of the 99 quads of energy consumed in the US in 2008, 57 quads (and roughly 57%) were lost to inefficiencies. The chart also shows that natural gas is the only fuel that is used in all five major energy sectors: Electricity Generation, Residential, Commercial, Industrial, and Transportation, and used extensively in four of the five. Figure 8.2, depicts total energy use for Texas in Comparing the 2008 charts for Texas and the US reveals several interesting differences: 1. Texas uses natural gas primarily in electricity generation and industrial processes. 2. Texas uses less natural gas than the US on average (as a percentage) in the residential and commercial sectors. 3. Texas, as a state, uses energy more efficiently than the US, as a whole, (47.5% compared to 42.5%). 1 These macro-level differences between Texas and the US are important and interrelated. As shown in Chapter Six (Residential Use of Natural Gas), total fuel cycle efficiency is 1 Calculated as Energy Services divided by Total Energy Use. 89

98 CHAPTER 8. CONCLUSIONS AND FUTURE WORK Figure 8.1: Most of the energy used each year in the United States (shown for 2008 by fuel and sector) is wasted (Rejected Energy).[16] 90 Natural Gas in Texas, UT Austin, 2012

99 CHAPTER 8. CONCLUSIONS AND FUTURE WORK Figure 8.2: Texas uses more energy in the industrial sector than any other state, and efficiently so, which leads to a higher overall efficiency than at the national level.[16] generally higher when primary fuels are used on site. 2 Texas uses a larger percentage of energy in the industrial sector than the US and as the industrial segment is primarily based on site use of fuel, this industrial use actually improves the state s overall energy efficiency. This type of high efficiency operation is not restricted to the industrial sector. In the electric sector, combined cycle natural gas power plants provide a means of significantly increasing the fuel cycle efficiency of the state s fleet of power plants while also reducing emissions and expanding the market for one of the state s principal natural resources. In transportation, the percentage of natural gas used in Texas is twice that of the nation (4% and 2.5% respectively), but still marginal compared to petroleum.[16] Aside from driving fewer miles and/or improving the fuel efficiency of trucks and automobiles, the only means of significantly reducing our use of petroleum is through replacement with alternative fuels. Of the alternatives, natural gas is one of the most technologically mature and affordable options. The fact that it is relatively abundant and domestic, makes a 2 This is due to fewer energy conversions and the ability (primarily in commercial and industrial applications) to make use of waste heat for other processes, which reduces the amount of Rejected Energy. Natural Gas in Texas, UT Austin,