The Potentials and Problems of Expanding Use of Shale Gas in the Continental U.S.

Transcription

1 The Potentials and Problems of Expanding Use of Shale Gas in the Continental U.S. December 3, 2014 Group 6 Cammie Chan, Brendan Fan, Ayhan Kucuk, Crystal Meng, Roberta Weiner, Rongchen Zhu 1

2 Contents I. Introduction... 3 II. Benefits of Shale Gas Environmental Benefits Economic Benefits III. Costs of Shale Gas Environmental Costs Economic Costs Social Costs IV. Cost-Benefit Analysis Benefits Costs Sensitivity Analysis V. Conclusion VI. Policy Recommendation VII. Limitations and Next Steps VIII. Appendix IX. References

3 I. Introduction Natural gas is a fossil fuel that is formed in the Earth s crust, created from organic matter that has been exposed to heat and pressure of overlying rock for thousands of years. It consists of mostly saturated aliphatic hydrocarbons like methane. When combusted, natural gas mainly produces carbon dioxide and water vapor, which makes it the cleanest of all fossil fuels. In comparison, coal and oil are composed of more complex molecules and, when combusted, release harmful emissions such as nitrogen oxides and sulfur dioxide. As a result, natural gas has been touted as a potential way to reduce emissions of pollutants into the atmosphere and reduce America s reliance on oil as an energy source [1]. The natural gas supply in the US has experienced a great increase recently with the advent of hydraulic fracturing, an innovation that allows gas trapped in shale to be released. This process, also called fracing or fracking, involves pressurizing a horizontal section of a well by pumping in 3 or 4 million gallons of water to pressures of up to 7,000 kilopascals [2]. This horizontal drilling contrasts the conventional method of vertical drilling. The resultant extreme pressure cracks the rocks and carries a material such as sand into the resultant fractures. The sand is the proppant, because it keeps the fractures open, which allows hydrocarbons to flow out of the surrounding rock and into the wellbore [3]. This process is repeated up to 30 times in one well, with tens of wells drilled at a single drill site. 3

4 Figure 1. Fracking process [133] The new technology is unique because it allows drillers to go right to the source. Conventional deposits of oil and gas are actually composed of far-traveled hydrocarbons that were originally in deeper source beds. In contrast, shale gas is an unconventional resource because it is still in its source bed whose organic matter gave rise to the gas [2]. Horizontal drilling and fracking technologies have allowed shale gas to become accessible. The propagation of fracking is widely traced to 1998, when success was first seen in the Barnett Shale in Texas [3]. Since then, shale gas has increased from comprising 1% of the US gas supply in 2000 to 20% in In the Barnett Shale alone, production increased 3,000% from 1998 to 2007 [2]. The prevalence of shale gas basins across the US can be seen in Figure 2. 4

5 Figure 2. Shale gas basins in the US [2] Use of Natural Gas Unlike oil, natural gas is segmented in consumption. Residentially, natural gas is used for heating and cooking. It is the most popular fuel for residential heating and is even cheaper than electricity as a source of energy. Commercially, natural gas is mainly used for space heating, water heating, and cooling. Industrially, natural gas helps to provide base ingredients for various products, including plastic, fabrics, and fertilizer. US Demand of Natural Gas The North American gas market is the largest in the world, with 773 bcm (billion cubic meters) consumed in This was 29% of global gas demand. Since the 1980s, US demand has been steadily rising, a pattern that is consistent with the great increase in supply of natural 5

6 gas since the advent of fracking technology and the related price decrease. Currently in the US, natural gas heats 50% of existing homes and nearly 70% of newly built homes [1]. Demand has also increased with recent emphasis on environmental sustainability and energy efficiency. For some companies, there is external pressure from investors who want to see the companies engaging in sustainable practices. For example, the Carbon Disclosure Project urges major companies to disclose their climate change strategies publically, which incentivizes them to promote environmentally-friendly activities [1]. Factors Influencing Demand The short-term demand in the US is generally cyclical and seasonal. During the winter times, there is an increased need for residential and commercial heating. Thus, natural gas prices spike in January/February and dip in July/August. Long-term demand determinants are crucial to the future role of natural gas. These include prospective climate change legislation in the US and also changing demographics. According to the Work Progress Administration, people have moved towards warmer Southern and Western states, which could increase demand for cooling in the long-term. Other factors include technological advancements. Supply in the US Market The US has the largest gas market in the world, with 4% of the world s gas reserves in Since then, gas reserves have only continued to rise, because new drilling technologies such as fracking are unlocking substantial amounts of natural gas from shale. Indeed, unconventional production is the single largest source of natural gas, which is predicted to account for 30% of US production by 2030 [1]. 6

7 Figure 3. US Natural Gas production by sources, This huge increase in available supply exceeds the market demand, which has created a glut and resulted in stable and low natural gas prices, especially compared to that of petroleum [1]. Experts believe it is directly the result of increasing production from North American shale rock formations. 7

8 II. Benefits of Shale Gas 1. Environmental Benefits Compared to coal and oil, natural gas is a relatively cleaner energy source. Natural gas is combusted to generate electricity. In the electricity-generating process of using natural gas, no substantial amount of solid waste is produced, and the combustion of natural gas requires very little water, except for cooling purposes of natural gas-fired boiler and combined cycle systems [4]. Burning of natural gas produces carbon dioxide, nitrogen oxides, sulfur dioxide, and mercury compounds. Emissions of carbon dioxide and nitrogen oxides from burning natural gas are of lower quantities than from burning coal or oil; and emissions of sulfur oxide and mercury compounds from natural gas combustion are negligible. Specifically, natural gas average emissions rates in the US for carbon dioxide, nitrogen oxides, and sulfur dioxide are 1135 lbs/mwh, 1.7 lbs/mwh, and 0.1 lbs/mwh, respectively [5]. When comparing coal-fired electricity generation with natural gas-fired electricity generation, coal produced twice as much carbon dioxide, more than three times as much nitrogen oxide, and one hundred times as much sulfur oxides. The relative cleanliness of the energy sources can also be demonstrated by comparing the amount of one major pollutant carbon dioxide emitted per unit of energy output. Pounds of carbon dioxide emitted per million Btu of energy for various fuels are [6]: 8

9 Table 1 Coal (anthracite) Coal (bituminous) Coal (lignite) Coal (subbituminous) Diesel fuel & heating oil Gasoline Propane Natural gas When burned for generating energy, natural gas emits the least amount of carbon dioxide comparing to coal or oil. However, one large concern of using natural gas is that methane a greenhouse gas and a primary component of natural gas is emitted into the air when natural gas is not burned completely. Methane leaks can also happen during natural gas production, transmission and distribution. 9

10 2. Economic Benefits Need for Infrastructure Development Expanding natural gas would increase the potential in the market for developing infrastructure. Apart from drilling and extraction needs, the expansion of natural gas use also increases demand in pipeline and storage capacity across the nation. Particularly with the recent shale boom, it is crucial to build new and enhance existing infrastructures to ease the difficulties in transporting natural gas to other regions. This includes pipeline networks or liquefaction infrastructure and equipment, as well as regasification facilities at the destination. Investments on natural gas infrastructures deserve significant attention. It is estimated that more than $30 billion per year will be required in total capital expenditure on infrastructure for natural gas and liquids [7]. Despite infrastructure investments involve large amounts of capital and long period of time to see return on investments, investments are needed to ensure the integrity and security of existing transmission and distribution infrastructure, which bring positive externalities to the economy. A comprehensive supply chain can enable a monitor system that can detect leaks and any potential safety and environmental concerns. The expansion of natural gas transmission, storage, and distribution can also alleviate any bottlenecks in the pipeline system, so that nationwide end-users can benefit directly from increased domestic gas supply as well as less volatile prices. This section argues that with the shale boom, shifting production profiles require pipeline constructions, as well as maintenance with the existing pipeline network. Then, a strengthened pipeline network will lead to a higher demand for storage capacity. Next, it will also highlight current government support that aims to incentivize infrastructure development. 10

11 Shifting Production Profiles Require Additional Pipeline Construction Pipeline construction has been increasing in the US as natural gas production has experienced robust growth over the past decade. The network of U.S. natural gas pipelines is highly complex and can transport natural gas to and from nearly any location in the lower 48 States. At the close of 2008, the U.S. Energy Information Administration (EIA) estimates that there are around 305,954 miles of natural gas pipeline in the lower 48 states (See Figure 4). In addition, according to data available on EIA s website, from 2009 to present, 8097 miles of pipeline have been built [9]. Currently, there are 123 projects that are either announced, approved or under construction. They sum up to another 8,782 miles of pipeline that will be in service within the next decade [8]. Pipeline projects have many problems that are yet to be resolved. An example is the lack of planning in constructing the pipeline network in the US. Pipelines are often built to service individual ventures or utility needs, they lack the logic of a highway-system-style network [9]. Furthermore, major changes in the US gas market have triggered significant additions to the pipeline network. The direction of pipeline flows in the US, which have historically moved from south to north, have been expanding west-to-east. The country is shifting production from Gulf of Mexico to onshore production including Rocky Mountains. As a result, not all areas will require significant new pipeline infrastructure, but many areas (even those that have a large amount of existing pipeline capacity) may require investment in new capacity to connect new supplies to markets. However, with the current rate of construction, the distribution network is still insufficient to alleviate geographical unevenness of natural gas distribution. The Interstate Natural Gas Association of America (INGAA), which represents the vast majority of the interstate natural gas transmission pipeline companies in the U.S., estimates that the U.S. and Canada will need approximately 28,900 to 61,900 miles of 11

12 additional transmission and distribution natural gas pipelines depending on assumptions for gas demand [10]. New infrastructure will be required to move hydrocarbons from regions where production is expected to grow to locations where the hydrocarbons are used [7]. Figure 4. Estimated natural gas pipeline mileage in the lower 48 states, close of 2008 Building pipeline infrastructure can incentivize production and lower consumer prices. This can be seen with the Rocky Mountain Express pipeline (REX), which was built in With a capacity of 1.8 Billion cubic feet per day (Bcfd), REX was the largest addition in the U.S. pipeline system, and has allowed Western producer markets to supply gas to eastern consumer markets [10]. Before the construction of the REX pipeline, natural gas transportation out of the Rockies region was very constrained. The relationship of the price differential to infrastructure is observed in the basis differentials at the Cheyenne and Algonquin hubs before and after the opening of the REX pipeline. From Figure 5, we can see that as the REX pipeline moves gas supplies from the region to Eastern markets, the regional price differentials change in a smaller degree, showing how alleviating pipeline infrastructure bottlenecks can incentivize production and lower consumer prices overall [10]. 12

13 Figure 5. Impacts of 2008 pipeline capacity expansion on regional prices and average basis [10] Existing Pipelines Require More Maintenance Attention to Ensure Stable Natural Gas Prices, Which Would Benefit the Macroeconomy As noted, natural gas markets are not traded as national as oil or coal markets because natural gas is logistically difficult to transport nationwide. Almost half (142,000 miles) of the natural gas pipelines currently in service were constructed in the 1950 s and 1960 s [11]. However, U.S. gas companies are replacing less than 5 percent of their leakiest pipes per year [12]. A recent study by Boston University estimates that leaking pipelines are releasing between 8 and 12 billion cubic feet of methane annually in Massachusetts alone [13]. With existing pipelines in far heavier use than they were during , addressing aging infrastructure is ever more imperative. Despite maintaining aging infrastructure is an immediate issue, there are few federal or state incentives to repair or replace leaky pipes or minimize lost gas nationwide. This is because natural gas suppliers can always transfer the cost of gas leaks onto consumers. As a result, consumers are paying for gas that never reached them [12]. 13

14 A report by the House Natural Resources Committee Democratic staff suggests that American consumers paid $20 billion from to cover the cost of natural gas leaks from pipelines operated in 46 states [12]. The limitation of the current infrastructure can be viewed in stark terms through the lens of winter wholesale natural gas prices in New England. In winter of , the wholesale price in Pennsylvania, on top of the Marcellus shale deposit, was $3.37 per million BTUs. In Boston, it was $24.09 [9]. The price difference across regions can be resolved by actively maintaining existing pipelines and repairing gas leaks. This can reduce the cost of gas and will provide economic benefit to the public. Improved Pipeline Network Also Leads to Higher Demand for Storage Capacity An extensive pipeline network is able to transport gas throughout regions in the lower 48 states, but storage capacity is equally important to support fluctuating demands. Natural gas can be stored in underground storage facilities to meet seasonal demand fluctuations, provide operational flexibility for the gas system, and hedge price variations. In the case of the Marcellus Shale, planned investments in pipelines drive investments in underground storage. Storage is critical for the region because the geology of the Northeast prevents significant storage in this key demand region, which could create a storage bottleneck when moving gas from points West to Northeastern markets, particularly in the peak demand months in the winter [10]. Increasing shale gas production has driven the growth of underground storage capacities. Figure 3 breaks down the total capacity of the three types of storage facilities from 2008 to 2013 [14]. In 2013, 80.86% were depleted reservoirs facilities, 9.54% were aquifers and 9.60% were salt caverns. Total working gas storage capacity nationwide in 2013 was around 4.75 Tcf [14]. Since 2000, the Federal Energy Regulatory Commission (FERC) has certificated over 1,100 Bcf of new underground storage capacity, both in expansions of existing storage fields or as new storage sites. The FERC has pending projects that would add an additional 140 Bcf of storage 14

15 capacity and is aware of the potential for more storage projects totaling an additional 70 Bcf of capacity [15]. Figure 4 portrays the distribution of facilities in the lower 48 states. Over 53% of the 4.75 Tcf working gas storage capacity is found in five states: Michigan, Illinois, Louisiana, Pennsylvania and Texas [10]. Storage development has generally occurred in the south central US, first to accommodate the expected increase in imported LNG and, more recently, to store the gas produced from the shale basins. Among the growth of underground storage capacities, salt caverns are expected to dominate new storage development [15]. This is because salt caverns are typically located in the Gulf Coast, where production is most concentrated (See Figure 7). When compared to depleted reservoirs and aquifers, salt caverns provide higher withdrawal and injection rates relative to their working capacity. Therefore, salt cavern storage is expected to increase its share in new storage development, with the volume of salt cavern storage essentially doubling over the forecast period. The INGAA study estimates that approximately 589 Bcf of new storage capacity is required by 2035 to meet market growth at a cost of $5 billion [15]. Cavern construction is more costly than depleted reservoirs when measured based on dollar per thousand cubic feet of working gas capacity. But even so, salt caverns ability to perform several withdrawal and injection cycles each year reduces the per-unit cost of each thousand cubic feet of gas injected and withdrawn [16]. Of the 17 new sites under construction and planned between 2013 and 2015, 12 are new salt cavern facilities [17]. Continuing innovation in salt caverns, or storage technologies as a whole, could provide value for both consumers in lowering cost and producers in improving profitability. 15

16 Figure 6. U.S. working natural gas underground storage capacity [14] Figure 7. U.S. Underground Natural Gas Storage Facilities, close of 2007 [18] 16

17 Government Initiatives to Incentivize Infrastructure Construction The U.S. Government has taken initiative to incentivize infrastructure construction. Currently, government agencies involved in regulating gas pipelines and other gas infrastructure include the Federal Energy Regulatory Commission (FERC), U.S. Environmental Protection Agency (EPA) and the Pipeline and Hazardous Materials Safety Administration (PHMSA) under the United States Department of Transportation. These government bureaus have worked to a common goal to drive the growth of infrastructure development in the United States. In particular, the FERC has taken several measures to increase electric generation and natural gas supply in the Western part of the U.S. In the past, the Commission has provided a temporary waiver of its pipeline blanket certificate regulations to waive regulations that would require prior notice for the construction of certain facilities. The Commission also instituted a temporary waiver of its blanket certificate regulations that limit the types of facilities that can be constructed pursuant to either automatic authorization or prior notice [19]. These measures allow interstate pipelines to quick add capacity without undergoing the time-consuming process of certification of large projects. The FERC is also largely involved in passing the Energy Policy Act of 2005, which recognizes the need to streamline siting, and supports the continuation of fine-tuning so that infrastructure can be analyzed and permitted in a timely manner [15]. Under the Act, the Commission issued pricing reforms that are designed to promote investments needed in energy infrastructure [20]. The Pipeline and Hazardous Materials Safety Administration (PHMSA) under the United States Department of Transportation has also identified $33.25 million in federal funding for pipeline safety technology since 2002, around $4 million per year. The improvement in 17

18 technology could drive down investment costs and improve timeliness for planning and operating infrastructure development [10]. Local states also implement policy mechanisms to pay to upgrade and replace existing pipelines. For example, states like Colorado use a tracker system that changes rates in response to the utility s operating costs. Also, the Georgia Public Services Commission has permitted Atlanta Gas Light Company to institute a surcharge on customer bills throughout its service territory to help fund pipeline replacement, improvement, and pressure increases through the Georgia Strategic Infrastructure Development and Enhancement (STRIDE) Program [21]. Government s incentivizing schemes have proved to have effect on infrastructure development. As an example, in 2006, FERC issued Order 678 which sought to incentivize the building of more storage by changing its regulations on market power requirements for underground storage. Since the order was issued, total storage capacity has increased by 169 Bcf, or 2% of overall storage capacity. This compares to a 1% increase in the previous three-year period [10]. Therefore, government should continue their efforts in creating incentives for producers to invest in more infrastructure development. Therefore, given the recent increase in the domestic supply of natural gas, infrastructure development must quickly adapt to meet the increasing demand from consumers. Infrastructure development provides huge economic benefit on the use of natural gas. Building new pipelines is essential to enhance the nation s pipeline network to ensure efficient and rapid natural gas transportation to households and businesses. Furthermore, maintaining existing pipelines is also important to prevent gas leaks that would result in lower the costs to consumers. Storage technology must also be invested to ensure adequate supply can reach to new regions of the nation. Increasing policy support and funding from the government are needed to support the 18

19 rapid development of natural gas infrastructure. As the development of infrastructure catches up with the domestic supply of natural gas, it will allow the nation to not only increase the use of natural gas (which emits less carbon than other non-renewable resources), but also stabilize gas prices across regions. Economic Impact on the U.S. Economy The natural gas industry contributes to the US economy on many levels. From upstream activities such as oil and gas extraction and well drilling, to downstream activities like refining, product sales and pipeline constructions, the natural gas industry has not only directly impacted the U.S. economy, but it has also indirectly impacted the economy. Here, we define direct impact as the effect of the core industry s output, employment and income. Any changes in the purchasing patterns or activities by the unconventional oil and natural gas segment initiate the indirect contributions to all of the supplier industries that support unconventional activities. To see the direct and indirect impacts, this section breaks down the industry s contribution on a national level, as well as by state and industry. On a national level, the natural gas industry directly and indirectly adds-value to national GDP growth, employment, labor income and tax revenue. Since natural gas resources are not available in all regions in the lower 48 states, analyzing the economic impact of natural gas industry by region and state can also be meaningful. Lastly, this section will also look at how the Barnett Shale transforms Texas economy; we will see that natural gas has a large upside economic benefit that will continue its trend. Economic Impact on National Level We have identified three reports that analyzed the economic impact of the natural gas industry on a national level. The PwC, on behalf of API, publishes a report in 2011 that studies 19

20 the economic impact of the oil and gas industry to US economy in 2009 [22]. PwC subsequently published another report in 2013 that analyzed the oil and gas industry s economic impact in 2011 [23]. Since PwC s studies are very comprehensive, it is widely used by other studies as a benchmark. In this section, we will be comparing these two reports with the IHS Report (2009) that analyzed the contributions of natural gas industry to US economy in GDP Growth Table 2. National-level studies on value added on oil and gas industry, $billion Study Scope and Year Direct Indirect and Induced Total PwC (2013) Oil and gas in , PwC (2011) Oil and gas in , IHS (2009) Natural gas in According to PwC, the oil and gas industry produced $465 billion of direct value added and $617 billion of indirect and induced value added in In total, this accounts for 7.7% of GDP. The value-added on oil and gas industry has increased in 2011, in which the total impact has risen to $1, billion. This represents an 11.80% growth from The industry s impact in 2011 accounts to 8% of US GDP [22]. The impacts of the oil and gas industry are felt throughout the economy. In forecast to future trend of gas industry and its contribution to US GDP, a report by McKinsey Global Institute estimates that between now and 2020, shale gas and oil will add $380 billion-690 billion, or two to four percentage points, to America s annual GDP, creating 1.7 million permanent jobs in the process [24]. Another report by the IHS predicts a $533 billion boost to GDP by 2025, creating around 3.9 million jobs. 20

21 Labor Market Table 3. National-level studies on employment in oil and gas industry, 000s Study Scope and Year Direct Indirect and Induced Total PwC (2013) Oil and gas in ,590 7,242 9,833 PwC (2011) Oil and gas in ,192 6,968 9,160 IHS (2009) Natural gas in ,206 2,828 In the US, jobs in the energy sector have nearly doubled since After the recent recession, energy sector jobs have grown at a faster rate than any other industry [24]. According to IHS Global Insight, the total natural gas employment was nearly 3 million in 2008 [25]. PwC s report estimates that, at the national level in 2011, the oil and natural gas industry s operations directly and indirectly supported 8.4 million full-time and part-time jobs in the national economy. Further, the industry s capital investment supported an additional 1.4 million jobs in the national economy. Combining the operational and capital investment impacts, the oil and natural gas industry s total employment impact on the national economy amounted to 9.8 million full-time and part-time jobs in 2011, accounting for 5.6% of total US employment [23]. A report by Interstate Natural Gas Association of America (INGAA) projects that an investment of $641 billion for midstream infrastructure will yield an annual average of roughly 432,000 jobs across the United States and Canada throughout its projection period, 2014 to These jobs include those necessary to manufacture and construct infrastructure, and the indirect and induced jobs linked to that process [26]. 21

22 Labor Income Table 4. National-level studies on labor income in oil and gas industry, $billion Study Scope and Year Direct Indirect and Induced Total PwC (2013) Oil and gas in PwC (2011) Oil and gas in IHS (2009) Natural gas in IHS s report estimates that in 2008, the natural gas industry alone contributed $181 billion of labor income [25]. According to PwC, the US oil and natural gas industry s direct labor income in 2011 is estimated to be $203.6 billion, which represents a 15.5% growth from Indirect and induced impact on other industries is $394.0 billion [22]. Tax Revenues Oil and gas companies pay significant taxes. Not only do they pay the standard federal and state corporate income taxes like other companies pay, upstream companies also pay severance and ad valorem taxes based on the amount of hydrocarbon they produce. They also pay bonuses and royalties to the owners of the mineral interests from whom they are leased. Interestingly, the largest mineral interest owners are the federal and state governments. In addition, oil and gas companies also pay significant other taxes directly, such as excise fuel taxes, sales, property and use taxes [27]. A report by IHS Global Insight estimates that in 2012, unconventional gas activity contributed around $31 billion in federal, state and local tax receipts. By 2020, total government revenues contribution to reach $58 billion. The same report estimates that cumulatively, unconventional gas activity will generate more than $1.36 trillion in tax revenues between 2012 and 2035 [28]. To put in context, $31 billion in associated federal taxes is sufficient to fund close 22

23 to 80% of the U.S. Department of Interior annual budget ($11 billion), the US Department of Commerce budget ($11 billion), and NASA s budget ($18 billion) combined [28]. Economic Impact by Region and State Since gas wells are concentrated only in certain areas of the US, not all states are economically impacted in the same extent. Indirect and induced effects of the industry typically occur within a state, and then cross into other states. Therefore, the state analysis reflects how higher diversification of industry exhibits a higher multiplier effect [27]. From a research conducted by the IHS, in 2012, among the states that produce natural gas, the top 10 states that generated the most jobs through unconventional oil and natural gas activity created a total of nearly 1.2 million jobs. This figure is expected to increase 70% and exceed 2.3 million by 2035 [29]. Table 4 provides the list of the top 10 producing states, as well as its current and projected jobs created. Based on 2012 data, Texas is the state that accounts for the most jobs attributable to the oil and gas industry (32.94%), followed by Pennsylvania (5.87%), California (5.52%), Louisiana (4.52%), Colorado (4.44%) and so on [29]. These 10 producing states accounted for 75% of the total value added to US GDP in Certain states unconventional oil and gas activities also drive unemployment down. North Dakota, for example, has the lowest unemployment rate among all states in 2013, which is just 3% [30]. In terms of GDP, these 10 states contributed $178 billion in 2012, which accounts for 75% of the total US value added from unconventional oil and gas activity across the nation. Furthermore, for Texas and North Dakota, unconventional oil and gas activities in 2012 represented around 7.4% and 15% of the states total economic activities respectively [29]. The contribution to economic growth is expected to roughly double over the 10 years. IHS report also expects technological advancement to be fueling the industry s expansion, which would improve productivity in states such as Ohio and North Dakota [29]. 23

24 Table 5. Unconventional oil and gas producing states: top 10 employment contributions [25] (Number of workers) Texas 576, , ,179 Pennsylvania 102, , ,360 California 96, , ,270 Louisiana 78,968 97, ,903 Colorado 77, , ,363 North Dakota 71, ,240 57,267 Oklahoma 65, , ,387 Utah 54,421 51,859 67,052 Ohio 38, , ,624 Arkansas 33,100 52,539 56,418 Top 10 Total 1,195,396 2,034,442 2,306,822 US Total 1,748,630 2,985,176 3,498,694 Case Study: Economic Impact of Barnett Shale in Texas Texas has consistently outperformed the other states in creating jobs since the beginning of 2008 s financial crisis and the discovery of the Eagle Ford Shale play. From July 2009 to June 2011, 49% of all new jobs created in the U.S. came from Texas, and most of those jobs were the result of the state s oil and natural gas activity [31]. PwC s study found that Texas oil and natural gas industry supports, directly and indirectly, 1.9 million jobs in 2011, which is 13.6% of the state s total employment that year. In the same year, Texas labor income supported by the oil and natural gas industry was $144 billion, which is 18.7% of the state s total labor income [23]. In particular, supporting jobs by hydraulic fracturing and horizontal drilling activities have reached 576,084 in It is expected to rise 27.3% by 2020 [32]. Among the various oil and gas sites in Texas, the Barnett Shale contributes a significant portion of the economic growth of the region. The Barnett Shale is located at Northern Texas. Since drilling activity began to escalate in the early 2000s, Barnett Shale has contributed to Texas economy tremendously. More than 15 Tcf of natural gas have been produced from the 24

25 Barnett Shale since 2001 [33]. The Perryman Group, an economic research and analysis firm based in Texas, conducted a study in both 2011 and 2014 on Barnett Shale s economic impact in Texas. Studies found that despite reduced drilling and fluctuating natural gas prices, Barnett Shale production increased by $700 million since the last study was conducted in The study of the fiscal contributions of the Barnett Shale finds that the current regional gains in business activity and tax receipts related to oil and gas exploration include $11.8 billion in gross product per year and more than 107,650 permanent jobs [33]. For the state of Texas as a whole, the report estimates that activity within the Barnett Shale has generated $120.2 billion in GDP and over 1.1 billion jobs since Tax revenue to both local and State government is estimated to close to $11.2 billion [33]. Over the next decade, the Perryman Group expects activity in Barnett Shale to continue generating an extra $153.4 billion in value-added and creating 1.4 million more jobs in Texas [33]. Therefore, through estimating the natural gas extraction and production activities on national and regional level, we are able to understand the industry s enormous economic impact to the U.S. economy. As exploration and production activities have already created millions of jobs and billions value-add to US GDP, these trends are expected to continue for the next decades. The Impact of Shale Gas on the Electric Generation Industry Over the past decade, natural gas has become increasingly important in the electric generation industry. This is apparent by looking at the trends in the composition of fuel sources (Figure 8), as the total amount of electricity being generated by natural gas has been steadily 25

26 Electricity Generation (Mwh) increasing [34]. While coal has been the largest source of electricity in the past, the use of coal has declined as the use of natural gas has increased Year Coal Petroleum Liquids Petroleum Coke Natural Gas Other Gas Nuclear Hydroelectric Conventional Renewable Sources Excluding Hydroelectric Hydroelectric Pumped Storage Other Figure 8. US total electricity generation by energy source [34] The large amount of unconventional gas on the market has led to one direct and immediate impact on the electricity industry: lower natural gas prices. This, combined with an increase in average coal prices, has led to the predictable switching from coal to natural gas for electricity generation. Figure 9 highlights the gradual increase in average coal prices, even as the average cost of natural gas has dramatically fallen over the past decade [34]. Figure 9. Average cost of fossil fuels to electricity generation [34] From inspecting Figure 8 and Figure 9, it is apparent that 2012 is a remarkable year. Not only was the difference between the amount of electricity generated by coal and natural gas the 26

27 smallest over the past decade, but the difference in the costs of coal and natural gas were also the smallest as well. The data represented by the two figures suggest that the spread in prices is correlated with the share of natural gas used in electricity generation. Intuitively, this makes sense, as a smaller spread incentivizes electricity producers to switch from coal to natural gas. Although the average cost of coal has consistently been lower than the average cost of natural gas, as shown in Figure 9, natural gas may still be economical if the spread between the two is small enough. This is because the heat efficiency of natural gas-powered plants is typically more efficient than those of coal-powered plants. As of 2012, the average operating heat rate for coal plants was 10,498 Btu/kWh, compared to that of 8,039 Btu/kWh for natural gas plants. Figure 10. Average operating heat of coal-powered plants vs. natural gas-powered plants [35] Figure 10 shows the changes in average operating heat rate for coal and natural gas plants in the 10-year period from 2002 to 2012 [35]. And while the efficiency for natural gas-powered plants has continued to improve (a lower number is better), coal-powered plants have become increasingly inefficient. The increasingly better efficiency of natural gas-powered plants compared to coal-powered plants is another dimension that explains why more natural gas is being used for electricity generation. 27

28 So far, we have established that natural gas generated electricity, under certain conditions (the spread between coal and natural gas prices is low enough and a given natural gas power plant is efficient enough), is economically preferable to coal generated electricity. But it remains to be seen who benefits from this switch: are end-users benefitting, are producers benefitting, or is it a combination of both? Looking at the average retail price of electricity to customers can tell us whether or not the switching from coal to natural gas has benefitted end-users. Figure 11 shows the average retail prices to residential, commercial, and industrial customers, as well as a weighted average of the four in the 10-year period from 2002 to 2012 [36]. Figure 11. Average retail price of electricity to different end-users [36] As we can see, the red line (total weighted average) shows that the average retail price of electricity has slowed beginning in This coincides with the increased consumption of natural gas and the decreased consumption of coal in 2008 as shown in Figure 8. While it appears that residential electricity prices have still increased since 2008, the average retail price 28

29 of electricity for the transportation, commercial, and industrial sectors have all stayed level or decreased since The relationship between decreasing electricity prices and decreasing natural gas prices can be shown more clearly by comparing states with an increasing share of electricity generated by natural gas, compared to all other states. Research by the Federal Reserve Bank of Kansas City has shown that in states with increasing share of electricity generated by natural gas, residential electricity prices declined an average of 6 percent, while all other states increased an average of 5 percent [37]. While the figures only pertain to residential electricity prices, it is reasonable to assume that the same relationship holds across all sectors: that an increasing share of natural gas electricity generation leads to lower electricity prices. Thus, it is safe to claim that the extraction of large amounts of natural gas from shale reserves has led to a decrease in electricity prices. Projecting future electricity prices and the impact of natural gas proves more difficult. In 2012, the cost of natural gas was 86 percent of the total production cost of electricity, while the cost of coal was 76 percent of the total production cost [37]. Thus, future electricity prices will largely depend on the future prices of both natural gas and coal. While coal prices have stayed relatively constant, natural gas prices have traditionally been much more volatile (Figure 9). Furthermore, it appears that the historically low prices of natural gas in 2012 are unsustainable, as projections from the reference case of the Annual Energy Outlook 2014 project for a real annual growth rate of 3.7 percent from 2012 to However, electricity prices are only expected to increase at a real annual growth rate of 0.4 percent from 2012 to 2040 as the share of natural gas consumption is expected to overtake coal around 2035 [38]. 29

30 There are many positives of using natural gas in the electricity generation industry. First and foremost, natural gas has been a downward pressure on the price of electricity, as natural gas prices have fallen dramatically due to the dramatically increased supply. Furthermore, the price of natural gas is not expected to rise greatly in the future, and the shift to natural gas is likely to be sustained in the future. In the residential sector, lower prices means that families spend less on electricity, increasing their disposable income. In the commercial and industrial sectors, lower electricity costs translates to lower overhead costs and lower production costs, increasing the profitability and competitiveness of businesses. The Impact of Shale Gas on the Manufacturing Industry In 1997, industrial consumption of natural gas in the United States was 8,510,879 million cubic feet (MMcf). Consumption levels gradually fell to 6,167,371 MMcf in 2009, before rising up to 7,413,918 MMcf in 2013 [39]. One simple explanation for the change in industrial natural gas consumption is price. As prices of natural gas rise, manufacturers may find alternative sources of energy or fuel for their factories. In cases where alternative sources of energy may not be economically viable, factories may even have to close. On the other hand, as prices of natural gas fall, manufacturers may find natural gas more attractive. 30

31 Figure 12. The relationship between price and consumption of industrial natural gas [40] Figure 12 shows an inverse relationship between price and consumption of industrial natural gas. The relationship between the two variables is quite strong, with a correlation coefficient of In the explanation given above, manufacturers react based on the price of natural gas. However, supply is more inelastic in the short run, due to possible factors such as preexisting contracts in the supply chain and the fact that capital is typically fixed in shorter timeframes. Thus, the industrial consumption of natural gas, a proxy for industrial output, should be reactionary based on the price of natural gas. In fact, the correlation coefficient between price and consumption of natural gas, when given a delay of one year, becomes a more robust -0.88, supporting the explanation that natural gas consumption is inversely related to natural gas price. 31

32 One particular sector that highlights the important of natural gas prices is the production of ammonia. Ammonia has many uses, including in fertilizers, cleaners, and as a refrigerant. Natural gas makes up between 70-90% of the cost of producing ammonia, and as a result ammonia production is highly affected by swings in the price of natural gas [41]. Indeed, in the time period from , as industrial natural gas prices rose (Figure 12), annual U.S. production of nitrogen-fixed ammonia fell from 11,800,000 tons to 8,190,000 tons [42]. During the same time period, the number of ammonia plants in the U.S. fell from 40 to 25 [43]. As the price of industrial natural gas began to fall in 2008, annual U.S. production of nitrogen-fixed ammonia increased from 7,870,000 tons to 8,730,000 tons in 2012 [42]. While only 77 percent of production capacity was used in 2006, it increased to 85 percent in 2012 [41][42]. When considering capital investment opportunities for new ammonia production plants, the size of plant effects the cost structure due to economies of scale. It is estimated that the cost of natural gas is around 50 percent of the levelized cost for a plant that produces 516,000 tons of ammonia, and that proportion increases as the size of the plant increases as well [44]. Low natural gas prices will support new plants to be constructed in the U.S. Until recently, no new ammonia plants had been constructed in the U.S. for over twenty years. In 2013, Incitec Pivot Limited announced plans to construct an $850 million ammonia plant in Louisiana. In the same year, CF Industries announced plans for a $1.7 billion fertilizer plant in Iowa [41]. The boost in industrial output is not only restricted to ammonia or the fertilizer industry. The American Chemistry Council estimates that as of September, 2014, a total of 197 chemical industry investment projects have been publicly announced, valued at $125 billion. They estimate these projects will lead to an increase of 407,000 direct and indirect jobs, as well as $274 billion in new economic output [45]. Even if these projections are optimistic, it is clear that 32

33 low natural gas prices as a result of shale gas have had a positive impact in at least some areas of the U.S. manufacturing industry. Although low natural gas prices may be beneficial in some industries, its effect may be limited in scope. One study published by The Institute for Sustainable Development and International Relations identified four manufacturing sub-sectors that use a significant amount of natural gas as feedstock. These four sub-sectors are petrochemicals, nitrogenous fertilizers, plastics materials and resins, and other basic organic chemicals, but combined together they only represent less than 0.5 percent of U.S. GDP. Even including other sectors that consume a significant amount of natural gas and its derivatives as a fuel, the number only increases to 1.2 percent of total U.S. GDP and less than 8.7 percent of the U.S. manufacturing sector [46]. Since natural gas is not significantly used in the majority of the U.S economy, the authors project that the long term effect of shale gas on the U.S. economy will be limited to a 0.84 percent overall increase between 2014 to Considering that the Federal Reserve projects a target of a percent increase in real GDP in the long run, an increase of 0.84 percent over 27 years is minimal [47]. In another study published by Stanford, the impact of shale gas was even less, providing an overall boost of about 0.46 percent from 2014 to 2035 [48]. The large amounts of shale gas have caused a decrease in the price of natural gas. As natural gas price has an inverse relationship with industrial gas consumption, shale gas has led to increased productivity in the manufacturing sector. One example of this is the production of ammonia and the larger petrochemical sector as a whole. Low natural gas prices have also encouraged the investment of new chemical industry investments in the United States. However, sectors that consume a significant amount of natural gas are minuscule when compared to the 33

34 larger U.S. economy. In that respect, shale gas has a positive, but limited impact on specific sectors of the manufacturing industry in the U.S. III. Costs of Shale Gas 1. Environmental Costs Several elements of the process of hydraulic fracturing are inherently hazardous to the health of human beings. These include the silicate used to hold shale pores open during the drilling and operation of a fracking well, the methane extracted by the well (as well as the methane that escapes during the extraction process), and the chemical mixture used to treat the well for maximal efficiency (henceforth referred to as fracking fluid). Silicate is a known carcinogen and irritant, while methane exposure can be toxic to humans, and fracking fluid may contain several hundred distinguishable chemicals, including carcinogens, radioactive elements, heavy metals, eye and organ irritants, toxins, and corrosive and volatile chemical agents. The amount of fracking fluid used per well and the composition of fracking fluid is almost always information that is protected by various trade secret regulations, so it is next to impossible to quantify the risk of any specific type of poisoning or sickness induced by fracking fluid exposure. In this section, risks associated with each element will be explained and assessed. 34

35 Figure 13. Fatality rates by state, with North Dakota in the lead [49] Worker Mortality and Morbidity The hydraulic fracturing process is particularly dangerous to workers based on the volume and inherent hazard of the chemicals whose use in the process is unavoidable, as well as the exemptions from worker safety regulations to which oil and gas industries in the United States are privy. The National Institute of Occupational Safety and Health places the national average for worker deaths in the oil and gas industry in 2012 at 27.5 per 100,000 workers, where the national average of workplace fatalities for all industries was only 3.4 per 100,000 workers. However, regionally, rates of fatalities among oil and gas workers were extremely variable. In North Dakota (a region where extraction of gas predominately uses the hydraulic fracturing technique), the average rate of fatalities among oil and gas workers was 75 out of every 100,000 workers, while in Texas, the state with the greatest number of oil and gas worker fatalities, the rate of fatality was 27 deaths per every 100,000 workers, much nearer to the national average. 35

36 However, West Virginia was the state with the highest rate of death per active drilling rigs, with 10.6 deaths per 100 active rigs in To give an idea of the scale of the yearly number of deaths related to oil and gas extraction, the total number of reported fatalities in the United States oil and gas industry in 2013 was 112, down from 142 in 2012 [49]. The leading cause of worker death associated with oil and gas production is transportation-related. Between 2003 and 2012, 38.2% of oil and gas worker deaths were related to transportation, 26.2% were related to contact with objects and equipment, while 13.2% were related to fires and explosions, 7.9% were related to materials exposure, and 5.8% were related to falls or slips. An additional 0.5% of deaths (6 deaths total) were related to violent injuries by persons or animals. Although the vital role trucking and transport plays in the extractive industry (particularly in the case of natural gas extraction via hydraulic fracturing, in which roughly truck trips occur per well per fracturing event) can partially explain the high rate of transportationrelated deaths in the oil and gas industry, policies exempting the oil and gas industry from standard transportation safety regulations potentially exacerbate the problem. While drivers of most commercial vehicles must spend at least 34 hours off duty in order to reset their accumulated hours (above which they are not permitted to work), drivers of commercial motor vehicles that are exclusively used for oil and gas-related transport are permitted to reset their cumulative hours worked after only 24 hours. Additionally, while time spent waiting is usually considered on-duty and therefore counts towards the maximum 14 hours that a driver may consecutively spend behind the wheel, time drivers spend waiting at gas sites counts as offduty and does not count towards workers consecutive hour counts [50]. This means that oil and gas drivers may be expected to (alertly) wait for an unspecified number of hours, then expected 36

37 to drive up to 14 consecutive hours afterwards. This increases the risk of driver inattentiveness and rate of fatigue among drivers, increasing the risk of accidents. Worker deaths related to blowouts, explosions, and contact with object equipment can also be at least partially attributed to loopholes in safety regulations (such as a lack of criminal penalties around workplace safety-related negligence in the Illinois regulations of hydraulic fracturing) and sporadic enforcement of safety standards. Wiseman et al mentions that in some states, violations of environmental and workplace safety regulations may be reported as alleged violations, which give the violator time to respond to the inspectors allegation and do not necessarily require the violation to be fixed, whereas if they were reported as violations, a penalty such as a consent order, a fine, or the institution of a remediation plan would be levied. Additionally, safety and environmental regulations around the fracturing process which are most heavily punished are often procedural violations rather than substantive violations [51]. While OSHA has begun to pursue criminal prosecution of workplace safety violations by the oil and gas industry that result in worker mortality, no further level of protection exists in many states legislation of fracking. For example, under Illinois regulations on fracturing, there is no criminal penalty for failing to build wells to API construction standards in order to minimize the risk of blowouts and explosions. Additionally, Food and Water Watch reports a culture of fear in fracturing-related workplaces, where requests for appropriate safety materials such as hazmat suits are not taken seriously. Accounts of workers expected to climb into produced water tanks and trucks in order to clean them are routinely issued a paper jumpsuit, a hard hat, no mask, essentially no protection are extremely common [52]. In many instances, such blatant violations are not prosecuted simply because they are not inspected: AFL-CIO reports that it would take OSHA (given current levels of staffing and inspection) 131 years to inspect each 37

38 workplace under its jurisdiction once, meaning that while perhaps a sample of fracking-related workplaces may be inspected by OSHA yearly, there is currently no system in place to police every potentially-hazardous extraction-related workplace for violations of workplace safety. The total reported number of workplace deaths that occur from exposure to hazardous materials related to hydraulic fracturing is misleading, because some of the hazardous materials to which workers are exposed are carcinogens expected to cause solid tumor formation over the course of many years, Therefore, we can assume many cancers and chronic diseases that would result from hazardous materials exposure such as exposure to airborne hazards such as silicate and carcinogens such as benzene go unreported. Additionally, illnesses and injuries that are unpleasant but nonfatal (such as chemical or thermal burns, crushed fingers or radiation poisoning) are often not reported or self-reported, because the number of reported accidents can play a role in an employee s future employment prospects (employees who report a high number of on-the-job accidents may be less desirable than those who report none) [52]. One good example of the system of problems described above is the issue of airborne silicate near fracturing sites. Several tons of silicates are generally used as a proppant in each well that is fractured. Silicate particles, up to 100 times smaller than naturally-occurring sand, is highly respirable, and exposure without proper ventilation masks may result in health problems such as thickening of the pulmonary arteries, right heart problems, renal failure, chronic obstructive pulmonary disorder, lung cancer and tuberculosis [53][54]. Rosenman reports that 84% of a representative sample of fracking wells at which airborne silicate levels were measured exceeded maximum permissible levels laid out by OSHA [55]. 38

39 Fracking Fluid Effects on Public Health Fracking fluid, the chemical mixture that is injected into fracking wells, includes anywhere from dozens to hundreds of substances. One estimate places the number of chemicals used in fracturing a single well at 750. These chemical agents include (but are not limited to) corrosives, corrosive inhibitors, intensifiers, bacterial control agents, clay control agents, surfactants, friction reducers, gellants, thickeners, buffers, and gel breakers. Many of these chemicals are known to be hazardous to human health. Some examples of toxins commonly used in the hydraulic fracturing process are ethylene glycol (a chemical commonly used in antifreeze that causes renal and cardiopulmonary failure in humans), BTEX compounds (benzene, toluene, ethylbenzene, and xylene, which are known carcinogens and also have adverse nervous system effects), formaldehyde, arsenic, uranium-238, and other known carcinogens such as lead, naphthalene, and diesel [56][57]. In fact, some chemicals used in fracturing are unknown, due to trade secret protection clauses in the Energy Policy Act of Although these chemicals are not necessarily known, the American Association of Pediatrics advises exposure to fracking fluid either directly or through tainted wellwater or air may have negative neurological, respiratory, cardiovascular, gastrointestinal, renal, urological, reproductive, immunological, mucocutaneous, dermatological, hematopoietic, oncological, and endocrine-related effects [58][59]. Since the Energy Policy Act of 2005 effectively stripped federal-level environmental regulations such as the National Environmental Policy Act, the Safe Drinking Water Act, the Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, Comprehensive Environmental Response Compensation and Liability Act (Superfund), and the Toxic Release Inventory of their potency, companies practicing hydraulic fracturing are exempt from federal minimum standards for contamination, toxic disclosure policies, research and testing requirements, and impact statement requirements [60]. Although states may pass their 39

40 own regulations for companies wishing to use hydraulic fracturing to extract natural gas, states often lack the resources to enforce such policies. Furthermore, states have a vested interest in the creation of lax regulations, because loosely-regulated areas are seen as more appealing (less costly) to business [61]. For these reasons, it is nearly impossible to find unbiased, peer-reviewed or agencysponsored data on the rate of well and groundwater contamination by fracking fluid [62]. Reviewing the effects on public health is equally difficult, especially because proponents of unconventional gas extraction are quick to publish industry-sponsored reports that deny the potential of any contamination or environmental toxicity. Thus, the following paragraphs must be considered in light of the fact that more independent research to determine the extent to which fracking fluid may be able to contaminate water supplies and have detrimental effects on public health absolutely must be carried out. While negative public health effects that are anecdotally attributable to the contamination of water wells by fracking wells are widely documented, there is a conspicuous lack of research demonstrating correlation or causation. For example, it is widely suspected that proximity to fracturing wells has a statistically significant positive correlation to rates of leukemia, which is associated with benzene exposure. Additionally, proximity to drilling at Flower Mound, Texas has been correlated to statistically-significant increases in rates of breast cancer. However, these studies have been subject to much criticism, because they do not appropriately take into account life history variables, meaning they might be over-attributing increased rates of cancer to fracking well proximity. Additionally, the Flower Mound research efforts were short-term studies, which is problematic because solid tumors that develop as a result of chemical exposure may take as long as twenty years to develop. Therefore, the possibility that the Flower Mound 40

41 studies are in fact underestimating the correlation between well proximity and rates of various cancers is also very real. Another set of issues which has successfully been linked to well density and proximity are birth defects, specifically congenital heart defects and neural tube defects [58]. A 2014 study of rural Coloradans found babies born to mothers in the top tertile of well exposure (based on both density and proximity of wells within a 10-mile radius from maternal residence) were 30% more likely to have congenital heart defects than babies born to mothers with no wells in a 10- mile radius. The same study also found the risk of neural tube disorders such as spina bifida in babies born to mothers in the top tertile of well exposure to be 2 times as high as for mothers who did not live within a 10-mile radius of any wells [63]. These findings are corroborated by Lupo et al s 2010 study, which found that mothers living in the areas of Texas with the highest rates of environmental benzene ( ppbv) were 2.3 times more likely to have babies with neural tube defects [64]. Additionally, Wennborg et al s 2005 study of Swedish mothers showed a significant correlation between the rate of neural tube defects in the children of mothers who were exposed to benzene, and those who were not exposed to benzene. In this study, children of mothers exposed to benzene were 5.3 times more likely to be born with neural tube defects than children of mothers not exposed to benzene [65]. While extensive research relating real-world fracturing wells to negative health outcomes is limited, exposure to many of the chemicals used in fracking are known to cause a number of deleterious effects in humans affecting every major system of the body. The American Association of Pediatricians New York branch suggests that in light of a lack of human-based research, veterinary medicine provides a sentinel for potential human health outcomes, and reveals reason to be concerned. [58][66] 41

42 Value of Health and Human Lives Determining the monetary value of a human life is one of the most difficult ethical challenges associated with economics and policy. It is important to note that valuations of human lives made by government agencies are the value of statistical lives rather than individual lives; rather, the value of a human life is actually an estimate of how much people are willing to pay for small reductions in their risk of dying. These values are reported as the aggregate dollar amount that a population would be willing to pay for a reduction in their individual risk of dying in a given year, so that on average, one fewer person from that population per year would die. For example, if a group of 10,000 people were on average willing to pay $1000 to decrease their risk of dying by 1/10000 (0.01%), the value of a statistical life would be set at $1000/person * 10,000 people, or $10 million. When people actually pay to reduce their risk of dying, they usually do so by shouldering a greater cost for goods or services associated with regulations meant to increase safety and reduce risk, or in taxes meant to support the implementation of such regulations [67]. It is important to note that quantifying human value is also a deeply political issue. In policy-related situations, dollar-number estimates of the value of human life ought to be thought of as the aggregate amount of money that a population is willing to spend to prevent one death. Since government agencies consist largely of appointed officials, their values often shift according to the agenda of the political regime under which they operate. For example, one administration might prioritize economic growth or corporate development over environmental protection. This administration would appoint officials likely to set a lower value for human life in order to encourage business (because regulations meant to make businesses take the burden of paying to prevent deaths off the government would be less significant if each life were valued more cheaply). In an administration that prioritized worker safety or environmental protection 42

43 over the expansion of business, officials likely to set higher values of human lives are appointed (in order to create appropriate economic grounds for strong environmental or workplace safety regulations) [68]. One good example of this effect is the discrepancy between United States Environmental Protection Agency s estimates for the value of human life under George W. Bush s pro-business administration ($6.8 million) and Obama s pro-environment administration ($9.1 million). Estimates also vary between agencies due to different agency priorities. For example, the Department of Transportation thinks of prevention of death in terms of vehicular accidents and vehicle safety standards, as well as speed regulations and signage, while the Environmental Protection Agency thinks of prevention of death in terms of pollution cleanup and prevention. Since humans can die in more or less costly ways (cancer deaths, which are lingering and is costly in terms of healthcare versus a traffic accident death, which is instantaneous), agencies must also consider the type of death they are paying to avoid. For this reason, the Environmental Protection Agency consistently assigns higher values to human lives than the Department of Transportation, because deaths associated with environmental pollution are typically more prolonged and costly to the system than deaths associated with transportation. Additionally, the Environmental Protection Agency has added a cancer differential to its estimate: this additional clause stipulates that up to 50% more should be paid to prevent cancerrelated deaths than instantaneous types of death [63]. Another method of calculating the value of a human life is the insurance-calculation method. This is better suited towards the calculation of an individual s monetary potential at any given point in time, based on tax rate, health, projected income, and amount of productive time left in the workforce [69]. We will not use this method because our cost-benefit analysis is meant 43

44 to provide insight into appropriate risk-reduction policies around unconventional natural gas extraction, rather than around individual remunerations for extraction-related injuries. Potential Effects on Water Resources One of the greatest arguments against the extraction of natural gas from American shale plays is the negative impact hydraulic fracturing can have on water resources. The argument that fracturing for natural gas is detrimental to water resources has several facets: first, the amount of water used in the fracturing process is extremely large. Second, water used in fracturing cannot necessarily be returned to the water cycle due to the toxicity it gains from being mixed with other chemicals during the process of fracturing. Third, there is no method of fracturing which guarantees methane and other chemicals do not seep into the water table (either during the fracturing itself, or from wastewater disposal wells), causing environmental toxicity and potentially destruction of natural filtration systems. Resource-Intensiveness of the Hydraulic Fracturing Process The process of hydraulic fracturing is extremely resource-intensive, especially in terms of water. It is estimated that 2-12 million gallons of water are required to fracture a single horizontally-drilled well, with different amounts of water required for varying depths of wells, which translates into the creation of approximately 882 billion gallons of produced water, or post-fracturing wastewater per year in the United States alone [70]. This amount is especially significant in light of the fact that fracking wastewater ought not to be returned to the water cycle, because no technologies currently exist to thoroughly remove toxins. As the global population increases, so does the demand for fresh water, which is used for direct human consumption and agriculture. Critics of fracturing claim the process jeopardizes freshwater resources in three major ways: first by using freshwater in a way which renders it toxic and largely untreatable, second, by allowing it to leach into groundwater and surface water reserves, 44

45 rendering them toxic and unusable; and third, allowing a large fraction of the water used to be reinjected or simply left in the ground, rendering it unusable [71]. Toxicity and Obstacles for Treatment of Wastewater Although most industrial and non-industrial uses of water are such that the water can be treated in municipal water treatment facilities, then effectively returned to the water cycle, wastewater produced in fracking poses several additional problems which prevent it from being effectively treated. Post-fracturing wastewater is comprised of the injected freshwater, the chemical mixtures injected, meaning fracking wastewater must be treated of several hundred (potentially toxic, carcinogenic, or radioactive) chemicals, but is also briny and somewhat radioactive. Currently, produced water is dealt with in one of the following ways: disposal by injection in deep underground wells; disposal into surface waters such as rivers after some chemical treatment; or recycling into future fracturing efforts, with or without treatment. The EPA cites several major problems with treatment of fracking wastewater using standard water treatment methods. For example, in chemical wastewater treatment systems, chemicals involved in fracking interact with chemical disinfectants to form complex and toxic byproducts such as trihalomethanes, haloacetic acids, bromate, and chlorite [70][72]. In biological treatment systems, where bacteria are used to remove toxins from water, high levels of chlorides cannot be removed by biological treatment systems. Additionally, high levels of mineral salts in the fracking wastewater change the osmotic pressure of biological treatment systems, killing the operative microorganisms and reducing the efficacy of the treatment system [73]. Contamination of Groundwater The object of hydraulic fracturing creating pathways for natural gas trapped in deposits of shale to reach the surface is precisely what makes the chemicals and fluids used in the process difficult to contain. Fractures in the rock which allow natural gas to escape and be 45

46 recovered may also serve as pathways for fracking fluid to travel. Indeed, the fracking fluid often continues to migrate along these pathways even after the process of fracturing is completed, due to the high levels of pressure at which the fluid is injected in the first place. This is especially problematic when manmade fractures in the rock extend into shallow rock areas used by humans for water resources, or connect with natural flaws in the rock which are linked to underground reserves of water, which not only allows methane to migrate into potential sources of drinking water, but also the chemical mixture used for fracturing itself (see Figure 14) [74][75]. Another way in which fracking fluid or methane might leach into ground water is through the failure of a well casing. Contamination of surface and ground water is a great concern when fracking wastewater is spilled accidentally, when it is improperly disposed of, and when it is allowed to reenter the water cycle without significant treatment. Some researchers also argue that produced water, post-treatment, ought not to be released into surface waters for fear of contamination of aquatic environments, and increased environmental toxicity [76]. Figure 14. Pathways for fracturing-related water pollution [133] 46

47 Induced Seismicity Induced seismicity refers to earth tremors and quakes associated with anthropogenic activity. The types of human activity which have historically caused seismicity are generally ones which cause the levels of stress, friction, and porosity of the earth s crust to vary. There are two clear ways in which this effect can cause tremors. First, the alteration of underground structures can allow groundwater to seep into faults, changing the pore pressure of the rock along the fault, making it more likely to slip more easily, allowing the fault to fail. Second, changes in the amount of material placing stress on a fault increase the possibility of slipping along that fault. This is especially true in the case of creation of formations such as large surface-level or subterranean lakes through damming or through the deep injection of wastewater. In cases such as these, both ways (seeping water increasing porosity along faults, and change in stress on the fault via increased mass and volume of matter exerting pressure) can increase the porosity of the rock, which allows the rock to slide more easily when shear stress is introduced, allowing the fault to fail [77]. The seismic events which have been shown to have a direct causal link to human activities have historically been of relatively small magnitude, and confined to nearby the site of the manmade activity. Typically, seismic events associated with the drilling and fracturing of a natural gas well are negligible in magnitude. However, the process of hydraulic fracturing has been shown to be associated with the increased magnitude of small-scale seismicity, even in zones that are not typically seismically active. For example, However, the process of wastewater injection presents a greater seismic risk. Under EPA regulation, wastewater from natural gas production must be disposed of in Class II wells, which are generally feet deep. There are approximately 144,000 Class II wells currently in operation in the continental United States, of which approximately 30,000 are disposal wells. 47

48 The injection of fluids into each of these wells creates a network of fractures in the surrounding rocks, and increases the porosity of rock where fluid is injected [78]. This effect itself is associated with increased rates of small-magnitude seismic events, and increased risk of larger seismic events, but the most concerning risk associated with injection of waste fluids is the possibility that these manmade fracture networks may be triggered by large, remote, naturallyoccurring quakes. Although large trigger earthquakes would ordinarily apply pressure on natural faults and could cause minor aftershocks, manmade fault networks are more susceptible to major slipping based on high porosity inherent to this type of fault network, and also because there are so many such manmade fracture networks. When one system of manmade fractures fails, resulting in earthquake, the risk of other nearby fracture networks doing the same skyrockets, due to the change in position and pressure of rock along the manmade fault cracks that occurs after the initial earthquake event [79]. 48

49 Figure 15. Top: Map of seismic risk by region, taking likelihood and potential magnitude of seismic risk into account. Red indicates highest risk, while grey indicates lowest risk. (United States Geographical Survey, 2014) Bottom: Map of viable shale plays in the Lower 48 United States. Pink areas indicate shale plays, while purple regions indicate shale basins. (United States Energy Information Administration, 2014) One example of a large earthquake believed to be caused by this ripple effect was the 2011 M5.7 earthquake in Prague, Oklahoma, which was most likely triggered by an M8.8 earthquake in Maule, Chile. This is notable for several reasons: first, because before the creation of injection wells, Oklahoma had no history of any large-scale seismic activity; and second, because the epicenter of the triggering earthquake was well over a thousand miles removed [77]. Another particularly worrisome possibility pertinent to the process of hydraulic fracturing (which I argue must necessarily include the process of wastewater injection, because no costeffective alternative exists to dispose of or treat produced water), is that of large-scale natural seismic activity in the central United States, which could trigger a swarm of large-scale seismic 49

50 events throughout every system of man-made fracture which exists. This possibility is especially concerning because the Wabash and New Madrid seismic zones, spread throughout the southern edge of the Midwestern Marcellus Shale, have been listed by USGS as high-risk. Many scientists believe this area is due for an earthquake on the scale of M7-M8. Since the most recent major seismic event on the New Madrid fault occurred in 1811, it is quite conceivable that another such event could occur at any time. This large-scale event would have the potential to trigger powerful aftershocks in both natural and anthropogenic faults [80]. Another terrifying possibility related to a New Madrid-triggered series of quakes would be that any injection wells even remotely near the Mississippi, Missouri, Ohio, or Wabash River floodplains could increase the risk of soil liquefaction in the case of a large seismic event. It is predicted that in the case of any seismic shock over M6.8, the silty soil and high water table of this region would allow the water pressure to rise to the point where soil particles could move freely, causing the foundations of bridges and other architectural foundations to become extremely unstable. Soil liquefaction could cause the collapse of many man-made structures, increasing the potential of earthquakes in this region to cause widespread loss of property and loss of life. Liquefaction also has the potential to disrupt any drilling or hydraulic fracturing wells in the region, to cause methane leaks as a result of compromised wells, and to cause leaks of highly radioactive, toxic produced water, which could permanently contaminate surface and ground waters. Greenhouse Gas Footprint Natural gas has been widely touted as a bridge fuel meant to ease the transition between traditionally dirty sources of energy such as coal and cleaner sources such as renewables without provoking the economic and infrastructure stresses a complete renouncement 50

51 of fossil fuels would. It is also widely stated in the popular sphere that natural gas has a smaller greenhouse gas footprint (and therefore a smaller potential to cause global warming) than other fossil fuels such as oil and coal. This is because when natural gas is burned, fewer units of carbon dioxide are produced per unit energy than when coal or oil is burned, as well as fewer additional pollutants. Per megajoule of energy produced, coal emits 92g of CO 2, oil emits 78g, and natural gas emits 56g. However, the assertion that natural gas is overall cleaner is problematic because it neglects lifecycle methane emissions associated with natural gas [69]. Natural gas is composed primarily of methane, itself a potent greenhouse gas. In terms of potential climate effects, methane is 25 times as potent as carbon dioxide (one mole of methane in the atmosphere would cause roughly 25 times the warming effect that one mole of carbon dioxide would) [81]. Once natural gas is burned for energy production, the most serious greenhouse gas byproducts which remain are carbon dioxide, meaning that the releasing a quantity of unburned natural gas into the atmosphere is actually worse on a short time frame than burning the same quantity of natural gas. However, carbon dioxide takes roughly 120 years to decay in the atmosphere, methane takes only roughly 10 years to decay. These measures of potency are complicated by the fact that methane reacts photochemically in the earth s atmosphere to form ozone (O 3 ), carbon dioxide (CO 2 ), and water vapor, all of which have additional global warming effects. For every mole of methane present to undergo the photochemical reaction, roughly one mole of CO 2 and 0.7 moles of O 3 would be formed [82]. Therefore, if natural gas that is mostly composed of methane is spilled in the production process, the relative cleanliness of the natural gas in respect to global warming outcomes may be somewhat lessened. Accounting for the varying time scales of greenhouse gas decay, Rodhe estimates that on a timescale of 100 years, methane leaks from natural gas production must be 51

52 limited to less than 4% of total natural gas production in order to break even in terms of greenhouse gas outcomes: that is, if natural gas was to be as clean as oil in terms of greenhouse gas production, no more than 4% of the natural gas present should escape via leaks or vents. If a timescale of less than 100 years is considered, the estimate shrinks to less than 3% because methane decay can be discounted less in the short term than in the long term [84]. Currently, 3.6%-7.9% of methane involved in the life cycle of an unconventional gas well escapes into the atmosphere [84]. This is at least 30% more than rate at which methane escapes from the average conventional gas well (conventional gas wells have lifetime fugitive emissions that range from 1.7%-6%, largely because no leaks occur during the flowback period, because no flowback period exists). Based on the current rate of methane emissions from shale gas wells, Howarth, Santoro, and Ingraffea argue that on the 20 year timescale, shale gas has a greenhouse gas footprint between 20% and 100% greater than that of coal s, while on the 100 year timescale, the greenhouse gas footprints of coal and shale gas are roughly equivalent [82]. Reducing atmospheric methane leaks in the natural gas sector is accomplishable to some extent by altering management practices (such as increasing inspection at pipe joints or areas where leaks are likely)or equipment types (such as making sure all pipes and seals are as efficient as possible), and reducing venting. However, leaks which occur during the drilling process, during the flowback process, and after the well has supposedly been sealed are largely unavoidable [85]. 52

53 2. Economic Costs Natural gas development is often touted for its associated economic prosperity brought to state and local economies. These boons may take the form of added jobs and greater revenue from the drilling crews and other gas-related business that move into the region to extract the resource. Indeed, this is the boom of the boom-bust cycle that characterizes extractive processes of non-renewable natural sources, including natural gas [86]. However, once drilling stops, either temporarily or permanently, there is an economic bust, one that may exceed the positive direct economic impact from the boom. Figure 16. Illustration of the boom-bust cycle in royalties, business income, tax revenue, and jobs [86] Regional Economics There are several reasons for poor long-term economic prospects, despite the booming activity that floods into a region during the drilling phase. First, the crew that enters the region creates extra demand for limited housing stock, which causes housing prices to rise [86]. Low income renters are consequently forced to leave the area, which creates a potential labor 53

54 shortage. It is one that is especially magnified once the crew, which is indeed transient and only remains for the duration of the drilling, departs the area. Businesses in the region are affected by this labor shortage, because labor costs for those occupations rise as a result. Those who are already on the margin may go under during the drilling phase. Dairy farmers in Northern Pennsylvania and the Southern Tier of New York, where the Marcellus Shale play is, are already experiencing this economic squeeze [86]. To use economic terms, these businesses are being crowded out. In general, crowding out mostly affects businesses that require a reliable and cheap labor supply, such as those in the agriculture, tourism, or retirement industries. However, there is an additional effect: higher wage businesses like manufacturers may be deterred from investing in a natural gas extraction company because of the higher housing costs, labor competition, and social issues besieging the resourcedependent region [86]. The overall resultant effect is a region with fewer non-drilling businesses and thus a less diverse and more volatile economy with greater income inequality. Therefore, the short-term winners created in a resource extraction economy are outweighed by the long-term losers. Studies examining other similar resource-dependent regions offer empirical evidence of both population loss and dampened economic growth. For example, Counties in New York and Pennsylvania with significant natural gas drilling experienced greater population loss when compared with similar rural counties in their respective states [87]. The population change from 1990 to 2008 for both states is evident in Figures 17 and

55 Figure 17. Population change in New York State [86] Figure 18. Population change in Pennsylvania [86] 55

56 Additionally, a study was conducted by Headwaters Economics on 26 counties in western US states with a strong economic dependence on fossil fuel extraction in order to assess their long-term economic development. The study demonstrates that these counties, which have at least 7% of their total jobs in resource extraction industries, underperform compared to similar counties without extraction industries from 1990 to 2005 [86]. All of the energy-dependent county economies were similar in that they exhibited less economic diversity, more income inequality between households, and less ability to attract investment. Finally, this study too showed that a majority of the energy industry-focused counties experienced population decline during this period. Infrastructure Trucks are crucial in many parts of the natural gas extraction process. A typical Marcellus well requires 5.6 million gallons of water during the drilling process, which is delivered by truck [86]. Liquid additives and hydrochloric acid are also shipped to the well site on flatbed trucks and tanker trucks, respectively. Millions of gallons of liquid are used in the short (weeks-long) initial drilling period, and it accounts for half of the estimated 890 to 1340 truckloads that are required in total per well site. In addition to the number of trips made, the sheer quantity and corresponding weight associated with each trip are significant as well. The impact of water hauled to one site (364 trips) is the equivalent of about 3.5 million car trips [86]. Not surprisingly, few roads at the town level in New York have been built to withstand such heavy volume of truck traffic. Although access roads to the well sites are built, funded, and maintained by the well operators, many of the trucks nonetheless journey through public roads, which are only maintained by local governments and consequently impact the local economy [86]. One solution that local governments have is to utilize state-level Department of Transportation protocols to post weight limits and require permits, which would make 56

57 overweight truck operators pay for documented damage to the roads. However, operators are inclined to post bonds only in regions where they have well sites. Therefore, the trucks that travel much longer routes through other towns and counties still damage vulnerable public rural roads. The extent of this truck-driven damage is significant. The Texas Department of Transportation reported that the cost to repair roads damaged by drilling activity to bring them up to standard would conservatively cost $1 billion for farm-to-market roads and $1 billion for local roads [87]. In New York, as a result of the Marcellus Shale gas development, the estimate for costs for local roads and bridges ranges from $121 million to $222 million per year [87]. This burden falls directly on local taxpayers, who will be forced to pay the cost of repairing these roads long after drilling has ceased. Although this is certainly a social cost, as will be discussed in a following section, this problem is also an economic cost, and a unique one borne specifically by the local community. These costs are unique in that they are not shared by the transient workers who have simply come to look for temporary work during the initial drilling. Although the drilling phase does provide tax revenue, when the local boom ends, the human and physical infrastructure that has been built to support the boomtown population is left for a much smaller population to support. Furthermore, this burden is not limited to merely road costs: The nature of infrastructure such as roads, sewer, and water facilities, and schools is that once it is built, it generates ongoing maintenance costs (as well as debt service costs) even if consumption of the facilities declines the departure of workers and higher income, mobile professionals [leaves] the burden of paying for such costs to the remaining smaller, lower-income, population [86]. 57

58 One potential solution is called haul route management, which would involve planning, posting, and enforcing truck routes that minimize the intrusiveness and damage caused by highvolume truck traffic [86]. However, while it certainly has the potential to alleviate some road damage, such a solution would represent yet another cost, because it would require planning capacity, additional signage, and law enforcement efforts beyond a local government s normal budget. Indeed, the economic burden associated with infrastructure damage seems to be an inevitable one associated with shale gas drilling. Regional Industrialization s Impacts on Local Industries The industrial landscape brought about by shale gas development is not limited to well pads: water extraction sites and water treatment facilities are also developed, along with pipelines and compressor stations to transmit the gas from the well sites to the main transmission lines [86]. These industrial facilities bring industrial contaminants and potential water, air, and land contamination, all of which negatively impact local industries that have been vital to some of the communities in the shale region [87]. For example, tourism and agriculture are large local industries that are significantly impacted by the perception of environmental contamination. Although industrial plants do contribute local taxes, there is a trade-off between tax revenue from well production and local industry revenue [86]. Often, the taxes are not sufficient to make up for the associated revenue loss. Many of the communities on the Marcellus Shale stand to benefit from tourism revenue: in 2008, visitors spent over $239 million in three counties of New York State s Southern Tier [87]. The tourism and travel sector accounted for 3,335 direct jobs and roughly $66 million in labor income [87]. Furthermore, tourism improves quality of life for residents in the form of restaurants, shops, parks, museums, and other related amenities. These amenities also make a region more attractive for economic investment, but as a result of shale gas development, public 58

59 fears of water, air, and land contamination (realistic fears or not) may permanently mar the public image of rural areas that currently enjoy tourism dollars. Agriculture is an industry that is similarly affected by damaged branding. The president of the Park Slope Food Coop, a large food coop in Brooklyn, NY, opposed shale gas development precisely because the company s members will not want the fruits and veggies that come from farms in an industrial area [87]. Therefore, the growth of local industry and the foregone economic development is an important opportunity cost that should be factored into the analysis of where networks of gas pipelines are constructed. Ineffectiveness of Taxes as a Solution Due to the issue of public costs attendant to high volume hydraulic fracturing (HVHF), taxation has been touted as a potential solution. First, there is evidence that exaction of tax revenues is not pivotal to industry decisions about where to drill for natural gas. Rather, the oil and natural gas industries are guided mainly by the location of reserves [86]. Therefore, production tax incentives would have little effect in influencing energy companies areas of exploration. Additionally, production taxes are downstream taxes, meaning that they are only levied on successfully producing wells, further weakening the possibility of a production tax in discouraging exploration. A property tax has the advantage of delivering revenue directly to the local governments in order to recoup the incurred costs. However, tax revenue is highly localized and variable from year to year, whereas the development of a shale gas play and its associated costs are geographically widespread and long term. This is because the tax would only be generated where gas production is active and would also be dependent on the volume of gas generated. If the locus of new drilling activity moves on, or if the yield declines, then so too does the tax revenue. 59

60 And, as described previously, the local economy will still be left to bear the burden. Therefore, a property tax is hardly effective at generating sufficient revenue to compensate for the public costs associated with the shale gas play. Producer Costs While consumers and local economies experience costs, so too do the producers and drilling rigs that decide to drill in the first place. Naturally, given a limited number of drilling rigs, firms choose to deploy them in those places (within a gas play or across gas plays) where profits are most likely. The question is not whether a well is viable in terms of potentially recoverable gas, but instead whether it is commercially viable. Therefore, energy companies must consider the costs and delivery rates of drilling operations, margins of commercial profitability, and corporate and competitive relationships [86]. The two most prominent costs involve fixed costs of capital for the drilling itself and production rates (especially initial flow). The costs of the capital-intensive fracking process are also enormous. A back-of-theenvelope calculation attributes 25% of drilling costs to fracking and completion. From 2006 to 2010, an average of 43,237 wells were drilled per year, with an average cost of $2.38 million per well [3]. 25% of that number is $595,000, with a range from $345,000 to $863,000. This calculation assumes that every single well drilled is fracked as well, so it represents a lower bound on servicing costs. More expensive wells are even more expensive: a typical Bakken well costs $8 million to $10 million, with about $1.5 million to $2.5 million in fracking costs [3]. Furthermore, drilling costs have increased over time, as depicted in Figure

61 Figure 19. Average cost of new wells of all types at all locations in the US (costs normalized to $2000) [3] There are a few reasons for this increase. First, drilling costs could be increasing because wells are getting deeper. The relative cheaper shallow deposits are drilled first, but when those are exhausted, more resources must be spent on drilling deeper deposits. Second, in order to use more advanced drilling techniques such like directional and horizontal drilling, more sophisticated rigs must be constructed, which have higher rates (on a day or footage basis) [3]. Third, stimulating the reservoir prior to first production, or fracking the well, adds to the drilling costs. Since nearly all wells are fractured, part of the increase is attributable to fracking. Indeed, the marked increase in drilling costs appears to begin from the late 1990s, which is when fracking started to become more widely used. An example of both factors (more extensive rig and more fracking) is the Woodford Shale of Southeast Oklahoma, which shifted from $2 million to $5 to $6 million per well [3]. Lastly, capital levels are difficult to adjust in the short 61

62 term, so prices might be sticky. For example, changing the rig inventory in order to accommodate larger rigs capable of handling deep horizontal wells takes time. In the short run, available rigs might cost a premium, so high costs could represent a temporary shortage of capital instead of a long-term change in cost due to different technology. Regardless of the precise reason, it is certainly clear that costs for producers have only increased over time, and operating companies involved in the shale play bear significant financial risks. Initial flow rate is important to the operator because it provides a large revenue stream to compensate for the capital-intensive development. Smaller independent operators, which drill a majority of wells, are especially concerned about initial production rates because they are heavily dependent on cash flow financing [3]. Ultimate recovery is certainly also an important measure of the value of a well, but the geophysics of extraction cause production to decline over time, so the ultimate recovery is a function of initial flow [3]. Furthermore, this production rate decline is extreme: there is a very steep decline curve early in shale production s life. Fractured wells typically decline hyperbolically, according to the industry projections. This means that the initial decline rate is high, with production later levelling off and continuing, making early production all the more important. However, geologist and investment adviser Arthur Berman, who has analyzed production trends across US shale plays, asserts that most wells do not actually maintain this hyperbolic decline projection. Rather, production rates commonly exhibit abrupt, catastrophic departures from hyperbolic decline as early as months into the production cycle [86]. The possibility that shale plays may not produce the long-term results indicated by the hyperbolic model adds uncertainty and makes it even more difficult for operating companies to cover their finding and development costs. 62

63 Figure 20. Gas production over time for the R. Smith 2H wellpad in the Marcellus Shale Play [88] Figure 21. Gas production over time for 3 wellpads in the Marcellus Shale Play [88] 63