The Potentials and Problems of Expanding Use of Shale Gas in the

Continental U.S.

December 3, 2014

Group 6Cammie Chan, Brendan Fan, Ayhan Kucuk, Crystal Meng,

Roberta Weiner, Rongchen Zhu

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Contents

I. Introduction..................................................................................................................................3

II. Benefits of Shale Gas..................................................................................................................8

1. Environmental Benefits............................................................................................................8

2. Economic Benefits.................................................................................................................10

III. Costs of Shale Gas...................................................................................................................34

1. Environmental Costs..............................................................................................................34

2. Economic Costs......................................................................................................................53

3. Social Costs............................................................................................................................64

IV. Cost-Benefit Analysis..............................................................................................................73

1. Benefits..................................................................................................................................74

2. Costs.......................................................................................................................................77

3. Sensitivity Analysis................................................................................................................81

V. Conclusion................................................................................................................................82

VI. Policy Recommendation..........................................................................................................84

VII. Limitations and Next Steps....................................................................................................85

VIII. Appendix...............................................................................................................................88

IX. References...............................................................................................................................91

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I. IntroductionNatural 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.

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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 2010. 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.

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Figure 2. Shale gas basins in the US [2]

Use of Natural GasUnlike 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 GasThe North American gas market is the largest in the world, with 773 bcm (billion cubic

meters) consumed in 2001. 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

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].

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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 DemandThe 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 MarketThe US has the largest gas market in the world, with 4% of the world’s gas reserves in

2002. 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].

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Figure 3. US Natural Gas production by sources, 1990-2025

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.

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II. Benefits of Shale Gas

1. Environmental BenefitsCompared 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]:

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Table 1

Coal (anthracite) 228.6

Coal (bituminous) 205.7

Coal (lignite) 215.4

Coal (subbituminous) 214.3

Diesel fuel & heating oil 161.3

Gasoline 157.2

Propane 139.0

Natural gas 117.0

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.

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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.

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Shifting Production Profiles Require Additional Pipeline ConstructionPipeline 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

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U.S., estimates that the U.S. and Canada will need approximately 28,900 to 61,900 miles of

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 2008.

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].

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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 2000-2011, 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].

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A report by the House Natural Resources Committee Democratic staff suggests that

American consumers paid $20 billion from 2000-2011 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

2013-2014, 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

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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.

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Figure 6. U.S. working natural gas underground storage capacity [14]

Figure 7. U.S. Underground Natural Gas Storage Facilities, close of 2007 [18]

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Government Initiatives to Incentivize Infrastructure ConstructionThe 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

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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

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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. EconomyThe 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

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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 2008.

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 2011 551.02 658.37 1,209.39

PwC (2011) Oil and gas in 2009 464.57 617.13 1,081.70

IHS (2009) Natural gas in 2008 172.14 212.60 384.74

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 2009. 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 $1,209.39 billion. This represents an 11.80% growth from 2009. 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.

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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 2011 2,590 7,242 9,833

PwC (2011) Oil and gas in 2009 2,192 6,968 9,160

IHS (2009) Natural gas in 2008 622 2,206 2,828

In the US, jobs in the energy sector have nearly doubled since 2005. 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 2035.

These jobs include those necessary to manufacture and construct infrastructure, and the indirect

and induced jobs linked to that process [26].

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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 2011 203.6 394.0 597.6

PwC (2011) Oil and gas in 2009 176.3 357.24 533.55

IHS (2009) Natural gas in 2008 70 111 181

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 2009.

Indirect and induced impact on other industries is $394.0 billion [22].

Tax RevenuesOil 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

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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 StateSince 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 2012. 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].

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Table 5. Unconventional oil and gas producing states: top 10 employment contributions [25]

(Number of workers)2012 2020 2035

Texas 576,084 929,482 733,179Pennsylvania 102,668 220,635 387,360California 96,553 153,658 187,270Louisiana 78,968 97,418 150,903Colorado 77,622 121,398 175,363North Dakota 71,824 114,240 57,267Oklahoma 65,325 149,617 225,387Utah 54,421 51,859 67,052Ohio 38,830 143,595 266,624Arkansas 33,100 52,539 56,418Top 10 Total 1,195,396 2,034,442 2,306,822US 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 2012. 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

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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 2011. 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 2001. 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 IndustryOver 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

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.

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

0

562500

1125000

1687500

2250000

CoalPetroleum LiquidsPetroleum CokeNatural GasOther GasNuclearHydroelectric ConventionalRenewable Sources Excluding HydroelectricHydroelectric Pumped Storage

Year

Ele

ctric

ity G

ener

atio

n (M

wh)

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

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

27

compared to coal-powered plants is another dimension that explains why more natural gas is

being used for electricity generation.

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 2008. This coincides with the increased consumption of

28

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

of electricity for the transportation, commercial, and industrial sectors have all stayed level or

decreased since 2008.

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 2040. However, electricity prices are only

29

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].

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 IndustryIn 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

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 -0.74. 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

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 2000-2006, 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

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 2040. Considering that the Federal Reserve projects a

target of a 2.0-2.3 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

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 CostsSeveral 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

Figure 13. Fatality rates by state, with North Dakota in the lead [49]

Worker Mortality and MorbidityThe 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

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 2012. 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 600-900 truck

trips occur per well per fracturing event) can partially explain the high rate of transportation-

related 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 “off-

duty” 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

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

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

Fracking Fluid Effects on Public HealthFracking 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 2005. 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

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 agency-

sponsored 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

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 (0.9-2.33 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

Value of Health and Human LivesDetermining 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

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 cancer-

related 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

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 ResourcesOne 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 ProcessThe 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

rendering them toxic and unusable; and third, allowing a large fraction of the water used to be re-

injected or simply left in the ground, rendering it unusable [71].

Toxicity and Obstacles for Treatment of WastewaterAlthough 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

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

Induced SeismicityInduced 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 4000-8000 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

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, naturally-

occurring 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].

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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 cost-

effective 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

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 FootprintNatural 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

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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 CO2, 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 (O3), carbon dioxide (CO2), 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 CO2 and 0.7 moles of O3 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

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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].

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2. Economic CostsNatural 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 EconomicsThere 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

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income renters are consequently forced to leave the area, which creates a potential labor

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 resource-

dependent 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 18.

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

Figure 18. Population change in Pennsylvania [86]

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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.

InfrastructureTrucks 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

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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].

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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 high-

volume 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 IndustriesThe 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

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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 SolutionDue 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.

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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-the-

envelope 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 19.

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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

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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 12-18 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.

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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]

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Because fracking is a relatively new technology and much research remains to be done on

its impact on gas production over time, multiple models and equations trying to model gas

production exist. Although there is no perfect model yet, the rapid decline in gas production is

nonetheless evident when examining graphs of wellpads’ production over time. Figures 20 and

21 display gas production over time for three wellpads in the Marcellus Shale Play. All three

graphs show the same rapid drop in production after the initial flow. For wellpads R. Smith 1H

and R. Smith 2H, the decline begins a mere two or three months after initial production. R. Smith

3H is not far behind, with the decline beginning roughly four months after initial production.

Despite the fact that these figures are only specific to the Marcellus Shale, they nonetheless

demonstrate the magnitude of importance that initial flow has to operating companies,

3. Social CostsMuch of the national discussion about fracking has focused on the obvious environmental

risks and economic costs, as mentioned above, while the social costs of fracking have been

largely ignored. However, the shale gas boom and fracking generate tangible social impacts that

undermine the quality of life in societies and create intense pressures on the social fabric,

particularly of the rural ones. The Associated Press summarized the problem:

In a modern-day echo of the raucous Old West, small towns enjoying a boom in

oil and gas drilling are seeing a sharp increase in drunken driving, bar fights and

other hell-raising, blamed largely on an influx of young men who find themselves

with lots of money in their pockets and nothing to do after they get off work [89].

The energy boom and fracking have transformed some rural communities into “modern

versions of Wild West mining towns,” which include ongoing examples in Pennsylvania,

Wyoming, Texas, and North Dakota. The influx of new workers creates a quick population bulge

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in small towns and rural communities that have a limited capacity to meet the growing needs and

challenges [90]. Energy boomtowns often face disruption of the social fabric, a decrease in both

availability and quality of housing facilities along with rent raises, traffic congestions and higher

number of traffic accidents, insufficiency of government and municipal services, an increase in

public service costs, rising levels of crime, and law enforcement difficulties [92].

In this section, we will focus on the social costs of the energy boom and fracking,

particularly in small communities. However, shale energy is a new phenomenon, and as such, the

level of direct knowledge on community risks from this phenomenon is low. But, there is an

array of community research that has focused on previous forms of energy extraction and their

impacts on society such as coal and oil. Due to scarcity and availability of proven and solid data

specifically related to social impacts of shale gas boom and fracking, we will also sometimes

utilize from those studies thanks to their long background in the USA.

Disruption of the Social FabricRural and remote societies have drawn strength from their social cohesion, but energy

booms can strain and disrupt the fabric of those societies. Community members generally report

changes in social norms and behaviors: a perceived loss of social cohesion and a reduction in

density of acquaintanceship, sense of identity, and solidarity in areas where ongoing natural gas

development has taken place; this is mostly due to an enormous influx of newcomers. For

example, Garfield County, Colorado noticed that the natural gas industry boom of 2003-2009

coincided with significant changes to the community’s demographics, social structures, and

community wellness [92].

A number of studies related to boomtowns found that energy exploration changed the

way of life in small towns significantly. These changes include strains in communicating with

newcomers and neighbors of long standing, the making of social class alignments previously

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considered unimportant, a shift in the established power structure from the ranchers to the new

mining industrialists, the need to live with constant and increased uncertainties and fear of crime

for which planning is virtually impossible, a keen interest on the part of some merchants and

businessmen in immediate monetary gain, the need to accommodate to the invasion and

requirements of newcomers who subscribe to foreign life-styles and value systems, alteration and

disappearance of social structures as shared histories and cultural ties, and finally, loss of a sense

of community [93][94][95][96].

Deone Lawlar, a 57-year-old native of Watford City, which is located in the middle of the

fracking play, said, “At first, we were excited about the prospect of bringing in new people and

money … but it slammed us so hard, in such a little time that a lot of locals now are kind of

resentful... and now we want our town back.” [97]

“Gillette Syndrome,” named after a well-known coal town in Wyoming, became the

epithet for representing an unflattering image of what happens to small towns when a large

energy development takes place nearby. In its general definition, Gillette Syndrome refers to

social disruption that can occur in a community due to rapid population growth particularly in

boomtowns. Such disruptions usually include increased crime, degraded mental health,

weakened social and community bonds, abnormally high costs of living, and other social

problems [98].

Decreases in Availability and Quality of Housing StockThe flood of new energy workers can exceed the available housing stock in rural areas,

which further results in increases of local rents and housing prices. A 2011 study conducted on

the effect of the development of the Marcellus Shale on housing facilities in Pennsylvania stated

that the influx of newcomers compared to limited housing stock has led to at least 50 percent

increase in rental prices. Many communities experienced a doubling or even tripling of rents in

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some of the counties. For instance, take a house in Lycoming County. Similar houses rented at

$900 per month before fracking but rented at $2,500 per month after fracking became intense. As

another example, a small older house that rented for $600 in 2008 rented for $2,000 three years

later in the same county [99].

In addition, due to a shortage of rental units, high rental prices, and quality of rentals,

workers may be forced to live in overcrowded and squalid conditions that further stress the

community. For example, In Gillette/Wyoming, coal miners and their families, just like gas

drillers in Pennsylvania, lived in “squatter colonies” of mobile homes that frequently lacked

sufficient water and sanitation infrastructure. Their situations were further troubled with

problems such as diseases, environmental pollution, and stress in the community [98][100].

Moreover, the effect of an increase in rental prices has been greatest on low and fixed

income individuals who can either no longer pay for their homes or pay almost half of their

income for rent. As a considerable result, local social services, including the need to develop

homeless shelters and food support, may be strained [101].

As another side effect of housing shortage due to the gas boom, more children are split

from parents and thus create higher demand for foster care services. Some low-income families

unable to secure adequate housing are separated, and children are put into the foster care system.

For example, in Greene County/Pennsylvania, the number of children in foster care due to

“inadequate housing” has been increased by more than double after fracking boom [102].

Increases in Road Congestion, Number of Traffic Accidents and Maintenance Cost Energy booms bring dramatically increased road congestion and heavy-truck traffic

because of the need to deliver water, equipment, supplies and workers to drilling sites. Total

truck movements during the construction and development phases of a well are estimated at

between 7,000 and 11,000 for a single ten-well pad, and on average 250 truck trips are made

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daily to an individual site [103]. According to a regional transportation study, between 2007 and

2010 the amount of truck traffic on three major northern Pennsylvania highways increased by

125 percent and overall average daily truck traffic rose 22 percent in the 5 county regions [104].

Increased heavy vehicle traffic also has contributed to an increase in traffic accidents in drilling

regions. Food and Water Watch found that shale gas drilling was associated with higher levels of

traffic accidents, particularly with more heavy-truck crashes. According to their research, heavy-

truck crashes rose 7.2 percent in heavily fracked rural Pennsylvania counties but fell 12.4 in un-

fracked rural counties after fracking began in 2005 [105].1

Although the road congestion and heavy truck traffic movements are temporary for the

drilling duration, they would nonetheless adversely affect both local and national roads. For

example, the trucks required to deliver water to a single fracking well cause as much damage to

roads as 3.5 million car journeys, putting massive stress on roadways and bridges not constructed

to handle such volumes of heavy traffic [106].

A 2014 study on the damage of fracking on local transportation infrastructure in the

Marcellus Shale formation in Pennsylvania notes that local roads are generally designed to

support passenger vehicles, not heavy trucks cause exponentially greater roadway damage. The

study also found that the estimated road-reconstruction costs associated with a single horizontal

well range from $13,000 to $23,000 [107]. The New York State of Transportation estimated that

the total road maintenance costs to mitigate impacts from truck traffic to 40,000 proposed wells

across New York State would total as much as $378 million annually [108].

The state of Texas has approved $40 million in funding for road repairs in the Barnett

Shale region, while Pennsylvania estimated in 2010 that $265 million would be needed to repair

1 Food & Water Watch analyzed a decade of socioeconomic-indicator data from rural Pennsylvania counties and compared these indicators before and after hydraulic fracturing (fracking) was commercialized in the state in 2005.

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damaged roads in the Marcellus Shale region [109]. Greene County has had similar experiences

with damaged roads and collapsed bridges. Greene County’s highway maintenance costs rose

from $11.7 million in 2000 to a high of $16.4 million in 2011 [102]. According to the above

mentioned regional transportation study, state and local governments in northern Pennsylvania

will have to repave many roads every 7 to 8 years instead of every 15 years [104]. These

appalling numbers indicate the great extent of infrastructural damage caused by fracking on

regional communities.

Increases in the Level of Social Disorder and Crime RatesThe rapid population growth resulting from energy development leads to higher levels of

social disorder and an increase in the number of crimes and arrests for civil disturbances,

especially for substance abuse and alcohol-related crimes. For example, in Rock Springs/WY,

the number of calls to the local police department increased from 8,000 to 36,000 amidst a

doubling population and complaints during the energy development process [98]. As another

example, in Cumberland Township/Greene County/PA, the overall call volume to police, which

included calls for drunken driving arrests (DUIs), theft, disturbances, disorderly conduct, sexual

assault, and motor vehicle accidents, nearly doubled between 2008 and 2011: from 1,549 calls to

3,086 calls [102]. According to U.S. Census Bureau data, the population increase in one oil-

producing county was 5 percent from 2010 to 2011 as contrasted with an approximately 40

percent increase in domestic violence calls to law enforcement during the same time period

[110].

A study by state intelligence agencies found that crime rose by 32 percent since 2005 in

communities at the center of the oil and gas boom [111]. Also the Pittsburgh Post-Gazette

reported increases in crime followed the Pennsylvania gas drilling boom. They noted that in

Bradford County, DUIs were up 60 percent, and DUI arrests were up 50 percent in Towanda.

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Overall, criminal sentencing was up 35 percent in 2010 [112]. In Sublette County/WI, a rural gas

boomtown that began its development in the early ‘90s displays a significant correlation between

population growth associated with energy development and crime rate over a nine year period

too. The population increase was 21%, while the crime rate, measured by the number of arrests

in the county, rose by 270% [113].

Also above-mentioned research by the Food and Water Watch also found that fracking is

associated with more social disorder arrests. Researchers state that disorderly conduct arrests

increased by 17.1 percent in heavily fracked rural counties, compared to 12.7 percent in un-

fracked rural counties in Pennsylvania. According to a recent nation-wide study (2014) by the

University of Alaska, there is strong evidence that, as a result of the ongoing shale-energy boom,

shale-rich counties experienced faster growth in rates of both property and violent crimes

including rape, assault, murder, robbery, burglary, larceny and grand theft auto. These results are

particularly robust for rates of assault, and less so for other types of crimes [114]. Also it is

asserted that gas booms brought about through fracking contribute to high rates of dating

violence, sexual assault, and stalking. The Department of Justice plans to spend up to half a

million dollars to further study this issue [115].

Impacts on Local GovernmentsAlthough the local “boomtown” governments enjoy large increases in revenues thanks to

royalties from natural gas development, they also suffer due to the high amount of expenditures

for the mitigation of impacts from the development. Population growth and industrial activities

outstrip a local government’s ability to effectively provide even basic provisions such as

infrastructure and maintenance (e.g. roads, sewer, and water systems) and law enforcement and

administration demands [116].

70

The largest new cost, especially for county governments, is often for road maintenance

and repair because heavy truck trips occur over a short period of time and in most cases on rural

roads not originally designed to handle such traffic. For example, road and bridge expenditures

in Van Buren County/Arkansas roughly doubled from $1.5 million to $3 million per year from

2005 to 2010 [117]. The related cost for road infrastructure is already mentioned above so we do

not need to repeat again.

Another major potential cost, primarily for municipal governments, is increased demand

for sewer and water infrastructure. Rapid population growth in parts of shale boom-enjoying

states such as North Dakota, Pennsylvania, Texas, and Wyoming has led cities to extend sewer

and water lines or to expand water and wastewater treatment plants. These projects cost tens of

millions of dollars, even for small municipalities. Other costs for local governments relate to

staff and equipment needs associated with a growing population. These include increased

staffing requirements for law enforcement and emergency services to deal with increased traffic,

accidents, or criminal activity, as well as increased staffing for administrative services such as

the county clerk’s office.

Finally, as mentioned above, energy booms lead to quickly rising rents, forcing

governments to increase housing facilities for both locals and newcomers. In the Bakken Region

(North Dakota), several local governments have purchased real estate and construct housing to

provide affordable living options for employees.

As a general example to all above mentioned costs, Midland/Texas approved $51 million

in infrastructure projects in 2012, which is a significant amount of its total annual revenues of

$171 million. The city has also seen major new staff costs, as roughly 35 new city employees

have been added, largely in the police and fire departments. Furthermore, large salary increases

71

have been necessary to retain staff. The city has also built a new fire station ($4 million) and a

municipal courthouse ($9 million), and expanded its office space ($10 million) [116][118][119].

All these findings suggest that shale gas boom and fracking impose real social costs on

society, including social fabric disruption and loosening social cohesion, a decrease in

availability of housing facilities, an increase in crime rates and law enforcement difficulties, and

insufficiency of public services. The cumulative social effects of shale gas development in rural

communities can ultimately be viewed as degradation in quality of life for the area’s population.

In addition, in some areas it is very clear that our knowledge has not progressed far

enough to capture every dimension of the social impacts incurred by shale gas booms and

fracking. In this regard, communities and states must take potential social costs into account and

perform a thorough social impact assessment when they consider approving controversial new

natural gas fracking. To supplement those efforts, more academic and/or government leading

research should be conducted to clarify the many different types of social costs involved in the

fracking industry.

IV. Cost-Benefit AnalysisAccounting the relevant variables, the following formula is constructed as a model of

cost-benefit analysis for expansion of use of shale gas:

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Utility= ∑t=2015

2040 Et

(1+rE )t−2015 +C t

b

(1+rC )t−2015−C t

c

( 1+rC )t−2015 −Pt

(1+r P )t −2015−Dt

(1+r D )t−2015 −Ft

(1+rF )t−2015−Rt

(1+r R )t−2015−M t

(1+rM ) t−2015−W t

(1+rW ) t−2015

Et = economic benefit at year t

C tb = benefit of carbon emission from burning shale gas at year t

C tc = cost of carbon emission from burning shale gas at year t

Pt = cost of greenhouse gas emission from upstream production at year t

Dt = cost of air impact from disel use during hydraulic fracturing at year t

F t = cost of forest disruption at year t

Rt = cost of road disruption at year t

M t = cost of well worker mortalities at year t

W t = cost of constructing new shale gas wells at year t

r E = discount rate for economic benefit

rC = discount rate for carbon benefit and cost

r P = discount rate for cost of greenhouse gas emission from upstream production

r D = discount rate for cost of air impact from disel use during hydraulic fracturing

r F = discount rate for cost of forest disruption

r R = discount rate for cost of road disruption

r M = discount rate for cost of well worker mortalities

rW = discount rate for cost of constructing new shale gas wells

The formula captures the major benefits and costs from expanded use of shale gas. The

time range of the formula is from 2015-2040. As this paper is exploring the effect of expanded

use of shale gas in the future and currently it is at the end of 2014, 2015 is used as the first year

in the model. 2040 is used as the final year because many U.S. Energy Information

Administration (EIA) projections used for this model, such as shale gas production and gas price,

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are projected until 2040. Beyond 2040 there is a lack of important projections from reliable

source for the model. 2040 is a reasonable end year also because it will be more than 25 years

from now and we cannot foresee what kind technological advancement will be achieved then.

Any projections and predictions beyond 2040 will become increasingly uncertain and unreliable.

Since there are no better suitable discount rates for each specific discount rate, it is thus

assumed thatr E=rC=r P=r D=rF=r R=rM=rW=7 %. 7% is approximately the average return of

all investments in the economy, so it is a reasonable discount rate for the 25-year period of 2015-

2040.

1. Benefits

Economic BenefitThe economic benefit is represented by the economic revenue generated from shale gas,

which is calculated by the projected volume of shale gas production times the projected weighted

average gas price for years 2015-2040 [120][121]. This economic revenue does capture all of the

economic benefits associated with shale gas because the projected weighted average gas price

used for the calculation is nominal end-user price. As the final end-user price, it takes into

account all the costs and profits for upstream production, midstream refinery and distribution,

and downstream sales and retail. In this case, costs also contribute to the economy because costs

for certain companies are actually incomes for other companies, such as the equipment costs for

oil companies are incomes for equipment companies. So all of the costs accumulated will be paid

with the final price by the end-user. The final end-user price will also capture the all of the

employment benefits in different stages of the shale gas production to consumption process,

represented by salaries paid by companies to employees, which is integrated into the overall cost

and price for end-user. So for this model it is assumed that all of the economic benefits

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associated with shale gas are reflected by the unit weighted-average nominal end-user price

times the projected volume of shale gas production.

The results are:

Table 6

Year 2015 2020 2025 2030 2035 2040

Price ($ per million Btu) 6.8 8.0 9.5 11.4 13.9 17.2

Bear case:Production growth rate 0%Shale gas production (trillion cubic feet) 10.0 10.0 10.0 10.0 10.0 10.0Shale gas revenue ($Bn) 69.5 82.0 97.0 116.7 141.9 175.8Present value of shale gas revenue ($Bn) 69.5 58.5 49.3 42.3 36.7 32.4Sum of present value of shale gas revenue ($Bn) 1,234.4

Base case:Production growth rate EIA projectionShale gas production (trillion cubic feet) 10.0 13.3 16.0 16.9 18.5 19.8Shale gas revenue ($Bn) 69.5 109.8 155.8 198.2 263.6 349.8Present value of shale gas revenue ($Bn) 69.5 78.3 79.2 71.8 68.1 64.5Sum of present value of shale gas revenue ($Bn) 1,883.1

Bull case:Production growth rate 5%Shale gas production (trillion cubic feet) 10.0 12.7 16.2 20.7 26.4 33.7Shale gas revenue ($Bn) 69.5 104.7 158.1 242.5 376.6 595.2Present value of shale gas revenue ($Bn) 69.5 74.6 80.4 87.9 97.3 109.7Sum of present value of shale gas revenue ($Bn) 2,229.5

Here the conversion rate used is 1,025 Btu per cubic feet [122]. There are three scenarios

—bear, base, and bull. The base scenario uses EIA’s projection of shale gas production for 2015-

2040. The bear case assumes that shale gas production maintains the 2015 level, and the bull

case assumes that shale gas production grows at an annual rate of 5%, whereas the base case

grows at approximately 2.8%. Clearly, the economic upside is quite significant. The discounted

economic revenue from shale gas is $1,234.4.8 billion, $1,883.1 billion, and $2,229.5 billion for

bear, base, and bull cases, respectively.

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Carbon BenefitThe economic benefit of carbon emission from burning shale gas lies in that shale gas is a

substitute to coal. Burning more shale gas means that there will be less coal burned, and that

natural gas emits less carbon dioxide than coal. Here the data comes from EIA’s projection of

carbon dioxide emissions from coal until 2040 [123]. The results are:

Table 7

Year 2011 2015 2020 2025 2030 2035 2040Carbon dioxide emission from coal (million metric tons carbon dioxide) 1,876.3 1,774.6 1,765.5 1,810.3 1,807.1 1,788.1 1,779.8 Carbon dioxide emission prevented (million metric tons carbon dioxide) 101.7 110.8 65.9 69.2 88.2 96.5 Carbon emission prevented (million metric tons carbon) 27.8 30.2 18.0 18.9 24.1 26.3 Carbon benefits ($Bn) 1.2 1.5 1.0 1.3 1.9 2.4 Present value of carbon benefits ($Bn) 1.2 1.1 0.5 0.5 0.5 0.4 Sum of present value of carbon benefits ($Bn) 19.2

Carbon dioxide emission peaked in 2011, and becomes less in every year thereafter. So it is

assumed that compared to 2011, the reduced amount of carbon dioxide emission from coal in

each future year is due to the expanded use of shale gas and less coal. Thus this becomes an

environmental benefit for burning shale gas. The carbon cost in dollar amount used in the model

is $43 per ton of carbon, which is the average value of Yohe et al (2007) peer-reviewed over 100

estimates of social cost of carbon [124]. Yohe et al (2007) also predicted that “it is very likely

that the rate of increase will be 2% to 4% per year,” so starting in the model’s second year 2016

an annual growth rate of 3% is applied to the $43 per ton social cost of carbon. Eventually the

sum of present value of carbon benefits in 2015-2040 will accumulatively be around $19.2

billion.

2. Costs

Carbon CostAlthough shale gas is comparatively cleaner than coal, burning shale gas still generates a

significant amount of carbon emission that is harmful to the environment. Using the previous

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shale gas production data as in economic benefit, and the $43 social cost of carbon with annual

growth rate 3%, the carbon cost of shale gas is:

Table 8

Year 2015 2020 2025 2030 2035 2040

Bear case:Shale gas production (trillion cubic feet) 10.0 10.0 10.0 10.0 10.0 10.0Shale gas' social cost of carbon ($Bn) 6.3 7.4 8.5 9.9 11.5 13.3Present value of shale gas' social cost of carbon ($Bn) 6.3 5.2 4.3 3.6 3.0 2.4Sum of present value of shale gas' social cost of carbon ($Bn) 106.7

Base case:Shale gas production (trillion cubic feet) 10.0 13.3 16.0 16.9 18.5 19.8Shale gas' social cost of carbon ($Bn) 6.3 9.8 13.7 16.8 21.3 26.5Present value of shale gas' social cost of carbon ($Bn) 6.3 7.0 7.0 6.1 5.5 4.9Sum of present value of shale gas' social cost of carbon ($Bn) 161.4

Bear case:Shale gas production (trillion cubic feet) 10.0 12.7 16.2 20.7 26.4 33.7Shale gas' social cost of carbon ($Bn) 6.3 9.4 13.9 20.6 30.4 45.0Present value of shale gas' social cost of carbon ($Bn) 6.3 6.7 7.1 7.5 7.9 8.3Sum of present value of shale gas' social cost of carbon ($Bn) 189.2

The social costs of carbon from shale gas in 2015-2040 for bear, base, and bull cases are $106.7

billion, $161.4 billion, and 189.2 billion, respectively.

Costs Associated with Shale Gas Wells: Costs of Greenhouse Gas Emission from Upstream Production, Air Impact from Diesel Use during Hydraulic Fracturing, Forest Disruption, Road Disruption, and Worker Mortality

The model estimates the number of shale gas wells and newly constructed wells in the

U.S. each year, and calculates the costs associated with them. These major costs include the

greenhouse gas emission from upstream production, air impact from diesel use during hydraulic

fracturing, forest disruption, road disruption, and worker mortality.

To estimate the number of shale gas wells in the U.S., a ratio between well numbers and

shale gas production volume is applied. In 2007, the U.S. had 25,145 shale gas wells, and shale

gas production was 1.52 trillion cubic feet, which gives a ratio of approximately 16,543 wells for

1 trillion cubic feet of shale gas produced [126][126]. Applying this ratio to every year’s

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production volume, we estimate the number of shale gas wells each year. This model assumes

that each shale gas well has a life of production of 8 years, and also that the relative increase in

wells from year t-8 to year t is the number of wells constructed in year t (e.g. the difference

between well numbers in 2015 and 2007 are the number of wells constructed in 2015) [127].

Therefore, we have a method of estimating the number of new wells constructed each year and

also the associated environmental costs. Again, we use scenarios of bear, base, and bull cases for

the shale gas production volume to demonstrate different well numbers and their costs.

Manhattan Institute estimates that on a per well basis throughout the well’s functional

life, the cost of greenhouse gas emission from upstream production is $2,796, the cost of air

impact from diesel use during hydraulic fracturing is $7,245, and the cost of forest disruption is

$3,943 [129]. Manhattan Institute is a conservative think tank, so its estimates might be biased,

but the estimates are nonetheless used in the model because there lacks these kinds of estimates

from more reliable sources, and these are important variables that need to be incorporated.

This model also assumes that the road disruption and re-construction costs are $18,000

per well, taking the average of the estimate of $13,000 to $23,000 per well [129]. As for worker

fatality costs, the model takes the assumptions that U.S. Bureau of Labor Statistics Census of

Fatal Occupational Injuries estimate that there are averagely 6.7 fatalities per 100 oil and gas

wells per year, and that U.S. Environmental Protection Agency (EPA) sets the value of a human

life at $9.1 million [130][131]. The results of the costs associated with shale gas wells are:

78

Table 9

Year 2007 2015 2020 2025 2030 2035 2040

Bear case:Shale gas produtioin volume (trillion cubic feet) 1.5 10.0 10.0 10.0 10.0 10.0 10.0 Estimated number of wells 25,145 164,446 164,446 164,446 164,446 164,446 164,446 Estimated number of new wells constructed 139,301 4,023 139,301 139,301 139,301 139,301

Cost of greenhouse gas emission from upstream production ($Bn) 0.4 0.0 0.4 0.4 0.4 0.4 Present value of cost of greenhouse gas emission from upstream production ($Bn) 0.39 0.01 0.20 0.14 0.10 0.07 Sum of present value of cost of greenhhouse gas emission from upstream production ($Bn) 3.7

Cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.0 1.0 1.0 1.0 1.0 Present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.0 0.5 0.4 0.3 0.2 Sum of present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 9.7

Cost of forest diruption ($Bn) 0.5 0.0 0.5 0.5 0.5 0.5 Present value of cost of forest diruption ($Bn) 0.5 0.0 0.3 0.2 0.1 0.1 Sum of present value of cost of forest diruption ($Bn) 5.3

Cost of road diruption ($Bn) 2.5 0.1 2.5 2.5 2.5 2.5 Present value of cost of road diruption ($Bn) 2.5 0.1 1.3 0.9 0.6 0.5 Sum of present value of cost of road diruption ($Bn) 24.1

Cost of mortality of workers ($Bn) 15.0 15.0 15.0 15.0 15.0 15.0 Present value of cost of mortality of workers ($Bn) 15.0 10.7 7.6 5.4 3.9 2.8 Sum of present value of cost of mortality of workers ($Bn) 189.4

Sum of present value of all costs associated with shale gas well 232.1

Base case:Shale gas produtioin volume (trillion cubic feet) 1.5 10.0 13.3 16.0 16.9 18.5 19.8 Estimated number of wells 25,145 164,446 220,042 264,047 279,336 305,458 327,311 Estimated number of new wells constructed 139,301 59,619 83,915 41,561 31,322 39,223

Cost of greenhouse gas emission from upstream production ($Bn) 0.39 0.17 0.23 0.12 0.09 0.11 Present value of cost of greenhouse gas emission from upstream production ($Bn) 0.39 0.12 0.12 0.04 0.02 0.02 Sum of present value of cost of greenhhouse gas emission from upstream production ($Bn) 2.8

Cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.4 0.6 0.3 0.2 0.3 Present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.3 0.3 0.1 0.1 0.1 Sum of present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 7.4

Cost of forest diruption ($Bn) 0.5 0.2 0.3 0.2 0.1 0.2 Present value of cost of forest diruption ($Bn) 0.5 0.2 0.2 0.1 0.0 0.0 Sum of present value of cost of forest diruption ($Bn) 4.0

Cost of road diruption ($Bn) 2.5 1.1 1.5 0.7 0.6 0.7 Present value of cost of road diruption ($Bn) 2.5 0.8 0.8 0.3 0.1 0.1 Sum of present value of cost of road diruption ($Bn) 18.3

Cost of mortality of workers ($Bn) 15.0 20.0 24.0 25.4 27.8 29.8 Present value of cost of mortality of workers ($Bn) 15.0 14.3 12.2 9.2 7.2 5.5 Sum of present value of cost of mortality of workers ($Bn) 274.7

Sum of present value of all costs associated with shale gas well 307.2

Bull case:Shale gas produtioin volume (trillion cubic feet) 1.5 10.0 12.7 16.2 20.7 26.4 33.7 Estimated number of wells 25,145 164,446 209,879 267,865 341,871 436,324 556,872 Estimated number of new wells constructed 139,301 49,456 86,563 110,479 141,003 179,959

Cost of greenhouse gas emission from upstream production ($Bn) 0.4 0.1 0.2 0.3 0.4 0.5 Present value of cost of greenhouse gas emission from upstream production ($Bn) 0.4 0.1 0.1 0.1 0.1 0.1 Sum of present value of cost of greenhhouse gas emission from upstream production ($Bn) 3.8

Cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.4 0.6 0.8 1.0 1.3 Present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.3 0.3 0.3 0.3 0.2 Sum of present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 9.8

Cost of forest diruption ($Bn) 0.5 0.2 0.3 0.4 0.6 0.7 Present value of cost of forest diruption ($Bn) 0.5 0.1 0.2 0.2 0.1 0.1 Sum of present value of cost of forest diruption ($Bn) 5.3

Cost of road diruption ($Bn) 2.5 0.9 1.6 2.0 2.5 3.2 Present value of cost of road diruption ($Bn) 2.5 0.6 0.8 0.7 0.7 0.6 Sum of present value of cost of road diruption ($Bn) 24.3

Cost of mortality of workers ($Bn) 15.0 19.1 24.4 31.1 39.7 50.7 Present value of cost of mortality of workers ($Bn) 15.0 13.6 12.4 11.3 10.3 9.3 Sum of present value of cost of mortality of workers ($Bn) 310.4

Sum of present value of all costs associated with shale gas well 353.6

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Compared to the base case of $1277.6 billion of economic benefits from shale gas, the

costs of greenhouse gas emission from upstream production, air impact from diesel use during

hydraulic fracturing, forest disruption, and road disruption are comparatively small, together

amounting to $32.5 billion in present value in the base case. Meanwhile, worker mortalities

alone amount to $307.2 billion in the base case, which is quite significant.

Cost of Construction of Shale Gas WellsBased on the estimated number of new wells each year, the model calculates the cost of

constructing new shale gas wells each year, assuming a low cost bull case of $3 million per well,

a base case of $6.5 million per well, and a high cost bear case of $10 million per well [127]:

Table 10Year 2007 2015 2020 2025 2030 2035 2040

Bull case:Cost per shale gas well ($Mn) 3.0 3.0 3.0 3.0 3.0 3.0 Shale gas produtioin volume (trillion cubic feet) 1.5 10.0 13.3 16.0 16.9 18.5 19.8 Estimated number of wells 25,145 164,446 220,042 264,047 279,336 305,458 327,311 Estimated number of new wells constructed 139,301 59,619 83,915 41,561 31,322 39,223 Construction cost of new wells ($Bn) 417.9 178.9 251.7 124.7 94.0 117.7 Present value of construction cost of new wells ($Bn) 417.9 127.5 128.0 45.2 24.3 21.7 Sum of present value of construction cost of new wells ($Bn) 3,051.3

Base case:Cost per shale gas well ($Mn) 6.5 6.5 6.5 6.5 6.5 6.5 Shale gas produtioin volume (trillion cubic feet) 1.5 10.0 13.3 16.0 16.9 18.5 19.8 Estimated number of wells 25,145 164,446 220,042 264,047 279,336 305,458 327,311 Estimated number of new wells constructed 139,301 59,619 83,915 41,561 31,322 39,223 Construction cost of new wells ($Bn) 905.5 387.5 545.4 270.1 203.6 254.9 Present value of construction cost of new wells ($Bn) 905.5 276.3 277.3 97.9 52.6 47.0 Sum of present value of construction cost of new wells ($Bn) 6,611.2

Bear case:Cost per shale gas well ($Mn) 10.0 10.0 10.0 10.0 10.0 10.0 Shale gas produtioin volume (trillion cubic feet) 1.5 10.0 13.3 16.0 16.9 18.5 19.8 Estimated number of wells 25,145 164,446 220,042 264,047 279,336 305,458 327,311 Estimated number of new wells constructed 139,301 59,619 83,915 41,561 31,322 39,223 Construction cost of new wells ($Bn) 1,393.0 596.2 839.1 415.6 313.2 392.2 Present value of construction cost of new wells ($Bn) 1,393.0 425.1 426.6 150.6 80.9 72.3 Sum of present value of construction cost of new wells ($Bn) 10,171.1

It is assumed here that the cost of constructing each well does not change over time, as the price

increase due to inflation and the price decrease due to technological advancement will cancel

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each other’s effect. The cost of constructing new wells turn out to be very significant, with a low

cost bull case of 3,051.3Bn, a base case of 6,611.2Bn, and a high cost bear case of 10,171.1Bn.

3. Sensitivity AnalysisHere two of the most uncertain and important factors in the model—natural gas price and

social cost of carbon—are manipulated in a sensitivity analysis:

Table 11. Sensitivity analysis of social utility ($bn) under different scenarios of natural gas price and social cost of carbon

$10 $43 $300$4 with 3.8% growth rate 799.6 690.4 -820.9EIA projection 1542.9 1433.7 -77.6$10 with 3.8% growth rate 1939.3 1830.1 318.8

Natural gas price ($ per million Btu)

Social cost of carbon ($ per ton of carbon)

For the EIA projection of nominal natural gas price from 2015 to 2040, the price has a

compounded annual growth rate (CAGR) of 3.8%, so the same annual growth rate is also

assigned to the assumed natural gas price of $4 in 2015 and $10 in 2015. As for the social cost of

carbon, Yohe et al (2007) describes the many estimates as highly uncertain, ranging from less

than $1 per ton of carbon to over $1,500 per ton of carbon. From the sensitivity it is evident that

maintaining the EIA projection of natural gas price the overall social utility becomes negative

when the social cost of carbon exceeds $300 per ton of carbon.

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V. ConclusionOverall, in the base case of the model, the social utility is:

Utility= ∑t=2015

2040 Et

(1+rE )t−2015 +C t

b

(1+rC )t−2015−C t

c

( 1+rC )t−2015 −Pt

(1+r P )t −2015−Dt

(1+r D )t−2015 −Ft

(1+rF )t−2015−Rt

(1+r R )t−2015−M t

(1+rM ) t−2015−W t

(1+rW ) t−2015

Combining the fourth to eighth terms into other costs associated with wells, the overall social

utility becomes (in present value of base case):

Utilit y=Economic Benefits+Carbon Benefits−Carbon Costs−Other Costs Associated withWells−Cost of Wells Construction

Utility=$ 1883.1 Bn+$ 19.2 Bn−$ 161.4 Bn−$ 307.2 Bn−$ 6,611.2=$−5,177.5 Bn

The final outcome is a negative number of $-5,177.5Bn, with the costs significantly

outweighing the benefits due to the large cost of new wells construction. It appears that

expansion of shale gas should not be pursued, but in fact it still may be logical to pursue shale

gas expansion for several reasons. First, the current cost-benefit analysis turns out to be negative

because the cost of constructing new wells is very large. The magnitude of this cost of

constructing new wells may be biased right now because the cost of constructing new wells will

vary by region. Some regions will have higher costs near $10 million per well, where developing

shale gas will not be economical, but other regions may have lower cost. If the cost per well is as

low as $1.5 million, it will be beneficial to develop shale gas. Since the federal government

cannot produce a solve-all solution for all regions in the country at a national level, this is

actually a good decision for individual companies in the private sector to decide for their own

specific cases whether drilling a well is profitable for the company given its particular well

construction cost in the region. If calculated without the construction cost of new wells, the

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social utility outcome for the cost-benefit analysis will be a positive number of $1,433.7Bn, with

the benefits outweighing the costs; then, expansion of shale gas should be pursued. So given

individual companies’ own profitability, if some of the companies can generate profit given their

lower cost of well construction, shale gas expansion should be allowed.

Also, the high construction cost of wells is based on the estimate of the new wells

constructed each year. The estimates of the new wells constructed each year may be biased

because the numbers of new wells constructed are predicted very aggressively, so the numbers

may be overstated. If the numbers of new wells are overstated and can be brought down with

more research, or technological advancement, this can lead to lower construction cost per well or

boost the production for each well so fewer new wells are needed each year. Then, the overall

cost of constructing new wells will decrease and may turn the cost-benefit analysis’ outcome

from negative to positive, therefore making it logical to expand shale gas.

Lastly, if shale gas is expanded in a very limited scale, in the long-term, there will be less

energy available for consumption in the market, which will drive up the energy price. When the

energy price becomes high enough, it will be rational again to develop shale gas despite the high

cost of new wells construction, because in this case the economic benefits will become big

enough to outweigh the high costs.

VI. Policy RecommendationThe final policy recommendation regarding shale gas expansion in the United States is

that the federal government on the national level should apply the policy to not encourage nor

discourage shale gas expansion, because even though the outcome of the cost-benefit analysis of

shale gas expansion on the national level is negative right now, it can be positive in some regions

83

and may on national level turn positive in the near future with technological advancement or

rising energy price. So the federal government on the national level should allow companies in

the private sector to decide for themselves whether to start their shale gas projects based on the

companies’ own profitability given the current cost and energy price. The federal government

should also allow the local governments to decide shale gas policies for their own regions based

on their regional cost-benefit analysis on whether in this specific region the economic benefits of

shale gas outweigh the environmental costs and high investment cost.

This would allow for more environmentally-conscious policy-making as well. One

recommendation is implementation of a region-by-region system of best management practices

pertaining to fracturing. This could include standards for the efficiency of the process, such as

mandating the recycling of water in repeated fractures of a single well, or setting standards for

technology that prevents methane from escaping as much as possible. Additionally, until more

comprehensive public health research and long-term studies are conducted, fracking should not

be expanded in populated areas, where the risks are highest. For the same reason, until more

research about induced seismic risk and seismic risk to infrastructure is conducted, placing

injection wells in areas with high seismic risk is also ill-advised.

Regarding companies in the shale gas business, both the federal and local governments

should still apply the reasonable earning tax and carbon tax, and ask the companies to fulfill their

obligations in paying for the pollution, forest disruption, road disruption, and the casualties

caused by the companies’ business, so the companies can profit responsibly and the governments

can ensure the greatest utility for the whole society.

84

VII. Limitations and Next StepsAlthough we have striven to be as comprehensive and detailed as possible in both the

research and cost-benefit analysis, limitations nonetheless exist that prevent complete accuracy.

These limitations exist within the research behind the environmental, economic, and social costs

and benefits that we examined, and also within the cost-benefit analysis that aggregates this

research. While limitations are unavoidable, various next steps can be taken to compensate for

them, on both the fundamental research and analysis sides.

Cost-Benefit AnalysisWithin the cost-benefit analysis model, several variables are lacking, particularly the

environmental costs associated with fracking. However, it is difficult to monetize an event such

as the increased likelihood of a disastrous earthquake. The difficulty of monetization certainly

does not reduce the magnitude of the cost, but because the cost-benefit analysis is a framework

that requires quantifiable variables, crucial variables are omitted from the analysis as a result.

Another limitation is the implicit assumption of static progress in the model. The

projections of the future, along with the data taken from organizations such as the EIA, all take

present trends and extrapolate them several years into the future. This assumes no technological

breakthroughs or innovations for the foreseeable future. Although it is difficult to anticipate

breakthroughs, Dr. Crabtree of Argonne National Laboratory argues that historical predictions

are nonetheless too conservative and offers an alternative framework for considering the future

of energy [132]. His thesis is to first assume breakthroughs in the future and then to decide what

kind of society is desired in that future. Having decided upon the ideal, the next step is to avidly

pursue the breakthroughs that will allow for the creation of such a future society. Therefore, in

accordance with Dr. Crabtree’s framework, a possible next step would be to examine the costs

and benefits of shale gas extraction, but not merely as objective costs and benefits. Instead, they

85

should be examined specifically in terms of challenges preventing and benefits furthering the

achievement of an ideal future society.

Research Availability and QualityBecause the technology for increased shale gas extraction is very recent, having occurred

only roughly in the last fifteen years, there is a dearth of information about fracking-related

statistics. For instance, because the industry is so young, it is difficult for environmental agencies

predict the growth of the industry and also the associated environmental damage. Uncertain or

widely-varying data reports not only make cost-benefit analysis difficult, but also render

regulation and future policy decisions much more problematic.

One area lacking research is infrastructure affected by fracking. Currently, research on

infrastructure mainly comes from private organizations, such as academic institutions (MIT,

UMichigan) and private organizations (INGAA). Even so, these reports only provide a limited

scope of the landscape of infrastructure development. The lack of existing research on this topic

hinders the accuracy of estimating the amount of money needed to invest in infrastructure, as

well as the cost for producing gas. Without an estimate in the cost of producing natural gas, it is

more difficult to compare the cost with its substitutes – oil and goal.

Therefore, given the above limitations, the government should perform the following in-

depth analyses. Firstly, the government should increase funding to support a detailed analysis of

increasing interdependencies of growing supply of natural gas and power generation

infrastructures. This kind of study can investigate on the scenario where increasing production

and consumption of natural gas would exhaust the infrastructure system, such as the problem of

pipelines bottlenecks, exhaustion of processing facilities, and the saturation of storage capacities.

Secondly, the government should set up a federally administered website to keep track of the

86

development of shale gas-specific infrastructure, such as the number of shale gas wells, cost of

operating storage facilities, and the cost of using of underground water in the process of

hydraulic fracturing. These analyses are essential in understanding current usage as well as

developing a comprehensive plan for infrastructure development in the United States.

87

VIII. AppendixTable 6

Table 7

Table 8

88

Year 2011 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040Carbon dioxide emission from coal (million metric tons carbon dioxide) 1,876.3 1,774.6 1,683.4 1,720.5 1,754.4 1,767.2 1,765.5 1,775.1 1,784.4 1,786.1 1,801.1 1,810.3 1,809.2 1,812.4 1,810.9 1,810.4 1,807.1 1,803.2 1,799.2 1,796.1 1,791.7 1,788.1 1,787.4 1,783.5 1,782.9 1,782.3 1,779.8 Carbon dioxide emission prevented (million metric tons carbon dioxide) 101.7 192.8 155.8 121.8 109.1 110.8 101.2 91.9 90.2 75.1 65.9 67.1 63.9 65.4 65.9 69.2 73.0 77.1 80.2 84.5 88.2 88.8 92.8 93.4 94.0 96.5 Carbon emission prevented (million metric tons carbon) 27.8 52.6 42.5 33.2 29.8 30.2 27.6 25.1 24.6 20.5 18.0 18.3 17.4 17.8 18.0 18.9 19.9 21.0 21.9 23.1 24.1 24.2 25.3 25.5 25.6 26.3 Carbon benefits ($Bn) 1.2 2.3 1.9 1.6 1.4 1.5 1.4 1.3 1.3 1.2 1.0 1.1 1.1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.9 1.9 2.1 2.2 2.2 2.4 Present value of carbon benefits ($Bn) 1.2 2.2 1.7 1.3 1.1 1.1 0.9 0.8 0.8 0.6 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.4 0.4 Sum of present value of carbon benefits ($Bn) 19.2

Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Bear case:Shale gas production (trillion cubic feet) 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0Shale gas' social cost of carbon ($Bn) 6.3 6.5 6.7 6.9 7.1 7.4 7.6 7.8 8.0 8.3 8.5 8.8 9.1 9.3 9.6 9.9 10.2 10.5 10.8 11.1 11.5 11.8 12.2 12.5 12.9 13.3Present value of shale gas' social cost of carbon ($Bn) 6.3 6.1 5.9 5.7 5.5 5.2 5.1 4.9 4.7 4.5 4.3 4.2 4.0 3.9 3.7 3.6 3.5 3.3 3.2 3.1 3.0 2.9 2.7 2.6 2.5 2.4Sum of present value of shale gas' social cost of carbon ($Bn) 106.7

Base case:Shale gas production (trillion cubic feet) 10.0 10.4 10.9 11.5 12.4 13.3 13.8 14.4 15.1 15.6 16.0 16.3 16.6 16.7 16.8 16.9 17.1 17.4 17.8 18.2 18.5 18.9 19.2 19.6 19.7 19.8Shale gas' social cost of carbon ($Bn) 6.3 6.9 7.4 8.0 8.9 9.8 10.5 11.3 12.2 13.0 13.7 14.4 15.1 15.7 16.2 16.8 17.5 18.4 19.3 20.3 21.3 22.4 23.4 24.6 25.6 26.5Present value of shale gas' social cost of carbon ($Bn) 6.3 6.4 6.4 6.5 6.8 7.0 7.0 7.0 7.1 7.0 7.0 6.8 6.7 6.5 6.3 6.1 5.9 5.8 5.7 5.6 5.5 5.4 5.3 5.2 5.0 4.9Sum of present value of shale gas' social cost of carbon ($Bn) 161.4

Bear case:Shale gas production (trillion cubic feet) 10.0 10.5 11.0 11.5 12.1 12.7 13.3 14.0 14.7 15.5 16.2 17.0 17.9 18.8 19.7 20.7 21.7 22.8 24.0 25.2 26.4 27.7 29.1 30.6 32.1 33.7Shale gas' social cost of carbon ($Bn) 6.3 6.9 7.4 8.0 8.7 9.4 10.2 11.0 11.9 12.8 13.9 15.0 16.3 17.6 19.0 20.6 22.2 24.0 26.0 28.1 30.4 32.9 35.6 38.5 41.6 45.0Present value of shale gas' social cost of carbon ($Bn) 6.3 6.4 6.5 6.6 6.6 6.7 6.8 6.8 6.9 7.0 7.1 7.1 7.2 7.3 7.4 7.5 7.5 7.6 7.7 7.8 7.9 7.9 8.0 8.1 8.2 8.3Sum of present value of shale gas' social cost of carbon ($Bn) 189.2

Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Price ($ per million Btu) 6.8 6.9 7.3 7.8 8.0 8.0 8.4 8.5 8.8 9.2 9.5 9.7 10.0 10.4 10.9 11.4 11.8 12.2 12.7 13.3 13.9 14.7 15.1 15.6 16.4 17.2

Bear case:Production growth rate 0%Shale gas production (trillion cubic feet) 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0Shale gas revenue ($Bn) 69.5 69.9 74.1 79.6 82.1 82.0 85.3 87.1 89.9 93.9 97.0 99.4 102.3 105.8 110.9 116.7 120.7 124.5 130.1 135.9 141.9 150.0 154.6 159.2 166.9 175.8Present value of shale gas revenue ($Bn) 69.5 65.4 64.7 65.0 62.7 58.5 56.8 54.2 52.3 51.1 49.3 47.2 45.4 43.9 43.0 42.3 40.9 39.4 38.5 37.6 36.7 36.2 34.9 33.6 32.9 32.4Sum of present value of shale gas revenue ($Bn) 1,234.4

Base case:Production growth rate EIA projectionShale gas production (trillion cubic feet) 10.0 10.4 10.9 11.5 12.4 13.3 13.8 14.4 15.1 15.6 16.0 16.3 16.6 16.7 16.8 16.9 17.1 17.4 17.8 18.2 18.5 18.9 19.2 19.6 19.7 19.8Shale gas revenue ($Bn) 69.5 73.4 81.1 91.7 102.2 109.8 118.5 125.9 136.2 146.9 155.8 163.0 170.6 177.9 187.1 198.2 207.0 218.2 232.4 247.7 263.6 284.0 297.6 312.6 330.8 349.8Present value of shale gas revenue ($Bn) 69.5 68.6 70.9 74.8 78.0 78.3 79.0 78.4 79.3 79.9 79.2 77.5 75.7 73.8 72.5 71.8 70.1 69.1 68.8 68.5 68.1 68.6 67.2 65.9 65.2 64.5Sum of present value of shale gas revenue ($Bn) 1,883.1

Bull case:Production growth rate 5%Shale gas production (trillion cubic feet) 10.0 10.5 11.0 11.5 12.1 12.7 13.3 14.0 14.7 15.5 16.2 17.0 17.9 18.8 19.7 20.7 21.7 22.8 24.0 25.2 26.4 27.7 29.1 30.6 32.1 33.7Shale gas revenue ($Bn) 69.5 73.4 81.6 92.2 99.8 104.7 114.3 122.6 132.8 145.6 158.1 170.0 183.7 199.6 219.6 242.5 263.5 285.4 313.0 343.4 376.6 417.8 452.4 489.0 538.4 595.2Present value of shale gas revenue ($Bn) 69.5 68.6 71.3 75.3 76.2 74.6 76.1 76.3 77.3 79.2 80.4 80.8 81.6 82.8 85.2 87.9 89.3 90.4 92.6 95.0 97.3 100.9 102.1 103.1 106.1 109.7Sum of present value of shale gas revenue ($Bn) 2,229.5

Table 9

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Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Bear case:Shale gas produtioin volume (trillion cubic feet) 1.5 2.0 3.4 4.9 7.9 9.7 9.4 9.6 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 Estimated number of wells 25,145 32,675 56,386 80,300 131,133 160,423 154,397 158,922 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 164,446 Estimated number of new wells constructed 139,301 131,771 108,060 84,146 33,313 4,023 10,049 5,523 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301 139,301

Cost of greenhouse gas emission from upstream production ($Bn) 0.4 0.4 0.3 0.2 0.1 0.0 0.0 0.0 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 Present value of cost of greenhouse gas emission from upstream production ($Bn) 0.39 0.34 0.26 0.19 0.07 0.01 0.02 0.01 0.23 0.21 0.20 0.19 0.17 0.16 0.15 0.14 0.13 0.12 0.12 0.11 0.10 0.09 0.09 0.08 0.08 0.07 Sum of present value of cost of greenhhouse gas emission from upstream production ($Bn) 3.7

Cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 1.0 0.8 0.6 0.2 0.0 0.1 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.9 0.7 0.5 0.2 0.0 0.0 0.0 0.6 0.5 0.5 0.5 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.3 0.2 0.2 0.2 0.2 0.2 Sum of present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 9.7

Cost of forest diruption ($Bn) 0.5 0.5 0.4 0.3 0.1 0.0 0.0 0.0 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 Present value of cost of forest diruption ($Bn) 0.5 0.5 0.4 0.3 0.1 0.0 0.0 0.0 0.3 0.3 0.3 0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 Sum of present value of cost of forest diruption ($Bn) 5.3

Cost of road diruption ($Bn) 2.5 2.4 1.9 1.5 0.6 0.1 0.2 0.1 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 Present value of cost of road diruption ($Bn) 2.5 2.2 1.7 1.2 0.5 0.1 0.1 0.1 1.5 1.4 1.3 1.2 1.1 1.0 1.0 0.9 0.8 0.8 0.7 0.7 0.6 0.6 0.6 0.5 0.5 0.5 Sum of present value of cost of road diruption ($Bn) 24.1

Cost of mortality of workers ($Bn) 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 Present value of cost of mortality of workers ($Bn) 15.0 14.0 13.1 12.2 11.4 10.7 10.0 9.3 8.7 8.1 7.6 7.1 6.6 6.2 5.8 5.4 5.1 4.7 4.4 4.1 3.9 3.6 3.4 3.2 3.0 2.8 Sum of present value of cost of mortality of workers ($Bn) 189.4

Sum of present value of all costs associated with shale gas well 232.1

Base case:Shale gas produtioin volume (trillion cubic feet) 1.5 2.0 3.4 4.9 7.9 9.7 9.4 9.6 10.0 10.4 10.9 11.5 12.4 13.3 13.8 14.4 15.1 15.6 16.0 16.3 16.6 16.7 16.8 16.9 17.1 17.4 17.8 18.2 18.5 18.9 19.2 19.6 19.7 19.8 Estimated number of wells 25,145 32,675 56,386 80,300 131,133 160,423 154,397 158,922 164,446 172,477 180,132 189,243 204,638 220,042 228,633 237,775 249,220 257,314 264,047 269,769 274,137 276,476 277,374 279,336 281,949 288,089 293,820 299,677 305,458 311,408 316,492 322,921 325,828 327,311 Estimated number of new wells constructed 139,301 139,802 123,747 108,943 73,505 59,619 74,236 78,852 84,775 84,837 83,915 80,527 69,499 56,434 48,740 41,561 32,728 30,775 29,773 29,908 31,322 34,932 39,118 43,585 43,879 39,223

Cost of greenhouse gas emission from upstream production ($Bn) 0.39 0.39 0.35 0.30 0.21 0.17 0.21 0.22 0.24 0.24 0.23 0.23 0.19 0.16 0.14 0.12 0.09 0.09 0.08 0.08 0.09 0.10 0.11 0.12 0.12 0.11 Present value of cost of greenhouse gas emission from upstream production ($Bn) 0.39 0.37 0.30 0.25 0.16 0.12 0.14 0.14 0.14 0.13 0.12 0.11 0.09 0.07 0.05 0.04 0.03 0.03 0.02 0.02 0.02 0.02 0.02 0.03 0.02 0.02 Sum of present value of cost of greenhhouse gas emission from upstream production ($Bn) 2.8

Cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 1.0 0.9 0.8 0.5 0.4 0.5 0.6 0.6 0.6 0.6 0.6 0.5 0.4 0.4 0.3 0.2 0.2 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3 Present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.9 0.8 0.6 0.4 0.3 0.4 0.4 0.4 0.3 0.3 0.3 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Sum of present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 7.4

Cost of forest diruption ($Bn) 0.5 0.6 0.5 0.4 0.3 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.2 0.2 Present value of cost of forest diruption ($Bn) 0.5 0.5 0.4 0.4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sum of present value of cost of forest diruption ($Bn) 4.0

Cost of road diruption ($Bn) 2.5 2.5 2.2 2.0 1.3 1.1 1.3 1.4 1.5 1.5 1.5 1.4 1.3 1.0 0.9 0.7 0.6 0.6 0.5 0.5 0.6 0.6 0.7 0.8 0.8 0.7 Present value of cost of road diruption ($Bn) 2.5 2.4 1.9 1.6 1.0 0.8 0.9 0.9 0.9 0.8 0.8 0.7 0.6 0.4 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.2 0.2 0.2 0.2 0.1 Sum of present value of cost of road diruption ($Bn) 18.3

Cost of mortality of workers ($Bn) 15.0 15.7 16.4 17.2 18.6 20.0 20.8 21.6 22.7 23.4 24.0 24.5 24.9 25.2 25.2 25.4 25.7 26.2 26.7 27.3 27.8 28.3 28.8 29.4 29.7 29.8 Present value of cost of mortality of workers ($Bn) 15.0 14.7 14.3 14.1 14.2 14.3 13.9 13.5 13.2 12.7 12.2 11.7 11.1 10.4 9.8 9.2 8.7 8.3 7.9 7.5 7.2 6.8 6.5 6.2 5.8 5.5 Sum of present value of cost of mortality of workers ($Bn) 274.7

Sum of present value of all costs associated with shale gas well 307.2

Bull case:Shale gas produtioin volume (trillion cubic feet) 1.5 2.0 3.4 4.9 7.9 9.7 9.4 9.6 10.0 10.5 11.0 11.5 12.1 12.7 13.3 14.0 14.7 15.5 16.2 17.0 17.9 18.8 19.7 20.7 21.7 22.8 24.0 25.2 26.4 27.7 29.1 30.6 32.1 33.7 Estimated number of wells 25,145 32,675 56,386 80,300 131,133 160,423 154,397 158,922 164,446 172,668 181,301 190,367 199,885 209,879 220,373 231,392 242,961 255,109 267,865 281,258 295,321 310,087 325,591 341,871 358,964 376,913 395,758 415,546 436,324 458,140 481,047 505,099 530,354 556,872 Estimated number of new wells constructed 139,301 139,993 124,916 110,067 68,752 49,456 65,976 72,469 78,516 82,441 86,563 90,892 95,436 100,208 105,218 110,479 116,003 121,803 127,894 134,288 141,003 148,053 155,455 163,228 171,390 179,959

Cost of greenhouse gas emission from upstream production ($Bn) 0.4 0.4 0.3 0.3 0.2 0.1 0.2 0.2 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.5 0.5 0.5 Present value of cost of greenhouse gas emission from upstream production ($Bn) 0.4 0.4 0.3 0.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Sum of present value of cost of greenhhouse gas emission from upstream production ($Bn) 3.8

Cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 1.0 0.9 0.8 0.5 0.4 0.5 0.5 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 1.0 1.0 1.1 1.1 1.2 1.2 1.3 Present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 1.0 0.9 0.8 0.7 0.4 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 0.2 0.2 Sum of present value of cost of air impacts from disel use during hydraulic fracturing ($Bn) 9.8

Cost of forest diruption ($Bn) 0.5 0.6 0.5 0.4 0.3 0.2 0.3 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 Present value of cost of forest diruption ($Bn) 0.5 0.5 0.4 0.4 0.2 0.1 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Sum of present value of cost of forest diruption ($Bn) 5.3

Cost of road diruption ($Bn) 2.5 2.5 2.2 2.0 1.2 0.9 1.2 1.3 1.4 1.5 1.6 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4 2.5 2.7 2.8 2.9 3.1 3.2 Present value of cost of road diruption ($Bn) 2.5 2.4 2.0 1.6 0.9 0.6 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.6 0.6 0.6 0.6 0.6 Sum of present value of cost of road diruption ($Bn) 24.3

Cost of mortality of workers ($Bn) 15.0 15.7 16.5 17.3 18.2 19.1 20.1 21.1 22.1 23.2 24.4 25.6 26.9 28.2 29.6 31.1 32.7 34.3 36.0 37.8 39.7 41.7 43.8 46.0 48.3 50.7 Present value of cost of mortality of workers ($Bn) 15.0 14.7 14.4 14.1 13.9 13.6 13.4 13.1 12.9 12.6 12.4 12.2 11.9 11.7 11.5 11.3 11.1 10.9 10.7 10.5 10.3 10.1 9.9 9.7 9.5 9.3 Sum of present value of cost of mortality of workers ($Bn) 310.4

Sum of present value of all costs associated with shale gas well 353.6

Table 10

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Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Bull case:Cost per shale gas well ($Mn) 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 Shale gas produtioin volume (trillion cubic feet) 1.5 2.0 3.4 4.9 7.9 9.7 9.4 9.6 10.0 10.4 10.9 11.5 12.4 13.3 13.8 14.4 15.1 15.6 16.0 16.3 16.6 16.7 16.8 16.9 17.1 17.4 17.8 18.2 18.5 18.9 19.2 19.6 19.7 19.8 Estimated number of wells 25,145 32,675 56,386 80,300 131,133 160,423 154,397 158,922 164,446 172,477 180,132 189,243 204,638 220,042 228,633 237,775 249,220 257,314 264,047 269,769 274,137 276,476 277,374 279,336 281,949 288,089 293,820 299,677 305,458 311,408 316,492 322,921 325,828 327,311 Estimated number of new wells constructed 139,301 139,802 123,747 108,943 73,505 59,619 74,236 78,852 84,775 84,837 83,915 80,527 69,499 56,434 48,740 41,561 32,728 30,775 29,773 29,908 31,322 34,932 39,118 43,585 43,879 39,223 Construction cost of new wells ($Bn) 417.9 419.4 371.2 326.8 220.5 178.9 222.7 236.6 254.3 254.5 251.7 241.6 208.5 169.3 146.2 124.7 98.2 92.3 89.3 89.7 94.0 104.8 117.4 130.8 131.6 117.7 Present value of construction cost of new wells ($Bn) 417.9 392.0 324.3 266.8 168.2 127.5 148.4 147.3 148.0 138.4 128.0 114.8 92.6 70.3 56.7 45.2 33.3 29.2 26.4 24.8 24.3 25.3 26.5 27.6 26.0 21.7 Sum of present value of construction cost of new wells ($Bn) 3,051.3

Base case:Cost per shale gas well ($Mn) 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 Shale gas produtioin volume (trillion cubic feet) 1.5 2.0 3.4 4.9 7.9 9.7 9.4 9.6 10.0 10.4 10.9 11.5 12.4 13.3 13.8 14.4 15.1 15.6 16.0 16.3 16.6 16.7 16.8 16.9 17.1 17.4 17.8 18.2 18.5 18.9 19.2 19.6 19.7 19.8 Estimated number of wells 25,145 32,675 56,386 80,300 131,133 160,423 154,397 158,922 164,446 172,477 180,132 189,243 204,638 220,042 228,633 237,775 249,220 257,314 264,047 269,769 274,137 276,476 277,374 279,336 281,949 288,089 293,820 299,677 305,458 311,408 316,492 322,921 325,828 327,311 Estimated number of new wells constructed 139,301 139,802 123,747 108,943 73,505 59,619 74,236 78,852 84,775 84,837 83,915 80,527 69,499 56,434 48,740 41,561 32,728 30,775 29,773 29,908 31,322 34,932 39,118 43,585 43,879 39,223 Construction cost of new wells ($Bn) 905.5 908.7 804.4 708.1 477.8 387.5 482.5 512.5 551.0 551.4 545.4 523.4 451.7 366.8 316.8 270.1 212.7 200.0 193.5 194.4 203.6 227.1 254.3 283.3 285.2 254.9 Present value of construction cost of new wells ($Bn) 905.5 849.3 702.6 578.0 364.5 276.3 321.5 319.2 320.7 299.9 277.3 248.7 200.6 152.2 122.9 97.9 72.1 63.3 57.3 53.8 52.6 54.8 57.4 59.8 56.2 47.0 Sum of present value of construction cost of new wells ($Bn) 6,611.2

Bear case:Cost per shale gas well ($Mn) 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 Shale gas produtioin volume (trillion cubic feet) 1.5 2.0 3.4 4.9 7.9 9.7 9.4 9.6 10.0 10.4 10.9 11.5 12.4 13.3 13.8 14.4 15.1 15.6 16.0 16.3 16.6 16.7 16.8 16.9 17.1 17.4 17.8 18.2 18.5 18.9 19.2 19.6 19.7 19.8 Estimated number of wells 25,145 32,675 56,386 80,300 131,133 160,423 154,397 158,922 164,446 172,477 180,132 189,243 204,638 220,042 228,633 237,775 249,220 257,314 264,047 269,769 274,137 276,476 277,374 279,336 281,949 288,089 293,820 299,677 305,458 311,408 316,492 322,921 325,828 327,311 Estimated number of new wells constructed 139,301 139,802 123,747 108,943 73,505 59,619 74,236 78,852 84,775 84,837 83,915 80,527 69,499 56,434 48,740 41,561 32,728 30,775 29,773 29,908 31,322 34,932 39,118 43,585 43,879 39,223 Construction cost of new wells ($Bn) 1,393.0 1,398.0 1,237.5 1,089.4 735.0 596.2 742.4 788.5 847.7 848.4 839.1 805.3 695.0 564.3 487.4 415.6 327.3 307.7 297.7 299.1 313.2 349.3 391.2 435.9 438.8 392.2 Present value of construction cost of new wells ($Bn) 1,393.0 1,306.6 1,080.9 889.3 560.8 425.1 494.7 491.1 493.4 461.5 426.6 382.6 308.6 234.2 189.0 150.6 110.9 97.4 88.1 82.7 80.9 84.4 88.3 91.9 86.5 72.3 Sum of present value of construction cost of new wells ($Bn) 10,171.1

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