Natural gas development is often touted for its associated economic prosperity brought to state and local economies. These boons may take the form of added jobs and greater revenue from the drilling crews and other gas-related business that move into the region to extract the resource. Indeed, this is the “boom” of the “boom-bust” cycle that characterizes extractive processes of non-renewable natural sources, including natural gas . 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 . Illustration of the boom-bust cycle in royalties, business income, tax revenue, and jobs 
There are several reasons for poor long-term economic prospects, despite the booming activity that floods into a region during the drilling phase. First, the crew that enters the region creates extra demand for limited housing stock, which causes housing prices to rise . Low 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 . 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 . 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 . The population change from 1990 to 2008 for both states is evident in Figures 17 and 18.
Figure . Population change in New York State 
Figure . Population change in Pennsylvania 
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 . 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.
Trucks are crucial in many parts of the natural gas extraction process. A typical Marcellus well requires 5.6 million gallons of water during the drilling process, which is delivered by truck . 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 .
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 . 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 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 . 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 . 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 .
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 . However, while it certainly has the potential to alleviate some road damage, such a solution would represent yet another cost, because it would require planning capacity, additional signage, and law enforcement efforts beyond a local government’s normal budget. Indeed, the economic burden associated with infrastructure damage seems to be an inevitable one associated with shale gas drilling.
Regional Industrialization’s Impacts on Local Industries
The industrial landscape brought about by shale gas development is not limited to well pads: water extraction sites and water treatment facilities are also developed, along with pipelines and compressor stations to transmit the gas from the well sites to the main transmission lines . 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 . 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 . 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 . The tourism and travel sector accounted for 3,335 direct jobs and roughly $66 million in labor income . 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 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” . Therefore, the growth of local industry and the foregone economic development is an important opportunity cost that should be factored into the analysis of where networks of gas pipelines are constructed.
Ineffectiveness of Taxes as a Solution
Due to the issue of public costs attendant to high volume hydraulic fracturing (HVHF), taxation has been touted as a potential solution. First, there is evidence that exaction of tax revenues is not pivotal to industry decisions about where to drill for natural gas. Rather, the oil and natural gas industries are guided mainly by the location of reserves . 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. 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.
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 . 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 . 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 .
Furthermore, drilling costs have increased over time, as depicted in Figure 19.
Figure . Average cost of new wells of all types at all locations in the US (costs normalized to $2000) 
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) . 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 . Lastly, capital levels are difficult to adjust in the short 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 . 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 . 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…” . 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.
Figure . Gas production over time for the R. Smith 2H wellpad in the Marcellus Shale Play 
Figure . Gas production over time for 3 wellpads in the Marcellus Shale Play 
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,