Cornell SGEIS Comments

Cornell University Faculty and Staff Comments on the revised draft version of the New York

Department of Environmental Conservation’s Supplemental Generic Environmental Impact

Statement on horizontal drilling and high-volume hydraulic fracturing

This is a compilation of comments from individual faculty and associates and is not meant to be read as a Cornell University Statement on the revised draft SGEIS.

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Chapter 6: Potential Environmental Impacts

6.8 Socioeconomic ImpactsThis section provides a discussion of the potential socioeconomic impacts on the Economy, Employment, and Income (Section 6.8.1); Population (Section 6.8.2); Housing (Section 6.8.3); Government Revenues and Expendi-tures (Section 6.8.4); and Environmental Justice (Section 6.8.5). A more detailed discussion of the potential im-pacts, as well as the assumptions used to estimate the impacts, is provided in the Economic Assessment Report, which is available as an addendum to this SGEIS. Revised Draft SGEIS 2011, Page 6-207

Comments by:David Kay, Senior Extension Associate, Cornell Community and Regional Development Institute, Department of Develop-ment Sociology

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Chapter 7: Existing and Recommended Mitigation Measures

7.1.1.1 New York State Department of Environmental Conservation Jurisdictions: Degradation of Water UseComment: The Revised SGEIS states that the NYSDEC intends to “require that permitees employ the Natural Flow Regime Method, as described below, as a mitigation measure to avoid degradation of water quality due to water withdrawals….” And, in the following paragraph, a Water Resources Bill is referenced which gives the NYSDEC authority to permit water withdrawals of any kind over 100,000 gallons per day. We suggest that it be explicitly stated that the NYSDEC will exercise permitting authority over all water withdrawals related to natural gas extraction, regardless of volume. This is important because 100,000 gallons represents a significant volume of water for some headwater streams, particularly during low flows. This could be incorporated into a “water sourcing plan” – similar to that proposed to be required for wastewater – which could be required as part of the permitting process.

7.1.1.4 Impact Mitigation Measures for Surface Water WithdrawalsComment: With respect to the regulation of surface water withdrawals, the Revised SGEIS proposes the use of the Natural Flow Regime Method (NFRM), with the use of regional passby flow coefficients based partly on wa-tershed area. We agree that this is likely an improvement over other methods, particularly approaches that rely on simplistic statistical measures such as the Q7-10. However, the drawback of the NFRM is not its appropriate-ness, but rather the amount of regulatory attention required to effectively administer it. In addition, we point out that the statement made on page 7-19, bottom paragraph, which states that “flow exceedance values… will depend on the watershed size upstream from the water withdrawal,” is subject to significant uncertainty. For example, an analysis of USGS gaged streams in NY will show locations where the relationship between watershed area and median/average flow is not easily modeled as the above statement implies. For example, the Chemung River at Chemung, NY drains a larger watershed than the Susquehanna River at Conklin, NY; however, the Susquehanna has an 81% higher median daily flow at this location. This illus-trates the importance of local and regional characteristics such as dams, water diversions, geology, and ground-water infiltration with respect to seasonal and daily flow characteristics. Passby flow coefficients, if they are to be used at all, are most effectively calculated on a finer scale. The NFRM approach as outlined in the Preliminary SGEIS has merit. However, to apply such a methodology effectively, taking into account local idiosyncrasies in hydrology, will require time and great care. Strategies that alleviate this regulatory burden while also providing environmental protection could be attractive if/when shale gas development increases in intensity.We suggest that the NYSDEC, in the face of potential shortages in regulatory personnel and rapid increases in shale gas development, consider a more strategic approach to mitigation of surface water withdrawal impacts. Restricting water withdrawals on small headwater streams while simultaneously allowing withdrawals on larger rivers might provide adequate environmental protection while reducing regulatory complexity.

7.1.8.1. Treatment Facilities (POTWs)Comment: As outlined in section 7.1.8.1., there are a number of proposed regulatory requirements that POTWs must satisfy before being allowed to accept shale gas wastewaters. In theory, the proposed approach protects receiving water bodies by requiring headworks analyses, by application of effluent limitations via SPDES per-mit, and by monitoring and reporting within a well established compliance system. We suggest, however, that the NYSDEC consider prohibiting all but the most advanced POTWs (those with parallel process configurations which are specifically designed for industrial waste streams) from accepting shale gas wastewaters. We offer the following reasoning: First, the additional capacity of POTW infrastructure in NY is currently very limited, particularly in the regions where most Marcellus development is likely to occur. Therefore, use of POTWs would likely involve significant transportation of wastes to areas of more intense historical industrial activity (such as Niagara Falls) and contribute to potential issues of equity with respect to who receives the benefits and con-sequences of this industrial development. Second, notwithstanding the limited flow capacity of POTWs, there are currently none with the capability to treat high-TDS waste (except by dilution). Furthermore, there is the potential for high-TDS waste streams to interfere with the effective operation of biological treatment systems.

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We suggest, as an alternative, that private investment in industrial treatment facilities, designed to treat these specific waste streams, and located within the region of waste generation, be promoted in every way possible. While it is obviously not within the scope of the SGEIS to require this kind of private treatment infrastructure, the prohibition of POTW use (at all but the most advanced plants) might further incentivize this development. Lastly, we note that such a policy may help to alleviate public fears, whether they be warranted or otherwise, regarding both the possibility of contamination of surface waters and/or the inability of the NYSDEC to ad-equately regulate and police large scale industrial development given limited staff.

Comments by: Susan J. Riha, Ph.D., Director, New York State Water Resources Insti-tute and Chrales L. Pack Professor, Dept. of Earth & Atmospheric Sciences, Cornell University

Brian G. Rahm, Ph.D., Research Associate, New York State Water Re-sources Institute

7.1.11.2 Setbacks from Other Surface Water Resources Based on the above information and mitigating factors, the Department proposes that site specific SEQRA re-view be required for projects involving any proposed well pad where the closest edge is located within 150 feet of a perennial or intermittent stream, storm drain, lake or pond.

7.2 Protectimg FloodplainsThe Department proposes to require, through permit condition and/or regulation, that high volume hydraulic fracturing not be permitted within 100-year floodplains in order to mitigate significant adverse impacts from such operations if located within 100-year floodplains.

7.4.1 Protecting Terrestrial Habitats and WildlifeSignificant adverse impacts to habitats, wildlife, and biodiversity from site disturbance associated with high-volume hydraulic fracturing in the area underlain by the Marcellus Shale in New York will be unavoidable. In particular, the most significant potential wildlife impact associated with high-volume hydraulic fracturing is fragmentation of rare interior forest and grassland habitats and the resulting impacts to the species that de-pend on those habitats. However, the following specific mitigation measures would prevent some impacts, minimize others, and provide valuable information for better understanding the impacts of habitat fragmenta-tion on New York’s wildlife from multi-pad horizontal gas wells.

7.4.1.1 BMPs for Reducing Direct Impacts at Individual Well SitesThe Department proposes that the BMPs listed below be required mitigation measures to reduce impacts as-sociated with development of individual wellpads and appurtenances located in natural habitats. During the permit review process, site-specific conditions would be considered to determine applicability of each BMP and permit conditions included as appropriate.

Require multiple wells on single pads wherever possible;

· Design well pads to fit the available landscape and minimize tree removal;· Require “soft” edges around forest clearings by either maintaining existing shrub areas,· planting shrubs, or allowing shrub areas to grow;· Limit mowing to one cutting per year or less after the construction phase of well pads is completed.

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Mowing would not occur during the nesting season for grassland birds (April 23 – August 15);· When well pads are placed in large patches of grassland habitat (greater than 30 acres) located within Grassland Focus Areas (as described in Section 7.4.1.2), construction and drilling activities are prohibited during grassland bird nesting season (April 23 – August 15);· When well pads are placed in large patches of grassland habitat (greater than 30 acres) located within Grassland Focus Areas, minimize impacts from dust during the grassland bird nesting season (April 23 – August 15) by using dust palliatives and other appropriate measures to reduce dust;· Require lighting used at wellpads to shine downward during bird migration periods (April 1 – June 1 and August 15 – October 15);· Limit the total area of disturbed ground, number of well pads, and especially, the linear distance of roads, where practicable; Design roads to lessen impacts ( including two-track roads and oak mats in low-vol ume areas) and limit canopy gaps;· Require roads, water lines, and well pads to follow existing road networks and be located as close as pos sible to existing road networks to minimize disturbance;· Gate single-purpose roads to limit human disturbance; and· Require reclamation of non-productive, plugged, and abandoned wells, well pads, roads and other infrastructure areas. Reclamation would be conducted as soon as practicable and would include interim steps to establish appropriate vegetation during substantial periods of inactivity. Native tree, shrub, and grass species should be used in appropriate habitats.


7.4.1.2 Reducing Indirect and Cumulative Impacts of Habitat FragmentationThe best opportunity for reducing indirect and cumulative impacts is to preserve existing blocks of the critically important grassland and interior forest habitats identified in Grassland and Forest Focus Areas (Figure 7.2) by avoiding site disturbance (wellpad construction) in those areas. Grassland Focus Areas represent those areas within the State that are most important for grassland nesting birds. Forest Focus Areas represent those areas in the State that contain large blocks of forest interior habitats. Development in these areas would be conditioned as outlined below to mitigate impacts on wildlife from habitat fragmentation. The following measures are considered necessary to mitigate the cumulative impacts of habitat fragmentation for these critically important habitat types while not strictly prohibiting development.

Grassland Focus AreasGrassland Focus Areas depicted in Figure 7.2 were determined by a group of grassland bird experts, including Department staff with input from outside experts representing federal agencies and academia.65 The focus ar-eas were derived from Breeding Bird Atlas (BBA) data from 2002- 2004;66 they were further modified by expert knowledge, and then followed up with a 2-year field verification study before being finalized. They represent areas of New York State that contain the most important grassland habitat mosaics.

The 2006 BBA provided the core dataset for delineating Grassland Focus Areas. All atlas blocks with a high rich-ness of breeding grassland birds, as well as contiguous blocks also supporting grassland species, were included in the focus areas. The target for the focus areas was to “capture” or include at least 50% of the BBA blocks where each of the grassland species was found to be breeding across the state. The focus areas were able to reach that target for all but the most widespread species. Although the BBA does not provide estimates of abundance or densities, one of the criteria for inclusion in a focus area was contiguity with adjacent blocks containing grass-land birds; analyses indicate that such blocks contain significantly higher abundances of the target species than isolated blocks.

Extensive field surveys were conducted in 2005 and 2006 throughout the focus areas. These surveys collected distribution and abundance data to confirm that the analysis of the breeding bird data reflected actual condi-tions in the field (Table 7.4). A total of 487 different habitat patches were surveyed statewide. In some cases, focus area boundaries were adjusted based on field survey data. The overall process resulted in the identifica-

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tion of 8 focus areas that support New York’s grassland breeding birds, 4 of which occur in the area underlain by the Marcellus Shale.

Specific Mitigation Measures to Reduce Impacts to GrasslandsIn order to mitigate impacts from fragmentation of grassland habitats, the Department proposes to require, through the permit process and/or by regulation, that surface disturbance associated with high-volume hydrau-lic fracturing activities in contiguous grassland habitat patches of 30 acres or more within Grassland Focus Areas would be based on the findings of a site-specific ecological assessment and implementation of mitigation mea-sures identified as part of such ecological assessment, in addition to the BMPs required for all disturbances in grassland areas that are identified in Section 7.4.1.1. This ecological assessment would include pre-disturbance biological studies and an evaluation of potential impacts on grassland birds from the project. Pre-disturbance studies would be required to be conducted by qualified biologists and would be required to include a compila-tion of historical information on grassland bird use of the area and a minimum of one year of field surveys at the site to determine the current extent, if any, of grassland bird use of the site. Should the Department decide to issue a permit after reviewing the ecological assessment, the applicant would be required to implement supplemental mitigation measures by locating the site disturbance as close to the edge of the grassland patch as feasible and proposing additional mitigation measures (e.g., conservation easements, habitat enhancement). In addition, enhanced monitoring of grassland birds during the construction phase of the project and for a minimum period of two years following active high-volume hydraulic fracturing activities (i.e., following well completion) would be required.

Explanation for 30 Acre Threshold: Many of New York’s rarest bird species that rely on grasslands are affected by the size of a grassland patch. Several species of conservation concern rely on larger-sized grassland patches and show strong correlation to a minimum patch size if they are to be present and to successfully breed. Mini-mum patch sizes will vary by species, and by surrounding land uses, but a minimum patch size of 30-100 acres is warranted to protect a wide assemblage of grassland-dependent species. Although a larger patch size is necessary for raptor species, a minimum 30 acres of grassland is needed to provide enough suitable habitat for a diversity of grassland species. Grasslands less than 30 acres in size are of less importance since they do not provide habitat for many of the rarer grassland bird species.68 The Grassland Focus Areas cover about 22% of the area underlain by the Marcellus Shale. However, the actual impacts on Marcellus development would affect less area for two reasons. First, only those portions of the Grassland Focus Areas meeting the minimum patch size requirement would be subject to the aforementioned additional restrictions on surface disturbance. Sec-ond, even in areas where surface disturbance should be avoided, gas deposits could be accessed horizontally from adjacent areas where the restriction does not apply.

Forest Focus AreasForest Focus Areas depicted in Figure 7.2 were based on Forest Matrix Blocks developed by The Nature Conser-vancy (TNC). TNC’s goal in developing Forest Matrix Blocks was to estimate viability and resilience of forests and determine those areas where forest structure, biological processes, and biological composition are most intact. Resilient forest ecosystems can absorb, buffer, and recover from the full range of natural disturbances. TNC used three characteristics in developing their Forest Matrix Blocks: size, condition, and landscape context. Size was based on the key factors of the area necessary to absorb natural disturbance and species area requirements (see Figure 7.3).Natural disturbances and minimum dynamic area: Eastern forests are subject to hurricanes, tornadoes, fires, ice storms, downbursts, and outbreaks of insects or disease. While most of these disturbances are small and recovery is fast, damage from larger catastrophic events may last for decades. Resilient forest ecosystems can absorb, buffer, and recover from the full range of natural disturbances. The effects of catastrophic events are typically spread across a landscape in an uneven way. Patches of severe damage are embedded in larger areas of moderate or light disturbance. Using historical records, vegetation studies, air photo analysis, and expert in-

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terviews, TNC scientists determined the size and extent of patches of severe damage for each disturbance type expected over one century. Historic patterns in the Northeast suggest that an area of approximately four times the size of the largest severe damage patch is necessary for a particular matrix block to remain adequately resilient.

· Breeding territories and area sensitive species: Forest ecosystems must also be big enough to support characteristic interior species, including birds, mammals, herptiles, and insects. Many species establish and defend territories during breeding season, from which they obtain resources to raise their young. Twentyfive times the average size of a territory, together with information on other minimum area restrictions for that species may be used as an estimate of the space needed for a small population. This reflects a rule of thumb developed for zoo populations on the number of breeding individuals required to conserve genetic diversity over generations (Figure 7.3)· Condition was based on the key factors of structural legacies, fragmenting features, and biotic composi-tion. TNC’s criteria for viable forest condition were: low road density with few or no bisecting roads; large regions of core interior habitat with no obvious fragmenting feature; evidence of the presence of forest breeding species; regions of old growth forest; mixed age forests with large amounts of structure or forests with no agricultural history; no obvious loss of native dominants; mid-sized or wide-ranging carnivores; composition not dominated by weedy or exotic species; no disproportional amount of damage by patho-gens; and minimal spraying or salvage cutting by current owners. Matrix blocks are bounded by fragment-ing features such as roads, railroads, major utility lines, and major shorelines. The bounding block features were chosen due to their ecological impact on biodiversity in terms of fragmentation, dispersion, edge effects, and invasive species; and· Landscape context was based on the key factors of edge-effect buffers, wide-ranging species, gradients, and structural retention. In evaluating landscape context, TNC evaluated and recorded information on the surrounding landscape context for all matrix communities. TNC generally considered areas embedded in much larger areas of forest to be more viable than those embedded in a sea of residential development and agriculture. However, no area was rejected solely on the basis of its landscape context because the matrix forests in many of the poorer landscape contexts currently serve as critical habitat for forest interior species and may be the best example of the forest ecosystem type. Thus, this criterion was used to reject or accept some examples that were initially of questionable size and condition.

TNC applied the territory size and disturbance factors to all of the ecoregions in the Northeast, and tai-lored minimum size thresholds for matrix blocks to each ecoregion’s forested extent, ecology, and natural disturbance history. The area underlain by the Marcellus Shale in New York is located in the High Allegheny Plateau (HAL) ecoregion (minimum block size of 15,000 acres), and contains 26 forest matrix blocks ranging in size from 17,000 acres to 176,000 acres, totaling 1.3 million acres. These matrix blocks are comprised of several dominant forest community types, including Northern hardwoods, maple-birch-beech forest, oak hickory forest and Allegheny oak forests.

Specific Mitigation Measures to Reduce Impacts to ForestsIn order to mitigate impacts from fragmentation of forest interior habitats, the Department proposes to require, through the permit process and/or by regulation, that surface disturbance associated with high-volume hydraulic fracturing activities in contiguous forest patches of 150 acres or more within Forest Focus Areas would be based on the findings of a site-specific ecological assessment and implementation of mitiga-tion measures identified as part of such ecological assessment, in addition to the BMPs required for all distur-bances in forested areas that are identified in Section 7.4.1.1. The ecological assessment would include pre-disturbance biological studies and an evaluation of potential impacts on forest interior birds from the project. Pre-disturbance studies would be required to be conducted by qualified biologists and would be required to include a compilation of historical information on forest interior bird use of the area and a minimum of one year of field surveys at the site to determine the current extent, if any, of forest interior bird use of the site.

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7.4.1.3 Monitoring Changes in HabitatThe following mitigation measures are necessary to better understand and evaluate the impacts of habitat fragmentation on New York’s wildlife from multi-pad horizontal gas wells and would be required as permit conditions for any applications seeking site disturbance in 150-acre portions of Forest Focus Areas and 30-acre portions of Grassland Focus Areas:

· Conduct pre-development surveys of plants and animals to establish baseline reference data for future comparison;· Monitor the effects of disturbance as active development proceeds and for a minimum of two years fol-lowing well completion. Practice adaptive management as previously unknown effects are documented; and· Conduct test plot studies to develop more effective revegetation practices. Variables might include slope, aspect, soil preparation, soil amendments, irrigation, and seed mix composition. With the aforementioned measures in place, the significant adverse impacts on habitat from high volume hydraulic fracturing would be partially mitigated.

7.4.3 Protecting Endangered and Threatened SpeciesProspective project sites should be screened against the Department’s Natural Heritage Database to deter-mine if endangered or threatened species are known to occur within the vicinity. The best method for reducing impacts to these species is to avoid siting projects in locations and habitats known to be utilized by endangered and threatened wildlife. Whenever possible, impacts to endangered and threatened animal species should be avoided. The process for accomplishing this is laid out below:

· As part of the EAF, the project proponent should do at least one of the following to screen the project


Should the Department decide to issue a permit after reviewing the ecological assessment, the applicant would be required to implement supplemental mitigation measures by locating the site disturbance as close to the edge of the forest patch as feasible and proposing additional mitigation measures (e.g., conservation ease-ments, habitat enhancement). In addition, enhanced monitoring of forest interior birds during the construction phase of the project and for a minimum period of two years following the end of high-volume hydraulic fractur-ing activities (i.e., following date of well completion) would be required.

Explanation for 150-Acre Threshold: Fragmentation of large forest blocks can negatively affect breeding birds that require interior forest habitat for successful reproduction. Fragmentation due to human development of forest openings and structures that are relatively permanent will fragment habitats, create more edge, and reduce breeding success. Human induced openings can influence breeding bird productivity several hundred feet from the edge of the forest through increased predation and increased nest parasitism. There is a wide diversity of bird species that rely on forest interior habitats to breed. As such, patch size requirements can vary widely by species, and can be influenced by surrounding land cover as well as the amount of forest cover on the landscape. Previous research on forest interior birds suggests that the minimum forest patch size needed to support forest breeding species ranges between 100 and 500 acres. A 100-acre patch size is the minimum that would probably support a relatively diverse assemblage of forest breeding birds. Additional research indicates that the negative impacts along a forest edge extend between 200-500 feet into the forest. If we assume a 100- acre forest patch with a 300-foot forested buffer, the minimum patch size for forest interior birds is approxi-mately 150 acres of contiguous forest. Patches less than 150 acres are not of optimum value to forest interior birds. The Forest Focus Areas outside the Catskill Forest Preserve cover about 6% of the area underlain by the Marcellus Shale. However, the actual impacts on Marcellus development would affect less area for two reasons. First, only those portions of the Forest Focus Areas meeting the minimum patch size requirement would be sub-ject to the aforementioned restrictions on surface disturbance. Second, even in areas where surface disturbance should be avoided, gas deposits could be accessed horizontally from adjacent areas. Given the horizontal reach of the wells, only about 2% of the subsurface areas would not be accessible.

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site for potential endangered and threatened animal species: · Request a screening from the New York Natural Heritage Program; · Self-screen utilizing the Nature Explorer and Environmental Resource Mapper web tools on the Depart-ment’s website; or · Conduct site-specific surveys to determine if endangered and threatened animal species are present at the project site; · If any endangered and threatened animal species are found to occur in the vicinity of the project site, the project proponent should consult with the Regional Department Natural Resources Office; · Regional Department staff can work with project proponent to identify how species may be affected; · Project proponent changes the location of the proposed project or otherwise modifies the project to avoid any potential “take” of a protected species identified by Department staff; and · If the “take” of an endangered and threatened species is deemed to be unavoidable, the project propo-nent would be required to apply for an Incidental Take Permit.

The specific procedure for applying for the Incidental Take Permit is set forth in the Department’s regulations at 6 NYCRR Part 182 and is summarized below:

· The applicant develops an endangered or threatened species mitigation plan; · The applicant develops an implementation agreement that affirms how the mitigation plan will be ac-complished; · The Department reviews the mitigation plan and implementation agreement to determine if it meets applicable regulatory criteria; and · If the Department approves the mitigation plan and implementation agreement and all other regulatory criteria are met, then an Incidental Take Permit can be issued, subject to the requisite SEQRA review.

The Department finds that with the implementation of the above measures, impacts on protected endangered and threatened species would be minimized.

7.4.4 Protecting State-Owned LandAs discussed in Section 6.4.4, the following issues are of significant concern as they relate to State-owned for-ests, wildlife management areas and parklands, and the potential impacts upon them (See also Sections 6.4.1 and 7.4.1):

· Forest fragmentation: Because of their size and long-term ownership, the specified stateowned public lands are integral to providing continuous interior forest habitat conditions and are protected from indus-trial development. The road systems needed to conduct drilling and fracturing operations represent signifi-cant potential impacts to this important habitat type; · Grassland fragmentation: Because of their size and long-term ownership, the specified state-owned lands are integral to providing grassland habitat conditions and are protected from industrial development. The road systems needed to conduct drilling and fracturing operations represent significant potential impacts to this important habitat type; · Public recreation: The level of truck traffic associated with horizontal drilling and high volume hydraulic fracturing, the presence of drilling rigs and compressor complexes, and the need to light well pads during drilling and fracturing operations would be likely to create significant impacts on public recreation opportu-nities during the construction, drilling and fracturing phases of development; and · Wildlife impacts: Increased light and noise levels would be likely to have significant impacts on local wildlife populations, including impacts on breeding, feeding and migration. The activities creating these impacts could take place for up to three years at any one site, depending on how many wells are drilled from a particular well pad. The local wildlife populations could take years or even decades to recover.

As an example for one natural gas reservoir that could be developed by high-volume hydraulic fracturing, State Forests, Wildlife Management Areas and State Parks comprise less than 6% of the area underlain by the Marcel-

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lus Shale in New York State. (As stated in Chapter2, drilling will not occur on Forest Preserve lands because the State Constitution prevents their being leased or sold.) Acknowledging that there will likely be physical, techno-logical, ownership and leasing impediments to reaching all areas under State-owned forests, wildlife manage-ment areas and parklands, it is still likely that less than 3% of the Marcellus Shale formation would be rendered unavailable by prohibiting horizontal drilling and high-volume hydraulic fracturing surface disturbance on these lands.

In order to ensure that the State fulfills the purposes for which State Forests and State Wildlife Management Areas were created, no surface disturbance associated with horizontal drilling and high-volume hydraulic fracturing would be permitted on State Forests or Wildlife Management Areas. This prohibition does not include accessing subsurface resources located within these areas from adjacent private lands. With the surface dis-turbance restriction in place, the Department concludes that impacts to the specified state-owned lands from high-volume hydraulic fracturing would be minimized. Current OPRHP policy would impose a similar restriction on State Parks.

Comments by: Todd Bittner, Natural Areas Director, Cornell Plantations

7.8 Socioeconomic Mitigation MeasuresHigh-volume hydraulic fracturing operations would have many positive socioeconomic results in the local areas where development is expected to occur. These operations would likely result in a substantial increase in economic activity in the affected areas, as well as a substantial increase in tax revenues to the state and locali-ties. However, as described in previous sections, this increased economic activity would also have the potential to result in adverse impacts in regions with high drilling activity, particularly acute in the short term, including localized impacts on the housing market caused by the in-migration of construction and production workforces and an increase in demand for certain state and local government services, resulting in increased government expenditures.

As discussed in Section 6.8, potentially significant adverse impacts on local communities associated with an in-crease in population and increased demand for housing and community services are tied to the rate of develop-ment. Impacts that were potentially significant under the average development scenario were not as significant under the low development scenario. Similarly, impacts on population, housing, and community services are more significant when concentrated in smaller geographic areas than when incurred across broader geographic areas or statewide. The rate and concentration of development also affects the significance of impacts on visual resources, the ambient noise environment, and transportation networks. The rate and concentration of devel-opment is related to many factors that cannot necessarily be controlled, such as the price of natural gas, input costs, the price of other energy sources, changes in technology, and the general economic conditions of state and nation, which will all affect the overall rate of development, as well as the uncertainty in the development potential of the Marcellus and Utica Shales. Revised Draft SGEIS 2011, Page 7-120

COMMENT A: Many of the adverse impacts mentioned are related to community character. Are mitiga-tions discussed in that section of the report as well?

Through its permitting process, the Department will monitor the pace and concentration of development throughout the state to mitigate adverse impacts at the local and regional levels. The Department will consult with local jurisdictions, as well as applicants, to reconcile the timing of development with the needs of the com-munities. Where appropriate the Department would impose specific construction windows within well con-struction permits in order to ensure that drilling activity and its cumulative adverse socioeconomic effects are not unduly concentrated in a specific geographic area. Revised Draft SGEIS 2011, Page 7-120

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COMMENT B: The Department says that is will “monitor… to mitigate” through its permitting process. it-self. What will the indicators or information be that are monitored, and the criteria for responding to them? Also, the permitting process itself controls the pace, scale and nature of development. So it seems the language should read “permitting to mitigate” as much or more than “monitoring to mitigate.” The idea of consultation with local jurisdictions and applicants in this context is laudable , but needs more definition as to what it might mean. Finally, while the option of imposing construction windows might well be a good one, care should be taken not to impose it in situations that create unintentionally perverse incentives where the deadline itself creates a rush. I would argue, perhaps as a caution, that a common lease provi-sions which require the gas developer to “hold by production” or forfeit the lease incentivizes a high pace of drilling, especially early in the development of a field, that is often not in the interests of the public, the gas developer, or sometimes even the landowner themselves whose interests in obtaining royalty payments are supposedly served by this provision.

Another way to mitigate the potential adverse impacts associated with in-migration to the region would be to actively encourage the hiring of local labor. Because natural gas exploration, drilling, and production activities typically require specialized skills, a jobs training program or apprentice program should be developed through the SUNY system (e.g., community colleges and agricultural and technical colleges) to increase the number of local residents with the requisite job skills for the natural gas industry, thereby reducing the number of workers that would need to be hired from outside the region. Such a program would also have the benefit of reduc-ing unemployment in these regions. A jobs training program would not eliminate the need for in-migration of skilled labor, but the program could partially offset the in-migration ofworkers and thus partially offset the potential housing impact from such in-migration. Revised Draft SGEIS 2011, Page 7-120

COMMENT C: Economic development strategies intended to optimize meaningful local workforce devel-opment should be pursued in any event, beyond whatever effectiveness they might have as a “mitigation measure” in the SEQRA context. In the same light, there are other “mitigation” strategies that should be undertaken by local governments in partnership with, and involving support from, various State and state supported agencies. Two areas of particular concern are with local government capacity to 1) manage the significant acceleration of off-site changes in land use likely to accompany natural gas development, as discussed in several places in the Draft SGEIS, and 2) manage the volatility of the revenue and cost impacts likely to be associated with drilling. In each of these cases, communities with low capacity for planning or low attention to these issues will either fail to capitalize on opportunities or be faced with avoidable prob-lems. The land use planning and technical assistance resources of the state, particularly through the DOS but also through funding of other entities with planning capacity, should be funded and deployed through-out the region at a level that can help mitigate the likely land use impacts of unplanned ancillary develop-ment. Similarly, the fiscal planning and technical assistance resources of the State, particularly through the NYS Comptroller’s office but also through funding of other entities with fiscal planning capacity, should be funded and deployed throughout the region at a level that can help mitigate the likely impacts of fiscal volatility. Because the impacts are likely to be regionally concentrated, strategies for focusing resources and capacity in this arguably heretofore underserved part of the state might be considered.

Comments by:David Kay, Senior Extension Associate, Cornell Community and Regional Development Institute, Department of Develop-ment Sociology

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Chapter 10: Review of Selected Non-Routine Incidents in Pennsylvania

Questions about two primary issues concerned me in the reading of this chapter. The first is, what is the ba-sis of the selected incidents described and what are the general lessons to be drawn from these incidents? Related questions include: how representative are these incidents, and how widely applicable would be the actions taken to redress and prevent them? How representative is the sample of incidents reported of the total number of incidents that have actually occurred? The second issue is that throughout the document it wasn’t clear whether the incidents occurred because of inadequate regulatory policies, violations of policies or some combination. The mitigations described primarily involve the kind of policies that will be implemented, but if adequate policies had already been in place in Pennsylvania, then it’s not clear whether policy implementation would provide sufficient protection against such incidents. Moreover, the document does not describe what will be done if incidents do occur, despite the precautions.

10.1: Gas Migration – Susquehanna and Bradford counties. The section reports that the appearance of methane in water wells in Dimock Township “was attributed to excessive pressures and improperly or insufficiently ce-mented casings…”, and other incidents “were attributed to the failure to properly case and cement wells”.. There is ambiguity in the verb “attributed”. It is not clear whether these factors (e.g., excessive pressures) were found definitively to be the cause of the methane appearance, or whether those factors were put forth as possible causes. One implication of this ambiguity is that if these factors were not found definitely to be the cause, then it isn’t clear whether the measures put into place would adequately address the problem of methane gas migra-tion. Examples of unambiguous verbs are: “was found to be caused by” or “was shown to be due to.” A second question here, related to the general point I raise at the beginning, is whether the improper cementing and casing in these incidents were violations of existing regulations or whether the regulations themselves were inadequate. It would be important to clarify this because, if Pennsylvania already had in place the kinds of regu-lations being proposed for New York, that then raises the question of whether the regulations being proposed for NY would be sufficient mitigation for the problem. More attention may need to be placed on enforcement strategies.

10.1.2: New York mitigation measures. This section describes requirements regarding well cementing and casing, and the degree of pressure. It isn’t clear, however, what criteria have been applied to determine the standards. For example, the second point in former Commissioner Williams’ decision is to “prohibit excessive annular pres-sure…” What is the criterion defining excessive, and what is the origin of the criterion? Later in the section it is stated that permits will not be issued until the wellbore design “has been reviewed by Department staff and deemed satisfactory.” What criteria would be applied for making this determination? Although the degree of detail and technical input that went into determining the standards may be beyond the intended scope of this chapter, some indication at least of the origin of the standards, and where someone with the interest and knowledge to review them could find them.

10.2 Fracturing Fluid Releases – Susquehanna and Bradford CountiesSection 10.2.2. New York Mitigation Measures to prevent fracturing fluid release. The section begins by describ-ing the site layout in Dimock as “unusual”, presumably based on the elevation differences between the well pad and the fresh water tanks. What standards would be applied to determine when a well layout falls outside of accepted standards, thus flagging the need for special review? This paragraph implies that sites with this kind of elevation would eventually be allowed in New York, as long as certain “site-specific permit conditions” were in place. Have such conditions been designed, and are they available for review?

10.3: Uncontrolled Wellbore Release of Flowback Water and Brine – Clearfield CountyThe description of the incident (section 10.3.1) does not indicate clearly whether the problems were ultimately due to inadequate regulations or to violations of existing regulations. The “blowout prevent equipment was inadequate,” but were the existing standards themselves inadequate, or was there violation of those standards?

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Chapter 10: Review of Selected Non-Routine Incidents in Pennsylvania

10.4: High Total Dissolved Solids (TDS) discharges – Monongahela RiverIn the description of the incident (Section 10.4.1) it may not be clear to the general public what exactly is meant by “…an increase in…wastewater discharges may have provided the TDS ‘tipping point’,,, It would be useful to indicate what the concept of a tipping point means in the specific context of TDS volume and what the implica-tions are for the river water. A description is given of regulatory measures taken by Pennsylvania to prevent this from occurring in the future, but are there direct actions that can be taken to lower TDS volume? Is it the case thatthese volumes eventually return to acceptable levels over time, through a natural process of the river flow? In the description of the NY mitigation, it is stated that “the Department anticipates that operators will favor reusing flowback water…” What are the reasons for not making such reuse a requirement?

Comments by:Poppy L. McLeod, Associate Professor, Cornell University Department of Communication

Was the absence of certified well-control personnel a violation of requirement, or were there not requirement for the presence of the personnel? The description of the mitigation (Section 10.3.2) describes the imposition of more stringent controls. The addition of such controls may not necessarily be sufficient mitigation if the root cause of the incident was violation of already adequate policies. What mitigation in the form of enforcement practices will also be implemented?

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General Thoughts and Comments

Having said that, it is clear that the SGEIS does nothing to protect ag land. So my concerns remain:• Hugeamountsofaglandwillbelostunnecessarilyasaresultofpoorplacementofdrillingpads,access

roads and pipelines, along with improper handling of topsoil• Largeamountsofimportantagsoilswillbedamagedduetoimproperhandlingofsoilsduringdrill

site preparations and pipeline digging operations.I also believe that to allay the concerns of the general public and consumers of the region’s ag products, the SGEIS should require food grade fracking fluid, or non-toxic fracking fluid.

Comments by:Kenneth SmithCooperative Extension Associate, Chenango County

Recommendation Three: Protection of Agricultural Lands and Coordination with NYSDAMYates County’s 126,000 acres of production agricultural lands are some of the best farmland soils in the State

of New York. The majority of the soils are either prime or soils of statewide significance and 4 farms totaling 1,200 acres have recently been protected through the purchase of development rights by NYS Ag and Markets due to their statewide and local importance. Our area is one of the few that demonstrates a significant growth in agriculture (dairy, grapes, vegetable, and so on) including a 17.5% increase in dairy farms from 223 to 262 between 2002 and 2007. The agriculture industry generates over $88 million per year and is an integral part of the economy, landscape and attraction for tourism, including the 36 wineries in the county.

Very little is mentioned in the dSGEIS on the value and the specific mitigation measures regarding agricul-ture. The dSGEIS mentions that a SEQR (State Environmental Quality Review) will be required for areas disturbed over 2.5 acres in Ag District, but does not guarantee what will be required or how it will be enforced. The NYS-DAM is not listed as an involved agency and should be for farms located in certified state Agricultural Districts. Hydrofrac sites should minimize their impact on farmlands located in Agricultural Districts and a mitigation plan should be developed following NYSDAM standards and reviewed and approved by certified erosion control specialists to ensure reclamation restores productive agricultural lands to pre-construction status (i.e. fertility, soil health, drainage, etc.) See Appendix Two. Agricultural plan remediation should be inspected by the NYSDEC inspectors and/or third party inspectors qualified to ensure reclamation restores productive agricultural land to pre-constructions conditions. Ideally, inspections should be conducted by Ag and Market hired and supervised inspectors ensuring Ag reclamation standards are met. We highly recommend that local SWCD (Soil and Water Conservation District) be hired to provide this inspection service locally as they are the most familiar with local farms, drainage, water quality issues, and SWPPP (Stormwater Pollution Prevention Plan) planning.

Comments by:Peter LandreDirector, Yates County Cooperative Extension

Agriculture

15

General Thoughts and CommentsEconomic and Social Impacts

SUMMARY OF KEY POINTSpertaining to the Revised Draft SGEIS section on Socioeconomic Impacts (http://www.dec.ny.gov/data/dmn/

rdsgeisfull0911.pdf, Revised Draft SGEIS 2011, Page 6-207 ff) and the “Economic Assessment Report for the Supplemental Generic Environmental Impact Statement on New York State’s Oil, Gas, and Solution Mining

Regulatory Program August 2011” (See http://www.dec.ny.gov/docs/materials_minerals_pdf/rdsgeisecon0811.pdf)

November 7, 2011I. The study adds a significant amount of new material to the public record that was not included in the initial draft. II. The study has significant new strengths and significant new weaknesses.

a. Major strengthsi. The report appropriately conveys the importance the pace and scale of gas drilling has for the analysis. ii. Inevitable uncertainties and difficulties in analysis at many levels – and most importantly re garding the pace and scale of development – are acknowledged and even highlighted

1. From the beginning to the end, the difficulty of making accurate “predictions” about the future based on limited information and a wide range of possible outcomes is acknowledged. 2. The study presents most of its results as a range of possible outcomes based on possible de velopment scenarios rather than as a single estimate. A “development scenario” approach is an appropriate way to address uncertainty.

iii. The study takes an important first step at analyzing impacts within different kinds of subre gions of the Marcellus shale play as well as within the state as a whole.

1According to the Revised Draft SGEIS, “Section 6.8, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011, and was adapted by the Department.” (See Revised Draft SGEIS 2011, Page 6-207), Ditto for Section 7.8 Socioeconomic Mitiga-tion Measures. Moroever, Section 6.8.2 Population, “presents a summary of the population and demographic findings of the Economic Assessment Report (2011) written by Ecology and Environment Engineering, P.C.” (Revised Draft SGEIS 2011, Page 6-231) Because it appears that almost all the statements included in these sections of the Revised Draft SGEIS are directly quoted from or derived from the report by Ecology and Environment Engineering, my comments focus more on that source document and its page numbers than on the Revised Draft SGEIS itself.

iv. The study considers major variables of importance that go beyond a minimalist approach to input/output analysis

1. IO focuses on employment/income2. This study includes estimates of population and housing impacts based on assumed workforce impacts.

b. Major weaknessesi. While jobs and income and population growth benefits are quantified, there is an inbalance in that most negative impacts are merely mentioned.ii. The high end development scenario appears to have been appropriately removed from consideration in relation to the economic impact analysis. However, there is reason to believe that even the “average” development scenario projects too much gas extraction, and that the range of likely impacts is therefore not credibly bounded. If so, both the positive and negative effects mentioned are likely exaggerated. This is a major concern.iii. While the broad geographic distribution of impacts is considered, no analysis at the community level is provided. This concern is particularly important regarding the fiscal impacts – local governments at the town and village level need to understand what will happen to them or they will miss critical opportunities and problems.iv. No real consideration is given to the effects of drilling on counties near but outside the areas of

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drilling. Similarly, little consideration is given to rural/urban relationships within the regions studied.v. While the smooth development pattern that is assumed is identified as being an unrealistic but convenient assumption, no effort is made to identify the extent to which this assumption masks the potential for impacts to exceed tolerances, thresholds, tipping points, etc. This is perhaps another of my biggest concerns about the study.vi. No effects of increased wages are included in the economic impact estimates, contrary to most input-output practice. No explanation of the unusual decision to analyze only interindustry effects is mentioned.vii. Even more notable but related, no effort to estimate and track income to landowners is made. Therefore the study ignores the potential for economic development planning strategies that capitalize on this income stream. This is yet another major concern.viii. The use of highly aggregated RIMS II multipliers involves an even less sophisticated modeling tool than used by other existing economic impact studies of shale gas development, none of which are critiqued or even mentioned. Limitations of input output models are not acknowl edged, nor are alternative modeling approaches that might have been used.

III. The study does not make assumptions that are uniformly favorable to one side or the other involved in the partisan debate about drilling. Some assumptions will tend to overestimate the socioeconomic impacts quantitatively reported (e.g . an excessively high estimate of gas extraction, counting many part time jobs as if they were full time – probably due to an error in interpreting RIMS II results; or using average overlapping tax rates to estimate tax revenues, which falsely assumes that the high tax rates common in more urban jurisdictions will be applied to the wells which are much more likely to be drilled in rural towns), while others will tend to underestimate the impacts (eg. not accounting for any positive effects of increased incomes to landowners; ignoring the induced effects of increased income to workers or business people in the region)

i. The issue of the accuracy about the number of wells drilled is probably determinative, but otherwise it is difficult to know whether the net effect of questionable assumptions would be positive or negative overall.

IV. Scope & purpose of study: The title of the Ecology and Environment Engineering report is: “Economic Assessment Report”. However, it’s also labeled a “Socio-economic Impact Analysis (PDF)” on the DEC website. This raises the question of what the study is intended to cover, and what its function is in the Revised Draft SGEIS analysis. Actual subjects covered include impacts on

a. Employment and Income impacts (traditional economic topic)b. Population impacts (traditional demographic/socioeconomic topic)c. Housing and property value impacts (traditional demographic/economic topic)d. Government revenue and expenditure impacts (traditional fiscal topic)e. So, what’s missing or not clearly present from a comprehensive socioeconomic study, just in terms of these broad subject areas?

i. Impact on schools, impact on crime rates, impact on accident rates, impact on “character of community” (types of people, distribution of impacts, effects on buildings, noise etc. – some of this presumably in other parts of document). Some of these are covered in other sections of the Draft SGEIS, but it’s not clear what went where and why.ii. What else was left out, and what standards guided the choice of what was analyzed and what was not?

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DETAILED COMMENTS ON TEXT

Comments on: Economic Assessment Report for the Supplemental Generic Environmental Impact Statement on New York State’s Oil, Gas, and Solution Mining Regulatory Program

Unless otherwise specified, page numbers refer to that document.

The Website header and text refer to:

Socio-economic Impact Analysis Report, Ecology and Environment, P.C. (E & E) (see http://www.dec.ny.gov/en-ergy/75370.html)

Table of contents says the following will be covered: Impacts on Economy, Employment Income; Population, Housing, Government (by Region)

This technical report provides additional analysis of the potential impacts on the socioeconomic environment from development and production of the natural gas resources of the Marcellus Shale and other low-permeabil-ity reservoirs in the state. From p 1-1

COMMENT 1: Is this a socioeconomic study, as the header text and other text imply but the actual report title does not? Clarify relation between economic and noneconomic impacts, and where they are addressed in Revised Draft SGEIS.The report covers a low, medium, and high level of development.

Three regions were selected to evaluate differences between areas with a •high,average,andlowproductionpotential;areasthathave•experiencedgasdevelopmentinthepastandareasthathavenotexperiencedgasdevelopmentinthe past; and •differencesinlandusepatterns.•RegionA:BroomeCounty,ChemungCounty,andTiogaCounty•RegionB:DelawareCounty,OtsegoCounty,andSullivanCounty•RegionC:CattaraugusCountyandChautauquaCounty

See p. 1.2

COMMENT 2: Another critical issue for economic impact analysis is the extent of economic integration and urbanization within the region; this is what largely determines the extent of local multipliers. Work spon-sored by the Legislative Commission on Rural Resources, for example, classified (as of 2000; see http://land-grant.cornell.edu/cu/cms/landgrant/impact/rural/upload/socioeconomic_trends.pdf) the counties in the regions as follows:

Region A: Broome County, METRO; Chemung County RURAL-URBAN; and Tioga County RURAL-SUBURBANRegion B: Delaware County, RURAL PERIPHERY; Otsego County RURAL URBAN; and Sullivan County RURAL PERIPHERYRegion C: Cattaraugus County and Chautauqua County, BOTH RURAL-URBAN

It is not simply the differences in land use pattern that are critical for this kind of economic analysis, but also understanding the extent to which the regional economy is or has the potential to be diversified and self sufficient. One would generally presume a priori that Region A would have much greater potential along

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Economic and Social Impactsthese lines than either of the other two regions. While it is a good move for this analysis to highlight the dif-ferent subregional impacts, the criteria for constituted the regions as they are lacks attention to this issue.

Similarly, what about the effects on other nearby counties – Steuben? Tompkins? Socioeconomic impacts do not stop at county boundaries, especially with a mobile labor force, significant housing costs/housing stock differentials as well as diverse amenities available in nearby counties . A similar point can be made for the various sources of indirect and induced purchases from business. The analysis would be strength-ened if it considered a proxy for many of these factors such as the relation of “commute sheds” to the subre-gional definitions.

“Socioeconomic impacts associated with well development and production in the Marcellus and Utica Shales are based on assumptions regarding

• theexpectednumberofwellsthatwouldbedeveloped,• theamountofnaturalgasproducedbyeachwell,and• thenumberofyearsthewellswouldremaininproduction.

All of these assumptions are influenced by a number of factors that singularly and collectivelyaffect the reliability of these estimates.” P 2-1 ... The national natural gas market has experienced significant un-foreseen developments on both the demand and supply side within the last two decades… The level of natural gas drilling activity, as measured by the number of active gas drilling rigs, also fluctuated substantially in the past decade (2001-2011) in response to changes in the price of natural gas (see Figure 2-2). P. 2-2.

COMMENT 3: All of this is good background, but its significance should also be explored in relation to the stages of development of the Marcellus fairway. The observed dynamic will differ in later stages of field development than during the earlier stages. Early on, the effects are more heavily influenced by patterns of exploratory drilling, the lack of infrastructure, and the “hold by production” imperative for the industry to retain rights to leases by drilling/producing, but while perhaps only “toe fracing” some of these wells to stimulate minimal production.

The EIA projects a massive increase in the production of natural gas from shale, with shale gas becoming the single largest source of natural gas supply within the next five years and remaining so for the remainder of the projection period. P 2-3

COMMENT 4: An update should reference the significance of the EIA’s revised estimates of the gas resource based on the USGS revisions announced in August, as was done on p. 4-23 of the revised SGEIS See http://www.usgs.gov/newsroom/article.asp?ID=2893

The EIA emphasizes that there is considerable uncertainty surrounding their projectionof the future supply of shale gas. They point out that this uncertainty derives in large part from the fact that shale formations have only recently become a major source of gas production and that, consequently, there are limited existing data upon which to base projections. P. 2-4

In the resulting projections, the production of natural gas in 2035 ranges from 22.4 to 30.1 trillion cubic feet, and the projected price of natural gas ranges from $9.26 to $5.35 per million British thermal units (Btus). P 2-4

Specific economic forecasts have not been developed for this report. Instead a range of potential economic impacts have been identified and analyzed. P. 2-5

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Economic and Social ImpactsAnalysis of the high development scenario is not included in this socioeconomic section of theSGEIS in order to be conservative in assessing the positive potential economic benefits of high volume hydrau-lic fracturing in New York State. The high development scenario was used as theconservative assumption of activity for all other sections of this SGEIS. Revised Draft SGEIS 2011, Page 6-208

COMMENT 5: In view of the acknowledged importance of the pace and scale of drilling for almost all kinds of impacts evaluated in the Draft, it is good that the DEC includes this discussion of how the scenarios in the Economic analysis are consistent or inconsistent with the assumptions made in other parts of the Revised Draft SGEIS. However, it would be preferable to specify in which other sections of the Draft SGEIS the high development scenario is actually relevant and employed. See also COMMENT 6, following.

COMMENT 6: The number of wells drilled and their gas production yield are appropriately identified as among the most critical, and difficult to predict, parameters affecting the impact analysis. The decision to consider a variety of well drilling scenarios is an important step in the right direction.

However, what were the criteria used to evaluate the plausibility and credibility of the “range of potential impacts [that] have been identified and analyzed”, as noted on P. 2-5? Some discussion of this should be added. One plausibility check might be related, for example, to the implicit number of rigs that would have to devoted to drilling in the NYS Marcellus to drill the assumed number of wells per year. Consider for example the following, excerpted from Table 4-1 on Major Development Scenarios (P 4-2) and Tablel 4-2 (P 4-6)

Total Wells Constructed (Year 1 to Year 30) LOW AVERAGE HIGHHorizontal 9,461 37,842 56,508Vertical 1,071 4,284 6,273Total 10,532 42,126 62,781

Maximum Number of New Wells Developed per Year (Year 10 to Year 30) (calculated for NYS from regional data provided in Table 4-2) LOW AVERAGE HIGHHorizontal 371 1,484 2,216Vertical 42 168 246Total 413 1,652 2,462

If it is assumed that each rig will drill twelve wells per year (one per month), this suggests that for 20 years the following number of rigs would need to be devoted to New York State.

POSSIBLE NUMBER OF RIGS DEDICATED TO NYS (author estimate) LOW AVERAGE HIGHTotal 34 138 205

To put this in context, the benchmark Baker Hughes rig count (see http://investor.shareholder.com/bhi/rig_counts/rc_index.cfm) indicates that the number of active rigs in the state of Pennsylvania grew from the low 20’s in early 2009 to a high of 116 in several weeks in mid to late 2011; this out of a total of roughly 2000 rigs active in the United States. Given this context (including the observed growth in the number of rigs moved to NYS over time), the Draft SGEIS should address the plausibility that the number of rigs estimated above for each of the scenarios would be dedicated to NYS alone for such a long time period, especially

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General Thoughts and CommentsEconomic and Social Impactsgiven the evidence that NY geology is less promising for gas production than is Pennsylvania. This evidence would support the decision to remove the High Development scenario from further consideration in the economic analysis, and at least raises the question about the “Average”.

Another simple calculation at least suggests that the assumptions need better justification; they appear to span an unreasonably high range of production estimates, and not just for the economic analysis. Insofar as the high range is assumed in order to define the outward bound of impacts requiring mitigation under SEQRA, such an approach can perhaps justifiable. However, insofar as the economic analysis is also pre-sented in the more unusual context for an EIS of presenting positive impacts or benefits, it is important not to overstate the case.

Specifically, the Figure 4-2 (P 4-3) shows the total number of wells drilled cumulatively over 30 years to range from 10,532 up to 62,781. The low development scenario involves 9,461 horizontal wells and 1,071 vertical wells. The high development scenario involves 56,508 horizontal and 6,273 vertical wells (From Revised Draft SGEIS 2011, Page 6-208)

The Revised Draft SGEIS reports further that IOGA-NY suggested that average Estimated Ultimate Recovery (EUR) associated with the low development scenario might be approximately 2.28 Bcf per horizontal well and that the average EUR for the high development scenario might be approximately 9.86 Bcf per horizon-tal well. (Revised Draft SGEIS Page 5-139) On P 4.12, it is stated that “the lower of the production estimates for horizontal wells [2.28 Bcf] was utilized throughout this report.” Presumably, these assumptions are behind the data in Tables 4-3 through 4-5 (P 4-13 through 4-17), which show the annual production sce-narios across each of the three regions. When this data is summed across all years and regions, the results yield the following estimate of total (horizontal and vertical production): 29.1 Tcf for the low development scenario, 116.1 Tcf for the average development scenario, and 173.2 Tcf for the high development scenario.

In contrast, on page 4-23 of the Revised Draft SGEIS, it is reported that, “In 2011, the USGS estimated a mean of 84.2 Tcf of technically recoverable undiscovered natural gas reserves in the Marcellus Shale in the Appalachian Basin.” Engelder’s well known higher 50% probability estimates are also reported: “Engelder had previously estimated a 50% probability that 489 Tcf of gas would be produced basin-wide from the Marcellus after a 50-year decline, and assigned 71.9 Tcf of that total to 17 counties in New York. Engelder’s basin-wide estimate appears to include both proven and undiscovered reserves.” If Engelder is correct that maybe 15% (72/489) of the total gas is likely to be recovered in NY State, then one might infer in relation to the USGS estimate that maybe 12-13 Tcf of their 84.2 Tcf estimate would be extractable from NYS.

The paragraph Page 4-23 of the Revised Draft SGEIS 2011, concludes, “There is insufficient information available to determine the validity of comparing these [the Engelder and USGS] projections, but it is com-mon for projections of these types to vary, as a function of the prevailing technologies and knowledge base associated with a given resource.” While this sentence highlights the uncertainty, the reader is also left with an implicit impression that these two estimates at least roughly encompass the range of plausible maxima for recoverable gas from the entire Marcellus formation. It is true that both the USGS and Engelder esti-mates are single points in a probability range, but the selection/presentation of these points for the SGEIS is not evaluated or explained.

Given this, how can the SGEIS scenarios be reconciled with either the reported USGS estimate of 84 Tcf or the Engelder estimate of 489 Tcf for the entire Marcellus region, much less the 12-13 Tcf implied USGS estimate or 71.9 Tcf Engelder estimate for New York alone? The 116 Tcf average scenario as well as the 173 Tcf high scenario for NY gas production greatly exceed even the cited Engelder estimate of recoverable

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General Thoughts and CommentsEconomic and Social Impactsgas for NYS. The 29 Tcf low scenario does not exceed the Engelder estimate for NYS, but does appear to significantly exceed the implied USGS estimate for New York, especially considering, as noted on P-5-139 of the Revised Draft SGEIS 2011, that, “The Marcellus fairway in New York is expected to have less formation thickness, and because there has not been horizontal Marcellus drilling to date in New York the reservoir characteristics and production performance are unknown. IOGA-NY expects lower average production rates in New York than in Pennsylvania.”

If the range of estimates is indeed misleadingly skewed to the high end, the implications for the Revised Draft SGEIS are likely large. If any overestimation is primarily due to the projected EUR per well, the profit-ability of wells would be called into question. Both the number of wells drilled and the economic benefits associated with well drilling expenditures would then be exaggerated. Insofar as any overestimation is due to assumptions about the number of wells anticipated in the scenarios, whether due to productivity/profit-ability or a variety of other possible feasibility considerations, the economic benefits estimated would again be overestimated.

Of course, it is important to consider that projections of a smaller number of wells would be associated with decreases in many of the negative impacts associated with gas development as well – lower contamination risks, less pressure on housing prices, and so forth. See COMMENT 5 in this context.

The impacts associated with both the construction and the operation of the natural gas wells are analyzed in this report. Actual well construction and drilling activities are assumed to occur for 30 years. It is assumed that once a well begins production the well would remain operational for another 30 years. P2-5

COMMENT 7: How reasonable is this assumption, which if false would inflate economic benefit? What is the sensitivity of the results presented to this assumption? Berman and Pittinger, for example, are well known contrarians who have challenged for technical and economic reasons the notion that hydrofracked wells can simply be assumed to be economically viable producers over a 30 year time frame. Their analysis is based on well performance in three of the major existing shale plays in the United States. (See http://www.theoildrum.com/node/8212 ) Other kinds of challenges to this assumption can be found in less criti-cal sources as well. King, for example (Jeffrey King. 2011. “Selected re-emerging and emerging trends in oil and gas law as a result of production from shale formations”, 18 Texas Wesleyan Law Review 1, Fall) details a variety of legal situations in Texas, often associated with low natural gas prices, that can lead even to lease termination long before 30 years.

Table 3-8 shows the impact of a $1 million increase in the final demand in the oil and gas extraction industry on the value of the output of other industries in New York State. The data used to construct the table were drawn from the estimates contained in the BEA’s Regional Input-Output Modeling System II (RIMS II). P. 3-6 Citation is to U.S. Bureau of Economic Analysis (USBEA). 2011a. Regional Input-Output Modeling System (RIMS II), Total Multipliers for Output, Earnings, Employment, and Value Added by State: Oil and Gas Extraction (Type 1).

COMMENT 8: The RIMS II system at its most disaggregated includes sectors 211000 (oil and gas extrac-tion) and 213111 (drilling oil and gas wells). The analysis at the level of aggregation that was used in the Draft SGEIS analysis uses the highest level of industry aggregation available, with the overall 21 sec-tor economy including an aggregated “mining” sector (see https://www.bea.gov/regional/rims/rimsii/download/406IndustryListA.pdf and https://www.bea.gov/regional/rims/rimsii/download/62IndustryListB.pdf and https://www.bea.gov/regional/rims/rimsii/download/21IndustryListC.pdf) Moreover, the most recent data available for the model is the 2002 BEA Benchmark IO Accounts (see https://www.bea.gov/faq/index.cfm?faq_id=15&searchQuery=&start=0&cat_id=0).

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Aside from the question of aggregation, the study might include some justification on why RIMS II was used rather than the more adaptable and commonly used IMPLAN model or the more theoretically sophisti-cated, and much more costly, REMI model.

More importantly, the extent to which the data embodied in the RIMS II model can accurately reflect the cost structures associated with the technology for the hydraulic fracturing of shale gas reservoirs in the Draft SGEIS should be addressed. Of concern are both the extent to which the level of industry aggregation in the model might misrepresent the true relationships, and the extent to which 2002 data on which the model is based appropriately reflects the state of technology in the oil and gas industry today. The concern is that Marcellus related spending patterns would not be accurately represented in the spending patterns of the oil and gas industry data from nearly a decade earlier. This issue was addressed most directly in the context of economic impact analysis in a series of studies conducted by Tim Considine (see eg. http://mar-celluscoalition.org/wp-content/uploads/2010/05/PA-Marcellus-Updated-Economic-Impacts-5.24.10.3.pdf). If industry data on costs is for some reason unavailable to DEC analysts, a detailed analysis of the value chain of a Marcellus shale well (see http://www.business.pitt.edu/faculty/papers/PittMarcellusShaleEco-nomics2011.pdf) would also provide information that could be evaluated to judge whether or not the RIMS parameters were roughly appropriate.

The New York State Department of Taxation and Finance (NYSDTF) provides a uniform, statewide method of valuing natural-gas-producing properties for real property tax purposes. Valuations of natural-gas-producing properties are based on “unit of production” value—a dollar amount per 1,000 cubic feet (MCF) of gas pro-duced. Therefore, the assessed value of an operating natural gas well is based on its production multiplied by the unit of production value.Each year the NYSDTF updates the unit of production values for each natural gas producing region in the state. To facilitate the valuation process, the state has been divided into four natural gas producing regions. In order to determine the assessed value of a natural gas producing property, the unit of production is multiplied by the amount of gas produced, and the annual New York State equalization rate is applied to the product. The resulting assessed value of this property is then taxed as a rate equal to any other real property taxed in a given locality. P 3-59

COMMENT 9 : This general discussion of the valuation process does not explain adequately how Marcellus production will be translated into the unit of production value. The source of data and formula should be explained and evaluated. The process for applying it in the Marcellus region should be explained, or the discussion on P 4-116 ff referenced. In particular, there is a concern that wells that are coming into produc-tion during a period of low prices may result in a very low unit of production value, resulting in minimal tax revenues for the government. The conditions under which a very low unit of production value might occur should be discussed, as well as the likelihood of such an occurrence and implications for the fiscal well be-ing of local governments. It is not possible to understand any of this without better information about how the general method described in the state’s relevant documentation(like http://www.tax.ny.gov/pdf/publi-cations/orpts/tentunitprodvalues.pdf on page 5, for example) will actually be applied in practice.

These development scenarios are designed to provide order-of-magnitude estimates for the following socio-economic analysis and are in no way meant to forecast actual well development levels in the Marcellus Shale or Utica Shale reserves in New York State. The high development scenario should be viewed as the upper bound-ary of possible development, while the low development scenario should be viewed as the likely lower bound-ary of possible development. These scenarios should be viewed as a “best-estimate” of the range of possible amounts of development that could occur in New York State.In addition, it is unlikely that new well construc-

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General Thoughts and CommentsEconomic and Social Impactstion would occur under a steady, constant rate. Economic factors such as the price of natural gas, input costs, the price of other energy sources, changes in technology, and the general economic conditions of the state and nation would all affect the yearly rate of well construction and the overall level of development of the gas reserves. The actual track of well construction would likely be much more cyclical in nature than as described in the following sections. P 4-4

COMMENT 10: The cyclicality, or variability, in the rate of well construction is appropriately noted in the SGEIS text. However, its implications are not adequately discussed or considered. Each of the scenarios assume a smooth rate of development; while this is more analytically tractable given the impossibility of predicting year to year variability, it is not necessary to predict this pattern of variation exactly in order to provide important insights. The ability of communities to minimize negative impacts and capitalize on positive impacts depends significantly on the variance in the pattern of well development that will occur in fact. No one would evaluate or plan for flooding or drought by looking only at average rainfall levels – be-cause the damage comes precisely at the extremes. The same is also true for many socioeconomic impacts. The impact on a community that has to provide dramatic increases in workforce housing for a workforce that shrinks and expands significantly every few years is radically different than the impact from one that expands and declines slowly over time and stays at a plateau for decades. The same would be true for any educational and social service responsibilities associated with a volatile and transient workforce.

The same is true for many other factors, not the least of which are the fiscal variables analyzed in this re-port. One of the peculiarities of the NY taxation system is that the Unit of Production calculations are used to translate annual gas production values into increases in the local annual assessment rolls. One of the characteristics that recommends the property tax as a source of local revenue is precisely that it is normally less volatile as a revenue source than the other major local revenue source, the sales tax. This feature of the property tax would be radically reversed with the variation that is likely to be associated with short term swings in well drilling and production. Many local governments are currently unprepared to manage this kind of fiscal volatility. In most situations, a municipality would advisedly lower its tax rate when its tax base goes up, all else equal. However, this advice is premised on the likelihood that the addition endures for more than a year. A municipality that has ephemeral increases in the tax base would presumably do bet-ter to raise its tax rate while the base is in place, a counterintuitive notion. Moreover, there are a variety of legal limitations on the ability of various local governments to carry over or smooth revenue streams over time. See for example, http://www.osc.state.ny.us/localgov/pubs/lgmg/reservefunds.pdf , which notes that under certain conditions regarding the Contingency and Tax Stabilization Reserve Fund (GML Section 6-e), “any excess must be used to reduce the amount of real property taxes needed to finance the eligible portion of the annual budget for the next fiscal year.” The same Comptroller’s document establishes further that, “Towns, villages, and counties are permitted by law to retain a ‘reasonable amount’ of any remaining estimated unappropriated, unreserved fund balance for each fund, consistent with prudent budgeting practices, necessary to ensure the orderly operation of their government. School districts, however, are limited to retaining 4 percent of the current school budget in unreserved, unappropriated fund balance.” School districts tend to be the largest beneficiary and the most dependent of local governments of prop-erty tax, yet this fund balance restriction makes it more difficult for them to deal with volatility on the scale that might be associated with gas drilling revenues and costs. The Draft SGEIS fails to explore any of these important issues.

These three development scenarios were provided by NYSDEC based on information the Department had requested of the Independent Oil & Gas Association of New York (IOGA-NY). IOGA-NY started with an estimated average rate of development, based on the following assumptions:

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General Thoughts and CommentsEconomic and Social Impacts• Approximately 67% of the area covered by the Marcellus and Utica shales is developable; • Approximately 90% of wells would be horizontal wells with an average of 160 acres per well; • Approximately 10% of wells would be vertical wells with an average of 40acres per well.

For a high rate of development, IOGA assumed that the average rate of development would be exceeded by a factor of 1.5. NYSDEC assumed a low rate of development, considering the potential effect on natural gas development of a decline in the price of natural gas and/or additional time needed for NYSDEC to review and issue permits. For the low rate of development, NYSDEC assumed a rate of 25% of IOGA’s estimated average rate of development.

These development scenarios are designed to provide order-of-magnitude estimates for the following socio-economic analysis and are in no way meant to forecast actual well development levels in the Marcellus Shale or Utica Shale reserves in New York State. The high development scenario should be viewed as the upper bound-ary of possible development, while the low development scenario should be viewed as the likely lower bound-ary of possible development. These scenarios should be viewed as a “best-estimate” of the range of possible amounts of development that could occur in New York State. P 4-4

COMMENT 11: See Comment 6 for concerns that the IOGA-NY assumptions might lead to an overestimate of recoverable gas in these scenarios, ie. at least some evidence suggests that the “best estimate of the range of possible amounts of development” is not the range assumed. In addition to Comment 6, I would also have to ask for the criteria behind the estimate that “approximately 67% of the area covered by the Marcellus and Utica shales is developable.” This seems like an extraordinarily optimistic proposition that should at the very least be justified in some way.

Region A: 50% of all new well construction would occur in Region A(Broome, Chemung, and Tioga counties);• Region B: 23% of all new well construction would occur in Region B (Delaware,Otsego, and Sullivan counties);• Region C: 5% of all new well construction would occur in Region C (Cattaraugusand Chautauqua counties); and• Remainder of the State: 22% of new well construction would occur in otherlocations throughout the area covered by the Marcellus Shale and other lowpermeabilityformations in New York State.

These proportions were derived from an evaluation of the drilling potential for natural gas for the two most prominent shale formations in New York State, the Utica Shale and the Marcellus Formation (Marcellus Shale). The assumptions in this evaluation focused on the location of the “fairway” for each of these formations, as well as other factors discussed below. P. 4-5COMMENT 12: Where does the apparent precision come from – was there some kind of formula used to arrive at a 22/23% split? It is hard to evaluate the assumptions without understanding the formula, if one exists. If the apparent precision is not real, this should be stated.

Indirect employment impacts were estimated using multipliers from the USBEA’s Regional Input-Output Mod-eling System (RIMS II). Type I, direct effect employment multipliers for the oil and gas extraction industry were used. Separate multipliers were used for each region and the state as a whole. Each of these multipliers repre-sents the number of new jobs (both direct and indirect) that would be generated by a new job in the oil and gas

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General Thoughts and CommentsEconomic and Social Impactsextraction industry.

Table 4-6 Maximum Direct and Indirect Employment Impacts on New York State under Each Development Scenario Total Employment (in number of FTE jobs)Scenario Low Average HighDirect Employment Impacts Construction Employment1 4,408 17,634 26,316 Production Employment2 1,790 7,161 10,673Indirect Employment2,3 7,293 29,174 43,521Total Employment Impacts 13,491 53,969 80,510

Total Employment as a Percent of New York State 2010 Labor Force0.1% 0.6% 0.8%

Source: USBEA 2011a; NYSDOL 2010a

These figures represent the maximum annual construction employment under each scenario and correspondto construction employment in Years 10 through 30.2 These figures represent the maximum annual production employment and indirect employment undereach scenario. These figures correspond to production employment in Year 30.3 Type I direct employment multipliers for the oil and gas extraction industry from the USBEA, RegionalInput-Output Modeling System (RIMS II) were used to estimate the indirect employment impacts.

COMMENT 13: Here is text taken directly from RIMS II documentation: “Jobs impacts estimated using the final-demand and direct-effect employment multipliers include both part-time and full-time employees. The RIMS II multipliers do not provide estimates of jobs in terms of full-time equivalences.” See https://www.bea.gov/regional/rims/rimsii/help.aspx#WhatAreType The impact results in this document are re-porting jobs on an FTE basis. If so, how did the analysts translate the RIMS results to this FTE basis? Should the tables clarify that that the results are not, in fact, FTE data.

COMMENT 14: The text fails to explain the decision to not account for induced effects (Type II multipliers), as is standard in most analyses of this type. Unlike other decisions and assumptions which tend to over-estimate the economic impacts, this decision significantly underestimates total likely impacts by failing to account for the spending effects of increased incomes.

Owners of the subsurface mineral rights where wells are drilled would also experience a significant increase in income and wealth. Royalty payments to property owners typically amount to 12.5% or more, of the annual value of production of the well (NYSDEC 2007b). These royalty payments, particularly in the initial stages of well production when natural gas production is at its peak, can result in significant increases in income. Signing bonuses/bonus bids also can provide significant additional income to property owners. P 4-29

COMMENT 15: Even more striking in its absence, the text fails to explain the decision to not say any more than this about the effects of any lease or royalty payments to landowners. This contribution to the local economy is a very important aspect of the potential economic benefit to the local and regional economies; other studies of shale drilling have suggested that a very substantial fraction of the gas company spending that might benefit local economies is injected into the region as bonus and royalty payments. Again, the decision not to further evaluate or quantify this spending as has been done in several other studies signifi-

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General Thoughts and CommentsEconomic and Social Impactscantly and inexplicably underestimates total likely impacts in and of itself, an oversight then compounded by the failure to account for standard income effects with Type II multipliers. Moreover, the non- treatment of landowner income fails to draw any attention whatsoever to the types of economic development strate-gies that would be needed to be put into place to increase the likelihood that landowner beneficiaries of drilling would spend their increased wealth in ways that would benefit the local economy.

As anticipated, the direct effect employment multiplier for the State of New York (2.1766) was substantially larger than the multipliers for the individual regions, which had direct-effect employment multipliers of 1.4977 in Region A, 1.3272 in Region B, and 1.4357 in Region C (USBEA 2011a, 2011b, 2011c, 2011d). This disparity underscores the fact that currently there is not a well-developed supply chain for oil and gas projects in the rep-resentative regions. Therefore, if drilling were to start today, many of the industry’s suppliers would be located outside of the representative regions and many of the positive indirect economic impacts would accrue to other areas of the state or country. As the natural gas industry grows, more of the suppliers would locate to the representative regions and less of the indirect and induced economic impacts would leave the regions. P 4-19

COMMENT 16: Yes, but in light of Comment 15, why the sudden reference to induced effects here? p 4-19

In some regions of the state where drilling would most likely occur, the increases in employment may be so large that these regions may experience some short term labor shortages. The increase in direct and indirect employment related to the natural gas extraction industry could drive wage rates up in such areas in the short term and make it more difficult for existing industries to recruit and retain qualified workers. In addition, the increase in wage rates could have a short-term negative impact on existing industries, as it would increase their labor costs.

These potential short-term labor impacts would less severe because the use of specialized labor from outside the region would likely be required for certain jobs,and the existence of employment opportunities would cause the migration of workers into the region. In addition, the positive employment impacts from well con-struction and development—and the related economic impacts derived from that employment—would generate more in-migration to the region. In time, the additional new residents to the areas would expand the regional labor force and reduce the pressure on labor costs. P. 4-46

COMMENT 17: This brief mention of possible negative impacts of drilling assumes that crowding out effects will only be short term, that the market will work its magic in fairly short order. This is a simplistic assump-tion that fails to even mention the empirical evidence and now mainstream concern about the so-called “resource curse” effect that can accompany high value mineral based extractive activity such as oil and gas drilling. Though this effect is most commonly analyzed in developing countries, recent econometric studies of the United States suggest that rural domestic economies are not necessarily immune to “curse” effects that persist beyond the “short term” (see a summary of these studies in http://www.cce.cornell.edu/EnergyClimateChange/NaturalGasDev/Documents/PDFs/KayFormattedMarcellus%20WorkingPaperRE-vised4-4-2011.pdf)

Each of these secondary industries would experience increases in their output, employment, income, and value added. As a result, industries that supply these secondary industries would also experience a positive economic impact, and they would expand as demand for their goods and services increases. Secondary, and eventu-ally even tertiary, suppliers would start to tailor their products to meet the needs of the natural gas extraction industry.

Conversely, some industries in the regional economies may contract as a result of the proposed natural gas de-

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General Thoughts and CommentsEconomic and Social Impactsvelopment. Negative externalities associated with the natural gas drilling and production could have a negative impact on some industries such as tourism and agriculture. Negative changes to the amenities and aesthetics in an area could have some affect the number of tourist that visit a region, thereby impacting the tourism industry. However, as shown by the tourism statistics provided for Region C, Cattaraugus and Chautauqua counties still have healthy tourism sectors despite having more than 3,900 active natural gas wells inthe region. P 4-58

COMMENT 18: The co-existence of a large number of active wells in Region C with tourism may or may not be relevant here. In order to make a compelling argument for relevance, at a minimum some evidence about the comparability of the character, timing, pace and scale of drilling, as well as the regional similar-ity of the tourism industry and disturbed landscapes (farmland vs. forest land, for example) would have to be adduced. Short of a serious analysis along these lines, the relationship between gas wells and a healthy tourism sector in Region C is no more securely established than is the relationship between the presence of gas wells in those counties and their relatively poor socioeconomic performance compared to similar neighboring counties (see http://www.greenchoices.cornell.edu/downloads/development/marcellus/Mar-cellus_SC_NR.pdf) .

Similarly, agricultural production in the heavily developed regions may experience some decline as produc-tive agricultural land is taken out of use and is developed by the natural gas industry. Property values also may experience some increase as a result of the natural gas development and the resulting increase in economic ac-tivity. The potential increase in land prices, which is one of the main factors of production for agriculture, could impact the industry’s input costs in areas experiencing the most intense development. P 4-59.

COMMENT 19: The discussion fails to mention any potential for positive impacts on agriculture due to their greater access to working capital from lease and royalty payments.

COMMENT 20: This whole section raises some serious issues but offers no analysis, and tends to dismiss concerns based on little or no evidence.

To assess the maximum potential population impacts, the discussion below is based on a hypothetical situation in which (1) all workers hired for the construction and production phases of the natural gas wells migrate into the regions from other areas or (2) workers migrate into the regions from other areas to fill positions that local construction and production workers vacate to work on the natural gas wells. Although this hypothetical situ-ation is used to examine the maximum potential population impacts, it is more likely that the actual outcome would beless than described. Not all workers employed during the construction and production phases would necessar-ily live in New York State or one of the representative regions. Particularly in the case of well development and production in the Southern Tier, existing natural gas workers currently residing in Pennsylvania, for example, may simply choose to maintain their residency in Pennsylvania and commute to work in New York. In addition, actual population impacts may also be less than what is described in the following section because currently unemployed or underemployed local workers could be hired to fill some of the construction and production positions, thereby, reducing the total in-migration to the region. P 4-59

COMMENT 21: It seems appropriate that maximum impacts are considered, given the responsibility under SEQRA to consider potentially significant negative impacts and their mitigations. This approach would have been appropriate in evaluating fluctuations in drilling rates for the Input Output analysis, and throughout.

The following additional assumptions were used to project population impacts:

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General Thoughts and CommentsEconomic and Social Impacts• A majority of construction jobs and related population migration to the regions would be temporary and transient in nature in the beginning of the well development phase. As well construction continues, these jobs would gradually be filled by permanent residents.• Transient construction workers are assumed to temporarily relocate to the region for a short duration and are assumed to not be accompanied by their households. Permanent construction workers are assumed to relocate to the region for the duration of the well development phase and would be accompanied by their entire house-holds.• Production jobs and related population migration to the regions would be permanent and entire households would relocate to the regions.• Natural gas development and production would not “crowd out” employment in other, unrelated industrial sectors, and employment in these sectors would remain unchanged. P 4-60

COMMENT 22: The absence of “crowding out” effects seems appropriate here in the context of attempting to establish maximum population impacts, even though it would be inappropriate in other contexts.

It is assumed that the households of permanent construction workers and production workers would, on aver-age, be the same size as the current average New York State household (i.e., 2.64 persons, including the worker). Therefore, in projecting population impacts, it is anticipated that transient construction workers would be tem-porary residents unaccompanied by family members, and permanent construction workers and all production workers would be permanent residents accompanied by an average of 1.64 family members. P 4-65

COMMENT 23 : This is debatable – the average NYS household is likely to be much older and of a different socioeconomic status than the Marcellus workforce. This difference would probably be less significant for indirect jobs than direct ones.

Table 4-49 identifies the total stock of rental housing units, the existing supply of vacant housing units for rent, and the rental vacancy rate in New York State as a whole. Assuming a worst-case scenario where each projected construction worker would require one rental-housing unit, New York State could easily supply rental housing to construction workers under all development scenarios with existing vacant units in Year 10. Therefore, the impact on the supply of rental housing resources from transient workers would be negligible at the statewide level. Impacts at the regional and local levels are discussed below. Table 4-50 identifies the existing supply of vacant housing units for sale or rent in New York State. Seasonal, recreational, and occasional use units and units rented or sold but not occupied were not included in these totals. Assuming a worst-case scenario at Year 30, it is anticipated that each projected permanent construction and production worker would require one per-manent housing unit. Given that assumption, New York State has more than enough houses for sale to provide permanent housing units to the new permanent workers. Therefore, the impact on the supply of permanent housing units would be negligible at the statewide level during the production phase. COMMENT 24 : The statewide analysis is pretty close to irrelevant, given the projected location of most wells and workers. The regional analysis is the only important one.

In areas of Pennsylvania where Marcellus shale drilling activity is occurring, it has been difficult at times to accommodate the influx of new workers (Kelsey 2011). There have been reports of large increases in rent in Bradford County, Pennsylvania, as a result of the influx of out-of-area workers (Lowenstein 2010). There have also been “frequent reports” of landlords not renewing leases with existing tenants in anticipation of leasing at higher rates to incoming workers, andreports of an increased demand for motel and hotel rooms, increased demand at RV camp sites, and increases in home sales (Kelsey 2011). Such localized increases in the demand for housing have raised concerns about the difficulties caused for existing local, low-income residents to afford housing (Kelsey 2011).

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The impacts on temporary housing described above for Bradford County, while acute in the short term, may decrease in the long term as more workers establish permanent residences in the area and as the market has time to respond to the shortage in temporary housing. As more hotel/motel rooms are constructed and more rental properties become available, the shortages of existing units would decline and subsequently rental prices would also decline. P 4-108

COMMENT 24: This is a rare reference to other work on economic impacts that have portrayed drilling in either a favorable or unfavorable light. Shouldn’t this analysis have addressed the pros and cons of existing impact work already completed by Tim Considine, Tim Kelsey and others, addressing its relevance or lack thereof to the current analysis?

Table 4-52 identifies the total rental inventory, the existing supply of vacant housingunits for rent, the rental vacancy rate, and the number of hotel/motel rooms in Regions A, B, and C. Assuming a worst-case scenario, where each incoming transient worker would require one rental housing unit or hotel/motel room during peak construction (Year 10), Regions B and C both have more vacant rental units than incoming workers under all three scenarios. However, Region A has only enough rental units to cope with the number of incoming workers under the low and average development scenarios. In Regions B and C under all three scenarios and in Regions A under the low and average development scenario, the existing stock of rental housing is sufficient to meet the needs of incoming workers; thus, no additional rental housing would need to be constructed. However, rent increases caused by the increased demand for rental housing could make such housing unaffordable for existing low-income tenants, and increased demand for hotel/ motel rooms would be likely to cause price increases in these sectors. P 4-109

Cyclical Nature of the Natural Gas Industry: The demand for housing, both temporary and permanent, would be expected to change over time. The demand for housing would be the greatest in the period during which the wells in an areas are being developed, and demand would decline thereafter. This would create the possibil-ity of an excess supply of such housing after the well development period (Kelsey 2011). If well development in a region occurs in some areas earlier than in others, then housing shortages and surpluses may occur at the same time in different areas within the same region. The natural gas market can be volatile, with large swings in well development activity. Downswings may cause periods of temporary housing surplus, while upswings may exacerbate housing shortages within the regions. P 4-111

COMMENT 25: The implications, plus and minus, of price increases for hotel/motel rooms should be dis-cussed. Possible mitigations for the negative effects of surplus and shortage should be considered.

PROPERTY VALUES

At this level of analysis, it is impossible to predict the actual impacts of developing the Marcellus and Utica Shale natural gas reserves on individual property values. However, some predictions can be made with regard to the general impact of mineral rights on property values and the impact of well development on adjacent properties.

Significant increases in property value are expected where the subsurface mineral rights and land are held jointly with land ownership and the exploitation of the subsurface resources is not limited in some way. Be-cause the owners of subsurface mineral rights typically receive royalty payments equal to or greater than 12.5% of the total value of production, the development of natural gas reserves would be expected to substantially increase the value of their property. Properties where the mineral rights are not held jointly with land owner-

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General Thoughts and CommentsEconomic and Social Impactsship, or where there is some restriction on drilling, would not experience this increase in value.

Property values could also be affected by the impacts associated with developing natural gas resources. Gas well development could impact local environmental resources and cause noise and vibration impacts, and trucks servicing the well development could also impact the surrounding areas. Once wells are in place, the local impacts would be less and there would be much less traffic moving to and from the wells. Pipelines would be constructed to carry the natural gas from the wells. Construction of the pipelines would have an impact on the landscape and would result in the maintenance of cleared rights-of-way once the pipeline is in place. Gas compressor stations would also be constructed to maintain the pressure of the gas in the pipelines, and there would be noise and air emissions associated with their operation.

It is possible that these various impacts, particularly those associated with the construction phase, could reduce the value of properties close to the wells relative to similar properties not located close to wells. P 4-112

COMMENT 26: There is no discussion of mortgage lending effects of leasing for residential property owners. The research of May et al. (see http://www.cce.cornell.edu/EnergyClimateChange/NaturalGasDev/Docu-ments/PDFs/Gas%20and%20Oil%20Leases%20Residential%20Lending%2010-11-11.pdf) raises important questions about the possible implications of leasing for compliance with standard Fannie Mae and Freddie Mac style mortgage conditions. This issue should be addressed. There is also no direct discussion of the potential property value impacts of water contamination, especially linked to the likely incidence of meth-ane migration due to faulty casing, which appears to be the most common contamination source. Perhaps an interest more academic in nature, but there is also no discussion of the linkage between property assess-ment and taxation issues and the way property taxes are capitalized in property prices (see for example the seminal paper by Wallace Oates at http://www.jstor.org/stable/1837209, and the enormous literature on this topic which has followed.

In order to assess the potential impact these negative externalities would have on property values in the af-fected regions, a review of economic literature was undertaken. P 4-112

COMMENT 27: The review of economic literature covers all the most relevant studies that I am aware of. Comments on individual studies follow.

BBC Research and Consulting (2001) examined the impact of coal bed methane Wells…. The authors found that having a well on a property was associated with a 22% reduction in the value of the property; that having a well within 550 feet of a property increased its value; and that having a well located between 551 feet and 2,600 feet from a property had a negative impact on a property’s value. The authors attributed the positive impact on property values of having a well located within 550 feet of a property to the prevention of further gas well development in that area due to a spacing order and setback conditions that prevented well drilling close to existing wells (BBC Research and Consulting 2001). P 4-113

COMMENT 28: How relevant are these results to the Marcellus situation. To evaluate this, it is important to address a number of questions. Were mineral rights separated or not? How urban/suburban/rural was the coal be methane context? Are the distance categories measured based on continuous or categorical variable analysis? What attributes of the wells cause the negative (positive) effects (visual, noise, potential for pollution, etc.)? Are these effects related to the construction phase or ongoing operations; and what is the timing of analysis/data in relation to the age of the well? One of the most interesting results is that the effect switched sign with distance. To me this appears to be an interesting case because it evaluates the ef-fect of actual wells. However even without knowing the answers to the other question posed, I suspect the

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General Thoughts and CommentsEconomic and Social Impactsresults of coal bed methane analysis are of limited relevance for conclusions about hydrofracturing in New York state.

Boxall, Chan, and McMillan (2005) examined the impact of small- to medium size oil and gas production facili-ties on rural residential property values using data from central Alberta, Canada. In this study, the authors found a statistically significant negative relationship between property values and the presence of oil and gas facili-ties within approximately of 2.5 miles of rural residential properties. The presence of oil and gas facilities within 2.5 miles of rural residential properties was estimated to reduce property values between 4% and 8%, with the potential to double the impact, depending on the level and composition of the nearby industry activities (Box-all et al. 2005) . P 4-113

COMMENT 29: The actual paper attributes the negative effects to proximity to “sour gas wells and flaring oil batteries within 4 km of the property.” I haven’t heard that the particularly noxious H2S that makes gas sour is a significant component of Marcellus Shale gas. This study is probably also of limited relevance.

Integra Realty Resources (2011) conducted a study of the impact of natural gas wells on property values in and around Flower Mound, a community approximately 28 miles northwest of downtown Dallas, Texas, where gas drilling is a recent development. The authors used four methods to estimate the impact of wells on property values: (1) examining the relationship between distance to a well site and property values; (2) comparing the sales prices of properties close to a well and comparable properties not close to a well; (3) a statistical analysis of the relationship between property attributes, including proximity to a well and values; and (4) surveying market participants (principally realty agents). With regard to the relationship between the distance between properties and well sites, they found that within Flower Mound itself there was a negative impact on property values when houses are immediately adjacent to well sites; however, this negative impact diminishes quickly with increasing distance from the well. The impact was found to be between -2% and -7% of property values. The results of the comparable sales analysis indicated that, in most cases, there was little correlation between proximity to a well site and property values. However, within Flower Mound itself and for properties in excess of $250,000 in selling price, proximity to a well had a negative impact of between -3% and -14% on property values.

The statistical analysis found no statistically significant relationship between property values and proximity to a well site. Finally, market participants reported that proximity to a well site had an impact on the time required to sell a property; however, this impact was most pronounced during the actual process of well development and diminished thereafter (Integra Realty Resources 2011). P 4-113COMMENT 30: This study appears to be the most relevant of the cited studies in terms of the gas well im-pacts. It would be useful for a statistician to evaluate its statistical power (ability to discriminate effects), how time was treated in statistical analysis, and other aspects of the technical quality of the analysis.

The paper seems to conclude, logically, that close proximity to well has small but significant negative effect, probably especially for upscale properties and during the intense parts of the drilling cycle.

For mitigation purposes, I’d ask if there is enough information here to figure out what setback/screening etc. would make be recommended strictly from a property value mitigation perspective?

The actual study notes that “Any influence on property values on a linear basis was found to dissipate at around 1000 feet from the wellhead. Data from most well sites studied in this report outside Flower Mound suggests that there is little or no impact on residential property from proximity to wells… Several sales where view of the well site was obstructed by buffers such as trees or other structures indicate that value

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General Thoughts and CommentsEconomic and Social Impactsis not measurably impacted, even when the property is in close proximity. The range in property value decline found in price-distance relationships was observed to be about -1% to -9%. This methodology was less conclusive than the sales comparison method but still indicated the same general trends…. Statistical analysis resulted in no consistent and statistically significant diminution in value within the distances mea-sured. This method illustrates how much variance in the data impacts the results. If there were a significant and sizeable diminution in value as a result of well proximity, the statistical analysis method likely would have revealed it.” If the DEC is to take this study seriously, it should discuss any implications of the results for mitigations like setbacks, screening requirements, etc.

Fruits (2008) studied the impact of the South Mist Pipeline Extension on residential property values in Clacka-mas and Washington counties, Oregon. In his Fruits (2008) studied the impact of the South Mist Pipeline Ex-tension on residential property values in Clackamas and Washington counties, Oregon. In his analysis, Fruits performed three statistical tests using the hedonic housing price approach and found no statistically significant impact from natural gas pipeline development on residential property values (Fruits 2008) . P 4-114

COMMENT 31: The Fruits study also may well be relevant regarding pipeline impacts. There seems to be more on this topic than on well impacts in the literature. Perhaps this is because pipelines are more promi-nent on a large scale for long time periods on landscape than are wells (ie when they’re in the production phase, NOT during shorter term drilling/fracking phase), but this is just speculation. To determine rele-vance more thoroughly, DEC should evaluate the actual characteristics of the pipeline studied (it was a 24” 62 mile long intrastate pipeline installed in 2004), its context in Oregon landscape, and so forth to see what kinds of characteristics in NY might be similar.

Palmer (2008) also looked at the impact of the South Mist Pipeline Extension on residential property values in Clackamas and Washington counties, Oregon. Palmer, working on behalf of Palomar Gas Transmission LLC, conducted a market study using data from 2004 to 2008 that compared sales of properties along pipeline corri-dors with comparable sales of non-affected properties. Palmer found no measurable impact on property values resulting from the construction and operation of natural gas pipelines (Palmer 2008). P 4-114

COMMENT 32: How does this data/method differ from the Fruits study? Is it really an independent analysis, or merely another version of the same study?

In conclusion, the above literature review suggests that being in proximity to a well could reduce the value of a property, but that proximity to a gas pipeline might not reduce the value of a property. P 4-114

COMMENT 33: “Could” and “might not” are operative qualifiers. Unfortunately, the existing evidence on these matters is pretty thin.

The proposed natural gas development would have an overall regional effect of increasing property values due to the expected in-migration of construction and production workers and the increased economic activity that would occur in the area. Likewise, properties that still included unexploited sub-surface mineral rights would increase in value due to the potential of receiving royalty payments. However, not all properties in the region would increase in value, as residential properties located in close proximity to the new gas wells would likely see some downward pressure on price. P 4-114

COMMENT 34: I suspect these comments are probably true, but the first two are based on simplified first principles of economic theory rather than any of the actual analysis or evidence presented, and there is only weak empirical evidence presented regarding the last comment.

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This downward pressure [on property prices] would be particularly acute for residential properties that do not own the subsurface mineral rights. P 4-114

COMMENT 35: So if this is true, what are the implications for mitigation measures?

REVENUES & EXPENDITURES

Impacts on major revenue sources for the state and local governments are discussed, as are expected changes in state and local government expenditures that could occur as a result high-volume hydraulic fracturing opera-tions. Given the uncertainty associated with the actual level of future development of these reserves, the rate of extraction that would occur, and the actual geographic location where development would take place, it is impossible to definitively quantify the fiscal impacts of this action. However, some estimates have been made. These estimates should be viewed only as order-of-magnitude estimates and not as actual revenue or cost projections. P 4-114

COMMENT 36: This is a useful introduction.

The proposed high-volume hydraulic fracturing operations would have a significant positive impact on rev-enues collected by New York State. Revenues in the state would increase directly as a result of lease payments for natural gas development that would occur under state-owned land and indirectly from an increase in tax revenues generated by the natural gas development and the resulting increase in economic activity throughout the state. No surface access would be granted for high-volume hydraulic fracturing operations on state-owned lands. However, the subsurface natural gas deposits under state-owned lands could be accessed by surface op-erations located on privately owned lands. If the subsurface natural gas deposit under state-owned lands were extracted, New York State would receive lease payments and royalties for the mineral rights.

At this point in the planning processes it is impossible to accurately assess the exact location where these wells would be drilled and whether or not these wells would be located on private lands that could access under-ground reserves under state-owned lands. Therefore, it is impossible to estimate the total royalty and lease payments that would accrue to the state. However, these payments are not expected to be large relative to the total New York State budget. Currently, New York State receives approximately $746,000 in lease payments per year for all oil and natural gas developments on state-owned lands.

The state would indirectly receive a significant increase in its revenue streams from high-volume hydraulic fracturing operations. As described in Section 4.2 (Economy, Employment, and Income) the development of high-volume hydraulic fracturing operations would increase employment and income throughout the state. Depending on the development scenario, $621.9 million to $3.7 billion in employee earnings would be directly and indirectly generated per year at maximum build-out (Year 30).

As a result, New York State would experience a large increase in its personal income tax receipts. In 2008 the effective personal income tax rate for all taxpayers in New York State was 5.0%. If this tax rate were used for esti-mation purposes, at maximum build-out (Year 30) the state could receive between $31 million and $185 million a year in personal income tax receipts, depending on the level of development assumed. P 4-115

COMMENT 37: First, note COMMENT 6 above as to why the estimated amount of drilling and range of rev-enues may well be overstated. Second, why was the 2008 effective rate used instead of more recent rates?

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General Thoughts and CommentsEconomic and Social ImpactsThere should be more background presented regarding the application of the state income tax. See eg http://www.itepnet.org/whopays3.pdf from 2009 which shows income tax rate rising from -3.5% in the lowest income group to a high of 7% in the top 1% of income distribution (ie. As combined personal in-come tax and corporate income tax). Is the estimated income cited only for instate residents – or does this not matter if nonresident income is taxed at the same rate as for residents? - see http://www.tax.ny.gov/pdf/publications/income/pub88.pdf “If you were a nonresident of New York State and received income dur-ing the tax year from New York State sources, or if you moved into or out of New York State during the tax year (part-year resident), you must file Form IT-203, Nonresident and Part-Year Resident Income Tax Return. You are subject to New York State tax on income you received from New York sources while you were a nonresident and all income you received while you were a New York State resident. To compute the amount of tax due, use Form IT-203, Nonresident and Part-Year Resident Income Tax Return. You will compute a base tax as if you were a full-year resident, then determine the percentage of your income that is subject to New York State tax and the amount of tax apportioned to New York State.”

In addition to the personal income tax, the state would also experience some increase in its corporate tax re-ceipts. Corporate income in the state would increase both directly, as the natural gas developers profit from the extraction of the gas in the low-permeability shale, and indirectly due to the resulting increase in economic ac-tivity in the state. However, given the many benefits in the New York State tax code for energy companies, such as expensing, depletion, and depreciation deductions, the taxable income from the natural gas industry would be greatly reduced. In addition, New York State offers an investment tax credit (ITC) that could substantially re-duce most, if not, all of the net income generated by these energy development companies. Also, the sale of the natural gas generated by these companies may not take place in New York and, therefore, may not be subject to New York State corporate tax (NYSDTF 2011a). Other tax receipts would also increase. Revenues generated from sales and use taxes would also register an increase as industry purchased the materials needed to develop these natural gas reserves that are not exempt from state and local sales tax. However, many of the materials needed to construct these wells would be tax-exempt, including such things as piping, drill rigs, service rigs, vehicles, tools and supplies, pollution control equipment, and services to real property (NYSDTF 2011a). P 4-116

COMMENT 38: It seems like there are a lot of policy relevant tax breaks to consider here. The implications are left unaddressed.

High-volume hydraulic fracturing operations would also result in some significant negative fiscal impacts on the state. The increased truck traffic required to deliver equipment, supplies, and water and sand to the well sites would increase the rate of deterioration of the state’s road system. P 4-116

COMMENT 39: Yes, but the extent of damage depends significantly on the quality of roads, the time of year, (see eg. http://cce.cornell.edu/EnergyClimateChange/NaturalGasDev/Documents/PDFs/Preserving%20Mu-nicipal%20Roads%20Slides%20%282%29.pdf) and the extent to which state roads will be used. What are the implications of where the New York fairway is located in the Southern Tier in relation to what’s known about road quality there?

Additional capital outlays would be required to maintain the same level of service on these roads for their pro-jected useful life. Depending on the exact location of well pads, the state may also be required to upgrade roads and interchanges under its jurisdiction in order to handlethe additional truck traffic. The potential increase in accidents and potential additional hazardous materials spills resulting from the increased truck traffic also would require additional expenditures. Finally, approval of transportation plans/permits would place additional administrative costs on the New York State Department of Transportation.

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General Thoughts and CommentsEconomic and Social ImpactsAdditional environmental monitoring, oversight, and permitting costs would also accrue to the state. In order to protect human health and the environment, New York State would be required to spend substantial funds to re-view permit applications; to ensure that permit requirements were met, safe drilling techniques were used, and the best available management plans were followed; and to provide enforcement against violations. In addi-tion, the state would experience administrative costs associated with the review of well permit applications and leasing requirements and enforcement of regulations and permit restrictions. All of these factors could result in significant added costs for the New York State government.The New York State Department of Health would also incur additional costs due to the need to provide addi-tional technical support and oversight services to local governments that would monitor water quality in local drinking water wells . P 4-116

COMMENT 40: The state should be attentive to other issue, like DOS planning assistance to local govern-ments; emergency preparedness and code enforcement, training, etc. Simple enumeration of costs and benefits gives no guidance as to how whether there is a clear net benefit or deficit, or whether this kind of rough calculation simply cannot be made.

4.5.2 Representative RegionsDevelopment of the natural gas reserves would have significant positive and negative fiscals (sic) impact on local governments wherever drilling would take place. As described above, local government entities who take part in sales tax revenue sharing schemes would experience a substantial increase in sales tax receipts as a result of the additional economic activity that would occur within their jurisdictions. P 4-117

COMMENT 41: The report should enumerate existing sales tax sharing arrangements of governments in the region to enable a more local perspective on who will benefit and how. Which counties have which rates operative – how many are at the 8% maximum? Where in the region do cities exercise preemption regard-ing sales tax distributions? Which counties and cities share revenues with towns based on assessed value, which based on population? What difference would this make? Regarding this distribution and given concerns about municipal costs being incurred before property taxes are actually collected (given lags in getting the assessed value on the rolls, levying and collecting the tax), what would be the timing of sales tax revenue receipts compared to when the sales tax is levied?

Local government entities that receive proceeds from ad valorem property taxes would see significant increases to their tax rolls and property tax receipts…. In order to predict the change in property tax revenues that would result from the proposed high-volume hydraulic fracturing operations, annual production of the wells were forecasted. Many factors affect the annual production of a natural gas well. Typically, production initially starts out at a maximum level and then declines quickly until it reaches a relatively slower rate of decline. Pro-duction then continues at this lower level for approximately 30 years.

COMMENT 42: All seems more or less true – production from an individual well should therefore result in a large short term boost to the tax base that quickly drops off. If all wells are drilled in given jurisdiction within a couple of years, the size of the tax base rise and fall will be very large, especially in proportion to a rural governments existing tax base. As suggested in an earlier comment, the natural incentive will be for local governments to reduce rates during the year that the tax base is very high, as most of their expenses may well be covered in the short term even with lower rates, and the habit of most governments is to pro-vide tax relief to their constituents. However, if governments were thinking longer term, they would want to tax at the maximum rate before the well production disappeared in a few short years, and carry the tax revenue over into the future… Insofar as the gas market and production patterns remain volatile, this issue is exacerbated. The actual timing and geography of development of the wells is therefore a critical variable.

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General Thoughts and CommentsEconomic and Social ImpactsHorizontal high-volume hydraulic-fracturing wells produce more natural gas than vertical high-volume hydrau-lic-fracturing wells. This discrepancy has been accounted for in the analysis. For a more detailed description of projected production levels, see Section4.1.

The estimation of the real property tax payments for a typical horizontal well ineach production year was done in the following steps…. P. 4-116

COMMENT 42: See COMMENT 9.

The annual property tax payment was calculated by multiplying the assessed value by the overall full-value tax rate for the county divided by one thousand. The overall full-value tax rate for each county was calculated by ORPTS and takes into account all local taxes on real property from all local taxing entities including county, town, village, school district, and other special districts, and the 2010 Medina formation unit of production value. As described previously, once Marcellus Shale or Utica Shale formations become developed in New York State, specific unit of production values would be developed for that specific formation and the specific drilling techniques used in that formation. Depending on the results of that analysis, the unit of production value could vary substantially from the Medina values utilized in this report (NYSDTF 2011c, 2011d).

Tables 4-54, 4-55, and 4-56 show the estimated annual real property tax payments for a typical high-volume hydraulic-fracturing horizontal well in Broome County in Region A, in Delaware County in Region B, and in Cat-taraugus County in Region C for each year of its productive life.The 2010 overall full-value millage rates for Cattaraugus and Chautauqua counties were 35.50 and 32.10, respectively. These rates have already been equalized and include the rates of all taxing districts in the county, including county, town, village, school district, and other special district rates (NYSDTF 2010b). P 4-118

COMMENT 43: The apparent use of the “overall full-value tax rate for the county” is likely to be misleading because there is an implicit and most likely incorrect assumption about the location of drilling. In reality, drilling is much more likely to be concentrated in the most rural jurisdictions and least likely to take place in the most urban jurisdictions. Because the tax rates in cities and villages (and associated school districts) tends strongly to be much higher than the tax rates in more rural jurisdictions, the estimated overall tax receipts are almost certainly exaggerated for this reason alone. A revised calculation should focus on the tax rates of towns and probably exclude all or most village and city rates. If this concern has already been considered, the rates used and rationale for using them should be made explicit.

Comments by:David Kay, Senior Extension Associate, Cornell Community and Regional Development Institute, Department of Development Sociology

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General Thoughts and CommentsEmissions

A Commentary on “The Greenhouse-gas footprint of natural gas in shale formations” by R.W. Howarth, R. Santoro, and Anthony Ingraffea

Lawrence M Cathles IIIa, Larry Browna, Milton Taamb, Andrew Hunterc a/ Department of Earth and Atmospheric Sciences, Cornell University, Ithaca, New York, 14853 b/ Electric Software, Inc., Caroline, New York c/ Department of chemical and Biological Engineering, Cornell University, Ithaca, New York, 14853

Abstract Natural gas is widely considered to be an environmentally cleaner fuel than coal because it does not produce detrimental by-products such as sulfur, mercury, ash and particulates and because it provides twice the energy per unit of weight with half the carbon footprint during combustion. These points are not in dispute. However, in their recent publication in Climatic Change Letters, Howarth et al. (2011) report that their life-cycle evaluation of shale gas drilling suggests that shale gas has a larger GHG footprint than coal and that this larger footprint “undercuts the logic of its use as a bridging fuel over the coming decades”. We argue here that their analysis is seriously flawed in that they significantly overestimate the fugitive emissions associated with unconventional gas extraction, undervalue the contribution of “green technologies” to reducing those emissions to a level approaching that of conventional gas, base their comparison between gas and coal on heat rather than electricity generation (almost the sole use of coal), and assume a time interval over which to compute the relative climate impact of gas compared to coal that does not capture the contrast between the long residence time of CO2 and the short residence time of methane in the atmosphere. High leakage rates, a short methane GWP, and comparison in terms of heat content are the inappropriate bases upon which Howarth et al. ground their claim that gas could be twice as bad as coal in its greenhouse impact. Using more reasonable leakage rates and bases of comparison, shale gas has a GHG footprint that is half and perhaps a third that of coal. Keywords: Unconventional Gas, Climate Change, Methane Emissions, Greenhouse Gas Footprint Coal vs Gas, Electric Power Generation

Natural gas is widely considered to be an environmentally cleaner fuel than coal because it does not produce detrimental by-products such as sulfur, mercury, ash and particulates and because it provides twice the energy per unit of weight with half the carbon footprint during combustion. These points are not in dispute.

These are submissions from faculty that, while they do not directly comment on the SGEIS, are relevant to the topics discussed in it.

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However, in their recent letter to Climatic Change, Howarth et al. (2011) report that their life-cycle evaluation of shale gas drilling suggests that shale gas has a larger GHG footprint than coal. They conclude that:

During the drilling, fracturing, and delivery processes, 3.6-7.9% of the methane from a shale gas well ends up, unburned, in the atmosphere. They claim that this is at least 30% and perhaps more than twice the methane emissions from a conventional gas well.

The greenhouse gas footprint for shale gas is greater than that for conventional gas or oil when viewed on any time horizon. In fact, they state that compared with the greenhouse gas (GHG) emissions from coal, it is 20 to 100 % greater on the 20-year horizon and is comparable over 100 years.

They close with the assertion that: "The large GHG footprint of shale gas undercuts the logic of its use as a bridging fuel over the coming decades, if the goal is to reduce global warming."

We argue here that the assumptions used by Howarth et al. are inappropriate and that their data, which the authors themselves characterize as “limited“, do not support their conclusions.

In particular, we believe Howarth et al.’s arguments fail on four critical points:

1. Howarth et al.’s high end (7.9%) estimate of methane leakage from well drilling to gas delivery exceeds a reasonable estimate by about a factor of three and they document nothing that indicates that shale wells vent significantly more gas than conventional wells.

The data they cite to support their contention that fugitive methane emissions from unconventional gas production is significantly greater than that from conventional gas production are actually estimates of gas emissions that were captured for sale. The authors implicitly assume that capture (or even flaring) is rare, and that the gas captured in the references they cite is normally vented directly into the atmosphere. There is nothing in their sources to support this assumption.

The largest leakage rate they cite (for the Haynesville Shale) assumes, in addition, that flow tests and initial production rates provide a measure of the rate of gas release during well completion, drill out and flowback. In other words they assume that initial production statistics can be extrapolated back to the gas venting rates during the earlier periods of well completion and drill out. This is incompatible with the physics of shale gas production, the safety of drilling operations, and the fate of the gas that is actually indicated in their references.

While their low-end estimate of total leakages from well drilling through delivery (3.6%) is consistent with the EPA (2011) methane leakage rate of ~2.2% of production, and consistent with previous estimates in peer reviewed studies, their high end estimate of 7.9% is unreasonably large and misleading.

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We discuss these issues at length below.

2. Even though the authors allow that technical solutions exist to substantially reduce any leakage, many of which are rapidly being or have already been adopted by industry (EPA, 2007, 2009), they seem to dismiss the importance of such technical improvements on the GHG footprint of shale gas. While the low end estimates they provide incorporate the potential impact of technical advances in reducing emissions from the sources common to both conventional and unconventional gas, they do not include the potential impact of “green technologies” on reducing losses from shale gas production. The references they cite document that the methane loss rate during completion of unconventional gas wells by modern techniques is, or could be, at least 10 times lower than the 1.9% they use for both their high end and low end estimates. Downplaying ongoing efforts and the opportunity to further reduce fugitive gas emissions in the natural gas industry, while at the same time citing technical improvements in the coal industry, gives a slanted assessment which minimizes the positive greenhouse potential of natural gas. Although the Howarth et al. agree "Methane emissions during the flow-back period in theory can be reduced by up to 90% through Reduced Emission Completions technologies or REC", they qualify this possibility by saying: "However, REC technologies require that pipelines to the well are in place prior to completion." This suggests that if the pipeline is not in place the methane would be vented to the atmosphere, which is misleading. If a sales pipeline is not available, the gas captured by REC technologies could be easily be (and are) flared and the GHG footprint thereby minimized.

3. Howarth et al. justify the 20-year time horizon for their GHG comparison by simply stating that “we agree with Nisbet et al. (2000) that the 20-year horizon is critical, given the need to reduce global warming in coming decades”. But the point Nisbet et al. make in their meeting abstract is that “adoption of 20-year GWPs would substantially increase incentives for reducing methane from tropical deforestation and biomass burning”. Their concern is that the 100-year timeframe would not discourage such methane emissions enough. Everyone would agree that discouraging methane as well as CO2 emissions is desirable, but the Nisbet et al. abstract offers no support whatever for the adoption of a 20-year GWP timeframe when considering replacing CO2 emissions with CH4 emission by swapping coal for gas, and we strongly disagree that the 20 year horizon is the appropriate choice in this context. As Pierrehumbert (2011) explains, “Over the long term, CO2 accumulates in the atmosphere, like mercury in the body of a fish, whereas methane does not. For this reason, it is the CO2 emissions, and the CO2 emissions alone, that determine the climate that humanity will need to live with.” In the context of a discussion of the benefits of swapping gas for coal, a 20 year horizon hides the critical fact that the lifetime of CO2 in the atmosphere is far longer than that of methane. Any timeframe is artificial and imperfect in at least some contexts, but a 100 year timeframe at least captures some of the implications of the shorter lifetime of methane in the atmosphere that are important when considering swapping gas for coal. One could argue (although Howarth et al do not) that the 20-year horizon is “critical” because of concern over triggering an irreversible tipping point such as

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glacial meltdown. However, if substituting gas for coal reduces (or could reduce) the GHG impact on a 20-year horizon as well as on a 100-year horizon, as we argue below is the case, substitution of gas for coal minimizes the tipping point risk as well. Most workers choose the 100 year timeframe. Hayhoe et al. (2002) adopt the 100 year timeframe, for example, and their more sophisticated analysis remains, in our opinion, more credible than that of Howarth et al on the issue of gas versus coal.

4. Howarth et al. choose an end use for comparing GHG footprints that is inappropriate in the context of evaluating shale gas as a bridging fuel. Coal is used almost entirely to generate electricity, so comparison on the basis of heat content is irrelevant. Gas that is substituted for coal will of necessity be used to generate electricity since that is coal’s almost sole use. The appropriate comparison of gas to coal is thus in terms of electricity generation. The "bridge" is from coal-generated electricity to a low-carbon future source of electricity such as renewables or nuclear (EIA AEO 2011). Howarth et al. treat the end use of electricity almost as a footnote. They acknowledge in their electronic supplemental material that, if the final use is considered, “the ability to increase efficiency is probably greater for natural gas than for coal (Hayhoe et al., 2002), and this suggests an additional penalty for using coal over natural gas for the generation of electricity not included in our analysis”. They address the electrical comparison in an electronic supplement table, however they do so there on the basis of a 20 year GWP and they minimize the efficiency differential between gas and coal by citing a broad range for each rather than emphasizing the likelihood that efficient gas plants will replace inefficient coal plants. Had they used a 100 year GWP and their low-end 3.6% methane leakage rate, shale gas would have about half the impact of surface coal when used to generate electricity (assuming an electricity conversion efficiency of 60% for gas and their high 37% conversion efficiency for coal). The electric industry has a large stock of old, inefficient coal-fired electric generating plants that could be considered for replacement by natural gas (EIA AEO-2011, Table 1). The much lower construction costs associated with gas power plants (e.g. Kaplan, 2008) means modern gas technology will likely replace this old coal technology as it is retired. If total (well drilling to delivery) leakage is limited to less than 2% (which may be the current situation and, in any case, seems well within the capabilities of modern technology; EPA, 2007, 2009), switching from coal to natural gas would dramatically reduce the greenhouse impact of electricity generation. Minimizing this point by stressing extreme rather than likely scenarios is perhaps the most misleading aspect of the Howarth et al. analysis.

Figure 1 depicts what we suggest is a more representative comparison of the likely impact on greenhouse gas emissions when natural gas replaces coal in older coal-burning electric power plants. In our analysis, we assume 60% efficiency for natural gas generation of electricity, 30% efficiency for coal generation of electricity in older plants, and a total methane leakage rate of 2.2%. Relatively low-cost 60% efficient generators using natural gas are commonly available (Siemens). When both fuels are used to produce electricity (MJe), the greenhouse impact of natural gas is only as bad as coal if a very high methane leakage rate of 7.9% and a short global warming impact period of 20 years are selected

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(column labeled Howarth et al. in Figure 1). If the comparison is based on the heat content of the fuels, the top (green) portion of the Howarth et al. column is doubled in length, and gas becomes twice as bad as coal from a greenhouse perspective. This is the basis of Howarth et al.’s suggestion that gas could be as bad or twice as bad as coal from a greenhouse perspective. Assuming more realistic estimates of gas leakage rates and using the 100 year global warming potential factor (of 33 grams of GHG-equivalent CO2 per gram of methane released to the atmosphere), which captures the contrast in atmospheric lifetimes of CO2 and natural gas, we show in Figure 1 that gas has a much smaller global warming impact than coal. For leakage rates less than 2%, the impact of natural gas approaches 1/3rd that of coal, and methane leakage (top green bar) is an insignificant part of the greenhouse forcing compared to the CO2 released during combustion (bottom blue part of bar). For the 100y GWP of 33, gas exceeds the global warming impact of deep coal only when its leakage rate exceeds 18.2% of production, and exceeds the global warming impact of surface coal only when its leakage exceeds 17.1% of production. These natural gas leakage rates are well beyond any known estimates.

Column 4 in Figure 1 makes more favorable assumptions regarding the use of coal. Here we compute the greenhouse impact of producing electricity in an ultra-supercritical pulverized coal unit without CO2 capture (which would reduce its conversion efficiency) of 62 gC/MJe. A 2007 interdisciplinary MIT study found that a plant of this nature might achieve a 43.3% conversion efficiency when burning low impurity coal (MIT, 2007). Although no plant of this kind has yet been constructed, the 4th column in the gas category of Figure 1 shows that the greenhouse impact of a gas plant with 50% conversion efficiency would have about half the GHG impact of this high-end coal plant.

Sixty percent conversion efficiency is not the limit for gas. Combined heat and power (CHP) generation can utilize 90% of the chemical energy in gas. Heat could be likewise used from coal facilities, but small gas units are more cost effective and gas facilities could be built closer to populated user markets that could utilize the heat. Thus gas has a greater CHP potential than coal.

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Figure 1. Comparison of the greenhouse impact of burning natural gas to coal when the fuels are used to produce electricity, expressed as the grams of GHG-equivalent CO2 carbon per megajoule of electricity generated. The conversion efficiency to electricity of coal and gas are assumed to be 30 and 60% respectively in all columns except the 4th and 8th columns, which compare a very efficient coal plant to a less efficient gas plant. As in Howarth et al. (2011) we use 20 and 100 year GWP factors of 105 and 33 grams of GHG-equivalent CO2 per gram of methane released, and assume deep and shallow coal mining releases 8.4 m3 and 2.3 m3methane per ton, respectively. Indicated below each column are the GWP factors, the percent methane leakage (1, 2.2 and 7.9%), whether the coal burned is from deep or shallow mines, and where different from 60%, the gas conversions efficiency used in the calculation. No allowance is made for the transport/transmission of either fuel, which effectively assumes electricity generation at the well/mine head. Shale gas is generally closer to power markets than coal, however.

Methane venting during well completion and drill out of unconventional gas wells A critical part of Howarth et al.’s paper’s contention that shale gas has a larger greenhouse impact than conventional gas is the contention that an unconventional gas well vents 1.9% of its lifetime gas production during well completion. (Unconventional gas wells include those producing from tight sands, shales, and coal bed methane wells - the Howarth et al. figures assume that emissions from these are all similar.) This is dramatically more than the 0.01% they cite as vented by a conventional gas well. Their 1.9% number is a large component in their high-end leakage rates, which are themselves central to their contention that the global warming impact of gas could be twice as bad as coal on a heat content basis.

We agree with Howarth et al. that the available data are extremely limited, that their analysis relies heavily on powerpoint presentations rather than values published in reviewed literature, and that there is an obvious need for better estimates. However, given the lack of quality data, we feel that the authors have a responsibility to make explicit the

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nature and limitations of such sources, and to be especially clear on the assumptions made in their interpretation of such data. We feel that was not done, and offer the following to put their estimates in context.

There are fundamental problems with key numbers that they use in their Table 1 to support their 1.9% contention:

(1) The numbers they use to represent fugitive emissions for the Haynesville Shale cannot be found in the references they cite. That the daily methane loss estimates shown in their Table 1 are close to the initial production (IP) values cited in their references suggests that the authors assume that the latter is somehow an estimate of the former. As argued below and in the electronic supplement, this is incompatible with (a) the basic physics of gas production, (b) the economic incentives of gas production, and (c) the only early production data related to shale gas that can be found amongst any of their references.

(2) The only discussion of methane losses during well completion is found in the citations for tight gas sands, and those values are presented to illustrate how currently used technologies can capture most (up to 99%; Backen, 2008) of those “losses” for sale.

(3) Their estimate of methane loss from drill out is based on two numbers from the Piceance Basin reported in a powerpoint slide presented to an EPA Gas STAR conference (EPA, 2007). They assume that 10 million cubic feet of gas is typically vented during well drill out rather than being captured or flared, although their source makes no such claim. For reasons discussed below and in the electronic supplement, gas production is rare during drill out and if significant gas were produced during drill out it would not be emitted into the atmosphere for economic and safety reasons.

(4) The magnitude of the releases they suggest are not credible when placed in the context of well completion and well pad operating procedures, safety, and economic factors.

The high releases of methane Howarth et al. suggest for the Haynesville data in their Table 1 are the most problematic because they skew the average for the suite of locations listed, and because the numbers are not based on documented releases to the atmosphere but rather on initial production rates that are likely to have been captured and sold or flared.

The value shown in their Table 1 for methane emitted during flowback in the Haynesville does not exist in any of their citations. The reference linked to this number (Eckhardt et al, 2009) is an online industry scout report on various values of flow tests and initial production (IP). To the extent that this reference deals with the fate of the gas associated with those flow tests it indicates that the production was captured and sold. The estimate for IP for the Haynesville is based on another informal, unvetted, web posting by a gas producer that is no longer available. However that estimate of IP is consistent with the values cited in Eckhardt et al. and the known characteristics of Haynesville wells. The fact their values for the daily rate of “lost” emissions for the Haynesville are virtually identical

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to the IP values for the wells indicates that the authors believe or assume that: (a) a well produces gas during completion at a rate that is equal to the highest rate reported for the well (the IP rate), and (b) that this gas is vented directly to the atmosphere. They provide no documentation for either of these beliefs/assumptions, which are on multiple grounds illogical. Because initial production is the highest flow achievable, and flowback occurs when the well still contains substantial water, flowback gas recoveries cannot exceed initial production recoveries, although Howarth et al. imply this is the case for all the areas listed in their Table 1. The problem is this: High gas flow rates are not possible when the well is substantially full of water, as it usually is during the flowback period. Gas cannot move up a wellbore filled with water other than in isolated packets, and it can flow optimally only when enough water is removed for the gas to have a connected pathway of gas up the well to the surface. Unless otherwise explicitly noted, initial production figures are published to show the highest recorded production rate for each well. They are a benchmark that characterizes what optimal production rate can be achieved by a well (and for which there is every incentive for producers to exaggerate in order to attract investors: http://www.oilempire.us/shalegas.html). These initial production tests are seldom run until after any substantial water has been removed from the well because substantial water impedes the outflow of gas.

The only sources which explicitly provide estimates of gas production during completion are for the Barnett (EPA , 2004; although the Barnett is not named in this reference), the Piceance (EPA, 2007), the Uinta (Samuels, 2010), and the Den Jules (Bracken, 2008) gas sands. These references report how gas production was recovered for sales and imply that this has been the case (at least for these companies) for several years! They emphasize the strong economic incentives for gas producers to capture and sell completion gases rather than flare or vent them. Only one (EPA, 2007) provides explicit measurements of both captured (with “green technology”) and lost emissions, and these numbers indicate a loss rate of 0.1% of total production. Howarth et al. cite the gas capture numbers in these references as representative of the gas leakage into the atmosphere that would occur if the gas was neither captured nor flared. They assume that this is the common situation, but do not make it clear that they have made this assumption. Rather they buttress their leakage estimates with the citations as if the latter explicitly documented methane leakage into the atmosphere, which they do not.

Based on conversations we have had with people experienced in well completions, we believe the losses during drill out and well completion for unconventional shale gas wells are not significantly greater than those cited by Howarth et al. for conventional gas wells. Certainly this could be made to be the case. This is supported by some of the examples cited by the EPA and Howarth et al. The Williams Corp (EPA, 2007, p 14) shows, for example, that >90% of the flowback gas is captured and some of the remainder flared (George, 2011, p14). If this were generally the case Howarth et al.’s 1.9% leakage would be reduced to 0.2%. An alternative life cycle analysis of a natural gas combined cycle power plant shows the total methane release from unconventional Barnett Shale hydrofractured gas wells is within a few percent of that from conventional onshore gas wells (DOE/NETL, 2010, Table 5.1 and Figure 5.1).

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It is also worth pointing out that much of the oil produced in the United States at present is either from hydrofractured wells or shale formations, and thus is unconventional oil. Almost every conventional and unconventional oil well also produces natural gas. A clean distinction between “conventional” and “unconventional” gas production, and between “oil” and “gas” wells, thus may be very difficult to make, as there is an enormous amount of overlap between these categories.

Additional material supporting the statements made above is provided in an electronic supplement to this commentary. We describe there what happens when a well is completed and brought into production, and explain why a well cannot vent at its IP rate during the early drill out and completion phases, and (with discussion and a figure) why Howarth et al.’s projection of the IP rate to the flowback stage (these early stages) of well development is inappropriate. We discuss the purpose and nature of a scout report and show that the scout report cited by Howarth et al. states that the reported gas production was captured and diverted to sales (not vented into the atmosphere as Howarth et al. suggest). We discuss the safety implications of Howarth et al.’s contention that 3.2% of the total eventual production of a shale gas well is vented into the atmosphere over a period of ~10 days, and show that this represents $1,000,000 worth of gas and would fill a square mile area to 176 ft with an explosive mixture of 5% methane. And we show that the EPA’s suggestion of release rates 50% of Howarth et al.’s is based on the assumption that, where capture or flaring is not required by law, methane is released to the atmosphere - an assumption that is simply not warranted on current practice, economic, or safety grounds. Those not familiar with well completion and production or economic and safety well procedures may find this additional material useful.

Methane leakage from the well site to the customer The leakage that occurs between an operating well and consumers as the result of gas handling, processing, storage, and distribution is the same whether the well is producing from tight shale or conventional source rock. These losses are very hard to measure as they rely on a variety of sources that cannot be controlled in a scientific fashion. As well as true leakage you have to deal with questions of metering accuracy, shrinkage due to removal of higher order hydrocarbons, fuel use by compressors along the pipeline, etc. Trying to reach an estimate is important because various parties have a financial interest in the gas as it travels to the consumer, but scientific assessments are also encumbered by accounting conventions that relate to how gas transmission is charged to pipeline users. The results of most studies should not be considered accurate estimates that can be used for climate studies.

With well completion and drill out losses from both sources negligibly small (see above), the range of methane emissions that Howarth et al. identify is from 1.7 to 6% of total production. Leaking 6% of the gas that will ultimately be produced into the atmosphere during on-site handling, transmission through pipelines, and delivery appears to be far too high and at odds with previous studies. The most recent comprehensive study (EPA, 2011, Table 3-37, assuming a 2009 U.S. production of natural gas of 24 TCF) shows the emission

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of methane between source and user is ~2.2% of production. Breaking this down, 1.3% occurs at the well site, 0.73% during transmission, storage, and distribution, and 0.17% during processing. The EPA Natural Gas STAR program (EPA, 2009), a voluntary partnership to encourage oil and natural gas companies to adopt best practices, reports methane emissions of 308 BCF in 2008 This represents an emission of ~1.3% of total production. A life cycle analysis of combined cycle natural gas power pollutants suggests leakage can be much smaller. This report estimates ~0.9 wt% leakage of methane between source and consumer (DOE/NETL, 2010, Table 5.1), and suggests what best practices might achieve. A reasonable range for methane emissions to the atmosphere between source and consumer in the U.S. (the proper subject of the current discussion) would thus appear to be between 0.9 and 2.2% of production.

Excepting completion and drill out losses, the losses during transmission, storage and distribution, which Howarth et al. claim are conservatively 1.4 to 3.6% of production, constitute the largest fraction of their range of total gas losses of 1.7 to 6%. Howarth et al.’s transmission, storage and distribution losses are 2 to 5 time higher than the EPA(2011) estimate of 0.73%. Even their low end estimate seems far too high. Furthermore, many organizations have addressed these leakages, and many are striving to reduce them. Even if a 6% leakage rate were true in the US, the obvious policy implication would surely be to “fix the leaks”. For example, Russian leakage was huge in the 1980s but with recent investments and improvements their leakage rate now is comparable to and perhaps less than ours. Of all the possibilities one could think of, reducing methane leakage should be the easiest, most accessible, and least costly way to reduce greenhouse gas emissions, and something that should be done regardless of how a comparison of gas and coal turns out.

Conclusions We have highlighted two aspects of the recent letter from Howarth et al. that we believe are misleading.

The first aspect is the question of just how much methane gets released directly into the atmosphere during drilling, production, and transmission from unconventional gas wells. We show that the authors base their leakage rates heavily on two assumptions: (1) that drillers vent gas to the atmosphere during the drill out and pre-IP stages of development rather than capture and divert it to sales or flare it, and (2) that the discharge rate during these periods is comparable to the maximum production rate the well will experience - the IP rate. Current industry practice does not vent gas during these periods in such extreme quantities for obvious economic and safety reasons. Howarth et al.’s assessment of the leakage from shale gas production thus appears to be too large by a factor of ~10 (0.2% of lifetime production rather than the 1.9% Howarth et al. assume). Even if we were to accept such an estimate as representative of current practice (which we believe it is not), it is clear from Howarth et al.’s own citations that there are existing technological options that can greatly reduce such losses, and future technological improvements are sure to further reduce losses venting from both conventional and unconventional wells.

The second aspect of the Howarth et al. paper that we question is the effect of methane leakage from gas drilling on greenhouse gases and the future climate. Howarth et al.

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compute the GHG impacts using the most unfavorable time period (20 years vs 100 years) and basis (heat vs electricity) for comparing gas with coal. Considering that coal is used almost exclusively for generating electricity, gas must replace electricity generation by coal and the fuels should be compared on this basis. When considering the impact of swapping methane for CO2 it is important to take into account the very short lifetime of methane in the atmosphere compared to the very long lifetime of the CO2. The 100 year GWP for methane does this, the 20 year GWP does not. Given the focus on electricity generation and using a 100 year GWP we show, using the same methods as Howarth et al., that gas has less than half and perhaps a third the greenhouse impact as coal. Since gas also possesses other important emission advantages such as no particulates, SO2, NO2, or ash, it is clearly the “cleaner” option in comparison to coal. Howarth et al. arrive at their conclusion that gas could have twice the greenhouse impact as coal only by using fugitive gas emissions 3.6 times larger than is reasonable (e.g. 2.2%), selecting a 20 year Global Warming Potential period for methane (which confers an impact 3.2 times bigger than a 100 year GWP), and failing to consider that a modern gas plant can generate electricity nearly twice as efficiently (and therefore with half the GHG input) as old coal plants.

It is of course possible, although we consider it highly unlikely and find no evidence to that effect, that methane emissions from wells and pipelines might be as large as Howarth et al. aver. But, as they acknowledge, these leaks could be economically and relatively easily fixed. Addressing whatever deficits natural gas might have at present so that it realizes the potential GHG benefits that are indicated in our Figure 1 seems to us a goal eminently more achievable with current technology, and should be far more economic and less risky than relying on undeveloped and unproven new technologies to achieve the same degree of GHG reduction through other methods. Surely we need to consider how to reduce GHG emissions for all fuels, and should do the best we can with all the fuels we are using and are likely to continue using for some time. But in the short term, our energy needs should be satisfied mainly by those fuels having the fewest inherent environmental disadvantages, and we believe those preferred fuels include natural gas.

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References

Bracken K (2008) Reduced emission completions in DJ basin and natural buttes. Presentation given at EPA/GasSTAR Producers Technology Transfer Workshop. Rock Springs Wyoming, 1 May 2008. http://www.epa.gov/gasstar/documents/workshops/2008-tech-transfer/rocksprings5.pdf

DOE/NETL (2010) Life cycle analysis: natural gas combined cycle (NGCC) power plant, DOE/NETL-403-110509, 127p. http://www.netl.doe.gov/energy-analyses/pubs/NGCC_LCA_Report_093010.pdf

Eckhardt M, Knowles B, Maker E, Stork P (2009) IHS U.S. Industry Highlights. (IHS) Houston, TX, Feb–Mar 2009. http://www.gecionline.com/2009-prt-7-final-reviews

EIA (AEO-2011) Annual Energy Outlook. http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf

MIT (2007) The Future of Coal, An Interdisciplinary MIT Study. http://web.mit.edu/coal/The_Future_of_Coal.pdf

MIT (2010) The Future of Natural Gas, An Interdisciplinary MIT Study. http://web.mit.edu/mitei/research/studies/report-natural-gas.pdf

EPA (2011) Inventory of greenhouse gas emissions and sinks 1990-2009, EPA 430-R-11-005, 55 phttp://epa.gov/climatechange/emissions/usinventoryreport.html

EPA (2009) EPA natural gas STAR program accomplishments, http://www.epa.gov/gasstar/accomplishments/index.html#three

EPA (2007) Reducing methane emissions during completion operations, 2007 natural gas STAR production technology workshop, Glenwood Springs, CO, September 11, 2007. http://epa.gov/gasstar/documents/workshops/glenwood-2007/04_recs.pdf

EPA (2004) Green completions. Natural Gas STAR Producer’s Technology Transfer Workshop, 21 September 2004. http://epa.gov/gasstar/workshops/techtransfer/2004/houston-02.html

George, F (2011) Re: Comments from El Paso Corporation on the DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009, 25p. Henk, D (2010) Encana, USA division overview. Encana Natural Gas, investors presentation, http://www.encana.com/investors/presentations/investorday/pdfs/usa-division-overview.pdf Howarth R, Santoro T, and Ingraffea A (2011) Methane and the greenhouse gas footprint of natural gas from shale formations, Climatic Change, DOI 10.1007/s10584-011-0061-5. http://www.springerlink.com/content/e384226wr4160653/

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Hayhoe K, Kheshgi HS, Jain AK and Wubbles DJ (2002) Substitution of natural gas for coal: climatic effects of utility sector emissions, Climate Change, 54, p 107-139. Kaplan, S (2008). Power plants: characteristics and costs. Report to Congress. http://www.fas.org/sgp/crs/misc/RL34746.pdf Lightly RG (2008). Work plan for potential GHG reductions: coal mine methane recovery. Pennsylvania Department of Environment Protection. http://files.dep.state.pa.us/Energy/Office%20of%20Energy%20and%20Technology/lib/energy/docs/climatechangeadvcom/industrial/coal_mine_methane_101408.doc

Malloy KP, Mdelely GH, and Stone RC (2007) Taking another look at the risk profile for air drilling in presence of hycrocarbons, Managed Pressure Drilling, March/April, p66-73. http://drillingcontractor.org/dcpi/dc-marapr07/DC_Mar07_malloy.pdf

Nisbet EG, Manning MR, Lowry D, Lassey KR (2000) Methane and the framework convention on climate change, A61F-10, Eos Trans. AGU 81(48), Fall Meet. Suppl.

Pierrehumbert R (2011) http://www.realclimate.org/index.php/archives/2010/12/losing-time-not-buying-time/

Saghafi A, Williams DJ, Lama RD (1997) Worldwide methane emissions from underground coal mining, in Proceedings of the 6th International Mine Ventilation Congress, May 17-22, p. 441-445. http://drillingcontractor.org/dcpi/dc-marapr07/DC_Mar07_malloy.pdf

Samuels J (2010) Emission reduction strategies in the greater natural buttes. Anadarko Petroleum Corporation. EPA Gas STAR, Producers Technology Transfer Workshop Vernal, Utah, 23 March 2010. http://www.epa.gov/gasstar/documents/workshops/vernal-2010/03_anadarko.pdf

Siemens power plants http://www.energy.siemens.com/us/en/power-generation/power-plants/gas-fired-power-plants/combined-cycle-power-plant-concept/scc5-8000h-1s.htm#content=Description

Yost C (2010) U.S. gas market well-supplied: LNG of shale gas?, Oil and Gas Journal 108(10), p46-50. http://www.ogj.com/etc/medialib/platform-7/ogj/articles/print-articles/volume-108/March-15.Par.35557.Image.600.460.1.gif

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Electronic Supplementary Material

Completing and Bringing a Well Into Production Consider what happens in completing a well and bringing it into production: The well is drilled, logged, and then hydrofractured. When the hydrofracturing is finished, the wellbore and producing formations are full of water. Drilling out the plugs which divide the well into hydrofracture intervals occurs at this stage. Because the well is filled with water, only water is typically produced from the well during this process, and only gas dissolved in this water is brought to the surface, at least initially. Generally this condition persists during the full drill out period, but sometimes gas enters the well during drill out and must be dealt with at this stage. When the drill out is under water-filled-wellbore conditions, the gas leakage rate is comparatively small because, compared to a freely venting gas well, very little gas can be brought to the surface dissolved in water since gas solubility in water is low. The water produced at this stage is usually (and could always be) put into a capped tank where the gas exsolves from the water and is flared or captured. When the drill out occurs with substantial gas in the wellbore, more and perhaps very much more gas can be produced, but for safety and economic reasons (see below) it is not vented, but captured and either flared of diverted to sales through a pipeline. After drill out is completed, the operator begins to flow water from the well and the flowback stage begins. Normally no gas (or very minimal dissolved gas) is produced initially, but after a period ranging from hours to multiple days, the well starts to produce slugs of gas, and shortly thereafter enough gas that the well effluent can be diverted to a separator. The gas flow from the separator is generally either flared or put into a pipeline for sale. The first well on a pad may be flared (the methane is not released), but after this the gas is generally diverted to a pipeline and delivered to sales once enough gas pressure is obtained (or a skid-mounted compressor is utilized).

Figure S1 shows gas well production curves for the Haynesville Shale that include the pre-IP production (that portion of a well’s production that took place before the flowback was completed and the production peaked). It shows clearly that production rates during the pre-IP production period are much lower than the monthly maximum production rates of the wells (which are themselves less than their reported IP rates). Production of gas is essentially non-existent in the early flow-back period (when only frac water is being produced). Significant gas flow starts only when enough frac water has been removed to let the gas begin to flow. The duration of the flowback period is poorly defined and there is no firm correlation between how a well will perform and the volume of gas that is produced during the flowback period. Gas production rates peak days to months later when frac water has been recovered from every producing frac stage and the well is operating optimally. From this maximum the production steadily declines. Most published production curves shown for unconventional gas production do not include the initial start up of gas production but begin when the well is considered to be done flowing back and in regular production and declining from its peak production.

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Figure S1. Production curves for Haynesville shale gas production. DI ESP (2010). The horizontal axis is time in months.

Scout Reports A scout report, such as the one cited by Howarth et al. for their initial Haynesville leakage and production numbers, rarely indicates what the operator actually does with their gas during the initial testing of a well. Initial production figures therefore generally can’t be used to estimate methane emissions because these reports are intended to convey how the well produces at its peak, not what the operator does with the production. The only entry in the source document Howarth et al. reference that gives any information related to emissions (Eckhardt et al., 2009) suggests that the gas flow noted was captured: “The 1 Moseley was reported producing to sales at the daily rate of 14 million cu ft of gas equivalent through perforations at 12,800-15,260 ft while the operator was still cleaning up frac load.” In other words, at the time the gas flow rate was measured, the flowback was still ongoing and gas was producing to sales. This is the exact opposite of the venting of the gas to the atmosphere that Howarth et al. suggest.

One of the authors of this scout report (Philip H. Stark) recently published a statement regarding the use of their data by Howarth et al. (Appendix 1 in Barcella et al., 2011). His conclusion matched the one we made independently here - that their (eg., Stark and others) report did not contain “any evidence of such methane emissions”.

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Economic and Safety Considerations The large values for methane lost during completion that Howarth et al. suggest is routine industry practice is incompatible with elementary safety and economic considerations. Consider again the Haynesville Shale case. Howarth et al. indicate that 6.8 million cubic meters of Haynesville natural gas (3.2% of a typical well’s lifetime production) is released during an assumed flowback period of 10 days. Releasing 6.8 million cubic meters of gas into the atmosphere is equivalent to venting roughly $1,000,000 worth of natural gas (wholesale) from a single well. This leakage rate is equal to the consumption rate of 100,000 households, a city the size of Buffalo, NY (assuming 2.6 people per household) (EIA 2010). It’s also a volume of potentially explosive gas so large that no driller (let alone their employees, contractors and regulators) would willfully release it. This volume of gas could cover a square mile of land with a combustible 5% mix of methane to a height of 176 feet, for example. Think how a homeowner worries what a very small emission from a gas stove might do to their house if not properly turned off before they leave for the theatre. The Howarth et al. leakage rate would fill a 3500 square foot house with an explosive mixture of 5% methane and air in 5 seconds. The idea that emissions such as Howarth et al. suggest occur on a routine basis in Haynesville Shale wells, or from any other large volume well, is simply not credible on safety considerations alone.

If an operator could find a way to safely vent such a high volume of shale gas, and preferred to do that over flaring or selling the gas, they could theoretically do so. It's illegal on this scale in most states (see 25 PA Code Sec. 78.74, for instance), and would clearly violate the terms of their liability insurance, but it could physically happen during initial production testing. As a practical matter, however, it doesn't happen on any scale except in very rare circumstances, such as a well blow-out, and it cannot happen during the periods when there is still substantial frac water in the well (generally the case during the drill out and early flow back periods) which is the period when Howarth et al. suggest the methane is released.

EPA’s Venting Analysis Howarth et al. support their very high leakage estimate in general terms by citing the EPA’s (2010) conclusion that large quantities of methane accompany the flow back of water and are vented in the first few days or weeks after hydrofracture injection. The basis for the EPA’s (2010, p. 84 ff) conclusion is their observation that 51% of the U.S. unconventional production (coal bed methane and shale gas only - no tight sands gas data was available) in 2007 was in Wyoming (of which none was from shale), where flaring is required by law, and 49% was in Texas, Oklahoma, and Louisiana, where it is not required, but isn‘t banned either. The EPA then assumed that where regulations did not require the methane to be flared, it was all released directly into the atmosphere (not flared or sold), and they generalized this to be universally true. The EPA thus concludes that 4.6 million cubic feet of methane (50% of the typical 9.2 million cubic feet that they estimate is produced from an unconventional gas well during flowback) is released into the atmosphere. For all the reasons discussed above, we believe that this is a highly questionable assumption, and certainly one that is clearly stated by the EPA to be speculative. They did not document the venting, and are very clear that their basis is the assumption that when not required by law to flare or sell gas, unconventional wells are vented (into the atmosphere) during initial

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production. At least the EPA acknowledges that a significant portion of the methane emissions may be flared, rather than vented, in contrast to Howarth et al, who appear to assume 100% venting, the least likely scenario for real world operations.

References Cited Barcella, ML, Gross S, and Rajan S (2011) Mismeasuring Methane: estimating greenhouse gas emissions from upstream natural gas development, iHS Cerra Report, http://www.ihs.com/info/en/a/mis-measuring-methane-report.aspx.

DI ESP (2010) Haynesville Shale News and Analysis from DI Energy Strategy Partners, http://info.drillinginfo.com/urb/haynesville/operators/2010/05/comstock-lease-positions-and-quarterly-earnings-call/

EIA (2010) Trends in U.S. Residential Natural Gas Consumption, Office of Oil and Gas, June, 12p. http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2010/ngtrendsresidcon/ngtrendsresidcon.pdf

Eckhardt M, Knowles B, Maker E, Stork P (2009) IHS U.S. Industry Highlights. (IHS) Houston, TX, Feb–Mar 2009. http://www.gecionline.com/2009-prt-7-final-reviews

EPA (2010) Greenhouse gas emissions reporting from the petroleum and natural gas industry. Background Technical Support Document. http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_TSD.pdf

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Department of Ecology and Evolutionary Biology

Statement to the Assembly Committee on Environmental Conservationregarding the draft sGEIS for shale gas development in New York State

Robert W. HowarthThe David R. Atkinson Professor of Ecology & Environmental Biology

309 Corson Hall, Cornell University, Ithaca, NY 14853607-255-6175

[email protected]

October 12, 2011

I am sorry I was not able to appear before the Committee in person during your hearinglast week, but I had a prior commitment to travel to Brussels and present testimony to theEuropean Union Parliament. The Parliament had invited me and paid my way to attend thehearing, due to their interest in on our research on greenhouse gas emissions from shale gasdevelopment and how this affects the European Union commitment to mitigating global climatechange. Note that our research was cited as one of the prime reasons that the government ofFrance passed a permanent ban on shale gas on October 3, 2011.

The Department of Environmental Conservation has prepared a long and detailed draftsGEIS. Unfortunately, I find the document critically lacking in important details. To summarizemy major concern in one statement, the draft sGEIS fails to use the most recent and bestscientific information, and as a result, the document reaches many incorrect conclusions and failsto adequately protect the environment and people of New York State. As Prof. Tony Ingraffeaand I wrote in an invited commentary for the journal Nature on September 15, 2011, “Becauseshale gas development is so new, scientific information on the environmental costs is scarce.Only this year have studies in peer-reviewed journals begun to appear, and these give reason forpause.” (Howarth & Ingraffea, Should fracking stop? Yes, it’s too high risk, Nature, v. 477, pages 271-273).

Here, let me briefly raise two issues (I will be providing more detailed feedback directlyto the DEC before their comment period ends). First, the sGEIS severely underestimates the riskto drinking water sources, and second, the sGEIS completely mischaracterizes the magnitude andconsequences of greenhouse gas emissions from shale gas development.

On the question of drinking water contamination, the sGEIS refers to the May 2011 paperby Duke University scientists published in the peer-reviewed journal Proceedings of the NationalAcademy of Sciences (Osborn, S. et al. 2011. Methane contamination of drinking water accompanyinggas-well drilling and hydraulic fracturing. Proceedings of the National Academy of Sciences; doi:

General Thoughts and CommentsEnvironmental Risk

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10.1073/pnas.1100682108). However, the sGEIS treats this important study in a rather dismissiveway. Since this paper represents the only peer-reviewed paper ever published on thecontamination of private drinking water wells from hydraulic fracturing, it deserves much morecredence than given in the sGEIS. The finding of the paper is that private water wells within 1km (approximately 7/10ths of a mile) of an active shale-gas well have a 75% percent of havingtheir water contaminated with very high levels of methane. Given the likely spacing of wellswithin New York State should shale gas be developed, the majority of private drinking waterwells in gas development areas seem likely to be contaminated.

Another drinking water supply concern is the contamination of municipal drinking watersupplies from fracking fluids, which can enter the water supply through surface accidents andspills, through illegal dumping of frac-fluid return wastes, and through the disposal of frac-fluidreturn wastes in sewage treatment plants (see details in the Howarth & Ingraffea Naturecommentary form September 15, as well as numerous well-documented reports in the New YorkTimes: http://www.nytimes.com/2011/02/27/us/27gas.html?hp;http://www.nytimes.com/2011/03/02/us/02gas.html?hp;http://www.nytimes.com/2011/03/04/us/04gas.html?hp;http://www.nytimes.com/2011/08/04/us/04natgas.html?ref=ianurbina).The sGEIS clearly recognizes that such contamination can occur, for instance stating on pagesES17 and ES18 of the Executive Summary: “In April 2010 the Department concluded that due to theunique issues presented by HVHF operations within the drinking watersheds for the City of New Yorkand Syracuse, the SGEIS would not apply to activities in those watersheds. Those areas present uniqueissues that primarily stem from the fact that they are unfiltered water supplies that depend on strict landuse and development controls to ensure that water quality is protected. The revised analysis of HVHFoperations in the dSGEIS concludes that the proposed HVHF activity is not consistent with thepreservation of these watersheds as an unfiltered drinking water supply. Even with all of the criteria andconditions identified in this dSGEIS, a risk remains that significant HVHF activities in these areas couldresult in a degradation of drinking water supplies from accidents, surface spills, etc.” However, thesGEIS has absolutely no scientific basis for assuming that the municipal drinking water suppliesin the State other than in Syracuse and New York City are somehow protected by filtrationsystems. In a September 15 letter to Governor Cuomo, I and 58 experts from across New YorkState and the world wrote to challenge this presumption. The full letter and list of signatories isavailable at http://www.psehealthyenergy.org/data/Sign_on_letter_Final.pdf

With regard to greenhouse gas emissions, the sGEIS completely ignores peer-reviewedscientific literature and instead relies on industry web sites. For context, the scientificunderstanding on greenhouse gas emissions from shale gas has undergone a massive change inthe past 11 months. A great deal of new information and new analyses have been published orpresented recently, and all of this information is completely ignored by the sGEIS. Instead, thepresentation represents a viewpoint based on information from the 1990s and earlier, before anyshale-gas development even occurred. The latest scientific information leads to the strongconclusion that shale gas has the largest greenhouse gas footprint of any fossil fuel, whenemissions of methane gas are fully considered and the consequences evaluated at time scales of50 years or less following emission (see the Howarth & Ingraffea commentary in Nature, as well

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as the references cited there). New York State may not be able to meet our commitment toreducing greenhouse gas emissions, if shale gas is allowed to be developed without effectiveregulation to mitigate greenhouse gas emissions. Such regulations are not considered in thesGEIS. A few key studies which are not presented in the sGEIS, but which must be considered ifthe consequences of shale gas development on greenhouse gas emissions are to be understood,are listed below. Note that all of these were available at the time the DEC issued the final draftof the sGEIS.

Shindell, D. et al. 2009. Improved attribution of climate forcing to emissions. Science326:716-718. [this study demonstrates that the global warming potential of methanecompared to carbon dioxide is far greater than previously appreciated, and far greaterthan assumed in the sGEIS, which relies on decades old science].

Governmental Accountability Office 2010. Federal Oil and Gas Leases: OpportunitiesExist to Capture Vented and Flared Natural Gas, Which would Increase RoyaltyPayments and Reduce Greenhouse Gases. GAO-11-34 U.S. General AccountabilityOffice Washington DC. October 2010. http://www.gao.gov/new.items/d1134.pdf [thisreport from October 2010 is an independent assessment by this investigatory arm ofCongress to examine losses of methane and natural gas on federally owned lands; thereport concludes that methane emissions are far higher than had generally been assumed].

Environmental Protection Agency 2010. Greenhouse Gas Emissions Reporting from thePetroleum and Natural Gas Industry. Background Technical Support Document.http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_TSD.pdf [thisreport from November 2010 is the first update on methane emissions from the natural gasindustry by the EPA since 1996; the report concludes that methane emissions are farhigher than previously believed, giving natural gas in general and shale gas in particular afar larger greenhouse gas footprint than had been assumed prior to November 2010].

Howarth, R., et al. 2011. Methane and the greenhouse gas footprint of natural gas fromshale formations. Climatic Change Letters, doi: 10.1007/s10584-011-0061-5 [this is thefirst comprehensive study to evaluate the greenhouse gas emissions from shale gas,including emissions of methane; the conclusion is that shale gas has a larger greenhousegas footprint than either coal or oil, particularly for time scales of a few decadesfollowing emission].

Hughes, D. 2011. Will Natural Gas Fuel America in the 21st Century? (Post CarbonInstitute 2011). http://www.postcarbon.org/report/331901-will-natural-gas-fuel-america-in [this report by a 32-year veteran scientist from the Canadian Geological Survey buildson the Howarth et al. 2011 paper, taking a more detailed look at the use of shale gas togenerate electricity; the report confirms the findings of Howarth et al. that shale gas hasa larger footprint than coal even when used to generate electricity, over time scales of 50years or less following emission].

Environmental Risk

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4

United Nations Environment Program and the World Meteorological Organization 2011.Integrated assessment on black carbon and tropospheric ozone: Summary for decisionmakers. [this report from the United Nations stresses the need to work immediately tocontrol the release of short-lived greenhouse gases, and concludes that controllingmethane emissions is probably the most important step that can be taken globally thatwill show immediate consequences in reducing global warming trends].

Wigley, T. 2011. Coal to gas: The influence of methane leakage. Climatic ChangeLetters, doi: 10.1007/s10584-011-0217-3 [this paper takes a detailed look at the conceptof using shale gas to replace coal for electricity generation, and concludes that in factshale gas development will aggravate global warming over time scales of severaldecades, not mitigate global warming as asserted by industry and presented in draft thesGEIS].

Thank you to the Committee for our interest and for the opportunity to present a writtenstatement.

Environmental Risk

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COMMENTCORRESPONDENCE Pros and cons

of 24/7 working stir up debate p.280

CULTURE Martin Kemp muses on 15 years of artists in lab schemes p.278

MUSIC In conversation with climate-change composer Paul D. Miller p.279

HISTORY Copernicus biography from Dava Sobel mixes fact and fiction p.276

Natural gas from shale is widely promoted as clean compared with oil and coal, a ‘win–win’ fuel that can lessen emissions while still supplying abundant fossil energy over coming dec-

ades until a switch to renewable energy sources is made. But shale gas isn’t clean, and shouldn’t be used as a bridge fuel.

Shale rock formations can contain vast amounts of natural gas (which is mostly methane). Until quite recently, most of

After a career in geological research on one of the world’s larg-est gas supplies, I am a born-again ‘cornucopian’. I believe that there is enough domestic gas to meet our needs for the foresee-

able future thanks to technological advances in hydraulic fracturing. According to IHS, a business-information company in Douglas County, Colorado, the estimated recoverable gas from US shale source rocks using fracking is about 42 trillion cubic metres, almost

Should fracking stop?Extracting gas from shale increases the availability of this

resource, but the health and environmental risks may be too high.

POINTYes, it’s too high riskNatural gas extracted from shale comes at too great a cost to the environment, say Robert W. Howarth and Anthony Ingraffea.

COUNTERPOINTNo, it’s too valuableFracking is crucial to global economic stability; the economic benefits outweigh the environmental risks, says Terry Engelder.

PAGE 272 PAGE 274

A drilling operation in Bradford County, Pennsylvania: one of the many places where shale rocks are fractured to release oil and gas.

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These are submissions from faculty that, while they do not directly comment on the SGEIS, are relevant to the topics discussed in it.

59


this gas was not eco-nomically obtainable, because shale is far less permeable than the rock formations exploited for conventional gas. Over the past decade or so, two new technologies have combined to allow extraction of shale gas: ‘high-volume, slick-water hydraulic fracturing’ (also known as ‘fracking’), in which high-pressure water with additives is used to increase fissures in the rock; and precision drilling of wells that can follow the contour of a shale layer closely for 3 kilometres or more at depths of more than 2 kilometres (see ‘Fracking for fuel’). Industry first experimented with these two technologies in Texas about 15 years ago. Significant shale-gas production in other states, including Arkansas, Pennsylvania and Louisiana, began only in 2007–09. Outside North America, only a handful of shale-gas wells have been drilled.

Industry sources claim that they have used fracking to produce more than 1 million oil and natural gas wells since the late 1940s. However, less than 2% of the well fractures since the 1940s have used the high-volume technology necessary to get gas from shale, almost all of these in the past ten years. This approach is far bigger and riskier than the conventional fracking of earlier years. An average of 20 mil-lion litres of water are forced under pressure into each well, combined with large volumes of sand or other materials to help keep the fissures open, and 200,000 litres of acids, biocides, scale inhibitors, friction reducers and surfactants. The fracking of a conventional well uses at

most 1–2% of the volume of water used to extract shale gas1. Many of the fracking additives are toxic, carcinogenic or mutagenic.

Many are kept secret. In the United States, such secrecy has been abetted by the 2005 ‘Halliburton loophole’ (named after an energy company headquartered in Houston, Texas), which exempts fracking from many of the nation’s major federal environmental-protection laws, including the Safe Drinking Water Act. In a 2-hectare site, up to 16 wells can be drilled, cumulatively servicing an area of up to 1.5 square kilometres, and using 300 million litres or more of water and additives. Around one-fifth of the fracking fluid flows back up the well to the surface in the first two weeks, with more continuing to flow out over the lifetime of the well. Fracking also extracts natural salts, heavy metals, hydrocarbons and radioactive materials from the shale, posing risks to ecosystems and public health when these return to the surface. This flowback is collected in open pits or large tanks until treated, recycled or disposed of.

Because shale-gas development is so new, scientific information on the environmental costs is scarce. Only this year have studies begun to appear in peer-reviewed journals, and these give reason for pause. We call for a moratorium on shale-gas development to allow for better study of the cumulative risks to water quality, air quality and global climate. Only with such comprehensive knowledge can appropriate regulatory frameworks be developed.

We have analysed the well-to-consumer life cycle greenhouse-gas footprint of shale gas when used for heat genera-tion (its main use), compared with conventional gas and other fossil fuels — the first estimate in the peer-reviewed literature2. Methane is a major component of this footprint, and we esti-mate that 3.6–7.9% of the lifetime production of a shale gas well (compared with 1.7–6% for conventional gas wells) is vented or leaked to the atmosphere from the well head, pipelines and storage facilities. In addition, carbon dioxide is released both directly through the burning of the gas for heat, and to a lesser extent indirectly through the process of developing the resource.

Methane is a potent greenhouse gas, so even small emissions matter. Over a 20-year time period, the greenhouse-gas footprint of shale gas is worse than that for coal or oil (see ‘A daunting climate footprint’). The influence of methane is lessened over longer time scales, because methane does not stay in the atmos-phere as long as carbon dioxide. Still, over 100 years, the footprint of shale gas remains com-parable to that of oil or coal.

When used to produce electricity rather than heat, the greater efficiency of gas plants compared with coal plants slightly lessens the footprint of shale gas3. Even then, the total green-house-gas footprint from shale gas exceed those of coal at timescales of less than about 50 years.

Methane venting and leakage can be decreased by upgrading old pipelines and stor-age systems, and by applying better technology for capturing gas in the 2-week flowback period after fracking. But current economic incentives are not sufficient to drive such improvements; stringent regulation will be required. In July, the US Environmental Protection Agency released a draft rule that would push industry to reduce at least some methane emissions, in part focus-ing on post-fracking flowback. Nonetheless, our analysis2 indicates that the greenhouse-gas footprint of shale gas is likely to remain large.

Another peer-reviewed study looked at

POINT: FRACKING: TOO HIGH RISK

FRACKING FOR FUELHydraulic fracturing is used to access oil and gas resources that are locked in non-porous rocks.

Well

Fissures

Watertable

Shale

Leakage of fracking �uids from the pipe has not been seen.

Possible �ow of methane.

High-pressure fracking �uid opens networks of fractures in the shale. Sand props the fractures open.

Holes in the well casing allow �uid to exit and gas to enter.

Leakage of fracking �uid from the fracture zone is highly unlikely.

Water recovery tanksPolluted �owback water may be injected into a deep storage well, recycled or sent to a treatment plant.

Steel pipe

Poorly treated �owback water has leaked into drinking water.

Methane gas escapes during the

mining process.

Blowouts are possible.

High-pressure fracturing �uid

Gas �ows from the fractures into the pipe.

Cement casing

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private water wells near fracking sites4. It found that about 75% of wells sampled within 1 kilometre of gas drilling in the Marcellus shale in Pennsylvania were contaminated with methane from the deep shale formations. Isotopic fingerprinting of the methane indi-cated that deep shale was the source of contamination, rather than biologically derived methane, which was present at much lower con-centrations in water wells at greater distances from gas wells. The study found no fracking fluids in any of the drinking-water wells examined. This is good news, because these fluids contain hazardous materials, and methane itself is not toxic. However, methane poses a high risk of explosion at the levels found, and it suggests a potential for other gaseous substances in the shale to migrate with the methane and contaminate water wells over time.

Have fracking-return fluids contaminated drinking water? Yes, although the evidence is not as strong as for methane contamination, and none of the data has yet appeared in the peer-reviewed litera-ture (although a series of articles in The New York Times documents the problem, for example go.nature.com/58hxot and go.nature.com/58koj3). Contamination can happen through blowouts, surface spills from storage facilities, or improper disposal of fracking fluids. In Texas, flowback fluids are disposed of through deep injection into abandoned gas or oil wells. But such wells are not available every-where. In New York and Pennsylvania, some of the waste is treated in municipal sewage plants that weren’t designed to handle these toxic and radioactive wastes. Subsequently, there has been contamination of tributaries of the Ohio River with barium, strontium and bro-mides from municipal wastewater treatment plants receiving frack-ing wastes5. This contamination apparently led to the formation of dangerous brominated hydrocarbons in municipal drinking-water supplies that relied on these surface waters, owing to interaction of the contaminants with organic matter during the chlorination process.

Shale-gas development — which uses huge diesel pumps to inject the water — also creates local air pollution, often at dangerous lev-els. Volatile hydrocarbons such as benzene (which occurs naturally in shale, and is a commonly used fracking additive) are one major concern. The state of Texas reports benzene concentrations in air in the Barnett shale area that sometimes exceed acute toxicity standards6, and although the concentra-tions observed in the Marcellus shale area in Pennsylvania are lower7 (with only 2,349 wells drilled at the time these air contami-nants were reported, out of an expected total of 100,000), they are high enough to pose a risk of cancer from chronic exposure8. Emis-sions from drills, compressors, trucks and other machinery can lead to very high levels of ground-level ozone, as documented in parts of Colorado that had not experienced severe air pollution before shale-gas development9.

UNPROFITABLE PROGRESSThe argument for continuing shale-gas exploitation often hinges on the presumed gigantic size of the resource. But this may be exagger-ated. The Energy Information Administration of the US Department of Energy estimates that 45% of US gas supply will come from shale gas by 2035 (with the vast majority of this replacing conventional gas, which has a lower greenhouse-gas footprint). Other gas industry observers are even more bullish. However, David Hughes, a geoscien-tist with more than 30 years experience with the Canadian Geological Survey, concludes in his report for the Post Carbon Institute, a non-profit group headquartered in Santa Rosa, California, that forecasts are likely to be overstated, perhaps greatly so3. Last month, the US Geological Survey released a new estimate of the amount of gas in the Marcellus shale formation (the largest shale-gas formation in the United States), concluding that the Department of Energy has over-estimated the resource by some five-fold10.

Shale gas may not be profitable at current prices, in part because

production rates for shale-gas wells decline far more quickly than for conventional wells. Although very large resources undoubtedly exist in shale reservoirs, an unprecedented rate of well drilling and fracking would be required to meet the Department of Energy’s projections, which might not be economic3. If so, the recent enthusiasm over shale gas could soon collapse, like the dot-com bubble.

Meanwhile, shale gas competes for investment with green energy technologies, slowing their development and distracting politicians and the public from developing a long-term sustainable energy policy.

With time, perhaps engineers can develop more appropriate ways to handle fracking-fluid return wastes, and perhaps the technology can be made more sustainable and less polluting in other ways. Mean-while, the gas should remain safely in the shale, while society uses energy more efficiently and develops renewable energy sources more aggressively. ■

Robert W. Howarth is in the Department of Ecology and Evolutionary Biology, Cornell University, Ithaca, New York, New York 14853, USA. Anthony Ingraffea is in the School of Civil and Environmental Engineering at Cornell University, Ithaca, New York, New York 14853, USA.e-mail: [email protected]

1. New York State Department of Environmental Conservation Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program (Sept. 2011); available at: http://go.nature.com/yzponk

2. Howarth, R. W., Santoro, R. & Ingraffea, A. Clim. Change 106, 679–690 (2011).3. Hughes, D. Will Natural Gas Fuel America in the 21st Century? (Post Carbon

Institute, 2011); available at: http://go.nature.com/gkboqm4. Osborn, S. G., Vengosh, A., Warner, N. R. & Jackson, R. B. Proc. Natl Acad. Sci. USA

108, 8172–8176 (2011).5. Volz, C. D. et al. Contaminant Characterization of Effluent from Pennsylvania Brine

Treatment Inc., Josephine Facility Being Released into Blacklick Creek, Indiana County, Pennsylvania (2011); available at: http://go.nature.com/5otd59

6. Texas Commission on Environmental Quality. Barnett Shale Formation Area Monitoring Projects (2010); available at: http://go.nature.com/v7k4re

7. Pennsylvania Department of Environmental Protection. Northeastern Pennsylvania Marcellus Shale Short-Term Ambient Air Sampling Report (2011); available at: http://go.nature.com/tjscnt

8. Talbott, E. O. et al. Environ. Res. 111, 597–602 (2011).9. Colorado Department of Public Health and Environment. Public Health

Implications of Ambient Air Exposures as Measured in Rural and Urban Oil & Gas Development Areas — an Analysis of 2008 Air Sampling Data (2010); available at: http://go.nature.com/5tttna

10. Coleman, J. L. et al. Assessment of Undiscovered Oil and Gas Resources of the Devonian Marcellus Shale of the Appalachian Basin Province, 2011. US Geological Survey Fact Sheet 2011–3092 (2011); available at http://go.nature.com/8kejhm

“Have fracking-return fluids contaminated drinking water? Yes.”

A DAUNTING CLIMATE FOOTPRINTOver 20 years, shale gas is likely to have a greater greenhouse e�ect than conventional gas or other fossil fuels.

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61

General Thoughts and CommentsWater

September 15, 2011

The Honorable Andrew M. CuomoGovernor of New York StateNYS State Capitol BuildingAlbany, NY 12224

Dear Governor Cuomo:

We the undersigned scientists write to you regarding the ability of municipal drinking water filtration systems to adequately remove contaminants of the sort found in return fluids from hydraulic fracturing, should they somehow enter the water system. The State has proposed that hydraulic fracturing not be allowed in the watersheds of the New York City and Syracuse water systems (where no filtration occurs), but be allowed in watersheds where drinking water is filtered before use. The presumption appears to be that municipal water filtration plants provide protection from potential contaminants. The best available scientific information does not support this presumption.

Most municipal water filtration systems are designed to remove potentially dangerous microorganisms from water, which they do efficiently. The typical filtration system would also remove some hazardous substances. However, there simply is not an adequate knowledge base to conclude that filtering would remove all, or even most, of the hazardous substances found in flow-back fluids from hydraulic fracturing. Potential contaminants of concern known to be in some flow-back fluids include benzene and other volatile aromatic hydrocarbons, surfactants and organic biocides, barium and other toxic metals, and soluble radioactive compounds containing thorium, radium, and uranium. Municipal filtration systems were not designed with such hazards in mind, and the ability of the filtration systems to remove such hazardous substances has received little, if any, study. We believe, however, the best available science suggests that some of these substances would pass through the typical municipal filtration system.

We urge the State to reconsider its position that existing water filtration systems provide adequate protection against the risk of hydraulic fracturing, should materials from flow-back fluids migrate to lakes, reservoirs, or groundwaters used for municipal water supplies.

Each signatory of this letter has significant professional experience with water treatment systems, with aquatic chemistry or biogeochemistry, and/or with the movement and fate of toxic or radioactive materials. We write as individuals and our professional affiliations are listed for your information. You should not infer any endorsement of our viewpoint by our affiliated institutions.

Sincerely,

Robert Howarth, Ph.D. the David R. Atkinson Professor of Ecology at Cornell University Founding Editor, Biogeochemistry Member of the Board of Directors, PSE

And 58 other scientists, listed alphabetically below.

Beth Ahner, Ph.D., Professor of Biological and Environmental Engineering, Cornell University

Aria Amirbahman, Ph.D., P.E., Professor of Civil and Environmental Engineering, University of Maine

Mary A. Arthur, Ph.D., Professor of Forest Ecology, University of Kentucky

Jill S. Baron, Ph.D., Ecosystem Ecologist, U.S. Geological Survey, and Senior Research Ecologist, Natural Resource

Ecology Laboratory, Colorado State University

Gilles Billen, Ph.D., Professor of Biogeochemistry, Institute of Pierre and Marie Curie, University of Paris VI

1