L.W. Allstadt Comments on New York State Department of Environmental Conservation

Revised Proposed Express Terms Parts 52, 190, 550-556, 560, and 570, Regarding High Volume Hydraulic Fracturing

The manner and timing with which the revised regulations were released for comment causes the entire process to be fatally flawed for the following reasons:

The findings of the final SGEIS should have been made available before or simultaneously with the revised regulations, with sufficient time for the public and the industry to read and understand the final SGEIS plus sufficient time to comment on the revised regulations.

Even if the public and the industry had the benefit of a final SGEIS, thirty days during a period with two major holidays is simply insufficient time to comment properly on regulations that are based on several years’ worth of submissions and draft documents.

Without the findings contained in the final SGEIS, neither the public nor the industry has any way of knowing what the New York State Department of Environmental Conservation (the Department) has covered in the SGEIS; what additions, deletions or changes will be made from the revised draft SGEIS (rdSGEIS); or what specific areas of the final SGEIS the Department intends to include in permitting conditions. This makes intelligent commenting on the revised regulations virtually impossible. Comments must be based on guesses about findings that may or may not be contained in the final SGEIS.

Without having the findings of the final SGEIS, it is impossible for the public and the industry to put forth reasons for some items being codified in the regulations and not left for permit conditions.

The draft SGEIS of 2009 and the revised draft SGEIS of 2011 had the same topic mentioned in more than one place sometimes with different wording. No one knows whether the final SGEIS will have similar areas of ambiguity. Without a final SGEIS, the public and the industry have no basis to propose clarifying some of those topics in the regulations.

Without a final SGEIS, the public and the industry have no way to determine whether there are any gaps between the 1992 GEIS and the final SGEIS and therefore no basis to comment about how such gaps might be addressed in the revised regulations.

By receiving comments on the revised regulations before the final SGEIS is published, the Department has given itself the opportunity to review public comments on the revised regulations, accept those that it wishes to accept, and “adjust” the final SGEIS to support those changes in the revised regulations that the department wishes to accept. Any procedure that does not protect against such manipulation is fatally flawed.

For the foregoing reasons, the revised regulations should be withdrawn and reissued for comments after a final SGEIS has been published.

Notwithstanding the foregoing reservations, I offer the following comments on specific portions of the revised regulations. I also point out omissions from the revised regulations. Each comment should be considered as a separate individual comment, as if it had been

submitted in a separate letter. The acceptance or rejection of any individual comment should not in any way affect the consideration given to any other comment. Specific recommendations are included as boldface bullets.

Comments on qualifications of owner/operators and contractors - Part 551.1(a)(1) through (7)

Each person who is a principal or acts as an agent for another in any of the following activities within the State must file an organizational report on a form the department prescribes:

(1) solution mining;(2) drilling, deepening, plugging back or converting oil, gas, solution mining or storage

well or wells, or drilling, deepening, plugging back or converting stratigraphic, geothermal or disposal well or wells greater than a true vertical depth of 500 feet;

(3) the production in the State of oil and gas;(4) the first purchase of oil and gas produced in the State;(5) the underground storage in the State of gas;(6) the practice of well abandonment and salvage of oil and gas subsurface equipment;

or(7) the first transportation of oil and gas produced in the State.

That information is gathered on form 85-15-12 (6/07)-28b which requires little more than the name, address and phone number of the entity and agent, as well as names and titles of director and officers and names of persons authorized to sign submittals to the Department.

There is no requirement for such information from persons engaged in hydraulic fracturing activities.

There is no place in the revised regulations or the proposed permitting conditions of the rdSGEIS of 2011 where information is gathered on the qualifications or experience of persons or entities engaged in any of these activities.

There is no place in the revised regulations or the proposed permitting conditions of the rdSGEIS of 2011 where information is gathered by the Department on the safety record of persons or entities engaged in any of these activities.

The Department should include drilling and hydraulic fracturing in the activities on which data is collected.

The Department should expand the information collected so as to assure that persons or entities conducting these activities in New York State have adequate prior experience.

The Department should require sufficient information on previous safety-related incidents to assure that persons or entities conducting these activities in New York State have not been cited for safety violations.

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Comments regarding the pace of HVHF development – Not Addressed in The Revised Regulations

The revised draft SGEIS of 2011 (the latest version available at the time of these comments) states, “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 communities. Where appropriate the Department would impose specific construction windows within well construction 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 2011Section 7.8, Pages 7-120/121)

This is a critical part in avoiding some of the most egregious environmental and socioeconomic impacts of drilling and related activities. Without ensuring that such activities are not unduly concentrated simultaneously in a specific geographic area, communities in New York State could be overwhelmed by a sudden influx of drilling and related projects such as pipelines and processing plants. There is nothing in the revised regulations that addresses the Department’s role in the “pace and concentration of development”, or that would provide the Department with the information necessary to implement this much-needed protection.

The Department’s permitting procedure requires an application for one well at a time. There is no process established in the revised regulations; in the Proposed Environmental Assessment Form Addendum I Appendix 6 of the 2011 rdSGEIS; or in the Proposed Supplementary Permit Conditions for High-Volume Hydraulic Fracturing in Appendix 10 of the rdSGEIS of 2011, whereby the department can obtain the information necessary to assure that cumulative adverse environmental and socioeconomic effects are not unduly concentrated in a specific geographic area within a short period of time.

There is nothing in the revised regulations or the rdSGEIS to require owner/operators to provide any information on what other wells and or infrastructure are contemplated in the same time frame as the individual well that is the subject of a permit application. Furthermore, there is no procedure for the Department to gather information from other owner/operators who might be planning wells in the same area at the same time as a well that is the subject of a permit application, nor is there is any procedure to gather information on infrastructure, including pipelines, processing plants and compression stations, that might be planned in the same time period.

The Department needs to build into its permitting process the gathering of enough information to assure that the objectives of section 7.8 of the rdSGEIS are met. This should include clear requirements in the regulations and in the Proposed Environmental Assessment Form Addendum that owner/operators must provide:

o A listing for the following two years of all its planned wells within 25 miles of the permit application well;

o A listing of all access roads, water impoundments, gathering systems, pipelines, treatment plants, compression stations, laydown yards, man camps, etc. that are planned (whether to be owned and/or operated by the owner/operator of the

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well or by others) in association with the planned wells. This should include copies of any application or submission to the Public Service Commission with regard to such infrastructure.

o A listing of any facilities that the owner/operator plans to own, operate or use in conjunction with other owner/operators within 25 miles of the permit application well.

The Department should develop a procedure to assure that all owners/operators who plan to operate in the same or overlapping geographic areas provide the Department with enough information about the timing and extent of their forward plans to enable the Department to implement the intent of Section 7.8 of the rdSGEIS.

The Department should also develop procedures for rejecting or requiring modification of plans to ensure that drilling activity and its cumulative adverse socioeconomic effects are not unduly concentrated in a specific geographic area.

Comments regarding setbacks from dwellings, water wells or springs for residential or livestock use, and places of assembly- Part 560.4(a)(1) and (2) and Part 560.4(c)

The revised regulations specify a setback distance of 500 feet from inhabited dwellings. Numerous localities in other states require greater setbacks, and some setbacks have been increased since oil and gas drilling using high volume hydraulic fracturing in shale began. The following are a few examples taken from readily available public information.

Places ofHouses Assembly Others

Flower Mound, TX 1500’ 1500’ 750’ from property lineMidland, TX 1320’ 1320’Southlake, TX 1000’ 1000’ 1000’ from property lineColleyville, TX 1000’ 1000’Lewisville, TX 800’ 800’Santa Fe County, NM 750’ 750’ 600’ from property lineRio Arriba County, NM 650’ 1000’

Common sense alone says that 500 feet from an inhabited dwelling to a well pad is totally inadequate. The revised draft SGEIS of 2011 describes in detail many of the industrial activities that occur at a well pad, including the large numbers of trucks required for each well; the noise and light pollution; the handling of many chemical additives; and the use of high pressure equipment. All or portions of these activities may continue for long periods of time. The Department’s attempts to mitigate these and other dangers may not be successful in all cases.

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Substantial setback distances are required to assure the health and safety of those who must live near a well pad. The people of New York State deserve as much protection as people who live in other states.

The Department should significantly increase the setbacks of well pads from inhabited dwellings to at least 1,000 feet. 1,500 feet would be better.

The revised regulations also specify a setback distance of “500 feet from a residential water well, a domestic supply spring or water well or a water well or spring used as a water supply for livestock or crops”. Such water supplies in proximity to a well pad are subject to the impact of all of the industrial activities that occur at a well pad, including the large numbers of trucks required for each well, the handling of many chemical additives, and emissions of volatile hydrocarbons and other gasses. Again, all or some of these activities may continue for long periods of time. Consequently, substantial setback distances are critical, both for persons living in a dwelling served by a domestic water supply and for the protection of the ultimate consumers of meat or produce from the area served by a well or spring used as a water supply for livestock and crops.

The Department should increase the setbacks of well pads from a residential water well, domestic supply spring or water well, or spring used as a water supply for livestock or crops to at least 1,000 feet. 1,500 feet would be better.

The variances in Part 560.4(c) would apply to setback distances from domestic water supplies and water supplies for livestock and crops; and to setback distances from inhabited dwellings (or places of assembly, which I intend to cover in a separate comment letter). It is critical that safe distances be maintained between these places and all activities associated with site preparation through partial reclamation after drilling. The Department, in the revised regulations, proposes to allow the landowner of such places (with the consent of all tenants in a dwelling) to agree to a waiver reducing the setback distances. The landowner’s consent to a waiver is likely to be obtained through monetary inducements from the well owner/operator.

For an occupied dwelling and its domestic water supplies, a waiver of the setback distance could subject persons who are not owners or tenants, including other family members, long-term guests, minor children, or persons who are not competent to make decisions in such matters, to increased risks through exposure to drilling-related activities.

The Department should specify that waivers of setback distances for dwellings that will remain inhabited will be allowed only if all inhabitants, whether or not they are owners or tenants, are competent and of legal age and agree to the waiver in writing.

For of domestic water supplies to dwellings that will remain inhabited, the Department should specify that waivers of setback distances will be allowed only if all inhabitants are competent and of legal age and agree to the waiver in writing.

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For water supplies for livestock and crops, there is no way for the ultimate consumer of meat, dairy products or produce from the livestock or crops to deny consent to a waiver of the setback distance which would expose the food they consume to the impacts of drilling related activities.

The Department should remove from the revised regulations the provision for waivers of setbacks from water wells or springs used as a water supply for livestock or crops.

In the case of places of assembly, most occupants, visitors and users are not the landowner. They may be patients in hospitals; occupants of nursing homes; children in school or on playgrounds and sports fields; families using parks; visitors to libraries; parishioners in churches; workers in factories, offices, public buildings and stores; customers in stores or at farmer’s markets; visitors to public buildings; or people in many similar places.

The Department should clarify that “places of assembly” includes all locations, whether privately or publicly owned, whether indoors or outdoors, at which people assemble for any reason.

The revised regulations specify a setback distance of 500 feet from a place of assembly. As shown above, readily available public information indicates that localities in other states require greater setbacks, and some have been increased since fracturing in shale began. Given the industrial nature of drilling operations and the lack of choice that many people have in places of public assembly, 500 feet from a place of assembly to a gas well pad is totally inadequate. The people of New York State deserve as much protection as people who live in other states.

The Department should increase the setbacks of well pads from places of public assembly to at least 1,000 feet. 1,500 feet would be better.

In Part 560.4(c), the Department proposes to allow the landowner of places of assembly to agree to a waiver reducing the setback distance. The landowner’s consent to a waiver is likely to be obtained through monetary inducements from the owner/operator of a proposed oil or gas well. In many cases the occupants or visitors to places of assembly (a few of which are noted above) have little or no choice about the location or time of their presence. Under the proposed regulations, none of the people who use the many different types of places of assembly, except for the landowner, would have an opportunity to deny consent to the additional exposure to drilling and hydro-fracturing-related activities to which a waiver of the setback distance might subject them.

The Department should remove from the revised regulations the provision for waivers of setbacks of well pads from places of assembly.

Comments regarding setbacks from floodplains - Part 560.4(a)(4) and Part 750-3.3(a)(3)

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Part 560.4(a)(4) and Part 750-3.3(a)(3) of the draft regulations prohibits the location of a well pad within a 100-year floodplain. This provision is inadequate for several reasons. The 100-year flood standard has been breached three times in upstate New York over the last five years, indicating that currently designated floodplain maps are sorely out of date. This clear trend toward more flooding and extreme flooding events in watersheds of the Delaware River and Susquehanna River poses an enormous risk if drilling is allowed. Without accurate floodplain maps, the DEC could permit drilling in areas that are now effectively floodplains, based on the 2006, 2010, and 2011 events. The DEC even notes in the 2011 rdSGEIS that the 100-year floodplain maps need to be updated. By failing to require that this happen before drilling is authorized, the DEC is consciously condoning the use of bad data and thus putting people, the environment, land, and livelihood in serious jeopardy. (More accurate maps have been prepared for Broome County, but this has not yet occurred in other potential drilling areas.)

The 2011 rdSGEIS (Section 6.2) acknowledges that flooding is one of the ways in which uncontrolled release of drilling brine and flowback fluids can occur. In addition, any chemicals or fuels that are stored on a well pad or elsewhere on a well site could potentially be released into the environment if flooding takes place. Although well pads are prohibited in the 100-year floodplain, the draft regulations fail to address other gas development activities or infrastructure that may be present at the well site or within the spacing unit, such as storage of HVHF materials, equipment, tanks, trucks, vehicle parking areas, and pipelines. These industrial features could negatively impact floodplains; and if flooding occurs, infrastructure, storage tanks, and equipment could be damaged, resulting in leaks or contamination.

DEC should make it a priority to update floodplain maps wherever drilling may be authorized. Where updated floodplain maps are not available, drilling should not be permitted.

Where updated floodplain maps are available, the draft regulations should require that either the 500-year floodplain be used, or a permanent safety buffer of at least 500 feet be established around updated 100-year floodplains to provide greater assurance that floodwaters will not come into contact with fracturing material.

The draft regulations should be revised to explicitly prohibit tanks, chemicals, material storage, pipelines, access roads, parking or other ancillary gas development activities in floodplains, whether such features are located on the well pads or elsewhere at a well site or within a spacing unit.

Comments regarding wetlands and setbacks from wetlands – inadequately and inconsistently addressed in revised regulations

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The draft regulations fail to provide a consistent, rational standard for protecting wetlands from the adverse impacts of fracturing. In Parts 560.4(a) and 750-3.3(a), the draft regulations require that well pads maintain specific distances from water-dependent features including aquifers, lakes, rivers, springs, and floodplains. However no explicit setback has been required in these two sections for wetlands—also a water dependent feature. Elsewhere, in Part 750-3.11(d) the draft regulations state that HVHF operations cannot be authorized within 300 feet of a wetland operating under a HVHF General Permit, but could potentially be permitted under an individual SPDES permit. (Note, however, that this differs from the DEC proposed regulation titled “SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing,” which appears to allow well pads to be located as close as 100 feet from a wetland (table within Part I.D.4, page 8) and implies that well pads could perhaps even be permitted inside of this with a separate SPDES permit. Additionally, the same document seems to suggest that runoff from well pads could be allowed to discharge into wetlands.) In its prior comments to DEC on the proposed regulations, the U.S. Fish and Wildlife Service requested a minimum 300-foot buffer for wetlands to protect water quality and aquatic systems, consistent with 2011 Delaware River Basin Commission (DRBC) recommendations for HVHF. Creating procedural loopholes to allow the circumvention of this will undermine critical environmental protections.

It should also be noted that the distances above are strangely inconsistent with Part 560.6(b)(1)(ii) of the proposed draft regulations which state: "For any well, fueling tanks must not be placed within 500 feet of a perennial or intermittent stream, storm drain, regulated wetland, lake or pond." (Emphasis added) Comparing these scattered sets of requirements, it appears that DEC could potentially allow a well pad to be located next to a wetland or maybe even inside a wetland (since doing so is not strictly prohibited), thereby creating a situation where fracturing fluid, flowback, or production brine could readily contaminate that wetland. However fueling tanks for fracturing the very same well would be required to maintain a safer distance of 500 ft. There is no rationale for this. As written, the revised regulations provide no clear, predictable protection of wetlands.

Wetlands are characterized by vegetation that grows in a moist environment, and are typically subject to inundation by water on an ongoing or intermittent basis. Regardless of the source of water, wetlands—like floodplains— can provide a path for contaminants to enter the environment. Moreover, because wetlands serve as important habitat and feeding areas for wildlife, they are particularly sensitive features in the natural landscape. Maintaining an undisturbed area around wetlands is also beneficial for natural communities and wildlife prevalent within wetland/upland ecotones (transitional areas). Wetland delineations do not always coincide with or fall within designated floodplains, and thus are not necessarily protected by floodplain boundaries. Because wetlands are fragile biological features, a separate setback requirement is needed.

In addition to potential contamination from toxic chemicals contained in fracturing fluid, flowback and production brine released following the fracturing process can alter the salinity

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of freshwater systems, resulting in negative impacts to wetlands and wetland-dependent species. Wetlands should receive no less protection from gas drilling activities than other water-dependent features. In many respects, they should receive more.

Section 560.4(a) and Section 750-3.3(a) of the draft regulations should be modified to enumerate a setback of at least 500 feet from wetlands. Alternatively, the draft regulations should require a strict setback of 300 feet, consistent with U.S. Fish and Wildlife Service and DRBC recommendations. Exemptions should not be permitted. (With this change, the reference to wetlands in Part 750-11(d) can be eliminated or revised so that alternate individual SPDES review would be applicable only for well pads proposed between 500 feet and 300 feet from a wetland.)

Due to the chemicals present in fracturing fluid and salinity of flowback, the draft regulations should be revised to prohibit the discharge of runoff from a well pad or any other HVHF activity into wetlands.

Part 560.6(b)(1)(ii) of the draft regulations should be revised to prohibit the location of fueling tanks, equipment, and any other infrastructure or gas development activities within 500 feet of wetlands.

Since many state wetland maps are inaccurate or may not show smaller isolated wetlands, the draft regulations should be revised to require delineation of all wetlands, regardless of size, for all well site and related infrastructure plans. The regulations should require avoidance of all wetlands, including those below the 12.4-acre regulatory threshold.

The DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing" should be revised consistent with the above. (Until this happens, including a wetland setback in Parts 560.4(a) and 750-3.3(a) ought to ensure implementation as controlling provisions over SPDES permitting.)

Comments regarding setbacks from drinking water supplies - Parts 560.4(a)(5), 750-3.3(a)(4), and 750-3.3(a)(5)

The setback requirements contained in Part 560.4(a)(5), Part 750-3.3(a)(4), and Part 750-3.3(a)(5) of the draft regulations are inadequate, lacking rational justification based on either watershed hydrology or a coherent understanding of drinking water treatment methods.

Part 560.4(a)(5) and Part 750.3-3(a)(4) contain similar, but not identical, requirements for a 2000ft setback from reservoirs, natural lakes, or man-made impoundments that serve as drinking water supply sources. (Part 750.3-3(a)(4) includes public supply wells and springs.) The setback distance is less than half of the more stringent requirement of 4000 feet that

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applies beyond the New York City and Syracuse watersheds. According to DEC in the 2011 revised draft SGEIS, this is because public water supplies outside of New York City and Syracuse are "filtered"—meaning that they have not been granted Filtration Avoidance Determination exemptions granted pursuant to EPA's 1998 Interim Enhanced Surface Water Treatment (IESWT) rule. However, this reason ignores a basic fact regarding filtering systems presently in place, which is that none of the filtering systems used by municipalities in New York State are designed to remove the chemicals in fracturing fluid or drilling waste. As noted in the rdSGEIS, filtering out dissolved chemicals from the fracturing and drilling process is virtually impossible, or prohibitively expensive. The claim that public water supplies outside of New York City and Syracuse are "filtered" is therefore irrelevant.

Furthermore, the 4000 feet setback protection granted to New York City and Syracuse apply to the entire watersheds of these two cities—meaning not only to specific water bodies like lakes or reservoirs that serve as storage, but also to all tributaries and surfaces that eventually drain to those supplies. By comparison, outside of these two watersheds, Part 750-3.3(a)(5) prohibits well pads within 2000 feet of a water supply intake or within 1000 feet of a tributary for a distance of one mile upstream. Based on outdated and inadequate provisions of Part 553.2, just beyond this one mile distance, the DEC would require no more than 50 feet of separation between a well and the same waterway. In crafting such a policy, the DEC appears to imply that any pollutants from a well-site contaminating a tributary would naturally remove themselves from the water column during their one mile journey downstream. This is very different from the approach used by DEC in granting whole watershed protection to New York City. Similarly, no rational explanation has been given for the weaker separation of 1000 feet between a well pad and directly connected tributary, compared to the aforementioned 2000 feet or 4000 feet distances. The arbitrary nature of these various thresholds appears to suggest that DEC believes the physical properties of water, fracturing chemicals, and their solubility are different upstate and downstate. It should be noted that the provisions of Part 750-3.3(a)(5) also differ from the DEC proposed regulation titled “SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing,” which specifies a 500 feet setback to tributaries of surface public water drinking supplies without a one-mile limitation (table within Part I.D.4, page 8). Furthermore, since all of the aforementioned provisions apply only to "HVHF wells", DEC could permit a well using 299,999 gallons of fracturing fluid directly next to a municipal drinking water supply, limited only by the 50ft minimum requirement provided by Part 553.2 of the current regulation.

The revised regulations in Part 560.4(a) and Part 750-3.3(a) only define distances with respect to the well pad. The draft regulations fail to address other gas development activities or infrastructure that may be present at the well site or within the spacing unit, such as storage of HVHF materials, equipment, tanks, trucks, vehicle parking areas, and pipelines. Because these industrial features are also potential sources of leaks or contamination, they should also be prohibited within appropriately defined setbacks.

Because existing municipal filtration systems are unable to remove chemicals present in fracturing fluids and flowback, all public water supplies should receive

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the same level of protection as the New York City and Syracuse watersheds. Part 560.4(a) and Part 750-3.3(a) should be revised to require a 4000 feet setback from all public drinking water supplies and their tributaries.

The draft regulations should be revised to expand the applicability of Parts 560.4(a) and 750-3.3(a) to include tanks, chemicals, material storage, pipelines, access roads, parking or other ancillary gas development activities within the setback established for public drinking water supplies, whether such features are located on the well pads or elsewhere at a well site or within a spacing unit.

The DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing" should be revised consistent with the above.

Comments regarding freshwater (other than drinking water) setbacks - Parts 560.4(a) and 750-3.3(a)

Parts 560.4(a) and 750-3.3(a) of the draft regulations for high-volume horizontal fracturing establish minimum setbacks only for surface waters that are public drinking water supplies. Freshwater lakes, ponds, or streams, or natural springs that are not presently part of a public drinking water supply are afforded no minimum standard of protection. By potentially allowing a well pad to be located next to a lake, river, or natural springs, the DEC jeopardizes flora and fauna endemic to freshwater systems, as well as recreational sites that attract tourists. By allowing impacts that could contaminate freshwater, the Department may be permanently sacrificing sources of clean water necessary to sustain growing populations, agriculture, and business.

Part 750-3.11(d) states that HVHF operations cannot be authorized within 300 feet of a perennial or intermittent stream, storm drain, lake, or pond under a HVHF General Permit, but allows for an exception to this through an individual SPDES permit. (Note, however, that this differs from the DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing," which appears to allow a well pad to be located as close as 150 feet from a perennial or intermittent stream, storm drain, lake, or pond (table within Part I.D.4, page 8) and implies that well pads could perhaps even be permitted inside of this with a separate SPDES permit.) In its prior comments to the Department on the proposed regulations, the U.S. Fish and Wildlife Service requested a minimum 300-foot buffer to aquatic systems including lakes, ponds and streams, consistent with the 2011 Delaware River Basin Commission (DRBC) recommendations for HVHF.

Based on older existing regulations, the only other regulatory provision that appears to apply is in Part 553.2, which states that no "well" shall be located "nearer than 50 feet from any public stream, river, or body of water." This, too, is ambiguous, since the provision applies only to a well (not the well pad) and seems to depend on the meaning of the word "public". Such a

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setback is woefully inadequate for any type of gas well. These distances are also inconsistent with Part 560.6(b)(1)(ii) of the proposed draft regulations which state: "For any well, fueling tanks must not be placed within 500 feet of a perennial or intermittent stream, storm drain, regulated wetland, lake or pond." A comparison of the DEC's scattered set of rules and procedures leads to the conclusion that a permit could be issued for a gas well next to a stream where the accidental release of fracturing fluid, flowback, or production brine could contaminate freshwater systems, while fueling tanks would be required to remain a much safer distance of 500 feet away. This makes no sense.

Part 560.4(a) and Part 750-3.3(a) of the draft regulations should be modified to specify a setback of 500 feet from freshwater systems, including but not limited to lakes, ponds, streams, and springs that do not contribute to a surface drinking water supply. Alternatively, the draft regulations should require a strict setback of 300 feet, consistent with U.S. Fish and Wildlife Service and DRBC recommendations. Exemptions to this rule should not be permitted. (With this change, Part 750-3.11(d) can be revised so that alternate individual SPDES review would be applicable only for wells proposed between 500 feet and 300 feet from freshwater systems, or for lesser water setbacks from man-made features such as storm drains.)

Part 560.6(b)(1)(ii) of the draft regulations should be revised to prohibit the location of fueling tanks, equipment, and any other infrastructure or gas development activities within 500 feet of freshwater systems, including but not limited to lakes, ponds, streams, and springs that do not contribute to a surface drinking water supply.

The draft regulations should be revised to prohibit the discharge of runoff from a well pad or any other HVHF activity into freshwater systems, including but not limited to lakes, ponds, streams, and springs.

The DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing" should be revised consistent with the above.

Comment regarding setbacks from seismic faults – Not addressed in revised regulations

The draft regulations ignore the potential for natural faults existing in gas-bearing formations to act as conduits for the migration of fracturing fluids and methane to drinking water aquifers,

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the surface, and the atmosphere. This deficiency is reflected in the 2011 revised draft SGEIS, which included a 1977 map (figure 4.13) depicting only limited geological faulting through the likely Marcellus and Utica shale drilling areas. Later maps by other authors (e.g., R. G. Jacobi, 2002) show many more faults throughout New York State. Although the 2011 revised draft SGEIS appeared to acknowledge the potential for abandoned gas wells to transmit methane and chemicals, geological faults can provide even larger channels to the surface. This issue needs to be addressed.

At a minimum, regulations should require that the applicant demonstrate that no faults exist beneath the proposed spacing unit or up to one-half mile outside of the spacing unit. If such a fault is determined to exist the applicant should be required to maintain a distance between the wellbore and the fault of least one-half mile.

The 2011 revised draft SGEIS downplays the potential for induced seismic activity by citing historic data for when there was no high-volume horizontal hydraulic fracturing in the state. Recent reports of earthquakes in Oklahoma, Ohio, and the United Kingdom, have been linked directly to hydraulic fracturing activity, both in location and time. The DEC needs to investigate these incidents and determine the probability of similar occurrences in New York if high-volume hydraulic fracturing were to proceed.

Until such an investigation is conducted and additional regulatory measures are enacted to avoid induced seismic activity, high-volume hydraulic fracturing should not be permitted.

Comments regarding setbacks from primary and principal aquifers – Part 560.4(a)(2) and Part 750-3.3(a)(1) and (2)

The revised regulations create an illogical and arbitrary distinction between primary and principal aquifers. A definition is provided for a primary aquifer in Part 560.2(b)(20): “ ‘primary aquifer’ shall mean a highly productive aquifer presently being utilized as a source of water supply by a major municipal supply system.” A similar definition for a principal aquifer is provided in Part 560.2(b)(21): “ ‘principal aquifer’ shall mean an aquifer known to be highly productive or whose geology suggests abundant potential water supply, but which is not intensively used as a source of water supply by a major municipal system at the present time.”

The only real distinction between primary and principal aquifers as defined in the regulations is whether they presently supply a ‘major municipal water system,’ for which no definition is provided in the regulations or in the rdSGEIS of 2011, nor in the Department of Health regulation’s Public Water System Definitions provided in Table 2.4 of the rdSGEIS of 2011. However, section 2.4.4.1 of the rdSGEIS clearly states that the Department of Health identified the primary aquifers in 1981. “In order to enhance regulatory protection in areas where ground water resources are most productive and most vulnerable, the NYSDOH, in 1981, identified 18 Primary Water Supply Aquifers (also referred to simply as Primary Aquifers) across the State.” (Emphasis added.) That was more than thirty years ago, long before the

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advent of High Volume Hydraulic Fracturing, so that the potential vulnerability of the aquifers to contamination from HVHF activities could not possibly have been considered.

A comparison of the map of Primary Aquifers and the map of Primary and Principal Aquifers on the DEC web site shows both types of aquifers in and around population centers of similar sizes, ranging from hamlets to cities, throughout the potential gas drilling areas identified by the Department. The Department has presented no evidence that the 1981 identifications of primary and principal aquifers have been updated to consider the vulnerability of aquifers to HVHF activities, which was part of the stated original purpose of making a distinction. The department has failed to consider the total numbers of people who use water supplies throughout much of the potential drilling area on a temporary basis, as summer and weekend residents or as tourists. The department has failed to provide any justification for providing weaker protections to people whose water supplies come from one aquifer versus those whose water supplies come from another.

The revised regulations, in Part 560.4(a)(3) provides that “No well pad or portion of a well pad may be located within a primary aquifer and a 500 feet buffer from the boundary of a primary aquifer. This Part of the revised regulations provides no such protection for principal aquifers. Part 750-3.3(a)(2) states that well pads for HVHF operations are prohibited, and no SPEDES permit will be issued authorizing any such activity or discharge “within 500 feet of, and including, a primary aquifer” However, this section of the revised regulations makes no similar provision for a principal aquifer.

The only partial protection of principal aquifers appears in Part 750-3.11(d) “HVHF operations within certain distances of specific surface or ground waters may be ineligible for coverage under an HVHF general permit and would require authorization under an individual SPEDES permit. At a minimum, HVHF operations sited within the following buffers cannot be authorized by an HVHF GP (calculated from the closest edge of the well pad): Principal Aquifer 500 feet”. Thus the department may permit well pads within 500 feet of principal aquifers under Individual SPEDES permits, but could not permit well pads within the same distance from primary aquifers.

A study by researchers from Duke University (Methane Contamination of Drinking Water Accompanying Gas-Well Drilling and Hydraulic Fracturing, Osborne et al. 2011) showed methane migration to water wells that were located 3000 feet from active producing gas wells. The methane has to reach aquifers before it can reach water wells. Thus, this study is also relevant to primary and principal aquifers. The rdSGEIS (7.1.11.1) attempted to discredit this study by pointing to a single gas well in Otsego County where there were no unusual levels of methane detected in nearby water wells. However, the well in question, Ross 1 in the Town of Maryland, was permitted for 80,000 gallons of fracturing (below the Department’s cutoff for HVHF), was never connected to a gathering system, was never an active producing well and has been plugged and abandoned (DEC’s on-line well data). That gas well never should have been included in the data. The rest of the study data using active producing wells in other states showed a very high probability of migration of methane from gas wells to water wells up to 3000 feet away. The DEC should reevaluate that study, eliminating the erroneous data point. Even if that erroneous data point is not eliminated, when the average of all wells in the study is considered, the probability of methane migration from gas wells to water wells is very high.

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The data currently available indicates that a setback of 3000 feet would reduce but not eliminate the danger of methane migration.

Protection for both principal and primary aquifers should be the same, and Parts 560.4(a)(3) and 750-3.3(a)(2) should be revised to include principal aquifers. With those changes, the reference to principal aquifers in Part 750-11(d) can be eliminated.

The 500-foot setback of well pads from primary and principal aquifers is insufficient and should be increased significantly. Until better information is available on methane migration a precautionary setbacks of 3000 feet should be established.

Comments regarding depth of wells - Part 750-3.5(c)(1)

Industry statements lead the public to believe that fracturing will occur many thousands of feet deep, so that the fluids cannot reach drinking water aquifers. To date most industry experience with horizontal high-volume hydraulic fracturing in tight shales is with relatively deep wells, about 5000 to 14000 feet deep. These wells are in fact many thousands of feet (4000 to 13,000 feet) below drinking water aquifers, so most experience in other parts of the United States is with a very large separation between the depth of the fracturing zone and the depth of drinking water aquifers. However, the Marcellus and Utica shales are at much shallower depths in many parts of New York State.

Furthermore, the revised regulations would allow fracturing at very shallow depths. Part 750-3.5(c)(1) states “the top of the target fracture zone at any point along any part of the proposed length of the wellbore, for HVHF must be deeper than 2,000 feet below the surface and must be deeper than 1,000 feet below the base of a known fresh water supply;” This is far shallower than most oil and gas wells in other parts of the United States have been drilled to date. At the shallow depths that high volume hydraulic fracturing would be allowed in New York State, the buffer of several thousand feet between fresh water supplies and fracturing simply would not exist as it does in other parts of the country.

The DEC must consider the potential impacts of hydraulic fracturing over short, medium and long time horizons. There is evidence that even if there are no immediate negative impacts, both fluids and methane gas could reach aquifers within a few years.

A study performed by ICF International for NYSERDA (Agreement No. 9679) states, “The literature review performed as part of the present study did not identify any published case histories or studies that included direct observation of the migration of frac fluids in hydraulically fractured shale.

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“Studies of fracturing fluid migration in geological materials other than shale have shown some potential for migration beyond the propped portions of the induced fractures. In 2004, EPA summarized data on over two dozen mined-through studies in coalbed methane formations published between 1987 and 1993. In these studies, subsequent mining of sub surface coal seams allowed direct measurement of previous hydraulic fractures. Because shale does not have the economic value of coal and because shale formations are generally at much greater depths than coalbed methane deposits, there are no mined-through studies in shale.

“The coalbed studies indicated that fracturing fluids follow the natural fractures and can migrate into overlying formations. EPA also reported that in half the cases studied, fracturing fluids migrated farther than and in more complex patterns than predicted. In several of the coalbed studies, the frac fluids penetrated hundreds of feet beyond the propped fractures either along unpropped portions of the induced fractures or along natural fracture within the coal.” (Emphasis added). Note, the foregoing was included in Appendix 11 of the July 2011 revised draft SGEIS, but this section was expunged from the September 2011 revised draft SGEIS.

From these EPA studies, we have direct evidence that at shallow depths material other than shale fracturing fluids migrated further and in more complex patterns than expected, sometimes hundreds of feet beyond the areas where the proppant was deposited along fractures caused by the process or along natural fractures.

We do not have similar information on shale. Thus, we really do not know what depths are safe. Contamination of drinking water aquifers can be irreversible. A cautious approach is needed. The DEC should establish safer vertical distances. A minimum of 4000 feet below the deepest drinking water aquifers and the top of the target formation, or 5000 feet below the surface, would be similar to the de facto buffer that exists in other parts of the United States, simply because of the depth of the shale in those other locations.

The DEC should require a minimum of 4000 feet between any fracturing zone and the deepest drinking water aquifer, or 5000 feet below the surface, whichever is greater. Alternatively, a site-specific SEQRA review should be required for wells less than 5000 feet below the surface, but under no circumstances should the fracturing zone depth be less than 3000 feet below the deepest drinking water aquifer or less than 4000 feet below the surface.

Furthermore, the revised regulations as proposed do not apply to wells using less than 300,000 gallons of fracturing water. Those wells would be regulated under the outdated 1992 GEIS and associated regulations, which does not specify a minimum depth requirement.

The minimum depth requirement should apply to all oil and gas wells— regardless of the volume of fracturing fluid used.

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Comments regarding financial security for wells over 6000 feet total measured depth - Part 551.6

The Department has correctly required, in the first sentence of Part 551.6, that “The owner of an oil, gas or solution mining, storage stratigraphic, geothermal or disposal well that exceeds or is expected to exceed 6,000 feet in true measured depth must file financial security for that well in an amount based on the anticipated costs of plugging and abandoning that well to the satisfaction of the department in accordance with Part 555 of this Title.” It is very clear in this sentence that the amount of security must cover the cost for that specific well. This sentence meets the stated purpose of the regulation as per the last sentence on page 9 of the Revised Regulatory Impact Statement, which states: “The Department proposes to remove the cap to require operators to post financial security in an amount that reflects the true costs of plugging a deep well. Although this change will increase costs to the regulated community, it is necessary to have adequate financial security in place to advance the public policy goals of ensuring that wells are properly plugged and abandoned to prevent such wells from becoming a pathway to contamination.” (Emphasis added) This intent is commendable.

However, the very next sentence in Part 551.6 opens up the possibility that the Department might limit the total amount of financial security that an owner might be required to establish to less than the sum of the financial security that would be required for all of an owner’s wells: “However, the owner is not required to file financial security under this section exceeding an amount specified by the department, regardless of the number of wells described in this section that an owner may have.” Any limit on the total amount of financial security below the amount that would be required to properly plug and abandon every single well that an operator is permitted to drill, flies in the face of the stated intent of Part 551.6. If the full total cost of plugging and abandoning all of an operator’s wells is not covered by financial security, the taxpayers of New York State face the uncovered cost or the very risk of contamination that Part 551.6 is intended to avoid.

The second sentence of Part 551.6 should be deleted or modified to make clear that the total of an owner’s financial security must equal the sum of the individual financial security requirements for all of that owner’s wells.

In addition, the Department should adjust financial security requirements annually to account for any anticipated increase in the cost of plugging wells. This adjustment is needed to protect the taxpayers and residents of New York from the expense of plugging cost escalation over the period from when the well is drilled until it is plugged.

Comments regarding financial security for wells up to 6000 feet total measured depth - Part 551.5

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The provisions Part 555.5(a)(1 through 5) with regard to the method of plugging of wells apply to all wells covered by Parts 550 through 556 and 560 without regard to the depth of the well.

In the first sentence of the revised Part 551.6 the Department has required, “The owner of an oil, gas or solution mining, storage stratigraphic, geothermal or disposal well that exceeds or is expected to exceed 6,000 feet in true measured depth must file financial security for that well in an amount based on the anticipated costs of plugging and abandoning that well to the satisfaction of the department in accordance with Part 555 of this Title.”

This requirement of Part 551.6 assures that the Department can require financial security sufficient to cover the cost of plugging the well. However, Part 551.5 “Amount of financial security: wells up to 6,000 feet deep”, requires fixed amounts per well with no relationship to the anticipated cost of plugging the well.

“Part 551.5 Amount of financial security: wells up to 6,000 feet deep(a) Except for gas wells drilled into lands under the waters of Lake Erie, for wells less than 6,000 feet in depth for which the department issued or is processing for issuance on or after October 1, 1963, permits to drill those wells or issued on or after June 5, 1973 acknowledgments of the notices of intention to drill those wells, the amount of financial security required is:(1) for wells less than 2,500 feet in depth:(i) for 1 to 25 wells, $2,500 per well, not exceeding $25,000;(ii) for 26 to 50 wells, $25,000, plus $2,500 per well in excess of 25 wells, not exceeding $40,000; (iii) for 51 to 100 wells, $40,000, plus $2,500 per well in excess of 50 wells, not exceeding $70,000; or(iv) for over 100 wells, $70,000, plus $2,500 per well in excess of 100 wells, not exceeding $100,000.(2) for wells between 2,500 feet and 6,000 feet in depth:(i) for 1 to 25 wells, $5,000 per well, not exceeding $40,000;(ii) for 26 to 50 wells, $40,000, plus $5,000 per well in excess of 25 wells, not exceeding $60,000;(iii) for 51 to 100 wells, $60,000, plus $5,000 per well in excess of 50 wells, not exceeding $100,000; or(iv) for over 100 wells, $100,000, plus $5,000 per well in excess of 100 wells, not exceeding $150,000.(b) If an owner has a well or wells that are less than 2,500 feet in depth and has another well or other wells that are between 2,500 feet and 6,000 feet in depth, instead of providing financial security under the provisions of each paragraph in subdivision (a) of this section, that owner may file financial security as if all of those wells were between 2,500 feet and 6,000 feet in depth.”

These amounts per well are insufficient to cover the likely costs of plugging individual wells as required by Part 555.5(a)(1) through (5). Even if the amount per well were sufficient, Part 551.5 places a total dollar limit on the amount of financial security that an owner would have to provide. This essentially provides owners with a volume discount on the amount of security,

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such that the total amount of security may be significantly less than the actual total cost of plugging all of the wells. This system sets up a financial incentive in some cases for an owner of a group of wells to give up his financial security and walk away without plugging his wells. Such a weak system of financial security exposes the taxpayers and residents of New York State to the expense of plugging wells—an expense that is rightfully the responsibility of the owner—or to the risk of unplugged wells.

Part 551.5 should be rewritten to provide that financial security for all wells up to 6,000 feet True Measured Depth must have financial security sufficient to cover the anticipated cost of plugging each and every well. Alternatively, Parts 551.5 and 551.6 could be combined to require that wells of any depth have financial security in place to cover the anticipated cost of plugging each well, with no limit on the total amount of security.

In addition, the Department should adjust financial security requirements annually to account for any anticipated increase in the cost of plugging wells. (This adjustment is needed to protect the taxpayers of New York from the expense of plugging cost escalation over the period from when the well is drilled until it is plugged . )

Comments regarding plugging wells - Part 555.5(a)(1) - (5)

Plugging oil or gas wells generally receives little attention, because it comes at the end of the productive life of the wells. Without strict regulations and very careful inspections plugging can be done in a slipshod manner that provides little real long-term protection.

Part 555.5(a)(1) through (5) provides what appear to be several improvements in plugging procedures. However, the Department has provided no discussion of the changes in plugging procedures in the 2011 revised draft SGEIS to indicate what alternative plugging procedures were investigated, why this particular set of procedures was chosen, or how effective these procedures might be over the many centuries or millennia that they must protect the aquifers, air and people of New York State. It is impossible to comment fully on this Part of the regulations without that information. Nevertheless, I provide the following comments:

No minimum quality is specified for cement used in plugging. There is no assurance that the cement will not contain materials that would be unsafe if the cement were to come into contact with fresh water aquifers. Also, the regulations contain no assurance that cement quality requirements will be revised to reflect any improvements that might be developed.

The regulations should specify a minimum quality of cement that does not contain materials that would be unsafe if contacted by fresh water.

The regulations should also specify that cement quality will be revised as necessary to reflect the best and safest technology available.

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Part 555.5(a)(5) states “Unless otherwise specified in this Part, the interval between all plugs mentioned in paragraphs (1) through (4) of this subdivision shall be filled with gelled fluid with a minimum density of 8.65 pounds per gallon with a 10 minute gel-shear strength of 15.3 to 23.5 pounds per hundred square feet or other department-approved fluid.” This language gives no assurance that the materials used in the gelled fluid will be safe if they come into contact with drinking water aquifers. It also gives no assurance that any “other department-approved fluid” will have at least the density and gel-shear strength specified.

The regulations should specify that all materials used in the gel fluid must be safe for contact with drinking water aquifers.

The regulations should also specify that any other department-approved fluid must have no less density and gel-shear strength.

Because of the long-term safety implications for many generations to come, it is critically important that plugging be done correctly. Without proper plugging, the migration of fluids or methane gas into drinking water aquifers and/or the surface is virtually assured at some point in time. Even with the best procedures, many wells that have been plugged do leak.

No plugging should take place unless a representative of the DEC, qualified to assure correct procedures, is onsite for the entire process.

The DEC should establish a schedule of periodic inspections of all plugged wells to monitor the integrity of the plugs and to assure that remedial action is taken if migration of fluids or methane gas to aquifers or the surface is identified.

Plugged wells must remain safe forever. The owner/operator should not be able to reap the financial benefits of drilling and leave the people of New York State with the cost of cleaning up problems when abandoned wells eventually leak.

The financial security that is required to assure plugging of wells should remain in effect in perpetuity. Alternatively, a plugging repair fund paid for by the owner/operator should be established to defray the cost of repairing plugged and abandoned wells whenever repairs are required.

Comments regarding security for matters other than well plugging – Not addressed in the revised regulations

The revised regulations require that financial security be established to assure that funds are available to cover costs associated with plugging wells. However, there is nothing in the revised regulations or the Proposed Permit Conditions of the rdSGEIS of 2011 which requires owners/operators to establish liability insurance or a security reserve to cover damages that

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may occur to others as a result of activities under a well permit. There have been numerous reports of such damages in other states.

The Department should require owners/operators to provide financial security to cover damages to the State and to individuals by the same methods provided for well plugging financial security in Part 551.4 or by requiring that a certificate of insurance be kept continuously in force. The total amount of liability security or insurance for each owner/operator should be equal to the largest amount of damages that have been incurred from accidents or negligence for any onshore well in the United States.

Comments regarding unplugged abandoned wells - Section 552.1(b) and Section 556.2(b)(8)

It has been estimated that there are tens of thousands of old, unplugged, abandoned oil or gas wells in New York State. Each of these poses a threat of serving as a conduit for the transmission of methane, fracturing fluid and chemicals to the aquifer or surface if fracturing occurs nearby. This was recently documented to have occurred in Tioga County, Pennsylvania where hydraulic fracturing led to the eruption of gas and water from an abandoned well drilled in 1932. (http://stateimpact.npr.org/pennsylvania/2012/10/09/perilous-pathways-how-drilling-near-an-abandoned-well-produced-a-methane-geyser/) The 2011 revised draft SGEIS (appendix 11) also acknowledges that communication between fracturing and old unplugged wells can occur, stating, "an undetected and unplugged wellbore could exist that directly connects the hydraulic fracture zone to an aquifer."

Part 552.1(b) and Part 556.2(b)(8) of the draft regulations requires identification of old abandoned wells within the spacing unit or within one mile of a well to be fractured. However, nowhere in the draft regulations does there appear to be any requirement that old wells be plugged before fracturing commences. This is omission needs to be corrected.

The draft regulations should specifically require that all unplugged wells located within the proposed spacing unit, or within one mile of the surface location of the well to be hydraulically fractured, are properly plugged and abandoned before high-volume hydraulic fracturing is permitted on a new well.

Comments with regard to process wastes from oil and gas development - Inadequately addressed in revised regulations

Overall, the proposed regulations regarding process wastes from oil and gas production in New York are riddled with deficiencies, which include lack of harmonization among sections overseen by different Divisions of the Department of Environmental Conservation, lack of

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comprehension of the similarity of conventional and HVHF oil and gas productions technologies (except for scale), lack of rigor in defining the responsibilities of industry operators, and lack of appreciation for how problematic the disposal of oil and gas process wastes is likely to become.

Part 364.1 (e): Waste Transporter Permits: Exceptions

Paragraph (1) of this section states: “Rail, water and air carriers are exempt from the requirements of this Part.”

This paragraph should be repealed with respect to oil and gas development wastes, particularly for rail and water transport.

Part 371.1 (e) (2): Identification and Listing of Hazardous Wastes: Exclusions

Exclusions from being listed as hazardous wastes include paragraph (v): “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy”, regardless of whether they contain substances which are defined as hazardous in 6 NYCRR Parts 371 and 597 – and many of them do.

This contradiction-introducing paragraph should be repealed.

Part 550.3: Definitions

“Subdivisions (a) through (g) of Section 550.3 are unchanged.”

This segment of unchanged language includes §550.3 (f), which states: “Brine is synonymous with salt water.” The related definition of salt water, formerly §550.3 (at) but now re-designated (av), states: “Salt water shall mean any water containing more than 250 parts per million of sodium chloride or 1,000 parts per million of total dissolved solids.” These two sentences constitute the only descriptions of flowback fluids, production brines, organic chemical condensates, or any other process wastes in the entire canon of definitions in Section 550.3. Indeed, “waste”, formerly listed as §550.3 (ax), but now designated (bb), is defined as follows:

”Waste shall mean:(1) physical waste, as that term is generally understood in the oil and gas industry;(2) the inefficient, excessive, or improper use of, or the unnecessary dissipation of reservoir

energy;(3) the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well or

wells in a manner which causes, or tends to cause, reduction in the quantity of oil or gas ultimately recoverable from a pool under prudent and proper operations, or which causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas;

(4) the inefficient storing of oil or gas;(5) the flaring of gas produced from an oil or condensate well after the department has

found that the utilization thereof, on terms that are just and reasonable is, or will be within a reasonable time, economically feasible.”

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This definition for “waste” clearly has no relationship to oil or gas industrial process wastes. And one does not need to be a chemist to understand that the two definitions that are given for brine and salt water do not begin to describe the materials that flow as by-products from oil and gas wells developed in New York or any other place. In fact, they are so simplistic as to be negligently misleading. Therefore, no working definitions for process wastes related to oil and gas production exist in this section of New York regulations . It is surprising that permits for petroleum extraction projects or the disposition of their process wastes could have been legally approved with such weak regulatory constructs in place.

Moreover, improved language to address these issues is sequestered in the new Part 560.2, paragraphs (2), (3), (6), (8), (12), (13), (22) and (23), where it has no practical effect on industrial activity not defined as “high volume”. Therefore, even though the Department acknowledges a need for regulation of chemicals disclosure and definition of process wastes, the changes proposed are worthless for conventional oil and gas projects targeting “tight” rock formations, which use chemicals indistinguishable from high-volume projects, except for the quantities consumed and disposed.

The Department should adopt regulations on chemical disclosure and the definition of process wastes that will apply to all wells, not just HVHF wells.

Part 554.1 (c): Prevention of pollution and migration

The new language of Paragraph (1) includes references to drilling mud, flowback water and production brine, which have no antecedents in Part 550.3: Definitions, as stated above.

The new language requires owners or operators to state that they will maximally reuse or recycle used drilling, flowback and production fluids, without any consideration that the means of recycling or reuse involve the applications of heat (for facilitated evaporation) and pressure (for reverse osmosis), which promote chemical reactions that, given the complex mixtures involved, have never been studied.

Revised regulatory language should require public reporting on the products resulting from the attempted reuse or recycling of waste fluids prior to acceptance of any disposal plan.

The new language also mentions the importance of noting the history of other drilling operations in the area, but makes no mention of an even more important factor: the regulatory compliance history of the applicant.

This paragraph should be revised to ensure that the compliance history of the applicant is evaluated for each owner/operator who submits an application.

Paragraph (4) of Part 554.1 opens the possibility of beneficial reuse of drill cuttings as solid wastes, as specified in 6 NYCRR Part 360-1.15: Beneficial Use Determinations. However, certain drill cuttings, including some of those from the Marcellus Shale formation, are too radioactive or otherwise environmentally toxic to be safely reused in any context.

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The reuse (road-spreading, asphalt manufacture, etc.) of oil and gas process wastes should be prohibited.

Part 560.2: Definitions

Conspicuously absent from the definitions in this section and from Part 550.3 are any references to by-products and wastes released primarily to the air, or the major pieces of equipment responsible for such releases, such as chemical processing facilities using glycol dehydrators, and compressor facilities.

At a minimum, the following terms should be defined in this section and in Part 550.3: diesel exhaust particulates, ozone, silica dust, and volatile organic compounds (VOC) including benzene, toluene, ethyl benzene, xylenes (BTEX), and polycyclic aromatic hydrocarbons (PAH).

Part 560.5 (f): Drilling and Production Waste Tracking Form

As mentioned above, the proposed regulations contain no mention of wastes released primarily to the air by oil and gas development projects. Since they can negatively impact the health of human beings and other organisms nearby, waste products released to the air must be monitored and reported.

The Drilling and Production Waste Tracking Form should be modified to include measurements of diesel exhaust particulates, ozone, silica dust, and volatile organic compounds which are released from each project site.

Measuring equipment should be required to be fixed in place and continuously operational at various points, so as to be capable of monitoring substance releases in varying wind conditions. This section should also require the reporting of any releases of aerosols or powders

Part 560.7: Waste Management and Reclamation

Paragraphs (a) and (b) prescribe the timely removal of fluids and other materials from pits. Overall, the use of pits for oil and gas production is very vaguely described and poorly organized. Whether and how they may be used for flowback fluids and production brines in projects requiring less than 300,000 gallons of completion fluids remains unclear, but it appears that they may be so used for such projects. Whether they could be used as contingency receivers in HVHF projects (as has happened in other states) is also unclear.

The use of open pits for oil and gas development in New York should be summarily prohibited—regardless of fracturing fluid volume.

Paragraphs (c), (d) and (e) prescribe conditions for on-site burial (encapsulation) of certain drill cuttings.

On-site burial of drill cuttings should be summarily prohibited. In the event that the Department disagrees with this assessment, the specific place where any

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cuttings are encapsulated underground should be mapped and marked for future reference.

Paragraph (i) prescribes the testing of flowback fluids and production brines for radioactivity.

This paragraph should be revised to include a standard or maximum contaminant level, and to clarify that landfills, treatment centers and the general public will have access to the test results.

Part 750-3.2 Definitions

The new definitions in this Division of Water section, especially (5), (7), (8), (14), (15), (18), (19), (20), (30), (31), (33), (38), (39), (40), (41), (42), (45), (51) and (52) should be harmonized with the Division of Solid Waste definitions section (Part 360-1.2), and the Division of Mineral Resources definitions sections (Part 550.3 and 560.2). (That this has not been done is emblematic of a larger problem: the lack of inter-divisional coherence, which currently exists in the New York Code of Rules and Regulations.)

Part 750-3.11: HVHF General Permit

Paragraph (c) clarifies that “An HVHF general permit does not authorize the discharge of hazardous substances (as listed in Part 597) or petroleum.”

Because of the heavy reliance of Part 597 on Part 371, it is critical for the contradictory language of Part 371.1 (e) (2) titled Exclusions to be repealed.

Part 750-3.12: Disposal of HVHF Wastewater

Paragraph (b) leaves open the possibility of beneficial use determinations (BUD) for flowback fluids by the Division of Solid Waste under Part 360-1.15. It is very difficult to assess and update the chemical composition of these fluids.

Beneficial Use Determinations for flowback fluids should not be allowed.

Paragraph (c) prescribes requirements for acceptance, treatment and disposal of HVHF wastewater at publically owned waste treatment works (POTW’s). These facilities are not designed to process industrial wastes, particularly those with such disparate components as radioisotopes, biocides, oil- and polymer-based lubricants, endocrine-disrupting compounds, resin-coated proppant materials and toxic heavy metals.

Flowback fluids and production brines from oil and gas projects should not be accepted at these POTWs. This paragraph should be replaced by a prohibition on this treatment option.

Paragraph (d) prescribes requirements for acceptance, treatment and disposal of HVHF wastewater at privately owned industrial treatment facilities. This is an appropriate destination of these wastes. However, they should be limited.

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A new provision should be added that aggregates the combined effluent limits for individual facilities within a watershed and sets limits for the combined effluents.

Paragraph (f) describes requirements for deep well injection of HVHF wastewater, which is primarily regulated by the Federal EPA’s Underground Injection Program. Sub-paragraph (5) provides that the Department “may propose additional monitoring, recording and reporting requirements in a State Pollution Discharge Elimination System (SPDES) permit”. A 5-year update cycle is imposed by the USEPA, within which changes or anomalies may not be reported.

The Department should replace the language of (f) (5) “may propose” to “shall propose,” and shorten the update period to 12 months or less.

Comments regarding chemicals and chemical disclosure – Part 560.3(d) and (h)

Section 560.3(d) “Hydraulic Fracturing Fluid Disclosure” and Section 560.3(h) “Hydraulic Fracturing Fluid Disclosure Following Well Completion” of the draft regulations fail to require full disclosure of all chemicals used in the fracturing process. As written, the draft regulations allow an applicant to withhold the identification of chemicals that are asserted to be "trade secrets". This provision, combined with exemptions regarding disclosure granted by the federal government, puts residents and visitors to New York State at risk of exposure to dangerous unknown chemicals. Furthermore, by failing to require the maintenance of a comprehensive registry of all chemicals used, the regulations as drafted prevent the legitimate access to information needed by medical professionals to treat patients who may become ill due to fracturing chemicals.

Although chemical additives represent only about one per cent of fracturing fluid (2011 rdSGEIS 5.4), the total volume of water predicted per fractured well is between 2.4 and 7.8 million gallons. At 1600 wells per year (2011 rdSGEIS chapter 2, page 2-1) this means that between 38 million and 125 million gallons of chemicals are likely to be used for fracturing annually in New York State. Several of these are known carcinogens, endocrine disruptors, or otherwise dangerous compounds. Since wastewater treatment facilities in New York State are not equipped to remove many of the chemicals that return to the surface as flowback, these chemicals will accumulate in the environment and over time pose an increasing threat to public health. Filtering systems used by public water supplies upstate are not capable of removing and disposing of these chemicals. For certain fracturing techniques to remain trade secrets may be appropriate; however under no circumstance should any individual chemical used in fracturing be protected from disclosure.

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The Department should establish a clear regulatory requirement that for every well, all chemicals used in the fracturing process--without exception—must be disclosed in a registry that is readily accessible to the public.

Despite growing evidence of harm, not a single carcinogen or toxic chemical has been deemed unsafe for fracturing in the draft regulations. Certain chemicals like benzene, which is dangerous at even very low concentrations and is not used by some operators, should be prohibited as a fracturing additive. In Texas communities where fracturing is occurring, scientific studies tracking the effects of chemicals like benzene have verified increases in local childhood leukemia rates, neural tube birth defects, and childhood asthma. BTEX compounds (benzene, toluene, ethyl benzene, and xylene) are known to be toxic to humans and animals and can contaminate both air and drinking water supplies. These serious health concerns, with significant morbidity and mortality consequences underscore the critical need for an independent Comprehensive Health Impact Study, which has not yet been conducted.

The draft regulations should be revised to prohibit the use of BTEX chemicals and other toxic additives in the fracturing process.

Comments regarding open pits - Part 560.6(c)(27)

The revised regulations do not prohibit open pits for flowback in all circumstances. Because HVHF has been improperly defined as operations using at least 300,000 gallons of water, the prohibition on open pits for flowback in Part 560.6(c)(27) does not apply for fracturing with 299,999 gallons or less. The 1992 GEIS and the current regulations make no mention of fracturing quantities greater than 300,000 gallons of fracturing water. No rationale was presented in the rdSGEIS for differentiating between wells using more or less than 300,000 gallons of fracturing water. No rationale was presented in the rdSGEIS indicating why it might be safe to allow open pits for wells using less than 300,000 gallons of fracturing water, while it would be unsafe to use open pits for wells using 300,000 gallons or more of fracturing water.

The use of open pits for any flowback should be prohibited for all oil and gas wells, regardless of the amount of fracturing water used.

All flowback should be captured and held in enclosed tanks until reprocessed or transferred to tank trucks for removal from the well site.

The revised regulations also fail to prohibit open pits for drilling fluids, drilling mud, and cuttings. As written, open pits are prohibited only for drilling fluid and cuttings associated with horizontal drilling in the Marcellus shale formation, but even this requirement can be waived if an "acid rock drainage mitigation plan" exists, in which case cuttings might even be left onsite (Section 560.6(c)(7)). According to Section 560.6(a)(4) of the draft regulations, open pits holding up to 250,000 or 500,000 gallons could actually be permitted, and requirements regarding their construction (thickness, etc.) would apply only to those used for

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multiple wells. In addition, although the rdSGEIS included a provision requiring open pits to have two feet of freeboard as a safety margin, that requirement does not appear in the revised regulations. As written, the revised regulations would allow open pits to be filled to the brim. This would virtually guarantee the overflow of contaminants from open pits if any subsequent rainfall occurs.

Regulations on open pits should apply to all HVHF activities (not limited to Marcellus shale).

With the exception of freshwater impoundments, and regardless of the gas-bearing formation, regulations should clearly prohibit the use of open pits for flowback fluids, drilling fluids, drilling mud, drill cuttings or any other material used before, during or after the drilling or fracturing of any well.

If the foregoing comment is not accepted, all pits should be constructed with adequate freeboard to assure that they cannot overflow in a worst-case storm scenario, and all pits (except for fresh water) should be located inside the boundaries of the well pad area.

Comments regarding fencing and security at well sites – Not addressed in revised regulations Well sites and well pads where high-volume hydraulic fracturing takes place are areas of intense industrial activity, involving the use of potentially dangerous machinery and toxic chemicals. These areas must remain secure during all stages of the drilling and fracturing process. The 2011 rdSGEIS discusses fencing to prevent livestock access, but only for "active pastures" located in designated Agricultural Districts and only for operations that disturb more than 2.5 acres. This provision fails to protect people, livestock outside of designated Agricultural Districts, and wildlife. Furthermore, the Department has contemplated fencing only as a possible permit condition, failing to include any requirement for it in the draft regulations.

To adequately protect people, wildlife, and livestock, the regulations should clearly require appropriate security measures and fencing, without exception, around all well pads or portions of the well site that contain drilling equipment, tanks, pits, chemicals, or garbage, regardless of the location or size of the disturbed area.

Comments regarding forest fragmentation – Not addressed in revised regulations

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Fragmentation caused by the widespread proliferation of fracturing is a major threat to forest ecosystems in New York State. The 2011 rdSGEIS (Section 6.4.1) acknowledges this, stating: " As forests are the most common cover type, it is reasonable to assume that development of the Marcellus Shale would have a substantial impact on forest habitats and species." However, despite this admission and a relatively good description in the rdSGEIS of how ecosystems could be impacted, the Department fails to discuss meaningful concrete action to avoid forest fragmentation. Instead of limiting fracturing in forests, the rdSGEIS proposes only to require that the applicant consider impacts in a very small percentage of New York forestland described as "forest focus areas.” This limitation is based on the Department’s misinterpretation of a study performed in 2003 by The Nature Conservancy involving the assessment of large forest matrix blocks. Comments submitted on the 2011 rdSGEIS by both The Nature Conservancy (TNC) and Environmental Defense Fund (EDF), make clear that limiting attention to these areas only is an invalid approach. According to the 2011 rdSGEIS, over half (57%) of the entire area overlain by the Marcellus shale is forested; however, only a very small fraction of this 57% is located within designated forest focus areas. (In fact, outside of the Catskill Park, only 6% of the area over the Marcellus shale is within a Forest Focus Area, according to the 2011 rdSGEIS.)

The failure of the regulations to fully address forest fragmentation has enormous adverse implications to forest ecology in New York State, since the Department’s approach neglects almost all of the Southern Tier's forested landscape. In a recent study of potential impacts from fracturing in Tioga County, The Nature Conservancy determined that disturbance of key forest areas would be extensive in a high development scenario. TNC recommended that the state make the reduction of well pad sitings in forestland a priority (“An Assessment of Potential Impacts of High Volume Hydraulic Fracturing on Forest Resources”, C. Lee, et al; Dec 19, 2011). The Department’s approach would protect none of Tioga County’s forests—which represent 61% of the county's land area.

The Department fails to identify any concrete requirements to avoid fragmentation. Rather than prohibiting fracturing in designated "focus areas,” the 2011 rdSGEIS states only that applicants should perform an ecological assessment, recommend their own "mitigation,” and monitor impacts. A recent publication titled "Hydraulic Fracturing Threats to Species with Restricted Geographic Ranges in the Eastern United States"(J. Gillen, E. Kiviat, Environmental Practices, Dec 2012), studied the potential impacts of fracturing on 15 species and concluded that a wide variety of species endemic to the Utica and Marcellus shale areas could be damaged by habitat loss, fragmentation, and increased soil salinity.

The Department’s approach neglects HVHF’s potential impact on most forests and lacks substantive requirements to avoid fragmentation and its effects. Moreover, the vague measures described by the DEC in the 2011 rdSGEIS are only suggested as potential "permit conditions,” none of which appear in the draft regulations, even by reference. If New York State

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is exposed to the scale of gas development that has begun in Pennsylvania, the Department’s regulatory program will be unable to ensure that large-scale collapse of forest ecosystems does not occur in the Southern Tier and other areas where HVHF could become widespread. Several measures should be taken by the DEC to address this issue:

The Department should identify forests of high quality or unique ecological value that should be off-limits to drilling. Forestland qualifying for this higher level of protection may include but should not be limited to the “forest focus areas” previously identified and lands ecologically linked to Catskill State Park.

Where drilling is allowed within forests, the Department should establish a managed phase-in and phase-out schedule of active production areas to control where and when gas development occurs.

The regulations should require that for any gas development that occurs within forests, well pads must be located as far apart as possible (preferably one mile apart).

Ancillary surface features of gas development (e.g., compressor stations and processing equipment) should be consolidated and located outside of forests to the greatest extent possible.

The regulations should require a mitigation plan for minimizing forest fragmentation and degradation of habitat, including attention to wildlife management, edge effects, noise, and light.

The regulations should require a restoration plan, bonded to ensure completion, for all areas impacted by gas development and related infrastructure (not just the well pad).

Comments regarding threatened and endangered species – Only partially addressed in revised regulations

Section 750-3.11(f)(3)) of the draft regulations states only that HVHF operations that adversely affect a listed or proposed to be listed endangered or threatened species or its critical habitat require an individual SPDES (State Pollutant Discharge Elimination System) permit.

“750-3.11 HVHF general permit(f) The following activities are ineligible for coverage under an HVHF general permit and would require authorization under an individual SPDES permit:

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…(3) HVHF operations that adversely affect a listed or proposed to be listed endangered or threatened species or its critical habitat;”

This provision does not ensure that threatened and endangered species will be protected. It states only that a different permit will be required.

The 2011 rdSGEIS, states, “Significant 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…”(Section 7.4.1) This statement concedes failure by the Department of Environmental Conservation to protect New York's unique natural resources. It is also an abandonment of DEC's obligation under federal and state law. DEC must exercise its authority to adopt and enforce meaningful regulations to ensure that the ecological integrity of New York State is protected and that listed species do not perish in the face of drilling and High Volume Hydraulic Fracturing.

The regulations should require as part of the application process, a site-specific field survey of natural communities, rare plants, and wildlife—including species listed as threatened, endangered, or of special concern.

Regulations should require an ecological report assessing impacts to natural communities and wildlife as part of the permit application process.

If the application is part of a larger project consisting of multiple wells and spacing units or if the proposed project abuts other approved or planned drilling units or infrastructure, the report should assess impact to natural communities and wildlife, including listed species, over the entire area.

Regulations should require that if listed species or protected natural communities are present, the applicant will seek a determination from the Department (or appropriate federal agency) as to whether or not the adverse impact is significant. If the impact can be avoided by modifying the location or configuration of development, then the applicant should be required to do so. Incidental take permits should be granted as a last resort only if mitigation is provided to compensate fully for impacts.

Comments regarding well pad spacing – Not addressed in revised regulations

The last version of the rdSGEIS suggests that surface impacts of HVHF development such as habitat loss, fragmentation, or interference with agriculture would be limited, because of spacing units anticipated to be 640 acres in size with wells drilled laterally beneath the ground from a single pad. These stated advantages, however, are negated if the size of a spacing unit is smaller, if wells are drilled from more than one pad, or if other activities and infrastructure are not concentrated at or near the well pad.

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In some drilling locations drilling gas reserves may exist in more than one formation, for example Marcellus Shale, various Sandstone/Limestone, and Utica Shale (sometimes referred to as a triple play). In such a situation, the way the spacing unit provisions of Part 553(a)(1) through (13) are written, it would be possible to have a 640 acre spacing unit with multiple wells drilled from a single well pad for the Marcellus Shale. Below that, within the same surface boundaries, could be four 160-acre spacing units, each with a pad for a single well, targeting a sand stone formation. And below that, again within the same surface boundaries, could be sixteen spacing units, each with a single well on sixteen well pads, targeting the Utica Shale. If all of these wells were issued permits, there could be a total of twenty-one (21) well pads within a surface area of 640 acres (one square mile). This would be completely contrary to the stated intention of the rdSGEIS to minimize surface impacts from drilling. The regulations make no provision for minimizing the number of well pads that could be constructed within a given surface area. Furthermore, Section 553(c) as revised would allow the DEC to approve any other size or wellbore distance from a unit boundary.

A further complication is that landowners do not have to lease all of the mineral rights below the surface of their land to a single owner/operator. Landowners may lease individual target zones, and they may lease different target zones to different owner/operators. It is therefore possible for more than one owner/operator to be working within the same surface area. Although it is common practice for owner/operators in such a situation to combine their activities to avoid duplication, nothing in the regulations assures that this will happen.

Horizontal drilling technology makes it possible to drill long distances horizontally from a single location, thus making any position within a 640-acre, or even larger, spacing unit accessible from a single well pad. In order to reduce surface impacts, the regulations should be significantly rewritten to minimize the number of well pads needed.

Spacing units should be redefined to maximize the surface area served by a single multi-well pad.

Spacing units of greater than 640–acres should be allowed, provided that only a single multi-well pad will serve the entire spacing unit

Wherever two or more spacing units of any size can be serviced by a single multi-well pad, those spacing units should be combined into a single spacing unit regardless of the target pool or pools.

Spacing units of 40 acres should not be routinely approved. Spacing units of 40 acres should be approved only if there is no other way to access a specific pool.

Once a spacing unit has been established, any future gas well in an underlying or overlying spacing unit should be drilled from the well pad serving the original spacing unit.

Wherever possible, owner/operators should be required to cooperate with owner/operators of potential neighboring spacing units to combine spacing units and operations such that a single multi-well pad can be used.

Changes proposed to Section 553.4(a) and new text in Section 553.4(b) eliminate the requirement to show "good and sufficient" reason for variances, shift the burden to outside

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parties to show that a variance should not be granted, and stifle public input. The requirement for “good and sufficient” reasons should be reinstated.

Reducing the number of well pads, minimizing surface disruption and/or increasing the distance of well pads from dwellings, places of assembly, drinking water supplies and sensitive areas should be encouraged and considered good and sufficient reasons for variances.

A formal hearing should continue to be required for all variances, and a public comment period of at least 60 days should be provided.

Comments regarding venting and flaring of gas - Parts 556.2(b), 556.2(c), and 556.2(g)(5)

The draft regulations fail to require minimizing the venting and flaring of gas well emissions. Methane is a greenhouse gas at least twenty-five times more potent than carbon dioxide in trapping heat. Data from the EPA indicates that natural gas production is now the largest source of methane pollution in the United States. Although flaring burns off methane and consumes hydrogen sulfide, doing so also generates large amounts of carbon dioxide and sulfur dioxide. Venting and flaring are major sources of air pollution and represent a known threat to human health, generating ground-level ozone that causes skin, eye, and nasal irritation or bleeding, and releasing chemicals like formaldehyde and benzene, which are human carcinogens.

Part 556.2(b) of the draft regulations allows gas from a well pad to escape into the air for at least 48 hours after drilling completion and possibly longer. This constitutes a tremendous amount of greenhouse gas, especially considering DEC estimates that 1,600 wells or more could be drilled per year in New York State. Parts 556.2(c) and 556.2(g)(5) also provide for the extension of flaring for an unspecified amount of time. The EPA and industry are both moving toward greater control of greenhouse gas emissions during the well completion process. The technology is available and is already being used by a number of companies. It should be required in New York State, if or whenever HVHF wells are allowed.

The regulations should be rewritten to require immediate compliance with the EPA's Green Completion Rules, including immediate compliance with those provisions of the Green Completion Rules that are not scheduled to go into effect until 2015.

Comments regarding protection of state lands – Not addressed in the revised regulations

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The draft regulations fail to protect state-owned land by permitting subsurface access for drilling and fracking beneath them. Well pads could be constructed immediately outside the boundary of a state park or historic area, completely encircling the park, drilling horizontally, and using HVHF under the park. This is very likely to occur, because drillers seeking to maximize subsurface access will wish to locate rigs as close to the boundary of state land as possible. Edge effects caused by the clearing of adjacent well sites would degrade the value of habitat for hundreds of feet inside state conservation land. Noise and light from industrial drilling activity would penetrate much deeper, disrupting ecosystem functions and wildlife behavior, including breeding, feeding, and denning, as well as interfering with people’ use and enjoyment of the parks

Many of the state parks in New York comprise relatively small patches of only a few hundred acres, so drilling activity next to these could completely devastate interior ecosystems. Fragmentation caused by the concentration of impacts along the perimeter of state land threatens to isolate otherwise protected core habitat from surrounding natural areas. The revised regulations do not require any property line setback. Therefore, state land would also be highly vulnerable to contamination from spills and air pollution.

The draft regulations do not prevent drilling beneath rivers, streams or ponds. Natural water bodies inside state land would be vulnerable to methane and chemical contamination from fracking below. For everyone who appreciates New York State lands, the adverse impacts would be profound. With the noise, odors, and gas flares of industrial activity nearby, possibly next to entrances, campgrounds, or picnic areas, families will no longer be able to relax and enjoy the outdoors. Hikers, hunters and bird watchers will no longer see the wildlife they appreciated in the past. Where fracking becomes widespread, impacts will be severe, and for smaller parks with greatest exposure, they will be catastrophic.

The revised regulations should be changed to avoid harm from fracking immediately next to and under state lands.

The regulations should require a minimum property line setback of at least 1000 feet between any well pad and state lands.

Section 52.3 and Section 190.8 of the draft regulations should be revised to prohibit any surface or subsurface disturbance to state lands from fracking. The horizontal drilling of gas wells beneath state lands should be prohibited.

The draft regulations do not clearly prohibit fracking within all state lands. As written, the term "state land" used in Section 52.3 applies only to property administered by the Division of Fish, Wildlife, and Mineral Resources. (This is based on the definition of "state land" contained in Section 52.1.) Similarly, text that has been added to Section 190.8 is limited in scope by subsection 190.0(a) to include only lands administered by the Division of Lands and Forest and Division of Operations. Nowhere in the draft regulations is there a clear prohibition against fracking—including the siting of gas wells or other surface impacts—on lands administered by the Office of Parks, Recreation, and Historic Preservation (OPRHP). The 178

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state parks and 38 historic preservation areas of New York State deserve the greatest degree of protection. Other lands under the auspices of OPRHP include lakes, golf courses, campsites, nature centers, and trails—all recreational amenities enjoyed by people throughout the state and the nation. Drilling and HVHF next to these places would permanently diminish or destroy their natural, scenic, historic, and recreational value. The fact that administrative authority over state parks is with OPRHP does not change the fact that regulatory authority for fracking still resides with the DEC.

The regulations should be revised to prohibit fracking on any state land, including State Forests, Wildlife Management Areas, and State Parks.

Comments with regard to wells using less than 300,000 gallons of fracturing water - Part 560.2(b)(14)

Part 560.2(b)(14) states, “(14), ‘high-volume hydraulic fracturing’ shall mean the stimulation of a well using 300,000 gallons or more of water as the base fluid in the hydraulic fracturing fluid per well completion. In determining whether the 300,000 gallon threshold has been met, the department will take into consideration the sum of all water-based fluids, including fresh water, and recycled flowback water used in all high-volume hydraulic fracturing stages.”

Under this definition the revised regulations would not apply to wells using less than 300,000 gallons of water as the base fracturing fluid. Such wells would fall under the 1992 GEIS and the regulations that were based on the 1992 GEIS.

The 2011 revised draft SGEIS (rdSGEIS) provides no rationale for defining wells using 300,000 gallons or more of fracturing water as “high–volume hydraulic fracturing” wells. The rdSGEIS offers no discussion whatsoever about why this would be an appropriate definition. The largest volume mentioned in the 1992 GEIS was 80,000 gallons. 300,000 gallons would be an almost fourfold increase, with no justification.

The 1992 GEIS was not written to cover this new type of drilling and fracturing. The practice of fracturing in tight shale formations was not yet in common use. The 1992 GEIS envisioned fracturing water volumes in the 20,000- to 80,000-gallon range. No plausible rationale exists for the DEC’s proposal to issue permits for wells using less than 300,000 gallons of fracturing water under the 1992 GEIS and regulations.

Fracturing in tight shale formations with less than 300,000 gallons of water is much more closely related to fracturing in tight shale formations using larger volumes of water than it is to

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fracturing in the more conventional formations that were the targets of drilling when the 1992 GEIS was completed and adopted.

Under the DEC’s proposal, wells using less than 300,000 gallons of fracturing water would not be required to use closed containers and secondary containment for fracturing additives, drilling fluids and other chemicals and fuels. Open pits and less safe casing would be permitted. Setbacks would be only 100 feet from dwellings, 150 feet from a public building or 50 feet from a public stream, river or other body of water. Less stringent emissions requirements would be allowed. All these and other unsafe procedures would apply to wells that are otherwise virtually identical to wells using more fracturing fluid. Furthermore, the application for wells under 300,000 gallons of fracturing water would include the woefully inadequate two-page form included as Appendix 5 Environmental Assessment Form (EAF) For Well Permitting in the 2011 rdSGEIS, in which the applicant checks a few boxes and provides little substantive information. Even the rdSGEIS—which is still inadequate—requires far more comprehensive information in regard to wells over 300,000 gallons (Appendix 6 PROPOSED Environmental Assessment Form Addendum).

Landowners and local governments would have no way of knowing whether drilling operations with less than 300,000 gallons of hydraulic fracturing water might be coming to their area, other than to constantly monitor permits issued by the DEC.

Any or all of the above-mentioned inconsistencies could result in adjacent wells being regulated under two significantly different protocols. This is absurd.

The final regulations should apply to all oil and gas wells, regardless of the volume of hydraulic fracturing fluid used.

Comments regarding local government—Not addressed in revised regulations

The 2011 rdSGEIS states "Local and regional planning documents are important in defining a community's character and are a principal way of managing change within a community. These plans are used to guide development and provide direction for land development regulations (e.g., zoning, noise control, and subdivision ordinances) and designation of special districts for economic development, historic preservation, and other reasons" (2011 rdSGEIS Section 7.12). In its discussion of how local government consent could be addressed, however, the 2011 rdSGEIS recommends a flawed certification process that fails to embrace these principles. The revised regulations are completely silent on the subject of local government authority.

The flawed process described by the DEC in the 2011 rdSGEIS would essentially allow drillers to self-certify whether or not a permit application is in conflict with local comprehensive plans or land use laws, thus placing a difficult, if not impossible, burden upon towns to track drilling

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applications submitted to the DEC and to verify that information contained in those applications is accurate. This process should be reversed to require certification by the local government to ensure consistency with the local comprehensive plan and land use laws before an application is submitted to DEC.

The self-certification process described in the 2011 rdSGEIS would apply only to wells drilled with more than 300,000 gallons of fracturing water. Thus, a well using a smaller volume of fracturing water could be totally inconsistent with comprehensive plans or land use laws—but the local government would have no way of knowing this.

The draft regulations should require that as part of the permit application, an official letter be included from the local government (or local governments) with jurisdiction certifying that the permit request is consistent with the local comprehensive plan and land use laws, or that no such local plan or laws exist. Permit applications should be considered incomplete without this certification from the appropriate local government.

The above requirement for local government certification should apply to any gas well, regardless of type or quantity of fracturing water.

This concludes the comments that I am able to provide in the limited time that has been made available. This by no means implies that there are no additional issues in the revised regulations that should be addressed before they are issued. Even with all the changes suggested above, the revised regulations will remain inadequate to protect the people of New York State.

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